Edgar Filing: UNITIL CORP

Large accelerated filer

Accelerated filer

Non-accelerated filer

☐ (Do not check if a smaller reporting company)

Smaller reporting company

Emerging growth company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended June 30, 2018

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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

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

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

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


Class		Outstanding at July 23, 2018
Common Stock, No par value		14,866,852 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2018

Table of Contents


		Page No.
Part I. Financial Information

Item 1.	Financial Statements - Unaudited

	Consolidated Statements of Earnings - Three and Six Months Ended June 30, 2018 and 2017	23

	Consolidated Balance Sheets, June 30, 2018, June 30, 2017 and December 31, 2017	24-25

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2018 and 2017	26

	Consolidated Statements of Changes in Common Stock Equity – Six Months Ended June 30, 2018 and 2017	27

	Notes to Consolidated Financial Statements	28-57

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	4-22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	57

Item 4.	Controls and Procedures	58

Part II. Other Information

Item 1.	Legal Proceedings	58

Item 1A.	Risk Factors	58

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	59

Item 6.	Exhibits	60

Signatures		61

CAUTIONARY STATEMENT

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

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

•

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

•

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

•

customers’ preferred energy sources;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

catastrophic events;

•

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

•

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

•

increased competition.

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

PART I. FINANCIAL INFORMATION

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

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

ii)

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

iii)

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

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 105,000 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 $989.8 million at June 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 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.

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.

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 issued its final order approving a settlement between Unitil Energy, NHPUC Staff and the Office of Consumer Advocate providing for a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019 to recover the revenue requirements associated with annual capital expenditures as defined under the rate plan. On 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 – On April 29, 2016 the MDPU issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. As part of its order, the MDPU approved, with modifications, Fitchburg’s request for an annual capital cost recovery mechanism, which allows for increases to target revenues to recover the revenue requirement associated with capital additions as defined under the mechanism. In 2016, Fitchburg filed its first compliance report on capital investments for calendar year 2015. The MDPU approved the recovery of approximately $0.5 million, effective January 1, 2017, subject to further investigation and reconciliation. On December 18, 2017, the MDPU approved Fitchburg’s calendar year 2015 capital investments and associated revenue requirements for recovery. On June 29, 2017, Fitchburg filed its compliance report on capital investments for calendar year 2016. On December 20, 2017, the MDPU approved the recovery of approximately $0.4 million, effective January 1, 2018, subject to further investigation and reconciliation. On June 28, 2018, Fitchburg filed its compliance report of capital investments for calendar year 2017.

Fitchburg – Electric Grid Modernization – In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP is a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. On May 10, 2018, the MDPU issued an order approving a three year plan for 2018 to 2020 with a spending cap of $4.4 million for Fitchburg. The order provides for a cost recovery mechanism for incremental capital investments and operation and maintenance (O&M) expenses. The electric distribution companies are to file compliance filings by August 8, 2018 which shall include 1) revised proposed performance metrics designed to address pre-authorized grid-facing investments, 2) a proposed evaluation plan for the 3 year investment term, and 3) a model tariff for cost recovery including proposed protocol for identifying and tracking incremental O&M expenses. Cost recovery filings will be due February 15 for rates effect April 1. Annual reports will be due April 1 for the prior calendar year and the first term report will be due April 1, 2021. The next plan is due July 1, 2020 for the three year term 2021 to 2023, and shall include a five year strategic plan for 2021 – 2025.

Fitchburg – Solar Generation – On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts, including a cost recovery mechanism to share the costs and benefits of the project among all Fitchburg customers. On November 9, 2016, the MDPU approved a Settlement Agreement supporting the proposal, which was reached among the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing 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.

Fitchburg – Base Rates – Gas – Pursuant to the Company’s revenue decoupling adjustment clause tariff, as approved in its last base rate case providing for an annual increase in revenue of $1.6 million effective May 1, 2016, the Company is allowed to modify, on a semi-annual basis, its base distribution rates to an established revenue per customer target which promotes revenue stability and mitigates 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 – On October 31, 2017, Fitchburg submitted its annual filing under its gas system enhancement program to recover the revenue requirements associated with its projected capital additions in 2018 as defined under the program. The filing sought approval to collect an additional $0.9 million of annual revenue requirements. As part of the filing, the Company requested to permanently change the revenue requirements cap to 3% as part of its tariff. On April 30, 2018, the MDPU approved recovery of the projected 2018 revenue requirements, subject to reconciliation and a cap of 1.5% on the change in revenue requirement to be billed in any given year. The cap resulted in approval of an additional $0.4 million of annual revenue requirements to be billed effective May 1, 2018 with the remaining $0.9 million of annual revenue requirements deferred for billing in future periods. In its May 1, 2018 annual reconciliation filing for 2017 revenue requirements, the Company requested that the MDPU waive the 1.5% revenue requirement cap and provide for full recovery of any under-collections. This matter remains pending.

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 TAB Program and TIRA mechanism. The new rates and other changes became effective on 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. This matter remains pending.

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 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.

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

Northern Utilities – Base Rates – New Hampshire – On May 2, 2018, the NHPUC approved a settlement agreement among the Company, the NHPUC Staff and the Office of the Consumer Advocate in the Company’s pending rate case. The agreement provides 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). Under the agreement, the Company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the Company chooses the option to implement the second step increase, the next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020.

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 June 30, 2018 and June 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.

Earnings Overview

The Company’s Net Income was $3.6 million, or $0.24 per share, for the second quarter of 2018, an increase of $0.5 million, or $0.01 per share, compared to the second quarter of 2017. For the six months ended June 30, 2018, the Company reported Net Income of $19.2 million, or $1.30 per share, an increase of $3.7 million, or $0.19 per share, compared to the same six month period in 2017.The increases in earnings in 2018 were driven by higher sales margins, reflecting: customer growth, colder winter weather and new distribution rates compared to 2017. 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 $22.9 million and $62.8 million in the three and six months ended June 30, 2018, respectively, increases of $2.4 million and $4.3 million, respectively, compared to the same periods in 2017. Gas sales margin in the first six months of 2018 was positively affected by higher natural gas distribution rates of $4.8 million. 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 revenue 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 six months of 2018 also reflects the positive effect of colder winter weather and customer growth on sales volume of $2.0 million, partially offset by lower revenue of $2.5 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA. The reduction in revenues related to the TCJA also reflects a lower provision for income taxes in the period.

Natural gas therm sales increased 2.8% and 7.2% in the three and six month periods ended June 30, 2018, respectively, compared to the same periods in 2017. The increase in gas therm sales in the Company’s service areas was driven by customer growth and, for the six month period, colder winter weather 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 six months of 2018 compared to the same period in 2017. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 2.8% in the first six months of 2018 compared to the same period in 2017. As of June 30, 2018, the number of total natural gas customers served has increased by 1,549 in the last twelve months.

Electric sales margins were $22.3 million and $44.6 million in the three and six months ended June 30, 2018, respectively, decreases of $1.0 million and $0.7 million, respectively, compared to the same periods in 2017. Electric sales margin in the first six months of 2018 was positively affected by higher electric distribution rates of $1.7 million as well as colder weather and customer growth of $0.5 million, partially offset by the termination of a one-year $1.4 million reconciliation adjustment which was recognized in the second quarter of 2017 to recoup the difference between temporary rates and final rates in the Company’s New Hampshire electric utility. Electric margin also reflects lower revenue of $1.5 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.

Total electric kilowatt-hour (kWh) sales increased 3.3% and 4.6%, respectively, in the three and six month periods ended June 30, 2018 compared to the same periods in 2017, reflecting customer growth, higher usage by industrial customers for production purposes and, for the six month period, the positive impact of colder winter weather. As of June 30, 2018, the number of total electric customers served has increased by 593 in the last twelve months.

Excluding the non-recurring 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, discussed above, total O&M expenses increased $0.1 million and $1.4 million for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The increase in the three month period reflects higher labor costs of $1.1 million, offset by lower professional fees of $0.8 million and lower utility operating costs of $0.2 million. The increase in the six month period reflects higher labor costs of $1.8 million and higher utility operating costs of $0.4 million, offset by lower professional fees of $0.8 million. The higher utility operating costs in the six month period reflect increased system maintenance costs related to a higher level of storms and colder weather in the first quarter of 2018 compared to the prior year period, as well as higher bad debt expense related to increased sales.

Depreciation and Amortization expense increased $0.8 million and $0.6 million in the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. These increases reflect higher utility plant in service and higher amortization of software costs, partially offset by lower amortization of deferred major storm costs which were being amortized for recovery over multi-year periods.

For the six months ended June 30, 2018, Taxes Other Than Income Taxes increased $0.3 million compared to the same period in 2017, reflecting higher payroll taxes.

Interest Expense, net increased $0.6 million in each of the three and six months ended June 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 and July 2018 meetings, the Unitil Corporation Board of Directors declared quarterly dividends on the Company’s common stock of $0.365 per share. These quarterly dividends result in a current effective annualized dividend rate of $1.46 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

A more detailed discussion of the Company’s results of operations for the three and six months ended June 30, 2018 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 2.8% and 7.2% in the three and six month periods ended June 30, 2018, respectively, compared to the same periods in 2017. In the second quarter of 2017, sales to Residential decreased 1.0% and sales to C&I customers increased 3.8%, respectively, compared to the same period in 2017, reflecting customer growth, partially offset by the impact on Residential sales of warmer spring weather in 2018 compared to 2017. For the six months ended June 30, 2018, sales to Residential and C&I customers increased 8.8% and 6.7%, respectively, compared to the same period in 2017. The increase in gas therm sales in the Company’s service areas in the six month period was driven by customer growth and colder winter weather in 2018 compared to 2017. Based on weather data collected in the Company’s natural gas service areas, there were 9% more HDD in the first six months of 2018 compared to the same period in 2017. The Company estimates that weather-normalized gas therm sales, excluding decoupled sales, were up 2.8% in the first six months of 2018 compared to the same period in 2017. As of June 30, 2018, the number of total natural gas customers served has increased by 1,549 in the last twelve months. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) are not sensitive to changes in gas therm sales.

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


Therm Sales (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2018		2017		Change			% Change			2018		2017		Change		% Change
Residential		9.6		9.7		(0.1	)		(1.0	%)		33.4		30.7		2.8		8.8	%
Commercial / Industrial		38.1		36.7		1.4			3.8	%		108.4		101.6		6.8		6.7	%

Total		47.7		46.4		1.3			2.8	%		141.8		132.3		9.5		7.2	%

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


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2018		2017		$ Change		% Change			2018		2017		$ Change		% Change
Gas Operating Revenue:
Residential	$	13.9	$	13.2	$	0.7		5.3	%	$	49.7	$	44.3	$	5.4		12.2	%
Commercial / Industrial		20.8		18.8		2.0		10.6	%		72.0		62.5		9.5		15.2	%

Total Gas Operating Revenue	$	34.7	$	32.0	$	2.7		8.4	%	$	121.7	$	106.8	$	14.9		14.0	%

Cost of Gas Sales	$	11.8	$	11.5	$	0.3		2.6	%	$	58.9	$	48.3	$	10.6		21.9	%

Gas Sales Margin	$	22.9	$	20.5	$	2.4		11.7	%	$	62.8	$	58.5	$	4.3		7.4	%

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

Natural gas sales margins were $22.9 million and $62.8 million in the three and six months ended June 30, 2018, respectively, increases of $2.4 million and $4.3 million, respectively, compared to the same periods in 2017. Gas sales margin in the second quarter of 2018 was positively affected by higher natural gas distribution rates of $3.2 million. 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 revenue 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 second quarter also reflects the positive effect of customer growth on sales volume of $0.2 million and lower revenue of $1.0 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 first six months of 2018 was positively affected by higher natural gas distribution rates of $4.8 million, including the non-recurring adjustment of $1.2 million, discussed above. Gas margin in the first six months of 2018 also reflects the positive effect of colder winter weather and customer growth on sales volume of $2.0 million, partially offset by lower revenue of $2.5 million to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA.

The increases in Total Gas Operating Revenues of $2.7 million and $14.9 million in the three and six months ended June 30, 2018, compared to the same periods in 2017, reflect higher natural gas sales volumes and higher cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers, partially offset by lower revenue related to the TCJA, discussed above.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales increased 3.3% and 4.6%, respectively in the three and six month periods ended June 30, 2018 compared to the same periods in 2017. Sales to Residential customers increased 1.8% and 4.7%, respectively, in the three and six month periods ended June 30, 2018 compared to the same periods in 2017. Sales to C&I customers increased 4.2% and 4.5%, respectively, in the three and six month periods ended June 30, 2018 compared to the same periods in 2017. These increases reflect customer growth, higher usage by industrial customers for production purposes and, for the six month period, the positive impact of colder winter weather. As of June 30, 2018, the number of total electric customers served has increased by 593 in the last twelve months. As previously discussed, sales margins derived from decoupled unit sales (representing approximately 27% of total annual kWh sales volume) are not sensitive to changes in electric kWh sales.

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


kWh Sales (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2018		2017		Change		% Change			2018		2017		Change		% Change
Residential		144.3		141.7		2.6		1.8	%		332.8		317.9		14.9		4.7	%
Commercial / Industrial		239.8		230.2		9.6		4.2	%		487.6		466.4		21.2		4.5	%

Total		384.1		371.9		12.2		3.3	%		820.4		784.3		36.1		4.6	%

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


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2018		2017		$ Change			% Change			2018		2017		$ Change			% Change
Electric Operating Revenue:
Residential	$	26.4	$	25.8	$	0.6			2.3	%	$	60.2	$	54.7	$	5.5			10.1	%
Commercial / Industrial		22.3		21.6		0.7			3.2	%		46.0		42.2		3.8			9.0	%

Total Electric Operating Revenue	$	48.7	$	47.4	$	1.3			2.7	%	$	106.2	$	96.9	$	9.3			9.6	%

Cost of Electric Sales	$	26.4	$	24.1	$	2.3			9.5	%	$	61.6	$	51.6	$	10.0			19.4	%

Electric Sales Margin	$	22.3	$	23.3	$	(1.0	)		(4.3	%)	$	44.6	$	45.3	$	(0.7	)		(1.5	%)

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

Electric sales margins were $22.3 million and $44.6 million in the three and six months ended June 30, 2018, respectively, decreases of $1.0 million and $0.7 million, respectively, compared to the same periods in 2017. Electric sales margin in the second quarter was positively affected by higher electric distribution rates of $0.8 million and customer growth of $0.3 million, offset by the termination of a one-year $1.4 million reconciliation adjustment which was recognized in the second quarter of 2017 to recoup the difference between temporary rates and final rates in the Company’s New Hampshire electric utility. Electric margin also reflects lower revenue of $0.7 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 first six months of 2018 was positively affected by higher electric distribution rates of $1.7 million as well as colder weather and customer growth of $0.5 million, offset by the non-recurring adjustment of $1.4 million, discussed above, and lower revenue of $1.5 million in 2018 to account for the reduction in rates due to the lower corporate income tax rate of 21% under the TCJA.

The increase in Total Electric Operating Revenues of $1.3 million in the second quarter of 2018 reflects higher electric sales volumes and higher cost of electric sales, which are tracked and reconciled to costs that are passed through directly 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.

The increase in Total Electric Operating Revenues of $9.3 million in the first six months of 2018 reflects higher electric sales volumes and higher cost of electric sales, which are tracked and reconciled to costs that are passed through directly 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.

Operating Revenue – Other

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


Other Revenue (000’s)
	Three Months Ended June 30,										Six Months Ended June 30,
	2018		2017		$ Change			% Change			2018		2017		$ Change			% Change
Other	$	1.1	$	1.4	$	(0.3	)		(21.4	%)	$	2.4	$	3.1	$	(0.7	)		(22.6	%)

Total Other Revenue	$	1.1	$	1.4	$	(0.3	)		(21.4	%)	$	2.4	$	3.1	$	(0.7	)		(22.6	%)

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 $0.7 million, or 22.6%, in the three and six 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 $0.2 million and $0.3 million in the three months ended June 30, 2018 and 2017, respectively. Channel Partner payments were $0.5 million and $0.5 million in the six months ended June 30, 2018 and 2017, respectively.

If ASU 2014-09 had been in effect for the three and six months ended June 30, 2017, the result would have been corresponding reductions of $0.3 million and $0.5 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.

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 $0.3 million, or 2.6%, and $10.6 million, or 21.9%, in the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The increase in the three month period primarily reflects higher sales of natural gas and a decrease in the amount of natural gas purchased by customers directly from third-party suppliers. The increase in the six 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.

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 $2.3 million, or 9.5%, and $10.0 million, or 19.4%, in the three and six months ended June 30, 2018, respectively, 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 six 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.

Operation and Maintenance (O&M) – O&M expense includes gas and electric utility operating costs, and the operating cost of the Company’s corporate and other business activities. Excluding a non-recurring 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, discussed above, total O&M expenses increased $0.1 million, or 0.6%, and $1.4 million, or 4.3%, for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The increase in the three month period reflects higher labor costs of $1.1 million, offset by lower professional fees of $0.8 million and lower utility operating costs of $0.2 million. The increase in the six month period reflects higher labor costs of $1.8 million and higher utility operating costs of $0.4 million, offset by lower professional fees of $0.8 million. The higher utility operating costs in the six month period reflect increased system maintenance costs related to a higher level of storms and colder weather in the first quarter of 2018 compared to the prior year period, as well as higher bad debt expense related to increased sales.

Depreciation and Amortization – Depreciation and Amortization expense increased $0.8 million, or 6.7%, and $0.6 million, or 2.5%, in the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. These increases reflect higher utility plant in service and higher amortization of software 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 was relatively unchanged in the three months ended June 30, 2018 compared to the same period in 2017. For the six months ended June 30, 2018, Taxes Other Than Income Taxes increased $0.3 million, or 2.8%, compared to the same period in 2017, reflecting higher payroll taxes.

Other Expense (Income), net – Other Expense (Income), net increased $0.1 million, or 8.3%, and $0.2 million, or 7.1%, in the three and six months ended June 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 June 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 $1.3 million and $1.1 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the three months ended June 30, 2018 and June 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery. There are $2.9 million and $2.7 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the six months ended June 30, 2018 and June 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery.

Income Taxes – Federal and State Income Taxes decreased by $2.2 million and $5.1 million for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The decrease in the three month period reflect $1.7 million from the lower tax rate on pre-tax earnings in 2018 and the current tax benefit of $0.5 million of book/tax temporary differences turning at the lower income tax rate from the TCJA in 2018. The decrease in the six month period reflect $4.0 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 accrued.

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


Interest Expense, net (Millions)	Three Months Ended June 30,									Six Months Ended June 30,
	2018			2017			Change			2018			2017			Change
Interest Expense
Long-term Debt	$	5.7		$	5.3		$	0.4		$	11.5		$	10.7		$	0.8
Short-term Debt		0.5			0.5			—			1.0			1.1			(0.1	)
Regulatory Liabilities		0.2			—			0.2			0.3			0.4			(0.1	)

Subtotal Interest Expense		6.4			5.8			0.6			12.8			12.2			0.6

Interest (Income)
Regulatory Assets		(0.2	)		(0.1	)		(0.1	)		(0.4	)		(0.3	)		(0.1	)
AFUDC⁽¹⁾ and Other		(0.3	)		(0.4	)		0.1			(0.5	)		(0.6	)		0.1

Subtotal Interest (Income)		(0.5	)		(0.5	)		—			(0.9	)		(0.9	)		—

Total Interest Expense, net	$	5.9		$	5.3		$	0.6		$	11.9		$	11.3		$	0.6

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

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 June 30, 2018, June 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.

including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate (LIBOR) plus 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $135.3 million for the six months ended June 30, 2018. Total gross repayments were $136.2 million for the six months ended June 30, 2018. The following table details the borrowing limits, amounts outstanding and amounts available under the Credit Facility as of June 30, 2018, June 30, 2017 and December 31, 2017:


	Revolving Credit Facility ($ millions)
	June 30,				December 31,
	2018		2017		2017
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	37.4	$	79.2	$	38.3
Letters of Credit Outstanding	$	0.0	$	1.1	$	0.0

Available	$	82.6	$	39.7	$	81.7

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil Corporation’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At June 30, 2018, June 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 July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement

with Bank of America, N.A. and the other lenders that are parties thereto, which amended and restated the Credit Facility. (See also “Subsequent Events” in Note 1.)

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 June 30, 2018, there are $2.7 million of current and $3.7 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 June 30, 2018, there were approximately $5.9 million of guarantees outstanding and the longest term guarantee extends through August 2018.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $5.3 million, $5.6 million and $8.5 million of natural gas storage inventory at June 30, 2018, June 30, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2018 and payable in July 2018 is $1.0 million and is recorded in Accounts Payable at June 30, 2018. The amount of natural gas inventory released in June 2017 and payable in July 2017 was $0.1 million and was recorded in Accounts Payable at June 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 notes issued by Granite State. As of June 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 June 30, 2018, there were approximately $5.9 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding and the longest term guarantee extends through August 2018. See Note 4 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

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 June 30, 2018, the Company and its subsidiaries had 530 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of June 30, 2018, a total of 171 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 June 30, 2018:


	Employees Covered		CBA Expiration
Fitchburg		51		05/31/2019
Northern Utilities NH Division		35		06/05/2020
Northern Utilities ME Division		38		03/31/2021
Granite State		3		03/31/2021
Unitil Energy		39		05/31/2023
Unitil Service		5		05/31/2023

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

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings and intercompany money pool transactions for the three months ended June 30, 2018 and June 30, 2017 were 3.3% and 2.3%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2018 and June 30, 2017 were 3.1% and 2.2%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2017 was 2.4%.

COMMODITY PRICE RISK

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

REGULATORY MATTERS

Please refer to Note 6 to the 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.

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions except per share data)

(UNAUDITED)


	Three Months Ended June 30,					Six Months Ended June 30,
	2018			2017		2018		2017

Operating Revenues
Gas	$	34.7		$	32.0	$	121.7	$	106.8
Electric		48.7			47.4		106.2		96.9
Other		1.1			1.4		2.4		3.1

Total Operating Revenues		84.5			80.8		230.3		206.8

Operating Expenses
Cost of Gas Sales		11.8			11.5		58.9		48.3
Cost of Electric Sales		26.4			24.1		61.6		51.6
Operation and Maintenance		17.8			16.5		35.1		32.5
Depreciation and Amortization		12.7			11.9		25.0		24.4
Taxes Other Than Income Taxes		5.2			5.2		11.0		10.7

Total Operating Expenses		73.9			69.2		191.6		167.5

Operating Income		10.6			11.6		38.7		39.3
Interest Expense, net		5.9			5.3		11.9		11.3
Other Expense (Income), net		1.3			1.2		3.0		2.8

Income Before Income Taxes		3.4			5.1		23.8		25.2
Income Tax Expense (Benefit)		(0.2	)		2.0		4.6		9.7

Net Income	$	3.6		$	3.1	$	19.2	$	15.5


Net Income Per Common Share (Basic and Diluted)	$	0.24		$	0.23	$	1.30	$	1.11
Weighted Average Common Shares Outstanding – (Basic and Diluted)		14.8			14.1		14.8		14.1
Dividends Declared Per Share of Common Stock	$	0.365		$	0.36	$	0.73	$	0.72

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	June 30,				December 31,
	2018		2017		2017
ASSETS:

Current Assets:
Cash and Cash Equivalents	$	8.5	$	7.8	$	8.9
Accounts Receivable, net		56.2		41.1		67.4
Accrued Revenue		29.7		36.6		53.3
Exchange Gas Receivable		5.5		5.9		5.8
Refundable Taxes		1.2		0.9		1.8
Gas Inventory		0.6		0.5		0.6
Materials and Supplies		7.5		7.1		6.9
Prepayments and Other		8.9		8.1		6.6

Total Current Assets		118.1		108.0		151.3

Utility Plant:
Gas		709.8		643.2		699.6
Electric		479.7		442.0		476.7
Common		69.5		35.4		67.4
Construction Work in Progress		51.0		92.7		35.5

Total Utility Plant		1,310.0		1,213.3		1,279.2
Less: Accumulated Depreciation		320.2		300.6		307.7

Net Utility Plant		989.8		912.7		971.5

Other Noncurrent Assets:
Regulatory Assets		110.7		102.9		109.6
Other Assets		16.0		14.1		9.5

Total Other Noncurrent Assets		126.7		117.0		119.1

TOTAL ASSETS	$	1,234.6	$	1,137.7	$	1,241.9

(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)


	June 30,				December 31,
	2018		2017		2017
LIABILITIES AND CAPITALIZATION:

Current Liabilities:
Accounts Payable	$	24.7	$	23.0	$	41.5
Short-Term Debt		37.4		79.2		38.3
Long-Term Debt, Current Portion		29.7		29.9		29.8
Regulatory Liabilities		14.2		16.6		9.2
Energy Supply Obligations		9.4		10.3		9.7
Environmental Obligations		0.6		0.5		0.5
Capital Lease Obligations		3.1		3.0		3.1
Interest Payable		4.1		3.9		4.4
Other Current Liabilities		12.2		11.5		14.5

Total Current Liabilities		135.4		177.9		151.0

Noncurrent Liabilities:
Retirement Benefit Obligations		154.7		153.3		150.1
Deferred Income Taxes, net		88.1		106.8		82.9
Cost of Removal Obligations		87.8		82.3		84.3
Regulatory Liabilities		47.1		—		48.9
Capital Lease Obligations		4.1		6.9		5.7
Environmental Obligations		1.5		1.7		1.6
Other Noncurrent Liabilities		5.6		4.9		4.3

Total Noncurrent Liabilities		388.9		355.9		377.8

Capitalization:
Long-Term Debt, Less Current Portion		363.1		303.5		376.3
Stockholders’ Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 14,866,588, 14,114,551 and 14,815,585 Shares)		277.9		242.7		275.8
Retained Earnings		69.1		57.5		60.8

Total Common Stock Equity		347.0		300.2		336.6
Preferred Stock		0.2		0.2		0.2

Total Stockholders’ Equity		347.2		300.4		336.8

Total Capitalization		710.3		603.9		713.1

Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,234.6	$	1,137.7	$	1,241.9

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Six Months Ended June 30,
	2018			2017
Operating Activities:
Net Income	$	19.2		$	15.5
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Depreciation and Amortization		25.0			24.4
Deferred Tax Provision		3.6			8.7
Changes in Working Capital Items:
Accounts Receivable		11.2			11.8
Accrued Revenue		23.6			12.9
Exchange Gas Receivable		0.3			2.4
Regulatory Liabilities		5.0			6.2
Accounts Payable		(16.8	)		(9.4	)
Other Changes in Working Capital Items		(4.9	)		(5.4	)
Deferred Regulatory and Other Charges		(10.3	)		(9.5	)
Other, net		7.4			5.6

Cash Provided by Operating Activities		63.3			63.2

Investing Activities:
Property, Plant and Equipment Additions		(37.2	)		(44.9	)

Cash (Used in) Investing Activities		(37.2	)		(44.9	)

Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net		(0.9	)		(2.7	)
Repayment of Long-Term Debt		(13.5	)		(0.4	)
Decrease in Capital Lease Obligations		(1.6	)		(1.4	)
Net Decrease in Exchange Gas Financing		(0.2	)		(2.3	)
Dividends Paid		(10.9	)		(10.2	)
Proceeds from Issuance of Common Stock, net		0.6			0.7

Cash (Used in) Financing Activities		(26.5	)		(16.3	)

Net Increase (Decrease)in Cash and Cash Equivalents		(0.4	)		2.0
Cash and Cash Equivalents at Beginning of Period		8.9			5.8

Cash and Cash Equivalents at End of Period	$	8.5		$	7.8

Supplemental Cash Flow Information:
Interest Paid	$	12.4		$	11.4
Income Taxes Paid	$	0.4		$	—
Payments on Capital Leases	$	1.5		$	1.7
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	0.4		$	0.9

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)

(UNAUDITED)


	Common Equity		Retained Earnings			Total
Balance at January 1, 2018	$	275.8	$	60.8		$	336.6
Net Income				19.2			19.2
Dividends on Common Shares				(10.9	)		(10.9	)
Stock Compensation Plans		1.5					1.5
Issuance of 14,277 Common Shares		0.6					0.6

Balance at June 30, 2018	$	277.9	$	69.1		$	347.0

Balance at January 1, 2017	$	240.7	$	52.2		$	292.9
Net Income				15.5			15.5
Dividends on Common Shares				(10.2	)		(10.2	)
Stock Compensation Plans		1.3					1.3
Issuance of 14,391 Common Shares		0.7					0.7

Balance at June 30, 2017	$	242.7	$	57.5		$	300.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

Basis of Presentation – The accompanying unaudited Consolidated Financial Statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of

management, all adjustments considered necessary for a fair presentation have been included and are of a normal and recurring nature. The results of operations for the three and six months ended June 30, 2018 are not necessarily indicative of results to be expected for the year ending December 31, 2018. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission (SEC) on February 1, 2018, for a description of the Company’s Basis of Presentation.

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

Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates and are then reversed in the following month when billed to customers.

In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017 recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the three and six months ended June 30, 2018. A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.

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

The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in ASU 2014-09. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (ASC) 980-605-25-3, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. ASU 2014-09 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

In the following tables, revenue is classified by the types of goods/services rendered and market/customer type. The lower revenues reported in the three and six months ended 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act of 2017 (TCJA) are shown separately in the tables below for informational purposes.


	Three Months Ended June 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	15.8		$	27.5		$	43.3
C&I		22.9			24.0			46.9
Other		2.4			2.9			5.3
Revenue Reductions – TCJA		(1.0	)		(0.7	)		(1.7	)

Total Billed and Unbilled Revenue		40.1			53.7			93.8
Rate Adjustment Mechanism Revenue		(5.4	)		(5.0	)		(10.4	)

Total Gas and Electric Operating Revenues	$	34.7		$	48.7		$	83.4


	Three Months Ended June 30, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	15.0		$	23.6		$	38.6
C&I		20.3			20.6			40.9
Other		1.5			1.5			3.0

Total Billed and Unbilled Revenue		36.8			45.7			82.5
Rate Adjustment Mechanism Revenue		(4.8	)		1.7			(3.1	)

Total Gas and Electric Operating Revenues	$	32.0		$	47.4		$	79.4


	Six Months Ended June 30, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	51.7		$	62.0		$	113.7
C&I		72.8			48.9			121.7
Other		9.5			5.9			15.4
Revenue Reductions – TCJA		(2.5	)		(1.5	)		(4.0	)

Total Billed and Unbilled Revenue		131.5			115.3			246.8
Rate Adjustment Mechanism Revenue		(9.8	)		(9.1	)		(18.9	)

Total Gas and Electric Operating Revenues	$	121.7		$	106.2		$	227.9


	Six Months Ended June 30, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric		Total
Billed and Unbilled Revenue:
Residential	$	45.9		$	51.0	$	96.9
C&I		62.3			40.7		103.0
Other		7.5			3.0		10.5

Total Billed and Unbilled Revenue		115.7			94.7		210.4
Rate Adjustment Mechanism Revenue		(8.9	)		2.2		(6.7	)

Total Gas and Electric Operating Revenues	$	106.8		$	96.9	$	203.7

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

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

As discussed above, the Company adopted ASU 2014-09 in the first quarter of 2018. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. ASU 2014-09 requires that payments made by Usource to third parties (“Channel Partners”) for revenue sharing agreements are recognized net, as a reduction from revenue, where those payments were previously recognized gross as an operating expense. Therefore, beginning in 2018 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to third parties for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $0.2 million and $0.3 million in the three months ended June 30, 2018 and 2017, respectively. Channel Partner payments were $0.5 million and $0.5 million in the six months ended June 30, 2018 and 2017, respectively.


	Three Months Ended June 30,
	As Reported		If ASU 2014-09 Had Been in Effect
Other Operating Revenues ($ millions):	2018		2017
Usource Contract Revenue	$	1.3	$	1.4
Less: Revenue Sharing Payments		0.2		0.3

Total Other Operating Revenues	$	1.1	$	1.1


	Three Months Ended June 30,
	As Reported		If ASU 2014-09 Had Been in Effect
Operation and Maintenance Expense ($ millions):	2018		2017
Operation and Maintenance Expense	$	17.8	$	16.2


	Six Months Ended June 30,
	As Reported		If ASU 2014-09 Had Been in Effect
Other Operating Revenues ($ millions):	2018		2017
Usource Contract Revenue	$	2.9	$	3.1
Less: Revenue Sharing Payments		0.5		0.5

Total Other Operating Revenues	$	2.4	$	2.6


	Six Months Ended June 30,
	As Reported		If ASU 2014-09 Had Been in Effect
Operation and Maintenance Expense ($ millions):	2018		2017
Operation and Maintenance Expense	$	35.1	$	32.0

Retirement Benefit Costs – The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan) and the Unitil Corporation Supplemental Executive Retirement Plan (SERP Plan).The net periodic benefit costs associated with these benefit plans consist of service cost and other components (See Note 9 to the Consolidated Financial Statements). In the first quarter of 2018, the Company adopted ASU No. 2017-07, “Compensation – Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-Q for the quarter ended June 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. The change in presentation for three and six months ended June 30, 2018 resulted in a reduction of “Operations and Maintenance” and an increase in “Other Expense (Income), net” on the Consolidated Statements of Earnings for the prior periods. There are $1.3 million and $1.1 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the three months ended June 30, 2018 and June 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery. There are $2.9 million and $2.7 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net” for the six months ended June 30, 2018 and June 30, 2017, respectively, net of amounts deferred as regulatory assets for future recovery.

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

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

Cash and Cash Equivalents – Cash and Cash Equivalents include all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of June 30, 2018, June 30, 2017 and December 31, 2017, the Unitil subsidiaries had deposited $2.2 million, $2.0 million and $2.9 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of June 30, 2018, June 30, 2017 and December 31, 2017.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including the level of customers enrolling in payment plans with the Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of June 30, 2018, June 30, 2017 and December 31, 2017, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)

June 30,

December 31,

2018

2017

Allowance for Doubtful Accounts

1.4

1.4

1.6

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of June 30, 2018, June 30, 2017 and December 31, 2017.


	June 30,				December 31,
Accrued Revenue ($ millions)	2018		2017		2017
Regulatory Assets – Current	$	21.2	$	29.1	$	39.5
Unbilled Revenues		8.5		7.5		13.8

Total Accrued Revenue	$	29.7	$	36.6	$	53.3

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of June 30, 2018, June 30, 2017 and December 31, 2017.


	June 30,				December 31,
Exchange Gas Receivable ($ millions)	2018		2017		2017
Northern Utilities	$	5.2	$	5.5	$	5.4
Fitchburg		0.3		0.4		0.4

Total Exchange Gas Receivable	$	5.5	$	5.9	$	5.8

Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of June 30, 2017, June 30, 2016 and December 31, 2016.


	June 30,				December 31,
Gas Inventory ($ millions)	2018		2017		2017
Natural Gas	$	0.2	$	0.2	$	0.4
Propane		0.3		0.2		0.1
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.6	$	0.5	$	0.6

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At June 30, 2018, June 30, 2017 and December 31, 2017, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $87.8 million, $82.3 million, and $84.3 million, respectively.

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


	June 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2018		2017		2017
Retirement Benefits	$	86.7	$	75.9	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		19.0		25.4		36.0
Deferred Storm Charges		6.8		7.7		7.2
Environmental		9.0		10.2		9.5
Income Taxes		6.1		7.0		6.5
Other		4.3		5.8		5.4

Total Regulatory Assets	$	131.9	$	132.0	$	149.1
Less: Current Portion of Regulatory Assets⁽¹⁾		21.2		29.1		39.5

Regulatory Assets – noncurrent	$	110.7	$	102.9	$	109.6

⁽¹⁾

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


	June 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2018		2017		2017
Rate Adjustment Mechanisms	$	14.2	$	13.1	$	6.9
Gas Pipeline Refund (Note 6)		—		3.5		2.3
Income Taxes (Note 8)		47.1		—		48.9

Total Regulatory Liabilities		61.3		16.6		58.1
Less: Current Portion of Regulatory Liabilities		14.2		16.6		9.2

Regulatory Liabilities – noncurrent	$	47.1	$	—	$	48.9

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of June 30, 2018 are $0.1 million of deferred storm charges to be recovered over the next year and $6.3 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

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

The Company has managed a regulatory approved hedging program for Northern Utilities, which is designed to fix or cap a portion of its gas supply costs for the coming years of service through the purchase of European call option contracts. Any gains or losses resulting from these option contracts are passed through to customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause. Currently, there are no active transactions and the Company has proposed to regulators to discontinue the program. This matter remains pending.

As of June 30, 2018, June 30, 2017 and December 31, 2017 the Company had zero, 1.2 billion and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

As of June 30, 2018, June 30, 2017 and December 31, 2017, the Company’s derivatives that are not designated as hedging instruments under FASB ASC 815-20 have a fair value of $0, $0.1 million and less than $0.1 million, respectively.

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

At June 30, 2018, June 30, 2017 and December 31, 2017, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.2 million, $3.4 million and $3.6 million, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense (Income), net.


	June 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2018		2017		2017
Equity Funds	$	2.9	$	1.9	$	2.1
Fixed Income Funds		2.3		1.5		1.5

Total Marketable Securities	$	5.2	$	3.4	$	3.6

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


	June 30,				December 31,
Energy Supply Obligations ($ millions)	2018		2017		2017
Current:
Exchange Gas Obligation	$	5.2	$	5.5	$	5.4
Renewable Energy Portfolio Standards		3.9		4.5		4.0
Power Supply Contract Divestitures		0.3		0.3		0.3

Total Energy Supply Obligations – Current		9.4		10.3		9.7
Noncurrent:
Power Supply Contract Divestitures		0.8		1.1		0.9

Total Energy Supply Obligations	$	10.2	$	11.4	$	10.6

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

Renewable Energy Portfolio Standards – Renewable Energy Portfolio Standards (RPS) require retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

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

Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

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

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

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

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

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

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

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

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

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period the Company did not have any material subsequent events, other than entering into its Second Amended and Restated Credit Agreement and related documents, as discussed below, that would result in adjustment to or disclosure in its unaudited consolidated financial statements.

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement with Bank of America, N.A. and the other lenders that are parties thereto (the “Second Amended Credit Facility”) and related documents. The Second Amended Credit Facility amends and restates the Amended and Restated Credit Agreement among Bank of America, N.A. and the other lenders that are parties thereto (the “Credit Facility”). The Second Amended Credit Facility maintains the current borrowing limit of $120 million under the Credit Facility. The other terms and conditions of the Second Amended Credit Facility, including affirmative and negative covenants, are generally substantially similar to those of the Credit Facility except that, among other things, (i) the Company may borrow under the Second Amended Credit Facility until July 25, 2023, subject to two one-year extensions under certain circumstances, (ii) the Company may increase the borrowing limit under the Second Amended Credit Facility by up to $50 million under certain circumstances and (iii) the Second Amended Credit Facility decreases the Applicable Margin (as defined in the Second Amended Credit Facility) from 1.25% to 1.125%.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
07/25/18	08/29/18	08/15/18	$0.365
04/25/18	05/29/18	05/15/18	$0.365
01/30/18	02/28/18	02/14/18	$0.365

10/25/17	11/29/17	11/15/17	$0.360
07/26/17	08/29/17	08/15/17	$0.360
04/26/17	05/30/17	05/16/17	$0.360
01/25/17	02/28/17	02/14/17	$0.360

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and six months ended June 30, 2018 and June 30, 2017 and as of December 31, 2017 (millions):


	Gas			Electric			Non- Regulated		Other			Total

Three Months Ended June 30, 2018
Revenues:
Billed and Unbilled Revenue	$	40.1		$	53.7		$	—	$	—		$	93.8
Rate Adjustment Mechanism Revenue		(5.4	)		(5.0	)		—		—			(10.4	)
Other Operating Revenue – Non-Regulated		—			—			1.1		—			1.1

Total Operating Revenues	$	34.7		$	48.7		$	1.1	$	—		$	84.5

Segment Profit (Loss)		(0.3	)		2.7			0.2		1.0			3.6
Capital Expenditures		18.6			7.6			—		0.9			27.1

Three Months Ended June 30, 2017
Revenues	$	32.0		$	47.4		$	1.4	$	—		$	80.8
Segment Profit (Loss)		0.1			3.1			0.1		(0.2	)		3.1
Capital Expenditures		17.0			5.5			—		4.9			27.4

Six Months Ended June 30, 2018
Revenues:
Billed and Unbilled Revenue	$	131.5		$	115.3		$	—	$	—		$	246.8
Rate Adjustment Mechanism Revenue		(9.8	)		(9.1	)		—		—			(18.9	)
Other Operating Revenue – Non-Regulated		—			—			2.4		—			2.4

Total Operating Revenues	$	121.7		$	106.2		$	2.4	$	—		$	230.3

Segment Profit		12.3			5.7			0.6		0.6			19.2
Capital Expenditures		22.2			13.6			—		1.4			37.2
Segment Assets		703.2			479.3			6.4		45.7			1,234.6

Six Months Ended June 30, 2017
Revenues	$	106.8		$	96.9		$	3.1	$	—		$	206.8
Segment Profit		10.0			5.2			0.5		(0.2	)		15.5
Capital Expenditures		22.7			13.8			—		8.4			44.9
Segment Assets		637.0			446.4			7.1		47.2			1,137.7

As of December 31, 2017
Segment Assets	$	714.3		$	476.9		$	6.7	$	44.0		$	1,241.9

NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Details on long-term debt at June 30, 2018, June 30, 2017 and December 31, 2017 are shown below:


($ millions)	June 30,				December 31,
	2018		2017		2017
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		10.0		15.0		15.0
8.49% Senior Secured Notes, Due October 14, 2024		7.5		9.0		7.5
6.96% Senior Secured Notes, Due September 1, 2028		20.0		20.0		20.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		7.6		9.5		7.6
6.79% Senior Notes, Due October 15, 2025		10.0		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		—		10.0
7.37% Senior Notes, Due January 15, 2029		12.0		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		—		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		10.0		20.0		10.0
5.29% Senior Notes, Due March 2, 2020		16.6		25.0		25.0
3.52% Senior Notes, Due November 1, 2027		20.0		—		20.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		—		30.0
Granite State:
7.15% Senior Notes, Due December 15, 2018		3.3		6.7		3.3
3.72% Senior Notes, Due November 1, 2027		15.0		—		15.0

Total Long-Term Debt		396.0		336.2		409.4
Less: Unamortized Debt Issuance Costs		3.2		2.8		3.3

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		392.8		333.4		406.1
Less: Current Portion		29.7		29.9		29.8

Total Long-term Debt, Less Current Portion	$	363.1	$	303.5	$	376.3

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

($ millions)

June 30,

December 31,

2018

2017

Estimated Fair Value of Long-Term Debt

420.5

381.5

457.1

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended and restated, modified or supplemented from time to time prior to the date of this Form 10-Q, the “Credit Facility”). The Credit Facility is a revolving facility that terminates October 4, 2020 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate (LIBOR) plus 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.


	Revolving Credit Facility ($ millions)
	June 30,				December 31,
	2018		2017		2017
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	37.4	$	79.2	$	38.3
Letters of Credit Outstanding	$	0.0	$	1.1	$	0.0

Available	$	82.6	$	39.7	$	81.7

On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement with Bank of America, N.A. and the other lenders that are parties thereto, which amended and restated the Credit Facility. (See also “Subsequent Events” in Note 1.)

The weighted average interest rates on all short-term borrowings and intercompany money pool transactions were 3.3% and 2.3% for the three months ended June 30, 2018 and June 30, 2017, respectively. The weighted average interest rate on all short-term borrowings for the twelve months ended December 31, 2017 was 2.4%.

Guarantees

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 14,114,551,14,815,585 and 14,866,588 shares of common stock outstanding at June 30, 2017, December 31, 2017 and June 30, 2018, respectively.

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

Dividend Reinvestment and Stock Purchase Plan - During the first six months of 2018, the Company sold 14,277 shares of its common stock, at an average price of $45.50 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $649,600. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

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

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

Restricted Shares

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

On January 29, 2018, 37,510 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 90,882 and 89,705 non-vested shares under the Stock Plan as of June 30, 2018 and 2017, respectively. The weighted average grant date fair value of these shares was $41.93 and $39.55, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.9 million and $2.0 million for the six months ended June 30, 2018 and 2017, respectively. At June 30, 2018, there was approximately $1.2 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. During the six months ended June 30, 2018 there were 784 shares of Restricted Shares forfeited. There were no cancellations under the Stock Plan during the six months ended June 30, 2018.

Restricted Stock Units

Non-management members of the Company’s Board of Directors (Directors) may elect to receive the equity portion of their annual retainer in the form of Restricted Stock Units. Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the six months ended June 30, 2018 in conjunction with the Stock Plan is presented in the following table:


Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2017		52,224	$	36.22
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		850	$	45.05
Restricted Stock Units Settled		—		—

Restricted Stock Units as of June 30, 2018		53,074	$	36.36

There were 44,028 Restricted Stock Units outstanding as of June 30, 2017 with a weighted average stock price of $33.60. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of June 30, 2018, June 30, 2017 and December 31, 2017 is $1.2 million, $0.9 million and $1.0 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock

There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2018, June 30, 2017 and December 31, 2017. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and six month periods ended June 30, 2018 and June 30, 2017, respectively.

NOTE 6 – REGULATORY MATTERS

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

Tax Cuts and Jobs Act of 2017

Base Rate Activity

which shall include 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. Cost recovery filings will be due February 15 for rates effect April 1. Annual reports will be due April 1 for the prior calendar year and the first term report will be due April 1, 2021. The next plan is due July 1, 2020 for the three year term 2021 to 2023, and shall include a five year strategic plan for 2021 – 2025.

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

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding – In May 2015, the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard (EERS), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Settlement, on September 1, 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plan for the period 2018-2020. The Settlement and the Statewide Energy Efficiency Plan for the period 2018-2020 were approved on January 2, 2018.

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

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

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

Fitchburg – Service Quality – On March 1, 2018, Fitchburg submitted its 2017 Service Quality Reports for both its gas and electric divisions in accordance with new Service Quality Guidelines issued by the MDPU in December 2015. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. These filings are pending approval.

Fitchburg – Energy Diversity – Massachusetts Governor Baker signed into law H.4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC), including Fitchburg, to jointly and competitively solicit proposals for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017,

for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016, and adopted as final regulations on March 8, 2017. The EDCs issued the RFP for Long-Term Contracts for Clean Energy Projects, pursuant to Section 83d on March 31, 2017 and project proposals were received on July 27, 2017. Final selection of projects concluded in the first quarter of 2018, contracts were signed in June 2018 and preparation of the regulatory approval filing is underway. The EDCs issued the RFP for Long-Term Contracts for Offshore Wind Energy Projects pursuant to Section 83c on June 29, 2017 and project proposals were received on December 20, 2017. Final selection of projects was made in late May 2018 and contract negotiation is underway.

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

Fitchburg – Other – On August 25, 2017, the Massachusetts Department of Energy Resources (DOER) issued its final Solar Massachusetts Renewable Target (SMART) Program regulations. These regulations were promulgated pursuant to Chapter 75 of the Acts of 2016, which required the DOER to establish a new solar incentive program. The regulation is designed to support the continued development of an additional 1,600 MW of solar renewable energy generating sources via a declining block compensation mechanism. On September 12, 2017, the Massachusetts electric utilities jointly filed a model SMART tariff with the MDPU to implement the program and propose a cost recovery mechanism. Hearings on the merits were held in late March and early April 2018. This filing remains pending. In the interim, the current program for solar renewable energy credits, known as SREC-II, remains in effect for all eligible solar facilities.

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

FERC Transmission Formula Rate Proceedings – Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (ROE) component of the ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating a decision of the FERC with respect to these formula rates, and remanded it for further proceedings. The FERC had found that the Transmission Owners existing ROE was unlawful, and had set a new ROE. The Court found that the FERC had failed to articulate a satisfactory

explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. Separately, on March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed return on equity component of the formula rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. The Company does not believe that these proceedings will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impact on its financial position, operating results or cash flows.

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court, (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remain pending. The Company continues to believe these claims are without merit and will continue to defend itself vigorously.

NOTE 7 – ENVIRONMENTAL MATTERS

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

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of June 30, 2018, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on the Company’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

Northern Utilities Manufactured Gas Plant Sites – Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

Northern Utilities has worked with the Maine Department of Environmental Protection (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required. Supplemental remediation at the Exeter and Somersworth MGP sites commenced in the second quarter of 2018. Activities have been completed at the Somersworth MGP site, and Northern Utilities anticipates remediation completion at the Exeter MGP site by the third quarter of 2018.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods.

The Environmental Obligations table below shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices.

Fitchburg’s Manufactured Gas Plant Site – Fitchburg has worked with the Massachusetts Department of Environmental Protection to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.

The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the six months ended June 30, 2018 and 2017.


Environmental Obligations
	($ millions)
	Fitchburg				Northern Utilities				Total
	Six months ended June 30,
	2018		2017		2018		2017		2018		2017
Total Balance at Beginning of Period	$	0.1	$	0.1	$	2.0	$	1.9	$	2.1	$	2.0
Additions		—		—		0.5		0.3		0.5		0.3
Less: Payments / Reductions		0.1		—		0.4		0.1		0.5		0.1

Total Balance at End of Period		—		0.1		2.1		2.1		2.1		2.2

Less: Current Portion		—		0.1		0.6		0.4		0.6		0.5

Noncurrent Balance at End of Period	$	—	$	—	$	1.5	$	1.7	$	1.5	$	1.7

NOTE 8: INCOME TAXES

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction to the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with GAAP Accounting Standard 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) at the new 21% tax rate at which the ADIT will be reversed in future periods. The Company recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation.

On March 15, 2018; FERC issued its Notice of Proposed Rulemaking in Docket No. RM18-11-000 in which FERC provided specific guidance on the flow back of excess ADIT: The amount of the reduction to ADIT that was collected from customers but is no longer payable to the IRS is excess ADIT and should be flowed back to ratepayers under general ratemaking principles. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of the excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA.

Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018 and as prescribed in the TCJA, the recent FERC guidance noted above and IRS normalization rules; the benefit of these excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences. The Company estimates the ARAM flow back period to be between fifteen and twenty years.

Following the enactment of the TCJA, the SEC staff issued Staff Accounting Bulletin 118—“Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. The Company’s regulators and the IRS are each expected to issue guidance in future periods that will determine the final disposition of the re-measurement of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of the TCJA and resolution of TCJA matters with the Company’s regulators may change the amounts estimated.

In addition to the excess $47.1 million ADIT amounts the Company expects to flow through to customers in utility rates, as noted above, there was $1.8 million of excess ADIT at December 31, 2017, related to the implementation of the new federal tax rate of the TCJA, which had not been previously collected from customers through utility rates. The Company will recognize a benefit in its tax provision as the underlying book/tax temporary differences reverse in the current and future periods.

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

As of December 31, 2017, the Company had recorded cumulative federal and state NOLC assets of $12.7 million to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029. In addition, at December 31, 2017, the Company

had $3.5 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable. In assessing the near-term use of NOLCs and tax credits, the Company evaluates the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income available in carryback years. Based on all available evidence, both positive and negative, and the weight of that evidence to the extent such evidence can be objectively verified, the Company expects to utilize all of its NOLCs by December 31, 2020 prior to their expiration in 2029.

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

The Company evaluated its tax positions at June 30, 2018 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2014; December 31, 2015; and December 31, 2016.

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

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

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

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


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

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


	Pension Plan						PBOP Plan						SERP Plan
Three Months Ended June 30,	2018			2017			2018			2017			2018			2017
Service Cost	$	848		$	823		$	733		$	743		$	122		$	115
Interest Cost		1,469			1,515			851			979			101			98
Expected Return on Plan Assets		(1,946	)		(1,834	)		(409	)		(336	)		—			—
Prior Service Cost Amortization		81			65			327			349			47			47
Actuarial Loss Amortization		1,447			1,155			346			525			122			74

Sub-total		1,899			1,724			1,848			2,260			392			334
Amounts Capitalized and Deferred		(908	)		(808	)		(885	)		(1,154	)		(113	)		(99	)

Net Periodic Benefit Cost Recognized	$	991		$	916		$	963		$	1,106		$	279		$	235


	Pension Plan						PBOP Plan						SERP Plan
Six Months Ended June 30,	2018			2017			2018			2017			2018			2017
Service Cost	$	1,696		$	1,647		$	1,466		$	1,487		$	244		$	230
Interest Cost		2,938			3,029			1,702			1,957			202			196
Expected Return on Plan Assets		(3,892	)		(3,653	)		(818	)		(673	)		—			—
Prior Service Cost Amortization		162			131			654			699			94			94
Actuarial Loss Amortization		2,894			2,331			692			1,049			244			148

Sub-total		3,798			3,485			3,696			4,519			784			668
Amounts Capitalized and Deferred		(1,628	)		(1,470	)		(1,627	)		(2,191	)		(226	)		(198	)

Net Periodic Benefit Cost Recognized	$	2,170		$	2,015		$	2,069		$	2,328		$	558		$	470

Employer Contributions

As of June 30, 2018, the Company had made $1.2 million and $2.0 million of contributions to its Pension and PBOP Plans, respectively, in 2018. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2018 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs. The Company currently intends to make a contribution of approximately $15 million to its Pension Plan for the remainder of 2018.

As of June 30, 2018, the Company had made $65,700 of benefit payments under the SERP Plan in 2018. The Company presently anticipates making an additional $333,500 of benefit payments under the SERP Plan in 2018.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

Item 4.

Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of June 30, 2018. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of June 30, 2018 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

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

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 1A.

Risk Factors

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

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company during the fiscal quarter ended June 30, 2018.

Issuer Purchases of Equity Securities

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2018, the Company will periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer for those Directors who elected to receive common stock. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $92,700 in value of shares have been purchased or, if sooner, on May 1, 2019.

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

The following table shows information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended June 30, 2018.


	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
4/1/18 – 4/30/18		—		—		—	$	1,856
5/1/18 – 5/31/18		—		—		—	$	92,700
6/1/18 – 6/30/18		160	$	48.00		160	$	85,020

Total		160	$	48.00		160

Item 5.

Other Information

On July 26, 2018, the Company issued a press release announcing its results of operations for the three and six month periods ended June 30, 2018. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

Item 6.

Exhibits

(a)

Exhibits


Exhibit No.	Description of Exhibit	Reference

11	Computation in Support of Earnings Per Weighted Average Common Share	Filed herewith

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

99.1	Unitil Corporation Press Release Dated July 26, 2018 Announcing Earnings For the Quarter Ended June 30, 2018.	Filed herewith

101.INS	XBRL Instance Document.	Filed herewith

101.SCH	XBRL Taxonomy Extension Schema Document.	Filed herewith

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith

101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith

SIGNATURES

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


		UNITIL CORPORATION
		(Registrant)

Date: July 26, 2018		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: July 26, 2018		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer