10-Q 1 d544531d10q.htm 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended March 31, 2018

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

New Hampshire |  | 02-0381573
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
6 Liberty Lane West, Hampton, New Hampshire |  | 03842-1720
(Address of principal executive office) |  | (Zip Code)

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

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

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

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

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

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

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

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

Class |  | Outstanding at April 23, 2018
Common Stock, no par value |  | 14,861,228 Shares

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended March 31, 2018

Table of Contents

|  | Page No.
Part I. Financial Information |  |
Item 1. |  | Financial Statements (Unaudited) |  |
|  | Consolidated Statements of Earnings - Three Months Ended March 31, 2018 and 2017 |  | 21
|  | Consolidated Balance Sheets, March 31, 2018, March 31, 2017 and December 31, 2017 |  | 22-23
|  | Consolidated Statements of Cash Flows - Three Months Ended March 31, 2018 and 2017 |  | 24
|  | Consolidated Statements of Changes in Common Stock Equity – Three Months Ended March 31, 2018 and 2017 |  | 25
|  | Notes to Consolidated Financial Statements |  | 26-52
Item 2. |  | Management’s Discussion and Analysis of Financial Condition and Results of Operations |  | 4-20
Item 3. |  | Quantitative and Qualitative Disclosures About Market Risk |  | 53
Item 4. |  | Controls and Procedures |  | 53
Part II. Other Information
Item 1. |  | Legal Proceedings |  | 54
Item 1A. |  | Risk Factors |  | 54
Item 2. |  | Unregistered Sales of Equity Securities and Use of Proceeds |  | 54
Item 3. |  | Defaults Upon Senior Securities |  | Inapplicable
Item 4. |  | Mine Safety Disclosures |  | Inapplicable
Item 5. |  | Other Information |  | 55
Item 6. |  | Exhibits |  | 56
Signatures |  |  |  | 57

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CAUTIONARY STATEMENT

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

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

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

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

| • |  | customers’ preferred energy sources;

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

| • |  | the Company’s stranded electric generation and generation-related supply costs and the Company’s ability to recover stranded costs in its rates;

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

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

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

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

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

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

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

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| • |  | 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;

| • |  | the Company’s energy brokering customers’ performance under multi-year energy brokering contracts; and

| • |  | increased competition.

Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.

PART I. FINANCIAL INFORMATION

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

OVERVIEW

Unitil Corporation (Unitil or the Company) is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005.

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

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

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

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

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 105,000 electric customers and 81,300 natural gas customers in their service territory.

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

Unitil had an investment in Net Utility Plant of $972.4 million at March 31, 2018. Unitil’s total operating revenue includes revenue to recover the approved cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Company’s earnings are not directly affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are primarily derived from the return on investment in the utility assets of the three distribution utilities and Granite State.

Unitil also conducts non-regulated operations principally through Usource Inc. and Usource L.L.C. (collectively, Usource), which is wholly-owned by Unitil Resources Inc., a wholly-owned subsidiary of Unitil. Usource provides energy brokering and advisory services to large commercial and industrial customers (C&I) primarily in the northeastern United States. The Company’s other subsidiaries include Unitil Service Corp., which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, Unitil Realty Corp. (Unitil Realty), which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

RATES AND REGULATION

Regulation

Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and the Maine Public Utilities Commission (MPUC). Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

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

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recognized as an increase or a decrease in Accrued

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Revenue which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases and other authorized adjustments that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

Tax Cuts and Jobs Act of 2017

At the end of December 2017, the United States Congress voted and the President signed into law major federal tax law changes Tax Cuts and Jobs Act of 2017 (TCJA) effective for tax year 2018. Among other things, the TCJA substantially reduces 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 or is in the process of issuing 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 is fully complying with these orders and will make any necessary changes to its rates as directed by the commissions. The FERC has opened a rulemaking proceeding on this matter (described below). The Company believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows.

In Maine, Northern Utilities’ Maine division has recently completed a base rate case (described more fully below). The MPUC had issued a procedural order indicating that the tax law changes were to be reflected in its calculation of final rates for the Company, and the final order in that docket incorporated the lower tax rates.

In New Hampshire, Northern Utilities’ New Hampshire division has a base rate case proceeding pending (described below), and the NHPUC issued an order directing the Company to show how the tax changes can be effected within the schedule for the rate case. On April 6, 2018, Northern Utilities filed a proposed comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which includes the effect of the tax changes in the calculation of the agreed upon revenue requirement. With respect to Unitil Energy, the NHPUC directed the Company to make a filing by April 1, 2018, showing the effect of the tax law changes on rates. On March 16, 2018, the Company filed for its annual step increase pursuant to the provisions of its last base rate case, and included in that filing proposed adjustments to account for the tax changes. This proposal remains pending.

In Massachusetts, the Attorney General filed a petition with the MDPU requesting that it open an investigation to require the flow-through of the tax law changes in rates for all utilities subject to the MDPU’s jurisdiction. On February 2, 2018 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. The MDPU consolidated the Attorney General’s petition into its investigation. In its order, the MDPU required each utility company subject to its jurisdiction to file, by May 1, 2018, a proposal to address the effects of the TCJA and to reduce its rates through the establishment of a revised cost of service incorporating the lower federal corporate income tax rate as of January 1, 2018. Such proposals must address the adjustment of rates going forward and also incorporate the timely refund of revenues associated with the lower tax expense on current income and excess accumulated deferred income taxes (ADIT). Fitchburg plans to submit filings for both its gas and electric divisions with estimated revenue reductions of $0.8 million at each respective division. This matter remains pending.

On March 15, 2018, the FERC issued a Notice of Proposed Rulemaking (NOPR) that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax rate reduction and changes to the FERC’s income tax allowance policies. The proposed rule, if adopted, would require an interstate pipeline to file a

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one-time report on the regulated rate effect of the new tax law and changes to the FERC’s income tax allowance policies. In addition to filing the one-time report, each pipeline would have four options: 1) make a limited rate filing to reduce its rates by the percentage reduction in its cost of service shown in its report; 2) commit to file either a prepackaged uncontested rate settlement or a general rate case by December 31, 2018; 3) file a statement explaining why it believes its current rates are reasonable and no reduction is necessary; or 4) file the required report without taking any other action, at which point FERC would consider whether to initiate an investigation. Granite State is reviewing the NOPR and will comply with all FERC requirements. Granite State believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows.

Rate Case Activity

Unitil Energy – Base Rates – On April 20, 2017 the NHPUC issued its final order approving a settlement between Unitil Energy, NHPUC Staff and the Office of Consumer Advocate providing for 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 as defined under the rate plan. On March 16, 2018, Unitil Energy filed its second step adjustment. The filing also incorporated the revenue requirement effect of the federal tax decrease pursuant to the TCJA, along with the termination of the one-year reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments results in a proposed revenue decrease of $0.4 million. The proposal remains pending.

Fitchburg – Base Rates – Electric – On April 29, 2016 the MDPU issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. As part of its order, the MDPU approved, with modifications, Fitchburg’s request for an annual capital cost recovery mechanism, which allows for increases to target revenues to recover the revenue requirement associated with capital additions as defined under the mechanism. In 2016, Fitchburg filed its first compliance report on capital investments for calendar year 2015. The MDPU approved the recovery of approximately $0.5 million, effective January 1, 2017, subject to further investigation and reconciliation. On December 18, 2017, the MDPU approved Fitchburg’s calendar year 2015 capital investments and associated revenue requirements for recovery. On June 29, 2017, Fitchburg filed its compliance report on capital investments for calendar year 2016. On December 20, 2017, the MDPU approved the recovery of approximately $0.4 million, effective January 1, 2018, subject to further investigation and reconciliation.

Fitchburg – Base Rates – Gas – On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg – Gas Operations – On October 31, 2016, Fitchburg submitted its annual filing under its gas system enhancement program to recover the revenue requirements associated with its projected capital additions in 2017 as defined under the program. The filing sought approval to collect an additional $0.9 million of annual revenue requirements. On April 28, 2017, the MDPU approved recovery of the projected 2017 revenue requirements, subject to reconciliation and a cap of 1.5% on the change in revenue requirement to be billed in any given year. The cap resulted in approval of an additional $0.5 million of annual revenue requirements to be billed effective May 1, 2017 with the remaining $0.4 million of annual revenue requirements deferred for billing in future periods. In its April 28, 2017 annual reconciliation filing for 2016 revenue requirements, the Company requested that the MDPU waive the 1.5% revenue requirement cap. On October 31, 2017, the MDPU approved a one-year waiver of the cap and allowed the Company to bill the total 2016 actual reconciliation balance. On October 31, 2017, Fitchburg submitted its annual filing under the program to recover the revenue requirements associated with its projected capital additions in 2018. In this filing, the Company has requested to change the revenue requirements cap to 3%. This matter remains pending.

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Northern Utilities – Base Rates – Maine – In May 2017, Northern Utilities filed a base rate case with the MPUC seeking to increase annual revenues by $6.0 million. The requested increase was subsequently supplemented by an additional $0.7 million associated with the Company’s Targeted Area Build-out (TAB) Program (see below). In addition to the distribution base rate increase, Northern Utilities requested to extend its Targeted Infrastructure Replacement Adjustment mechanism (TIRA) (see below).

On February 28, 2018 the MPUC issued its Final Order (Order) in the base rate case. The Order provides for a revenue increase of $2.1 million offset by a revenue decrease of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA, resulting in an overall annual revenue decrease of $0.1 million. The MPUC 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. The Order addresses a number of other issues including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s TAB Program and TIRA mechanism. The new rates and other changes became effective as of March 1, 2018. On March 16, 2018, the Company filed a Motion for Clarification requesting the MPUC clarify its Order in light of what the Company believes to be an inadvertent inconsistency with the Order regarding 2016 TIRA Eligible Facilities, rate base and related annual revenue adjustments.

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 Company’s TIRA mechanism, with revision, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On March 30, 2018, the Company filed its request to increase its annual base rates to recover the revenue requirements for 2017 Eligible Facilities. This matter remains pending.

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 (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 June 5, 2017, Northern Utilities filed for a base rate increase with the NHPUC seeking to increase annual revenues by $4.7 million. On June 15, 2017, the NHPUC suspended the Company’s proposed permanent rates tariffs while the filing is under regulatory review

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Northern Utilities reached a settlement agreement on temporary rates to produce an increase in annual revenues of approximately $1.6 million, effective with service rendered on and after August 1, 2017, and until a final, non-appealable order on permanent rates is issued. The settlement agreement was approved by the NHPUC on July 31, 2017. As of March 31, 2018, Northern Utilities has deferred approximately $1.1 million of costs associated with this base rate case. Once a final decision on permanent rates is issued, it will be reconciled back to the date that temporary rates were implemented.

On April 6, 2018, Northern Utilities filed a proposed comprehensive settlement agreement among the Company, the NHPUC Staff and the Office of the Consumer Advocate. The settling parties agreed to an annual revenue increase of $2.6 million and an offsetting decrease of $1.7 million to reflect the effect of the TCJA, for a net annual revenue increase of $0.9 million, effective May 1, 2018. The parties also agreed to a step increase of $2.3 million to recover post-test year capital investments, also effective May 1, 2018. 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 shall be based on an historic test year of no earlier than twelve months ending December 31, 2020. A hearing before the NHPUC to consider the settlement agreement was held on April 12, 2018. This matter remains pending.

Northern Utilities – Pipeline Refund – On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers over three years as directed by the NHPUC and MPUC. As of March 31, 2018, $21.4 million has been refunded to Northern Utilities’ customers and marketers. The Company has recorded current Regulatory Liabilities related to these refunds of $0.6 million on its Consolidated Balance Sheets as of March 31, 2018.

Granite State – Base Rates – Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cap on expenditures. On June 21, 2017 Granite State filed for an annual revenue increase under this provision of $0.2 million, effective August 1, 2017. The FERC issued an order approving the filing on July 28, 2017. This is the last annual rate adjustment allowed under the second amended settlement because Granite must file a general rate case pursuant to Section 4 of the Natural Gas Act by April 30, 2018 with rates effective no later than November 1, 2018.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended March 31, 2018 and March 31, 2017 and should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and the accompanying Notes to unaudited Consolidated Financial Statements included in Part I, Item 1 of this report, which are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The Company’s results of operations reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive

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to weather than natural gas sales, but may also be affected by the weather conditions in both the winter and summer seasons. Also, as a result of recent rate cases, the Company’s natural gas sales margins are derived from a higher percentage of fixed billing components, including customer charges. Therefore, natural gas revenues and margin will be less affected by the seasonal nature of the natural gas business. In addition, as previously discussed, 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.

Earnings Overview

The Company’s Net Income was $15.6 million, or $1.06 per share, for the first quarter of 2018, an increase of $3.2 million in Net Income, and $0.18 in Earnings Per Share, compared to the first quarter of 2017. The Company’s earnings in the first quarter of 2018 were driven by higher natural gas and electric sales margins, reflecting: customer growth, colder winter weather and new distribution rates compared to the first quarter of 2017.

Natural gas sales margin was $39.9 million in the three months ended March 31, 2018, an increase of $1.9 million compared to the same period in 2017. Gas sales margin in the first quarter of 2018 was positively affected by colder weather and customer growth of $1.8 million and higher natural gas distribution rates of $1.6 million, partially offset by lower revenue of $1.5 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues also reflects a lower provision for income taxes.

Natural gas therm sales increased 9.5% in the three months ended March 31, 2018 compared to the same period in 2017. Based on weather data collected in the Company’s natural gas service areas, there were 10% more HDD in the first quarter of 2018 compared to the same period in 2017. As of March 31, 2018, the number of total natural gas customers served has increased by 1,478 in the last twelve months.

Electric sales margin was $22.3 million in the three months ended March 31, 2018, an increase of $0.3 million compared to the same period in 2017. Electric sales margin in the first quarter of 2018 was positively affected by higher electric distribution rates of $0.9 million as well as colder weather and customer growth of $0.2 million, partially offset by lower revenue of $0.8 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues also reflects a lower provision for income taxes.

Total electric kWh sales increased 5.8% compared to the first quarter of 2017. As of March 31, 2018, the number of total electric customers served has increased by 516 in the last twelve months.

Operation and Maintenance (O&M) expenses increased $1.3 million in the three months ended March 31, 2018 compared to the same period in 2017. The change in O&M expenses reflects an increase in compensation and benefit costs of $0.7 million, bad debt expenses of $0.2 million and utility operating costs of $0.4 million.

Depreciation and Amortization expense decreased $0.2 million in the three months ended March 31, 2018 compared to the same period in 2017, reflecting lower amortization of deferred major storm costs, partially offset by higher utility plant in service and amortization of information system and software costs.

Taxes Other Than Income Taxes increased $0.3 million in the three months ended March 31, 2018 compared to the same period in 2017, primarily reflecting higher local property taxes on higher levels of utility plant assets in service.

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Interest Expense, net was essentially unchanged in the three months ended March 31, 2018 compared to the same period in 2017, reflecting higher interest on long-term debt offset by lower net interest expense on net regulatory assets/liabilities and lower levels of short-term debt.

Federal and State Income Taxes decreased by $2.9 million for the three months ended March 31, 2018 compared to the same period in 2017, reflecting $2.3 million from a lower tax rate on higher pre-tax earnings in Q1 2018 (see revenue discussion above) and the current tax benefit of $0.6 million on book/tax items not previously included in customers’ utility rates.

At its January 2018 and April 2018 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.365 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.46 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

A more detailed discussion of the Company’s results of operations for the three months ended March 31, 2018 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 9.5% in the three months ended March 31, 2018 compared to the same period in 2017, reflecting increases of 13.3% and 8.3% in sales to Residential and Commercial and Industrial (C&I) customers, respectively. The increase in gas therm sales in the Company’s service areas was driven by customer growth and colder winter weather in the first quarter of 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 10% more HDD in the first quarter of 2018 compared to the same period in 2017. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 3.6% in the first quarter of 2018 compared to the same period in 2017. As of March 31, 2018, the number of total natural gas customers served has increased by 1,478 in the last twelve months. 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.

The following table details total firm therm sales for the three months ended March 31, 2018 and 2017, by major customer class:

Therm Sales (millions) |
|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |  |  | Change |  |  | % Change |
Residential |  |  | 23.8 |  |  |  | 21.0 |  |  |  | 2.8 |  |  |  | 13.3 | %
Commercial / Industrial |  |  | 70.3 |  |  |  | 64.9 |  |  |  | 5.4 |  |  |  | 8.3 | %
Total |  |  | 94.1 |  |  |  | 85.9 |  |  |  | 8.2 |  |  |  | 9.5 | %

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Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three months ended March 31, 2018 and 2017:

Gas Operating Revenues and Sales Margin (millions) |
|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |  |  | $ Change |  |  | % Change |
Gas Operating Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 35.8 |  |  | $ | 31.1 |  |  | $ | 4.7 |  |  |  | 15.1 | %
Commercial / Industrial |  |  | 51.2 |  |  |  | 43.7 |  |  |  | 7.5 |  |  |  | 17.2 | %
Total Gas Operating Revenues |  | $ | 87.0 |  |  | $ | 74.8 |  |  | $ | 12.2 |  |  |  | 16.3 | %
Cost of Gas Sales |  | $ | 47.1 |  |  | $ | 36.8 |  |  | $ | 10.3 |  |  |  | 28.0 | %
Gas Sales Margin |  | $ | 39.9 |  |  | $ | 38.0 |  |  | $ | 1.9 |  |  |  | 5.0 | %

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

Natural gas sales margin was $39.9 million in the three months ended March 31, 2018, an increase of $1.9 million compared to the same period in 2017. Gas sales margin in the first quarter of 2018 was positively affected by colder weather and customer growth of $1.8 million and higher natural gas distribution rates of $1.6 million, partially offset by lower revenue of $1.5 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues also reflects a lower provision for income taxes.

The increase in Total Gas Operating Revenues of $12.2 million in the first quarter of 2018 reflects higher natural gas sales volumes and higher cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers, partially offset by lower revenue related to the TCJA, discussed above.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – In the first quarter of 2018, Unitil’s total electric kWh sales increased 5.8% compared to the first quarter of 2017. Sales to Residential and C&I customers increased 7.0% and 4.9%, respectively, in the first quarter of 2018 compared to the same period in 2017, reflecting the positive impact of colder weather, customer growth and higher usage by industrial customers for production purposes. As of March 31, 2018, the number of total electric customers served has increased by 516 in the last twelve months. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.

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The following table details total kWh sales for the three months ended March 31, 2018 and 2017 by major customer class:

kWh Sales (millions) |
|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |  |  | Change |  |  | % Change |
Residential |  |  | 188.5 |  |  |  | 176.2 |  |  |  | 12.3 |  |  |  | 7.0 | %
Commercial / Industrial |  |  | 247.8 |  |  |  | 236.2 |  |  |  | 11.6 |  |  |  | 4.9 | %
Total |  |  | 436.3 |  |  |  | 412.4 |  |  |  | 23.9 |  |  |  | 5.8 | %

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three months ended March 31, 2018 and 2017:

Electric Operating Revenues and Sales Margin (millions) |
|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |  |  | $ Change |  |  | % Change |
Electric Operating Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 33.8 |  |  | $ | 28.9 |  |  | $ | 4.9 |  |  |  | 17.0 | %
Commercial / Industrial |  |  | 23.7 |  |  |  | 20.6 |  |  |  | 3.1 |  |  |  | 15.0 | %
Total Electric Operating Revenues |  | $ | 57.5 |  |  | $ | 49.5 |  |  | $ | 8.0 |  |  |  | 16.2 | %
Total Cost of Electric Sales |  | $ | 35.2 |  |  | $ | 27.5 |  |  | $ | 7.7 |  |  |  | 28.0 | %
Electric Sales Margin |  | $ | 22.3 |  |  | $ | 22.0 |  |  | $ | 0.3 |  |  |  | 1.4 | %

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

Electric sales margin was $22.3 million in the three months ended March 31, 2018, an increase of $0.3 million compared to the same period in 2017. Electric sales margin in the first quarter of 2018 was positively affected by higher electric distribution rates of $0.9 million as well as colder weather and customer growth of $0.2 million, partially offset by lower revenue of $0.8 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues also reflects a lower provision for income taxes.

The increase in Total Electric Operating Revenues of $8.0 million in the first quarter of 2018 reflects higher electric sales volumes and higher cost of electric sales, which are tracked and reconciled costs that are passed through directly to customers, partially offset by lower revenues related to the TCJA, discussed above.

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Operating Revenue – Other

The following table details total Other Operating Revenue for the three months ended March 31, 2018 and 2017:

Other Operating Revenue (Millions) |
|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |  |  | $ Change |  |  | % Change |
Other |  | $ | 1.3 |  |  | $ | 1.7 |  |  | $ | (0.4 | ) |  |  | (23.5 | %)
Total Other Operating Revenue |  | $ | 1.3 |  |  | $ | 1.7 |  |  | $ | (0.4 | ) |  |  | (23.5 | %)

Total Other Operating Revenue (See “Other Operating Revenue – Non-regulated” in Note 1 to the accompanying Consolidated Financial Statements), which is comprised of revenues from the Company’s non-regulated energy brokering business, Usource, decreased $0.4 million, or 23.5% in the first quarter of 2018, compared to the first quarter of 2017, primarily as a 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 with the three months ended March 31, 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 $0.3 million each of the first quarters of 2018 and 2017.

If ASU 2014-09 had been in effect for the three months ended March 31, 2017, the result would have been corresponding reductions of $0.3 million in both “Other” in 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. 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.

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 $10.3 million, or 28.0%, in the three months ended March 31, 2018 compared to the same period in 2017. This increase reflects higher wholesale natural gas prices and higher sales of natural gas. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

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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 $7.7 million, or 28.0%, in the three months ended March 31, 2018 compared to the same period in 2017. This increase reflects higher wholesale electricity prices and higher sales of electricity. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

Operation and Maintenance – O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s other business activities. O&M expenses increased $1.3 million, or 8.1%, in the three months ended March 31, 2018 compared to the same period in 2017. The change in O&M expenses reflects an increase in compensation and benefit costs of $0.7 million, bad debt expenses of $0.2 million and utility operating costs of $0.4 million.The higher utility operating costs reflect increased system maintenance costs related to a higher level of storms and colder weather in the first quarter of 2018 compared to the prior year period, as well as higher bad debt expense related to increased sales.

Depreciation and Amortization – Depreciation and Amortization expense decreased $0.2 million, or 1.6%, in the three months ended March 31, 2018 compared to the same period in 2017, reflecting lower amortization of deferred major storm costs, partially offset by higher utility plant in service and amortization of information system and software costs.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes increased $0.3 million, or 5.5%, in the three months ended March 31, 2018 compared to the same period in 2017, primarily reflecting higher local property taxes on higher levels of utility plant assets in service.

Other Expense, net – Other Expense, net in the three month period ended March 31, 2018 increased $0.1 million compared with the same period in 2017. 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-Q for the quarter ended March 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 $1.5 million and $1.6 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the three months ended March 31, 2018 and March 31, 2017, respectively.

Income Taxes – Federal and State Income Taxes decreased by $2.9 million for the three months ended March 31, 2018 compared to the same period in 2017, reflecting $2.3 million from a lower tax rate on higher pre-tax earnings in Q1 2018 and the current tax benefit of $0.6 million on book/tax items not previously included in customers’ utility rates.

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 accrued.

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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.

Interest Expense, net (millions) |  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |  |  | Change |
Interest Expense |  |  |  |  |  |  |  |  |  |  |  |
Long-term Debt |  | $ | 5.8 |  |  | $ | 5.3 |  |  | $ | 0.5 |
Short-term Debt |  |  | 0.5 |  |  |  | 0.6 |  |  |  | (0.1 | )
Regulatory Liabilities |  |  | 0.1 |  |  |  | 0.5 |  |  |  | (0.4 | )
Subtotal Interest Expense |  |  | 6.4 |  |  |  | 6.4 |  |  |  | — |
Interest (Income) |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | (0.2 | ) |  |  | (0.2 | ) |  |  | — |
AFUDC and Other |  |  | (0.2 | ) |  |  | (0.2 | ) |  |  | — |
Subtotal Interest (Income) |  |  | (0.4 | ) |  |  | (0.4 | ) |  |  | — |
Total Interest Expense, net |  | $ | 6.0 |  |  | $ | 6.0 |  |  | $ | — |

Interest Expense, net was essentially unchanged in the three months ended March 31, 2018 compared to the same period in 2017, reflecting higher interest on long-term debt offset by lower net interest expense on net regulatory assets/liabilities and lower levels of short-term debt.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally-generated funds through short-term bank borrowings, as needed, under its unsecured revolving Credit Facility. Periodically, the Company replaces portions of its short-term debt with long-term 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

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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 March 31, 2018, March 31, 2017 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 October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Facility”). The Credit Facility terminates October 4, 2020 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil 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 (LIBOR) plus 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $88.9 million for the three months ended March 31, 2018. Total gross repayments were $81.9 million for the three months ended March 31, 2017. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of March 31, 2018, March 31, 2017 and December 31, 2017:

|  | Revolving Credit Facility ($ millions) |
|  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |  |  | $ | 120.0 |
Short-Term Borrowings Outstanding |  | $ | 45.3 |  |  | $ | 76.6 |  |  | $ | 38.3 |
Letters of Credit Outstanding |  | $ | 0.0 |  |  | $ | 1.1 |  |  | $ | 0.0 |
Available |  | $ | 74.7 |  |  | $ | 42.3 |  |  | $ | 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 Corporation’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 until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At March 31, 2018, March 31, 2017 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 4.)

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.

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In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of March 31, 2018, there are $2.7 million of current and $4.4 million of noncurrent obligations under this capital lease on the Company’s 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.

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

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of March 31, 2018, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2018.

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 $1.0 million, $3.8 million and $8.5 million of natural gas storage inventory at March 31, 2018, March 31, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2018 and payable in April 2018 is $1.0 million and is recorded in Accounts Payable at March 31, 2018. The amount of natural gas inventory released in March 2017 and payable in April 2017 was $2.0 million and was recorded in Accounts Payable at March 31, 2017. The amount of natural gas inventory released in December 2017 and payable in January 2018 was $3.1 million and was recorded in Accounts Payable at December 31, 2017.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Granite State. As of March 31, 2018, the principal amount outstanding for the 7.15% Granite State notes was $3.3 million.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil Corporation’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of March 31, 2018, there were approximately $17.9 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding and the longest term guarantee extends through August 2018. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

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CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. For a complete discussion of the Company’s significant accounting policies, refer to Note 1 to the Consolidated Financial Statements in this quarterly report on Form 10-Q and Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 1, 2018.

LABOR RELATIONS

As of March 31, 2018, the Company and its subsidiaries had 514 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of March 31, 2018, a total of 167 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 March 31, 2018:

|  | Employees Covered |  |  | CBA Expiration |
Fitchburg |  |  | 48 |  |  |  | 05/31/2019 |
Northern Utilities NH Division |  |  | 36 |  |  |  | 06/05/2020 |
Northern Utilities ME Division |  |  | 36 |  |  |  | 03/31/2021 |
Granite State |  |  | 4 |  |  |  | 03/31/2021 |
Unitil Energy |  |  | 38 |  |  |  | 05/31/2018 |
Unitil Service |  |  | 5 |  |  |  | 05/31/2018 |

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

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest

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rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings and intercompany money pool transactions for the three months ended March 31, 2018 and March 31, 2017 were 2.9% and 2.1%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2017 was 2.4%.

COMMODITY PRICE RISK

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

REGULATORY MATTERS

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

ENVIRONMENTAL MATTERS

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

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Item 1. | Financial Statements

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

(UNAUDITED)

|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |
Operating Revenues |  |  |  |  |  |  |  |
Gas |  | $ | 87.0 |  |  | $ | 74.8 |
Electric |  |  | 57.5 |  |  |  | 49.5 |
Other |  |  | 1.3 |  |  |  | 1.7 |
Total Operating Revenues |  |  | 145.8 |  |  |  | 126.0 |
Operating Expenses |  |  |  |  |  |  |  |
Cost of Gas Sales |  |  | 47.1 |  |  |  | 36.8 |
Cost of Electric Sales |  |  | 35.2 |  |  |  | 27.5 |
Operation and Maintenance |  |  | 17.3 |  |  |  | 16.0 |
Depreciation and Amortization |  |  | 12.3 |  |  |  | 12.5 |
Taxes Other than Income Taxes |  |  | 5.8 |  |  |  | 5.5 |
Total Operating Expenses |  |  | 117.7 |  |  |  | 98.3 |
Operating Income |  |  | 28.1 |  |  |  | 27.7 |
Interest Expense, net |  |  | 6.0 |  |  |  | 6.0 |
Other Expense (Income), net |  |  | 1.7 |  |  |  | 1.6 |
Income Before Income Taxes |  |  | 20.4 |  |  |  | 20.1 |
Income Taxes |  |  | 4.8 |  |  |  | 7.7 |
Net Income |  | $ | 15.6 |  |  | $ | 12.4 |
Net Income Per Common Share (Basic and Diluted) |  | $ | 1.06 |  |  | $ | 0.88 |
Weighted Average Common Shares Outstanding – (Basic and Diluted) |  |  | 14.8 |  |  |  | 14.0 |
Dividends Declared Per Share of Common Stock |  | $ | 0.365 |  |  | $ | 0.360 |

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

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)

|  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
ASSETS: |  |  |  |  |  |  |  |  |  |  |  |
Current Assets: |  |  |  |  |  |  |  |  |  |  |  |
Cash and Cash Equivalents |  | $ | 9.5 |  |  | $ | 8.8 |  |  | $ | 8.9 |
Accounts Receivable, net |  |  | 74.4 |  |  |  | 57.6 |  |  |  | 67.4 |
Accrued Revenue |  |  | 45.1 |  |  |  | 41.3 |  |  |  | 53.3 |
Exchange Gas Receivable |  |  | 0.2 |  |  |  | 2.1 |  |  |  | 5.8 |
Gas Inventory |  |  | 0.4 |  |  |  | 0.3 |  |  |  | 0.6 |
Materials and Supplies |  |  | 7.8 |  |  |  | 7.1 |  |  |  | 6.9 |
Prepayments and Other |  |  | 7.1 |  |  |  | 8.9 |  |  |  | 8.4 |
Total Current Assets |  |  | 144.5 |  |  |  | 126.1 |  |  |  | 151.3 |
Utility Plant: |  |  |  |  |  |  |  |  |  |  |  |
Gas |  |  | 706.7 |  |  |  | 642.0 |  |  |  | 699.6 |
Electric |  |  | 478.8 |  |  |  | 440.9 |  |  |  | 476.7 |
Common |  |  | 69.1 |  |  |  | 35.9 |  |  |  | 67.4 |
Construction Work in Progress |  |  | 32.1 |  |  |  | 68.6 |  |  |  | 35.5 |
Total Utility Plant |  |  | 1,286.7 |  |  |  | 1,187.4 |  |  |  | 1,279.2 |
Less: Accumulated Depreciation |  |  | 314.3 |  |  |  | 296.5 |  |  |  | 307.7 |
Net Utility Plant |  |  | 972.4 |  |  |  | 890.9 |  |  |  | 971.5 |
Other Noncurrent Assets: |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | 111.2 |  |  |  | 103.5 |  |  |  | 109.6 |
Other Assets |  |  | 16.2 |  |  |  | 13.9 |  |  |  | 9.5 |
Total Other Noncurrent Assets |  |  | 127.4 |  |  |  | 117.4 |  |  |  | 119.1 |
TOTAL ASSETS |  | $ | 1,244.3 |  |  | $ | 1,134.4 |  |  | $ | 1,241.9 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)

|  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
LIABILITIES AND CAPITALIZATION: |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Accounts Payable |  | $ | 30.1 |  |  | $ | 28.1 |  |  | $ | 41.5 |
Short-Term Debt |  |  | 45.3 |  |  |  | 76.6 |  |  |  | 38.3 |
Long-Term Debt, Current Portion |  |  | 29.8 |  |  |  | 30.0 |  |  |  | 29.8 |
Regulatory Liabilities |  |  | 10.9 |  |  |  | 12.8 |  |  |  | 9.2 |
Energy Supply Obligations |  |  | 7.8 |  |  |  | 9.0 |  |  |  | 9.7 |
Environmental Obligations |  |  | 0.6 |  |  |  | 0.5 |  |  |  | 0.5 |
Capital Lease Obligations |  |  | 3.1 |  |  |  | 3.0 |  |  |  | 3.1 |
Interest Payable |  |  | 6.9 |  |  |  | 6.0 |  |  |  | 4.4 |
Other Current Liabilities |  |  | 11.8 |  |  |  | 11.0 |  |  |  | 14.5 |
Total Current Liabilities |  |  | 146.3 |  |  |  | 177.0 |  |  |  | 151.0 |
Noncurrent Liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Retirement Benefit Obligations |  |  | 151.6 |  |  |  | 151.5 |  |  |  | 150.1 |
Deferred Income Taxes, net |  |  | 87.0 |  |  |  | 106.0 |  |  |  | 82.9 |
Cost of Removal Obligations |  |  | 86.6 |  |  |  | 79.7 |  |  |  | 84.3 |
Regulatory Liabilities |  |  | 49.1 |  |  |  | 0.7 |  |  |  | 48.9 |
Capital Lease Obligations |  |  | 4.9 |  |  |  | 7.5 |  |  |  | 5.7 |
Environmental Obligations |  |  | 1.5 |  |  |  | 1.8 |  |  |  | 1.6 |
Other Noncurrent Liabilities |  |  | 5.7 |  |  |  | 4.9 |  |  |  | 4.3 |
Total Noncurrent Liabilities |  |  | 386.4 |  |  |  | 352.1 |  |  |  | 377.8 |
Capitalization: |  |  |  |  |  |  |  |  |  |  |  |
Long-Term Debt, Less Current Portion |  |  | 363.0 |  |  |  | 303.5 |  |  |  | 376.3 |
Stockholders’ Equity: |  |  |  |  |  |  |  |  |  |  |  |
Common Equity (Authorized: 25,000,000 and Outstanding:14,860,123, 14,107,741 and 14,815,585 Shares) |  |  | 277.4 |  |  |  | 242.1 |  |  |  | 275.8 |
Retained Earnings |  |  | 71.0 |  |  |  | 59.5 |  |  |  | 60.8 |
Total Common Stock Equity |  |  | 348.4 |  |  |  | 301.6 |  |  |  | 336.6 |
Preferred Stock |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.2 |
Total Stockholders’ Equity |  |  | 348.6 |  |  |  | 301.8 |  |  |  | 336.8 |
Total Capitalization |  |  | 711.6 |  |  |  | 605.3 |  |  |  | 713.1 |
Commitments and Contingencies (Notes 6 & 7) |  |  |  |  |  |  |  |  |  |  |  |
TOTAL LIABILITIES AND CAPITALIZATION |  | $ | 1,244.3 |  |  | $ | 1,134.4 |  |  | $ | 1,241.9 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)

|  | Three Months Ended March 31, |
|  | 2018 |  |  | 2017 |
Operating Activities: |  |  |  |  |  |  |  |
Net Income |  | $ | 15.6 |  |  | $ | 12.4 |
Adjustments to Reconcile Net Income to Cash |  |  |  |  |  |  |  |
Provided by Operating Activities: |  |  |  |  |  |  |  |
Depreciation and Amortization |  |  | 12.3 |  |  |  | 12.5 |
Deferred Tax Provision |  |  | 4.7 |  |  |  | 7.9 |
Changes in Working Capital Items: |  |  |  |  |  |  |  |
Accounts Receivable |  |  | (7.0 | ) |  |  | (4.7 | )
Accrued Revenue |  |  | 8.2 |  |  |  | 8.2 |
Exchange Gas Receivable |  |  | 5.6 |  |  |  | 6.2 |
Regulatory Liabilities |  |  | 1.7 |  |  |  | 2.4 |
Accounts Payable |  |  | (11.4 | ) |  |  | (4.3 | )
Other Changes in Working Capital Items |  |  | 3.6 |  |  |  | (1.2 | )
Deferred Regulatory and Other Charges |  |  | (7.9 | ) |  |  | (7.7 | )
Other, net |  |  | 3.0 |  |  |  | 5.8 |
Cash Provided by Operating Activities |  |  | 28.4 |  |  |  | 37.5 |
Investing Activities: |  |  |  |  |  |  |  |
Property, Plant and Equipment Additions |  |  | (10.1 | ) |  |  | (17.5 | )
Cash (Used in) Investing Activities |  |  | (10.1 | ) |  |  | (17.5 | )
Financing Activities: |  |  |  |  |  |  |  |
Proceeds from (Repayment of) Short-Term Debt, net |  |  | 7.0 |  |  |  | (5.3 | )
Repayment of Long-Term Debt |  |  | (13.4 | ) |  |  | (0.2 | )
Decrease in Capital Lease Obligations |  |  | (0.8 | ) |  |  | (0.8 | )
Net Decrease in Exchange Gas Financing |  |  | (5.4 | ) |  |  | (5.9 | )
Dividends Paid |  |  | (5.4 | ) |  |  | (5.1 | )
Proceeds from Issuance of Common Stock |  |  | 0.3 |  |  |  | 0.3 |
Cash (Used in) Financing Activities |  |  | (17.7 | ) |  |  | (17.0 | )
Net Increase in Cash and Cash Equivalents |  |  | 0.6 |  |  |  | 3.0 |
Cash and Cash Equivalents at Beginning of Period |  |  | 8.9 |  |  |  | 5.8 |
Cash and Cash Equivalents at End of Period |  | $ | 9.5 |  |  | $ | 8.8 |
Supplemental Cash Flow Information: |  |  |  |  |  |  |  |
Interest Paid |  | $ | 3.6 |  |  | $ | 4.0 |
Income Taxes Paid |  | $ | 0.2 |  |  | $ | — |
Payments on Capital Leases |  | $ | 0.8 |  |  | $ | 0.9 |
Non-cash Investing Activity: |  |  |  |  |  |  |  |
Capital Expenditures Included in Accounts Payable |  | $ | 0.5 |  |  | $ | 0.6 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)

(UNAUDITED)

|  | Common Equity |  |  | Retained Earnings |  |  | Total |
Balance at January 1, 2018 |  | $ | 275.8 |  |  | $ | 60.8 |  |  | $ | 336.6 |
Net Income |  |  |  |  |  |  | 15.6 |  |  |  | 15.6 |
Dividends on Common Shares |  |  |  |  |  |  | (5.4 | ) |  |  | (5.4 | )
Stock Compensation Plans |  |  | 1.3 |  |  |  |  |  |  |  | 1.3 |
Issuance of 7,812 Common Shares |  |  | 0.3 |  |  |  |  |  |  |  | 0.3 |
Balance at March 31, 2018 |  | $ | 277.4 |  |  | $ | 71.0 |  |  | $ | 348.4 |
Balance at January 1, 2017 |  | $ | 240.7 |  |  | $ | 52.2 |  |  | $ | 292.9 |
Net Income |  |  |  |  |  |  | 12.4 |  |  |  | 12.4 |
Dividends on Common Shares |  |  |  |  |  |  | (5.1 | ) |  |  | (5.1 | )
Stock Compensation Plans |  |  | 1.1 |  |  |  |  |  |  |  | 1.1 |
Issuance of 7,581 Common Shares |  |  | 0.3 |  |  |  |  |  |  |  | 0.3 |
Balance at March 31, 2017 |  | $ | 242.1 |  |  | $ | 59.5 |  |  | $ | 301.6 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the distribution utilities).

Granite State is a natural gas transportation pipeline, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers.

Unitil also has three other wholly-owned subsidiaries: Unitil Service; Unitil Realty; and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.

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##### Table of Contents

Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three months ended March 31, 2018 are not necessarily indicative of results to be expected for the year ending December 31, 2018. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission (SEC) on February 1, 2018, for a description of the Company’s Basis of Presentation.

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

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 three months ended March 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.

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##### Table of Contents

In the following tables, revenue is classified by the types of goods/services rendered and market/customer type. The lower revenues reported in the first quarter of 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 table below for informational purposes.

|  | Three Months Ended March 31, 2018 |
Gas and Electric Operating Revenues ($ millions): |  | Gas |  |  | Electric |  |  | Total |
Billed and Unbilled Revenue: |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 35.8 |  |  | $ | 34.4 |  |  | $ | 70.2 |
C&I |  |  | 50.6 |  |  |  | 24.1 |  |  |  | 74.7 |
Other |  |  | 6.5 |  |  |  | 3.9 |  |  |  | 10.4 |
Revenue Reductions – TCJA |  |  | (1.5 | ) |  |  | (0.8 | ) |  |  | (2.3 | )
Total Billed and Unbilled Revenue |  |  | 91.4 |  |  |  | 61.6 |  |  |  | 153.0 |
Rate Adjustment Mechanism Revenue |  |  | (4.4 | ) |  |  | (4.1 | ) |  |  | (8.5 | )
Total Gas and Electric Operating Revenues |  | $ | 87.0 |  |  | $ | 57.5 |  |  | $ | 144.5 |
|  | Three Months Ended March 31, 2017 |
Gas and Electric Operating Revenues ($ millions): |  | Gas |  |  | Electric |  |  | Total |
Billed and Unbilled Revenue: |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 30.9 |  |  | $ | 27.3 |  |  | $ | 58.2 |
C&I |  |  | 42.3 |  |  |  | 19.5 |  |  |  | 61.8 |
Other |  |  | 5.6 |  |  |  | 2.2 |  |  |  | 7.8 |
Total Billed and Unbilled Revenue |  |  | 78.8 |  |  |  | 49.0 |  |  |  | 127.8 |
Rate Adjustment Mechanism Revenue |  |  | (4.0 | ) |  |  | 0.5 |  |  |  | (3.5 | )
Total Gas and Electric Operating Revenues |  | $ | 74.8 |  |  | $ | 49.5 |  |  | $ | 124.3 |

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.

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##### Table of Contents

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 with the three months ended March 31, 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 $0.3 million each of the first quarters of 2018 and 2017.

If ASU 2014-09 had been adopted retroactively for the three months ended March 31, 2017, the result would have been corresponding reductions of $0.3 million in both “Other” in 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.

|  | Three Months Ended March 31, |
|  | As Reported |  |  | If ASU 2014-09 Had Been in Effect |
Other Operating Revenues ($ millions): |  | 2018 |  |  | 2017 |
Usource Contract Revenue |  | $ | 1.6 |  |  | $ | 1.7 |
Less: Revenue Sharing Payments |  |  | 0.3 |  |  |  | 0.3 |
Total Other Operating Revenues |  | $ | 1.3 |  |  | $ | 1.4 |
|  | Three Months Ended March 31, |
|  | As Reported |  |  | If ASU 2014-09 Had Been in Effect |
Operation and Maintenance Expense ($ millions): |  | 2018 |  |  | 2017 |
Operation and Maintenance Expense |  | $ | 17.3 |  |  | $ | 15.7 |

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 9 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.

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##### Table of Contents

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-Q for the quarter ended March 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 quarter ended March 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 period. There are $1.5 million and $1.6 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net for the three months ended March 31, 2018 and March 31, 2017, respectively, net of amounts deferred as regulatory assets for future recovery.

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 current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of March 31, 2018, March 31, 2017 and December 31, 2017, the Unitil subsidiaries had deposited $3.3 million, $2.6 million and $2.9 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of March 31, 2018, March 31, 2017 and December 31, 2017.

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##### Table of Contents

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.

The Allowance for Doubtful Accounts as of March 31, 2018, March 31, 2017 and December 31, 2017, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions) |  |  |
|  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
Allowance for Doubtful Accounts |  | $ | 1.6 |  |  | $ | 1.0 |  |  | $ | 1.6 |

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of March 31, 2018, March 31, 2017 and December 31, 2017.

|  | March 31, |  |  | December 31, |
Accrued Revenue ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Regulatory Assets – Current |  | $ | 34.6 |  |  | $ | 32.0 |  |  | $ | 39.5 |
Unbilled Revenues |  |  | 10.5 |  |  |  | 9.3 |  |  |  | 13.8 |
Total Accrued Revenue |  | $ | 45.1 |  |  | $ | 41.3 |  |  | $ | 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 March 31, 2018, March 31, 2017 and December 31, 2017.

|  | March 31, |  |  | December 31, |
Exchange Gas Receivable ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Northern Utilities |  | $ | — |  |  | $ | 1.9 |  |  | $ | 5.4 |
Fitchburg |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.4 |
Total Exchange Gas Receivable |  | $ | 0.2 |  |  | $ | 2.1 |  |  | $ | 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 March 31, 2018, March 31, 2017 and December 31, 2017.

|  | March 31, |  |  | December 31, |
Gas Inventory ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Natural Gas |  | $ | — |  |  | $ | — |  |  | $ | 0.4 |
Propane |  |  | 0.3 |  |  |  | 0.2 |  |  |  | 0.1 |
Liquefied Natural Gas & Other |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.1 |
Total Gas Inventory |  | $ | 0.4 |  |  | $ | 0.3 |  |  | $ | 0.6 |

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At March 31, 2018, March 31, 2017 and December 31, 2017, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $86.6 million, $79.7 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.

|  | March 31, |  |  | December 31, |
Regulatory Assets consist of the following ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Retirement Benefits |  | $ | 85.4 |  |  | $ | 75.7 |  |  | $ | 84.5 |
Energy Supply & Other Rate Adjustment Mechanisms |  |  | 31.9 |  |  |  | 27.7 |  |  |  | 36.0 |
Deferred Storm Charges |  |  | 8.0 |  |  |  | 8.6 |  |  |  | 7.2 |
Environmental |  |  | 9.0 |  |  |  | 10.7 |  |  |  | 9.5 |
Income Taxes |  |  | 6.3 |  |  |  | 7.3 |  |  |  | 6.5 |
Other |  |  | 5.2 |  |  |  | 5.5 |  |  |  | 5.4 |
Total Regulatory Assets |  |  | 145.8 |  |  |  | 135.5 |  |  |  | 149.1 |
Less: Current Portion of Regulatory Assets(1) |  |  | 34.6 |  |  |  | 32.0 |  |  |  | 39.5 |
Regulatory Assets – noncurrent |  | $ | 111.2 |  |  | $ | 103.5 |  |  | $ | 109.6 |

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

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##### Table of Contents

|  | March 31, |  |  | December 31, |
Regulatory Liabilities consist of the following ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Rate Adjustment Mechanisms |  | $ | 10.3 |  |  | $ | 9.2 |  |  | $ | 6.9 |
Gas Pipeline Refund (Note 6) |  |  | 0.6 |  |  |  | 4.3 |  |  |  | 2.3 |
Income Taxes (Note 8) |  |  | 49.1 |  |  |  | — |  |  |  | 48.9 |
Total Regulatory Liabilities |  |  | 60.0 |  |  |  | 13.5 |  |  |  | 58.1 |
Less: Current Portion of Regulatory Liabilities |  |  | 10.9 |  |  |  | 12.8 |  |  |  | 9.2 |
Regulatory Liabilities – noncurrent |  | $ | 49.1 |  |  | $ | 0.7 |  |  | $ | 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 March 31, 2018 are $0.5 million of deferred storm charges to be recovered over the year and $6.5 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material 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, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.

The Company has managed a regulatory approved hedging program for Northern Utilities, which is designed to fix or cap a portion of its gas supply costs for the coming years of service through the purchase of European call option contracts. Any gains or losses resulting from these option contracts are passed through to customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is 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 records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause. Currently, there are no active transactions and the Company has proposed to regulators to discontinue the program. This matter remains pending.

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As of March 31, 2018, March 31, 2017 and December 31, 2017 the Company had zero, 1.2 billion and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

As of March 31, 2018 and March 31, 2017 and December 31, 2017, the Company’s derivatives that are not designated as hedging instruments under FASB ASC 815-20 have a fair value of $0, $0.3 million and less than $0.1 million, respectively.

Investments in Marketable Securities – The Company has a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 9.

At March 31, 2018, March 31, 2017 and December 31, 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 $5.1 million, $3.3 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.

|  | March 31, |  |  | December 31, |
Fair Value of Marketable Securities ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Equity Funds |  | $ | 1.9 |  |  | $ | 1.1 |  |  | $ | 2.1 |
Fixed Income Funds |  |  | 1.6 |  |  |  | 0.9 |  |  |  | 1.5 |
Cash and Equivalents |  |  | 1.6 |  |  |  | 1.3 |  |  |  | — |
Total Marketable Securities |  | $ | 5.1 |  |  | $ | 3.3 |  |  | $ | 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.

|  | March 31, |  |  | December 31, |
Energy Supply Obligations ($ millions) |  | 2018 |  |  | 2017 |  |  | 2017 |
Current: |  |  |  |  |  |  |  |  |  |  |  |
Exchange Gas Obligation |  | $ | — |  |  | $ | 1.9 |  |  | $ | 5.4 |
Renewable Energy Portfolio Standards |  |  | 7.5 |  |  |  | 6.8 |  |  |  | 4.0 |
Power Supply Contract Divestitures |  |  | 0.3 |  |  |  | 0.3 |  |  |  | 0.3 |
Total Energy Supply Obligations – Current |  |  | 7.8 |  |  |  | 9.0 |  |  |  | 9.7 |
Long-Term: |  |  |  |  |  |  |  |  |  |  |  |
Power Supply Contract Divestitures |  |  | 0.8 |  |  |  | 1.2 |  |  |  | 0.9 |
Total Energy Supply Obligations |  | $ | 8.6 |  |  | $ | 10.2 |  |  | $ | 10.6 |

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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 electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are operating. A recent round of long-term renewable energy procurements was conducted during 2016 and several contracts were finalized and submitted to MDPU for approval in 2017. These approvals remain pending. Additional procurements are expected in compliance with the Act to Promote Energy Diversity (2016). 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).

Recently Issued Pronouncements – 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.

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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 February 2016, the FASB issued ASU 2016-02, Leases, Topic 842, which amends the existing guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. In November 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for the Company on January 1, 2019, with early adoption permitted. The Company plans to adopt this guidance in the first quarter of 2019. The Company expects this ASU to increase lease assets and lease liabilities on the Consolidated Balance Sheets and does not expect the guidance will have a material impact on the Consolidated Statements of Income, Statements of Cash Flows and lease disclosures.

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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NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration Date |  | Date Paid (Payable) |  | Shareholder of Record Date |  | Dividend Amount
04/25/18 |  | 05/29/18 |  | 05/15/18 |  | $0.365
01/30/18 |  | 02/28/18 |  | 02/14/18 |  | $0.365
10/25/17 |  | 11/29/17 |  | 11/15/17 |  | $0.360
07/26/17 |  | 08/29/17 |  | 08/15/17 |  | $0.360
04/26/17 |  | 05/30/17 |  | 05/16/17 |  | $0.360
01/25/17 |  | 02/28/17 |  | 02/14/17 |  | $0.360

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three months ended March 31, 2018 and March 31, 2017:

|  | Gas |  |  | Electric |  |  | Non- Regulated |  |  | Other |  |  | Total |
Three Months Ended March 31, 2018 ($ millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Billed and Unbilled Revenue |  | $ | 91.4 |  |  | $ | 61.6 |  |  | $ | — |  |  | $ | — |  |  | $ | 153.0 |
Rate Adjustment Mechanism Revenue |  |  | (4.4 | ) |  |  | (4.1 | ) |  |  | — |  |  |  | — |  |  |  | (8.5 | )
Other Operating Revenue – Non-Regulated |  |  | — |  |  |  | — |  |  |  | 1.3 |  |  |  | — |  |  |  | 1.3 |
Total Operating Revenues |  | $ | 87.0 |  |  | $ | 57.5 |  |  | $ | 1.3 |  |  | $ | — |  |  | $ | 145.8 |
Segment Profit (Loss) |  |  | 12.6 |  |  |  | 3.0 |  |  |  | 0.4 |  |  |  | (0.4 | ) |  |  | 15.6 |
Identifiable Segment Assets |  |  | 712.6 |  |  |  | 481.8 |  |  |  | 7.1 |  |  |  | 42.8 |  |  |  | 1,244.3 |
Capital Expenditures |  |  | 3.6 |  |  |  | 6.0 |  |  |  | — |  |  |  | 0.5 |  |  |  | 10.1 |
Three Months Ended March 31, 2017 ($ millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 74.8 |  |  | $ | 49.5 |  |  | $ | 1.7 |  |  | $ | — |  |  | $ | 126.0 |
Segment Profit |  |  | 9.9 |  |  |  | 2.1 |  |  |  | 0.4 |  |  |  | — |  |  |  | 12.4 |
Identifiable Segment Assets |  |  | 641.8 |  |  |  | 442.8 |  |  |  | 7.0 |  |  |  | 42.8 |  |  |  | 1,134.4 |
Capital Expenditures |  |  | 5.7 |  |  |  | 8.3 |  |  |  | — |  |  |  | 3.5 |  |  |  | 17.5 |
As of December 31, 2017 ($ millions) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Identifiable Segment Assets |  | $ | 714.3 |  |  | $ | 476.9 |  |  | $ | 6.7 |  |  | $ | 44.0 |  |  | $ | 1,241.9 |

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NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

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

($ millions) |  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
Unitil Corporation: |  |  |  |  |  |  |  |  |  |  |  |
6.33% Senior Notes, Due May 1, 2022 |  | $ | 20.0 |  |  | $ | 20.0 |  |  | $ | 20.0 |
3.70% Senior Notes, Due August 1, 2026 |  |  | 30.0 |  |  |  | 30.0 |  |  |  | 30.0 |
Unitil Energy First Mortgage Bonds: |  |  |  |  |  |  |  |  |  |  |  |
5.24% Senior Secured Notes, Due March 2, 2020 |  |  | 10.0 |  |  |  | 15.0 |  |  |  | 15.0 |
8.49% Senior Secured Notes, Due October 14, 2024 |  |  | 7.5 |  |  |  | 9.0 |  |  |  | 7.5 |
6.96% Senior Secured Notes, Due September 1, 2028 |  |  | 20.0 |  |  |  | 20.0 |  |  |  | 20.0 |
8.00% Senior Secured Notes, Due May 1, 2031 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
6.32% Senior Secured Notes, Due September 15, 2036 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
Fitchburg: |  |  |  |  |  |  |  |  |  |  |  |
6.75% Senior Notes, Due November 30, 2023 |  |  | 7.6 |  |  |  | 9.5 |  |  |  | 7.6 |
6.79% Senior Notes, Due October 15, 2025 |  |  | 10.0 |  |  |  | 10.0 |  |  |  | 10.0 |
3.52% Senior Notes, Due November 1, 2027 |  |  | 10.0 |  |  |  | — |  |  |  | 10.0 |
7.37% Senior Notes, Due January 15, 2029 |  |  | 12.0 |  |  |  | 12.0 |  |  |  | 12.0 |
5.90% Senior Notes, Due December 15, 2030 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
7.98% Senior Notes, Due June 1, 2031 |  |  | 14.0 |  |  |  | 14.0 |  |  |  | 14.0 |
4.32% Senior Notes, Due November 1, 2047 |  |  | 15.0 |  |  |  | — |  |  |  | 15.0 |
Northern Utilities: |  |  |  |  |  |  |  |  |  |  |  |
6.95% Senior Notes, Due December 3, 2018 |  |  | 10.0 |  |  |  | 20.0 |  |  |  | 10.0 |
5.29% Senior Notes, Due March 2, 2020 |  |  | 16.6 |  |  |  | 25.0 |  |  |  | 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 |  |  |  | 50.0 |
4.42% Senior Notes, Due October 15, 2044 |  |  | 50.0 |  |  |  | 50.0 |  |  |  | 50.0 |
4.32% Senior Notes, Due November 1, 2047 |  |  | 30.0 |  |  |  | — |  |  |  | 30.0 |
Granite State: |  |  |  |  |  |  |  |  |  |  |  |
7.15% Senior Notes, Due December 15, 2018 |  |  | 3.3 |  |  |  | 6.7 |  |  |  | 3.3 |
3.72% Senior Notes, Due November 1, 2027 |  |  | 15.0 |  |  |  | — |  |  |  | 15.0 |
Unitil Realty Corp.: |  |  |  |  |  |  |  |  |  |  |  |
8.00% Senior Secured Notes, Due Through August 1, 2017 |  |  | — |  |  |  | 0.2 |  |  |  | — |
Total Long-Term Debt |  |  | 396.0 |  |  |  | 336.4 |  |  |  | 409.4 |
Less: Unamortized Debt Issuance Costs |  |  | 3.2 |  |  |  | 2.9 |  |  |  | 3.3 |
Total Long-Term Debt, net of Unamortized Debt Issuance Costs |  |  | 392.8 |  |  |  | 333.5 |  |  |  | 406.1 |
Less: Current Portion |  |  | 29.8 |  |  |  | 30.0 |  |  |  | 29.8 |
Total Long-term Debt, Less Current Portion |  | $ | 363.0 |  |  | $ | 303.5 |  |  | $ | 376.3 |

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

($ millions) |  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
Estimated Fair Value of Long-Term Debt |  | $ | 428.0 |  |  | $ | 374.3 |  |  | $ | 457.1 |

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Facility”). The Credit Facility terminates October 4, 2020 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil 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 (LIBOR) plus 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $88.9 million for the three months ended March 31, 2018. Total gross repayments were $81.9 million for the three months ended March 31, 2017. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of March 31, 2018, March 31, 2017 and December 31, 2017:

|  | Revolving Credit Facility ($ millions) |
|  | March 31, |  |  | December 31, |
|  | 2018 |  |  | 2017 |  |  | 2017 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |  |  | $ | 120.0 |
Short-Term Borrowings Outstanding |  | $ | 45.3 |  |  | $ | 76.6 |  |  | $ | 38.3 |
Letters of Credit Outstanding |  | $ | 0.0 |  |  | $ | 1.1 |  |  | $ | 0.0 |
Available |  | $ | 74.7 |  |  | $ | 42.3 |  |  | $ | 81.7 |

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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 Corporation’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 until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At March 31, 2018, March 31, 2017 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 4.)

The weighted average interest rates on all short-term borrowings and intercompany money pool transactions were 2.9% and 2.1% for the three months ended March 31, 2018 and March 31, 2017, respectively. The weighted average interest rate on all short-term borrowings for the twelve months ended December 31, 2017 was 2.4%.

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.

In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of March 31, 2018, there are $2.7 million of current and $4.4 million of noncurrent obligations under this capital lease on the Company’s 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.

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 $1.0 million, $3.8 million and $8.5 million of natural gas storage inventory at March 31, 2018, March 31, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2018 and payable in April 2018 is $1.0 million and is recorded in Accounts Payable at March 31, 2018. The amount of natural gas inventory released in March 2017 and payable in April 2017 was $2.0 million and was recorded in Accounts Payable at March 31, 2017. The amount of natural gas inventory released in December 2017 and payable in January 2018 was $3.1 million and was recorded in Accounts Payable at December 31, 2017.

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Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of March 31, 2018, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2018.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Granite State. As of March 31, 2018, the principal amount outstanding for the 7.15% Granite State notes was $3.3 million.

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 14,107,741, 14,815,585 and 14,860,123 shares of common stock outstanding at March 31, 2017, December 31, 2017 and March 31, 2018, respectively.

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 the first quarter of 2018, the Company sold 7,812 shares of its common stock, at an average price of $43.71 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $341,500. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

Stock Plan - The Company maintains the Unitil Corporation Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind

of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.

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Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an Award. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

On January 29, 2018, 37,510 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 90,882 and 94,880 non-vested shares under the Stock Plan as of March 31, 2018 and 2017, respectively. The weighted average grant date fair value of these shares was $41.93 and $39.55, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.8 million and $1.7 million for the three months ended March 31, 2018 and 2017, respectively. At March 31, 2018, there was approximately $1.3 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.8 years. During the three months ended March 31, 2018 there were 784 shares of Restricted Shares forfeited. There were no cancellations under the Stock Plan during the three months ended March 31, 2018.

Restricted Stock Units

Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the three months ended March 31, 2018 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion) |
|  | Units |  |  | Weighted Average Stock Price |
Restricted Stock Units as of December 31, 2017 |  |  | 52,224 |  |  | $ | 36.22 |
Restricted Stock Units Granted |  |  | — |  |  |  | — |
Dividend Equivalents Earned |  |  | 453 |  |  | $ | 42.04 |
Restricted Stock Units Settled |  |  | — |  |  |  | — |
Restricted Stock Units as of March 31, 2018 |  |  | 52,677 |  |  | $ | 36.27 |

There were 43,696 Restricted Stock Units outstanding as of March 31, 2017 with a weighted average stock price of $33.49. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of March 31, 2018, March 31, 2017 and December 31, 2017 is $1.0 million, $0.8 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.

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Preferred Stock

There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of March 31, 2018, March 31, 2017 and December 31, 2017. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three month periods ended March 31, 2018 and March 31, 2017, respectively.

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.

Tax Cuts and Jobs Act of 2017

At the end of December 2017, the United States Congress voted and the President signed into law major federal tax law changes Tax Cuts and Jobs Act of 2017 (TCJA) effective for tax year 2018. Among other things, the TCJA substantially reduces 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 or is in the process of issuing 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 is fully complying with these orders and will make any necessary changes to its rates as directed by the commissions. The FERC has opened a rulemaking proceeding on this matter (described below). The Company believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows.

In Maine, Northern Utilities’ Maine division has recently completed a base rate case (described more fully below). The MPUC had issued a procedural order indicating that the tax law changes were to be reflected in its calculation of final rates for the Company, and the final order in that docket incorporated the lower tax rates.

In New Hampshire, Northern Utilities’ New Hampshire division has a base rate case proceeding pending (described below), and the NHPUC issued an order directing the Company to show how the tax changes can be effected within the schedule for the rate case. On April 6, 2018, Northern Utilities filed a proposed comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which includes the effect of the tax changes in the calculation of the agreed upon revenue requirement. With respect to Unitil Energy, the NHPUC directed the Company to make a filing by April 1, 2018, showing the effect of the tax law changes on rates. On March 16, 2018, the Company filed for its annual step increase pursuant to the provisions of its last base rate case, and included in that filing proposed adjustments to account for the tax changes. This proposal remains pending.

In Massachusetts, the Attorney General filed a petition with the MDPU requesting that it open an investigation to require the flow-through of the tax law changes in rates for all utilities subject to the MDPU’s jurisdiction. On February 2, 2018 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. The MDPU consolidated the Attorney General’s petition into its investigation. In its order, the MDPU required each utility company subject to its jurisdiction to file, by May 1, 2018, a proposal to address the effects of the TCJA and to reduce its rates through the establishment of a revised cost of service incorporating the lower federal corporate income tax rate as of January 1, 2018. Such proposals must address the adjustment of rates going forward

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and also incorporate the timely refund of revenues associated with the lower tax expense on current income and excess accumulated deferred income taxes (ADIT). Fitchburg plans to submit filings for both its gas and electric divisions with estimated revenue reductions of $0.8 million at each respective division. This matter remains pending.

On March 15, 2018, the FERC issued a Notice of Proposed Rulemaking (NOPR) that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax rate reduction and changes to the FERC’s income tax allowance policies. The proposed rule, if adopted, would require an interstate pipeline to file a one-time report on the regulated rate effect of the new tax law and changes to the FERC’s income tax allowance policies. In addition to filing the one-time report, each pipeline would have four options: 1) make a limited rate filing to reduce its rates by the percentage reduction in its cost of service shown in its report; 2) commit to file either a prepackaged uncontested rate settlement or a general rate case by December 31, 2018; 3) file a statement explaining why it believes its current rates are reasonable and no reduction is necessary; or 4) file the required report without taking any other action, at which point FERC would consider whether to initiate an investigation. Granite State is reviewing the NOPR and will comply with all FERC requirements. Granite State believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows.

Rate Case Activity

Unitil Energy – Base Rates – On April 20, 2017 the NHPUC issued its final order approving a settlement between Unitil Energy, NHPUC Staff and the Office of Consumer Advocate providing for 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 as defined under the rate plan. On March 16, 2018, Unitil Energy filed its second step adjustment. The filing also incorporated the revenue requirement effect of the federal tax decrease pursuant to the TCJA, along with the termination of the one-year reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments results in a proposed revenue decrease of $0.4 million. The proposal remains pending.

Fitchburg – Base Rates – Electric – On April 29, 2016 the MDPU issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. As part of its order, the MDPU approved, with modifications, Fitchburg’s request for an annual capital cost recovery mechanism, which allows for increases to target revenues to recover the revenue requirement associated with capital additions as defined under the mechanism. In 2016, Fitchburg filed its first compliance report on capital investments for calendar year 2015. The MDPU approved the recovery of approximately $0.5 million, effective January 1, 2017, subject to further investigation and reconciliation. On December 18, 2017, the MDPU approved Fitchburg’s calendar year 2015 capital investments and associated revenue requirements for recovery. On June 29, 2017, Fitchburg filed its compliance report on capital investments for calendar year 2016. On December 20, 2017, the MDPU approved the recovery of approximately $0.4 million, effective January 1, 2018, subject to further investigation and reconciliation.

Fitchburg – Base Rates – Gas – On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg – Gas Operations – On October 31, 2016, Fitchburg submitted its annual filing under its gas system enhancement program to recover the revenue requirements associated with its projected capital additions in 2017 as defined under the program. The filing sought approval to collect an additional $0.9 million of annual revenue requirements. On April 28, 2017, the MDPU

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approved recovery of the projected 2017 revenue requirements, subject to reconciliation and a cap of 1.5% on the change in revenue requirement to be billed in any given year. The cap resulted in approval of an additional $0.5 million of annual revenue requirements to be billed effective May 1, 2017 with the remaining $0.4 million of annual revenue requirements deferred for billing in future periods. In its April 28, 2017 annual reconciliation filing for 2016 revenue requirements, the Company requested that the MDPU waive the 1.5% revenue requirement cap. On October 31, 2017, the MDPU approved a one-year waiver of the cap and allowed the Company to bill the total 2016 actual reconciliation balance. On October 31, 2017, Fitchburg submitted its annual filing under the program to recover the revenue requirements associated with its projected capital additions in 2018. In this filing, the Company has requested to change the revenue requirements cap to 3%. This matter remains pending.

Northern Utilities – Base Rates – Maine – In May 2017, Northern Utilities filed a base rate case with the MPUC seeking to increase annual revenues by $6.0 million. The requested increase was subsequently supplemented by an additional $0.7 million associated with the Company’s Targeted Area Build-out (TAB) Program (see below). In addition to the distribution base rate increase, Northern Utilities requested to extend its Targeted Infrastructure Replacement Adjustment mechanism (TIRA) (see below).

On February 28, 2018 the MPUC issued its Final Order (Order) in the base rate case. The Order provides for a revenue increase of $2.1 million offset by a revenue decrease of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA, resulting in an overall annual revenue decrease of $0.1 million. The MPUC 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. The Order addresses a number of other issues including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s TAB Program and TIRA mechanism. The new rates and other changes became effective as of March 1, 2018. On March 16, 2018, the Company filed a Motion for Clarification requesting the MPUC clarify its Order in light of what the Company believes to be an inadvertent inconsistency with the Order regarding 2016 TIRA Eligible Facilities, rate base and related annual revenue adjustments.

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 Company’s TIRA mechanism, with revision, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On March 30, 2018, the Company filed its request to increase its annual base rates to recover the revenue requirements for 2017 Eligible Facilities. This matter remains pending.

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

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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 (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 June 5, 2017, Northern Utilities filed for a base rate increase with the NHPUC seeking to increase annual revenues by $4.7 million. On June 15, 2017, the NHPUC suspended the Company’s proposed permanent rates tariffs while the filing is under regulatory review

Northern Utilities reached a settlement agreement on temporary rates to produce an increase in annual revenues of approximately $1.6 million, effective with service rendered on and after August 1, 2017, and until a final, non-appealable order on permanent rates is issued. The settlement agreement was approved by the NHPUC on July 31, 2017. As of March 31, 2018, Northern Utilities has deferred approximately $1.1 million of costs associated with this base rate case. Once a final decision on permanent rates is issued, it will be reconciled back to the date that temporary rates were implemented.

On April 6, 2018, Northern Utilities filed a proposed comprehensive settlement agreement among the Company, the NHPUC Staff and the Office of the Consumer Advocate. The settling parties agreed to an annual revenue increase of $2.6 million and an offsetting decrease of $1.7 million to reflect the effect of the TCJA, for a net annual revenue increase of $0.9 million, effective May 1, 2018. The parties also agreed to a step increase of $2.3 million to recover post-test year capital investments, also effective May 1, 2018. 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 shall be based on an historic test year of no earlier than twelve months ending December 31, 2020. A hearing before the NHPUC to consider the settlement agreement was held on April 12, 2018. This matter remains pending.

Northern Utilities – Pipeline Refund – On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers over three years as directed by the NHPUC and MPUC. As of March 31, 2018, $21.4 million has been refunded to Northern Utilities’ customers and marketers. The Company has recorded current Regulatory Liabilities related to these refunds of $0.6 million on its Consolidated Balance Sheets as of March 31, 2018.

Granite State – Base Rates – Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cap on expenditures. On June 21, 2017 Granite State filed for an annual revenue increase under this provision of $0.2 million, effective August 1, 2017. The FERC issued an order approving the filing on July 28, 2017. This is the last annual rate adjustment allowed under the second amended settlement because Granite must file a general rate case pursuant to Section 4 of the Natural Gas Act by April 30, 2018 with rates effective no later than November 1, 2018.

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding – In May 2015, the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard (“EERS”), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and

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gas utilities must meet. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Settlement, on September 1, 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plan for the period 2018-2020. The Settlement and the Statewide Energy Efficiency Plan for the period 2018-2020 were approved on January 2, 2018.

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.

Fitchburg – Electric Operations – On November 1, 2017, Fitchburg submitted its 2017 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were given final approval by the MDPU on December 28, 2017, effective January 1, 2018.

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. These filings are pending approval.

Fitchburg – Solar Generation – On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts, including a cost recovery mechanism to share the costs and benefits of the project among all Fitchburg customers. On November 9, 2016, the MDPU approved a Settlement Agreement supporting the proposal, which was reached among the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. 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 seeks a net amount of approximately $300,000 for recovery effective June 1, 2018.

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Fitchburg – Energy Diversity – Governor Baker signed into law H4568 “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 and contract negotiation is underway. 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.

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. This matter remains pending.

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. This filing remains pending. In the interim, the current program for solar renewable energy credits, known as SREC-II, remains in effect for all eligible solar facilities.

On May 11, 2016, the MDPU issued an Order commencing a rulemaking proceeding to adopt emergency regulations amending 220 C.M.R. § 18.00 et seq. (“Net Metering Regulations”). Specifically, the MDPU amended its Net Metering Regulations to implement the net metering provisions of An Act Relative to Solar Energy, St. 2016, c. 75, §§ 3-9, and to make additional clerical changes to the Net Metering Regulations. On July 15, 2016, the MDPU issued an order approving Final Net Metering Regulations. Fitchburg’s tariff, filed in compliance with the new regulations, was approved on February 7, 2017.

In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the

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MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP is a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filings are currently under MDPU review and remain pending.

On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its Energy Efficiency Surcharge; and found that each Program Administrator’s Three-Year Plan is consistent with the Green Communities Act, the Guidelines, and Department precedent.

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 these formula rates, 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. 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 (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks 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

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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 remain pending. The Company continues to believe these claims are without merit and will continue to defend itself vigorously.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.

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 March 31, 2018, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we 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 (ME DEP) and New Hampshire Department of Environmental Services (NH DES) 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. Supplemental remediation at the Exeter and Somersworth MGP sites commenced in the second quarter of 2018 with anticipated completions by the third quarter of 2018.

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.

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The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are 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 three months ended March 31, 2018 and 2017.

Environmental Obligations |  |  |  |  |  |  |  |  |  |  |  |
|  | ($ millions) |
|  | Fitchburg |  |  | Northern Utilities |  |  | Total |
|  | Three months ended March 31, |
|  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Total Balance at Beginning of Period |  | $ | 0.1 |  |  | $ | 0.1 |  |  | $ | 2.0 |  |  | $ | 1.9 |  |  | $ | 2.1 |  |  | $ | 2.0 |
Additions |  |  | 0.1 |  |  |  | — |  |  |  | 0.1 |  |  |  | 0.4 |  |  |  | 0.2 |  |  |  | 0.4 |
Less: Payments / Reductions |  |  | 0.1 |  |  |  | — |  |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.1 |
Total Balance at End of Period |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 2.0 |  |  |  | 2.2 |  |  |  | 2.1 |  |  |  | 2.3 |
Less: Current Portion |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.5 |  |  |  | 0.4 |  |  |  | 0.6 |  |  |  | 0.5 |
Noncurrent Balance at End of Period |  | $ | — |  |  | $ | — |  |  | $ | 1.5 |  |  | $ | 1.8 |  |  | $ | 1.5 |  |  | $ | 1.8 |

NOTE 8: INCOME TAXES

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 reasonable estimates to reflect the impacts of the Tax Act and recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation.

On March 15, 2018; FERC issued its Notice of Proposed Rulemaking in Docket No. RM18-11-000 in which FERC provided specific guidance on the flow back of excess ADIT: The amount of the reduction to ADIT that was 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. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of the excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA.

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 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. The Company’s regulators and the IRS are each expected to issue 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 the TCJA and regulatory decisions may change the amounts estimated.

In addition to the excess $47.1 million ADIT amounts the Company expects to flow back to customers in future utility rates, as noted above, there was $1.8 million of excess ADIT at December 31, 2017, which had not been previously included in customers’ utility rates. During 2018, the Company determined that since this excess ADIT had not been previously collected from utility customers; it would, therefore, not be subject to flow back to customers in future rates. The Company will recognize a nonrecurring benefit in its tax provision as the underlying book/tax temporary differences reverse in the current and future periods.

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The Company filed its tax returns for the year ended December 31, 2016 with the Internal Revenue Service in September 2017 and generated additional federal net operating loss carryforward (NOLC) assets principally due to current tax repair deductions, tax depreciation and research and development deductions. In 2016, the Company recorded a benefit of approximately $0.7 million for New Hampshire business enterprise tax credits utilized in filing the Company’s 2015 tax returns. For the year ended December 31, 2017, the Company decreased its federal NOLC $1.1 million in the calculation of its provisions for income taxes for the period and revalued the NOLC by $10.1 million for federal rate of 21% enacted in the TCJA.

As of December 31, 2017, the Company had recorded cumulative federal and state NOLC assets of $12.7 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 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, 2014; December 31, 2015; and December 31, 2016. Income tax filings for the year ended December 31, 2016 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 March 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, 2014; December 31, 2015; and December 31, 2016.

The Company bills its customers for 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 unaudited Consolidated Statements of Earnings.

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2017 as filed with the SEC on February 1, 2018 for additional information regarding these plans.

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

|  | 2018 |  |  | 2017 |
Used to Determine Plan Costs |  |  |  |  |  |  |  |
Discount Rate |  |  | 3.60 | % |  |  | 4.10 | %
Rate of Compensation Increase |  |  | 3.00 | % |  |  | 3.00 | %
Expected Long-term rate of return on plan assets |  |  | 7.75 | % |  |  | 7.75 | %
Health Care Cost Trend Rate Assumed for Next Year |  |  | 7.50 | % |  |  | 8.00 | %
Ultimate Health Care Cost Trend Rate |  |  | 4.50 | % |  |  | 4.00 | %
Year that Ultimate Health Care Cost Trend Rate is reached |  |  | 2024 |  |  |  | 2025 |

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

|  | Pension Plan |  |  | PBOP Plan |  |  | SERP |
Three Months Ended March 31, |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Service Cost |  | $ | 848 |  |  | $ | 824 |  |  | $ | 733 |  |  | $ | 744 |  |  | $ | 122 |  |  | $ | 115 |
Interest Cost |  |  | 1,469 |  |  |  | 1,514 |  |  |  | 851 |  |  |  | 978 |  |  |  | 101 |  |  |  | 98 |
Expected Return on Plan Assets |  |  | (1,946 | ) |  |  | (1,819 | ) |  |  | (409 | ) |  |  | (337 | ) |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 81 |  |  |  | 66 |  |  |  | 327 |  |  |  | 350 |  |  |  | 47 |  |  |  | 47 |
Actuarial Loss Amortization |  |  | 1,447 |  |  |  | 1,176 |  |  |  | 346 |  |  |  | 524 |  |  |  | 122 |  |  |  | 74 |
Sub-total |  |  | 1,899 |  |  |  | 1,761 |  |  |  | 1,848 |  |  |  | 2,259 |  |  |  | 392 |  |  |  | 334 |
Amounts Capitalized and Deferred |  |  | (720 | ) |  |  | (662 | ) |  |  | (742 | ) |  |  | (1,037 | ) |  |  | (113 | ) |  |  | (99 | )
Net Periodic Benefit Cost Recognized |  | $ | 1,179 |  |  | $ | 1,099 |  |  | $ | 1,106 |  |  | $ | 1,222 |  |  | $ | 279 |  |  | $ | 235 |

Employer Contributions

As of March 31, 2018, the Company had made $1.2 million and $1.0 million of contributions to its Pension Plan and PBOP Plan, respectively, in 2018. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2018 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of March 31, 2018, the Company had made $43,900 of benefit payments under the SERP Plan in 2018. The Company presently anticipates making an additional $356,300 of benefit payments under the SERP Plan in 2018.

Item 3. | Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. | Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of March 31, 2018. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of March 31, 2018 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

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There have been no changes in the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) during the fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. | Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 6 and 7 to the unaudited Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

Item 1A. | Risk Factors

There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2017 as filed with the SEC on February 1, 2018.

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

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company during the fiscal quarter ended March 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 by the Company on May 1, 2017, 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 $85,000 in value of shares have been purchased or, if sooner, on May 1, 2018.

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 March 31, 2018.

|  | 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 |
1/1/18 – 1/31/18 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 7,039 |
2/1/18 – 2/28/18 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 7,039 |
3/1/18 – 3/31/18 |  |  | 122 |  |  | $ | 42.48 |  |  |  | 122 |  |  | $ | 1,856 |
Total |  |  | 122 |  |  | $ | 42.48 |  |  |  | 122 |  |  |  |  |

Item 5. | Other Information

On April 26, 2018, the Company issued a press release announcing its results of operations for the three-month period ended March 31, 2018. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

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Item 6. | Exhibits

(a) | Exhibits

Exhibit No. |  | Description of Exhibit |  | Reference
10.1 |  | 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)
11 |  | Computation in Support of Earnings Per Average Common Share |  | Filed herewith
31.1 |  | Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  | Filed herewith
31.2 |  | Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  | Filed herewith
31.3 |  | Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |  | Filed herewith
32.1 |  | Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |  | Filed herewith
99.1 |  | Unitil Corporation Press Release Dated April 26, 2018 Announcing Earnings For the Quarter Ended March 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

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SIGNATURES

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

|  | UNITIL CORPORATION
|  | (Registrant)
Date: April 26, 2018 |  | /s/ Mark H. Collin
|  | Mark H. Collin
|  | Chief Financial Officer
Date: April 26, 2018 |  | /s/ Laurence M. Brock
|  | Laurence M. Brock
|  | Chief Accounting Officer

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