10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2018

OR

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

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 offices)	(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	Name of Each Exchange on Which Registered
Common Stock, No Par Value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☒    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☒

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

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

Large accelerated filer  ☒      Accelerated filer  ☐      Non-accelerated filer  ☐      Smaller reporting company  ☐

Emerging growth company  ☐

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

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

Based on the closing price of the registrant’s common stock on June 30, 2018, the aggregate market value of common stock held by non-affiliates of the registrant was $749,186,923

The number of shares of the registrant’s common stock outstanding was 14,878,075 as of January 28, 2019.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 24, 2019 are incorporated by reference into Part III of this Report.

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2018

Table of Contents

Item	Description	Page
	PART I
1.	Business		3
	Unitil Corporation		3
	Operations		4
	Rates and Regulation		6
	Natural Gas Supply		9
	Electric Power Supply		10
	Environmental Matters		12
	Employees		12
	Available Information		13
	Investor Information		13
1A.	Risk Factors		14
1B.	Unresolved Staff Comments		20
2.	Properties		20
3.	Legal Proceedings		21
4.	Mine Safety Disclosures		22
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
6.	Selected Financial Data		26
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)		27
7A.	Quantitative and Qualitative Disclosures about Market Risk		42
8.	Financial Statements and Supplementary Data		43
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		91
9A.	Controls and Procedures		91
9B.	Other Information		91
	PART III
10.	Directors, Executive Officers and Corporate Governance		92
11.	Executive Compensation		92
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		92
13.	Certain Relationships and Related Transactions, and Director Independence		92
14.	Principal Accountant Fees and Services		92
	PART IV
15.	Exhibits and Financial Statement Schedules		93
	SIGNATURES
	Signatures		99

CAUTIONARY STATEMENT

This report and the documents incorporated by reference into this report contain statements that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, 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 future operations of the Company (as such term is defined in Part I, Item I (Business)), are forward-looking statements.

These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Part I, 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, gas and electric energy commodities and transmission and transportation capacity and the Company’s ability to recover energy supply costs in its rates;

• customers’ preferred energy sources;

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

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

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

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

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

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

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

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

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

• increased competition.

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

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PART I

Item 1. Business

UNITIL CORPORATION

In this Annual Report on Form 10-K, the “Company”, “Unitil”, “we”, and “our” refer to Unitil Corporation and its subsidiaries, unless the context requires otherwise. Unitil is a public utility holding company and was incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:

Company Name	State and Year of Organization	Principal Business
Unitil Energy Systems, Inc. (Unitil Energy)	NH - 1901	Electric Distribution Utility
Fitchburg Gas and Electric Light Company (Fitchburg)	MA - 1852	Electric & Natural Gas Distribution Utility
Northern Utilities, Inc. (Northern Utilities)	NH - 1979	Natural Gas Distribution Utility
Granite State Gas Transmission, Inc. (Granite State)	NH - 1955	Natural Gas Transmission Pipeline
Unitil Power Corp. (Unitil Power)	NH - 1984	Wholesale Electric Power Utility
Unitil Service Corp. (Unitil Service)	NH - 1984	Utility Service Company
Unitil Realty Corp. (Unitil Realty)	NH - 1986	Real Estate Management
Unitil Resources, Inc. (Unitil Resources)	NH - 1993	Non-regulated Energy Services
Usource, Inc. and Usource, L.L.C. (collectively Usource)	DE - 2000	Energy Brokering Services

Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005.

Unitil’s principal business is the local distribution of electricity and natural gas to 188,330 customers throughout its service territories in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities: i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts, and iii) 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. In addition, Unitil is the parent company of Granite State, an interstate natural gas transmission pipeline company that provides interstate natural gas pipeline access and transportation services to Northern Utilities in its New Hampshire and Maine service territory. Together, Unitil’s three distribution utilities serve 105,571 electric customers and 82,759 natural gas customers.

	Customers Served as of December 31, 2018
	Residential		Commercial & Industrial (C&I)		Total
Electric:
Unitil Energy		64,934		11,127		76,061
Fitchburg		25,603		3,907		29,510
Total Electric		90,537		15,034		105,571
Natural Gas:
Northern Utilities		50,335		16,451		66,786
Fitchburg		14,269		1,704		15,973
Total Natural Gas		64,604		18,155		82,759
Total Customers Served		155,141		33,189		188,330

Unitil had an investment in Net Utility Plant of $1,036.8 million at December 31, 2018. Unitil’s total operating revenue was $444.1 million in 2018. Unitil’s operating revenue is substantially derived from regulated natural gas and electric distribution utility operations. A fifth utility subsidiary, Unitil Power,

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formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but currently has limited business and operating activities. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy in 2003 and divested of substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with those contracts.

Unitil also has three other wholly-owned non-utility 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 and energy supply 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. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are indirect subsidiaries that are wholly-owned by Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. For segment information relating to each segment’s revenue, earnings and assets, see Note 3 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report. All of the Company’s revenues are attributable to customers in the United States of America and all its long-lived assets are located in the United States of America.

OPERATIONS

Natural Gas Operations

Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations, discussed below. Revenue from Unitil’s gas operations was $216.1 million for 2018, which represents about 49% of Unitil’s total operating revenue.

Natural Gas Distribution Utility Operations

Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and Fitchburg. The primary business of Unitil’s natural gas utility operations is the local distribution of natural gas to customers in its service territories in New Hampshire, Massachusetts and Maine. Northern Utilities’ C&I customers and Fitchburg’s residential and C&I customers are entitled to purchase their natural gas supply from third-party competitive suppliers, while Northern Utilities or Fitchburg remains their gas distribution company. Both Northern Utilities and Fitchburg supply gas to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with this gas supply being recovered on a pass-through basis through regulated reconciling rate mechanisms that are periodically adjusted.

Natural gas is distributed by Northern Utilities to 66,786 customers in 44 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine in the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include healthcare, education, government and retail. Northern Utilities’ industrial base includes manufacturers in the auto, housing, rubber, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2018 gas operating revenue was $174.4 million, of which approximately 38% was derived from residential firm sales and 62% from C&I firm sales.

Natural gas is distributed by Fitchburg to 15,973 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries. Fitchburg’s 2018 gas operating revenue was $35.1 million, of which approximately 58% was derived from residential firm sales and 42% from C&I firm sales.

Gas Transmission Pipeline Operations

Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State

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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. Granite State had operating revenue of $6.6 million for 2018. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party suppliers.

Electric Distribution Utility Operations

Unitil’s electric distribution operations are conducted through two of the Company’s utilities, Unitil Energy and Fitchburg. Revenue from Unitil’s electric utility operations was $223.3 million for 2018, which represents about 50% of Unitil’s total operating revenue.

The primary business of Unitil’s electric utility operations is the local distribution of electricity to customers in its service territory in New Hampshire and Massachusetts. All of Unitil Energy’s and Fitchburg’s electric customers are entitled to choose to purchase their supply of electricity from third-party competitive suppliers, while Unitil Energy or Fitchburg remains their electric distribution company. Both Unitil Energy and Fitchburg supply electricity to those customers who do not obtain their supply from third-party competitive suppliers, with the approved costs associated with electricity supply being recovered on a pass-through basis through regulated reconciling rate mechanisms that are periodically adjusted.

Unitil Energy distributes electricity to 76,061 customers in New Hampshire in the capital city of Concord as well as parts of 12 surrounding towns and all or part of 18 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. Unitil Energy’s service territory consists of approximately 408 square miles. In addition, Unitil Energy’s service territory encompasses retail trading and recreation centers for the central and southeastern parts of the state and includes the Hampton Beach recreational area. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wire and plastics, healthcare and education. Unitil Energy’s 2018 electric operating revenue was $158.6 million, of which approximately 56% was derived from residential sales and 44% from C&I sales.

Fitchburg is engaged in the distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. Fitchburg’s service territory encompasses approximately 170 square miles. Electricity is distributed by Fitchburg to 29,510 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies, printing, publishing and associated industries and educational institutions. Fitchburg’s 2018 electric operating revenue was $64.7 million, of which approximately 59% was derived from residential sales and 41% from C&I sales.

Seasonality

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating related purposes. 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 and the temperature in both the winter and summer seasons.

Unitil Energy, Fitchburg and Northern Utilities are not dependent on a single customer or a few customers for their electric and natural gas sales.

Non-Regulated and Other Non-Utility Operations

Unitil’s non-regulated operations are conducted through Usource, a subsidiary of Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. Revenue from Unitil’s non-regulated operations was $4.7 million in 2018.

The results of Unitil’s other non-utility subsidiaries, Unitil Service and Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of these non-utility

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operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note 3 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.

RATES AND REGULATION

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, has issued procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC has opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below). 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.

In Maine, Northern Utilities’ Maine division recently completed a base rate case (described below). The Maine Public Utilities Commission’s (MPUC) final order in that docket incorporated the lower tax rates in the calculation of rates for the Company.

Similarly, in New Hampshire, Northern Utilities’ New Hampshire division recently completed a base rate case proceeding (described below). The New Hampshire Public Utilities Commission’s (NHPUC) final order in that docket approved a comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which included the effect of the tax changes in the calculation of the revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC approved the Company’s annual step increase pursuant to the provisions of its last base rate case, which included adjustments to account for the TCJA’s income tax changes.

In Massachusetts, the Massachusetts Department of Public Utilities (MDPU) issued an order opening an investigation into the effect on rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. On December 21, 2018 the MDPU issued an order addressing the refund of excess ADIT in phase two of its investigation. Fitchburg was ordered to make a filing by January 4, 2019, for rates effective February 1, 2019, to refund $10.1 million for the electric division amortized over 15 years and $10.4 million for the gas division amortized over 14 years. The filing establishes a “Tax Act Credit Factor” for Fitchburg’s gas and electric divisions effective February 1, 2019 in accordance with the order. To the extent any of the regulatory liability above includes excess ADIT amounts specifically associated with reconciling mechanisms, Fitchburg shall return those amounts through the respective reconciling mechanism and adjust the regulatory liability amount accordingly. The MDPU approved this filing on January 16, 2019.

On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reduction under the TCJA.

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Base Rate Activity

Unitil Energy—Base Rates—On April 20, 2017 the NHPUC approved a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019 to recover the revenue requirements associated with annual capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s step adjustment filing. The filing incorporated the revenue requirement of $3.3 million for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of the one-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resulted in a revenue decrease of $0.3 million.

Fitchburg—Base Rates—Electric—Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. While a number of the capital cost recovery filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. On November 1, 2018, Fitchburg filed its cumulative revenue requirement associated with the Company’s 2015, 2016 and 2017 capital expenditures and associated Capital Cost Adjustment Factors to become effective on January 1, 2019. On December 27, 2018, the Capital Cost Adjustment Factors were approved subject to further investigation and reconciliation. This matter remains pending.

Fitchburg—Electric Grid Modernization—On May 10, 2018, the MDPU issued an order approving a three year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Massachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to address pre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.

Fitchburg—Solar Generation—On November 9, 2016, the MDPU approved Fitchburg’s petition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing sought a net amount of approximately $0.3 million for recovery effective June 1, 2018. The recovery of this amount in rates was approved by the MDPU on May 31, 2018, subject to further investigation and reconciliation. A final order is pending.

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.

Fitchburg—Gas System Enhancement Program—Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably

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and prudently incurred. While a number of the filings under the GSEP tariff may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff, a revenue increase of $0.9 million went into effect on May 1, 2018, subject to the annual cap and reconciliation. On October 31, 2018, the MDPU approved the Company’s request for a waiver of the annual cap in order to recover its reconciliation adjustment of $0.4 million effective November 1, 2018 associated with its actual 2017 revenue requirement.

Northern Utilities—Base Rates—Maine—On February 28, 2018, the MPUC issued its Final Order (Order) in Northern Utilities’ pending base rate case. The Order provided for an annual revenue increase of $2.1 million before a reduction of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million, and addressed a number of other issues, including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s Targeted Area Build-out (TAB) program and Targeted Infrastructure Replacement Adjustment (TIRA) mechanism. The new rates and other changes became effective on March 1, 2018.

Northern Utilities—Targeted Infrastructure Replacement Adjustment—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). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, 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, to recover the revenue requirements for 2017 eligible facilities.

Northern Utilities—Targeted Area Build-out Program—Maine—In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.

Northern Utilities—Base Rates—New Hampshire—On May 2, 2018, the NHPUC approved a settlement agreement providing for an annual revenue increase of $2.6 million, a reduction of annual revenue of $1.7 million to reflect the effect of the TCJA, and a step increase of $2.3 million to recover post-test year capital investments, all effective May 1, 2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case will be based on an historic test year of no earlier than twelve months ending December 31, 2020.

Northern Utilities—Franchise Extensions—New Hampshire—On October 3, 2018, the NHPUC granted Northern Utilities authority to expand its natural gas service territory in the Towns of Kingston, New Hampshire and Atkinson, New Hampshire (where the Company already had a limited franchise) to serve new industrial, commercial and residential customers. Northern Utilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and residential developments present the Company with opportunities for growth. The franchise petition for service to the Town of Epping remains pending.

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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. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.

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 NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and 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.

Also see Regulatory Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

NATURAL GAS SUPPLY

Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

Northern Utilities’ C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third-party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2018, 79% of Unitil’s largest New Hampshire gas customers, representing 37% of Unitil’s New Hampshire gas therm sales and 68% of Unitil’s largest Maine customers, representing 23% of Unitil’s Maine gas therm sales, are purchasing gas supply from a third-party supplier.

Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many large and some medium C&I customers purchase their gas supply

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from third-party suppliers while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2018, 85% of Unitil’s largest Massachusetts gas customers, representing 26% of Unitil’s Massachusetts gas therm sales, are purchasing gas supply from third-party suppliers. The approved costs associated with natural gas supplied to customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

Regulated Natural Gas Supply

Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers largely under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), via over the road trucking of supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 4.3 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

Fitchburg purchases natural gas under contracts from producers and marketers largely under contracts of one year or less, and occasionally on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), via trucking of supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round transportation and 0.33 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

ELECTRIC POWER SUPPLY

Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2018, 77% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales and 81% of Unitil’s largest Massachusetts customers, representing 32% of Unitil’s Massachusetts electric kWh sales, are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base and customers in Ashby comprise another 4%. Buoyed by the municipal aggregations, 31% of Unitil’s residential customers in Massachusetts purchase their electricity from a third-party supplier as of December 2018.

In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier stands at 10%, down slightly relative to prior years when 13% of Unitil’s residential customers in New Hampshire purchased their supply from third-party suppliers. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

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Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

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 and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Long-Term Renewable Contracts

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 filed with MDPU in 2018 and approvals remain pending.

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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.

ENVIRONMENTAL MATTERS

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2018, 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 to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required.

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.

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.

Also, see Environmental Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES

As of December 31, 2018, the Company and its subsidiaries had 520 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

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As of December 31, 2018, a total of 165 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of December 31, 2018:

	Employees Covered		CBA Expiration
Fitchburg		47		05/31/2019
Northern Utilities NH Division		34		06/05/2020
Northern Utilities ME Division		39		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.

AVAILABLE INFORMATION

The Internet address for the Company’s website is www.unitil.com. On the Investors section of the Company’s website, the Company makes available, free of charge, its Securities and Exchange Commission (SEC) reports, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other reports, as well as amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practical after the Company electronically files such material with, or furnishes such material to, the SEC.

The Company’s current Code of Ethics was approved by Unitil’s Board of Directors on January 15, 2004. This Code of Ethics, along with any amendments or waivers, is also available on Unitil’s website.

Unitil’s common stock is listed on the New York Stock Exchange under the ticker symbol “UTL”.

INVESTOR INFORMATION

Annual Meeting

The Company’s annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Wednesday, April 24, 2019, at 11:30 a.m.

Transfer Agent

The Company’s transfer agent, Computershare Investor Services, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, and the distribution of Unitil’s dividends and IRS Form 1099-DIV. Shareholders may contact Computershare at:

Computershare Investor Services

P.O. Box 30170

College Station, TX 77842-3170

Telephone: 800-736-3001

www.computershare.com/investor

Investor Relations

For information about the Company, you may call the Company directly, toll-free, at: 800-999-6501 and ask for the Investor Relations Representative; visit the Investors page at www.unitil.com; or contact the transfer agent, Computershare, at the number listed above.

Special Services & Shareholder Programs Available to Holders of Record

If a shareholder’s shares of our common stock are registered directly in the shareholder’s name with the Company’s transfer agent, the shareholder is considered a holder of record of the shares. The following services and programs are available to shareholders of record:

• Internet Account Access is available at www.computershare.com/investor.

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• Dividend Reinvestment and Stock Purchase Plan:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

• Dividend Direct Deposit Service:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

• Direct Registration:

For information, please contact Computershare at 800-935-9330 or the Company’s Investor Relations Representative at 800-999-6501.

Item 1A. Risk Factors

Risks Relating to Our Business

The Company is subject to comprehensive regulation, which could adversely impact the rates it is able to charge, its authorized rate of return and its ability to recover costs. In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company, which could adversely affect the Company’s financial condition and results of operations.

The Company is subject to comprehensive regulation by federal regulatory authorities (including the FERC) and state regulatory authorities (including the NHPUC, MDPU and MPUC). These authorities regulate many aspects of the Company’s operations, including the rates that the Company can charge customers, the Company’s authorized rates of return, the Company’s ability to recover costs from its customers, construction and maintenance of the Company’s facilities, the Company’s safety protocols and procedures, including environmental compliance, the Company’s ability to issue securities, the Company’s accounting matters, and transactions between the Company and its affiliates. The Company is unable to predict the impact on its financial condition and results of operations from the regulatory activities of any of these regulatory authorities. Changes in regulations, the imposition of additional regulations or regulatory decisions particular to the Company could adversely affect the Company’s financial condition and results of operations.

The Company’s ability to obtain rate adjustments to maintain its current authorized rates of return depends upon action by regulatory authorities under applicable statutes, rules and regulations. These regulatory authorities are authorized to leave the Company’s rates unchanged, to grant increases in such rates or to order decreases in such rates. The Company may be unable to obtain favorable rate adjustments or to maintain its current authorized rates of return, which could adversely affect its financial condition and results of operations.

Regulatory authorities also have authority with respect to the Company’s ability to recover its electricity and natural gas supply costs, as incurred by Unitil Power, Unitil Energy, Fitchburg, and Northern Utilities. If the Company is unable to recover a significant amount of these costs, or if the Company’s recovery of these costs is significantly delayed, then the Company’s financial condition and results or operations could be adversely affected.

In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company if the Company is found to have violated statutes, rules or regulations governing its utility operations. Any such penalties or sanctions could adversely affect the Company’s financial condition and results of operations.

The Company’s electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may adversely affect the Company’s customers and correspondingly the Company’s financial condition and results of operations.

The Company’s business is influenced by the economic activity within its service territory. The level of economic activity in the Company’s electric and natural gas distribution service territories directly affects the Company’s business. As a result, adverse changes in the economy may adversely affect the Company’s financial condition and results or operations. Economic downturns or periods of high electric and gas supply

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costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited. In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations and/or cash flows.

The Company may not be able to obtain financing, or may not be able to obtain financing on acceptable terms, which could adversely affect the Company’s financial condition and results of operations.

The Company requires capital to fund utility plant additions, working capital and other utility expenditures. While the Company derives the capital necessary to meet these requirements primarily from internally-generated funds, the Company supplements internally-generated funds by incurring short-term and long-term debt, as needed. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. A downgrade of our credit rating or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

The Company’s short-term debt revolving credit facility typically has variable interest rates. Therefore, an increase or decrease in interest rates will increase or decrease the Company’s interest expense associated with its revolving credit facility. An increase in the Company’s interest expense could adversely affect the Company’s financial condition and results of operations. As of December 31, 2018, the Company had approximately $82.8 million in short-term debt outstanding under its revolving credit facility. Additionally, if the lending counterparties under the Company’s current credit facility are unwilling or unable to meet their funding obligations, then the Company may be unable to, or limited in its ability to, incur short-term debt under its credit facility. This could hinder or prevent the Company from meeting its current and future capital needs, which could correspondingly adversely affect the Company’s financial condition and results or operations.

Also, from time to time, the Company repays portions of its short-term debt with the proceeds it receives from long-term debt financings or equity financings. General economic conditions, conditions in the capital and credit markets and the Company’s operating and financial performance could negatively affect the Company’s ability to obtain such financings or the terms of such financings, which could correspondingly adversely affect the Company’s financial condition and results of operations. The Company’s long-term debt typically has fixed interest rates. Therefore, changes in interest rates will not affect the Company’s interest expense associated with its presently outstanding fixed rate long-term debt. However, an increase or decrease in interest rates may increase or decrease the Company’s interest expense associated with any new fixed rate long-term debt issued by the Company, which could adversely affect the Company’s financial condition and results of operations.

In addition, the Company may need to use a significant portion of its cash flow to repay its short-term debt and long-term debt, which would limit the amount of cash it has available for working capital, capital expenditures and other general corporate purposes and could adversely affect its financial condition and results of operations.

Changes in taxation and the ability to quantify such changes could adversely affect the Company’s financial results.

The Company is subject to taxation by the various taxing authorities at the federal, state and local levels where it does business. See “Tax Cuts and Jobs Act of 2017” in “Rates and Regulation” above. Legislation or regulation which could affect the Company’s tax burden could be enacted by any of these governmental authorities. The Company cannot predict the timing or extent of such tax-related developments which could have a negative impact on the financial results. Additionally, the Company uses its best judgment in attempting to quantify and reserve for these tax obligations. However, a challenge by a

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taxing authority, the Company’s ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates. (See Note 9 to the Consolidated Financial Statements).

Declines in the valuation of capital markets could require the Company to make substantial cash contributions to cover its pension and other post-retirement benefit obligations. If the Company is unable to recover a significant amount of pension and other post-retirement benefit obligation costs in its rates, or if the Company’s recovery of these costs in its rates is significantly delayed, then the Company’s financial condition and results of operations could be adversely affected.

The amount of cash contributions the Company is required to make in respect of its pension and other post-retirement benefit obligations is dependent upon the valuation of the capital markets. Adverse changes in the valuation of the capital markets could result in the Company being required to make substantial cash contributions in respect to these obligations. These cash contributions could have an adverse effect on the Company’s financial condition and results of operations if the Company is unable to recover such costs in rates or if such recovery is significantly delayed. Please see the section entitled Critical Accounting Policies—Retirement Benefit Obligations in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 10 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements for a more detailed discussion of the Company’ pension obligations.

The terms of the Company’s and its subsidiaries’ indebtedness restrict the Company’s and its subsidiaries’ business operations (including their ability to incur material amounts of additional indebtedness), which could adversely affect the Company’s financial condition and results of operations.

The terms of the Company’s and its subsidiaries’ indebtedness impose various restrictions on the Company’s business operations, including the ability of the Company and its subsidiaries to incur additional indebtedness. These restrictions could adversely affect the Company’s financial condition and results of operations. See the sections entitled Liquidity, Commitments and Capital Requirements in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements for a more detailed discussion of these restrictions.

A significant amount of the Company’s sales are temperature sensitive. Because of this, mild winter and summer temperatures could decrease the Company’s sales, which could adversely affect the Company’s financial condition and results of operations. Also, the Company’s sales may vary from year to year depending on weather conditions, and the Company’s results of operations generally reflect seasonality.

The Company estimates that approximately 70% of its annual natural gas sales are temperature sensitive. Therefore, mild winter temperatures could decrease the amount of natural gas sold by the Company, which could adversely affect the Company’s financial condition and results of operations. The Company’s electric sales also are temperature sensitive, but less so than its natural gas sales. The highest usage of electricity typically occurs in the summer months (due to air conditioning demand) and the winter months (due to heating-related and lighting requirements). Therefore, mild summer temperatures and mild winter temperatures could decrease the amount of electricity sold by the Company, which could adversely affect the Company’s financial condition and results of operations. Also, because of this temperature sensitivity, sales by the Company’s distribution utilities vary from year to year, depending on weather conditions.

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating related purposes. 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 and the temperature in both the winter and summer seasons.

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Unitil is a public utility holding company and has no operating income of its own. The Company’s ability to pay dividends on its common stock is dependent on dividends and other payments received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure that its current annual dividend will be paid in the future.

The ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil depends on, among other things:

• the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

• the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

• the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

• limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory authorities.

In addition, before the Company can pay dividends on its common stock, it has to satisfy its debt obligations and comply with any statutory or contractual limitations.

As of January 30, 2019, the Company’s current effective annualized dividend is $1.48 per share of common stock, payable quarterly. The Company’s Board of Directors reviews Unitil’s dividend policy periodically in light of a number of business and financial factors, including those referred to above, and the Company cannot assure the amount of dividends, if any, that may be paid in the future.

A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity and electric transmission capacity may impair the Company’s ability to meet customers’ existing and future requirements.

In order to meet existing and future customer demands for natural gas and electricity, the Company must acquire sufficient supplies of natural gas and electricity. In addition, the Company must contract for reliable and adequate upstream transmission and transportation capacity for its distribution systems while considering the dynamics of the natural gas interstate pipelines and storage, the electric transmission markets and its own on-system resources. The Company’s financial condition or results of operations may be adversely affected if the future availability of natural gas and electric supply were insufficient to meet future customer demands for natural gas and electricity.

The Company’s electric and natural gas distribution activities (including storing natural gas and supplemental gas supplies) involve numerous hazards and operating risks that may result in accidents and other operating risks and costs. Any such accident or costs could adversely affect the Company’s financial position or results of operations.

Inherent in the Company’s electric and natural gas distribution activities are a variety of hazards and operating risks, including leaks, explosions, electrocutions, mechanical problems and aging infrastructure. These hazards and risks could result in loss of human life, significant damage to property, environmental pollution, damage to natural resources and impairment of the Company’s operations, which could adversely affect the Company’s financial position or results of operations.

The Company maintains insurance against some, but not all, of these risks and losses in accordance with customary industry practice. The location of pipelines, storage facilities and electric distribution equipment near populated areas (including residential areas, commercial business centers and industrial sites) could increase the level of damages associated with these hazards and operating risks. The occurrence of any of these events could adversely affect the Company’s financial position or results of operations.

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The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and its costs of compliance are significant. New, or changes to existing, environmental regulation, including those related to climate change or greenhouse gas emissions, and the incurrence of environmental liabilities could adversely affect the Company’s financial condition and results of operations.

The Company’s utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources, and the health and safety of the Company’s employees. The Company’s utility operations also may be subject to new and emerging federal, state and local legislative and regulatory initiatives related to climate change or greenhouse gas emissions including the U.S. Environmental Protection Agency’s mandatory greenhouse gas reporting rule. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties and other sanctions; imposition of remedial requirements; and issuance of injunctions to ensure future compliance. Liability under certain environmental laws and regulations is strict, joint and several in nature. Although the Company believes it is in material compliance with all applicable environmental and safety laws and regulations, we cannot assure you that the Company will not incur significant costs and liabilities in the future. Moreover, it is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations, including those related to climate change or greenhouse gas emissions, could result in increased environmental compliance costs.

Catastrophic events could adversely affect the Company’s financial condition and results of operations.

The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could inhibit the Company’s ability to deliver electric or natural gas to its customers for an extended period, which could affect customer satisfaction and adversely affect the Company’s financial condition and results of operations. If customers, legislators, or regulators develop a negative opinion of the Company, this could result in increased regulatory oversight and could affect the returns on equity that the Company is allowed to earn. Also, if the Company is unable to recover a significant amount of costs associated with catastrophic events in its rates, or if the Company’s recovery of such costs in its rates is significantly delayed, then the Company’s financial condition and results or operations may be adversely affected.

The Company’s operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense.

The operation of the Company’s extensive electricity and natural gas systems rely on evolving information technology systems and network infrastructures that are likely to become more complex as new technologies and systems are developed. The Company’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of transactions, many of which are highly complex. The failure of these information systems and networks could significantly disrupt operations; result in outages and/or damages to the Company’s assets or operations or those of third parties on which it relies; and subject the Company to claims by customers or third parties, any of which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

The Company’s information systems, including its financial information, operational systems, metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increases the risk of errors and malfunction. Any disruptions or deficiencies in existing information systems, or disruptions, delays or deficiencies in the modification or implementation of new information systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively impact the effectiveness of the Company’s control environment, and/or the Company’s ability to timely file required regulatory reports. Despite implementation of security and mitigation measures, all of the Company’s technology systems are

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vulnerable to impairment or failure due to cyber-attacks, computer viruses, human errors, acts of war or terrorism and other reasons. If the Company’s information technology systems were to fail or be materially impaired, the Company might be unable to fulfill critical business functions and serve its customers, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

In the ordinary course of its business, the Company collects and retains sensitive electronic data including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data through security breaches or other means could subject the Company to penalties for violation of applicable privacy laws or claims from third parties and could harm the Company’s reputation and adversely affect the Company’s financial condition and results of operations.

In addition, the Company’s electric and natural gas distribution and transmission delivery systems are part of an interconnected regional grid and pipeline system. If these neighboring interconnected systems were to be disrupted due to cyber-attacks, computer viruses, human errors, acts of war or terrorism or other reasons, the Company’s operations and its ability to serve its customers would be adversely affected, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

We outsource certain business functions to third-party suppliers and service providers, and substandard performance by those third parties could harm our business, reputation and results of operations.

We outsource certain services to third parties in areas including information technology, telecommunications, networks, transaction processing, human resources, payroll and payroll processing and other areas. Outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively impact our results of operations. We also continue to pursue enhancements to modernize our systems and processes. If any difficulties in the operation of these systems were to occur, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on the Company’s operations.

The success of our business depends on the leadership of our executive officers and other key employees to implement our business strategies. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. There may not be sufficiently skilled employees available internally to replace employees when they retire or otherwise leave active employment. Shortages of certain highly skilled employees may also mean that qualified employees are not available externally to replace these employees when they are needed. In addition, shortages in highly skilled employees coupled with competitive pressures may require the Company to incur additional employee recruiting and compensation expenses.

The Company may be adversely impacted by work stoppages, labor disputes, and/or pandemic illness to which it may not able to promptly respond.

Approximately one-third of the Company’s employees are represented by labor unions and are covered by collective bargaining agreements. Disputes with the unions over terms and conditions of the agreements could result in instability in the Company’s labor relationships and work stoppages that could impact the timely delivery of natural gas and electricity, which could strain relationships with customers and state regulators and cause a loss of revenues. The Company’s collective bargaining agreements may also increase the cost of employing its union workforce, affect its ability to continue offering market-based salaries and employee benefits, limit its flexibility in dealing with its workforce, and limit its ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace, which may negatively affect the Company’s financial condition and results of operations.

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Additionally, pandemic illness could result in part, or all, of the Company’s workforce being unable to operate or maintain the Company’s infrastructure or perform other tasks necessary to conduct the Company’s business. A slow or inadequate response to this type of event may adversely affect the Company’s financial condition and results of operations.

The Company’s business could be adversely affected if it is unable to retain its existing customers or attract new customers, or if customers’ demand for its current products and services significantly decreases.

The success of the Company’s business depends, in part, on its ability to maintain and increase its customer base and the demand that those customers have for the Company’s products and services. The Company’s failure to maintain or increase its customer base and/or customer demand for its products and services could adversely affect its financial condition and results of operations.

The natural gas and electric supply requirements of the Company’s customers are fulfilled by the Company or, in some instances and as allowed by state regulatory authorities, by third-party suppliers who contract directly with customers. In either scenario, significant increases in natural gas and electricity commodity prices may negatively impact the Company’s ability to attract new customers and grow its customer base.

Developments in distributed generation, energy conservation, power generation and energy storage could affect the Company’s revenues and the timing of the recovery of the Company’s costs. Advancements in power generation technology are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Such developments could reduce customer purchases of electricity, but may not necessarily reduce the Company’s investment and operating requirements due to the Company’s obligation to serve customers, including those self-supply customers whose equipment has failed for any reason, to provide the power they need. In addition, since a portion of the Company’s costs are recovered through charges based upon the volume of power delivered, reductions in electricity deliveries will affect the timing of the Company’s recovery of those costs and may require changes to the Company’s rate structures.

The financial performance of the Company’s non-regulated energy brokering business, Usource, may be adversely affected if suppliers and/or customers default in their performance under multi-year energy brokering contracts or by competition from other energy brokers.

Usource provides energy brokering and consulting services to a national client base of large commercial and industrial customers. Revenues from this business are primarily derived from brokering fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts. Usource’s customers and/or the suppliers providing energy to Usource’s customers may default in their performance under multi-year energy brokering contracts, which could adversely affect the Company’s financial condition and results of operations. In addition, Usource may lose market share to other energy brokers which could adversely affect the Company’s financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2018, Unitil owned, through its natural gas and electric distribution utilities, five utility operation centers located in New Hampshire, Maine and Massachusetts. In addition, the Company’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the land on which it is located. In May 2018, Fitchburg relocated to its new operating center in Lunenburg on a 15 acre property owned by Unitil.

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The following tables detail certain of the Company’s natural gas and electric operations properties.

Natural Gas Operations

	Northern Utilities				Fitchburg		Granite State		Total
Description	NH		ME
Underground Natural Gas Mains—Miles		544		589		274		—		1,407
Natural Gas Transmission Pipeline—Miles		—		—		—		86		86
Service Pipes		23,642		22,481		11,074		—		57,197

Electric Operations

Description	Unitil Energy		Fitchburg		Total
Primary Transmission and Distribution Pole Miles—Overhead		1,278		445		1,723
Conduit Distribution Bank Miles—Underground		231		67		298
Transmission and Distribution Substations		34		16		50
Transformer Capacity of Transmission and Distribution Substations (MVA)		549.5		608.2		1,157.7

The Company’s natural gas operations property includes two liquid propane gas plants and two liquid natural gas plants. Northern Utilities also owns a propane air gas plant and an LNG storage and vaporization facility. FG&E owns a propane air gas plant and an LNG storage and vaporization facility, both of which are located on land owned by FG&E in north central Massachusetts.

Northern Utilities’ gas mains are primarily made up of polyethylene plastic (80%), coated and wrapped cathodically protected steel (16%), cast/wrought iron (3%), and unprotected bare and coated steel (1%). FG&E’s gas mains are primarily made up of coated steel (45%), bare steel (2%), polyethylene plastic (36%), cast iron (16) and wrought and ductile iron (1%).

Granite State’s underground natural gas transmission pipeline, regulated by the FERC, is located primarily in Maine and New Hampshire.

Unitil Energy’s electric substations are located on land owned by Unitil Energy or land occupied by Unitil Energy pursuant to perpetual easements in the southeastern seacoast and state capital regions of New Hampshire. Unitil Energy’s electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by Unitil Energy without objection by the owners. In the case of certain distribution lines, Unitil Energy owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telecommunication companies.

The physical utility properties of Unitil Energy, with certain exceptions, and its franchises are subject to its indenture of mortgage and deed of trust under which the respective series of first mortgage bonds of Unitil Energy are outstanding.

FG&E’s electric substations, with minor exceptions, are located in north central Massachusetts on land owned by FG&E or occupied by FG&E pursuant to perpetual easements. FG&E’s electric distribution lines and gas mains are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, express or implied through use by FG&E without objection by the owners. FG&E owns full interest in the poles upon which its wires are installed.

The Company believes that its facilities are currently adequate for their intended uses.

Item 3. 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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In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court, (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint sought an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remained pending. The Company resolved this matter by settlement in the fall of 2018 and there was no material impact on the Company’s financial position, operating results or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2018, there were 1,350 shareholders of record of our common stock.

Common Stock Data

Dividends per Common Share	2018		2017
1st Quarter	$	0.365	$	0.360
2nd Quarter		0.365		0.360
3rd Quarter		0.365		0.360
4th Quarter		0.365		0.360
Total for Year	$	1.46	$	1.44

See also “Dividends” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) below.

Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2018, is set forth in the table below.

Equity Compensation Plan Information

	(a)		(b)		(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders(1)		—		—		305,449
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		305,449

NOTES: (also see Note 6 to the accompanying Consolidated Financial Statements)

⁽¹⁾  Consists of the Second Amended and Restated 2003 Stock Plan (the Plan). On April 19, 2012, shareholders approved the Plan, and a total of 677,500 shares of our common stock were reserved for issuance pursuant to awards of restricted stock, restricted stock units and common stock under the Plan. A total of 380,161 shares of restricted stock have been awarded and 1,106 restricted stock units have been settled and issued as shares of common stock by Plan participants through December 31, 2018. As of December 31, 2018, a total of 8,110 shares of restricted stock were forfeited and once again became available for issuance under the Plan.

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Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2013 with the Peer Group index, comprised of the S&P 500 Utilities Index, and the S&P 500 index. The graph assumes that the value of the investment in the Company’s common stock and each index (including reinvestment of dividends) was $100 on December 31, 2013.

Comparative Five-Year Total Returns

NOTE:

⁽¹⁾ The graph above assumes $100 invested on December 31, 2013, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P 500 Utilities Index.

Unregistered Sales of Equity Securities and Uses of Proceeds

There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2018.

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, 2018, the Company will periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and 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 $92,700 in value of shares have been purchased or, if sooner, on May 1, 2019.

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.

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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 December 31, 2018.

Period	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
10/1/18 – 10/31/18		—		—		—	$	75,366
11/1/18 – 11/30/18		—		—		—	$	75,366
12/1/18 – 12/31/18		319	$	50.330		319	$	59,311
Total		319	$	50.330		319

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Item 6. Selected Financial Data

	For the Years Ended December 31, (all data in millions except customers served, shares, % and per share data)
	2018			2017			2016			2015			2014
Customers Served (Year-End):
Electric:
Residential		90,537			90,009			89,400			88,444			88,012
Commercial & Industrial		15,034			14,969			14,872			14,825			14,740
Total Electric		105,571			104,978			104,272			103,269			102,752
Natural Gas:
Residential		64,604			63,441			62,284			61,270			60,236
Commercial & Industrial		18,155			17,868			17,654			17,479			17,624
Total Natural Gas		82,759			81,309			79,938			78,749			77,860
Total Customers Served		188,330			186,287			184,210			182,018			180,612
Electric and Gas Sales:
Electric Distribution Sales (kWh)		1,675.8			1,624.1			1,628.8			1,667.7			1,679.0
Firm Natural Gas Distribution Sales (Therms)		231.1			213.8			205.7			219.4			216.2
Consolidated Statements of Earnings:
Operating Revenue	$	444.1		$	406.2		$	383.4		$	426.8		$	425.8
Operating Income		71.2			75.4			70.2			68.0			63.5
Interest Expense, net		24.0			23.1			22.5			21.9			20.9
Other Expense (Income), net		5.8			5.8			5.2			4.4			3.9
Income Before Income Taxes		41.4			46.5			42.5			41.7			38.7
Income Taxes		8.4			17.5			15.4			15.4			14.0
Net Income		33.0			29.0			27.1			26.3			24.7
Dividends on Preferred Stock		—			—			—			—			—
Earnings Applicable to Common Shareholders	$	33.0		$	29.0		$	27.1		$	26.3		$	24.7
Earnings Per Average Share:	$	2.23		$	2.06		$	1.94		$	1.89		$	1.79
Common Stock—(Diluted Weighted Average Outstanding, 000’s)		14,829			14,102			13,996			13,920			13,847
Dividends Declared Per Share	$	1.46		$	1.44		$	1.42		$	1.40		$	1.38
Book Value Per Share (Year-End)	$	23.60		$	22.72		$	20.82		$	20.20		$	19.62
Balance Sheet Data (as of December 31,):
Utility Plant	$	1,369.3		$	1,279.2		$	1,173.4		$	1,080.6		$	988.8
Capital Lease Obligations(1)	$	5.8		$	8.8		$	11.3		$	14.1		$	8.0
Total Assets	$	1,298.3		$	1,241.9		$	1,128.2		$	1,038.8		$	997.0
Capitalization:
Common Stock Equity	$	351.1		$	336.6		$	292.9		$	282.6		$	273.1
Preferred Stock		0.2			0.2			0.2			0.2			0.2
Long-Term Debt, less current portion		387.4			376.3			316.8			305.5			326.0
Total Capitalization	$	738.7		$	713.1		$	609.9		$	588.3		$	599.3
Current Portion of Long-Term Debt	$	18.4		$	29.8		$	16.8		$	17.1		$	3.7
Short-Term Debt	$	82.8		$	38.3		$	81.9		$	42.0		$	29.3
Capital Structure Ratios (as of December 31,):
Common Stock Equity		48	%		47	%		48	%		48	%		46	%
Long-Term Debt, less current portion		52	%		53	%		52	%		52	%		54	%

⁽¹⁾  Includes amounts due within one year.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Note references are to the Notes to the Consolidated Financial Statements included in Item 8, below.)

OVERVIEW

Unitil is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005.

Unitil’s principal business is the local distribution of electricity and natural gas to approximately 188,300 customers throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire;

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

iii) Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area.

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, a natural gas transmission pipeline, regulated by the FERC, 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 North American pipeline supplies.

The distribution utilities are local “pipes and wires” operating companies, and Unitil had an investment in Net Utility Plant of $1,036.8 million at December 31, 2018. Unitil’s total revenue was $444.1 million in 2018, which 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 affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are derived from the return on investment in the three distribution utilities and Granite State.

Unitil also conducts non-regulated operations principally through Usource, which is wholly-owned by Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. Usource’s total revenues were $4.7 million in 2018. The Company’s other subsidiaries include Unitil Service, which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, and Unitil Realty, which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

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 NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and 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.

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Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under traditional 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.

Most of Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy suppliers. Many of Unitil’s distribution utilities’ largest C&I customers purchase their electricity or gas supply from third-party suppliers, while most small C&I customers, as well residential customers, purchase their electricity or gas supply from the distribution utilities under regulated rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale energy suppliers and recover the actual approved costs of these supplies on a pass-through basis, through reconciling rate mechanisms that are periodically adjusted.

Also see Regulatory Matters shown below and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

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 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.

RESULTS OF OPERATIONS

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.

The Company’s results of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the colder weather seasons of the year as a result of higher sales of natural gas used for heating related purposes. 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 and the temperature 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 on decoupled sales volumes.

Net Income and EPS Overview

2018 Compared to 2017—The Company’s Net Income was $33.0 million, or $2.23 per share, for the year ended December 31, 2018, an increase of $4.0 million, or 13.8%, in Net Income, and $0.17, or 8.25%, in Earnings Per Share, compared to 2017. The Company’s earnings for 2018 were driven by increases in natural gas and electric sales margins.

Natural gas sales margin was $116.9 million in 2018, an increase of $7.2 million compared to 2017. Gas sales margin in 2018 was positively affected by higher natural gas distribution rates of $7.1 million, which was partially offset by the reduction in rates of $3.7 million due to the lower corporate income tax rate of 21% under the TCJA. Gas margin in 2018 reflects the positive effect of colder winter weather and customer growth on sales volume of $3.8 million.

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Natural gas therm sales increased 8.1% in 2018 compared to 2017. The increase in gas therm sales in the Company’s service areas was driven by customer growth and colder winter weather in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 12.2% more Heating Degree Days in 2018 compared to 2017. As of December 31, 2018 the number of natural gas customers served has increased by 1,450 over the last year.

Electric sales margin was $91.9 million in 2018, a decrease of $0.3 million compared to 2017. Electric sales margin in 2018 was positively affected by higher electric distribution rates of $2.9 million, partially offset by the reduction in rates of $2.6 million in 2018 due to the lower corporate income tax rate of 21% under the TCJA. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $0.8 million. These positive impacts on electric sales margin were offset by the absence in the current period of a one-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

Electric kilowatt-hour (kWh) sales increased 3.2% in 2018 compared to 2017 reflecting customer growth and warmer-than-average summer temperatures in 2018. Based on weather data collected in the Company’s electric service areas, there were 42.2% more Cooling Degree Days in 2018 compared to 2017. As of December 31, 2018, the number of electric customers served has increased by 593 over the last year.

O&M expenses increased $5.0 million in 2018 compared to 2017. The change in O&M expense reflects higher labor costs of $1.8 million and higher utility operating costs of $4.0 million, partially offset by lower professional fees of $0.8 million. The higher utility operating costs include a non-recurring temporary rate adjustment which increased O&M expenses by $1.2 million in the second quarter of 2018, which was offset by a corresponding increase in gas revenue, and also includes higher bad debt expense of $0.8 million and higher storm-related and other distribution and transmission systems maintenance costs of $2.0 million.

Depreciation and Amortization expense increased $3.5 million in 2018 compared to 2017, reflecting higher depreciation on higher utility plant in service and higher amortization of information technology costs, partially offset by lower amortization of deferred major storm costs which were amortized for recovery over multi-year periods.

Taxes Other Than Income Taxes increased $1.3 million in 2018 compared to 2017, primarily reflecting higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

Interest Expense, net increased $0.9 million, or 3.9%, in 2018 compared to 2017 reflecting interest on higher short-term debt rates and higher levels of long-term debt.

Other Expense (Income) was essentially unchanged in 2018 compared to 2017.

Income Taxes decreased $9.1 million in 2018 compared to 2017 reflecting $6.3 million from the lower tax rate on pre-tax earnings in 2018 and the current tax benefit of $2.8 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018.

In 2018, Unitil’s annual common dividend was $1.46 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2019 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.37 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.48 per share from $1.46 per share.

2017 Compared to 2016—The Company’s Net Income was $29.0 million, or $2.06 per share, for the year ended December 31, 2017, an increase of $1.9 million in Net Income, and $0.12 in Earnings Per Share, compared to 2016. The Company’s earnings for 2017 were driven by increases in natural gas and electric sales margins.

A more detailed discussion of the Company’s 2018 and 2017 results of operations and a year-to-year comparison of changes in financial position are presented below.

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Gas Sales, Revenues and Margin

Therm Sales—Unitil’s total therm sales of natural gas increased 8.1% in 2018 compared to 2017. Sales to residential and C&I customers increased 12.2% and 7.0%, respectively, in 2018 compared to 2017. The increase in gas therm sales in the Company’s service areas was driven by customer growth and colder winter weather in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 12.2% more HDD in 2018 compared to 2017. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 3.3% in 2018 compared to 2017. As of December 31, 2018 the number of natural gas customers served has increased by 1,450 over the last year. As previously discussed, sales margin derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) is not sensitive to changes in gas therm sales.

Unitil’s total therm sales of natural gas increased 3.9% in 2017 compared to 2016. Sales to residential and C&I customers increased 6.9% and 3.2%, respectively, in 2017 compared to 2016. The increase in gas therm sales in the Company’s service areas was driven by customer growth and colder winter weather in 2017 compared to 2016. Based on weather data collected in the Company’s natural gas service areas, there were 5% more HDD in 2017 compared to 2016. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 1.7% in 2017 compared to 2016. As of December 31, 2017 the total number of natural gas customers served increased by 1,371 compared to the prior year.

The following table details total therm sales for the last three years, by major customer class:

Therm Sales (millions)							Change
							2018 vs. 2017					2017 vs. 2016
	2018		2017		2016		Therms		%			Therms		%
Residential		48.7		43.4		40.6		5.3		12.2	%		2.8		6.9	%
Commercial & Industrial		182.4		170.4		165.1		12.0		7.0	%		5.3		3.2	%
Total Therm Sales		231.1		213.8		205.7		17.3		8.1	%		8.1		3.9	%

Gas Operating Revenues and Sales Margin—The following table details total Gas Operating Revenue and Sales Margin for the last three years by major customer class:

Gas Operating Revenues and Sales Margin (millions)
							Change
							2018 vs. 2017					2017 vs. 2016
	2018		2017		2016		$		%			$		%
Gas Operating Revenue:
Residential	$	86.0	$	77.3	$	71.0	$	8.7		11.3	%	$	6.3		8.9	%
Commercial & Industrial		130.1		116.7		110.2		13.4		11.5	%		6.5		5.9	%
Total Gas Operating Revenue	$	216.1	$	194.0	$	181.2	$	22.1		11.4	%	$	12.8		7.1	%
Cost of Gas Sales	$	99.2	$	84.3	$	77.6	$	14.9		17.7	%	$	6.7		8.6	%
Gas Sales Margin	$	116.9	$	109.7	$	103.6	$	7.2		6.6	%	$	6.1		5.9	%

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue 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 to costs that are passed through directly to customers, 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.

Natural gas sales margin was $116.9 million in 2018, an increase of $7.2 million compared to 2017. Gas sales margin in 2018 was positively affected by higher natural gas distribution rates of $7.1 million, which was partially offset by the reduction in rates of $3.7 million due to the lower corporate income tax rate of 21% under the TCJA. As a result of the final base rate award in the Company’s New Hampshire gas

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utility, the Company recognized concurrent non-recurring adjustments to increase both Gas Operating Revenues and O&M expenses by $1.2 million in the second quarter of 2018 to reconcile permanent rates and deferred costs to the temporary rates which were effective July 1, 2017. Gas margin in 2018 reflects the positive effect of colder winter weather and customer growth on sales volume of $3.8 million.

The increase in Total Gas Operating Revenues of $22.1 million, or 11.4%, in 2018 compared to 2017 reflects higher natural gas distribution rates, customer growth and higher cost of gas sales, which are tracked and reconciled costs as a pass-through to customers.

Natural gas sales margin was $109.7 million in 2017, an increase of $6.1 million compared to 2016, driven by higher natural gas distribution rates of $3.3 million and the positive impact of colder weather and customer growth of $2.8 million.

The increase in Total Gas Operating Revenues of $12.8 million, or 7.1%, in 2017 compared to 2016 reflects higher natural gas distribution rates, customer growth and higher cost of gas sales, which are tracked and reconciled costs as a pass-through to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales—Unitil’s total electric kWh sales increased 3.2% in 2018 compared to 2017. Sales to residential customers and C&I customers increased 5.6% and 1.6%, respectively, in 2018 compared to 2017, reflecting customer growth and warmer-than-average summer temperatures in 2018. Based on weather data collected in the Company’s electric service areas, there were 42.2% more Cooling Degree Days in 2018 compared to 2017. As of December 31, 2018, the number of electric customers served has increased by 593 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual sales volume) are not sensitive to changes in kWh sales.

Unitil’s total electric kWh sales decreased 0.3% in 2017 compared to 2016. Sales to residential customers and C&I customers decreased 0.3% and 0.3%, respectively, in 2017 compared to 2016, reflecting milder summer weather in 2017, largely offset by customer growth. Based on weather data collected in the Company’s electric service areas, there were 21% fewer Cooling Degree Days in 2017 compared to 2016. As of December 31, 2017, the number of electric customers served increased by 706 compared to the prior year.

The following table details total kWh sales for the last three years by major customer class:

kWh Sales (millions)							Change
							2018 vs. 2017					2017 vs. 2016
	2018		2017		2016		kWh		%			kWh			%
Residential		685.5		649.4		651.3		36.1		5.6	%		(1.9	)		(0.3	%)
Commercial & Industrial		990.3		974.7		977.5		15.6		1.6	%		(2.8	)		(0.3	%)
Total kWh Sales		1,675.8		1,624.1		1,628.8		51.7		3.2	%		(4.7	)		(0.3	%)

Electric Operating Revenues and Sales Margin—The following table details Total Electric Operating Revenue and Sales Margin for the last three years by major customer class:

Electric Operating Revenues and Sales Margin (millions)
							Change
							2018 vs. 2017						2017 vs. 2016
	2018		2017		2016		$			%			$		%
Electric Operating Revenue:
Residential	$	127.2	$	115.5	$	110.6	$	11.7			10.1	%	$	4.9		4.4	%
Commercial & Industrial		96.1		90.7		85.5		5.4			6.0	%		5.2		6.1	%
Total Electric Operating Revenue	$	223.3	$	206.2	$	196.1	$	17.1			8.3	%	$	10.1		5.2	%
Cost of Electric Sales	$	131.4	$	114.0	$	108.0	$	17.4			15.3	%	$	6.0		5.6	%
Electric Sales Margin	$	91.9	$	92.2	$	88.1	$	(0.3	)		(0.3	%)	$	4.1		4.7	%

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The Company analyzes operating results using Electric Sales Margin, a non-GAAP measure. Electric Sales Margin is calculated as Total Electric Operating Revenues 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 to costs that are passed through directly to customers 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 margin was $91.9 million in 2018, a decrease of $0.3 million compared to 2017. Electric sales margin in 2018 was positively affected by higher electric distribution rates of $2.9 million, partially offset by the reduction in rates of $2.6 million in 2018 due to the lower corporate income tax rate of 21% under the TCJA. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $0.8 million. These positive impacts on electric sales margin were offset by the absence in the current period of a one-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

The increase in Total Electric Operating Revenue of $17.1 million, or 8.3%, in 2018 compared to 2017 reflects higher electric distribution rates, customer growth and higher cost of electric sales, which are tracked and reconciled costs as a pass-through to customers.

Electric sales margin was $92.2 million in 2017, an increase of $4.1 million compared to 2016. Electric sales margin in 2017 was positively affected by higher electric distribution rates of $5.4 million and customer growth of $1.0 million, partially offset by lower sales volumes due to the net impact of milder summer weather of $0.5 million and lower transmission revenues of $1.8 million. The higher electric distribution rates in 2017 include $1.4 million from a one-year $1.4 million temporary rate reconciliation adjustment, discussed above, recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

The increase in Total Electric Operating Revenue of $10.1 million, or 5.2%, in 2017 compared to 2016 reflects higher electric distribution rates and higher cost of electric sales, which are tracked and reconciled costs as a pass-through to customers.

Operating Revenue—Other

Total Other Operating Revenue (See “Other Operating Revenue – Non-regulated” in Note 1 to the accompanying Consolidated Financial Statements) is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from those suppliers under term contracts brokered by Usource.

Usource’s revenues decreased $1.3 million, or 21.7%, in 2018 compared to 2017 and $0.1 million, or 1.6%, in 2017 compared to 2016. The decrease in 2018 compared to 2017 is primarily the result of the adoption of a new accounting standard.

In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018. ASU 2014-09 requires that payments made by Usource to third parties (“Channel Partners”) for revenue sharing agreements are recognized as a reduction from revenue, where those payments were previously recognized as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to third parties for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to Channel Partners for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $1.0 million, $1.1 million and $1.0 million in 2018, 2017 and 2016, respectively.

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If ASU 2014-09 had been in effect for 2017 and 2016, the result would have been corresponding reductions of $1.1 million and $1.0 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings.

The following table details total Other Revenue for the last three years:

Other Revenue (millions)
							Change
							2018 vs. 2017						2017 vs. 2016
	2018		2017		2016		$			%			$			%
Usource	$	4.7	$	6.0	$	6.1	$	(1.3	)		(21.7	%)	$	(0.1	)		(1.6	%)
Total Other Revenue	$	4.7	$	6.0	$	6.1	$	(1.3	)		(21.7	%)	$	(0.1	)		(1.6	%)

Operating Expenses

Cost of Gas Sales—Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales increased $14.9 million, or 17.7%, in 2018 compared to 2017. This increase reflects higher sales of natural gas and higher wholesale natural gas prices. 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.

In 2017, Cost of Gas increased $6.7 million, or 8.6%, compared to 2016. This increase reflects higher sales of natural gas and higher wholesale natural gas prices, partially offset by an increase in the amount of natural gas purchased by customers directly from third-party suppliers.

Cost of Electric Sales—Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales increased $17.4 million, or 15.3%, in 2018 compared to 2017. This increase reflects higher wholesale electricity prices and a decrease in the amount of electricity purchased by customers directly from third-party suppliers. 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.

In 2017, Cost of Electric Sales increased $6.0 million, or 5.6%, compared to 2016. This increase reflects higher wholesale electricity prices and a decrease in the amount of electricity purchased by customers directly from third-party suppliers.

Operation and Maintenance—O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s non-regulated business activities. Total O&M expenses increased $5.0 million, or 7.8%, in 2018 compared to 2017. The change in O&M expense reflects higher labor costs of $1.8 million and higher utility operating costs of $4.0 million, partially offset by lower professional fees of $0.8 million. The higher utility operating costs include a non-recurring temporary rate adjustment which increased O&M expenses by $1.2 million in the second quarter of 2018, which was offset by a corresponding increase in gas revenue, and also includes higher bad debt expense of $0.8 million and higher storm-related and other distribution and transmission systems maintenance costs of $2.0 million.

In 2017, total O&M expenses increased $3.1 million, or 5.0%, compared to 2016. The change in O&M expenses reflects higher compensation and benefit costs of $1.2 million and higher utility operating costs of $1.9 million. Utility operating costs include higher pass-through regulatory and vegetation management costs of $1.1 million, which are recovered on a reconciling basis in sales margins.

Depreciation and Amortization—Depreciation and Amortization expense increased $3.5 million, or 7.5%, in 2018 compared to 2017, reflecting higher depreciation on higher utility plant in service and higher amortization of information technology costs, partially offset by lower amortization of deferred major storm costs which were amortized for recovery over multi-year periods.

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In 2017, Depreciation and Amortization expense increased $0.3 million, or 0.6%, compared to 2016, reflecting higher utility plant assets in service, partially offset by lower amortization of deferred major storm costs which were amortized for recovery over multi-year periods.

Taxes Other Than Income Taxes—Taxes Other Than Income Taxes increased $1.3 million, or 6.2%, in 2018 compared to 2017, primarily reflecting higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

In 2017, Taxes Other Than Income Taxes increased $1.5 million, or 7.7%, compared to 2016, primarily reflecting higher local property tax rates on higher levels of utility plant assets in service.

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. Certain reconciling rate mechanisms used by the Company’s distribution utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated (See Note 5 to the accompanying Consolidated Financial Statements).

Interest Expense, net increased $0.9 million, or 3.9%, in 2018 compared to 2017 reflecting interest on higher short-term debt rates and higher levels of long-term debt.

In 2017, Interest Expense, increased $0.6 million, or 2.7%, compared to 2016 reflecting interest on higher levels of short-term debt, partially offset by higher net interest income on regulatory assets/liabilities and repayment of higher cost long-term debt.

Other Expense (Income), net

Other Expense, net was essentially unchanged in 2018 compared to 2017 and increased $0.6 million in 2017 compared to 2016. The increase in 2017 reflects higher retirement benefit costs in 2017 compared to 2017. In 2018, the Company adopted ASU No. 2017-07, “Compensation – Retirement Benefits (Topic 715)” which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-K for the year ended December 31, 2018, the service cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Other Expense (Income), net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. There are $5.5 million, $5.7 million and $4.9 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for 2018, 2017 and 2018, respectively, net of amounts deferred as regulatory assets for future recovery.

Income Taxes

Federal and State Income Taxes decreased $9.1 million in 2018 compared to 2017 reflecting $6.3 million from the lower tax rate on pre-tax earnings in 2018 and the current tax benefit of $2.8 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018. (See Note 9 to the accompanying Consolidated Financial Statements).

In 2017, Income Taxes increased $2.1 million compared to 2016 reflecting higher pre-tax earnings in 2017.

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LIQUIDITY, COMMITMENTS AND CAPITAL REQUIREMENTS

Sources of Capital

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

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. At December 31, 2018 and December 31, 2017, 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 (the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends to July 25, 2023, subject to two one-year extensions 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%. Provided there is no event of default, the Company may increase the borrowing limit under the Credit Facility by up to $50 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $265.6 million and $234.9 million for the years ended December 31, 2018 and December 31, 2017, respectively. Total gross repayments were $221.1 million and $278.5 million for the years ended December 31, 2018 and December 31, 2017, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2018 and December 31, 2017:

Revolving Credit Facility (millions)
	December 31,
	2018		2017
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	82.8	$	38.3
Letters of Credit Outstanding	$	—	$	0
Available	$	37.2	$	81.7

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2018 and December 31, 2017, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 5.)

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Issuance of Long-Term Debt—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.

On November 1, 2017, Northern Utilities issued $20 million of Notes due 2027 at 3.52% and $30 million of Notes due 2047 at 4.32%. Fitchburg issued $10 million of Notes due 2027 at 3.52% and $15 million of Notes due 2047 at 4.32%. Granite State issued $15 million of Notes due 2027 at 3.72%. Northern Utilities, Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017, to repay short-term debt and for general corporate purposes. Approximately $0.7 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

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.

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2018, there are $2.8 million of current and $2.3 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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.

Contractual Obligations

The table below lists the Company’s known specified contractual obligations as of December 31, 2018.

			Payments Due by Period
Contractual Obligations (millions) as of December 31, 2018	Total		2019		2020— 2021		2022— 2023		2024 & Beyond
Long-Term Debt	$	409.3	$	18.8	$	28.4	$	34.9	$	327.2
Interest on Long-Term Debt		303.9		22.3		41.4		36.7		203.5
Gas Supply Contracts		489.9		41.2		69.1		70.5		309.1
Electric Supply Contracts		14.1		1.7		2.7		2.2		7.5
Other (Including Capital and Operating Lease Obligations)		10.4		4.5		4.7		1.1		0.1
Total Contractual Cash Obligations	$	1,227.6	$	88.5	$	146.3	$	145.4	$	847.4

The Company and its subsidiaries have material energy supply commitments that are discussed in Note 7 to the accompanying Consolidated Financial Statements. Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

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 December 31, 2018, there were approximately $4.3 million of guarantees outstanding.

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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 $8.4 million and $8.5 million of natural gas storage inventory at December 31, 2018 and 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2018, which was payable in January 2019, was $0.9 million and recorded in Accounts Payable at December 31, 2018. The amount of natural gas inventory released in December 2017, which was payable in January 2018, was $3.1 million and recorded in Accounts Payable at December 31, 2017.

Benefit Plan Funding

The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amounts of $16.6 million and $4.1 million in 2018 and 2017, respectively. The Company, along with its subsidiaries, contributed $4.0 million to Voluntary Employee Benefit Trusts (VEBTs) in each of 2018 and 2017. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in 2019 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these benefit plans. See Note 10 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of December 31, 2018, 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 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Cash Flows

Unitil’s utility operations, taken as a whole, are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The tables below summarize the major sources and uses of cash (in millions) for 2018 and 2017.

	2018		2017
Cash Provided by Operating Activities	$	78.5	$	86.2

Cash Provided by Operating Activities—Cash Provided by Operating Activities was $78.5 million in 2018, a decrease of $7.7 million compared to 2017.

Cash flow from net income, adjusted for the total of non-cash charges to depreciation, amortization and deferred taxes, was $91.4 million in 2018 compared to $93.4 million in 2017, reflecting a decrease of $2.0 million. The increase in net income of $4.0 million in 2018 compared to 2017 is primarily attributable to increases in natural gas margins and customer growth. The increase in depreciation and amortization of $3.5 million in 2018 compared to 2017 reflects higher utility depreciation from higher net utility plant in service, partially offset by decreases in amortization of prior storm costs. The decrease in the deferred tax provision of $9.5 million in 2018 compared to 2017 is primarily a result of decreased tax depreciation deductions and due to the reduction of the corporate income tax rate per the TCJA.

Changes in working capital items resulted in a $3.9 million source of cash in 2018 compared to a ($9.7) million use of cash in 2017, representing an increase of $13.6 million. The change in working capital in 2018 compared to 2017 is reflective of normal fluctuations in business and operating conditions.

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Deferred Regulatory and Other Charges decreased by $5.2 million in 2018 compared to 2017. The change in Other, net in 2018 compared to 2017 was ($14.1) million, primarily driven by increased contributions to the Company’s retirement plans.

	2018			2017
Cash (Used in) Investing Activities	$	(102.4	)	$	(119.3	)

Cash (Used in) Investing Activities—Cash Used in Investing Activities was ($102.4) million in 2018 compared to ($119.3) million in 2017. The actual capital spending in both 2018 and 2017 is related to utility capital expenditures for electric and gas utility system additions. The lower spending in 2018 is largely attributable to special major information technology investments and the construction of a new distribution operations center for Fitchburg, which were in addition to the normal level of utility capital expenditures. The Company’s projected capital spending range for 2019 is $120 million to $130 million.

	2018		2017
Cash Provided by Financing Activities	$	22.8	$	36.2

Cash Provided by Financing Activities—Cash Provided by Financing Activities was $22.8 million in 2018 compared to $36.2 million in 2017. The lower cash provided by financing activities in 2018 compared to 2017 is primarily attributable to the repayment of long-term debt of ($12.9) million. Other changes in financing activities in 2018 compared to 2017 total ($0.5) million.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the Company and its subsidiaries issue long-term debt contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions, business combinations and covenants restricting the ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets. See Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Unitil’s Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2018 and December 31, 2017, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The Company and its subsidiaries are currently in compliance with all such covenants in these debt instruments.

DIVIDENDS

Unitil’s annual common dividend was $1.46 per common share in 2018, $1.44 per common share in 2017, and $1.42 per share in 2016. Unitil’s dividend policy is reviewed periodically by the Board of Directors. Unitil has maintained an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2019 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.370 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.48 from $1.46. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will

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depend upon business conditions, results of operations, financial conditions and other factors. In addition, the ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil, and, therefore, Unitil’s ability to pay dividends, depends on, among other things:

• the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

• the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

• the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

• limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.

In addition, before the Company can pay dividends on its common stock, it has to satisfy its debt obligations and comply with any statutory or contractual limitations. See Financial Covenants and Restrictions, above, as well as Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

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. Refer to “Legal Proceedings” in Note 8 of the Consolidated Financial Statements for a discussion of legal proceedings.

REGULATORY MATTERS

See Note 8 to the Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s Consolidated 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. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the financial statements and Note 1: Summary of Significant Accounting Policies.

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 MDPU, Unitil Energy is regulated by the NHPUC and Northern Utilities is regulated by the 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 Financial Accounting Standards Board Accounting Standards Codification (FASB Codification). In accordance with 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.

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The FASB Codification specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets.” If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities.”

The Company’s principal regulatory assets and liabilities are included on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided in Note 1 thereto. Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. 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.

Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are 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.

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 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.

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. 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.

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Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of its employees. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The FASB Codification requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates. The Company’s RBO and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For the year ended December 31, 2018, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $589,000 in the Net Periodic Benefit Cost for the Pension Plan. Similarly, a change of 0.50% in the expected long-term rate of return on plan assets would have resulted in an increase or decrease of approximately $502,000 in the Net Periodic Benefit Cost for the Pension Plan. (See Note 10 to the accompanying Consolidated Financial Statements).

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 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 deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company 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 that gave rise to the revision become known.

Commitments and Contingencies—The Company’s accounting policy is to record a nd/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2018, the Company is not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

Refer to “Recently Issued Pronouncements” in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.

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For further information regarding the foregoing matters, see Note 1 (Summary of Significant Accounting Policies), Note 9 (Income Taxes), Note 7 (Energy Supply), Note 10 (Retirement Benefit Plans) and Note 8 (Commitment and Contingencies) to the Consolidated Financial Statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Please also refer to Part I, Item 1A. “Risk Factors”.

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 rate on short-term borrowings and intercompany money pool transactions was 3.3%, 2.4%, and 1.8% during 2018, 2017, and 2016, respectively.

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. Additionally, as discussed in the section entitled Rates and Regulation in Part I, Item 1 (Business) and in Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Unitil Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statements of earnings, changes in common stock equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of

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records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Boston, MA

January 31, 2019

We have served as the Company’s auditor since 2014.    

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CONSOLIDATED STATEMENTS OF EARNINGS     

(Millions, except per share data)

Year Ended December 31,	2018		2017		2016
Operating Revenues:
Gas	$	216.1	$	194.0	$	181.2
Electric		223.3		206.2		196.1
Other		4.7		6.0		6.1
Total Operating Revenues		444.1		406.2		383.4
Operating Expenses:
Cost of Gas Sales		99.2		84.3		77.6
Cost of Electric Sales		131.4		114.0		108.0
Operation and Maintenance		69.5		64.5		61.4
Depreciation and Amortization		50.4		46.9		46.6
Taxes Other Than Income Taxes		22.4		21.1		19.6
Total Operating Expenses		372.9		330.8		313.2
Operating Income		71.2		75.4		70.2
Interest Expense, net		24.0		23.1		22.5
Other Expense (Income), net		5.8		5.8		5.2
Income Before Income Taxes		41.4		46.5		42.5
Income Taxes		8.4		17.5		15.4
Net Income Applicable to Common Shares	$	33.0	$	29.0	$	27.1
Earnings per Common Share—Basic and Diluted	$	2.23	$	2.06	$	1.94
Weighted Average Common Shares Outstanding—(Basic and Diluted)		14.8		14.1		14.0

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

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CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS

December 31,	2018		2017
Current Assets:
Cash and Cash Equivalents	$	7.8	$	8.9
Accounts Receivable, net		66.8		67.4
Accrued Revenue		54.7		53.3
Exchange Gas Receivable		8.1		5.8
Gas Inventory		0.8		0.6
Materials and Supplies		7.0		6.9
Prepayments and Other		7.0		8.4
Total Current Assets		152.2		151.3
Utility Plant:
Gas		760.6		699.6
Electric		500.1		476.7
Common		83.1		67.4
Construction Work in Progress		25.5		35.5
Utility Plant		1,369.3		1,279.2
Less: Accumulated Depreciation		332.5		307.7
Net Utility Plant		1,036.8		971.5
Other Noncurrent Assets:
Regulatory Assets		99.0		109.6
Other Assets		10.3		9.5
Total Other Noncurrent Assets		109.3		119.1
TOTAL ASSETS	$	1,298.3	$	1,241.9

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

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CONSOLIDATED BALANCE SHEETS (cont.) (Millions, except number of shares) 

LIABILITIES AND CAPITALIZATION

December 31,	2018		2017
Current Liabilities:
Accounts Payable	$	42.6	$	41.5
Short-Term Debt		82.8		38.3
Long-Term Debt, Current Portion		18.4		29.8
Regulatory Liabilities		11.5		9.2
Energy Supply Obligations		13.4		9.7
Environmental Obligations		0.6		0.5
Capital Lease Obligations		3.1		3.1
Other Current Liabilities		20.1		18.9
Total Current Liabilities		192.5		151.0
Noncurrent Liabilities:
Retirement Benefit Obligations		121.5		150.1
Deferred Income Taxes, net		97.8		82.9
Cost of Removal Obligations		90.7		84.3
Regulatory Liabilities		47.0		48.9
Capital Lease Obligations		2.7		5.7
Environmental Obligations		1.4		1.6
Other Noncurrent Liabilities		6.0		4.3
Total Noncurrent Liabilities		367.1		377.8
Capitalization:
Long-Term Debt, Less Current Portion		387.4		376.3
Stockholders’ Equity:
Common Equity (Outstanding 14,876,955 and 14,815,585 Shares)		279.1		275.8
Retained Earnings		72.0		60.8
Total Common Stock Equity		351.1		336.6
Preferred Stock		0.2		0.2
Total Stockholders’ Equity		351.3		336.8
Total Capitalization		738.7		713.1
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,298.3	$	1,241.9

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions)                

Year Ended December 31,	2018			2017			2016
Operating Activities:
Net Income	$	33.0		$	29.0		$	27.1
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		50.4			46.9			46.6
Deferred Tax Provision		8.0			17.5			15.4
Changes in Working Capital Items:
Accounts Receivable		0.6			(14.5	)		(5.4	)
Accrued Revenue		(1.4	)		(3.8	)		(11.1	)
Regulatory Liabilities		2.3			(1.2	)		(5.2	)
Exchange Gas Receivable		(2.3	)		2.5			2.8
Accounts Payable		1.1			9.1			(0.9	)
Other Changes in Working Capital Items		3.6			(1.8	)		(1.0	)
Deferred Regulatory and Other Charges		(11.3	)		(6.1	)		(5.0	)
Other, net		(5.5	)		8.6			5.0
Cash Provided by Operating Activities		78.5			86.2			68.3
Investing Activities:
Property, Plant and Equipment Additions		(102.4	)		(119.3	)		(98.1	)
Cash Used In Investing Activities		(102.4	)		(119.3	)		(98.1	)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net		44.5			(43.6	)		39.9
Issuance of Long-Term Debt		29.9			89.3			30.0
Repayment of Long-Term Debt		(30.1	)		(17.2	)		(19.0	)
Decrease in Capital Lease Obligations		(3.0	)		(2.5	)		(2.8	)
Net Increase (Decrease) in Exchange Gas Financing		2.1			(2.4	)		(2.5	)
Dividends Paid		(21.8	)		(20.4	)		(20.0	)
Proceeds from Issuance of Common Stock		1.2			33.0			1.3
Cash Provided by Financing Activities		22.8			36.2			26.9
Net (Decrease) Increase in Cash		(1.1	)		3.1			(2.9	)
Cash at Beginning of Year		8.9			5.8			8.7
Cash at End of Year	$	7.8		$	8.9		$	5.8
Supplemental Information:
Interest Paid	$	24.6		$	23.0		$	22.1
Income Taxes Paid	$	0.4		$	—		$	1.6
Payments on Capital Leases	$	3.3		$	3.3		$	3.4
Capital Expenditures Included in Accounts Payable	$	0.5		$	1.1		$	0.3
Non-Cash Additions to Property, Plant and Equipment	$	—		$	—		$	3.5

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

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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Millions, except shares data)                

	Common Equity		Retained Earnings			Total
Balance at January 1, 2016	$	237.5	$	45.1		$	282.6
Net Income for 2016				27.1			27.1
Dividends ($1.42 per Common Share)				(20.0	)		(20.0	)
Shares Issued Under Stock Plans		1.9					1.9
Issuance of 32,095 Common Shares (See Note 6)		1.3					1.3
Balance at December 31, 2016		240.7		52.2			292.9
Net Income for 2017				29.0			29.0
Dividends ($1.44 per Common Share)				(20.4	)		(20.4	)
Shares Issued Under Stock Plans		2.1					2.1
Issuance of 26,256 Common Shares (See Note 6)		1.3					1.3
Issuance of 690,000 Common Shares (See Note 6)		31.7					31.7
Balance at December 31, 2017		275.8		60.8			336.6
Net Income for 2018				33.0			33.0
Dividends ($1.46 per Common Share)				(21.8	)		(21.8	)
Shares Issued Under Stock Plans		2.1					2.1
Issuance of 25,932 Common Shares (See Note 6)		1.2					1.2
Balance at December 31, 2018	$	279.1	$	72.0		$	351.1

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

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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. are 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 capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate 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 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) are wholly- owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers.

Basis of Presentation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation related to the adoption of new accounting standards.

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

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Fair Value—The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:

Level 1—	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2—	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3—	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

There have been no changes in the valuation techniques used during the current period.

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.

In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017 recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the twelve months ended December 31, 2018. A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and

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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.

As discussed below, the Company plans to disclose billed and unbilled revenue separately from rate adjustment mechanism revenue in the Notes to the Consolidated Financial Statements for periods in 2018 going forward, and will also provide this disclosure for prior periods for informational purposes.

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. The lower revenues reported in the twelve months ended December 31, 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act of 2017 (TCJA) are shown separately in the tables below for informational purposes.

	Twelve Months Ended December 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	81.4		$	123.6		$	205.0
Commercial & Industrial		119.7			96.4			216.1
Other		13.3			11.3			24.6
Revenue Reductions—TCJA		(3.7	)		(2.6	)		(6.3	)
Total Billed and Unbilled Revenue		210.7			228.7			439.4
Rate Adjustment Mechanism Revenue		5.4			(5.4	)		—
Total Gas and Electric Operating Revenues	$	216.1		$	223.3		$	439.4
	Twelve Months Ended December 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	71.2		$	107.9		$	179.1
Commercial & Industrial		102.8			87.7			190.5
Other		13.5			6.0			19.5
Total Billed and Unbilled Revenue		187.5			201.6			389.1
Rate Adjustment Mechanism Revenue		6.5			4.6			11.1
Total Gas and Electric Operating Revenues	$	194.0		$	206.2		$	400.2
	Twelve Months Ended December 31, 2016
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	61.5		$	101.9		$	163.4
Commercial & Industrial		92.7			81.5			174.2
Other		11.2			4.9			16.1
Total Billed and Unbilled Revenue		165.4			188.3			353.7
Rate Adjustment Mechanism Revenue		15.8			7.8			23.6
Total Gas and Electric Operating Revenues	$	181.2		$	196.1		$	377.3

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

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difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the MDPU. 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—Usource, Unitil’s non-regulated subsidiary, conducts its business activities as a broker of competitive energy services. Usource does not take title to the electric and gas commodities which are the subject of the brokerage contracts. The Company records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partners with certain entities to facilitate these brokerage services and pays these entities a fee under revenue sharing agreements.

As discussed above, the Company adopted ASU 2014-09 in the first quarter of 2018. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. ASU 2014-09 requires that payments made by Usource to third parties (Channel Partners) for revenue sharing agreements are recognized net, as a reduction from revenue, where those payments were previously recognized gross as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to third parties for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $1.0 million, $1.1 million and $1.0 million in 2018, 2017 and 2016, respectively.

If ASU 2014-09 had been in effect for 2017 and 2016, the result would have been corresponding reductions of $1.1 million and $1.0 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below.

Other Operating Revenues ($ millions):	Twelve Months Ended December 31
	As Reported			If ASU 2014-09 Had Been in Effect
	2018			2017			2016
Usource Contract Revenue	$	5.7		$	6.0		$	6.1
Less: Revenue Sharing Payments		(1.0	)		(1.1	)		(1.0	)
Total Other Operating Revenues	$	4.7		$	4.9		$	5.1

Operation and Maintenance Expense ($ millions):	Twelve Months Ended December 31
	As Reported		If ASU 2014-09 Had Been in Effect
	2018		2017		2016
Operation and Maintenance Expense	$	69.5	$	63.4	$	60.4

Retirement Benefit Costs—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan) and the Unitil Corporation Supplemental Executive Retirement Plan (SERP).The net periodic benefit costs associated with these benefit plans consist of service cost and other components (See Note 10 to the Consolidated Financial Statements). In the first quarter of 2018, the Company adopted ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net

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benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-K for the twelve months ended December 31, 2018, the service cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Other Expense (Income), net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. The change in presentation for the twelve months ended December 31, 2018 resulted in a reduction of “Operations and Maintenance” and an increase in “Other Expense (Income), net” on the Consolidated Statements of Earnings for the prior periods. There are $5.5 million, $5.7 million and $4.9 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the twelve months ended December 31, 2018, 2017 and 2016, respectively, net of amounts deferred as regulatory assets for future recovery.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2018 – 3.38%, 2017 – 3.45% and 2016 – 3.49%.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes—The Company bills its customers sales tax in Massachusetts and Maine and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings. The consumption tax in New Hampshire has been repealed effective January 1, 2019.

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 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 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.

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2018 the Company paid quarterly dividends of $0.365 per share, resulting in an

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annualized dividend rate of $1.46 per common share. For the years ended December 31, 2017 and 2016, the Company paid quarterly dividends of $0.36 and $0.355 per common share, respectively, resulting in annualized dividend rates of $1.44 and $1.42 per common share, respectively. At its January 2019 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.37 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.48 per share from $1.46 per share.

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2018 and 2017, the Unitil subsidiaries had deposited $3.5 million and $2.9 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2018 and 2017.

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. 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.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2018 and 2017.

Accrued Revenue (millions)	December 31,
	2018		2017
Regulatory Assets—Current	$	41.3	$	39.5
Unbilled Revenues		13.4		13.8
Total Accrued Revenue	$	54.7	$	53.3

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 December 31, 2018 and 2017.

Exchange Gas Receivable (millions)	December 31,
	2018		2017
Northern Utilities	$	7.5	$	5.4
Fitchburg		0.6		0.4
Total Exchange Gas Receivable	$	8.1	$	5.8

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Gas Inventory—The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of December 31, 2018 and 2017.

Gas Inventory (millions)	December 31,
	2018		2017
Natural Gas	$	0.3	$	0.4
Propane		0.4		0.1
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	0.8	$	0.6

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.70%, 2.90% and 2.18% in 2018, 2017 and 2016, respectively. 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 December 31, 2018 and 2017, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $90.7 million and $84.3 million, respectively.

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.

Regulatory Assets consist of the following (millions)	December 31,
	2018		2017
Retirement Benefits	$	72.0	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		38.4		36.0
Deferred Storm Charges		6.3		7.2
Environmental		7.9		9.5
Income Taxes		5.7		6.5
Other Deferred Charges		10.0		5.4
Total Regulatory Assets	$	140.3	$	149.1
Less: Current Portion of Regulatory Assets(1)		41.3		39.5
Regulatory Assets—noncurrent	$	99.0	$	109.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions)	December 31,
	2018		2017
Rate Adjustment Mechanisms	$	11.5	$	6.9
Gas Pipeline Refund		—		2.3
Income Taxes (Note 9)		47.0		48.9
Total Regulatory Liabilities		58.5		58.1
Less: Current Portion of Regulatory Liabilities		11.5		9.2
Regulatory Liabilities—noncurrent	$	47.0	$	48.9

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Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2018 are $6.0 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material 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 qualify as a derivative instrument under the guidance set forth in the FASB Codification.

The Company previously operated a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service, which included use of derivative instruments. The hedging program was terminated in 2018.

Under the hedging program previously operated by Northern Utilities, any gains or losses resulting from the change in the fair value of these derivatives were passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause. The fair value of these derivatives was determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company recorded gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassified these gains or losses into Cost of Gas Sales when the gains and losses were passed through to customers through the Cost of Gas Clause.

As of December 31, 2018 and December 31, 2017, the Company had zero and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program. The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31, 2018 and December 31, 2017. There was zero and $0.4 million of losses / (gains) recognized in Regulatory Assets / Liabilities for the years ended December 31, 2018 and 2017, respectively. There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31, 2018 and 2017.

Investments in Marketable Securities—The Company maintains 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 Supplemental Executive Retirement Plan (SERP) (See further discussion of the SERP in Note 10).

At December 31, 2018 and 2017, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $4.8 million and $3.6 million, respectively, as shown in the table below. These investments are valued based on quoted

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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.

Fair Value of Marketable Securities (millions)	December 31,
	2018		2017
Equity Funds	$	—	$	2.1
Fixed Income Funds		—		1.5
Money Market Funds		4.8		—
Total Marketable Securities	$	4.8	$	3.6

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

	December 31,
Energy Supply Obligations consist of the following: (millions)	2018		2017
Current:
Exchange Gas Obligation	$	7.5	$	5.4
Renewable Energy Portfolio Standards		5.6		4.0
Power Supply Contract Divestitures		0.3		0.3
Total Energy Supply Obligations—Current	$	13.4	$	9.7
Noncurrent:
Power Supply Contract Divestitures	$	0.6	$	0.9
Total Energy Supply Obligations	$	14.0	$	10.6

Exchange Gas Obligation—As discussed above, 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 maintain accrued revenue 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 filed with MDPU in 2018 and approvals remain pending.

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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—Unitil Energy’s and Fitchburg’s customers are entitled 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 (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (noncurrent portion).

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements—As of December 31, 2018, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2018, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2018, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements— In August 2018, the FASB issued Accounting Standards Update (ASU) No. 2018-14, “Compensation—Retirement Benefits—Defined Benefit Plans—General (Sutopic 715-20)” which amends existing guidance to add, remove and clarify disclosure requirements related to

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defined benefit pension and other postretirement plans. The ASU is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company adopted this ASU in the fourth quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

In June 2018, the FASB issued ASU No. 2018-07, “Compensation—Stock Compensation (Topic 718)” which amends the existing guidance relating to the accounting for nonemployee share-based payments. Under this ASU, most of the guidance on share-based payments to nonemployees will be aligned with the requirements for share-based payments granted to employees. The ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted this ASU in the second quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715)” which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for the Company on January 1, 2018. The change in capitalization of retirement benefits did not have a material impact on the Company’s Consolidated Financial Statements.

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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company plans to adopt the standard as of January 1, 2019. The Company will elect 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 will also elect 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 will make an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company will recognize those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The Company expects that adoption of the standard will result 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 does not believe the standard will have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.

The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales.

The Company used the modified retrospective method when adopting the new standard on January 1, 2018. The new guidance did not have a material impact to the Consolidated Financial Statements. (See “Utility Revenue Recognition” and “Other Operating Revenue—Non-regulated” above.)

In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A

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financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. The ASU became effective for the Company on January 1, 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

Other than the pronouncements 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 evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

Note 2: Quarterly Financial Information (unaudited; millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented.

	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2018		2017		2018		2017		2018		2017		2018		2017
Total Operating Revenues	$	145.8	$	126.0	$	84.5	$	80.8	$	88.2	$	84.0	$	125.6	$	115.4
Operating Income	$	28.1	$	27.7	$	10.6	$	11.6	$	10.3	$	10.4	$	22.2	$	25.7
Net Income Applicable to Common	$	15.6	$	12.4	$	3.6	$	3.1	$	2.8	$	2.3	$	11.0	$	11.2
	Per Share Data:
Earnings Per Common Share	$	1.06	$	0.88	$	0.24	$	0.23	$	0.19	$	0.16	$	0.74	$	0.79
Dividends Paid Per Common Share	$	0.365	$	0.360	$	0.365	$	0.360	$	0.365	$	0.360	$	0.365	$	0.360

Note 3: Segment Information

Unitil reports three segments: utility gas operations, utility electric operations and non-regulated. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area 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.

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

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated column below.

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

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

The following table provides significant segment financial data for the years ended December 31, 2018, 2017 and 2016 (millions):

Year Ended December 31, 2018	Gas		Electric			Non- Regulated		Other			Total
Revenues:
Billed and Unbilled Revenue	$	210.7	$	228.7		$	—	$	—		$	439.4
Rate Adjustment Mechanism Revenue		5.4		(5.4	)		—		—			—
Other Operating Revenue—Non-Regulated		—		—			4.7		—			4.7
Total Operating Revenues	$	216.1	$	223.3		$	4.7	$	—		$	444.1
Interest Income		0.8		0.8			0.2		0.6			2.4
Interest Expense		14.2		9.0			—		3.2			26.4
Depreciation & Amortization Expense		24.9		23.1			0.1		2.3			50.4
Income Tax Expense (Benefit)		7.1		4.2			0.5		(3.4	)		8.4
Segment Profit		18.8		11.4			1.3		1.5			33.0
Segment Assets		764.1		484.2			6.9		43.1			1,298.3
Capital Expenditures		70.8		28.4			—		3.2			102.4
Year Ended December 31, 2017
Revenues	$	194.0	$	206.2		$	6.0	$	—		$	406.2
Interest Income		0.7		1.0			0.1		0.6			2.4
Interest Expense		13.7		8.8			—		3.0			25.5
Depreciation & Amortization Expense		22.4		23.4			0.1		1.0			46.9
Income Tax Expense (Benefit)		10.7		7.5			0.7		(1.4	)		17.5
Segment Profit		16.4		11.9			1.2		(0.5	)		29.0
Segment Assets		714.3		476.9			6.7		44.0			1,241.9
Capital Expenditures		72.1		33.7			—		13.5			119.3
Year Ended December 31, 2016
Revenues	$	181.2	$	196.1		$	6.1	$	—		$	383.4
Interest Income		0.2		0.7			0.1		0.2			1.2
Interest Expense		13.3		8.3			—		2.1			23.7
Depreciation & Amortization Expense		21.9		23.8			0.1		0.8			46.6
Income Tax Expense (Benefit)		9.2		6.6			0.8		(1.2	)		15.4
Segment Profit		14.5		11.1			1.1		0.4			27.1
Segment Assets		645.2		441.1			6.8		35.1			1,128.2
Capital Expenditures		57.0		30.1			—		11.0			98.1

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Note 4: Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2018, 2017 and 2016, the Company recorded provisions for the energy commodity portion of bad debts of $2.6 million, $1.3 million and $1.6 million, respectively. These provisions were recognized in Cost of Gas Sales and Cost of Electric Sales expense as the associated electric and gas utility revenues were billed. Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling 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.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2016—2018 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision			Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2018
Electric	$	0.9	$	3.2		$	0.3	$	3.9	$	0.5
Gas		0.6		2.9			0.3		3.0		0.8
Other		0.1		(0.1	)		—		—		—
	$	1.6	$	6.0		$	0.6	$	6.9	$	1.3
Year Ended December 31, 2017
Electric	$	0.8	$	1.8		$	0.3	$	2.0	$	0.9
Gas		0.2		1.9			0.3		1.8		0.6
Other		0.1		—			—		—		0.1
	$	1.1	$	3.7		$	0.6	$	3.8	$	1.6
Year Ended December 31, 2016
Electric	$	0.6	$	2.9		$	0.3	$	3.0	$	0.8
Gas		0.5		1.7			0.3		2.3		0.2
Other		0.1		—			—		—		0.1
	$	1.2	$	4.6		$	0.6	$	5.3	$	1.1

Note 5: Debt and Financing Arrangements

The Company funds a portion of its operations through the issuance of long-term debt and through short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow:

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants—The agreements under which the long-term debt of Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations, as described below.

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt

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agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met; including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets.

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2018, in accordance with the covenants, these subsidiary companies had a combined amount of $249.2 million available for the payment of dividends and Unitil Corporation had $137.4 million available for the payment of dividends. As of December 31, 2018, the Company’s balance in Retained Earnings was $72.0 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2018 for the payment of dividends.

Issuance of Long-Term Debt—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.

On November 1, 2017, Northern Utilities issued $20 million of Notes due 2027 at 3.52% and $30 million of Notes due 2047 at 4.32%. Fitchburg issued $10 million of Notes due 2027 at 3.52% and $15 million of Notes due 2047 at 4.32%. Granite State issued $15 million of Notes due 2027 at 3.72%. Northern Utilities, Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017, to repay short-term debt and for general corporate purposes. Approximately $0.7 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $30.1 million, $17.2 million and $19.0 million in 2018, 2017, and 2016, respectively.

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The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2018 is: 2019 – $18.8 million; 2020 – $19.8 million; 2021 – $8.6 million; 2022 – $28.2 million; 2023 – $6.7 million and thereafter $327.2 million.

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.

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2018		2017
Estimated Fair Value of Long-Term Debt	$	422.0	$	457.1

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Details on long-term debt at December 31, 2018 and 2017 are shown below:

Long-Term Debt (millions)	December 31,
	2018		2017
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		10.0		15.0
8.49% Senior Secured Notes, Due October 14, 2024		6.0		7.5
6.96% Senior Secured Notes, Due September 1, 2028		20.0		20.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0
4.18% Senior Secured Notes, Due November 30, 2048		30.0		—
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		5.7		7.6
6.79% Senior Notes, Due October 15, 2025		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		—		10.0
5.29% Senior Notes, Due March 2, 2020		16.6		25.0
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
Granite State:
7.15% Senior Notes, Due December 15, 2018		—		3.3
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
Total Long-Term Debt		409.3		409.4
Less: Unamortized Debt Issuance Costs		3.5		3.3
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		405.8		406.1
Less: Current Portion		18.4		29.8
Total Long-Term Debt, Less Current Portion	$	387.4	$	376.3

Interest Expense, net—Interest expense is presented in the 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 calculated.

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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 monthly 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. A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2018			2017			2016
Interest Expense
Long-Term Debt	$	23.1		$	21.8		$	21.8
Short-Term Debt		2.6			2.5			1.4
Regulatory Liabilities		0.7			1.2			0.5
Subtotal Interest Expense		26.4			25.5			23.7
Interest Income
Regulatory Assets		(0.8	)		(0.7	)		(0.3	)
AFUDC(1) and Other		(1.6	)		(1.7	)		(0.9	)
Subtotal Interest Income		(2.4	)		(2.4	)		(1.2	)
Total Interest Expense, net	$	24.0		$	23.1		$	22.5

⁽¹⁾  AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends to July 25, 2023, subject to two one-year extensions 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%. Provided there is no event of default, the Company may increase the borrowing limit under the Credit Facility by up to $50 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $265.6 million and $234.9 million for the years ended December 31, 2018 and December 31, 2017, respectively. Total gross repayments were $221.1 million and $278.5 million for the years ended December 31, 2018 and December 31, 2017, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2018 and December 31, 2017:

Revolving Credit Facility (millions)
	December 31,
	2018		2017
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	82.8	$	38.3
Letters of Credit Outstanding	$	—	$	—
Available	$	37.2	$	81.7

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

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consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2018 and December 31, 2017, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The weighted average interest rates on all short-term borrowings were 3.3%, 2.4%, and 1.8% during 2018, 2017, and 2016, respectively.

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.

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2018, there are $2.8 million of current and $2.3 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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 $8.4 million and $8.5 million of natural gas storage inventory at December 31, 2018 and 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2018, which was payable in January 2019, was $0.9 million and recorded in Accounts Payable at December 31, 2018. The amount of natural gas inventory released in December 2017, which was payable in January 2018, was $3.1 million and recorded in Accounts Payable at December 31, 2017.

Leases

Unitil’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.

Total rental expense under operating leases charged to operations for the years ended December 31, 2018, 2017 and 2016 amounted to $2.2 million, $2.0 million and $1.8 million respectively.

Assets under capital leases amounted to approximately $15.0 million and $15.0 million as of December 31, 2018 and 2017, respectively, less accumulated amortization of $1.7 million and $0.7 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

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The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2018. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $2.7 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2018. $2.8 million of the current Capital Lease Obligations and $2.3 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s)	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

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 December 31, 2018, there were approximately $4.3 million of guarantees outstanding.

Note 6: Equity

The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding. Details regarding these forms of capitalization follow:

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 14,815,585 and 14,876,955 shares of common stock outstanding at December 31, 2017 and December 31, 2018, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2017 and December 31, 2018.

Unitil Corporation Common Stock Offering—On December 14, 2017, the Company issued and sold 690,000 shares of its common stock at a price of $48.30 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $31.7 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan—During 2018, the Company sold 25,932 shares of its common stock, at an average price of $47.78 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.2 million. 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. During 2017 and 2016, the Company raised $1.3 million and $1.3 million, respectively, through the issuance of 26,256 and 32,095 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014, the Company may periodically repurchase shares of its common stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. (See Part II, Item 5, for additional information). During 2018, 2017 and 2016, the Company repurchased 791, 1,686 and 1,949 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was less than $0.1 million, $0.1 million and $0.1 million in 2018, 2017 and 2016, respectively.

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During 2018, 2017 and 2016, the Company did not cancel or retire any of its common stock.

Stock-Based Compensation Plans—Unitil maintains a stock plan. The Company accounts for its stock-based compensation plan in accordance with the provisions of the FASB Codification and measures compensation costs at fair value at the date of grant. Details of the plan are as follows:

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.

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.

Restricted Shares issued for 2016 – 2018 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
1/26/16	43,220	$1.6
4/19/16	800	<$0.1
1/30/17	34,930	$1.6
1/29/18	37,510	$1.6

There were 29,252 and 89,326 non-vested shares under the Stock Plan as of December 31, 2018 and 2017, respectively. The weighted average grant date fair value of these shares was $42.86 per share and $39.54 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $2.2 million, $2.7 million and $2.2 million in 2018, 2017 and 2016, respectively. At December 31, 2018, there was approximately $0.8 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.3 years. There were 2,072 restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2018. On January 29, 2019, there were 33,150 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

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Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, 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 2018 and 2017 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2018				2017
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		52,224	$	36.22		43,345	$	33.40
Restricted Stock Units Granted		7,892	$	49.63		7,522	$	50.23
Dividend Equivalents Earned		1,673	$	47.85		1,357	$	48.57
Restricted Stock Units Settled		—		—		—		—
Ending Restricted Stock Units		61,789	$	38.25		52,224	$	36.22

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2018 and 2017 is $1.3 million and $1.0 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 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2018 and December 31, 2017. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2018 and December 31, 2017, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share (EPS).

(Millions except shares and per share data)	2018		2017		2016
Earnings Available to Common Shareholders	$	33.0	$	29.0	$	27.1
Weighted Average Common Shares Outstanding—Basic (000’s)		14,824		14,095		13,990
Plus: Diluted Effect of Incremental Shares (000’s)		5		7		6
Weighted Average Common Shares Outstanding—Diluted (000’s)		14,829		14,102		13,996
Earnings per Share—Basic and Diluted	$	2.23	$	2.06	$	1.94

The following table shows the number of weighted average non-vested restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.

	2018		2017		2016
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		6,102		8,733		600

Note 7: Energy Supply

NATURAL GAS SUPPLY

Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

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Northern Utilities’ C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third-party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2018, 79% of Unitil’s largest New Hampshire gas customers, representing 37% of Unitil’s New Hampshire gas therm sales and 68% of Unitil’s largest Maine customers, representing 23% of Unitil’s Maine gas therm sales, are purchasing gas supply from a third-party supplier.

Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many large and some medium C&I customers purchase their gas supply from third-party suppliers while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2018, 85% of Unitil’s largest Massachusetts gas customers, representing 26% of Unitil’s Massachusetts gas therm sales, are purchasing gas supply from third-party suppliers. The approved costs associated with natural gas supplied to customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

Regulated Natural Gas Supply

Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers largely under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), via over the road trucking of supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 4.3 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

Fitchburg purchases natural gas under contracts from producers and marketers largely under contracts of one year or less, and occasionally on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), via trucking of supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round transportation and 0.33 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

ELECTRIC POWER SUPPLY

Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2018, 77% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales and 81% of Unitil’s largest Massachusetts customers, representing 32% of Unitil’s Massachusetts electric kWh sales, are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have

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active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base and customers in Ashby comprise another 4%. Buoyed by the municipal aggregations, 31% of Unitil’s residential customers in Massachusetts purchase their electricity from a third-party supplier as of December 2018.

In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier stands at 10%, down slightly relative to prior years when 13% of Unitil’s residential customers in New Hampshire purchased their supply from third-party suppliers. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

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 and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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Long-Term Renewable Contracts

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 filed with MDPU in 2018 and approvals remain pending.

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.

Note 8: Commitments and Contingencies

Regulatory Matters

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MDPU, the NHPUC and the MPUC have each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31, 2017. The remaining balance of these assets is $0.9 million as of December 31, 2018, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $0.6 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next two years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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, has issued procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil has complied with these orders and has made the required changes to its rates as directed by the

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commissions. The FERC has opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below). 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.

In Maine, Northern Utilities’ Maine division recently completed a base rate case (described below). The MPUC’s final order in that docket incorporated the lower tax rates in the calculation of rates for the Company.

Similarly, in New Hampshire, Northern Utilities’ New Hampshire division recently completed a base rate case proceeding (described below). The NHPUC’s final order in that docket approved a comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which included the effect of the tax changes in the calculation of the revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC approved the Company’s annual step increase pursuant to the provisions of its last base rate case, which included adjustments to account for the TCJA’s income tax changes.

In Massachusetts, the MDPU issued an order opening an investigation into the effect on rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. On December 21, 2018 the MDPU issued an order addressing the refund of excess ADIT in phase two of its investigation. Fitchburg was ordered to make a filing by January 4, 2019, for rates effective February 1, 2019, to refund $10.1 million for the electric division amortized over 15 years and $10.4 million for the gas division amortized over 14 years. The filing establishes a “Tax Act Credit Factor” for Fitchburg’s gas and electric divisions effective February 1, 2019 in accordance with the order. To the extent any of the regulatory liability above includes excess ADIT amounts specifically associated with reconciling mechanisms, Fitchburg shall return those amounts through the respective reconciling mechanism and adjust the regulatory liability amount accordingly. The MDPU approved this filing on January 16, 2019.

On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reduction under the TCJA.

Base Rate Activity

Unitil Energy—Base Rates—On April 20, 2017 the NHPUC approved a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019 to recover the revenue requirements associated with annual capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s step adjustment filing. The filing incorporated the revenue requirement of $3.3 million for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of the one-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resulted in a revenue decrease of $0.3 million.

Fitchburg—Base Rates—Electric—Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue

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requirement associated with certain capital additions. While a number of the capital cost recovery filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. On November 1, 2018, Fitchburg filed its cumulative revenue requirement associated with the Company’s 2015, 2016 and 2017 capital expenditures and associated Capital Cost Adjustment Factors to become effective on January 1, 2019. On December 27, 2018, the Capital Cost Adjustment Factors were approved subject to further investigation and reconciliation. This matter remains pending.

Fitchburg—Electric Grid Modernization—On May 10, 2018, the MDPU issued an order approving a three year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Massachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to address pre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.

Fitchburg—Solar Generation—On November 9, 2016, the MDPU approved Fitchburg’s petition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing sought a net amount of approximately $0.3 million for recovery effective June 1, 2018. The recovery of this amount in rates was approved by the MDPU on May 31, 2018, subject to further investigation and reconciliation. A final order is pending.

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.

Fitchburg—Gas System Enhancement Program—Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. While a number of the filings under the GSEP tariff may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff, a revenue increase of $0.9 million went into effect on May 1, 2018, subject to the annual cap and reconciliation. On October 31, 2018, the MDPU approved the Company’s request for a waiver of the annual cap in order to recover its reconciliation adjustment of $0.4 million effective November 1, 2018 associated with its actual 2017 revenue requirement.

Northern Utilities—Base Rates—Maine—On February 28, 2018, the MPUC issued its Final Order (Order) in Northern Utilities’ pending base rate case. The Order provided for an annual revenue increase of $2.1 million before a reduction of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million, and addressed a number of other issues, including a change to therm billing, increases in other

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delivery charges, and cost recovery under the Company’s Targeted Area Build-out (TAB) program and Targeted Infrastructure Replacement Adjustment (TIRA) mechanism. The new rates and other changes became effective on March 1, 2018.

Northern Utilities—Targeted Infrastructure Replacement Adjustment—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). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, 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, to recover the revenue requirements for 2017 eligible facilities.

Northern Utilities—Targeted Area Build-out Program—Maine—In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.

Northern Utilities—Base Rates—New Hampshire—On May 2, 2018, the NHPUC approved a settlement agreement providing for an annual revenue increase of $2.6 million, a reduction of annual revenue of $1.7 million to reflect the effect of the TCJA, and a step increase of $2.3 million to recover post-test year capital investments, all effective May 1, 2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case will be based on an historic test year of no earlier than twelve months ending December 31, 2020.

Northern Utilities—Franchise Extensions—New Hampshire—On October 3, 2018, the NHPUC granted Northern Utilities authority to expand its natural gas service territory in the Towns of Kingston, New Hampshire and Atkinson, New Hampshire (where the Company already had a limited franchise) to serve new industrial, commercial and residential customers. Northern Utilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and residential developments present the Company with opportunities for growth. The franchise petition for service to the Town of Epping 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. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding—On August 2, 2016, the NHPUC issued an order establishing an Energy Efficiency Resource Standard (EERS), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet.

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The EERS includes a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs, and performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Order, on September 1, 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plan for the period 2018-2020, which was approved on January 2, 2018. On September 14, 2018, the New Hampshire electric and gas utilities jointly filed its 2019 update to the Statewide Energy Efficiency Plan. On December 31, 2018, the Commission approved a settlement agreement regarding the 2019 update to the plan.

Unitil Energy—Electric Grid Modernization—In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The final report was filed on March 20, 2017. This matter remains pending.

Unitil Energy—Net Metering—Pursuant to legislation that became effective in May 2016, the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The NHPUC issued an Order on June 23, 2017. The Order removes the cap on the total amount of generation capacity which may be owned or operated by customer-generators eligible for net metering. The order also adopts an alternative net metering tariff for small customer-generators (those with renewable energy systems of 100 kW or less) which will remain in effect for a period of years while further data is collected and analyzed, time-of-use and other pilot programs are implemented, and a distributed energy resource valuation study is conducted. Systems that are installed or queued during this period will have their net metering rate structure “grandfathered” until December 31, 2040. The Company does not believe that this proceeding will have a material adverse impact on the Company’s financial position, operating results or cash flows.

Unitil Energy—Recent Legislation—On September 13, 2018, the New Hampshire legislature voted to override New Hampshire Governor Sununu’s veto of Senate Bill 365. The enacted legislation requires Unitil Energy to enter into a power purchase agreement with a trash incinerator located in its service territory to purchase the facility’s entire net electrical output for a period that is coterminous with Unitil Energy’s next six default service procurements. The procurement is to be priced at the adjusted energy rate derived from the default service rates approved by the NHPUC in each applicable default service supply solicitation proceeding. The anticipated higher cost differential of the power purchase agreement is to be recovered through a non-by-passable charge applicable to all customers.

Fitchburg—Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System—On September 26, 2018, the Chairman of the MDPU directed the Department to procure and contract with 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 will issue a report that will include, but not be limited to, potential opportunities for improvement in each of these areas. Effective November 14, 2018, the MDPU engaged the evaluator to conduct the examination. On December 21, 2018, discovery was issued to the gas and municipal distribution companies, including the Company, and the Company provided its responses on January 9, 2019. The investigation is on-going.

Fitchburg—Electric Reconciliation Filing—The MDPU investigates and reviews Fitchburg’s annual filings which reconcile the costs and revenues in the Company’s various reconciliation accounts. Typically, the Reconciliation Filings are submitted during the fourth quarter for rates effective January 1 of the following year, and the MDPU approves them subject to reconciliation and pending further investigation. Subsequently, during the course of the year, the MDPU engages in more intensive review of these filings, including discovery and, when deemed necessary, the scheduling of evidentiary hearings. While a number of the Reconciling Filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

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Fitchburg—Service Quality—On March 1, 2018, Fitchburg submitted its 2017 Service Quality Reports for both its gas and electric divisions in accordance with new Service Quality Guidelines issued by the MDPU in December 2015. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. The MDPU approved the gas division’s filing on October 22, 2018. The electric division’s filing is pending approval.

Fitchburg—Energy Diversity—Massachusetts Governor Baker signed into law H.4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC), including Fitchburg, to jointly and competitively solicit proposals 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. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016, and adopted as final regulations on March 8, 2017. The EDCs issued the RFP for Long-Term Contracts for Clean Energy Projects, pursuant to Section 83d on March 31, 2017 and project proposals were received on July 27, 2017. Final selection of projects concluded in the first quarter of 2018, contracts were signed in June 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed the 83d long-term contracts with MDPU for approval. This matter remains pending. The EDCs issued the RFP for Long-Term Contracts for Offshore Wind Energy Projects pursuant to Section 83c on June 29, 2017 and project proposals were received on December 20, 2017. Final selection of projects was made in late May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed the 83c long-term contracts with MDPU for approval. This matter remains pending. A subsequent Section 83c solicitation is expected to be issued in June 2019.

Fitchburg—Recent Legislation—On August 9, 2018, Massachusetts Governor Baker signed into law H. 4857, “An Act to Advance Clean Energy.” The legislation contains numerous provisions, including: a requirement that increases the pace at which the Class 1 Renewable Portfolio Standard requirement increases, from the current pace of an additional 1 percent of sales each year to an additional 2 percent of sales each year during the period from January 1, 2020 through December 31, 2029; Electric supply contracts entered into after December 1, 2018 are required to provide a minimum percentage of kWh sales with clean peak resources, subject to regulations to be promulgated by the MDPU; Authorizes electric distribution companies to implement demand charges as part of a monthly minimum reliability charge provided the demand charge is based on system peak demand during the peak hours of the day and if affected customers are informed of the manner by which the demand charges are assessed and ways by which customers may manage and reduce demand; requires all gas distribution companies to report to the MDPU, in a uniform manner, lost and unaccounted for gas each year; Requires electric distribution companies to annually file with the MDPU an Electric Distribution System Resiliency Report which must include heat maps that show the electric load on the distribution system including loads during peak times, highlight the most congested or constrained areas of the distribution system and identify areas of the system most vulnerable to outages due to high electricity demand, lack of local generation, and extreme weather events; Establishes an energy storage target of 1,000 megawatt (MW) hours to be achieved by December 31, 2025, and requires each electric distribution company to submit a report to the Massachusetts Department of Energy Resources (DOER) documenting the energy storage installation in their service territory; Requires the DOER to investigate the necessity of requiring electric distribution companies to jointly conduct additional offshore wind generation solicitations and procurement of up to 1,600 MW of capacity in addition to the 1,600 MW required in H.4568 “An Act to Promote Energy Diversity”. Many of these provisions require further development and implementation by the MDPU and DOER. Fitchburg intends to actively participate in all such proceedings and will comply with all regulatory directives and requirements resulting from these legislative changes.

Fitchburg—Clean Energy RFP—Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg, issued an RFP for

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clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposals for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations concluded during the second quarter of 2017. On September 20, 2017, Fitchburg, along with the other three EDCs, filed for approval of the purchase power agreements which were negotiated as a result of the joint solicitation. A hearing on the merits was held in February 2018. The MDPU approved the agreements on June 15, 2018.

Fitchburg—Other—On August 25, 2017, the Massachusetts Department of Energy Resources (DOER) issued its final Solar Massachusetts Renewable Target (SMART) Program regulations. These regulations were promulgated pursuant to Chapter 75 of the Acts of 2016, which required the DOER to establish a new solar incentive program. The regulation is designed to support the continued development of an additional 1,600 MW of solar renewable energy generating sources via a declining block compensation mechanism. On September 12, 2017, the Massachusetts electric utilities jointly filed a model SMART tariff with the MDPU to implement the program and propose a cost recovery mechanism. Hearings on the merits were held in late March and early April 2018. The MDPU issued its Order on September 26, 2018 making the program effective on that date. The MDPU approved a final model tariff on November 20, 2018 and approved Fitchburg’s company specific tariff on December 21, 2018. On or before November 1 of each year the Company is required to submit to the MDPU its annual SMART Factor cost recovery filing for effect January 1 of the next year. On December 27, 2018, the MDPU approved Fitchburg’s proposed SMART Factors for effect January 1, 2019, subject to investigation and reconciliation. This matter remains pending.

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 and remains pending. 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.

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court, (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint sought an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an

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order denying class certification status in July 2016, though the plaintiffs’ individual claims remained pending. The Company resolved this matter by settlement in the fall of 2018 and there was no material impact on the Company’s financial position, operating results or cash flows.

Environmental Matters

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2018, 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 to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required.

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 Environmental Obligations for the years ended December 31, 2018 and 2017. The Company’s current and noncurrent environmental obligations are recorded on the Company’s Consolidated Balance Sheets in Other Current Liabilities and Other Noncurrent Liabilities, respectively.

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Environmental Obligations

	(millions)
	Fitchburg				Northern Utilities				Total
	2018		2017		2018		2017		2018		2017
Total Balance at Beginning of Period	$	0.1	$	0.1	$	2.0	$	1.8	$	2.1	$	1.9
Additions		—		—		0.3		0.4		0.3		0.4
Less: Payments / Reductions		0.1		—		0.3		0.2		0.4		0.2
Total Balance at End of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Less: Current Portion		—		—		0.6		0.5		0.6		0.5
Noncurrent Balance at December 31,	$	—	$	0.1	$	1.4	$	1.5	$	1.4	$	1.6

Note 9: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2018, 2017 and 2016 are shown in the table below:

	($000’s)
	2018		2017		2016
Current Income Tax Provision
Federal	$	—	$	—	$	—
State		355		—		—
Total Current Income Taxes	$	355		—		—
Deferred Income Provision
Federal	$	5,032		13,675		11,209
State		3,006		3,862		4,145
Total Deferred Income Taxes		8,038		17,537		15,354
Total Income Tax Expense	$	8,393	$	17,537	$	15,354

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

	2018			2017			2016
Statutory Federal Income Tax Rate		21	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		6			6			4
Utility Plant Differences		(7	)		(1	)		(1	)
Tax Credits and Other, net		—			(1	)		(1	)
Effective Income Tax Rate		20	%		38	%		36	%

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Temporary differences which gave rise to deferred tax assets and liabilities in 2018 and 2017 are shown below:

Temporary Differences (000’s)	2018		2017
Deferred Tax Assets
Retirement Benefit Obligations	$	32,249	$	38,915
Net Operating Loss Carryforwards		10,773		12,686
Tax Credit Carryforwards		2,704		3,536
Other, net		1,571		1,155
Total Deferred Tax Assets	$	47,297	$	56,292
Deferred Tax Liabilities
Utility Plant Differences	$	132,682	$	127,932
Regulatory Assets & Liabilities		6,429		9,323
Other, net		5,964		1,894
Total Deferred Tax Liabilities		145,075		139,149
Net Deferred Tax Liabilities	$	97,778	$	82,857

The Company is subject to federal and state income taxes as well as various other business taxes. 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. As a regulated Public Utility Holding Company (PUHC) entity under the Energy Policy Act of 2005; the Company follows income tax accounting guidance and regulations promulgated by the FERC for regulated utility companies under its jurisdiction. Also, the MDPU, NHPUC and the MPUC have, from time to time, issued specific income tax accounting rules for regulated utility companies in their respective jurisdictions. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company 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 that gave rise to the revision become known.

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.

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 first 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.

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.

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

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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 to be between fifteen and twenty years. 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 is $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 expects to recognize the remaining $3.4 million of this excess ADIT in future periods in accordance with regulatory guidance as discussed above.

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, 2017 with the Internal Revenue Service in September 2018 and generated additional federal NOLC assets of $3.7 million principally due to pension cost deductions, tax repair deductions, tax depreciation and research and development deductions. For the year ended December 31, 2018, the Company calculated federal current tax of $7.7 million and offset it with a decrease to the federal NOLC of $7.7 million, resulting in no federal current taxes payable for the period. As of December 31, 2018, the Company had recorded cumulative federal and state NOLC assets of $10.8 million 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, 2017, the Company had $3.5 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.

In March 2018, Unitil Corporation received notice that its Federal Income Tax return filings for the years ended December 31, 2015 and December 31, 2016 are under examination by the IRS. Currently, the Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s financial statements. The Company remains subject to examination by New Hampshire tax

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authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017. Income tax filings for the year ended December 31, 2017 have been filed with the New Hampshire Department of Revenue Administration. The State of Maine has concluded its review of the Company’s tax returns for December 31, 2014, December 31, 2015, and December 31, 2016 which resulted in a small additional refund to the Company.

The Company evaluated its tax positions at December 31, 2018 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 Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017.

Note 10: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:

• The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

• The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified retirement plan, with participation limited to executives selected by the Board of Directors.

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

	2018			2017			2016
Used to Determine Plan costs for years ended December 31:
Discount Rate		3.60	%		4.10	%		4.30	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.50	%		8.00	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2025			2022

Used to Determine Benefit Obligations at December 31:
Discount Rate	4.25	%	3.60	%	4.10	%
Rate of Compensation Increase	3.00	%	3.00	%	3.00	%
Health Care Cost Trend Rate Assumed for Next Year	7.00	%	7.50	%	8.00	%
Ultimate Health Care Cost Trend Rate	4.50	%	4.50	%	4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached	2024		2024		2025

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2018, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $589,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2018 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

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The following table provides the components of the Company’s Retirement plan costs (000’s):

	Pension Plan									PBOP Plan									SERP
	2018			2017			2016			2018			2017			2016			2018		2017		2016
Service Cost	$	3,393		$	3,295		$	3,402		$	2,933		$	2,974		$	2,610		$	487	$	460	$	162
Interest Cost		5,878			6,057			5,945			3,404			3,913			3,232			404		392		386
Expected Return on Plan Assets		(7,785	)		(7,306	)		(7,257	)		(1,635	)		(1,347	)		(1,205	)		—		—		—
Prior Service Cost Amortization		324			263			263			1,309			1,399			1,486			189		189		189
Actuarial Loss Amortization		5,786			4,662			4,398			1,383			2,098			1,049			486		295		375
Sub-total		7,596			6,971			6,751			7,394			9,037			7,172			1,566		1,336		1,112
Amounts Capitalized or Deferred		(3,465	)		(3,122	)		(3,008	)		(3,416	)		(4,515	)		(3,351	)		(451)		(397)		(290)
NPBC Recognized	$	4,131		$	3,849		$	3,743		$	3,978		$	4,522		$	3,821		$	1,115	$	939	$	822

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2018, 2017 and 2016 before capitalization and deferral was $7.6 million, $7.0 million and $6.8 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2018, 2017 and 2016 would have been $7.2 million, $7.6 million and $7.7 million respectively, prior to amounts capitalized or deferred.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2018			2017			2018			2017			2018			2017
Plan Assets at Beginning of Year	$	102,315		$	91,058		$	20,234		$	16,606		$	—		$	—
Actual Return on Plan Assets		(6,149	)		12,731			(1,085	)		1,907			—			—
Employer Contributions		16,628			4,100			4,000			4,000			401			34
Participant Contributions		—			—			153			126			—			—
Benefits Paid		(4,986	)		(5,574	)		(2,193	)		(2,405	)		(401	)		(34	)
Plan Assets at End of Year	$	107,808		$	102,315		$	21,109		$	20,234		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	166,921		$	150,439		$	94,122		$	96,659		$	11,723		$	9,566
Service Cost		3,393			3,295			2,933			2,974			487			460
Interest Cost		5,878			6,057			3,404			3,913			404			392
Participant Contributions		—			—			153			126			—			—
Plan Amendments		—			608			—			—			—			—
Benefits Paid		(4,986	)		(5,574	)		(2,193	)		(2,405	)		(401	)		(34	)
Actuarial (Gain) or Loss		(15,009	)		12,096			(17,414	)		(7,145	)		1,541			1,339
PBO at End of Year	$	156,197		$	166,921		$	81,005		$	94,122		$	13,754		$	11,723
Funded Status: Assets vs PBO	$	(48,389	)	$	(64,606	)	$	(59,896	)	$	(73,888	)	$	(13,754	)		(11,723	)

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The decrease in the PBO for the Pension plan as of December 31, 2018 compared to December 31, 2017 reflects an increase in the assumed discount rate as of December 31, 2018. The decrease in the PBO for the PBOP plan as of December 31, 2018 compared to December 31, 2017 reflects an increase in the assumed discount rate as of December 31, 2018 and the rate of increase for medical premiums being less than the assumed rate of medical inflation.

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets, net of deferred tax benefits, of $72.0 million and $84.5 million at December 31, 2018 and 2017, respectively, to account for the future collection of these plan obligations in electric and gas rates.

The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $142.8 million and $150.6 million as of December 31, 2018 and 2017, respectively. The ABO for the SERP was $10.8 million and $9.5 million as of December 31, 2018 and 2017, respectively. For the PBOP Plan, the ABO and PBO are the same.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan 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 Plan costs.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

	Pension Plan						PBOP Plan						SERP
	2018		2017		2016		2018		2017		2016		2018		2017		2016
Employer Contributions	$	16,628	$	4,100	$	5,146	$	4,000	$	4,000	$	4,000	$	401	$	34	$	34
Participant Contributions	$	—	$	—	$	—	$	153	$	126	$	61		$—	$	—	$	—
Benefit Payments	$	4,986	$	5,574	$	4,900	$	2,193	$	2,405	$	2,421	$	401	$	34	$	34

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2019	$	5,888	$	2,314	$	522
2020		6,484		2,520		521
2021		6,949		2,780		681
2022		6,853		2,955		678
2022		7,588		3,106		675
2024 - 2028		46,942		19,244		4,904

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The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 53% in common stock equities, 37% in fixed income securities and 10% in real estate securities. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2019			Actual Allocation at December 31,
				2018			2017			2016
Equity Funds		53	%		49	%		49	%		46	%
Debt Funds		37	%		40	%		34	%		37	%
Real Estate Fund		10	%		10	%		10	%		10	%
Asset Allocation Fund(1)		—			—			6	%		7	%
Other(2)		—			1	%		1	%		—
Total					100	%		100	%		100	%

(1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

(2) Represents investments being held in cash equivalents as of December 31, 2018 pending payment of benefits.

PBOP Plan	Target Allocation 2019			Actual Allocation at December 31,
				2018			2017			2016
Equity Funds		55	%		53	%		56	%		55	%
Debt Funds		45	%		47	%		42	%		43	%
Other(1)		—			—			2	%		2	%
Total					100	%		100	%		100	%

(1) Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds.

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.75% for 2018. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2018 and 2017. Please also see Note 1 for a discussion of the Company’s fair value accounting policy.

Equity, Fixed Income, Index and Asset Allocation Funds

These investments are valued based on quoted prices from active markets. These securities are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Cash  Equivalents

These investments are valued at cost, which approximates fair value, and are categorized in Level 1.

Real Estate Fund

These investments are valued at net asset value (NAV) per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity. In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these

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investments have not been classified in the fair value hierarchy. The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2018 and 2017 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2018
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	52,884	$	52,884	$	—	$	—
Fixed Income Funds		43,281		43,281		—		—
Total Mutual Funds		96,165		96,165		—		—
Cash Equivalents		1,202		1,202		—
Total Assets in the Fair Value Hierarchy	$	97,367	$	97,367	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		10,441
Total Assets	$	107,808
2017
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	50,373	$	50,373	$	—	$	—
Fixed Income Funds		34,757		34,757		—		—
Asset Allocation Fund		6,398		6,398		—		—
Total Mutual Funds		91,528		91,528		—		—
Cash Equivalents		1,200		1,200		—
Total Assets in the Fair Value Hierarchy	$	92,728	$	92,728	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		9,587
Total Assets	$	102,315

Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments.

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Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2018 and 2017 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2018
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	9,905	$	9,905	$	—	$	—
Equity Funds		11,204		11,204
Total Assets	$	21,109	$	21,109	$	—	$	—
2017
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	8,419	$	8,419	$	—	$	—
Equity Funds		11,415		11,415
Total Mutual Funds		19,834		19,834
Cash Equivalents		400		400
Total Assets	$	20,234	$	20,234	$	—	$	—

Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $2.7 million, $2.4 million and $2.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure 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, conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of December 31, 2018. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2018 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).

Under the supervision and with the participation of management, including the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, Unitil management has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, based upon criteria established in the “Internal Control–Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, Unitil management concluded that Unitil’s internal control over financial reporting was effective as of December 31, 2018.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their report which appears in Part II, Item 8 herein.

Changes in Internal Control over Financial Reporting

There have been no changes in Unitil’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control over financial reporting.

Item 9B. Other Information

On January 31, 2019, the Company issued a press release announcing its results of operations for the quarter and year ended December 31, 2018. The press release is furnished with this Annual Report on Form 10-K as Exhibit 99.1.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required by this Item is set forth in the “Proposal 1: Election of Directors” section and the “Description of Management” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019. Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934, is set forth in the “Corporate Governance and Policies of the Board—Section 16(a) Beneficial Ownership Reporting Compliance” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019. Information regarding the Company’s Audit Committee is set forth in the “Committees of the Board—Audit Committee” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019. Information regarding the Company’s Code of Ethics is set forth in the “Corporate Governance and Policies of the Board—Code of Ethics” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019. Information regarding procedures by which shareholders may recommend nominees to the Company’s Board of Directors is set forth in the “Corporate Governance and Policies of the Board—Nominations” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019.

Item 11. Executive Compensation

Information required by this Item is set forth in the “Compensation Discussion and Analysis” and “Compensation of Named Executive Officers” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this Item is set forth in the “Beneficial Ownership” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019, as well as the Equity Compensation Plan Information table in Part II, Item 5 of this Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this Item is set forth in the “Corporate Governance and Policies of the Board—Transactions with Related Persons” and the “Corporate Governance and Policies of the Board—Director Independence” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019.

Item 14. Principal Accountant Fees and Services

Information required by this Item is set forth in the “Audit Committee Report—Principal Accountant Fees and Services” and the “Audit Committee Report—Audit Committee Pre-Approval Policy” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 24, 2019.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) and (2)—LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:

• Report of Independent Registered Public Accounting Firm

• Consolidated Statements of Earnings for the years ended December 31, 2018, 2017 and 2016

• Consolidated Balance Sheets—December 31, 2018 and 2017

• Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016

• Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2018, 2017 and 2016

• Notes to Consolidated Financial Statements

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.

(3)—LIST OF EXHIBITS

Exhibit Number	Description of Exhibit	Reference*
3.1	Articles of Incorporation of Unitil Corporation.	Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984 (P)
3.2	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on March 4, 1992.	Exhibit 3.2 to Form 10-K for 1991 (SEC File No. 1-8858) (P)
3.3	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on September 23, 2008.	Exhibit 3.3 to Form S-3/A Registration Statement No. 333-152823 dated November 25, 2008
3.4	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on April  27, 2011.	Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 333-168394, dated January 28, 2014
3.5	Third Amended and Restated By-Laws of Unitil Corporation.	Exhibit 3.1 to Form 8-K dated December 12, 2013 (SEC File No. 1-8858)
4.1	Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December  2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958.	Exhibit 4.1 to Form 10-K for 2002 (SEC File No. 1-8858)
4.2	Fitchburg Note Agreement dated November 1, 1993 for the 6.75% Notes due November 30, 2023.	Exhibit 4.18 to Form 10-K for 1993 (SEC File No. 1-8858) (P)

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Exhibit Number	Description of Exhibit	Reference*
4.3	Fitchburg Note Agreement dated January 15, 1999 for the 7.37% Notes due January 15, 2029.	Exhibit 4.25 to Form 10-K for 1999 (SEC File No. 1-8858)
4.4	Fitchburg Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031.	Exhibit 4.6 to Form 10-Q for June 30, 2001 (SEC File No. 1-8858)
4.5	Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025.	Exhibit 4.7 to Form 10-K for 2003 (SEC File No. 1-8858)
4.6	Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030.	**
4.7	Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006.	**
4.8	Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022.	**
4.9	Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December  3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038.	Exhibit 4.1 to Form 8-K dated December 3, 2008 (SEC File No. 1-8858)
4.10	Granite State Note Purchase Agreement, dated as of December 15, 2008, for the 7.15% Senior Notes due December 15, 2018.	Exhibit 99.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
4.11	Northern Utilities Note Purchase Agreement, dated as of March 2, 2010, for the 5.29% Senior Notes, due March 2, 2020.	Exhibit 4.1 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
4.12	Fourteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of March 2, 2010.	Exhibit 4.4 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
4.13	Northern Utilities form of Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October  15, 2044.	Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
4.14	Northern Utilities form of Note issued pursuant to the Note Purchase Agreement, dated as of October  15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
4.15	Note Purchase Agreement dated August  1, 2016 by and among Unitil Corporation and the several purchasers named therein for the 3.70% Senior Notes, Series 2016, due August 1, 2026.	Exhibit 4.1 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.16	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by Metropolitan Life Insurance Company in the principal amount of $11,200,000.	Exhibit 4.2 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.17	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $4,000,000.	Exhibit 4.3 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
4.18	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $3,800,000.	Exhibit 4.4 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)

94

Exhibit Number		Description of Exhibit	Reference*
	4.19	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by Lincoln Benefit Life Company in the principal amount of $1,000,000.	Exhibit 4.5 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
	4.20	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $5,000,000.	Exhibit 4.6 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
	4.21	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by United of Omaha Life Insurance Company in the principal amount of $3,000,000.	Exhibit 4.7 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
	4.22	3.70% Senior Note, Series 2016, dated as of August  1, 2016 purchased by Companion Life Insurance Company in the principal amount of $2,000,000.	Exhibit 4.8 to Form 8-K dated August 1, 2016 (SEC File No. 1-8858)
	4.23	Note Purchase Agreement dated July  14, 2017 by and among Northern Utilities, Inc. and the several purchasers named therein for the 3.52% Senior Notes, Series 2017A, due November 1, 2027 and the 4.32% Senior Notes, Series 2017B, due November 1, 2047.	Exhibit 4.1 to Form 8-K dated July 14, 2017 (SEC File No. 1-8858)
	4.24	Note Purchase Agreement dated July  14, 2017 by and among Fitchburg Gas and Electric Light Company and the several purchasers named therein for the 3.52% Senior Notes, Series 2017A, due November 1, 2027 and the 4.32% Senior Notes, Series 2017B, due November 1, 2047.	Exhibit 4.2 to Form 8-K dated July 14, 2017 (SEC File No. 1-8858)
	4.25	Note Purchase Agreement dated July  14, 2017 by and among Granite State Gas Transmission, Inc. and the several purchasers named therein for the 3.72% Senior Notes, Series 2017A, due November 1, 2027.	Exhibit 4.3 to Form 8-K dated July 14, 2017 (SEC File No. 1-8858)
	4.26****	3.52% Senior Note, Series 2017A, due November 1, 2027, issued by Northern Utilities, Inc. to Great-West Life  & Annuity Insurance Company.	Exhibit 4.2 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
	4.27****	4.32% Senior Note, Series 2017B, due November  1, 2047, issued by Northern Utilities, Inc. to The Canada Life Insurance Company of Canada.	Exhibit 4.3 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
	4.28****	3.52% Senior Note, Series 2017A, due November 1, 2027, issued by Fitchburg Gas and Electric Light Company to Great-West Life  & Annuity Insurance Company.	Exhibit 4.5 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
	4.29****	4.32% Senior Note, Series 2017B, due November  1, 2047, issued by Fitchburg Gas and Electric Light Company to The Great-West Life Assurance Company.	Exhibit 4.6 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
	4.30****	3.72% Senior Note, Series 2017A, due November  1, 2027, issued by Granite State Gas Transmission, Inc. to Thrivent Financial for Lutherans.	Exhibit 4.8 to Form 8-K dated November 1, 2017 (SEC File No. 1-8858)
	4.31	Bond Purchase Agreement dated November  30, 2018 by and among Unitil Energy Systems, Inc. and the several purchasers named therein for the $30,000,000 aggregate principal amount of first mortgage bonds, Series Q, due November 30, 2048.	Exhibit 4.1 to Form 8-K dated November 30, 2018 (SEC File No. 1-8858)
	4.32	Fifteenth Supplemental Indenture dated November  29, 2018 by and between Unitil Energy Systems, Inc. and U.S. Bank National Association (as trustee).	Exhibit 4.2 to Form 8-K dated November 30, 2018 (SEC File No. 1-8858)

95

Exhibit Number		Description of Exhibit	Reference*
	4.33****	First Mortgage Bond, Series Q, 4.18%, due November  30, 2048, issued by Unitil Energy Systems, Inc. to United of Omaha Life Insurance Company.	Exhibit 4.3 to Form 8-K dated November 30, 2018 (SEC File No. 1-8858)
	4.34	Second Amended and Restated Credit Agreement dated July  25, 2018 among Unitil Corporation, Bank of America, N.A., as administrative agent, and the Lenders.	Exhibit 4.1 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	4.35	Amended and Restated Note issued to Bank of America, N.A..	Exhibit 4.2 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	4.36	Amended and Restated Note issued to Citizens Bank, N.A.	Exhibit 4.3 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	4.37	Amended and Restated Note issued to TD Bank, N.A.	Exhibit 4.4 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.1***	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.2 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.2***	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.3 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.3***	Amended and Restated Form of Severance Agreement (Three-Year Term)	Exhibit 10.1 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.4***	Amended and Restated Form of Severance Agreement (Two-Year Term)	Exhibit 10.2 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.5***	Amended and Restated Form of Severance Agreement (Two-Year Term; Non Pension)	Exhibit 10.3 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.6***	Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2016.	Exhibit 10.1 to Form 10-Q for March 31, 2017 (SEC File No. 1-8858)
	10.7***	Amended and Restated Supplemental Executive Retirement Plan	Exhibit 10.5 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.8***	Unitil Corporation Deferred Compensation Plan	Exhibit 10.6 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.9***	Unitil Corporation Management Incentive Plan (amended and restated as of June 5, 2013).	Exhibit 10.2 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
	10.10***	Unitil Corporation Second Amended and Restated 2003 Stock Plan	Appendix 1 to the Proxy Statement filed on Schedule 14A dated March 13, 2012 (SEC File No. 1-8858)

96

Exhibit Number		Description of Exhibit	Reference*
	10.11***	Form of Restricted Stock Unit Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
	10.12***	Form of Restricted Stock Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 4.8 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
	10.13***	Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement.	Exhibit 10.1 to Form 10-Q for September 30, 2004 (SEC File No. 1-8858)
	10.14***	Unitil Corporation Tax Deferred Savings and Investment Plan, as amended to date	Exhibit 10.13 to Form 10-K for 2013 (SEC File No. 1-8858)
	10.15***	Employment Agreement effective November 1, 2015 between Unitil Corporation and Robert G. Schoenberger	Exhibit 10.1 to Form 8-K dated October 21, 2015 (SEC File No. 1-8858)
	10.16***	Employment Agreement effective April 25, 2018 between Unitil Corporation and Thomas P. Meissner, Jr.	Exhibit 10.1 to Form 8-K dated March 1, 2018 (SEC File No. 1-8858)
	10.17***	Amended and Restated Employment Agreement between Unitil Corporation and Thomas P. Meissner, Jr.	Exhibit 10.4 to Form 8-K dated July 25, 2018 (SEC File No. 1-8858)
	10.18	Amended and Restated Credit Agreement dated as of October 4, 2013 by and among Unitil Corporation and Bank of America, N.A.	Exhibit 10.1 to Form 8-K dated October 4, 2013 (SEC File No. 1-8858)
	10.19	First Amendment to Amended and Restated Credit Agreement dated as of July  24, 2015 by and among Unitil Corporation, Bank of America, N.A., and the other parties thereto.	Exhibit 10.1 to Form 8-K dated July 24, 2015 (SEC File No. 1-8858)
	10.20	Parent Guaranty of Unitil Corporation for the Granite State 7.15% Senior Notes due December 15, 2018.	Exhibit 10.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
	10.21***	Unitil Corporation Incentive Plan (amended and restated as of January 26, 2015)	Exhibit 10.1 to Form 10-Q for March 31, 2015 (SEC File No. 1-8858)
	10.22***	Unitil Corporation—Compensation of Directors.	Exhibit 10.20 to Form 10-K for 2016 (SEC File No. 1-8858)
	11.1	Statement Re: Computation in Support of Earnings per Share for the Company.	Filed herewith
	21.1	Statement Re: Subsidiaries of Registrant.	Filed herewith
	23.1	Consent of Independent Registered Public Accounting Firm.	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

97

Exhibit Number		Description of Exhibit	Reference*
	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 January 31, 2019 Announcing Earnings For the Quarter and Year Ended December 31, 2018.	Filed herewith
	101.INS	XBRL Instance 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
	101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith

* 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.

** In accordance with Item 601(b)(4)(iii)(A) of Regulation S-K, the instrument defining the debt of the Registrant and its subsidiary, described above, has been omitted but will be furnished to the Commission upon request.

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

**** This Note or Bond (each, an “Instrument”) is substantially identical in all material respects to other Instruments that are otherwise required to be filed as exhibits, except as to the registered payee of such Instrument, the identifying number of such Instrument, and the principal amount of such Instrument. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed a copy of only one of such Instruments, with a schedule identifying the other Instruments omitted and setting forth the material details in which such Instruments differ from the Instrument 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 Instruments so omitted.

(P) Paper exhibit.

98

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	UNITIL CORPORATION
Date January 31, 2019	By	/S/    THOMAS P. MEISSNER, JR.
		Thomas P. Meissner, Jr.
		Chairman of the Board of Directors, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/S/    THOMAS P. MEISSNER, JR. Thomas P. Meissner, Jr.	Principal Executive Officer; Director	January 31, 2019
/S/    MARK H. COLLIN Mark H. Collin	Principal Financial Officer; Director	January 31, 2019
/S/    LAURENCE M. BROCK Laurence M. Brock	Principal Accounting Officer	January 31, 2019
/S/    ALBERT H. ELFNER, III Albert H. Elfner, III	Director	January 31, 2019
/S/    M. BRIAN O’SHAUGHNESSY M. Brian O’Shaughnessy	Director	January 31, 2019
/S/    EBEN S. MOULTON Eben S. Moulton	Director	January 31, 2019
/S/    DAVID P. BROWNELL David P. Brownell	Director	January 31, 2019
/S/    EDWARD F. GODFREY Edward F. Godfrey	Director	January 31, 2019
/S/    MICHAEL B. GREEN Michael B. Green	Director	January 31, 2019
/S/    DR. ROBERT V. ANTONUCCI Dr. Robert V. Antonucci	Director	January 31, 2019
/S/    LISA CRUTCHFIELD Lisa Crutchfield	Director	January 31, 2019
/S/    DAVID A. WHITELEY David A. Whiteley	Director	January 31, 2019
Suzanne Foster	Director
Justine Vogel	Director

99

EX-11.1

Exhibit 11.1

UNITIL CORPORATION

COMPUTATION IN SUPPORT OF EARNINGS PER SHARE

	Year Ended December 31,
	2018		2017		2016
EARNINGS PER SHARE (000’s, except per share data)
Net Income	$	33,041	$	29,005	$	27,124
Less: Dividend Requirements on Preferred Stock		11		11		11
Net Income Applicable to Common Stock	$	33,030	$	28,994	$	27,113
Average Number of Common Shares Outstanding—Basic		14,824		14,095		13,990
Dilutive Effect of Stock Options and Restricted Stock		5		7		6
Average Number of Common Shares Outstanding—Diluted		14,829		14,102		13,996
Earnings Per Share—Basic	$	2.23	$	2.06	$	1.94
Earnings Per Share—Diluted	$	2.23	$	2.06	$	1.94

EX-21.1

Exhibit 21.1

Subsidiaries of Registrant

The Company or the registrant has eight wholly-owned subsidiaries, seven of which are corporations organized under the laws of the State of New Hampshire: Unitil Energy Systems, Inc., Northern Utilities, Inc., Granite State Gas Transmission, Inc., Unitil Power Corp., Unitil Realty Corp., Unitil Resources, Inc. and Unitil Service Corp. The eighth, Fitchburg Gas and Electric Light Company, is organized under the laws of the Commonwealth of Massachusetts. Usource, Inc., which is a corporation organized under the laws of the State of Delaware, is a wholly-owned subsidiary of Unitil Resources, Inc. Usource, Inc. is the sole member of Usource L.L.C., which is a limited liability company formed under the laws of the State of Delaware.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-168394, and 333-221333 on Form S-3 and Nos. 333-184849 and 333-42266 on Form S-8 of our report dated January 31, 2019, relating to the consolidated financial statements of Unitil Corporation and subsidiaries and the effectiveness of Unitil Corporation and subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Unitil Corporation for the year ended December 31, 2018.

/s/ Deloitte and Touche LLP

January 31, 2019

Boston, Massachusetts

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 annual report on Form 10-K 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: January 31, 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, Mark H. Collin, certify that:

1) I have reviewed this annual report on Form 10-K 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: January 31, 2019

/s/ Mark H. Collin

Mark H. Collin

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 annual report on Form 10-K 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: January 31, 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 Annual Report of Unitil Corporation (the “Company”) on Form 10-K for the year ended December 31, 2018 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, Mark H. Collin, 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	January 31, 2019
/s/ Mark H. Collin
Mark H. Collin	Chief Financial Officer	January 31, 2019
/s/ Laurence M. Brock
Laurence M. Brock	Chief Accounting Officer	January 31, 2019

EX-99.1

Exhibit 99.1

Page 1 of 4

FOR RELEASE

UNITIL REPORTS YEAR END EARNINGS

HAMPTON, N.H., JANUARY 31, 2019—Unitil Corporation (NYSE: UTL) (www.unitil.com) today announced Net Income of $33.0 million, or $2.23 per share, for the year ended December 31, 2018, an increase of $4.0 million, or 13.8%, in Net Income and $0.17, or 8.25%, in Earnings Per Share, compared to 2017. The Company’s earnings for 2018 were driven by increases in natural gas and electric sales margins. Net Income for the three months ended December 31, 2018 was $11.0 million, or $0.74 per share, compared to Net Income of $11.2 million, or $0.79 per share, for the same period in 2017.

“We are pleased with the Company’s financial results for 2018,” said Thomas P. Meissner, Jr., Unitil’s Chairman and Chief Executive Officer. “Our growing customer base and steady investment in our gas and electric systems have allowed us to continue to focus on providing our customers with safe and reliable services cost-effectively.”

Natural gas sales margin was $116.9 million in 2018, an increase of $7.2 million compared to 2017. Gas sales margin in 2018 was positively affected by higher natural gas distribution rates of $7.1 million, which was partially offset by the reduction in rates of $3.7 million due to the lower corporate income tax rate of 21% under the Tax Cuts and Jobs Act of 2017 (TCJA). Gas margin in 2018 reflects the positive effect of colder winter weather and customer growth on sales volume of $3.8 million.

Natural gas therm sales increased 8.1% in 2018 compared to 2017. The increase in gas therm sales in the Company’s service areas was driven by customer growth and colder winter weather in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 12.2% more Heating Degree Days in 2018 compared to 2017. As of December 31, 2018 the number of natural gas customers served has increased by 1,450 over the last year.

Electric sales margin was $91.9 million in 2018, a decrease of $0.3 million compared to 2017. Electric sales margin in 2018 was positively affected by higher electric distribution rates of $2.9 million, partially offset by the reduction in rates of $2.6 million in 2018 due to the lower corporate income tax rate of 21% under the TCJA. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $0.8 million. These positive impacts on electric sales margin were offset by the absence in the current period of a one-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

Electric kilowatt-hour (kWh) sales increased 3.2% in 2018 compared to 2017 reflecting customer growth and warmer-than-average summer temperatures in 2018. Based on weather data collected in the Company’s electric service areas, there were 42.2% more Cooling Degree Days in 2018 compared to 2017. As of December 31, 2018, the number of electric customers served has increased by 593 over the last year.

O&M expenses increased $5.0 million in 2018 compared to 2017. The change in O&M expense reflects higher labor costs of $1.8 million and higher utility operating costs of $4.0 million, partially offset by lower professional fees of $0.8 million. The higher utility operating costs include a non-recurring temporary rate adjustment which increased O&M expenses by $1.2 million in the second quarter of 2018, which was offset by a corresponding increase in gas revenue, and also includes higher bad debt expense of $0.8 million and higher storm-related and other distribution and transmission systems maintenance costs of $2.0 million.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

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Depreciation and Amortization expense increased $3.5 million in 2018 compared to 2017, reflecting higher depreciation on higher utility plant in service and higher amortization of information technology costs, partially offset by lower amortization of deferred major storm costs which were amortized for recovery over multi-year periods.

Taxes Other Than Income Taxes increased $1.3 million in 2018 compared to 2017, primarily reflecting higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

Interest Expense, net increased $0.9 million, or 3.9%, in 2018 compared to 2017 reflecting interest on higher short-term debt rates and higher levels of long-term debt.

Other Expense (Income) was essentially unchanged in 2018 compared to 2017.

Income Taxes decreased $9.1 million in 2018 compared to 2017 reflecting $6.3 million from the lower tax rate on pre-tax earnings in 2018 and the current tax benefit of $2.8 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018.

At its January 2019 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.37 per share, an increase of $0.005 per share on a quarterly basis. This quarterly dividend results in an increase in the current effective annualized dividend rate to $1.48 per share from $1.46 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 fourth quarter and full year 2018 results on Thursday, January 31, 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. Other subsidiaries include Usource, Unitil’s non-regulated business segment. 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

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

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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 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 4 of 4

Selected financial data for 2018 and 2017 is presented in the following table:

Unitil Corporation—Condensed Consolidated Financial Data
(Millions, except Per Share data)(Unaudited)
	Three Months Ended December 31,							Twelve Months Ended December 31,
	2018		2017		Change			2018		2017		Change
Gas Therm Sales:
Residential		12.8		9.9		29.3	%		48.7		43.4		12.2	%
Commercial/Industrial		50.1		44.4		12.8	%		182.4		170.4		7.0	%
Total Gas Therm Sales		62.9		54.3		15.8	%		231.1		213.8		8.1	%
Electric kWh Sales:
Residential		157.7		153.0		3.1	%		685.5		649.4		5.6	%
Commercial/Industrial		234.4		238.8		(1.8	%)		990.3		974.7		1.6	%
Total Electric kWh Sales		392.1		391.8		0.1	%		1,675.8		1,624.1		3.2	%
Gas Revenues	$	68.7	$	62.1	$	6.6		$	216.1	$	194.0	$	22.1
Cost of Gas Sales		32.2		27.7		4.5			99.2		84.3		14.9
Gas Sales Margin		36.5		34.4		2.1			116.9		109.7		7.2
Electric Revenues		55.7		51.8		3.9			223.3		206.2		17.1
Cost of Electric Sales		34.3		29.7		4.6			131.4		114.0		17.4
Electric Sales Margin		21.4		22.1		(0.7	)		91.9		92.2		(0.3	)
Usource Revenues		1.2		1.5		(0.3	)		4.7		6.0		(1.3	)
Total Sales Margin:		59.1		58.0		1.1			213.5		207.9		5.6
Operation & Maintenance Expenses		18.0		15.1		2.9			69.5		64.5		5.0
Depreciation & Amortization		13.0		11.7		1.3			50.4		46.9		3.5
Property & Other Taxes		5.9		5.5		0.4			22.4		21.1		1.3
Other Expense (Income), net		1.7		2.1		(0.4	)		5.8		5.8		—
Interest Expense, net		6.1		6.0		0.1			24.0		23.1		0.9
Income Before Income Taxes		14.4		17.6		(3.2	)		41.4		46.5		(5.1	)
Income Tax Expense		3.4		6.4		(3.0	)		8.4		17.5		(9.1	)
Net Income	$	11.0	$	11.2	$	(0.2	)	$	33.0	$	29.0	$	4.0
Earnings Per Share	$	0.74	$	0.79	$	(0.05	)	$	2.23	$	2.06	$	0.17

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Jan. 28, 2019	Jun. 30, 2018
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity shell company	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		14,878,075
Entity Public Float			$ 749,186,923

XML

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues
Total Operating Revenues	$ 444,100	$ 406,200	$ 383,400
Operating Expenses
Operation and Maintenance	69,500	64,500	61,400
Depreciation and Amortization	50,400	46,900	46,600
Taxes Other Than Income Taxes	22,400	21,100	19,600
Total Operating Expenses	372,900	330,800	313,200
Operating Income	71,200	75,400	70,200
Interest Expense, net	24,000	23,100	22,500
Other Expense (Income), net	5,800	5,800	5,200
Income Before Income Taxes	41,400	46,500	42,500
Income Taxes	8,393	17,537	15,354
Net Income Applicable to Common Shares	$ 33,000	$ 29,000	$ 27,100
Earnings per Common Share-Basic and Diluted	$ 2.23	$ 2.06	$ 1.94
Weighted Average Common Shares Outstanding-(Basic and Diluted)	14.8	14.1	14.0
Gas
Operating Revenues
Total Operating Revenues	$ 216,100	$ 194,000	$ 181,200
Operating Expenses
Operating Expenses	99,200	84,300	77,600
Electric
Operating Revenues
Total Operating Revenues	223,300	206,200	196,100
Operating Expenses
Operating Expenses	131,400	114,000	108,000
Other
Operating Revenues
Total Operating Revenues	$ 4,700	$ 6,000	$ 6,100

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and Cash Equivalents	$ 7.8	$ 8.9
Accounts Receivable, net	66.8	67.4
Accrued Revenue	54.7	53.3
Exchange Gas Receivable	8.1	5.8
Gas Inventory	0.8	0.6
Materials and Supplies	7.0	6.9
Prepayments and Other	7.0	8.4
Total Current Assets	152.2	151.3
Utility Plant:
Gas	760.6	699.6
Electric	500.1	476.7
Common	83.1	67.4
Construction Work in Progress	25.5	35.5
Utility Plant	1,369.3	1,279.2
Less: Accumulated Depreciation	332.5	307.7
Net Utility Plant	1,036.8	971.5
Other Noncurrent Assets:
Regulatory Assets	99.0	109.6
Other Assets	10.3	9.5
Total Other Noncurrent Assets	109.3	119.1
TOTAL ASSETS	1,298.3	1,241.9
Current Liabilities:
Accounts Payable	42.6	41.5
Short-Term Debt	82.8	38.3
Long-Term Debt, Current Portion	18.4	29.8
Regulatory Liabilities	11.5	9.2
Energy Supply Obligations	13.4	9.7
Environmental Obligations	0.6	0.5
Capital Lease Obligations	3.1	3.1
Other Current Liabilities	20.1	18.9
Total Current Liabilities	192.5	151.0
Noncurrent Liabilities:
Retirement Benefit Obligations	121.5	150.1
Deferred Income Taxes, net	97.8	82.9
Cost of Removal Obligations	90.7	84.3
Regulatory Liabilities	47.0	48.9
Capital Lease Obligations	2.7	5.7
Environmental Obligations	1.4	1.6
Other Noncurrent Liabilities	6.0	4.3
Total Noncurrent Liabilities	367.1	377.8
Capitalization:
Long-Term Debt, Less Current Portion	387.4	376.3
Stockholders' Equity:
Common Equity (Outstanding 14,876,955 and 14,815,585 Shares)	279.1	275.8
Retained Earnings	72.0	60.8
Total Common Stock Equity	351.1	336.6
Preferred Stock	0.2	0.2
Total Stockholders' Equity	351.3	336.8
Total Capitalization	738.7	713.1
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,298.3	$ 1,241.9

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2018	Dec. 31, 2017
Common Equity Outstanding	14,876,955	14,815,585

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Activities:
Net Income	$ 33.0	$ 29.0	$ 27.1
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	50.4	46.9	46.6
Deferred Tax Provision	8.0	17.5	15.4
Changes in Working Capital Items:
Accounts Receivable	0.6	(14.5)	(5.4)
Accrued Revenue	(1.4)	(3.8)	(11.1)
Regulatory Liabilities	2.3	(1.2)	(5.2)
Exchange Gas Receivable	(2.3)	2.5	2.8
Accounts Payable	1.1	9.1	(0.9)
Other Changes in Working Capital Items	3.6	(1.8)	(1.0)
Deferred Regulatory and Other Charges	(11.3)	(6.1)	(5.0)
Other, net	(5.5)	8.6	5.0
Cash Provided by Operating Activities	78.5	86.2	68.3
Investing Activities:
Property, Plant and Equipment Additions	(102.4)	(119.3)	(98.1)
Cash Used In Investing Activities	(102.4)	(119.3)	(98.1)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	44.5	(43.6)	39.9
Issuance of Long-Term Debt	29.9	89.3	30.0
Repayment of Long-Term Debt	(30.1)	(17.2)	(19.0)
Decrease in Capital Lease Obligations	(3.0)	(2.5)	(2.8)
Net Increase (Decrease) in Exchange Gas Financing	2.1	(2.4)	(2.5)
Dividends Paid	(21.8)	(20.4)	(20.0)
Proceeds from Issuance of Common Stock	1.2	33.0	1.3
Cash Provided by Financing Activities	22.8	36.2	26.9
Net (Decrease) Increase in Cash	(1.1)	3.1	(2.9)
Cash at Beginning of Year	8.9	5.8	8.7
Cash at End of Year	7.8	8.9	5.8
Supplemental Information:
Interest Paid	24.6	23.0	22.1
Income Taxes Paid	0.4		1.6
Payments on Capital Leases	3.3	3.3	3.4
Capital Expenditures Included in Accounts Payable	$ 0.5	$ 1.1	0.3
Non-Cash Additions to Property, Plant and Equipment			$ 3.5

XML

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Dividend and Distribution Reinvestment and Share Purchase Plan	Registered Public Offering	Common Equity	Common Equity Dividend and Distribution Reinvestment and Share Purchase Plan	Common Equity Registered Public Offering	Retained Earnings
Beginning Balance at Dec. 31, 2015	$ 282.6			$ 237.5			$ 45.1
Net Income	27.1						27.1
Dividends on Common Shares	(20.0)						(20.0)
Shares Issued Under Stock Plans	1.9			1.9
Issuance of Common Shares	1.3			1.3
Ending Balance at Dec. 31, 2016	292.9			240.7			52.2
Net Income	29.0						29.0
Dividends on Common Shares	(20.4)						(20.4)
Shares Issued Under Stock Plans	2.1			2.1
Issuance of Common Shares		$ 1.3	$ 31.7		$ 1.3	$ 31.7
Ending Balance at Dec. 31, 2017	336.6			275.8			60.8
Net Income	33.0						33.0
Dividends on Common Shares	(21.8)						(21.8)
Shares Issued Under Stock Plans	2.1			2.1
Issuance of Common Shares	1.2			1.2
Ending Balance at Dec. 31, 2018	$ 351.1			$ 279.1			$ 72.0

XML

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Dividends per Common Share	$ 1.46	$ 1.44	$ 1.42
Common Stock, Shares issued	25,932		32,095
Dividend and Distribution Reinvestment and Share Purchase Plan
Common Stock, Shares issued		26,256
Registered Public Offering
Common Stock, Shares issued		690,000

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

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. are 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 capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate 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 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) are wholly- owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers.

Basis of Presentation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation related to the adoption of new accounting standards.

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

Fair Value—The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:

Level 1—	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2—	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3—	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

There have been no changes in the valuation techniques used during the current period.

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.

In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017 recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the twelve months ended December 31, 2018. 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.

As discussed below, the Company plans to disclose billed and unbilled revenue separately from rate adjustment mechanism revenue in the Notes to the Consolidated Financial Statements for periods in 2018 going forward, and will also provide this disclosure for prior periods for informational purposes.

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. The lower revenues reported in the twelve months ended December 31, 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act of 2017 (TCJA) are shown separately in the tables below for informational purposes.

	Twelve Months Ended December 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	81.4		$	123.6		$	205.0
Commercial & Industrial		119.7			96.4			216.1
Other		13.3			11.3			24.6
Revenue Reductions—TCJA		(3.7	)		(2.6	)		(6.3	)
Total Billed and Unbilled Revenue		210.7			228.7			439.4
Rate Adjustment Mechanism Revenue		5.4			(5.4	)		—
Total Gas and Electric Operating Revenues	$	216.1		$	223.3		$	439.4
	Twelve Months Ended December 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	71.2		$	107.9		$	179.1
Commercial & Industrial		102.8			87.7			190.5
Other		13.5			6.0			19.5
Total Billed and Unbilled Revenue		187.5			201.6			389.1
Rate Adjustment Mechanism Revenue		6.5			4.6			11.1
Total Gas and Electric Operating Revenues	$	194.0		$	206.2		$	400.2
	Twelve Months Ended December 31, 2016
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	61.5		$	101.9		$	163.4
Commercial & Industrial		92.7			81.5			174.2
Other		11.2			4.9			16.1
Total Billed and Unbilled Revenue		165.4			188.3			353.7
Rate Adjustment Mechanism Revenue		15.8			7.8			23.6
Total Gas and Electric Operating Revenues	$	181.2		$	196.1		$	377.3

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 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—Usource, Unitil’s non-regulated subsidiary, conducts its business activities as a broker of competitive energy services. Usource does not take title to the electric and gas commodities which are the subject of the brokerage contracts. The Company records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partners with certain entities to facilitate these brokerage services and pays these entities a fee under revenue sharing agreements.

As discussed above, the Company adopted ASU 2014-09 in the first quarter of 2018. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. ASU 2014-09 requires that payments made by Usource to third parties (Channel Partners) for revenue sharing agreements are recognized net, as a reduction from revenue, where those payments were previously recognized gross as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to third parties for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $1.0 million, $1.1 million and $1.0 million in 2018, 2017 and 2016, respectively.

If ASU 2014-09 had been in effect for 2017 and 2016, the result would have been corresponding reductions of $1.1 million and $1.0 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below.

Other Operating Revenues ($ millions):	Twelve Months Ended December 31
	As Reported			If ASU 2014-09 Had Been in Effect
	2018			2017			2016
Usource Contract Revenue	$	5.7		$	6.0		$	6.1
Less: Revenue Sharing Payments		(1.0	)		(1.1	)		(1.0	)
Total Other Operating Revenues	$	4.7		$	4.9		$	5.1

Operation and Maintenance Expense ($ millions):	Twelve Months Ended December 31
	As Reported		If ASU 2014-09 Had Been in Effect
	2018		2017		2016
Operation and Maintenance Expense	$	69.5	$	63.4	$	60.4

Retirement Benefit Costs—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan) and the Unitil Corporation Supplemental Executive Retirement Plan (SERP).The net periodic benefit costs associated with these benefit plans consist of service cost and other components (See Note 10 to the Consolidated Financial Statements). In the first quarter of 2018, the Company adopted ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-K for the twelve months ended December 31, 2018, the service cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Other Expense (Income), net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. The change in presentation for the twelve months ended December 31, 2018 resulted in a reduction of “Operations and Maintenance” and an increase in “Other Expense (Income), net” on the Consolidated Statements of Earnings for the prior periods. There are $5.5 million, $5.7 million and $4.9 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the twelve months ended December 31, 2018, 2017 and 2016, respectively, net of amounts deferred as regulatory assets for future recovery.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2018 – 3.38%, 2017 – 3.45% and 2016 – 3.49%.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes—The Company bills its customers sales tax in Massachusetts and Maine and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings. The consumption tax in New Hampshire has been repealed effective January 1, 2019.

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 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 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.

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2018 the Company paid quarterly dividends of $0.365 per share, resulting in an annualized dividend rate of $1.46 per common share. For the years ended December 31, 2017 and 2016, the Company paid quarterly dividends of $0.36 and $0.355 per common share, respectively, resulting in annualized dividend rates of $1.44 and $1.42 per common share, respectively. At its January 2019 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.37 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.48 per share from $1.46 per share.

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2018 and 2017, the Unitil subsidiaries had deposited $3.5 million and $2.9 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2018 and 2017.

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. 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.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2018 and 2017.

Accrued Revenue (millions)	December 31,
	2018		2017
Regulatory Assets—Current	$	41.3	$	39.5
Unbilled Revenues		13.4		13.8
Total Accrued Revenue	$	54.7	$	53.3

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 December 31, 2018 and 2017.

Exchange Gas Receivable (millions)	December 31,
	2018		2017
Northern Utilities	$	7.5	$	5.4
Fitchburg		0.6		0.4
Total Exchange Gas Receivable	$	8.1	$	5.8

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 December 31, 2018 and 2017.

Gas Inventory (millions)	December 31,
	2018		2017
Natural Gas	$	0.3	$	0.4
Propane		0.4		0.1
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	0.8	$	0.6

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.70%, 2.90% and 2.18% in 2018, 2017 and 2016, respectively. 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 December 31, 2018 and 2017, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $90.7 million and $84.3 million, respectively.

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.

Regulatory Assets consist of the following (millions)	December 31,
	2018		2017
Retirement Benefits	$	72.0	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		38.4		36.0
Deferred Storm Charges		6.3		7.2
Environmental		7.9		9.5
Income Taxes		5.7		6.5
Other Deferred Charges		10.0		5.4
Total Regulatory Assets	$	140.3	$	149.1
Less: Current Portion of Regulatory Assets(1)		41.3		39.5
Regulatory Assets—noncurrent	$	99.0	$	109.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions)	December 31,
	2018		2017
Rate Adjustment Mechanisms	$	11.5	$	6.9
Gas Pipeline Refund		—		2.3
Income Taxes (Note 9)		47.0		48.9
Total Regulatory Liabilities		58.5		58.1
Less: Current Portion of Regulatory Liabilities		11.5		9.2
Regulatory Liabilities—noncurrent	$	47.0	$	48.9

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2018 are $6.0 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material 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 qualify as a derivative instrument under the guidance set forth in the FASB Codification.

The Company previously operated a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service, which included use of derivative instruments. The hedging program was terminated in 2018.

Under the hedging program previously operated by Northern Utilities, any gains or losses resulting from the change in the fair value of these derivatives were passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause. The fair value of these derivatives was determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company recorded gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassified these gains or losses into Cost of Gas Sales when the gains and losses were passed through to customers through the Cost of Gas Clause.

As of December 31, 2018 and December 31, 2017, the Company had zero and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program. The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31, 2018 and December 31, 2017. There was zero and $0.4 million of losses / (gains) recognized in Regulatory Assets / Liabilities for the years ended December 31, 2018 and 2017, respectively. There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31, 2018 and 2017.

Investments in Marketable Securities—The Company maintains 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 Supplemental Executive Retirement Plan (SERP) (See further discussion of the SERP in Note 10).

At December 31, 2018 and 2017, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $4.8 million and $3.6 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, net.

Fair Value of Marketable Securities (millions)	December 31,
	2018		2017
Equity Funds	$	—	$	2.1
Fixed Income Funds		—		1.5
Money Market Funds		4.8		—
Total Marketable Securities	$	4.8	$	3.6

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

	December 31,
Energy Supply Obligations consist of the following: (millions)	2018		2017
Current:
Exchange Gas Obligation	$	7.5	$	5.4
Renewable Energy Portfolio Standards		5.6		4.0
Power Supply Contract Divestitures		0.3		0.3
Total Energy Supply Obligations—Current	$	13.4	$	9.7
Noncurrent:
Power Supply Contract Divestitures	$	0.6	$	0.9
Total Energy Supply Obligations	$	14.0	$	10.6

Exchange Gas Obligation—As discussed above, 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 maintain accrued revenue 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 filed with MDPU in 2018 and approvals remain pending.

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—Unitil Energy’s and Fitchburg’s customers are entitled 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 (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (noncurrent portion).

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements—As of December 31, 2018, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2018, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2018, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements— In August 2018, the FASB issued Accounting Standards Update (ASU) No. 2018-14, “Compensation—Retirement Benefits—Defined Benefit Plans—General (Sutopic 715-20)” which amends existing guidance to add, remove and clarify disclosure requirements related to defined benefit pension and other postretirement plans. The ASU is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company adopted this ASU in the fourth quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

In June 2018, the FASB issued ASU No. 2018-07, “Compensation—Stock Compensation (Topic 718)” which amends the existing guidance relating to the accounting for nonemployee share-based payments. Under this ASU, most of the guidance on share-based payments to nonemployees will be aligned with the requirements for share-based payments granted to employees. The ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted this ASU in the second quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715)” which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for the Company on January 1, 2018. The change in capitalization of retirement benefits did not have a material impact on the Company’s Consolidated Financial Statements.

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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company plans to adopt the standard as of January 1, 2019. The Company will elect 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 will also elect 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 will make an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company will recognize those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The Company expects that adoption of the standard will result 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 does not believe the standard will have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.

The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales.

The Company used the modified retrospective method when adopting the new standard on January 1, 2018. The new guidance did not have a material impact to the Consolidated Financial Statements. (See “Utility Revenue Recognition” and “Other Operating Revenue—Non-regulated” above.)

In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. The ASU became effective for the Company on January 1, 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

Other than the pronouncements 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 evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

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Quarterly Financial Information

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information

Note 2: Quarterly Financial Information (unaudited; millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented.

	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2018		2017		2018		2017		2018		2017		2018		2017
Total Operating Revenues	$	145.8	$	126.0	$	84.5	$	80.8	$	88.2	$	84.0	$	125.6	$	115.4
Operating Income	$	28.1	$	27.7	$	10.6	$	11.6	$	10.3	$	10.4	$	22.2	$	25.7
Net Income Applicable to Common	$	15.6	$	12.4	$	3.6	$	3.1	$	2.8	$	2.3	$	11.0	$	11.2
	Per Share Data:
Earnings Per Common Share	$	1.06	$	0.88	$	0.24	$	0.23	$	0.19	$	0.16	$	0.74	$	0.79
Dividends Paid Per Common Share	$	0.365	$	0.360	$	0.365	$	0.360	$	0.365	$	0.360	$	0.365	$	0.360

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Segment Information

12 Months Ended

Dec. 31, 2018

Segment Information

Note 3: Segment Information

Unitil reports three segments: utility gas operations, utility electric operations and non-regulated. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area 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.

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

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated column below.

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

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

The following table provides significant segment financial data for the years ended December 31, 2018, 2017 and 2016 (millions):

Year Ended December 31, 2018	Gas		Electric			Non- Regulated		Other			Total
Revenues:
Billed and Unbilled Revenue	$	210.7	$	228.7		$	—	$	—		$	439.4
Rate Adjustment Mechanism Revenue		5.4		(5.4	)		—		—			—
Other Operating Revenue—Non-Regulated		—		—			4.7		—			4.7
Total Operating Revenues	$	216.1	$	223.3		$	4.7	$	—		$	444.1
Interest Income		0.8		0.8			0.2		0.6			2.4
Interest Expense		14.2		9.0			—		3.2			26.4
Depreciation & Amortization Expense		24.9		23.1			0.1		2.3			50.4
Income Tax Expense (Benefit)		7.1		4.2			0.5		(3.4	)		8.4
Segment Profit		18.8		11.4			1.3		1.5			33.0
Segment Assets		764.1		484.2			6.9		43.1			1,298.3
Capital Expenditures		70.8		28.4			—		3.2			102.4
Year Ended December 31, 2017
Revenues	$	194.0	$	206.2		$	6.0	$	—		$	406.2
Interest Income		0.7		1.0			0.1		0.6			2.4
Interest Expense		13.7		8.8			—		3.0			25.5
Depreciation & Amortization Expense		22.4		23.4			0.1		1.0			46.9
Income Tax Expense (Benefit)		10.7		7.5			0.7		(1.4	)		17.5
Segment Profit		16.4		11.9			1.2		(0.5	)		29.0
Segment Assets		714.3		476.9			6.7		44.0			1,241.9
Capital Expenditures		72.1		33.7			—		13.5			119.3
Year Ended December 31, 2016
Revenues	$	181.2	$	196.1		$	6.1	$	—		$	383.4
Interest Income		0.2		0.7			0.1		0.2			1.2
Interest Expense		13.3		8.3			—		2.1			23.7
Depreciation & Amortization Expense		21.9		23.8			0.1		0.8			46.6
Income Tax Expense (Benefit)		9.2		6.6			0.8		(1.2	)		15.4
Segment Profit		14.5		11.1			1.1		0.4			27.1
Segment Assets		645.2		441.1			6.8		35.1			1,128.2
Capital Expenditures		57.0		30.1			—		11.0			98.1

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Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2018

Allowance for Doubtful Accounts

Note 4: Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2018, 2017 and 2016, the Company recorded provisions for the energy commodity portion of bad debts of $2.6 million, $1.3 million and $1.6 million, respectively. These provisions were recognized in Cost of Gas Sales and Cost of Electric Sales expense as the associated electric and gas utility revenues were billed. Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling 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.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2016—2018 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision			Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2018
Electric	$	0.9	$	3.2		$	0.3	$	3.9	$	0.5
Gas		0.6		2.9			0.3		3.0		0.8
Other		0.1		(0.1	)		—		—		—
	$	1.6	$	6.0		$	0.6	$	6.9	$	1.3
Year Ended December 31, 2017
Electric	$	0.8	$	1.8		$	0.3	$	2.0	$	0.9
Gas		0.2		1.9			0.3		1.8		0.6
Other		0.1		—			—		—		0.1
	$	1.1	$	3.7		$	0.6	$	3.8	$	1.6
Year Ended December 31, 2016
Electric	$	0.6	$	2.9		$	0.3	$	3.0	$	0.8
Gas		0.5		1.7			0.3		2.3		0.2
Other		0.1		—			—		—		0.1
	$	1.2	$	4.6		$	0.6	$	5.3	$	1.1

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Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2018

Debt and Financing Arrangements

Note 5: Debt and Financing Arrangements

The Company funds a portion of its operations through the issuance of long-term debt and through short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow:

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants—The agreements under which the long-term debt of Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations, as described below.

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met; including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets.

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2018, in accordance with the covenants, these subsidiary companies had a combined amount of $249.2 million available for the payment of dividends and Unitil Corporation had $137.4 million available for the payment of dividends. As of December 31, 2018, the Company’s balance in Retained Earnings was $72.0 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2018 for the payment of dividends.

Issuance of Long-Term Debt—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.

On November 1, 2017, Northern Utilities issued $20 million of Notes due 2027 at 3.52% and $30 million of Notes due 2047 at 4.32%. Fitchburg issued $10 million of Notes due 2027 at 3.52% and $15 million of Notes due 2047 at 4.32%. Granite State issued $15 million of Notes due 2027 at 3.72%. Northern Utilities, Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017, to repay short-term debt and for general corporate purposes. Approximately $0.7 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $30.1 million, $17.2 million and $19.0 million in 2018, 2017, and 2016, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2018 is: 2019 – $18.8 million; 2020 – $19.8 million; 2021 – $8.6 million; 2022 – $28.2 million; 2023 – $6.7 million and thereafter $327.2 million.

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.

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2018		2017
Estimated Fair Value of Long-Term Debt	$	422.0	$	457.1

Details on long-term debt at December 31, 2018 and 2017 are shown below:

Long-Term Debt (millions)	December 31,
	2018		2017
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		10.0		15.0
8.49% Senior Secured Notes, Due October 14, 2024		6.0		7.5
6.96% Senior Secured Notes, Due September 1, 2028		20.0		20.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0
4.18% Senior Secured Notes, Due November 30, 2048		30.0		—
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		5.7		7.6
6.79% Senior Notes, Due October 15, 2025		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		—		10.0
5.29% Senior Notes, Due March 2, 2020		16.6		25.0
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
Granite State:
7.15% Senior Notes, Due December 15, 2018		—		3.3
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
Total Long-Term Debt		409.3		409.4
Less: Unamortized Debt Issuance Costs		3.5		3.3
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		405.8		406.1
Less: Current Portion		18.4		29.8
Total Long-Term Debt, Less Current Portion	$	387.4	$	376.3

Interest Expense, net—Interest expense is presented in the 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 calculated.

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 monthly 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. A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2018			2017			2016
Interest Expense
Long-Term Debt	$	23.1		$	21.8		$	21.8
Short-Term Debt		2.6			2.5			1.4
Regulatory Liabilities		0.7			1.2			0.5
Subtotal Interest Expense		26.4			25.5			23.7
Interest Income
Regulatory Assets		(0.8	)		(0.7	)		(0.3	)
AFUDC(1) and Other		(1.6	)		(1.7	)		(0.9	)
Subtotal Interest Income		(2.4	)		(2.4	)		(1.2	)
Total Interest Expense, net	$	24.0		$	23.1		$	22.5

⁽¹⁾  AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends to July 25, 2023, subject to two one-year extensions 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%. Provided there is no event of default, the Company may increase the borrowing limit under the Credit Facility by up to $50 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $265.6 million and $234.9 million for the years ended December 31, 2018 and December 31, 2017, respectively. Total gross repayments were $221.1 million and $278.5 million for the years ended December 31, 2018 and December 31, 2017, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2018 and December 31, 2017:

Revolving Credit Facility (millions)
	December 31,
	2018		2017
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	82.8	$	38.3
Letters of Credit Outstanding	$	—	$	—
Available	$	37.2	$	81.7

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2018 and December 31, 2017, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The weighted average interest rates on all short-term borrowings were 3.3%, 2.4%, and 1.8% during 2018, 2017, and 2016, respectively.

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.

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2018, there are $2.8 million of current and $2.3 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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 $8.4 million and $8.5 million of natural gas storage inventory at December 31, 2018 and 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2018, which was payable in January 2019, was $0.9 million and recorded in Accounts Payable at December 31, 2018. The amount of natural gas inventory released in December 2017, which was payable in January 2018, was $3.1 million and recorded in Accounts Payable at December 31, 2017.

Leases

Unitil’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.

Total rental expense under operating leases charged to operations for the years ended December 31, 2018, 2017 and 2016 amounted to $2.2 million, $2.0 million and $1.8 million respectively.

Assets under capital leases amounted to approximately $15.0 million and $15.0 million as of December 31, 2018 and 2017, respectively, less accumulated amortization of $1.7 million and $0.7 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 December 31, 2018. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $2.7 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2018. $2.8 million of the current Capital Lease Obligations and $2.3 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s)	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

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 December 31, 2018, there were approximately $4.3 million of guarantees outstanding.

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Equity

12 Months Ended

Dec. 31, 2018

Equity

Note 6: Equity

The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding. Details regarding these forms of capitalization follow:

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 14,815,585 and 14,876,955 shares of common stock outstanding at December 31, 2017 and December 31, 2018, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2017 and December 31, 2018.

Unitil Corporation Common Stock Offering—On December 14, 2017, the Company issued and sold 690,000 shares of its common stock at a price of $48.30 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $31.7 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan—During 2018, the Company sold 25,932 shares of its common stock, at an average price of $47.78 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.2 million. 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. During 2017 and 2016, the Company raised $1.3 million and $1.3 million, respectively, through the issuance of 26,256 and 32,095 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014, the Company may periodically repurchase shares of its common stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. (See Part II, Item 5, for additional information). During 2018, 2017 and 2016, the Company repurchased 791, 1,686 and 1,949 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was less than $0.1 million, $0.1 million and $0.1 million in 2018, 2017 and 2016, respectively.

During 2018, 2017 and 2016, the Company did not cancel or retire any of its common stock.

Stock-Based Compensation Plans—Unitil maintains a stock plan. The Company accounts for its stock-based compensation plan in accordance with the provisions of the FASB Codification and measures compensation costs at fair value at the date of grant. Details of the plan are as follows:

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.

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.

Restricted Shares issued for 2016 – 2018 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
1/26/16	43,220	$1.6
4/19/16	800	<$0.1
1/30/17	34,930	$1.6
1/29/18	37,510	$1.6

There were 29,252 and 89,326 non-vested shares under the Stock Plan as of December 31, 2018 and 2017, respectively. The weighted average grant date fair value of these shares was $42.86 per share and $39.54 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $2.2 million, $2.7 million and $2.2 million in 2018, 2017 and 2016, respectively. At December 31, 2018, there was approximately $0.8 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.3 years. There were 2,072 restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2018. On January 29, 2019, there were 33,150 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, 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 2018 and 2017 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2018				2017
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		52,224	$	36.22		43,345	$	33.40
Restricted Stock Units Granted		7,892	$	49.63		7,522	$	50.23
Dividend Equivalents Earned		1,673	$	47.85		1,357	$	48.57
Restricted Stock Units Settled		—		—		—		—
Ending Restricted Stock Units		61,789	$	38.25		52,224	$	36.22

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2018 and 2017 is $1.3 million and $1.0 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 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2018 and December 31, 2017. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2018 and December 31, 2017, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share (EPS).

(Millions except shares and per share data)	2018		2017		2016
Earnings Available to Common Shareholders	$	33.0	$	29.0	$	27.1
Weighted Average Common Shares Outstanding—Basic (000’s)		14,824		14,095		13,990
Plus: Diluted Effect of Incremental Shares (000’s)		5		7		6
Weighted Average Common Shares Outstanding—Diluted (000’s)		14,829		14,102		13,996
Earnings per Share—Basic and Diluted	$	2.23	$	2.06	$	1.94

The following table shows the number of weighted average non-vested restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.

	2018		2017		2016
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		6,102		8,733		600

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Energy Supply

12 Months Ended

Dec. 31, 2018

Energy Supply

Note 7: Energy Supply

NATURAL GAS SUPPLY

Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

Northern Utilities’ C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third-party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2018, 79% of Unitil’s largest New Hampshire gas customers, representing 37% of Unitil’s New Hampshire gas therm sales and 68% of Unitil’s largest Maine customers, representing 23% of Unitil’s Maine gas therm sales, are purchasing gas supply from a third-party supplier.

Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many large and some medium C&I customers purchase their gas supply from third-party suppliers while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2018, 85% of Unitil’s largest Massachusetts gas customers, representing 26% of Unitil’s Massachusetts gas therm sales, are purchasing gas supply from third-party suppliers. The approved costs associated with natural gas supplied to customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

Regulated Natural Gas Supply

Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers largely under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), via over the road trucking of supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 4.3 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

Fitchburg purchases natural gas under contracts from producers and marketers largely under contracts of one year or less, and occasionally on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), via trucking of supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round transportation and 0.33 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

ELECTRIC POWER SUPPLY

Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2018, 77% of Unitil’s largest New Hampshire customers, representing 24% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales and 81% of Unitil’s largest Massachusetts customers, representing 32% of Unitil’s Massachusetts electric kWh sales, are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base and customers in Ashby comprise another 4%. Buoyed by the municipal aggregations, 31% of Unitil’s residential customers in Massachusetts purchase their electricity from a third-party supplier as of December 2018.

In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier stands at 10%, down slightly relative to prior years when 13% of Unitil’s residential customers in New Hampshire purchased their supply from third-party suppliers. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

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 and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Long-Term Renewable Contracts

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 filed with MDPU in 2018 and approvals remain pending.

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.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies

Note 8: Commitments and Contingencies

Regulatory Matters

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MDPU, the NHPUC and the MPUC have each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31, 2017. The remaining balance of these assets is $0.9 million as of December 31, 2018, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $0.6 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next two years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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, has issued procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC has opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below). 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.

In Maine, Northern Utilities’ Maine division recently completed a base rate case (described below). The MPUC’s final order in that docket incorporated the lower tax rates in the calculation of rates for the Company.

Similarly, in New Hampshire, Northern Utilities’ New Hampshire division recently completed a base rate case proceeding (described below). The NHPUC’s final order in that docket approved a comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which included the effect of the tax changes in the calculation of the revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC approved the Company’s annual step increase pursuant to the provisions of its last base rate case, which included adjustments to account for the TCJA’s income tax changes.

In Massachusetts, the MDPU issued an order opening an investigation into the effect on rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. On December 21, 2018 the MDPU issued an order addressing the refund of excess ADIT in phase two of its investigation. Fitchburg was ordered to make a filing by January 4, 2019, for rates effective February 1, 2019, to refund $10.1 million for the electric division amortized over 15 years and $10.4 million for the gas division amortized over 14 years. The filing establishes a “Tax Act Credit Factor” for Fitchburg’s gas and electric divisions effective February 1, 2019 in accordance with the order. To the extent any of the regulatory liability above includes excess ADIT amounts specifically associated with reconciling mechanisms, Fitchburg shall return those amounts through the respective reconciling mechanism and adjust the regulatory liability amount accordingly. The MDPU approved this filing on January 16, 2019.

On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reduction under the TCJA.

Base Rate Activity

Unitil Energy—Base Rates—On April 20, 2017 the NHPUC approved a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019 to recover the revenue requirements associated with annual capital expenditures. On April 30, 2018, the NHPUC approved Unitil Energy’s step adjustment filing. The filing incorporated the revenue requirement of $3.3 million for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of the one-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resulted in a revenue decrease of $0.3 million.

Fitchburg—Base Rates—Electric—Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. While a number of the capital cost recovery filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. On November 1, 2018, Fitchburg filed its cumulative revenue requirement associated with the Company’s 2015, 2016 and 2017 capital expenditures and associated Capital Cost Adjustment Factors to become effective on January 1, 2019. On December 27, 2018, the Capital Cost Adjustment Factors were approved subject to further investigation and reconciliation. This matter remains pending.

Fitchburg—Electric Grid Modernization—On May 10, 2018, the MDPU issued an order approving a three year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Massachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to address pre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.

Fitchburg—Solar Generation—On November 9, 2016, the MDPU approved Fitchburg’s petition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing sought a net amount of approximately $0.3 million for recovery effective June 1, 2018. The recovery of this amount in rates was approved by the MDPU on May 31, 2018, subject to further investigation and reconciliation. A final order is pending.

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.

Fitchburg—Gas System Enhancement Program—Pursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31; and a filing, submitted on or before May 1, of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred. While a number of the filings under the GSEP tariff may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Under this tariff, a revenue increase of $0.9 million went into effect on May 1, 2018, subject to the annual cap and reconciliation. On October 31, 2018, the MDPU approved the Company’s request for a waiver of the annual cap in order to recover its reconciliation adjustment of $0.4 million effective November 1, 2018 associated with its actual 2017 revenue requirement.

Northern Utilities—Base Rates—Maine—On February 28, 2018, the MPUC issued its Final Order (Order) in Northern Utilities’ pending base rate case. The Order provided for an annual revenue increase of $2.1 million before a reduction of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million, and addressed a number of other issues, including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s Targeted Area Build-out (TAB) program and Targeted Infrastructure Replacement Adjustment (TIRA) mechanism. The new rates and other changes became effective on March 1, 2018.

Northern Utilities—Targeted Infrastructure Replacement Adjustment—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). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, 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, to recover the revenue requirements for 2017 eligible facilities.

Northern Utilities—Targeted Area Build-out Program—Maine—In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.

Northern Utilities—Base Rates—New Hampshire—On May 2, 2018, the NHPUC approved a settlement agreement providing for an annual revenue increase of $2.6 million, a reduction of annual revenue of $1.7 million to reflect the effect of the TCJA, and a step increase of $2.3 million to recover post-test year capital investments, all effective May 1, 2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case will be based on an historic test year of no earlier than twelve months ending December 31, 2020.

Northern Utilities—Franchise Extensions—New Hampshire—On October 3, 2018, the NHPUC granted Northern Utilities authority to expand its natural gas service territory in the Towns of Kingston, New Hampshire and Atkinson, New Hampshire (where the Company already had a limited franchise) to serve new industrial, commercial and residential customers. Northern Utilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and residential developments present the Company with opportunities for growth. The franchise petition for service to the Town of Epping 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. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding—On August 2, 2016, the NHPUC issued an order establishing an Energy Efficiency Resource Standard (EERS), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. The EERS includes a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs, and performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Order, on September 1, 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plan for the period 2018-2020, which was approved on January 2, 2018. On September 14, 2018, the New Hampshire electric and gas utilities jointly filed its 2019 update to the Statewide Energy Efficiency Plan. On December 31, 2018, the Commission approved a settlement agreement regarding the 2019 update to the plan.

Unitil Energy—Electric Grid Modernization—In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The final report was filed on March 20, 2017. This matter remains pending.

Unitil Energy—Net Metering—Pursuant to legislation that became effective in May 2016, the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The NHPUC issued an Order on June 23, 2017. The Order removes the cap on the total amount of generation capacity which may be owned or operated by customer-generators eligible for net metering. The order also adopts an alternative net metering tariff for small customer-generators (those with renewable energy systems of 100 kW or less) which will remain in effect for a period of years while further data is collected and analyzed, time-of-use and other pilot programs are implemented, and a distributed energy resource valuation study is conducted. Systems that are installed or queued during this period will have their net metering rate structure “grandfathered” until December 31, 2040. The Company does not believe that this proceeding will have a material adverse impact on the Company’s financial position, operating results or cash flows.

Unitil Energy—Recent Legislation—On September 13, 2018, the New Hampshire legislature voted to override New Hampshire Governor Sununu’s veto of Senate Bill 365. The enacted legislation requires Unitil Energy to enter into a power purchase agreement with a trash incinerator located in its service territory to purchase the facility’s entire net electrical output for a period that is coterminous with Unitil Energy’s next six default service procurements. The procurement is to be priced at the adjusted energy rate derived from the default service rates approved by the NHPUC in each applicable default service supply solicitation proceeding. The anticipated higher cost differential of the power purchase agreement is to be recovered through a non-by-passable charge applicable to all customers.

Fitchburg—Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System—On September 26, 2018, the Chairman of the MDPU directed the Department to procure and contract with 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 will issue a report that will include, but not be limited to, potential opportunities for improvement in each of these areas. Effective November 14, 2018, the MDPU engaged the evaluator to conduct the examination. On December 21, 2018, discovery was issued to the gas and municipal distribution companies, including the Company, and the Company provided its responses on January 9, 2019. The investigation is on-going.

Fitchburg—Electric Reconciliation Filing—The MDPU investigates and reviews Fitchburg’s annual filings which reconcile the costs and revenues in the Company’s various reconciliation accounts. Typically, the Reconciliation Filings are submitted during the fourth quarter for rates effective January 1 of the following year, and the MDPU approves them subject to reconciliation and pending further investigation. Subsequently, during the course of the year, the MDPU engages in more intensive review of these filings, including discovery and, when deemed necessary, the scheduling of evidentiary hearings. While a number of the Reconciling Filings may remain pending from year-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding.

Fitchburg—Service Quality—On March 1, 2018, Fitchburg submitted its 2017 Service Quality Reports for both its gas and electric divisions in accordance with new Service Quality Guidelines issued by the MDPU in December 2015. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. The MDPU approved the gas division’s filing on October 22, 2018. The electric division’s filing is pending approval.

Fitchburg—Energy Diversity—Massachusetts Governor Baker signed into law H.4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC), including Fitchburg, to jointly and competitively solicit proposals 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. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016, and adopted as final regulations on March 8, 2017. The EDCs issued the RFP for Long-Term Contracts for Clean Energy Projects, pursuant to Section 83d on March 31, 2017 and project proposals were received on July 27, 2017. Final selection of projects concluded in the first quarter of 2018, contracts were signed in June 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed the 83d long-term contracts with MDPU for approval. This matter remains pending. The EDCs issued the RFP for Long-Term Contracts for Offshore Wind Energy Projects pursuant to Section 83c on June 29, 2017 and project proposals were received on December 20, 2017. Final selection of projects was made in late May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed the 83c long-term contracts with MDPU for approval. This matter remains pending. A subsequent Section 83c solicitation is expected to be issued in June 2019.

Fitchburg—Recent Legislation—On August 9, 2018, Massachusetts Governor Baker signed into law H. 4857, “An Act to Advance Clean Energy.” The legislation contains numerous provisions, including: a requirement that increases the pace at which the Class 1 Renewable Portfolio Standard requirement increases, from the current pace of an additional 1 percent of sales each year to an additional 2 percent of sales each year during the period from January 1, 2020 through December 31, 2029; Electric supply contracts entered into after December 1, 2018 are required to provide a minimum percentage of kWh sales with clean peak resources, subject to regulations to be promulgated by the MDPU; Authorizes electric distribution companies to implement demand charges as part of a monthly minimum reliability charge provided the demand charge is based on system peak demand during the peak hours of the day and if affected customers are informed of the manner by which the demand charges are assessed and ways by which customers may manage and reduce demand; requires all gas distribution companies to report to the MDPU, in a uniform manner, lost and unaccounted for gas each year; Requires electric distribution companies to annually file with the MDPU an Electric Distribution System Resiliency Report which must include heat maps that show the electric load on the distribution system including loads during peak times, highlight the most congested or constrained areas of the distribution system and identify areas of the system most vulnerable to outages due to high electricity demand, lack of local generation, and extreme weather events; Establishes an energy storage target of 1,000 megawatt (MW) hours to be achieved by December 31, 2025, and requires each electric distribution company to submit a report to the Massachusetts Department of Energy Resources (DOER) documenting the energy storage installation in their service territory; Requires the DOER to investigate the necessity of requiring electric distribution companies to jointly conduct additional offshore wind generation solicitations and procurement of up to 1,600 MW of capacity in addition to the 1,600 MW required in H.4568 “An Act to Promote Energy Diversity”. Many of these provisions require further development and implementation by the MDPU and DOER. Fitchburg intends to actively participate in all such proceedings and will comply with all regulatory directives and requirements resulting from these legislative changes.

Fitchburg—Clean Energy RFP—Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposals for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations concluded during the second quarter of 2017. On September 20, 2017, Fitchburg, along with the other three EDCs, filed for approval of the purchase power agreements which were negotiated as a result of the joint solicitation. A hearing on the merits was held in February 2018. The MDPU approved the agreements on June 15, 2018.

Fitchburg—Other—On August 25, 2017, the Massachusetts Department of Energy Resources (DOER) issued its final Solar Massachusetts Renewable Target (SMART) Program regulations. These regulations were promulgated pursuant to Chapter 75 of the Acts of 2016, which required the DOER to establish a new solar incentive program. The regulation is designed to support the continued development of an additional 1,600 MW of solar renewable energy generating sources via a declining block compensation mechanism. On September 12, 2017, the Massachusetts electric utilities jointly filed a model SMART tariff with the MDPU to implement the program and propose a cost recovery mechanism. Hearings on the merits were held in late March and early April 2018. The MDPU issued its Order on September 26, 2018 making the program effective on that date. The MDPU approved a final model tariff on November 20, 2018 and approved Fitchburg’s company specific tariff on December 21, 2018. On or before November 1 of each year the Company is required to submit to the MDPU its annual SMART Factor cost recovery filing for effect January 1 of the next year. On December 27, 2018, the MDPU approved Fitchburg’s proposed SMART Factors for effect January 1, 2019, subject to investigation and reconciliation. This matter remains pending.

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 and remains pending. 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.

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court, (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint sought an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remained pending. The Company resolved this matter by settlement in the fall of 2018 and there was no material impact on the Company’s financial position, operating results or cash flows.

Environmental Matters

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2018, 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 to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required.

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 Environmental Obligations for the years ended December 31, 2018 and 2017. The Company’s current and noncurrent environmental obligations are recorded on the Company’s Consolidated Balance Sheets in Other Current Liabilities and Other Noncurrent Liabilities, respectively.

Environmental Obligations

	(millions)
	Fitchburg				Northern Utilities				Total
	2018		2017		2018		2017		2018		2017
Total Balance at Beginning of Period	$	0.1	$	0.1	$	2.0	$	1.8	$	2.1	$	1.9
Additions		—		—		0.3		0.4		0.3		0.4
Less: Payments / Reductions		0.1		—		0.3		0.2		0.4		0.2
Total Balance at End of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Less: Current Portion		—		—		0.6		0.5		0.6		0.5
Noncurrent Balance at December 31,	$	—	$	0.1	$	1.4	$	1.5	$	1.4	$	1.6

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Income Taxes

12 Months Ended

Dec. 31, 2018

Income Taxes

Note 9: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2018, 2017 and 2016 are shown in the table below:

	($000’s)
	2018		2017		2016
Current Income Tax Provision
Federal	$	—	$	—	$	—
State		355		—		—
Total Current Income Taxes	$	355		—		—
Deferred Income Provision
Federal	$	5,032		13,675		11,209
State		3,006		3,862		4,145
Total Deferred Income Taxes		8,038		17,537		15,354
Total Income Tax Expense	$	8,393	$	17,537	$	15,354

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

	2018			2017			2016
Statutory Federal Income Tax Rate		21	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		6			6			4
Utility Plant Differences		(7	)		(1	)		(1	)
Tax Credits and Other, net		—			(1	)		(1	)
Effective Income Tax Rate		20	%		38	%		36	%

Temporary differences which gave rise to deferred tax assets and liabilities in 2018 and 2017 are shown below:

Temporary Differences (000’s)	2018		2017
Deferred Tax Assets
Retirement Benefit Obligations	$	32,249	$	38,915
Net Operating Loss Carryforwards		10,773		12,686
Tax Credit Carryforwards		2,704		3,536
Other, net		1,571		1,155
Total Deferred Tax Assets	$	47,297	$	56,292
Deferred Tax Liabilities
Utility Plant Differences	$	132,682	$	127,932
Regulatory Assets & Liabilities		6,429		9,323
Other, net		5,964		1,894
Total Deferred Tax Liabilities		145,075		139,149
Net Deferred Tax Liabilities	$	97,778	$	82,857

The Company is subject to federal and state income taxes as well as various other business taxes. 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. As a regulated Public Utility Holding Company (PUHC) entity under the Energy Policy Act of 2005; the Company follows income tax accounting guidance and regulations promulgated by the FERC for regulated utility companies under its jurisdiction. Also, the MDPU, NHPUC and the MPUC have, from time to time, issued specific income tax accounting rules for regulated utility companies in their respective jurisdictions. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company 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 that gave rise to the revision become known.

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.

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 first 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.

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.

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 to be between fifteen and twenty years. 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 is $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 expects to recognize the remaining $3.4 million of this excess ADIT in future periods in accordance with regulatory guidance as discussed above.

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, 2017 with the Internal Revenue Service in September 2018 and generated additional federal NOLC assets of $3.7 million principally due to pension cost deductions, tax repair deductions, tax depreciation and research and development deductions. For the year ended December 31, 2018, the Company calculated federal current tax of $7.7 million and offset it with a decrease to the federal NOLC of $7.7 million, resulting in no federal current taxes payable for the period. As of December 31, 2018, the Company had recorded cumulative federal and state NOLC assets of $10.8 million 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, 2017, the Company had $3.5 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.

In March 2018, Unitil Corporation received notice that its Federal Income Tax return filings for the years ended December 31, 2015 and December 31, 2016 are under examination by the IRS. Currently, the Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s financial statements. The Company remains subject to examination by New Hampshire tax authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017. Income tax filings for the year ended December 31, 2017 have been filed with the New Hampshire Department of Revenue Administration. The State of Maine has concluded its review of the Company’s tax returns for December 31, 2014, December 31, 2015, and December 31, 2016 which resulted in a small additional refund to the Company.

The Company evaluated its tax positions at December 31, 2018 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 Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017.

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Retirement Benefit Plans

12 Months Ended

Dec. 31, 2018

Retirement Benefit Plans

Note 10: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:

• The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

• The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified retirement plan, with participation limited to executives selected by the Board of Directors.

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

	2018			2017			2016
Used to Determine Plan costs for years ended December 31:
Discount Rate		3.60	%		4.10	%		4.30	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.50	%		8.00	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2025			2022

Used to Determine Benefit Obligations at December 31:
Discount Rate	4.25	%	3.60	%	4.10	%
Rate of Compensation Increase	3.00	%	3.00	%	3.00	%
Health Care Cost Trend Rate Assumed for Next Year	7.00	%	7.50	%	8.00	%
Ultimate Health Care Cost Trend Rate	4.50	%	4.50	%	4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached	2024		2024		2025

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2018, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $589,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2018 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

The following table provides the components of the Company’s Retirement plan costs (000’s):

	Pension Plan									PBOP Plan									SERP
	2018			2017			2016			2018			2017			2016			2018		2017		2016
Service Cost	$	3,393		$	3,295		$	3,402		$	2,933		$	2,974		$	2,610		$	487	$	460	$	162
Interest Cost		5,878			6,057			5,945			3,404			3,913			3,232			404		392		386
Expected Return on Plan Assets		(7,785	)		(7,306	)		(7,257	)		(1,635	)		(1,347	)		(1,205	)		—		—		—
Prior Service Cost Amortization		324			263			263			1,309			1,399			1,486			189		189		189
Actuarial Loss Amortization		5,786			4,662			4,398			1,383			2,098			1,049			486		295		375
Sub-total		7,596			6,971			6,751			7,394			9,037			7,172			1,566		1,336		1,112
Amounts Capitalized or Deferred		(3,465	)		(3,122	)		(3,008	)		(3,416	)		(4,515	)		(3,351	)		(451)		(397)		(290)
NPBC Recognized	$	4,131		$	3,849		$	3,743		$	3,978		$	4,522		$	3,821		$	1,115	$	939	$	822

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2018, 2017 and 2016 before capitalization and deferral was $7.6 million, $7.0 million and $6.8 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2018, 2017 and 2016 would have been $7.2 million, $7.6 million and $7.7 million respectively, prior to amounts capitalized or deferred.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2018			2017			2018			2017			2018			2017
Plan Assets at Beginning of Year	$	102,315		$	91,058		$	20,234		$	16,606		$	—		$	—
Actual Return on Plan Assets		(6,149	)		12,731			(1,085	)		1,907			—			—
Employer Contributions		16,628			4,100			4,000			4,000			401			34
Participant Contributions		—			—			153			126			—			—
Benefits Paid		(4,986	)		(5,574	)		(2,193	)		(2,405	)		(401	)		(34	)
Plan Assets at End of Year	$	107,808		$	102,315		$	21,109		$	20,234		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	166,921		$	150,439		$	94,122		$	96,659		$	11,723		$	9,566
Service Cost		3,393			3,295			2,933			2,974			487			460
Interest Cost		5,878			6,057			3,404			3,913			404			392
Participant Contributions		—			—			153			126			—			—
Plan Amendments		—			608			—			—			—			—
Benefits Paid		(4,986	)		(5,574	)		(2,193	)		(2,405	)		(401	)		(34	)
Actuarial (Gain) or Loss		(15,009	)		12,096			(17,414	)		(7,145	)		1,541			1,339
PBO at End of Year	$	156,197		$	166,921		$	81,005		$	94,122		$	13,754		$	11,723
Funded Status: Assets vs PBO	$	(48,389	)	$	(64,606	)	$	(59,896	)	$	(73,888	)	$	(13,754	)		(11,723	)

The decrease in the PBO for the Pension plan as of December 31, 2018 compared to December 31, 2017 reflects an increase in the assumed discount rate as of December 31, 2018. The decrease in the PBO for the PBOP plan as of December 31, 2018 compared to December 31, 2017 reflects an increase in the assumed discount rate as of December 31, 2018 and the rate of increase for medical premiums being less than the assumed rate of medical inflation.

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets, net of deferred tax benefits, of $72.0 million and $84.5 million at December 31, 2018 and 2017, respectively, to account for the future collection of these plan obligations in electric and gas rates.

The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $142.8 million and $150.6 million as of December 31, 2018 and 2017, respectively. The ABO for the SERP was $10.8 million and $9.5 million as of December 31, 2018 and 2017, respectively. For the PBOP Plan, the ABO and PBO are the same.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan 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 Plan costs.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

	Pension Plan						PBOP Plan						SERP
	2018		2017		2016		2018		2017		2016		2018		2017		2016
Employer Contributions	$	16,628	$	4,100	$	5,146	$	4,000	$	4,000	$	4,000	$	401	$	34	$	34
Participant Contributions	$	—	$	—	$	—	$	153	$	126	$	61		$—	$	—	$	—
Benefit Payments	$	4,986	$	5,574	$	4,900	$	2,193	$	2,405	$	2,421	$	401	$	34	$	34

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2019	$	5,888	$	2,314	$	522
2020		6,484		2,520		521
2021		6,949		2,780		681
2022		6,853		2,955		678
2022		7,588		3,106		675
2024 - 2028		46,942		19,244		4,904

The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 53% in common stock equities, 37% in fixed income securities and 10% in real estate securities. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2019			Actual Allocation at December 31,
				2018			2017			2016
Equity Funds		53	%		49	%		49	%		46	%
Debt Funds		37	%		40	%		34	%		37	%
Real Estate Fund		10	%		10	%		10	%		10	%
Asset Allocation Fund(1)		—			—			6	%		7	%
Other(2)		—			1	%		1	%		—
Total					100	%		100	%		100	%

(1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

(2) Represents investments being held in cash equivalents as of December 31, 2018 pending payment of benefits.

PBOP Plan	Target Allocation 2019			Actual Allocation at December 31,
				2018			2017			2016
Equity Funds		55	%		53	%		56	%		55	%
Debt Funds		45	%		47	%		42	%		43	%
Other(1)		—			—			2	%		2	%
Total					100	%		100	%		100	%

(1) Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds.

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.75% for 2018. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2018 and 2017. Please also see Note 1 for a discussion of the Company’s fair value accounting policy.

Equity, Fixed Income, Index and Asset Allocation Funds

These investments are valued based on quoted prices from active markets. These securities are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Cash  Equivalents

These investments are valued at cost, which approximates fair value, and are categorized in Level 1.

Real Estate Fund

These investments are valued at net asset value (NAV) per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity. In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy. The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2018 and 2017 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2018
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	52,884	$	52,884	$	—	$	—
Fixed Income Funds		43,281		43,281		—		—
Total Mutual Funds		96,165		96,165		—		—
Cash Equivalents		1,202		1,202		—
Total Assets in the Fair Value Hierarchy	$	97,367	$	97,367	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		10,441
Total Assets	$	107,808
2017
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	50,373	$	50,373	$	—	$	—
Fixed Income Funds		34,757		34,757		—		—
Asset Allocation Fund		6,398		6,398		—		—
Total Mutual Funds		91,528		91,528		—		—
Cash Equivalents		1,200		1,200		—
Total Assets in the Fair Value Hierarchy	$	92,728	$	92,728	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		9,587
Total Assets	$	102,315

Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments.

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2018 and 2017 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2018
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	9,905	$	9,905	$	—	$	—
Equity Funds		11,204		11,204
Total Assets	$	21,109	$	21,109	$	—	$	—
2017
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	8,419	$	8,419	$	—	$	—
Equity Funds		11,415		11,415
Total Mutual Funds		19,834		19,834
Cash Equivalents		400		400
Total Assets	$	20,234	$	20,234	$	—	$	—

Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $2.7 million, $2.4 million and $2.3 million for the years ended December 31, 2018, 2017 and 2016, respectively.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

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. are 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 capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”).

Granite State is an interstate 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 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) are wholly- owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers.

Principles of Consolidation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation related to the adoption of new accounting standards.

Use of Estimates

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

Fair Value

Fair Value—The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:

Level 1—	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2—	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3—	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

There have been no changes in the valuation techniques used during the current period.

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.

In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017 recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the twelve months ended December 31, 2018. 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.

As discussed below, the Company plans to disclose billed and unbilled revenue separately from rate adjustment mechanism revenue in the Notes to the Consolidated Financial Statements for periods in 2018 going forward, and will also provide this disclosure for prior periods for informational purposes.

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. The lower revenues reported in the twelve months ended December 31, 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act of 2017 (TCJA) are shown separately in the tables below for informational purposes.

	Twelve Months Ended December 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	81.4		$	123.6		$	205.0
Commercial & Industrial		119.7			96.4			216.1
Other		13.3			11.3			24.6
Revenue Reductions—TCJA		(3.7	)		(2.6	)		(6.3	)
Total Billed and Unbilled Revenue		210.7			228.7			439.4
Rate Adjustment Mechanism Revenue		5.4			(5.4	)		—
Total Gas and Electric Operating Revenues	$	216.1		$	223.3		$	439.4
	Twelve Months Ended December 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	71.2		$	107.9		$	179.1
Commercial & Industrial		102.8			87.7			190.5
Other		13.5			6.0			19.5
Total Billed and Unbilled Revenue		187.5			201.6			389.1
Rate Adjustment Mechanism Revenue		6.5			4.6			11.1
Total Gas and Electric Operating Revenues	$	194.0		$	206.2		$	400.2
	Twelve Months Ended December 31, 2016
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	61.5		$	101.9		$	163.4
Commercial & Industrial		92.7			81.5			174.2
Other		11.2			4.9			16.1
Total Billed and Unbilled Revenue		165.4			188.3			353.7
Rate Adjustment Mechanism Revenue		15.8			7.8			23.6
Total Gas and Electric Operating Revenues	$	181.2		$	196.1		$	377.3

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 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—Usource, Unitil’s non-regulated subsidiary, conducts its business activities as a broker of competitive energy services. Usource does not take title to the electric and gas commodities which are the subject of the brokerage contracts. The Company records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partners with certain entities to facilitate these brokerage services and pays these entities a fee under revenue sharing agreements.

As discussed above, the Company adopted ASU 2014-09 in the first quarter of 2018. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. ASU 2014-09 requires that payments made by Usource to third parties (Channel Partners) for revenue sharing agreements are recognized net, as a reduction from revenue, where those payments were previously recognized gross as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to third parties for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $1.0 million, $1.1 million and $1.0 million in 2018, 2017 and 2016, respectively.

If ASU 2014-09 had been in effect for 2017 and 2016, the result would have been corresponding reductions of $1.1 million and $1.0 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below.

Other Operating Revenues ($ millions):	Twelve Months Ended December 31
	As Reported			If ASU 2014-09 Had Been in Effect
	2018			2017			2016
Usource Contract Revenue	$	5.7		$	6.0		$	6.1
Less: Revenue Sharing Payments		(1.0	)		(1.1	)		(1.0	)
Total Other Operating Revenues	$	4.7		$	4.9		$	5.1

Operation and Maintenance Expense ($ millions):	Twelve Months Ended December 31
	As Reported		If ASU 2014-09 Had Been in Effect
	2018		2017		2016
Operation and Maintenance Expense	$	69.5	$	63.4	$	60.4

Retirement Benefit Costs

Retirement Benefit Costs—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan) and the Unitil Corporation Supplemental Executive Retirement Plan (SERP).The net periodic benefit costs associated with these benefit plans consist of service cost and other components (See Note 10 to the Consolidated Financial Statements). In the first quarter of 2018, the Company adopted ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-K for the twelve months ended December 31, 2018, the service cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Other Expense (Income), net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. The change in presentation for the twelve months ended December 31, 2018 resulted in a reduction of “Operations and Maintenance” and an increase in “Other Expense (Income), net” on the Consolidated Statements of Earnings for the prior periods. There are $5.5 million, $5.7 million and $4.9 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the twelve months ended December 31, 2018, 2017 and 2016, respectively, net of amounts deferred as regulatory assets for future recovery.

Depreciation and Amortization

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2018 – 3.38%, 2017 – 3.45% and 2016 – 3.49%.

Stock-based Employee Compensation

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes

Sales and Consumption Taxes—The Company bills its customers sales tax in Massachusetts and Maine and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings. The consumption tax in New Hampshire has been repealed effective January 1, 2019.

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 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 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.

Dividends

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2018 the Company paid quarterly dividends of $0.365 per share, resulting in an annualized dividend rate of $1.46 per common share. For the years ended December 31, 2017 and 2016, the Company paid quarterly dividends of $0.36 and $0.355 per common share, respectively, resulting in annualized dividend rates of $1.44 and $1.42 per common share, respectively. At its January 2019 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.37 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.48 per share from $1.46 per share.

Cash and Cash Equivalents

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2018 and 2017, the Unitil subsidiaries had deposited $3.5 million and $2.9 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2018 and 2017.

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. 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.

Accrued Revenue

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2018 and 2017.

Accrued Revenue (millions)	December 31,
	2018		2017
Regulatory Assets—Current	$	41.3	$	39.5
Unbilled Revenues		13.4		13.8
Total Accrued Revenue	$	54.7	$	53.3

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 December 31, 2018 and 2017.

Exchange Gas Receivable (millions)	December 31,
	2018		2017
Northern Utilities	$	7.5	$	5.4
Fitchburg		0.6		0.4
Total Exchange Gas Receivable	$	8.1	$	5.8

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 December 31, 2018 and 2017.

Gas Inventory (millions)	December 31,
	2018		2017
Natural Gas	$	0.3	$	0.4
Propane		0.4		0.1
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	0.8	$	0.6

Utility Plant

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.70%, 2.90% and 2.18% in 2018, 2017 and 2016, respectively. 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 December 31, 2018 and 2017, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $90.7 million and $84.3 million, respectively.

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.

Regulatory Assets consist of the following (millions)	December 31,
	2018		2017
Retirement Benefits	$	72.0	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		38.4		36.0
Deferred Storm Charges		6.3		7.2
Environmental		7.9		9.5
Income Taxes		5.7		6.5
Other Deferred Charges		10.0		5.4
Total Regulatory Assets	$	140.3	$	149.1
Less: Current Portion of Regulatory Assets(1)		41.3		39.5
Regulatory Assets—noncurrent	$	99.0	$	109.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions)	December 31,
	2018		2017
Rate Adjustment Mechanisms	$	11.5	$	6.9
Gas Pipeline Refund		—		2.3
Income Taxes (Note 9)		47.0		48.9
Total Regulatory Liabilities		58.5		58.1
Less: Current Portion of Regulatory Liabilities		11.5		9.2
Regulatory Liabilities—noncurrent	$	47.0	$	48.9

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2018 are $6.0 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material 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 qualify as a derivative instrument under the guidance set forth in the FASB Codification.

The Company previously operated a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service, which included use of derivative instruments. The hedging program was terminated in 2018.

Under the hedging program previously operated by Northern Utilities, any gains or losses resulting from the change in the fair value of these derivatives were passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause. The fair value of these derivatives was determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company recorded gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassified these gains or losses into Cost of Gas Sales when the gains and losses were passed through to customers through the Cost of Gas Clause.

As of December 31, 2018 and December 31, 2017, the Company had zero and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program. The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31, 2018 and December 31, 2017. There was zero and $0.4 million of losses / (gains) recognized in Regulatory Assets / Liabilities for the years ended December 31, 2018 and 2017, respectively. There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31, 2018 and 2017.

Investments in Marketable Securities

Investments in Marketable Securities—The Company maintains 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 Supplemental Executive Retirement Plan (SERP) (See further discussion of the SERP in Note 10).

At December 31, 2018 and 2017, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $4.8 million and $3.6 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, net.

Fair Value of Marketable Securities (millions)	December 31,
	2018		2017
Equity Funds	$	—	$	2.1
Fixed Income Funds		—		1.5
Money Market Funds		4.8		—
Total Marketable Securities	$	4.8	$	3.6

Energy Supply Obligations

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

	December 31,
Energy Supply Obligations consist of the following: (millions)	2018		2017
Current:
Exchange Gas Obligation	$	7.5	$	5.4
Renewable Energy Portfolio Standards		5.6		4.0
Power Supply Contract Divestitures		0.3		0.3
Total Energy Supply Obligations—Current	$	13.4	$	9.7
Noncurrent:
Power Supply Contract Divestitures	$	0.6	$	0.9
Total Energy Supply Obligations	$	14.0	$	10.6

Exchange Gas Obligation—As discussed above, 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 maintain accrued revenue 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 filed with MDPU in 2018 and approvals remain pending.

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—Unitil Energy’s and Fitchburg’s customers are entitled 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 (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (noncurrent portion).

Retirement Benefit Obligations

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements

Off-Balance Sheet Arrangements—As of December 31, 2018, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2018, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2018, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements

Recently Issued Pronouncements— In August 2018, the FASB issued Accounting Standards Update (ASU) No. 2018-14, “Compensation—Retirement Benefits—Defined Benefit Plans—General (Sutopic 715-20)” which amends existing guidance to add, remove and clarify disclosure requirements related to defined benefit pension and other postretirement plans. The ASU is effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company adopted this ASU in the fourth quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

In June 2018, the FASB issued ASU No. 2018-07, “Compensation—Stock Compensation (Topic 718)” which amends the existing guidance relating to the accounting for nonemployee share-based payments. Under this ASU, most of the guidance on share-based payments to nonemployees will be aligned with the requirements for share-based payments granted to employees. The ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted this ASU in the second quarter of 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, “Compensation—Retirement Benefits (Topic 715)” which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for the Company on January 1, 2018. The change in capitalization of retirement benefits did not have a material impact on the Company’s Consolidated Financial Statements.

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. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company plans to adopt the standard as of January 1, 2019. The Company will elect 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 will also elect 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 will make an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company will recognize those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The Company expects that adoption of the standard will result 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 does not believe the standard will have a material effect on its Consolidated Statements of Earnings and Consolidated Statements of Cash Flows.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.

The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales.

The Company used the modified retrospective method when adopting the new standard on January 1, 2018. The new guidance did not have a material impact to the Consolidated Financial Statements. (See “Utility Revenue Recognition” and “Other Operating Revenue—Non-regulated” above.)

In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. The ASU became effective for the Company on January 1, 2018 and it did not have a material impact on the Company’s Consolidated Financial Statements.

Other than the pronouncements 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 evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

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. The lower revenues reported in the twelve months ended December 31, 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act of 2017 (TCJA) are shown separately in the tables below for informational purposes.

	Twelve Months Ended December 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	81.4		$	123.6		$	205.0
Commercial & Industrial		119.7			96.4			216.1
Other		13.3			11.3			24.6
Revenue Reductions—TCJA		(3.7	)		(2.6	)		(6.3	)
Total Billed and Unbilled Revenue		210.7			228.7			439.4
Rate Adjustment Mechanism Revenue		5.4			(5.4	)		—
Total Gas and Electric Operating Revenues	$	216.1		$	223.3		$	439.4
	Twelve Months Ended December 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	71.2		$	107.9		$	179.1
Commercial & Industrial		102.8			87.7			190.5
Other		13.5			6.0			19.5
Total Billed and Unbilled Revenue		187.5			201.6			389.1
Rate Adjustment Mechanism Revenue		6.5			4.6			11.1
Total Gas and Electric Operating Revenues	$	194.0		$	206.2		$	400.2
	Twelve Months Ended December 31, 2016
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	61.5		$	101.9		$	163.4
Commercial & Industrial		92.7			81.5			174.2
Other		11.2			4.9			16.1
Total Billed and Unbilled Revenue		165.4			188.3			353.7
Rate Adjustment Mechanism Revenue		15.8			7.8			23.6
Total Gas and Electric Operating Revenues	$	181.2		$	196.1		$	377.3

Schedule of Other Operating Revenues and Operating Expenses

If ASU 2014-09 had been in effect for 2017 and 2016, the result would have been corresponding reductions of $1.1 million and $1.0 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below.

Other Operating Revenues ($ millions):	Twelve Months Ended December 31
	As Reported			If ASU 2014-09 Had Been in Effect
	2018			2017			2016
Usource Contract Revenue	$	5.7		$	6.0		$	6.1
Less: Revenue Sharing Payments		(1.0	)		(1.1	)		(1.0	)
Total Other Operating Revenues	$	4.7		$	4.9		$	5.1

Operation and Maintenance Expense ($ millions):	Twelve Months Ended December 31
	As Reported		If ASU 2014-09 Had Been in Effect
	2018		2017		2016
Operation and Maintenance Expense	$	69.5	$	63.4	$	60.4

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2018 and 2017.

Accrued Revenue (millions)	December 31,
	2018		2017
Regulatory Assets—Current	$	41.3	$	39.5
Unbilled Revenues		13.4		13.8
Total Accrued Revenue	$	54.7	$	53.3

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2018 and 2017.

Exchange Gas Receivable (millions)	December 31,
	2018		2017
Northern Utilities	$	7.5	$	5.4
Fitchburg		0.6		0.4
Total Exchange Gas Receivable	$	8.1	$	5.8

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2018 and 2017.

Gas Inventory (millions)	December 31,
	2018		2017
Natural Gas	$	0.3	$	0.4
Propane		0.4		0.1
Liquefied Natural Gas & Other		0.1		0.1
Total Gas Inventory	$	0.8	$	0.6

Regulatory Assets

Regulatory Assets consist of the following (millions)	December 31,
	2018		2017
Retirement Benefits	$	72.0	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		38.4		36.0
Deferred Storm Charges		6.3		7.2
Environmental		7.9		9.5
Income Taxes		5.7		6.5
Other Deferred Charges		10.0		5.4
Total Regulatory Assets	$	140.3	$	149.1
Less: Current Portion of Regulatory Assets(1)		41.3		39.5
Regulatory Assets—noncurrent	$	99.0	$	109.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities

Regulatory Liabilities consist of the following (millions)	December 31,
	2018		2017
Rate Adjustment Mechanisms	$	11.5	$	6.9
Gas Pipeline Refund		—		2.3
Income Taxes (Note 9)		47.0		48.9
Total Regulatory Liabilities		58.5		58.1
Less: Current Portion of Regulatory Liabilities		11.5		9.2
Regulatory Liabilities—noncurrent	$	47.0	$	48.9

Fair Value of Marketable Securities

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

Fair Value of Marketable Securities (millions)	December 31,
	2018		2017
Equity Funds	$	—	$	2.1
Fixed Income Funds		—		1.5
Money Market Funds		4.8		—
Total Marketable Securities	$	4.8	$	3.6

Components of Energy Supply Obligations

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

	December 31,
Energy Supply Obligations consist of the following: (millions)	2018		2017
Current:
Exchange Gas Obligation	$	7.5	$	5.4
Renewable Energy Portfolio Standards		5.6		4.0
Power Supply Contract Divestitures		0.3		0.3
Total Energy Supply Obligations—Current	$	13.4	$	9.7
Noncurrent:
Power Supply Contract Divestitures	$	0.6	$	0.9
Total Energy Supply Obligations	$	14.0	$	10.6

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Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Information

	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2018		2017		2018		2017		2018		2017		2018		2017
Total Operating Revenues	$	145.8	$	126.0	$	84.5	$	80.8	$	88.2	$	84.0	$	125.6	$	115.4
Operating Income	$	28.1	$	27.7	$	10.6	$	11.6	$	10.3	$	10.4	$	22.2	$	25.7
Net Income Applicable to Common	$	15.6	$	12.4	$	3.6	$	3.1	$	2.8	$	2.3	$	11.0	$	11.2
	Per Share Data:
Earnings Per Common Share	$	1.06	$	0.88	$	0.24	$	0.23	$	0.19	$	0.16	$	0.74	$	0.79
Dividends Paid Per Common Share	$	0.365	$	0.360	$	0.365	$	0.360	$	0.365	$	0.360	$	0.365	$	0.360

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2018

Significant Segment Financial Data

The following table provides significant segment financial data for the years ended December 31, 2018, 2017 and 2016 (millions):

Year Ended December 31, 2018	Gas		Electric			Non- Regulated		Other			Total
Revenues:
Billed and Unbilled Revenue	$	210.7	$	228.7		$	—	$	—		$	439.4
Rate Adjustment Mechanism Revenue		5.4		(5.4	)		—		—			—
Other Operating Revenue—Non-Regulated		—		—			4.7		—			4.7
Total Operating Revenues	$	216.1	$	223.3		$	4.7	$	—		$	444.1
Interest Income		0.8		0.8			0.2		0.6			2.4
Interest Expense		14.2		9.0			—		3.2			26.4
Depreciation & Amortization Expense		24.9		23.1			0.1		2.3			50.4
Income Tax Expense (Benefit)		7.1		4.2			0.5		(3.4	)		8.4
Segment Profit		18.8		11.4			1.3		1.5			33.0
Segment Assets		764.1		484.2			6.9		43.1			1,298.3
Capital Expenditures		70.8		28.4			—		3.2			102.4
Year Ended December 31, 2017
Revenues	$	194.0	$	206.2		$	6.0	$	—		$	406.2
Interest Income		0.7		1.0			0.1		0.6			2.4
Interest Expense		13.7		8.8			—		3.0			25.5
Depreciation & Amortization Expense		22.4		23.4			0.1		1.0			46.9
Income Tax Expense (Benefit)		10.7		7.5			0.7		(1.4	)		17.5
Segment Profit		16.4		11.9			1.2		(0.5	)		29.0
Segment Assets		714.3		476.9			6.7		44.0			1,241.9
Capital Expenditures		72.1		33.7			—		13.5			119.3
Year Ended December 31, 2016
Revenues	$	181.2	$	196.1		$	6.1	$	—		$	383.4
Interest Income		0.2		0.7			0.1		0.2			1.2
Interest Expense		13.3		8.3			—		2.1			23.7
Depreciation & Amortization Expense		21.9		23.8			0.1		0.8			46.6
Income Tax Expense (Benefit)		9.2		6.6			0.8		(1.2	)		15.4
Segment Profit		14.5		11.1			1.1		0.4			27.1
Segment Assets		645.2		441.1			6.8		35.1			1,128.2
Capital Expenditures		57.0		30.1			—		11.0			98.1

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Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2018

Allowance for Doubtful Accounts

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2016—2018 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision			Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2018
Electric	$	0.9	$	3.2		$	0.3	$	3.9	$	0.5
Gas		0.6		2.9			0.3		3.0		0.8
Other		0.1		(0.1	)		—		—		—
	$	1.6	$	6.0		$	0.6	$	6.9	$	1.3
Year Ended December 31, 2017
Electric	$	0.8	$	1.8		$	0.3	$	2.0	$	0.9
Gas		0.2		1.9			0.3		1.8		0.6
Other		0.1		—			—		—		0.1
	$	1.1	$	3.7		$	0.6	$	3.8	$	1.6
Year Ended December 31, 2016
Electric	$	0.6	$	2.9		$	0.3	$	3.0	$	0.8
Gas		0.5		1.7			0.3		2.3		0.2
Other		0.1		—			—		—		0.1
	$	1.2	$	4.6		$	0.6	$	5.3	$	1.1

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Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value of Long Term Debt

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2018		2017
Estimated Fair Value of Long-Term Debt	$	422.0	$	457.1

Details on Long Term Debt

Details on long-term debt at December 31, 2018 and 2017 are shown below:

Long-Term Debt (millions)	December 31,
	2018		2017
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		10.0		15.0
8.49% Senior Secured Notes, Due October 14, 2024		6.0		7.5
6.96% Senior Secured Notes, Due September 1, 2028		20.0		20.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0
4.18% Senior Secured Notes, Due November 30, 2048		30.0		—
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		5.7		7.6
6.79% Senior Notes, Due October 15, 2025		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		10.0
7.37% Senior Notes, Due January 15, 2029		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		—		10.0
5.29% Senior Notes, Due March 2, 2020		16.6		25.0
3.52% Senior Notes, Due November 1, 2027		20.0		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		30.0
Granite State:
7.15% Senior Notes, Due December 15, 2018		—		3.3
3.72% Senior Notes, Due November 1, 2027		15.0		15.0
Total Long-Term Debt		409.3		409.4
Less: Unamortized Debt Issuance Costs		3.5		3.3
Total Long-Term Debt, net of Unamortized Debt Issuance Costs		405.8		406.1
Less: Current Portion		18.4		29.8
Total Long-Term Debt, Less Current Portion	$	387.4	$	376.3

Summary of Interest Expense and Interest Income

A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2018			2017			2016
Interest Expense
Long-Term Debt	$	23.1		$	21.8		$	21.8
Short-Term Debt		2.6			2.5			1.4
Regulatory Liabilities		0.7			1.2			0.5
Subtotal Interest Expense		26.4			25.5			23.7
Interest Income
Regulatory Assets		(0.8	)		(0.7	)		(0.3	)
AFUDC(1) and Other		(1.6	)		(1.7	)		(0.9	)
Subtotal Interest Income		(2.4	)		(2.4	)		(1.2	)
Total Interest Expense, net	$	24.0		$	23.1		$	22.5

⁽¹⁾  AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2018 and December 31, 2017:

Revolving Credit Facility (millions)
	December 31,
	2018		2017
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	82.8	$	38.3
Letters of Credit Outstanding	$	—	$	—
Available	$	37.2	$	81.7

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 December 31, 2018. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $2.7 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2018. $2.8 million of the current Capital Lease Obligations and $2.3 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s)	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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Equity (Tables)

12 Months Ended

Dec. 31, 2018

Restricted Shares Issued in Conjunction with Stock Plan

Restricted Shares issued for 2016 – 2018 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
1/26/16	43,220	$1.6
4/19/16	800	<$0.1
1/30/17	34,930	$1.6
1/29/18	37,510	$1.6

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during 2018 and 2017 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2018				2017
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		52,224	$	36.22		43,345	$	33.40
Restricted Stock Units Granted		7,892	$	49.63		7,522	$	50.23
Dividend Equivalents Earned		1,673	$	47.85		1,357	$	48.57
Restricted Stock Units Settled		—		—		—		—
Ending Restricted Stock Units		61,789	$	38.25		52,224	$	36.22

Reconciliation of Basic and Diluted Earnings Per Share

Earnings Per Share

The following table reconciles basic and diluted earnings per share (EPS).

(Millions except shares and per share data)	2018		2017		2016
Earnings Available to Common Shareholders	$	33.0	$	29.0	$	27.1
Weighted Average Common Shares Outstanding—Basic (000’s)		14,824		14,095		13,990
Plus: Diluted Effect of Incremental Shares (000’s)		5		7		6
Weighted Average Common Shares Outstanding—Diluted (000’s)		14,829		14,102		13,996
Earnings per Share—Basic and Diluted	$	2.23	$	2.06	$	1.94

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share

The following table shows the number of weighted average non-vested restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.

	2018		2017		2016
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		6,102		8,733		600

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

Environmental Obligations Recognized by Company

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years ended December 31, 2018 and 2017. The Company’s current and noncurrent environmental obligations are recorded on the Company’s Consolidated Balance Sheets in Other Current Liabilities and Other Noncurrent Liabilities, respectively.

Environmental Obligations

	(millions)
	Fitchburg				Northern Utilities				Total
	2018		2017		2018		2017		2018		2017
Total Balance at Beginning of Period	$	0.1	$	0.1	$	2.0	$	1.8	$	2.1	$	1.9
Additions		—		—		0.3		0.4		0.3		0.4
Less: Payments / Reductions		0.1		—		0.3		0.2		0.4		0.2
Total Balance at End of Period	$	—	$	0.1	$	2.0	$	2.0	$	2.0	$	2.1
Less: Current Portion		—		—		0.6		0.5		0.6		0.5
Noncurrent Balance at December 31,	$	—	$	0.1	$	1.4	$	1.5	$	1.4	$	1.6

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Provisions for Federal and State Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2018, 2017 and 2016 are shown in the table below:

	($000’s)
	2018		2017		2016
Current Income Tax Provision
Federal	$	—	$	—	$	—
State		355		—		—
Total Current Income Taxes	$	355		—		—
Deferred Income Provision
Federal	$	5,032		13,675		11,209
State		3,006		3,862		4,145
Total Deferred Income Taxes		8,038		17,537		15,354
Total Income Tax Expense	$	8,393	$	17,537	$	15,354

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

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

	2018			2017			2016
Statutory Federal Income Tax Rate		21	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		6			6			4
Utility Plant Differences		(7	)		(1	)		(1	)
Tax Credits and Other, net		—			(1	)		(1	)
Effective Income Tax Rate		20	%		38	%		36	%

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to deferred tax assets and liabilities in 2018 and 2017 are shown below:

Temporary Differences (000’s)	2018		2017
Deferred Tax Assets
Retirement Benefit Obligations	$	32,249	$	38,915
Net Operating Loss Carryforwards		10,773		12,686
Tax Credit Carryforwards		2,704		3,536
Other, net		1,571		1,155
Total Deferred Tax Assets	$	47,297	$	56,292
Deferred Tax Liabilities
Utility Plant Differences	$	132,682	$	127,932
Regulatory Assets & Liabilities		6,429		9,323
Other, net		5,964		1,894
Total Deferred Tax Liabilities		145,075		139,149
Net Deferred Tax Liabilities	$	97,778	$	82,857

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Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2018

Key Assumptions Used in Determining Benefit Plan Costs and Obligations

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

	2018			2017			2016
Used to Determine Plan costs for years ended December 31:
Discount Rate		3.60	%		4.10	%		4.30	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.50	%		8.00	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2025			2022

Used to Determine Benefit Obligations at December 31:
Discount Rate	4.25	%	3.60	%	4.10	%
Rate of Compensation Increase	3.00	%	3.00	%	3.00	%
Health Care Cost Trend Rate Assumed for Next Year	7.00	%	7.50	%	8.00	%
Ultimate Health Care Cost Trend Rate	4.50	%	4.50	%	4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached	2024		2024		2025

Components of Retirement Plan Costs

The following table provides the components of the Company’s Retirement plan costs (000’s):

	Pension Plan									PBOP Plan									SERP
	2018			2017			2016			2018			2017			2016			2018		2017		2016
Service Cost	$	3,393		$	3,295		$	3,402		$	2,933		$	2,974		$	2,610		$	487	$	460	$	162
Interest Cost		5,878			6,057			5,945			3,404			3,913			3,232			404		392		386
Expected Return on Plan Assets		(7,785	)		(7,306	)		(7,257	)		(1,635	)		(1,347	)		(1,205	)		—		—		—
Prior Service Cost Amortization		324			263			263			1,309			1,399			1,486			189		189		189
Actuarial Loss Amortization		5,786			4,662			4,398			1,383			2,098			1,049			486		295		375
Sub-total		7,596			6,971			6,751			7,394			9,037			7,172			1,566		1,336		1,112
Amounts Capitalized or Deferred		(3,465	)		(3,122	)		(3,008	)		(3,416	)		(4,515	)		(3,351	)		(451)		(397)		(290)
NPBC Recognized	$	4,131		$	3,849		$	3,743		$	3,978		$	4,522		$	3,821		$	1,115	$	939	$	822

Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2018			2017			2018			2017			2018			2017
Plan Assets at Beginning of Year	$	102,315		$	91,058		$	20,234		$	16,606		$	—		$	—
Actual Return on Plan Assets		(6,149	)		12,731			(1,085	)		1,907			—			—
Employer Contributions		16,628			4,100			4,000			4,000			401			34
Participant Contributions		—			—			153			126			—			—
Benefits Paid		(4,986	)		(5,574	)		(2,193	)		(2,405	)		(401	)		(34	)
Plan Assets at End of Year	$	107,808		$	102,315		$	21,109		$	20,234		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	166,921		$	150,439		$	94,122		$	96,659		$	11,723		$	9,566
Service Cost		3,393			3,295			2,933			2,974			487			460
Interest Cost		5,878			6,057			3,404			3,913			404			392
Participant Contributions		—			—			153			126			—			—
Plan Amendments		—			608			—			—			—			—
Benefits Paid		(4,986	)		(5,574	)		(2,193	)		(2,405	)		(401	)		(34	)
Actuarial (Gain) or Loss		(15,009	)		12,096			(17,414	)		(7,145	)		1,541			1,339
PBO at End of Year	$	156,197		$	166,921		$	81,005		$	94,122		$	13,754		$	11,723
Funded Status: Assets vs PBO	$	(48,389	)	$	(64,606	)	$	(59,896	)	$	(73,888	)	$	(13,754	)		(11,723	)

Employer Contributions, Participant Contributions and Benefit Payments

The following table represents employer contributions, participant contributions and benefit payments (000’s).

	Pension Plan						PBOP Plan						SERP
	2018		2017		2016		2018		2017		2016		2018		2017		2016
Employer Contributions	$	16,628	$	4,100	$	5,146	$	4,000	$	4,000	$	4,000	$	401	$	34	$	34
Participant Contributions	$	—	$	—	$	—	$	153	$	126	$	61		$—	$	—	$	—
Benefit Payments	$	4,986	$	5,574	$	4,900	$	2,193	$	2,405	$	2,421	$	401	$	34	$	34

Estimated Future Benefit Payments

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2019	$	5,888	$	2,314	$	522
2020		6,484		2,520		521
2021		6,949		2,780		681
2022		6,853		2,955		678
2022		7,588		3,106		675
2024 - 2028		46,942		19,244		4,904

Pension Plans

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2019			Actual Allocation at December 31,
				2018			2017			2016
Equity Funds		53	%		49	%		49	%		46	%
Debt Funds		37	%		40	%		34	%		37	%
Real Estate Fund		10	%		10	%		10	%		10	%
Asset Allocation Fund(1)		—			—			6	%		7	%
Other(2)		—			1	%		1	%		—
Total					100	%		100	%		100	%

(1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

(2) Represents investments being held in cash equivalents as of December 31, 2018 pending payment of benefits.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2018 and 2017 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2018
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	52,884	$	52,884	$	—	$	—
Fixed Income Funds		43,281		43,281		—		—
Total Mutual Funds		96,165		96,165		—		—
Cash Equivalents		1,202		1,202		—
Total Assets in the Fair Value Hierarchy	$	97,367	$	97,367	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		10,441
Total Assets	$	107,808
2017
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	50,373	$	50,373	$	—	$	—
Fixed Income Funds		34,757		34,757		—		—
Asset Allocation Fund		6,398		6,398		—		—
Total Mutual Funds		91,528		91,528		—		—
Cash Equivalents		1,200		1,200		—
Total Assets in the Fair Value Hierarchy	$	92,728	$	92,728	$	—	$	—
Real Estate Fund–Measured at Net Asset Value		9,587
Total Assets	$	102,315

Other Postretirement Benefit Plans, Defined Benefit

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the tables below.

PBOP Plan	Target Allocation 2019			Actual Allocation at December 31,
				2018			2017			2016
Equity Funds		55	%		53	%		56	%		55	%
Debt Funds		45	%		47	%		42	%		43	%
Other(1)		—			—			2	%		2	%
Total					100	%		100	%		100	%

(1) Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds.

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2018 and 2017 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2018
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	9,905	$	9,905	$	—	$	—
Equity Funds		11,204		11,204
Total Assets	$	21,109	$	21,109	$	—	$	—
2017
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	8,419	$	8,419	$	—	$	—
Equity Funds		11,415		11,415
Total Mutual Funds		19,834		19,834
Cash Equivalents		400		400
Total Assets	$	20,234	$	20,234	$	—	$	—

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Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, Bcf in Billions	1 Months Ended	3 Months Ended								12 Months Ended
	Feb. 02, 2019 $ / shares	Dec. 31, 2018 USD ($) $ / shares Bcf	Sep. 30, 2018 $ / shares	Jun. 30, 2018 $ / shares	Mar. 31, 2018 $ / shares	Dec. 31, 2017 USD ($) $ / shares Bcf	Sep. 30, 2017 $ / shares	Jun. 30, 2017 $ / shares	Mar. 31, 2017 $ / shares	Dec. 31, 2018 USD ($) Entity Subsidiary mi $ / shares Bcf	Dec. 31, 2017 USD ($) $ / shares Bcf	Dec. 31, 2016 USD ($) $ / shares	Jan. 01, 2019 USD ($)
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Entity										3
Length Of Pipeline | mi										86
Revenue sharing payments										$ 1,000,000	$ 1,100,000	$ 1,000,000
Other										439,400,000	400,200,000	377,300,000
Operation and Maintenance Expense										$ 69,500,000	$ 64,500,000	$ 61,400,000
Depreciation rate based on average depreciable property balance										3.38%	3.45%	3.49%
Common stock dividend paid per share | $ / shares		$ 0.365	$ 0.365	$ 0.365	$ 0.365	$ 0.360	$ 0.360	$ 0.360	$ 0.360	$ 1.46	$ 1.44	$ 1.42
Common stock dividend per share, declared | $ / shares										$ 1.46	$ 1.44	$ 1.42
Cost of removal obligation		$ 90,700,000				$ 84,300,000				$ 90,700,000	$ 84,300,000
Average interest rates										2.70%	2.90%	2.18%
Regulatory Assets		$ 140,300,000				$ 149,100,000				$ 140,300,000	$ 149,100,000
Number of Natural Gas Storage Outstanding | Bcf		0.0				0.6				0.0	0.6
Derivatives assets		$ 0				$ 0				$ 0	$ 0
Derivatives liabilities		0				0				0	0
Losses / (gains) recognized in regulatory assets / liabilities										0	400,000
Losses / (gains) reclassified into unaudited consolidated statement of earnings										0	0
Investments in trading securities		4,800,000				3,600,000				4,800,000	3,600,000
ASU 2014-09
Significant Accounting Policies [Line Items]
Revenue sharing payments											1,100,000	$ 1,000,000
Operation and Maintenance Expense											63,400,000	60,400,000
Non Service
Significant Accounting Policies [Line Items]
Non-service cost net periodic benefit costs										$ 5,500,000	5,700,000	$ 4,900,000
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%
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period										3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits		3,500,000				2,900,000				$ 3,500,000	2,900,000
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits		0				$ 0				$ 0	$ 0
Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	$ 1.48
Recognition of lease assets													$ 4,200,000
Recognition of lease liabilities													$ 4,200,000
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share | $ / shares										$ 0.365	$ 0.360	$ 0.355
Quarterly Dividends | Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	0.37
Increase in dividend declared amount per share | $ / shares	$ 0.005
Environmental and Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory Assets		$ 6,000,000								$ 6,000,000
Restatement Adjustment [Member] | ASU 2014-09
Significant Accounting Policies [Line Items]
Other											$ (1,100,000)	$ (1,000,000)
Operation and Maintenance Expense											$ (1,100,000)	$ (1,000,000)
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

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Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 439.4	$ 400.2	$ 377.3
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	439.4	389.1	353.7
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues		11.1	23.6
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	216.1	194.0	181.2
Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	210.7	187.5	165.4
Gas Segment | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	5.4	6.5	15.8
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	223.3	206.2	196.1
Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	228.7	201.6	188.3
Electric | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(5.4)	4.6	7.8
Residential | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	205.0	179.1	163.4
Residential | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	81.4	71.2	61.5
Residential | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	123.6	107.9	101.9
C&I | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	216.1	190.5	174.2
C&I | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	119.7	102.8	92.7
C&I | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	96.4	87.7	81.5
Other | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	24.6	19.5	16.1
Other | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	13.3	13.5	11.2
Other | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	11.3	$ 6.0	$ 4.9
Revenue Reduction - TCJA | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(6.3)
Revenue Reduction - TCJA | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(3.7)
Revenue Reduction - TCJA | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ (2.6)

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Schedule of Other Operating Revenues and Operating Expenses (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Component of Operating Other Cost and Expense [Abstract]
Total Operating Revenues	$ 439.4	$ 400.2	$ 377.3
Less: Revenue Sharing Payments	(1.0)	(1.1)	(1.0)
Operation and Maintenance Expense	69.5	64.5	61.4
Usource Contract Revenues [Member]
Component of Operating Other Cost and Expense [Abstract]
Total Operating Revenues	5.7
Other
Component of Operating Other Cost and Expense [Abstract]
Total Operating Revenues	$ 4.7
ASU 2014-09
Component of Operating Other Cost and Expense [Abstract]
Less: Revenue Sharing Payments		(1.1)	(1.0)
Operation and Maintenance Expense		63.4	60.4
ASU 2014-09 | Usource Contract Revenues [Member]
Component of Operating Other Cost and Expense [Abstract]
Total Operating Revenues		6.0	6.1
ASU 2014-09 | Other
Component of Operating Other Cost and Expense [Abstract]
Total Operating Revenues		$ 4.9	$ 5.1

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Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 54.7	$ 53.3
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	13.4	13.8
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 41.3	$ 39.5

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Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Receivables [Line Items]
Total Exchange Gas Receivable	$ 8.1	$ 5.8
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	7.5	5.4
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.6	$ 0.4

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Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.8	$ 0.6
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.4
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.4	$ 0.1

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Regulatory Assets (Detail) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory Assets		$ 140.3	$ 149.1
Less: Current Portion of Regulatory Assets	[1]	41.3	39.5
Regulatory Assets-noncurrent		99.0	109.6
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets		7.9	9.5
Other Deferred Charges
Regulatory Assets [Line Items]
Regulatory Assets		10.0	5.4
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets		72.0	84.5
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory Assets		6.3	7.2
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets		5.7	6.5
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets		$ 38.4	$ 36.0

[1] Reflects amounts included in Accrued Revenue on the Company's Consolidated Balance Sheets and in the Accrued Revenue table shown above.

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Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 58.5	$ 58.1
Less: Current Portion of Regulatory Liabilities	11.5	9.2
Regulatory Liabilities-noncurrent	47.0	48.9
Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	11.5	6.9
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities		2.3
Income Tax Related Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 47.0	$ 48.9

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Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 4.8	$ 3.6
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	4.8	3.6
Fair Value, Inputs, Level 1 | Equity Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities		2.1
Fair Value, Inputs, Level 1 | Fixed Income Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities		$ 1.5
Fair Value, Inputs, Level 1 | Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 4.8

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Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 13.4	$ 9.7
Power Supply Contract Divestitures, Noncurrent	0.6	0.9
Total Energy Supply Obligations	14.0	10.6
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	7.5	5.4
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	5.6	4.0
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 0.3	$ 0.3

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Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 125.6	$ 88.2	$ 84.5	$ 145.8	$ 115.4	$ 84.0	$ 80.8	$ 126.0	$ 444.1	$ 406.2	$ 383.4
Operating Income	22.2	10.3	10.6	28.1	25.7	10.4	11.6	27.7	71.2	75.4	70.2
Net Income Applicable to Common	$ 11.0	$ 2.8	$ 3.6	$ 15.6	$ 11.2	$ 2.3	$ 3.1	$ 12.4	$ 33.0	$ 29.0	$ 27.1
Per Share Data:
Earnings Per Common Share	$ 0.74	$ 0.19	$ 0.24	$ 1.06	$ 0.79	$ 0.16	$ 0.23	$ 0.88	$ 2.23	$ 2.06	$ 1.94
Dividends Paid Per Common Share	$ 0.365	$ 0.365	$ 0.365	$ 0.365	$ 0.360	$ 0.360	$ 0.360	$ 0.360	$ 1.46	$ 1.44	$ 1.42

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 Segment Entity Pipeline mi
Segment Reporting Information [Line Items]
No of segments | Segment	3
No of subsidiaries | Entity	3
Length Of Pipeline	86
Granite State Gas Transmission Inc
Segment Reporting Information [Line Items]
Length Of Pipeline	86
No of major pipeline | Pipeline	3

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Significant Segment Financial Data (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue - Non-Regulated									$ 4,700
Revenues	$ 125,600	$ 88,200	$ 84,500	$ 145,800	$ 115,400	$ 84,000	$ 80,800	$ 126,000	444,100	$ 406,200	$ 383,400
Interest Income									2,400	2,400	1,200
Interest Expense									26,400	25,500	23,700
Depreciation & Amortization Expense									50,400	46,900	46,600
Income Tax Expense (Benefit)									8,393	17,537	15,354
Segment Profit	11,000	$ 2,800	$ 3,600	$ 15,600	11,200	$ 2,300	$ 3,100	$ 12,400	33,000	29,000	27,100
Segment Assets	1,298,300				1,241,900				1,298,300	1,241,900	1,128,200
Capital Expenditures									102,400	119,300	98,100
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									439,400
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									216,100	194,000	181,200
Interest Income									800	700	200
Interest Expense									14,200	13,700	13,300
Depreciation & Amortization Expense									24,900	22,400	21,900
Income Tax Expense (Benefit)									7,100	10,700	9,200
Segment Profit									18,800	16,400	14,500
Segment Assets	764,100				714,300				764,100	714,300	645,200
Capital Expenditures									70,800	72,100	57,000
Gas Segment | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									210,700
Gas Segment | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									5,400
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									223,300	206,200	196,100
Interest Income									800	1,000	700
Interest Expense									9,000	8,800	8,300
Depreciation & Amortization Expense									23,100	23,400	23,800
Income Tax Expense (Benefit)									4,200	7,500	6,600
Segment Profit									11,400	11,900	11,100
Segment Assets	484,200				476,900				484,200	476,900	441,100
Capital Expenditures									28,400	33,700	30,100
Electric | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									228,700
Electric | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									(5,400)
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									600	600	200
Interest Expense									3,200	3,000	2,100
Depreciation & Amortization Expense									2,300	1,000	800
Income Tax Expense (Benefit)									(3,400)	(1,400)	(1,200)
Segment Profit									1,500	(500)	400
Segment Assets	43,100				44,000				43,100	44,000	35,100
Capital Expenditures									3,200	13,500	11,000
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue - Non-Regulated									4,700
Revenues									4,700	6,000	6,100
Interest Income									200	100	100
Depreciation & Amortization Expense									100	100	100
Income Tax Expense (Benefit)									500	700	800
Segment Profit									1,300	1,200	1,100
Segment Assets	$ 6,900				$ 6,700				$ 6,900	$ 6,700	$ 6,800

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Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 6.0	$ 3.7	$ 4.6
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 2.6	$ 1.3	$ 1.6

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Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	$ 1.6	$ 1.1	$ 1.2
Provision	6.0	3.7	4.6
Recoveries	0.6	0.6	0.6
Accounts Written Off	6.9	3.8	5.3
Balance at End of Period	1.3	1.6	1.1
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.9	0.8	0.6
Provision	3.2	1.8	2.9
Recoveries	0.3	0.3	0.3
Accounts Written Off	3.9	2.0	3.0
Balance at End of Period	0.5	0.9	0.8
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.6	0.2	0.5
Provision	2.9	1.9	1.7
Recoveries	0.3	0.3	0.3
Accounts Written Off	3.0	1.8	2.3
Balance at End of Period	0.8	0.6	0.2
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.1	0.1	0.1
Provision	$ (0.1)
Balance at End of Period		$ 0.1	$ 0.1

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Debt and Financing Arrangements - Additional Information (Detail) - USD ($)			1 Months Ended	12 Months Ended
	Jul. 25, 2018	Nov. 01, 2017	Nov. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Oct. 30, 2015
Line of Credit Facility [Line Items]
Amount available for the payment of dividends				$ 137,400,000
Retained Earnings				$ 72,000,000	$ 60,800,000
Restriction on retained earnings for dividend payments				Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2018 for the payment of dividends.
Issuance of long-term debt		$ 700,000	$ 500,000
Long term debt repayments				$ 30,100,000	$ 17,200,000	$ 19,000,000
Weighted average interest rate on short term borrowings				3.30%	2.40%	1.80%
Capital lease obligation, current				$ 3,100,000	$ 3,100,000
Capital lease obligation, noncurrent				2,700,000	5,700,000
Accounts Payable				42,600,000	41,500,000
Total rental expense under operating leases				2,200,000	2,000,000	$ 1,800,000
Net Utility Plant				1,036,800,000	971,500,000
Guarantee outstanding				4,300,000
Financing Arrangements
Line of Credit Facility [Line Items]
Capital lease obligation, current				2,800,000
Capital lease obligation, noncurrent				2,300,000
Assets under Capital Leases
Line of Credit Facility [Line Items]
Net Utility Plant				15,000,000	15,000,000
Net Utility Plant, accumulated amortization				$ 1,700,000	700,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				65.00%
Natural gas storage inventory				$ 8,400,000	8,500,000
Accounts Payable				$ 900,000	3,100,000
Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				65.00%
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				65.00%
Unitil Corporation | Maximum
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization				70.00%
Unitil Service Corp.
Line of Credit Facility [Line Items]
Capital lease obligation, total capitalized cost							$ 13,400,000
Capital lease obligation, maturity period				Sep. 30, 2020
Capital lease obligation, current				$ 2,800,000
Capital lease obligation, noncurrent				2,300,000
Unitil Energy, Fitchburg, Northern Utilities and Granite State
Line of Credit Facility [Line Items]
Amount available for the payment of dividends				249,200,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility				120,000,000	120,000,000
Proceeds from lines of credit				265,600,000	234,900,000
Repayments of lines of credit				$ 221,100,000	$ 278,500,000
3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 20,000,000
Long-term debt, stated interest rate		3.52%		3.52%	3.52%
Long-term debt, maturity date		Nov. 01, 2027		Nov. 01, 2027	Nov. 01, 2027
3.52% Senior Notes, Due November 1, 2027 | Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 10,000,000
Long-term debt, stated interest rate		3.52%		3.52%	3.52%
Long-term debt, maturity date		Nov. 01, 2027		Nov. 01, 2027	Nov. 01, 2027
4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 30,000,000
Long-term debt, stated interest rate		4.32%		4.32%	4.32%
Long-term debt, maturity date		Nov. 01, 2047		Nov. 01, 2047	Nov. 01, 2047
4.32% Senior Notes, Due November 1, 2047 | Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 15,000,000
Long-term debt, stated interest rate		4.32%		4.32%	4.32%
Long-term debt, maturity date		Nov. 01, 2047		Nov. 01, 2047	Nov. 01, 2047
3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 15,000,000
Long-term debt, stated interest rate		3.72%		3.72%	3.72%
Long-term debt, maturity date		Nov. 01, 2027		Nov. 01, 2027	Nov. 01, 2027
Bonds
Line of Credit Facility [Line Items]
Long term debt repayments				$ 30,100,000	$ 17,200,000	$ 19,000,000
Debt repayment, 2019				18,800,000
Debt repayment, 2020				19,800,000
Debt repayment, 2021				8,600,000
Debt repayment, 2022				28,200,000
Debt repayment, 2023				6,700,000
Debt repayment, Thereafter				$ 327,200,000
Credit Facility | Second Amended Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility	$ 120,000,000
Sublimit for the issuance of standby letters of credit	$ 25,000,000
Revolving credit facility termination date	Jul. 25, 2023
Increase in borrowing limit	$ 50,000,000
Credit Facility | Second Amended Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	1.125%
Credit Facility | Revolving Credit Facility
Line of Credit Facility [Line Items]
Percentage of capitalization				The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2018 and December 31, 2017, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
4.18% First Mortgage Bonds, Due November 30, 2048 | Unitil Energy
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

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Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 422.0	$ 457.1

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Details on Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total Long-Term Debt	$ 409.3	$ 409.4
Less: Unamortized Debt Issuance Costs	3.5	3.3
Long-Term Debt	405.8	406.1
Less: Current Portion	18.4	29.8
Total Long-Term Debt, Less Current Portion	387.4	376.3
Long-Term Debt	405.8	406.1
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Total Long-Term Debt	20.0	20.0
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt	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	10.0	15.0
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	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	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
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
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
Fitchburg Gas and Electric Light Company | 6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Total Long-Term Debt	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
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
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
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
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
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
Northern Utilities Inc | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	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
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	16.6	25.0
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt	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
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

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Details on Long Term Debt (Parenthetical) (Detail)		12 Months Ended
	Nov. 01, 2017	Dec. 31, 2018	Dec. 31, 2017
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate		6.33%	6.33%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		Oct. 15, 2044	Oct. 15, 2044
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate		7.15%	7.15%
Debt instrument due date		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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Summary of Interest Expense and Interest Income (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest Expense
Long-Term Debt		$ 23.1	$ 21.8	$ 21.8
Short-Term Debt		2.6	2.5	1.4
Regulatory Liabilities		0.7	1.2	0.5
Interest Expense		26.4	25.5	23.7
Interest Income
Interest income		(2.4)	(2.4)	(1.2)
Total Interest Expense, net		24.0	23.1	22.5
Regulatory Assets
Interest Income
Interest income		(0.8)	(0.7)	(0.3)
AFUDC and Other
Interest Income
Interest income	[1]	$ (1.6)	$ (1.7)	$ (0.9)

[1] AFUDC-Allowance for Funds Used During Construction

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Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 82,800,000	$ 38,300,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120,000,000	120,000,000
Short-Term Borrowings Outstanding	82,800,000	38,300,000
Letters of Credit Outstanding	0	0
Available revolving credit facility	$ 37,200,000	$ 81,700,000

XML

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Capital lease
2019	$ 1,372
2020	1,138
2021	969
2022	689
2023	390
2024 - 2028	120
Total Payments	4,678
Operating leases
2019	3,069
2020	2,535
2021	93
2022	32
2023	14
2024 - 2028	0
Total Payments	$ 5,743

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Equity - Additional Information (Detail) - USD ($)			12 Months Ended
	Jan. 29, 2019	Dec. 14, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Common stock, shares outstanding			14,876,955	14,815,585
Common stock, shares authorized			25,000,000	25,000,000
Common Stock, Shares issued			25,932		32,095
Proceeds from Issuance of Common Stock			$ 1,200,000	$ 33,000,000	$ 1,300,000
Common stock shares repurchase			791	1,686	1,949
Share based compensation expense			$ 2,200,000	$ 2,700,000	$ 2,200,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled			70.00%
Percentage of fully-vested restricted stock units that directors will receive in cash when settled			30.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 1,300,000	1,000,000
Preferred Stock			200,000	200,000
Maximum
Class of Stock [Line Items]
Repurchase expense			100,000	100,000	100,000
Dividend declared			100,000	$ 100,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common Stock, Shares issued				26,256
Proceeds from Issuance of Common Stock			$ 1,200,000	$ 1,300,000	$ 1,300,000
Dividend and Distribution Reinvestment and Share Purchase Plan | Average
Class of Stock [Line Items]
Common stock price per share			$ 47.78
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common Stock, Shares issued			25,932	26,256	32,095
Registered Public Offering
Class of Stock [Line Items]
Common Stock, Shares issued				690,000
Proceeds from Issuance of Common Stock		$ 31,700,000
Registered Public Offering | Common Stock
Class of Stock [Line Items]
Common Stock, Shares issued		690,000
Common stock price per share		$ 48.30
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			1,893	1,893
Preferred Stock			$ 200,000	$ 200,000
Dividend rate			6.00%	6.00%
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period			4 years
Restricted stock non-vested			29,252	89,326
Restricted stock weighted average grant date fair value			$ 42.86	$ 39.54
Unrecognized share based compensation			$ 800,000
Share compensation recognition period			2 years 3 months 19 days
Forfeitures under the stock plan			2,072
Cancellations under the stock plan			0
Restricted Stock | Subsequent Event
Class of Stock [Line Items]
Aggregate Market Value	$ 1,600,000
Restricted Stock Units Granted	33,150
Restricted Stock | Maximum
Class of Stock [Line Items]
Restricted stock available for awards			677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000
Restricted Stock | Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually			25.00%

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Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) shares
Period 1
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2016
Shares | shares	43,220
Aggregate Market Value | $	$ 1.6
Period 2
Class of Stock [Line Items]
Issuance Date	Apr. 19, 2016
Shares | shares	800
Period 3
Class of Stock [Line Items]
Issuance Date	Jan. 30, 2017
Shares | shares	34,930
Aggregate Market Value | $	$ 1.6
Period 3 | Maximum
Class of Stock [Line Items]
Aggregate Market Value | $	$ 0.1
Period 4
Class of Stock [Line Items]
Issuance Date	Jan. 29, 2018
Shares | shares	37,510
Aggregate Market Value | $	$ 1.6

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Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Restricted Stock Units
Beginning Restricted Stock Units	52,224	43,345
Restricted Stock Units Granted	7,892	7,522
Dividend Equivalents Earned	1,673	1,357
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	61,789	52,224
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 36.22	$ 33.40
Restricted Stock Units Granted	49.63	50.23
Dividend Equivalents Earned	47.85	48.57
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	$ 38.25	$ 36.22

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Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders									$ 33.0	$ 29.0	$ 27.1
Weighted Average Common Shares Outstanding-Basic									14,824	14,095	13,990
Plus: Diluted Effect of Incremental Shares									5	7	6
Weighted Average Common Shares Outstanding-Diluted									14,829	14,102	13,996
Earnings per Share-Basic and Diluted	$ 0.74	$ 0.19	$ 0.24	$ 1.06	$ 0.79	$ 0.16	$ 0.23	$ 0.88	$ 2.23	$ 2.06	$ 1.94

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Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Non Vested Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation	6,102	8,733	600

XML

Energy Supply - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 Bcf MMBTU
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities | MMBTU	115,000,000,000
Natural gas, underground storage | Bcf	4,300,000,000
Northern Utilities Inc | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities | MMBTU	14,057
Natural gas, underground storage | Bcf	0.33
Percentage of power supply requirement	50.00%
Power supply contract duration	12 months
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement	100.00%
Power supply contract duration	6 months

XML

Commitments and Contingencies - Additional Information (Detail) $ in Thousands											1 Months Ended	12 Months Ended
	May 01, 2019 USD ($)	May 07, 2018 USD ($)	May 02, 2018 USD ($)	May 01, 2018 USD ($)	Apr. 30, 2018 USD ($)	Feb. 28, 2018 USD ($)	Jan. 01, 2018 USD ($)	Aug. 25, 2017 MW	Aug. 01, 2017 USD ($)	Apr. 20, 2017 USD ($)	Oct. 31, 2018 USD ($)	Dec. 31, 2018 USD ($) State Customer MW	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Jun. 30, 2027 MW	Dec. 31, 2025 MWh	Dec. 31, 2022 MWh	Jun. 01, 2018 USD ($)	May 10, 2018 USD ($)	Jun. 30, 2017 MW	Jun. 23, 2017 kW	Nov. 09, 2016 MW
Regulatory Assets [Line Items]
Regulatory Assets, Remaining Balance												$ 900
Accrued Revenue												54,700	$ 53,300
Regulatory Assets												$ 99,000	$ 109,600
Corporate income tax rate												21.00%	34.00%	34.00%
Reduction of federal tax decrease												$ 0	$ 0	$ 0
Spending cap																			$ 4,400
Annual revenue adjustment				$ 2,300
Power capacity facility for small customers | kW																					100
Electric Base
Regulatory Assets [Line Items]
Refund of excess ADIT												$ 10,100
Number of years refund amortized												15 years
Gas Base
Regulatory Assets [Line Items]
Refund of excess ADIT												$ 10,400
Number of years refund amortized												14 years
Tax Year 2018
Regulatory Assets [Line Items]
Corporate income tax rate													21.00%
Other Restructuring
Regulatory Assets [Line Items]
Accrued Revenue												$ 300
Regulatory Assets												$ 600
Cost recovery period, years												2 years
Scenario Forecast
Regulatory Assets [Line Items]
Annual revenue adjustment	$ 2,200
Maine | Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs												5 years
New Hampshire | Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs												7 years
Northern Utilities Inc
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue			$ 2,600				$ 3,200		$ 2,600
Increase in annual base rate		2.40%
Annual TIRA Adjustment		$ 1,100
TIRA initial term												Four years
Northern Utilities Inc | Revenue Offset [Member]
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue			$ (1,700)
Northern Utilities Inc | Maine
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue						$ 2,100
Percentage of approved return on equity						9.50%
Percentage of approved return on equity, reflecting on equity						50.00%
Percentage of approved return on equity, reflecting on debt						50.00%
Reduction of annual operating costs						$ 500
TIRA extended term												8 years
Construction completion period												3 years
Number of new customers | Customer												1,000
Potential regulated operating revenue												$ 1,000
Northern Utilities Inc | Maine | Revenue Offset [Member]
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue						$ 2,200
Northern Utilities Inc | Maine | Second TAB program
Regulatory Assets [Line Items]
Number of new customers | Customer												2,000
Potential regulated operating revenue												$ 2,000
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue				$ 900								$ (800)
Annual revenue adjustment											$ 400
Amendment effective date											Nov. 01, 2018
Description of percentage of sales in legislation												The legislation contains numerous provisions, including: a requirement that increases the pace at which the Class 1 Renewable Portfolio Standard requirement increases, from the current pace of an additional 1 percent of sales each year to an additional 2 percent of sales each year during the period from January 1, 2020 through December 31, 2029.
Number of states with electric distribution companies | State												3
Fitchburg Gas and Electric Light Company | Solar Generation
Regulatory Assets [Line Items]
Power generation facility | MW																						1.3
Recovery amount																		$ 300
Fitchburg Gas and Electric Light Company | Solar Generation | Solar Massachusetts Renewable Target Program
Regulatory Assets [Line Items]
Power generation capacity | MW								1,600
Fitchburg Gas and Electric Light Company | Maximum
Regulatory Assets [Line Items]
Power generation facility | MW												1,600
Fitchburg Gas and Electric Light Company | Minimum | 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																1,600	9,450,000
Fitchburg Gas and Electric Light Company | Scenario Forecast | Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility | MW															1,600
Unitil Energy Systems Inc | New Hampshire
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue					$ 300
Permanent rate increase										$ 4,100
Reduction of federal tax decrease					2,200
Reconciliation adjustment of recouped difference between temporary rates and final rates					1,400
Unitil Energy Systems Inc | New Hampshire | First Rate Step Adjustments
Regulatory Assets [Line Items]
Permanent rate increase										$ 900
Unitil Energy Systems Inc | New Hampshire | Second rate Step Adjustments [Member]
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue					$ 3,300

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Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2.1	$ 1.9
Additions	0.3	0.4
Less: Payments / Reductions	0.4	0.2
Total Balance at End of Period	2.0	2.1
Less: Current Portion			$ 0.6	$ 0.5
Noncurrent Balance			1.4	1.6
Total Balance at End of Period	2.1	1.9	2.0	2.1
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	0.1	0.1
Less: Payments / Reductions	0.1
Total Balance at End of Period		0.1
Noncurrent Balance				0.1
Total Balance at End of Period	0.1	0.1		0.1
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	2.0	1.8
Additions	0.3	0.4
Less: Payments / Reductions	0.3	0.2
Total Balance at End of Period	2.0	2.0
Less: Current Portion			0.6	0.5
Noncurrent Balance			1.4	1.5
Total Balance at End of Period	$ 2.0	$ 1.8	$ 2.0	$ 2.0

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Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current Income Tax Provision
Federal	$ 0	$ 0	$ 0
State	355
Total Current Income Taxes	355
Deferred Income Provision
Federal	5,032	13,675	11,209
State	3,006	3,862	4,145
Total Deferred Income Taxes	8,038	17,537	15,354
Total Income Tax Expense	$ 8,393	$ 17,537	$ 15,354

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Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	21.00%	34.00%	34.00%
State Income Taxes, net	6.00%	6.00%	4.00%
Utility Plant Differences	(7.00%)	(1.00%)	(1.00%)
Tax Credits and Other, net		(1.00%)	(1.00%)
Effective Income Tax Rate	20.00%	38.00%	36.00%

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Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Deferred Tax Assets
Retirement Benefit Obligations	$ 32,249		$ 38,915
Net Operating Loss Carryforwards	10,773	$ 3,700	12,686
Tax Credit Carryforwards	2,704		3,536
Other, net	1,571		1,155
Total Deferred Tax Assets	47,297		56,292
Deferred Tax Liabilities
Utility Plant Differences	132,682		127,932
Regulatory Assets & Liabilities	6,429		9,323
Other, net	5,964		1,894
Total Deferred Tax Liabilities	145,075		139,149
Net Deferred Tax Liabilities	$ 97,778		$ 82,857

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Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Sep. 30, 2018
Income Taxes [Line Items]
Corporate federal income tax	21.00%	34.00%	34.00%
Regulatory Liability	$ 58,500,000	$ 58,100,000
Regulatory liability, expected flow back to customers	47,100,000	48,900,000
Tax provision	2,400,000
Net Operating Loss Carryforwards	10,773,000	12,686,000		$ 3,700,000
Calculated federal current tax	7,700,000
Deferred tax assets, operating loss carryforwards, federal	7,700,000
Federal current taxes payable	$ 0
NOL carryforward assets expiration date	2029
Alternative minimum tax credit carryforwards		3,500,000
Minimum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period	15 years
Maximum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period	20 years
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 47,000,000	48,900,000
Reconciling Mechanisms
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers		1,800,000
Net Operating Loss Carryforward Assets
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers	$ 3,400,000	$ 5,800,000
Fitchburg Gas and Electric Light Company
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period	15 years
Fitchburg Gas and Electric Light Company | Electric Ratepayers
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers	$ 10,100,000
Fitchburg Gas and Electric Light Company | Gas Ratepayers
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers	$ 10,400,000
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax		21.00%
Federal, Maine, Massachusetts, and New Hampshire Tax Authorities
Income Taxes [Line Items]
Tax examination description	The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2015; December 31, 2016; and December 31, 2017.

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Key Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.60%	4.10%	4.30%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.75%	7.75%	8.00%
Health Care Cost Trend Rate Assumed for Next Year	7.50%	8.00%	7.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2024	2025	2022
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.25%	3.60%	4.10%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	7.50%	8.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2024	2024	2025

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Retirement Benefit Obligations - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Change in Discount Rate	0.25%
Increase or decrease of Net Periodic Benefit Cost (NPBC) due to change in the discount rate	$ 589
Pension expense	7,600	$ 7,000	$ 6,800
Regulatory Assets	$ 140,300	149,100
Defined Benefit Plan, Expected Long-term Rate-of-Return on Assets Assumption	The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index.
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ 142,800	150,600
Company's contributions	16,628	4,100	5,146
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	4,000	4,000	4,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	9,500	9,500
Company's contributions	401	34	34
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense	7,200	7,600	7,700
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory Assets	72,000	84,500
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	$ 2,700	$ 2,400	$ 2,300
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Long-term Return on Assets	7.75%	7.75%	8.00%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				53.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				37.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				45.00%
Real Estate Funds | Scenario Forecast | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				10.00%

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Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3,393	$ 3,295	$ 3,402
Interest Cost	5,878	6,057	5,945
Expected Return on Plan Assets	(7,785)	(7,306)	(7,257)
Prior Service Cost Amortization	324	263	263
Actuarial Loss Amortization	5,786	4,662	4,398
Sub-total	7,596	6,971	6,751
Amounts Capitalized or Deferred	(3,465)	(3,122)	(3,008)
NPBC Recognized	4,131	3,849	3,743
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,933	2,974	2,610
Interest Cost	3,404	3,913	3,232
Expected Return on Plan Assets	(1,635)	(1,347)	(1,205)
Prior Service Cost Amortization	1,309	1,399	1,486
Actuarial Loss Amortization	1,383	2,098	1,049
Sub-total	7,394	9,037	7,172
Amounts Capitalized or Deferred	(3,416)	(4,515)	(3,351)
NPBC Recognized	3,978	4,522	3,821
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	487	460	162
Interest Cost	404	392	386
Prior Service Cost Amortization	189	189	189
Actuarial Loss Amortization	486	295	375
Sub-total	1,566	1,336	1,112
Amounts Capitalized or Deferred	(451)	(397)	(290)
NPBC Recognized	$ 1,115	$ 939	$ 822

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Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 102,315	$ 91,058
Actual Return on Plan Assets	(6,149)	12,731
Employer Contributions	16,628	4,100	$ 5,146
Benefits Paid	(4,986)	(5,574)
Plan Assets at End of Year	107,808	102,315	91,058
PBO at Beginning of Year	166,921	150,439
Service Cost	3,393	3,295	3,402
Interest Cost	5,878	6,057	5,945
Plan Amendments		608
Benefits Paid	(4,986)	(5,574)	(4,900)
Actuarial (Gain) or Loss	(15,009)	12,096
PBO at End of Year	156,197	166,921	150,439
Funded Status: Assets vs PBO	(48,389)	(64,606)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	20,234	16,606
Actual Return on Plan Assets	(1,085)	1,907
Employer Contributions	4,000	4,000	4,000
Participant Contributions	153	126
Benefits Paid	(2,193)	(2,405)
Plan Assets at End of Year	21,109	20,234	16,606
PBO at Beginning of Year	94,122	96,659
Service Cost	2,933	2,974	2,610
Interest Cost	3,404	3,913	3,232
Participant Contributions	153	126	61
Benefits Paid	(2,193)	(2,405)	(2,421)
Actuarial (Gain) or Loss	(17,414)	(7,145)
PBO at End of Year	81,005	94,122	96,659
Funded Status: Assets vs PBO	(59,896)	(73,888)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	401	34	34
Benefits Paid	(401)	(34)
PBO at Beginning of Year	11,723	9,566
Service Cost	487	460	162
Interest Cost	404	392	386
Benefits Paid	(401)	(34)	(34)
Actuarial (Gain) or Loss	1,541	1,339
PBO at End of Year	13,754	11,723	$ 9,566
Funded Status: Assets vs PBO	$ (13,754)	$ (11,723)

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Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 16,628	$ 4,100	$ 5,146
Benefit Payments	4,986	5,574	4,900
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	4,000	4,000	4,000
Participant Contributions	153	126	61
Benefit Payments	2,193	2,405	2,421
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	401	34	34
Benefit Payments	$ 401	$ 34	$ 34

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Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2019	$ 5,888
2020	6,484
2021	6,949
2022	6,853
2022	7,588
2024 - 2028	46,942
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2019	2,314
2020	2,520
2021	2,780
2022	2,955
2022	3,106
2024 - 2028	19,244
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2019	522
2020	521
2021	681
2022	678
2022	675
2024 - 2028	$ 4,904

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Actual Investment Allocations (Detail)		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			49.00%	49.00%	46.00%
Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			40.00%	34.00%	37.00%
Pension Plans | Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[1]			6.00%	7.00%
Pension Plans | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[2]		1.00%	1.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			53.00%	56.00%	55.00%
Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			47.00%	42.00%	43.00%
Other Postretirement Benefit Plans, Defined Benefit | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[3]			2.00%	2.00%
Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			10.00%	10.00%	10.00%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		53.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		37.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		45.00%
Scenario Forecast | Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		10.00%

[1] Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

[2] Represents investments being held in cash equivalents as of December 31, 2018 pending payment of benefits.

[3] Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds.

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Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 107,808	$ 102,315	$ 91,058
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	96,165	91,528
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	52,884	50,373
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	43,281	34,757
Mutual Fund | Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value		6,398
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	1,202	1,200
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	97,367	92,728
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	10,441	9,587
Fair Value, Inputs, Level 1 | Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	96,165	91,528
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	52,884	50,373
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	43,281	34,757
Fair Value, Inputs, Level 1 | Mutual Fund | Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value		6,398
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	1,202	1,200
Fair Value, Inputs, Level 1 | Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 97,367	$ 92,728

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Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 21,109	$ 20,234	$ 16,606
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value		19,834
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	9,905	8,419
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	11,204	11,415
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value		400
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	21,109	20,234
Fair Value, Inputs, Level 1 | Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value		19,834
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	9,905	8,419
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 11,204	11,415
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value		$ 400