UNITIL CORP - Quarter Report: 2018 September (Form 10-Q)

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended September 30, 2018

Commission File Number 1-8858

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.

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.

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2018

Table of Contents

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:

3

Table of Contents

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

PART I. FINANCIAL INFORMATION

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

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

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

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 $1,022.3 million at 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 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

4

Table of Contents

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

Tax Cuts and Jobs Act of 2017

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21 percent, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, has issued procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC has 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 these matters are substantially resolved and will not have a material impact on its financial position, operating results, or cash flows.

5

Table of Contents

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

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

In Massachusetts, the MDPU issued an order opening an investigation into the effect on rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities, and required each utility subject to its jurisdiction to submit proposals to address the effects of the TCJA and to reduce its rates as of January 1, 2018. The MDPU consolidated an earlier petition filed by the Attorney General requesting such an investigation into its order. On June 29, 2018, the MDPU issued an order accepting Fitchburg’s proposal to decrease the annual revenue requirement of both its gas and electric divisions by $0.8 million each. The MDPU will address the refund of excess accumulated deferred income taxes in phase two of its investigation. An order is pending.

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

Base Rate Activity

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

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

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

6

Table of Contents

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

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

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

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

Northern Utilities – Targeted Infrastructure Replacement Adjustment – Maine – The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the TIRA mechanism, with adjustment, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On May 7, 2018, the MPUC approved the Company’s request to increase its annual base rates by 2.4%, or $1.1 million, to recover the revenue requirements for 2017 eligible facilities.

Northern Utilities – Targeted Area Build-out Program – Maine – In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was

7

Table of Contents

approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (described above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.

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

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

Granite State – Base Rates – On May 2, 2018, Granite State filed an uncontested rate settlement with FERC which provided for no change in rates, and accounted for the effects of a capital step adjustment offset by the effect of the TCJA. The settlement was approved by FERC on June 27, 2018, and complies with the FERC Notice of Proposed Rulemaking concerning the justness and reasonableness of rates in light of the corporate income tax reductions under the TCJA. The settlement also provides that Granite State may not file a general (Section 4) rate case prior to April 30, 2019.

RESULTS OF OPERATIONS

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

8

Table of Contents

Earnings Overview

The Company’s Net Income was $2.8 million, or $0.19 per share, for the third quarter of 2018, an increase of $0.5 million, or $0.03 per share, compared to the third 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 increases in earnings in 2018 were driven by higher sales margins, reflecting: customer growth, favorable impacts of weather on unit sales and new distribution rates. Also, earnings per share reflect a higher number of shares outstanding due to the issuance of 690,000 common shares on December 14, 2017, discussed below in Note 5 to the Consolidated Financial Statements.

Natural gas sales margins were $17.6 million and $80.4 million in the three and nine months ended September 30, 2018, respectively, increases of $0.8 million and $5.1 million, respectively, compared to the same periods in 2017. 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 revenues 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 concurrent non-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 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 5.5% in the three and nine month periods ended 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 9% more Heating Degree Days (HDD) in the first nine months of 2018 compared to the same period in 2017. As of September 30, 2018, the number of total natural gas customers served has increased by approximately 1,200 over the last year.

Electric sales margins were $25.9 million and $70.5 million in the three and nine months ended September 30, 2018, respectively, increases of $1.1 million and $0.4 million, respectively, compared to the same periods in 2017. 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 a 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 kilowatt-hour (kWh) sales increased 3.4% and 4.2%, respectively, in the three and nine month periods ended September 30, 2018 compared to the same 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 September 30, 2018, the number of total electric customers served has increased by approximately 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 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 a non-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.

9

Table of Contents

Depreciation and Amortization expense increased $1.6 million and $2.2 million in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. 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 which were being amortized for recovery over multi-year periods.

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

Interest Expense, net increased $0.2 million and $0.8 million in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. These increases primarily reflect interest on higher levels of long-term debt.

At its January 2018, April 2018, July 2018 and October 2018 meetings, Unitil’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 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 5.5% in the three and nine month periods ended 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 warmer late summer and early fall weather in 2018, partially offset by customer growth. For the nine months ended September 30, 2018, sales to Residential and C&I customers increased 7.2% and 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 in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 9% more HDD in the first nine months of 2018 compared to the same period in 2017. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 2.0% in the first nine months of 2018 compared to the same period in 2017. As of September 30, 2018, the number of total natural gas customers served has increased by approximately 1,200 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) are not sensitive to changes in gas therm sales.

10

Table of Contents

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

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

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is an important measure to analyze profitability because the approved cost of sales are tracked and reconciled 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 margins were $17.6 million and $80.4 million in the three and nine months ended September 30, 2018, respectively, increases of $0.8 million and $5.1 million, respectively, compared to the same periods in 2017. Gas sales margin in the third quarter of 2018 was positively affected by higher natural gas distribution revenues of $1.1 million, partially offset by lower revenue of $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 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 concurrent non-recurring adjustments to increase both Gas Operating Revenues and O&M expenses by $1.2 million in the second quarter of 2018 to reconcile permanent rates and deferred costs to the temporary rates which were effective July 1, 2017. Gas margin in 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.

11

Table of Contents

The increase in Total Gas Operating Revenues of $0.6 million in the three 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 as a pass-through to customers, partially offset by lower revenue related to the TCJA, discussed above.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales increased 3.4% and 4.2%, respectively, in the three and nine month periods ended September 30, 2018 compared to the same periods in 2017. In the third quarter of 2018, sales to Residential and C&I customers increased 9.2% and 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 Company’s electric service areas, there were 48.7% more CDD in the third quarter of 2018 compared to the same period in 2017 and 9.0% more HDD in the first nine months of 2018 compared to the same period in 2017. As of September 30, 2018, the number of total electric customers served has increased by approximately 575 over the last year. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.

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

12

Table of Contents

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

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

Electric sales margins were $25.9 million and $70.5 million in the three and nine months ended September 30, 2018, respectively, increases of $1.1 million and $0.4 million, respectively, compared to the same periods in 2017. Electric sales margin in the third quarter was positively affected by higher electric distribution revenues of $0.8 million, partially offset by lower revenue of $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 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 a one-year $1.4 million temporary rate reconciliation adjustment recognized in 2017 Electric Operating Revenues by the Company’s New Hampshire electric utility.

The increase in Total Electric Operating Revenues of $3.9 million in the third quarter 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 lower revenue 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 a non-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.

13

Table of Contents

Operating Revenue – Other

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

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

Usource’s revenues decreased $0.3 million, or 21.4%, and $1.0 million, or 22.2%, in the three and nine months ended June 30, 2018, respectively, compared to the same 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 ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018. ASU 2014-09 requires that payments made by Usource to third parties (“Channel Partners”) for revenue sharing agreements are recognized as a reduction from revenue, where those payments were previously recognized as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to third parties for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to Channel Partners for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $0.3 million and $0.3 million in the three months ended September 30, 2018 and 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 ASU 2014-09 had been in effect for the three and nine months ended September 30, 2017, the result would have been corresponding reductions of $0.3 million and $0.8 million, respectively, in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings.

Operating Expenses

Cost of Gas Sales – Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $0.2 million, or 2.4%, and increased $10.4 million, or 18.4%, in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. The 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. 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.

14

Table of Contents

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 $2.8 million, or 8.6% and $12.8 million, or 15.2% in the three and nine months ended September 30, 2018 compared to the same periods in 2017. The 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 a decrease in the amount of electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass-through basis and therefore changes in approved expenses do not affect earnings.

O&M expense includes gas and electric 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 $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 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 a non-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.

Depreciation and Amortization – Depreciation and Amortization expense increased $1.6 million, or 14.8%, and $2.2 million, or 6.3%, in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. 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 which were being amortized for recovery over multi-year periods.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes increased $0.6 million, or 12.2% and $0.9 million, or 5.8% in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017, primarily reflecting higher local property tax rates on higher levels of utility plant assets in 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 and nine months ended September 30, 2018, respectively, compared to the same periods 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 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

15

Table of Contents

Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. There are $1.2 million and $0.8 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the three months ended September 30, 2018 and September 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery. There are $4.1 million and $3.6 million of non-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 $1.0 million and $6.1 million for the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. The decrease in the three month period reflects the lower tax rate on pre-tax earnings from the TCJA in 2018. The decrease in the nine month period reflects $5.0 million from the lower tax rate on pre-tax earnings in 2018 and the current tax benefit of $1.1 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018.

Interest Expense, net – Interest expense is presented in the Consolidated Financial Statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. In addition, certain reconciling rate mechanisms used by the Company’s distribution operating utilities give rise to regulatory assets and regulatory liabilities on which interest is calculated.

Unitil’s utility subsidiaries operate a number of reconciling rate adjustment mechanisms to recover specifically identified costs on a pass through basis. These reconciling rate adjustment mechanisms track costs and revenue on a monthly basis. In any given month, this tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

Interest Expense, net increased $0.2 million and $0.8 million in the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017. These increases primarily reflect interest on higher levels of long-term debt.

16

Table of Contents

CAPITAL REQUIREMENTS

Sources of Capital

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

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the “Cash Pool”). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility (as defined below). At September 30, 2018, 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 July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement and related documents (collectively, the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit facility. The Credit Facility extends to July 25, 2023, subject to two one-year extensions under certain circumstances, and has a borrowing limit of $120 million, which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides the Company with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.125%. The Company may increase the borrowing limit under the Credit Facility by up to $50 million under certain circumstances.

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

17

Table of Contents

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, the Company’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on the Company’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At September 30, 2018, 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 September 30, 2018, there are $2.7 million of current and $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 September 30, 2018, there were approximately $5.6 million of guarantees outstanding.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $9.6 million, $9.0 million and $8.5 million of natural gas storage inventory at September 30, 2018, September 30, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2018 and payable in October 2018 is $0.1 million and is recorded in Accounts Payable at September 30, 2018. The amount of natural gas inventory released in September 2017 and payable in October 2017 was $0.1 million and was recorded in Accounts Payable at 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 September 30, 2018, the principal amount outstanding for the 7.15% Granite State notes was $3.3 million.

18

Table of Contents

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil Corporation’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of September 30, 2018, there were approximately $5.6 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

CRITICAL ACCOUNTING POLICIES

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

LABOR RELATIONS

As of September 30, 2018, the Company and its subsidiaries had 513 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of September 30, 2018, a total of 165 employees of certain of the Company’s subsidiaries were represented by labor unions. The following table details by subsidiary the employees covered by a collective bargaining agreement (CBA) as of 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.

19

Table of Contents

INTEREST RATE RISK

As discussed above, the 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 September 30, 2018 and 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 3.2% and 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 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 Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Regulatory Matters.

ENVIRONMENTAL MATTERS

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

20

Table of Contents

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.)

21

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)

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

22

Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)