UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM10-Q

QUARTERLY REPORT PURSUANT TOUNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended March 31,September 30, 2018

Commission File Number1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

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 RegulationS-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, anon-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule12b-2 of the Exchange Act.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule12b-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.

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM10-Q

For the Quarter Ended March 31,September 30, 2018

Table of Contents

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:

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 territoryareas in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

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.

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$1,022.3 million at March 31,September 30, 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 conductsnon-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��sUnitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

RATES AND REGULATION

Regulation

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

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

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

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

Tax Cuts and Jobs Act of 2017

At the end ofOn December 22, 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.was signed into law. Among other things, the TCJA substantially reducesreduced 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 issuingissued 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 complyinghas complied with these orders and will make any necessaryhas made the required changes to its rates as directed by the commissions. The FERC has also opened a rulemaking proceeding on this matter which has been addressed in a rate settlement filing by Granite State (described below). The Company believes that the ultimate resolution of these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.

In Maine, Northern Utilities’ Maine division 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 theMPUC’s final order in that docket incorporated the lower tax rates.rates in the calculation of rates for the Company.

InSimilarly, in New Hampshire, Northern Utilities’ New Hampshire division hasrecently completed a base rate case proceeding pending (described below), and the NHPUC issued an. The NHPUC’s final 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 filedin that docket approved a proposed comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which includesincluded the effect of the tax changes in the calculation of the agreed upon revenue requirement. With respect to Unitil Energy, on April 30, 2018 the NHPUC directedapproved 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 itsCompany’s annual step increase pursuant to the provisions of its last base rate case, andwhich included in that filing proposed adjustments to account for the TCJA’s income 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 MDPUutilities, and required each utility company subject to its jurisdiction to file, by May 1, 2018, a proposalsubmit proposals 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 addressThe MDPU consolidated an earlier petition filed by the adjustmentAttorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of 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 ofby $0.8 million at each respective division. This matter remainseach. The MDPU will address the refund of excess accumulated deferred income taxes in phase two of its investigation. An order is pending.

On March 15,May 2, 2018, Granite State filed an uncontested rate settlement with FERC which accounted for the effects of the TCJA in its rates. The settlement was approved by FERC on June 27, 2018, and complies with and satisfies the FERC issued a Notice of Proposed Rulemaking (NOPR) that would allow it to determine which pipelines underconcerning the Natural Gas Act may be collecting unjustjustness and unreasonablereasonableness of 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 onreduction under the regulated rate effect of the new tax law and changes to the FERC’s income tax allowance policies. In addition to filing theone-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.TCJA.

Base 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 forapproved 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 underexpenditures. On April 30, 2018, the rate plan. On March 16, 2018,NHPUC approved Unitil Energy filed itsEnergy’s second step adjustment.adjustment filing. The filing also incorporated the revenue requirement of $3.3 million for 2017 plant additions, a reduction of $2.2 million for the effect of the federal tax decrease pursuant to the TCJA, along with the termination of theone-year $1.4 million reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments resultsresulted in a proposed revenue decrease of $0.4$0.3 million. The proposal remains pending.

Fitchburg – Base Rates – Electric –Fitchburg’s last base rate order from the MDPU, issued in April 2016, included the approval of an annual capital cost recovery mechanism to recover the revenue requirement associated with certain capital additions. While a number of the capital cost recovery filings may remain pending fromyear-to-year in any given year, the Company considers these to be routine regulatory proceedings and there are no material issues outstanding. On April 29, 2016June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017. This matter remains pending.

Fitchburg – Electric Grid Modernization –On May 10, 2018, the MDPU issued an order approving a $2.1 million increasethree year grid modernization investment plan for Fitchburg for the period 2018 through 2020 with a spending cap of $4.4 million. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies in Fitchburg’s electric base revenue decoupling target, effective MayMassachusetts jointly filed compliance filings in August 2018 including 1) revised proposed performance metrics designed to addresspre-authorized grid-facing investments, 2) a proposed evaluation plan for the three-year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Approval of these filings is pending. The next three year investment plan is due July 1, 2016. As part of its order,2020 for the period 2021 through 2023, and is required to include a five year strategic plan for 2021 – 2025.

Fitchburg – Solar Generation –On November 9, 2016, the MDPU approved with modifications, Fitchburg’s request for anpetition to develop a 1.3 MW solar generation facility located on Company property in Fitchburg Massachusetts. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the Company recovers its annual capital cost recovery mechanism, which allows for increases to target revenues to recover the revenue requirement associated with capital additions as defined underrelated to its investment in the mechanism. In 2016, Fitchburg filed its first compliance report on capital investmentssolar generation facility. The filing sought a net amount of approximately $0.3 million for calendar year 2015.recovery effective June 1, 2018. The MDPU approved the recovery of approximately $0.5 million, effective January 1, 2017,this amount in rates was approved by the MDPU on May 31, 2018, 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.A final order is pending.

Fitchburg – Base Rates – Gas –On April 29, 2016,Pursuant to the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas baseCompany’s revenue decoupling adjustment clause tariff, as approved in its last base rate case, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target effective May 1, 2016.in order to mitigate economic, weather and energy efficiency impacts to the Company’s revenues. The MDPU has consistently found that the Company’s filings are in accord with its approved tariffs, applicable law and precedent, and that they result in just and reasonable rates.

Fitchburg – Gas OperationsSystem Enhancement Program –OnPursuant to statute and MDPU order, Fitchburg has an approved Gas System Enhancement Plan (GSEP) tariff through which it may recover certain gas infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October 31, 2016, Fitchburg31; and a filing, submitted its annual filing under its gas system enhancement program to recoveron or before May 1, of final project documentation for projects completed during the revenue requirements associatedprior year, demonstrating substantial compliance with its projected capital additionsplan in 2017 as definedeffect for that year and showing that project costs were reasonably and prudently incurred. While a number of the filings 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 billedGSEP tariff may remain pending fromyear-to-year in any given year. The cap resulted in approval of an additional $0.5 million of annual revenue requirementsyear, the Company considers these to be billed effectiveroutine regulatory proceedings and there are no material issues outstanding. Under this tariff, a revenue increase of $0.9 million went into effect on May 1, 2017 with2018, subject to 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 aone-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.reconciliation.

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 AreaBuild-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 theNorthern Utilities pending base rate case. The Order providesprovided for aan annual revenue increase of $2.1 million offset bybefore a revenue decreasereduction 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.TCJA. The MPUC Order approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense, reducing the Company’s annual operating costs by approximately $0.5 million. The Order addressesmillion, and addressed a number of other issues, including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s TABTargeted AreaBuild-out (TAB) Program and TIRATargeted Infrastructure Replacement Adjustment (TIRA) mechanism. The new rates and other changes became effective as ofon 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,adjustment, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On March 30,May 7, 2018, the Company filed itsMPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, to recover the revenue requirements for 2017 Eligible Facilities. This matter remains pending.eligible facilities.

Northern Utilities – Targeted AreaBuild-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)(described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.

Northern Utilities – Base Rates – New Hampshire –On June 5, 2017, Northern Utilities filed for a base rate increase withMay 2, 2018, 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 reachedapproved 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 toproviding for an annual revenue increase of $2.6 million, and an offsetting decreasea reduction of annual revenue 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 toand a step increase of $2.3 million to recover post-test year capital investments, alsoall effective May 1, 2018.2018 (with the revenue increase of $2.6 million reconciling to the date of temporary rates of August 1, 2017 and the revenue decrease for TCJA reconciling to January 1, 2018), for a net increase of approximately $3.2 million. Under the agreement, the companyCompany 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 companyCompany chooses the option to implement the second step increase, the next distribution base rate case shallwill 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 RefundFranchise Extensions – New Hampshire –On February 19, 2015,October 3, 2018, the FERC issued OpinionNo. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers.NHPUC granted Northern Utilities received a pipeline refundauthority to expand its previously limited franchise to provide natural gas service in the Towns of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be creditedKingston and Atkinson, New Hampshire to serve new industrial, commercial and residential customers. Northern Utilities’ customers and marketers over three years as directed byUtilities has also petitioned the NHPUC to extend its franchise into the Town of Epping, New Hampshire, where new commercial and MPUC. Asresidential developments present the Company with opportunities for growth. The franchise petition for service to the Town 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.Epping remains pending.

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, 2017May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for an annual revenue increase under this provisionno change in rates, and accounted for the effects of $0.2 million, effective August 1, 2017.a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC issued an order approvingon June 27, 2018, and complies with the filing on July 28, 2017. This isFERC Notice of Proposed Rulemaking concerning the last annual rate adjustment allowedjustness and reasonableness of rates in light of the corporate income tax reductions under the second amendedTCJA. The settlement becausealso provides that Granite mustState may not file a general (Section 4) rate case pursuantprior to Section 4 of the Natural Gas Act by April 30, 2018 with rates effective no later than November 1, 2018.2019.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended March 31,September 30, 2018 and March 31,September 30, 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

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 above, approximately 27% and 11% of the Company’s total annual electric and natural gas sales volumes, respectively, are decoupled and changes in sales to existing customers do not affect sales margin.

Earnings Overview

The Company’s Net Income was $15.6$2.8 million, or $1.06$0.19 per share, for the firstthird quarter of 2018, an increase of $3.2$0.5 million, in Net Income, and $0.18 in Earnings Per Share,or $0.03 per share, compared to the firstthird quarter of 2017. For the nine months ended September 30, 2018, the Company reported Net Income of $22.0 million, or $1.49 per share, an increase of $4.2 million, or $0.22 per share, compared to the same nine month period in 2017. The Company’sincreases in earnings in the first quarter of 2018 were driven by higher natural gas and electric sales margins, reflecting: customer growth, colder winterfavorable impacts of weather on unit sales and new distribution rates comparedrates. Also, earnings per share reflect a higher number of shares outstanding due to the first quarterissuance of 2017.690,000 common shares on December 14, 2017, discussed below in Note 5 to the Consolidated Financial Statements.

Natural gas sales margin was $39.9margins were $17.6 million and $80.4 million in the three and nine months ended March 31,September 30, 2018, an increaserespectively, increases of $1.9$0.8 million and $5.1 million, respectively, compared to the same periodperiods in 2017. Gas sales margin in the first quarternine months of 2018 was positively affected by colder weather and customer growth of $1.8 million and higher natural gas distribution ratesrevenues of $1.6$5.9 million, partially offset by lower revenuerevenues of $1.5$2.9 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reductionAs a result of the final base rate award in revenuesthe Company’s New Hampshire gas utility, the Company recognized concurrentnon-recurring adjustments to increase both Gas Operating Revenues and Operation and Maintenance (O&M) expenses by $1.2 million in the second quarter of 2018 to reconcile permanent rates and deferred costs to the temporary rates which were effective July 1, 2017. Gas margin in the first nine months of 2018 also reflects a lower provision for income taxes.the positive effect of colder winter weather and customer growth on sales volume of $2.1 million.

Natural gas therm sales decreased 2.9% and increased 9.5%5.5% in the three monthsand nine month periods ended March 31,September 30, 2018, respectively, compared to the same periods in 2017. The increase in gas therm sales in the Company’s service areas in the nine month period was driven by customer growth and a colder winter in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 10%9% more HDDHeating Degree Days (HDD) in the first quarternine months of 2018 compared to the same period in 2017. As of March 31,September 30, 2018, the number of total natural gas customers served has increased by 1,478 inapproximately 1,200 over the last twelve months.year.

Electric sales margin was $22.3margins were $25.9 million and $70.5 million in the three and nine months ended March 31,September 30, 2018, an increaserespectively, increases of $0.3$1.1 million and $0.4 million, respectively, compared to the same periodperiods in 2017. Electric sales margin in the first quarternine months of 2018 was positively affected by higher electric distribution ratesrevenues of $0.9 million as well as colder weather and customer growth of $0.2$2.5 million, partially offset by lower revenuerevenues of $0.8$2.1 million in 2018 to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reductionElectric sales margin in revenuesthe current period was also reflectspositively affected by warmer-than-average summer temperatures and customer growth of $1.4 million. These positive impacts on electric sales margin were partially offset by the absence in the current period of a lower provision for income taxes.one-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

Total electric kWhkilowatt-hour (kWh) sales increased 5.8%3.4% and 4.2%, respectively, in the three and nine month periods ended September 30, 2018 compared to the firstsame periods in 2017. The increase in the nine month period reflects customer growth, the favorable impacts of weather on unit sales and higher usage by industrial customers for production purposes. Based on weather data collected in the Company’s electric service areas, there were 48.7% more Cooling Degree Days (CDD) in the third quarter of 2018 compared to the same period in 2017. As of March 31,September 30, 2018, the number of total electric customers served has increased by 516approximately 575 over the last year.

O&M expenses decreased $0.5 million and increased $2.1 million for the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. The decrease in the last twelve months.three month period reflects lower professional fees of $0.5 million and lower labor costs of $0.3 million, partially offset by higher utility operating costs of $0.3 million. The increase in the nine month period reflects higher labor costs of $1.5 million and higher utility operating costs of $1.9 million, offset by lower professional fees of $1.3 million. The higher utility operating costs in the nine month period include anon-recurring temporary rate adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018, which was offset by a corresponding increase in gas revenue.

Operation

Depreciation and Maintenance (O&M) expensesAmortization expense increased $1.3$1.6 million and $2.2 million in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017. The changeThese increases reflect higher utility plant in O&M expenses reflects an increase in compensationservice and benefithigher amortization of information technology 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, reflectingpartially offset by lower amortization of deferred major storm costs partially offset by higher utility plant in service and amortization of information system and software costs.which were being amortized for recovery over multi-year periods.

Taxes Other Than Income Taxes increased $0.3$0.6 million and $0.9 million in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017, primarily reflecting higher local property taxestax rates on higher levels of utility plant assets in service.service and higher payroll taxes.

Interest Expense, net was essentially unchangedincreased $0.2 million and $0.8 million in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017, reflecting higher2017. These increases primarily reflect interest on long-term debt offset by lower net interest expense on net regulatory assets/liabilities and lowerhigher levels of short-termlong-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 higherpre-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, July 2018 and October 2018 meetings, the Unitil CorporationUnitil’s 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 and nine months ended March 31,September 30, 2018 is presented below.

Gas Sales, Revenues and Margin

Therm Sales –Unitil’s total therm sales of natural gas decreased 2.9% and increased 9.5%5.5% in the three monthsand nine month periods ended March 31,September 30, 2018, respectively, compared to the same periods in 2017. In the third quarter of 2018, sales to Residential and C&I customers decreased 10.7% and 2.0%, respectively, compared to the same period in 2017, reflecting increases of 13.3%warmer late summer and 8.3%early fall weather in 2018, partially offset by customer growth. For the nine months ended September 30, 2018, sales to Residential and CommercialC&I customers increased 7.2% and Industrial (C&I) customers, respectively.5.0%, respectively, compared to the same period in 2017. The increase in gas therm sales in the Company’s service areas in the nine month period was driven by customer growth and a 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%9% more HDD in the first quarternine months 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%2.0% in the first quarternine months of 2018 compared to the same period in 2017. As of March 31,September 30, 2018, the number of total natural gas customers served has increased by 1,478 inapproximately 1,200 over the last twelve months.year. As previously discussed, sales marginmargins derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) isare not sensitive to changes in gas therm sales.

The following table details total firm therm sales for the three and nine months ended March 31,September 30, 2018 and 2017, by major customer class:

Therm Sales (millions)
		Three Months Ended September 30,																Nine Months Ended September 30,
		2018				2017				Change				% Change				2018				2017				Change				% Change
Residential			2.5				2.8				(0.3	)			(10.7	%)			35.9				33.5				2.4				7.2	%
Commercial / Industrial			23.9				24.4				(0.5	)			(2.0	%)			132.3				126.0				6.3				5.0	%
Total			26.4				27.2				(0.8	)			(2.9	%)			168.2				159.5				8.7				5.5	%

Gas Operating Revenues and Sales Margin – – The following table details total Gas Operating Revenues and Sales Margin for the three and nine months ended March 31,September 30, 2018 and 2017:

The Company analyzes operating results using Gas Sales Margin, anon-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 $39.9margins were $17.6 million and $80.4 million in the three and nine months ended March 31,September 30, 2018, an increaserespectively, increases of $1.9$0.8 million and $5.1 million, respectively, compared to the same periodperiods in 2017. Gas sales margin in the firstthird quarter of 2018 was positively affected by colder weather and customer growth of $1.8 million and higher natural gas distribution ratesrevenues of $1.6$1.1 million, partially offset by lower revenue of $1.5$0.4 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 related to the TCJA also reflects a lower provision for income taxes.taxes in the period. Gas sales margin in the third quarter of 2018 also reflects the effect of customer growth on sales volume of $0.1 million.

Gas sales margin in the first nine months of 2018 was positively affected by higher natural gas distribution revenues of $5.9 million, partially offset by lower revenue of $2.9 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. As a result of the final base rate award in the Company’s New Hampshire gas utility, the Company recognized concurrentnon-recurring adjustments to increase both Gas Operating Revenues and O&M expenses by $1.2 million in the second quarter of 2018 to reconcile permanent rates and deferred costs to the temporary rates which were effective July 1, 2017. Gas margin in the first nine months of 2018 also reflects the positive effect of colder winter weather and customer growth on sales volume of $2.1 million.

The increase in Total Gas Operating Revenues of $12.2$0.6 million in the first quarterthree months ended September 30, 2018 compared to the same period in 2017 reflects higher natural gas distribution rates and customer growth, partially offset by lower natural gas sales volumes, lower revenue related to the TCJA, discussed above, and lower cost of gas sales, which are tracked and reconciled costs as a pass-through to customers. The increase in Total Gas Operating Revenues of $15.5 million in the nine months ended September 30, 2018 compared to the same period in 2017 reflects higher natural gas distribution rates, customer growth, higher natural gas sales volumes and higher cost of gas sales, which are tracked and reconciled costs that are passed through directlyas a pass-through 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%3.4% and 4.2%, respectively, in the three and nine month periods ended September 30, 2018 compared to the firstsame periods in 2017. In the third quarter of 2017. Sales2018, sales to Residential and C&I customers increased 7.0%9.2% and 4.9%decreased 0.4%, respectively, compared to the same period in 2017, reflecting warmer-than-average summer temperatures in 2018 and customer growth. For the nine months ended September 30, 2018, sales to Residential and C&I customers increased 6.3% and 2.7%, respectively, compared to the same period in 2017, reflecting customer growth, the favorable impacts of weather on unit sales and higher usage by industrial customers for production purposes. Based on weather data collected in the firstCompany’s electric service areas, there were 48.7% more CDD in the third quarter of 2018 compared to the same period in 2017 reflectingand 9.0% more HDD in the positive impactfirst nine months of colder weather, customer growth and higher usage by industrial customers for production purposes.2018 compared to the same period in 2017. As of March 31,September 30, 2018, the number of total electric customers served has increased by 516 inapproximately 575 over the last twelve months.year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.

The following table details total kWh sales for the three and nine months ended March 31,September 30, 2018 and 2017 by major customer class:

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three monthsand nine month periods ended March 31,September 30, 2018 and 2017:

The Company analyzes operating results using Electric Sales Margin, anon-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 $22.3margins were $25.9 million and $70.5 million in the three and nine months ended March 31,September 30, 2018, an increaserespectively, increases of $0.3$1.1 million and $0.4 million, respectively, compared to the same periodperiods in 2017. Electric sales margin in the firstthird quarter of 2018 was positively affected by higher electric distribution ratesrevenues of $0.9 million as well as colder weather and customer growth of $0.2$0.8 million, partially offset by lower revenue of $0.8$0.6 million in 2018 to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues related to the TCJA also reflects a lower provision for income taxes.taxes in the period. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth on sales volume of $0.9 million.

Electric sales margin in the first nine months of 2018 was positively affected by higher electric distribution revenues of $2.5 million, partially offset by lower revenues of $2.1 million in 2018 to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. Electric sales margin in the current period was also positively affected by warmer-than-average summer temperatures and customer growth of $1.4 million. These positive impacts on electric sales margin were partially offset by the absence in the current period of aone-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

The increase in Total Electric Operating Revenues of $8.0$3.9 million in the firstthird quarter of 2018 reflects higher electric sales volumesdistribution rates and higher cost of electric sales, which are tracked and reconciled to costs that are passed through directlyas a pass-through to customers, partially offset by lower revenuesrevenue related to the TCJA, discussed above.

The increase in Total Electric Operating Revenues of $13.2 million in the first nine months of 2018 reflects higher electric distribution rates and higher cost of electric sales, which are tracked and reconciled to costs as a pass-through to customers, partially offset by anon-recurring adjustment in the second quarter of 2017 to increase revenue by $1.4 million related to the completion of a base rate case and lower revenue related to the TCJA, discussed above.

Operating Revenue – Other

The following table details total Other Operating Revenue for the three and nine months ended March 31,September 30, 2018 and 2017:

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’snon-regulated energy brokering business, Usource,Usource. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from those suppliers under term contracts brokered by Usource.

Usource’s revenues decreased $0.4$0.3 million, or 23.5%21.4%, and $1.0 million, or 22.2%, in the first quarter ofthree and nine months ended June 30, 2018, respectively, compared to the first quarter ofsame periods in 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 ASU2015-14, ASU2016-08, ASU2016-10 and ASU2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018. ASU2014-09 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,in 2018 and going forward, payments made by Usource to third parties for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU2014-09, 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 ofand $0.3 million in the first quarters ofthree months ended September 30, 2018 and 2017.2017, respectively. Channel Partner payments were $0.8 million and $0.8 million in the nine months ended September 30, 2018 and 2017, respectively.

If ASU2014-09 had been in effect for the three and nine months ended March 31,September 30, 2017, the result would have been corresponding reductions of $0.3 million and $0.8 million, respectively, 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 $10.3decreased $0.2 million, or 28.0%2.4%, and increased $10.4 million, or 18.4%, in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017. ThisThe decrease in the three month period primarily reflects lower sales of natural gas and lower wholesale natural gas prices, partially offset by a decrease in the amount of natural gas purchased by customers directly from third-party suppliers. The increase in the nine month period reflects higher sales of natural gas and higher wholesale natural gas prices and higher sales of natural gas.prices. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

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$2.8 million, or 28.0%,8.6% and $12.8 million, or 15.2% in the three and nine months ended March 31,September 30, 2018 compared to the same periodperiods in 2017. ThisThe increase in the three month period reflects higher electric sales and a decrease in the amount of electricity purchased by customers directly from third-party suppliers. The increase in the nine month period reflects higher electric sales, higher wholesale electricity prices and higher salesa decrease in the amount of electricity.electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

Operation and Maintenance– O&M expense includes electricgas and gaselectric utility operating costs, and the operating costs of the Company’s corporate and other business activities. Total O&M expenses decreased $0.5 million and increased $1.3$2.1 million or 8.1%, infor the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017. The changedecrease in O&M expensesthe three month period reflects an increase in compensationlower professional fees of $0.5 million and benefitlower labor costs of $0.7$0.3 million, bad debt expenses of $0.2 million andpartially offset by higher utility operating costs of $0.4 million.The$0.3 million. The increase in the nine month period reflects higher labor costs of $1.5 million and higher utility operating costs reflect increased system maintenanceof $1.9 million, offset by lower professional fees of $1.3 million. The higher utility operating costs related to a higher level of storms and colder weather in the firstnine month period include anon-recurring temporary rate adjustment to increase O&M expenses by $1.2 million in the second quarter of 2018, compared to the prior year period, as well as higher bad debt expense related to increased sales.which was offset by a corresponding increase in gas revenue.

Depreciation and Amortization –Depreciation and Amortization expense decreased $0.2increased $1.6 million, or 1.6%14.8%, and $2.2 million, or 6.3%, in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017, reflecting2017. These increases reflect higher utility plant in service and higher amortization of information technology costs, partially offset by lower amortization of deferred major storm costs partially offset by higher utility plant in service and amortization of information system and software costs.which were being amortized for recovery over multi-year periods.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes increased $0.3$0.6 million, or 5.5%,12.2% and $0.9 million, or 5.8% in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017, primarily reflecting higher local property taxestax rates on higher levels of utility plant assets in service.service and higher payroll taxes.

Other Expense, net –Other Expense, net increased $0.2 million, or 22.2%, and $0.4 million, or 10.8%, in the three month periodand nine months ended March 31,September 30, 2018, increased $0.1 millionrespectively, compared withto the same periodperiods in 2017. In the first quarter of 2018, the Company adopted ASUNo. 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 Form10-Q for the quarter ended March 31,September 30, 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$1.2 million and $1.6$0.8 million ofnon-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the three months ended March 31,September 30, 2018 and March 31,September 30, 2017, respectively.respectively, net of amounts deferred as regulatory assets for future recovery. There are $4.1 million and $3.6 million ofnon-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the nine months ended September 30, 2018 and September 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery.

Income Taxes – Federal and State Income Taxes decreased by $2.9$1.0 million and $6.1 million for the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periods in 2017. The decrease in the three month period in 2017, reflecting $2.3 million from areflects the lower tax rate on higherpre-tax earnings from the TCJA in 2018. The decrease in the nine month period reflects $5.0 million from the lower tax rate onpre-tax earnings in Q1 2018 and the current tax benefit of $0.6$1.1 million onof book/tax items not previously includedtemporary differences turning at the lower income tax rate from the TCJA in customers’ utility rates.2018.

Interest Expense, net

–Interest expense is presented in the financial statementsConsolidated 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.calculated.

Unitil’s utility subsidiaries operate a number of reconciling rate adjustment mechanisms to recover specifically identified costs on a pass-throughpass through basis. These reconciling rate adjustment 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 was essentially unchangedincreased $0.2 million and $0.8 million in the three and nine months ended March 31,September 30, 2018, respectively, compared to the same periodperiods in 2017, reflecting higher2017. These increases primarily reflect interest on long-term debt offset by lower net interest expense on net regulatory assets/liabilities and lowerhigher levels of short-termlong-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 forday-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its

subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility.Facility (as defined below). At March 31,September 30, 2018, March 31,September 30, 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,July 25, 2018, the Company entered into ana Second Amended and Restated Credit Agreement (as further amended, restated,and related documents (collectively, the “Credit Facility”) with a syndicate of lenders, which amended and restated modified or supplemented from time to time,in its entirety the “Credit Facility”).Company’s prior credit facility. The Credit Facility terminates October 4, 2020extends to July 25, 2023, subject to twoone-year extensions under certain circumstances, and provides forhas a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitilthe Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal toone-month London Interbank Offered Rate (LIBOR) plus 1.25%1.125%. Provided there is no event of default under the Credit Facility, theThe Company may on aone-time basis request an increase in the aggregate commitmentsborrowing limit under the Credit Facility by an aggregate additional amount of up to $30 million.$50 million under certain circumstances.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $88.9$202.5 million for the threenine months ended March 31,September 30, 2018. Total gross repayments were $81.9$171.7 million for the threenine months ended March 31, 2017.September 30, 2018. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of March 31,September 30, 2018, March 31,September 30, 2017 and December 31, 2017:

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’sthe Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’sthe Company’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At March 31,September 30, 2018, March 31,September 30, 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.

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,September 30, 2018, there are $2.7 million of current and $4.4$3.0 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,September 30, 2018, there were approximately $17.9$5.6 million of guarantees outstanding and the longest term guarantee extends through August 2018.outstanding.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $1.0$9.6 million, $3.8$9.0 million and $8.5 million of natural gas storage inventory at March 31,September 30, 2018, March 31,September 30, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in MarchSeptember 2018 and payable in AprilOctober 2018 is $1.0$0.1 million and is recorded in Accounts Payable at March 31,September 30, 2018. The amount of natural gas inventory released in MarchSeptember 2017 and payable in AprilOctober 2017 was $2.0$0.1 million and was recorded in Accounts Payable at March 31,September 30, 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 7.15% notes issued by Granite State. As of March 31,September 30, 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,September 30, 2018, there were approximately $17.9$5.6 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.outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. For a complete discussion of the Company’s significant accounting policies, refer to Note 1 to the Consolidated Financial Statements in this quarterly report on Form10-Q and Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form10-K, as filed with the Securities and Exchange Commission on February 1, 2018.

LABOR RELATIONS

As of March 31,September 30, 2018, the Company and its subsidiaries had 514513 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of March 31,September 30, 2018, a total of 167165 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,September 30, 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, Unitilthe Company meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest

rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings and intercompany money pool transactions for the three months ended March 31,September 30, 2018 and March 31,September 30, 2018 were 3.3% and 2.5%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2018 and September 30, 2017 were 2.9%3.2% and 2.1%2.3%, 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’sUnitil Corporation’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.

Item 1.

Financial Statements

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions except per share data)

(UNAUDITED)

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)