Edgar Filing: UNITIL CORP

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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, 2016

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 x 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 x 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. (Check one):

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

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 18, 2016
Common Stock, No par value		14,052,533 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2016

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, 2016 and 2015	19

	Consolidated Balance Sheets, June 30, 2016, June 30, 2015 and December 31, 2015	20-21

	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2016 and 2015	22

	Consolidated Statements of Changes in Common Stock Equity – Six Months Ended June 30, 2016 and 2015	23

	Notes to Consolidated Financial Statements	24-46

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	4-18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	46

Part II. Other Information

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	47

Item 6.	Exhibits	48

Signatures		49

Exhibits		50

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 103,300 electric customers and 78,700 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 $834.6 million at June 30, 2016. 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 commercial and industrial customers primarily in the northeastern United States. As an energy broker and advisor, Usource assists its clients with the procurement and contracting for electricity and natural gas in competitive energy markets.

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 traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, Unitil’s customers, with the exception of Northern Utilities’ residential customers, have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

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.

Rate Case Activity

Unitil Energy – Base Rates – On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the NHPUC. The Company is seeking an increase in base rates of approximately $6.3 million or 3.6 percent above present rates. The Company also requested a long-term rate plan for the annual recovery in future years of the costs associated with certain plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the OCA on a $2.4 million temporary rate increase effective July 1, 2016. The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The remaining issues in the rate case are pending investigation and decision by the NHPUC.

Fitchburg – Base Rates – Electric – On June 16, 2015, Fitchburg filed for a $3.8 million increase in its electric base revenue decoupling target, which represented a 5.6 percent increase over 2014 test year operating electric revenues. The filing included a request for approval of a capital cost recovery mechanism to recover additions to utility plant on an annual basis. An Order was issued on April 29, 2016 approving a $2.1 million increase effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism. On July 1, 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and presenting the associated revenue requirements for recovery beginning January 1, 2017. This filing is under MDPU review.

Fitchburg – Electric Operations – On November 17, 2015, Fitchburg submitted its 2015 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 29, 2015, effective January 1, 2016.

Fitchburg – Base Rates – Gas – On June 16, 2015, Fitchburg filed for a $3.0 million increase in its gas base revenue decoupling target, which represents an 8.3 percent increase over 2014 test year total gas operating revenues. Hearings were completed and briefs filed. An Order was issued on April 29, 2016 approving a $1.6 million increase effective May 1, 2016.

Fitchburg – Gas Operations – On October 31, 2015, Fitchburg submitted its second annual filing to recover the estimated costs to be incurred in calendar year 2016 under its approved 20 year gas system enhancement plan program. The plan was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. On April 29, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments for 2015 and 2016, effective May 1, 2016. Also on April 29, 2016, Fitchburg submitted its cost filing which documents the Company’s actual capital costs and final revenue requirement under the program for calendar year 2015. Any over or under-recovery of the Company’s 2015 revenue requirement will be reconciled in rates effective November 1, 2016. This matter remains pending.

Northern Utilities – Base Rates – Maine – The rate case settlement in Northern Utilities’ Maine division’s last rate case allowed the Company to implement a Targeted Infrastructure Replacement Adjustment (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. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. The 2016 TIRA, for 2015 expenditures, was filed on February 29, 2016, provides for an annual increase in base distribution revenue of $1.5 million, effective May 1, 2016, and was approved by the MPUC on April 28, 2016.

Northern Utilities – Targeted Area Build-out Program – Maine – On December 22, 2015 the MPUC approved a new Targeted Area Build-out 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 and is being initially piloted in the City of Saco. 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. This pilot program is planned to be built out over the next three years and has the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco pilot area. The Company will continue to evaluate the success of the program and ways to economically reach new targeted service areas.

Northern Utilities – Base Rates – New Hampshire – Northern Utilities’ New Hampshire division’s last rate case resulted in a settlement agreement providing for an increase of $4.6 million in distribution base revenue and an additional step increase in revenue of $1.4 million for investments in gas mains extensions and infrastructure replacement projects, effective May 1, 2014, and a step adjustment that provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities – Pipeline Refund – On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund is being credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities are being credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities of $5.0 million and $3.6 million, respectively, on its Consolidated Balance Sheets as of June 30, 2016.

Granite State – Base Rates – Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cost cap. On June 24, 2016 Granite State filed for an annual revenue and rate increase under this provision of $0.3 million, effective August 1, 2016. This filing was approved by the FERC on July 13, 2016.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended June 30, 2016 and June 30, 2015 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 $2.5 million, or $0.18 per share, for the second quarter of 2016, an increase of $0.8 million, or $0.06 per share, compared to the second quarter of 2015. For the six months ended June 30, 2016, the Company reported Net Income of $13.4 million, a decrease of $1.9 million compared to the same six month period in 2015. Earnings Per Share (EPS) for the six months ended June 30, 2016 were $0.96, a decrease of $0.14 per share, compared to the same period of 2015. The increase in earnings for the second quarter of 2016 was driven by higher natural gas sales margins, reflecting higher natural gas distribution rates and customer growth. The decrease in earnings for the six month period reflect lower natural gas and electric sales and margins, driven by significantly warmer winter weather in 2016 compared to 2015.

Natural gas sales margins were $19.8 million and $55.7 million in the three and six months ended June 30, 2016, respectively, resulting in an increase of $1.7 million for the three month period and a decrease of $1.2 million for the six month period compared to the same periods in 2015. Gas sales margins in the second quarter were positively affected by higher natural gas distribution rates and customer growth. For the six month period, natural gas sales margins were negatively affected by lower unit sales due to warmer winter weather, partially offset by the positive impacts of customer growth and higher natural gas distribution rates. The Company estimates that the warmer winter weather in 2016 compared to 2015 negatively impacted gas sales margins by approximately $5.0 million, or $0.22 per share.

Natural gas therm sales decreased 1.8% and 12.1% in the three and six month periods ended June 30, 2016, respectively, compared to the same periods in 2015. The decreases in gas therm sales reflect warmer weather in 2016 compared to 2015, partially offset by customer growth. Based on weather data collected in the Company’s natural gas service areas, there were 19% fewer HDD in the first six months of 2016 compared to the same period in 2015. Estimated weather-normalized gas therm sales, excluding decoupled sales, were up 2.3% in the first six months of 2016 compared to the same period in 2015. This growth was led by a year over year increase of 6.4% in gas therm sales to large industrial customers. As of June 30, 2016, the number of total natural gas customers served has increased by 1.5% in the last twelve months.

Electric sales margins were $20.4 million and $40.5 million in the three and six months ended June 30, 2016, respectively, resulting in decreases of $0.1 million and $1.2 million, respectively, compared to the same periods in 2015. These decreases reflect lower electric kilowatt-hour (kWh) sales due to warmer winter weather in 2016 and lower average usage by customers. Electric kWh sales decreased 2.9% and 5.1%, respectively in the three and six month periods ended June 30, 2016 compared to the same periods in 2015.

Operation and Maintenance (O&M) expenses decreased $0.6 million, or 3.7%, and $0.1 million, or 0.3%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. The decrease in the three month period reflects lower utility operating costs of $0.8 million, partially offset by higher compensation, health care and other benefit costs of $0.2 million. The decrease in O&M expenses in the six month period reflects lower utility operating costs of $1.1 million, partially offset by higher compensation, health care and other benefit costs of $1.0 million.

Depreciation and Amortization expense increased $0.4 million, or 3.5%, and $0.8 million, or 3.5%, in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. The increase in the three month period reflects higher depreciation of $0.7 million on normal utility plant assets in service, partially offset by lower amortization of $0.3 million. The increase in the six month period reflects higher depreciation of $1.3 million on normal utility plant assets in service, partially offset by lower amortization of $0.5 million.

Taxes Other Than Income Taxes increased $1.2 million and $1.3 million in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015, primarily reflecting higher local property tax expense.

Interest Expense, net decreased $0.3 million and $0.6 million in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015, primarily reflecting lower levels of long-term debt and higher net interest income on regulatory assets.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $1.5 million and $3.1 million for the three and six months ended June 30, 2016, respectively, on par with the same periods in 2015.

At its January 2016, April 2016 and July 2016 meetings, Unitil’s Board of Directors declared quarterly dividends on the Company’s common stock of $0.3550 per share, resulting in an increase in the effective annual dividend rate to $1.42 per share from $1.40 per share. These dividend declarations continue 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, 2016 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas decreased 1.8% and 12.1% in the three and six month periods ended June 30, 2016, respectively, compared to the same periods in 2015. In the second quarter of 2016, sales to Residential and Commercial and Industrial (C&I) customers decreased 5.8% and 0.8%, respectively, compared to the same period in 2015, reflecting warmer early spring weather in 2016 compared to 2015, partially offset by customer growth. For the six months ended June 30, 2016, sales to Residential and C&I customers decreased 17.2% and 10.5%, respectively, compared to the same period in 2015. The decrease in gas therm sales in the Company’s service areas was driven by warmer winter weather in the first six months of 2016 compared to 2015, partially offset by customer growth. Based on weather data collected in the Company’s natural gas service areas, there were 19% fewer HDD in the first six months of 2016 compared to the same period in 2015. Estimated weather-normalized gas therm sales, excluding decoupled sales, were up 2.3% in the first six months of 2016 compared to the same period in 2015. This growth was led by a year over year increase of 6.4% in gas therm sales to large industrial customers. As of June 30, 2016, the number of total natural gas customers served has increased by 1.5% in the last twelve months. As discussed above, sales margin derived from decoupled unit sales (representing approximately 11% of total annual therm sales volume) is not sensitive to changes in gas therm sales.

The following table details total firm therm sales for the three and six months ended June 30, 2016 and 2015, by major customer class:


Therm Sales (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2016		2015		Change			% Change			2016		2015		Change			% Change
Residential		8.1		8.6		(0.5	)		(5.8	%)		27.9		33.7		(5.8	)		(17.2	%)
Commercial / Industrial		35.5		35.8		(0.3	)		(0.8	%)		98.6		110.2		(11.6	)		(10.5	%)

Total		43.6		44.4		(0.8	)		(1.8	%)		126.5		143.9		(17.4	)		(12.1	%)

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, 2016 and 2015:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2016		2015		$ Change			% Change			2016		2015		$ Change			% Change
Gas Operating Revenue:
Residential	$	11.4	$	10.6	$	0.8			7.5	%	$	40.8	$	51.1	$	(10.3	)		(20.2	%)
Commercial / Industrial		17.5		17.0		0.5			2.9	%		61.2		76.8		(15.6	)		(20.3	%)

Total Gas Operating Revenue	$	28.9	$	27.6	$	1.3			4.7	%	$	102.0	$	127.9	$	(25.9	)		(20.3	%)

Cost of Gas Sales	$	9.1	$	9.5	$	(0.4	)		(4.2	%)	$	46.3	$	71.0	$	(24.7	)		(34.8	%)

Gas Sales Margin	$	19.8	$	18.1	$	1.7			9.4	%	$	55.7	$	56.9	$	(1.2	)		(2.1	%)

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is a better measure to analyze profitability than Total Gas Operating Revenue because the approved cost of sales are tracked and reconciled to 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 $19.8 million and $55.7 million in the three and six months ended June 30, 2016, respectively, resulting in an increase of $1.7 million for the three month period and a decrease of $1.2 million for the six month period compared to the same periods in 2015. Gas sales margins in the second quarter were positively affected by $1.1 million from customer growth and $0.7 million in higher natural gas distribution rates, partially offset by the negative impact of $0.1 million from warmer early spring weather. For the six month period, the warmer winter weather in 2016 compared to 2015 had a negative impact on gas sales margins of approximately $5.0 million, which was partially offset by the positive impacts of $2.0 million from customer growth and $1.8 million in higher natural gas distribution rates.

The increase in Total Gas Operating Revenues of $1.3 million in the second quarter of 2016 reflects higher gas base rates and customer growth, partially offset by lower sales volumes and lower cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers.

The decrease in Total Gas Operating Revenues of $25.9 million in the first six months of 2016 reflects higher gas base rates and customer growth, partially offset by lower sales volumes and lower cost of gas sales, which are tracked and reconciled costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales decreased 2.9% and 5.1%, respectively in the three and six month periods ended June 30, 2016 compared to the same periods in 2015. Sales to Residential customers decreased 3.8% and 8.4%, respectively, in the three and six month periods ended June 30, 2016 compared to the same periods in 2015. Sales to C&I customers decreased 2.4% and 2.8%, respectively, in the three and six month periods ended

June 30, 2016 compared to the same periods in 2015. These decreases reflect warmer winter and early spring weather in 2016 compared to 2015. As discussed above, sales margin derived from RDM decoupled unit sales (representing approximately 27% of total annual kWh sales volume) is not sensitive to changes in electric kWh sales.

The following table details total kWh sales for the three and six months ended June 30, 2016 and 2015 by major customer class:


kWh Sales (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2016		2015		Change			% Change			2016		2015		Change			% Change
Residential		138.8		144.3		(5.5	)		(3.8	%)		314.2		342.9		(28.7	)		(8.4	%)
Commercial / Industrial		234.6		240.4		(5.8	)		(2.4	%)		476.5		490.2		(13.7	)		(2.8	%)

Total		373.4		384.7		(11.3	)		(2.9	%)		790.7		833.1		(42.4	)		(5.1	%)

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, 2016 and 2015:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,										Six Months Ended June 30,
	2016		2015		$ Change			% Change			2016		2015		$ Change			% Change
Electric Operating Revenue:
Residential	$	24.3	$	27.6	$	(3.3	)		(12.0	%)	$	54.4	$	70.3	$	(15.9	)		(22.6	%)
Commercial / Industrial		19.8		20.8		(1.0	)		(4.8	%)		40.8		48.4		(7.6	)		(15.7	%)

Total Electric Operating Revenue	$	44.1	$	48.4	$	(4.3	)		(8.9	%)	$	95.2	$	118.7	$	(23.5	)		(19.8	%)

Cost of Electric Sales	$	23.7	$	27.9	$	(4.2	)		(15.1	%)	$	54.7	$	77.0	$	(22.3	)		(29.0	%)

Electric Sales Margin	$	20.4	$	20.5	$	(0.1	)		(0.5	%)	$	40.5	$	41.7	$	(1.2	)		(2.9	%)

The Company analyzes operating results using Electric Sales Margin, a non-GAAP measure. Electric Sales Margin is calculated as Total Electric Operating Revenues less Cost of Electric Sales. The Company believes Electric Sales Margin is a better measure to analyze profitability than Total Electric Operating Revenues because the approved cost of sales are tracked and reconciled to 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 $20.4 million and $40.5 million in the three and six months ended June 30, 2016, respectively, resulting in decreases of $0.1 million and $1.2 million, respectively, compared to the same periods in 2015. Electric sales margins in the second quarter reflect lower average usage of $0.5 million, partially offset by the positive impact of higher electric distribution rates of $0.4 million. For the six month period, electric sales margins reflect lower average usage of $1.0 million and the negative impact of warmer winter weather in 2016 compared to 2015 of $0.6 million, partially offset by the positive impact of higher electric distribution rates of $0.4 million.

The decrease in Total Electric Operating Revenues of $4.3 million in the second quarter of 2016 reflects lower electric sales volumes and lower cost of electric sales, which are tracked and reconciled to costs that are passed through directly to customers.

The decrease in Total Electric Operating Revenues of $23.5 million in the first six months of 2016 reflects lower electric sales volumes and lower cost of electric sales, which are tracked and reconciled to costs that are passed through directly to customers.

Operating Revenue – Other

The following table details total Other Revenue for the three and six months ended June 30, 2016 and 2015:


Other Revenue (000’s)
	Three Months Ended June 30,								Six Months Ended June 30,
	2016		2015		$ Change		% Change		2016		2015		$ Change		% Change
Other	$	1.5	$	1.5	$	—		—	$	3.1	$	3.1	$	—		—

Total Other Revenue	$	1.5	$	1.5	$	—		—	$	3.1	$	3.1	$	—		—

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues were on par in each of the three and six month periods ended June 30, 2016 compared to the same periods in 2015. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

Operating Expenses

Cost of Gas Sales – Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $0.4 million, or 4.2%, and $24.7 million, or 34.8%, in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. The decrease in the three month period primarily reflects lower sales of natural gas, lower wholesale natural gas prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The decrease in the six month period reflects lower sales of natural gas and lower wholesale natural gas prices, partially offset by a decrease in the amount of natural gas purchased by customers directly from third-party suppliers. The 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 decreased $4.2 million, or 15.1%, and $22.3 million, or 29.0%, in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. These decreases reflect lower wholesale electricity prices, lower electric sales and an increase 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 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. Total O&M expenses decreased $0.6 million, or 3.7%, and $0.1 million, or 0.3%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. The decrease in the three month period reflects lower utility operating costs of $0.8 million, partially offset by higher compensation, health care and other benefit costs of $0.2 million. The decrease in O&M expenses in the six month period reflects lower utility operating costs of $1.1 million, partially offset by higher compensation, health care and other benefit costs of $1.0 million.

Depreciation and Amortization – Depreciation and Amortization expense increased $0.4 million, or 3.5%, and $0.8 million, or 3.5%, in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. The increase in the three month period reflects higher depreciation of $0.7 million on normal utility plant assets in service, partially offset by lower amortization of $0.3 million. The increase in the six month period reflects higher depreciation of $1.3 million on normal utility plant assets in service, partially offset by lower amortization of $0.5 million.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes increased $1.2 million, or 33.3%, and $1.3 million, or 15.3%, in the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015, primarily reflecting higher local property tax expense.

Other Expense, net – Other Expense, net was relatively unchanged in the three month period ended June 30, 2016 compared to the same periods in 2015 and decreased $0.1 million in the six months ended June 30, 2016 compared to the same period in 2015.

Income Taxes – Federal and State Income Taxes increased by $0.1 million for the three months ended June 30, 2016 compared to the same period in 2015, reflecting higher pre-tax earnings. Federal and State Income Taxes decreased by $1.8 million for the six months ended June 30, 2016 compared to the same period in 2015, reflecting lower pre-tax earnings.

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

Unitil’s utility subsidiaries operate a number of reconciling rate 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,
	2016			2015			Change			2016			2015			Change
Interest Expense
Long-term Debt	$	5.4		$	5.5		$	(0.1	)	$	10.8		$	11.0		$	(0.2	)
Short-term Debt		0.3			0.2			0.1			0.6			0.5			0.1
Regulatory Liabilities		0.2			0.3			(0.1	)		0.3			0.5			(0.2	)

Subtotal Interest Expense		5.9			6.0			(0.1	)		11.7			12.0			(0.3	)

Interest (Income)
Regulatory Assets		—			0.1			(0.1	)		(0.2	)		0.1			(0.3	)
AFUDC⁽¹⁾ and Other		(0.2	)		(0.1	)		(0.1	)		(0.3	)		(0.3	)		—

Subtotal Interest (Income)		(0.2	)		—			(0.2	)		(0.5	)		(0.2	)		(0.3	)

Total Interest Expense, net	$	5.7		$	6.0		$	(0.3	)	$	11.2		$	11.8		$	(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. At June 30, 2016, June 30, 2015 and December 31, 2015, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

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 $105.6 million and $73.0 million for the six months ended June 30, 2016 and June 30, 2015, respectively. Total gross repayments were $93.5 million and $102.3 million for the six months ended June 30, 2016 and June 30, 2015, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of June 30, 2016, June 30, 2015 and December 31, 2015:


	Revolving Credit Facility ($ millions)
	June 30,				December 31,
	2016		2015		2015
Limit	$	120.0	$	120.0	$	120.0
Outstanding	$	54.2	$	0.0	$	42.0
Available	$	65.8	$	120.0	$	78.0

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At June 30, 2016, June 30, 2015 and December 31, 2015, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 5.)

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services.

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, 2016, there are $2.6 million of current and $9.1 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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

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, 2016, there were approximately $28.9 million of guarantees outstanding and the longest term guarantee extends through April 2017.

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 $7.6 million, $6.8 million and $10.8 million of natural gas storage inventory at June 30, 2016, June 30, 2015 and December 31, 2015, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2016 and payable in July 2016 is less than $0.1 million and is recorded in Accounts Payable at June 30, 2016. The amount of natural gas inventory released in June 2015 and payable in July 2015 was $0.1 million and is recorded in Accounts Payable at June 30, 2015. The amount of natural gas inventory released in December 2015 and payable in January 2016 was $0.6 million and was recorded in Accounts Payable at December 31, 2015.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of June 30, 2016, the principal amount outstanding for the 8% Unitil Realty notes was $0.8 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 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’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, 2016, there were approximately $28.9 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 April 2017. 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. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the 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 January 28, 2016.

LABOR RELATIONS

As of June 30, 2016, the Company and its subsidiaries had 501 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of June 30, 2016, a total of 164 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, 2016:


	Employees Covered		CBA Expiration
Fitchburg		46		05/31/2019
Northern Utilities NH Division		36		06/05/2017
Northern Utilities ME Division/Granite State		39		03/31/2017
Unitil Energy		38		05/31/2018
Unitil Service		5		05/31/2018

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

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest 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 for the three months ended June 30, 2016 and June 30, 2015 were 1.72% and 1.58%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2016 and June 30, 2015 were 1.71% and 1.57%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2015 was 1.55%.

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 the reconciliation and collection of approved purchased electricity and gas costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

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,
	2016		2015		2016		2015
Operating Revenues
Gas	$	28.9	$	27.6	$	102.0	$	127.9
Electric		44.1		48.4		95.2		118.7
Other		1.5		1.5		3.1		3.1

Total Operating Revenues		74.5		77.5		200.3		249.7

Operating Expenses
Cost of Gas Sales		9.1		9.5		46.3		71.0
Cost of Electric Sales		23.7		27.9		54.7		77.0
Operation and Maintenance		15.7		16.3		33.1		33.2
Depreciation and Amortization		11.7		11.3		23.5		22.7
Taxes Other Than Income Taxes		4.8		3.6		9.8		8.5

Total Operating Expenses		65.0		68.6		167.4		212.4

Operating Income		9.5		8.9		32.9		37.3
Interest Expense, net		5.7		6.0		11.2		11.8
Other Expense, net		0.1		0.1		0.1		0.2

Income Before Income Taxes		3.7		2.8		21.6		25.3
Income Tax Expense		1.2		1.1		8.2		10.0


Net Income	$	2.5	$	1.7	$	13.4	$	15.3


Net Income Per Common Share (Basic and Diluted)	$	0.18	$	0.12	$	0.96	$	1.10
Weighted Average Common Shares Outstanding – (Basic and Diluted)		14.0		13.9		14.0		13.9
Dividends Declared Per Share of Common Stock	$	0.355	$	0.350	$	0.71	$	0.70

(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,
	2016		2015		2015
ASSETS:

Current Assets:
Cash and Cash Equivalents	$	7.9	$	16.1	$	8.7
Accounts Receivable, net		42.9		52.3		49.8
Accrued Revenue		31.9		28.6		38.4
Exchange Gas Receivable		8.0		7.2		11.1
Gas Inventory		0.4		0.5		0.8
Prepayments and Other		14.6		14.0		11.7

Total Current Assets		105.7		118.7		120.5

Utility Plant:
Gas		589.1		532.1		576.8
Electric		421.2		396.4		408.4
Common		35.6		35.0		35.5
Construction Work in Progress		69.6		57.4		59.9

Total Utility Plant		1,115.5		1,020.9		1,080.6
Less: Accumulated Depreciation		280.9		263.9		271.7

Net Utility Plant		834.6		757.0		808.9

Other Noncurrent Assets:
Regulatory Assets		98.1		104.3		99.6
Other Assets		13.3		13.9		9.8

Total Other Noncurrent Assets		111.4		118.2		109.4

TOTAL ASSETS	$	1,051.7	$	993.9	$	1,038.8

(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,
	2016		2015		2015
LIABILITIES AND CAPITALIZATION:

Current Liabilities:
Accounts Payable	$	21.4	$	19.0	$	33.3
Short-Term Debt		54.2		—		42.0
Long-Term Debt, Current Portion		17.2		3.8		17.1
Regulatory Liabilities		15.9		31.2		15.6
Energy Supply Obligations		12.8		13.8		14.6
Environmental Obligations		0.3		3.4		1.3
Capital Lease Obligations		3.1		0.4		3.1
Interest Payable		3.5		3.5		3.4
Taxes Payable		0.4		9.1		2.4
Other Current Liabilities		10.2		10.0		11.5

Total Current Liabilities		139.0		94.2		144.3

Noncurrent Liabilities:
Retirement Benefit Obligations		128.3		124.2		124.4
Deferred Income Taxes, net		95.6		75.0		87.5
Cost of Removal Obligations		74.9		68.1		70.1
Regulatory Liabilities		3.7		11.0		8.1
Capital Lease Obligations		9.7		9.5		11.0
Environmental Obligations		2.7		2.0		1.5
Other Noncurrent Liabilities		4.5		3.5		3.6

Total Noncurrent Liabilities		319.4		293.3		306.2

Capitalization:
Long-Term Debt, Less Current Portion		305.2		325.9		305.5
Stockholders’ Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 14,052,096, 13,974,576 and 13,991,430 Shares)		239.4		236.4		237.5
Retained Earnings		48.5		43.9		45.1

Total Common Stock Equity		287.9		280.3		282.6
Preferred Stock		0.2		0.2		0.2

Total Stockholders’ Equity		288.1		280.5		282.8

Total Capitalization		593.3		606.4		588.3

Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,051.7	$	993.9	$	1,038.8

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Six Months Ended June 30,
	2016			2015
Operating Activities:
Net Income	$	13.4		$	15.3
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		23.5			22.7
Deferred Tax Provision		8.9			(0.7	)
Changes in Working Capital Items:
Accounts Payable		(11.9	)		(25.2	)
Accounts Receivable		6.9			8.4
Accrued Revenue		6.5			19.9
Exchange Gas Receivable		3.1			7.8
Regulatory Liabilities		0.3			22.5
Taxes Payable		(2.0	)		9.0
Other Changes in Working Capital Items		(3.8	)		(3.2	)
Deferred Regulatory and Other Charges		(7.7	)		7.0
Other, net		3.0			6.9

Cash Provided by Operating Activities		40.2			90.4

Investing Activities:
Property, Plant and Equipment Additions		(39.6	)		(38.4	)

Cash (Used in) Investing Activities		(39.6	)		(38.4	)

Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net		12.2			(29.3	)
Repayment of Long-Term Debt		(0.3	)		(0.2	)
(Decrease) Increase in Capital Lease Obligations		(1.3	)		1.9
Net Decrease in Exchange Gas Financing		(2.7	)		(7.5	)
Dividends Paid		(10.0	)		(9.8	)
Proceeds from Issuance of Common Stock, net		0.7			0.6

Cash (Used in) Financing Activities		(1.4	)		(44.3	)

Net (Decrease) Increase in Cash and Cash Equivalents		(0.8	)		7.7
Cash and Cash Equivalents at Beginning of Period		8.7			8.4

Cash and Cash Equivalents at End of Period	$	7.9		$	16.1

Supplemental Cash Flow Information:
Interest Paid	$	11.4		$	12.0
Income Taxes Paid	$	1.6		$	1.5
Payments on Capital Leases	$	1.7		$	0.3
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	1.9		$	1.0

(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, 2016	$	237.5	$	45.1		$	282.6
Net Income				13.4			13.4
Dividends on Common Shares				(10.0	)		(10.0	)
Stock Compensation Plans		1.2					1.2
Issuance of 16,646 Common Shares		0.7					0.7

Balance at June 30, 2016	$	239.4	$	48.5		$	287.9


Balance at January 1, 2015	$	234.7	$	38.4		$	273.1
Net Income				15.3			15.3
Dividends on Common Shares				(9.8	)		(9.8	)
Stock Compensation Plans		1.1					1.1
Issuance of 19,411 Common Shares		0.6					0.6

Balance at June 30, 2015	$	236.4	$	43.9		$	280.3

(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, 2016 are not necessarily indicative of results to be expected for the year ending December 31, 2016. 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, 2015, as filed with the Securities and Exchange Commission (SEC) on January 28, 2016, for a description of the Company’s Basis of Presentation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation.

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

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

In the first quarter of 2016, the Company adopted ASU 2015-17 which simplifies the presentation of deferred income taxes in a classified statement of financial position. Current generally accepted accounting principles (GAAP) require an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. ASU 2015-17 amends current GAAP to require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position.

For all periods presented in this Form 10-Q for the quarter ended June 30, 2016, deferred income taxes are reported as “Deferred Income Taxes” in the “Noncurrent Liabilities” section on the Consolidated Balance Sheets. Prior to adoption, the Company reported deferred income taxes in either the “Current Assets” or “Current Liabilities” and “Other Noncurrent Assets” or “Noncurrent Liabilities” sections on the Consolidated Balance Sheets, depending on whether the net current deferred income taxes and net noncurrent deferred income taxes were in an asset or liability position, respectively. The change in presentation for the quarter ended June 30, 2016 resulted in a reduction of both “Current Assets” and “Noncurrent Liabilities” for all prior periods presented.

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of

their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of June 30, 2016, June 30, 2015 and December 31, 2015, the Unitil subsidiaries had deposited $1.7 million, $0.7 million and $2.3 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. As of June 30, 2016, June 30, 2015 and December 31, 2015, there was $0, $0.1 million and $0, respectively, deposited for this purpose.

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, 2016, June 30, 2015 and December 31, 2015, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)

June 30,

December 31,

2016

2015

Allowance for Doubtful Accounts

1.5

2.0

1.2

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, 2016, June 30, 2015 and December 31, 2015.


	June 30,				December 31,
Accrued Revenue ($ millions)	2016		2015		2015
Regulatory Assets – Current	$	25.2	$	22.6	$	26.8
Unbilled Revenues		6.7		6.0		11.6

Total Accrued Revenue	$	31.9	$	28.6	$	38.4

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, 2016, June 30, 2015 and December 31, 2015.


	June 30,				December 31,
Exchange Gas Receivable ($ millions)	2016		2015		2015
Northern Utilities	$	7.6	$	6.7	$	10.3
Fitchburg		0.4		0.5		0.8

Total Exchange Gas Receivable	$	8.0	$	7.2	$	11.1

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, 2016, June 30, 2015 and December 31, 2015.


	June 30,				December 31,
Gas Inventory ($ millions)	2016		2015		2015
Natural Gas	$	0.1	$	0.2	$	0.3
Propane		0.2		0.2		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.2

Total Gas Inventory	$	0.4	$	0.5	$	0.8

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, 2016, June 30, 2015 and December 31, 2015, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $74.9 million, $68.1 million, and $70.1 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)	2016		2015		2015
Retirement Benefits	$	64.5	$	65.1	$	64.7
Energy Supply & Tracker Mechanisms		19.7		17.4		21.3
Deferred Storm Charges		12.5		18.6		15.4
Environmental		12.3		10.9		11.2
Income Taxes		7.9		9.1		8.5
Other		6.4		5.8		5.3

Total Regulatory Assets	$	123.3	$	126.9	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		25.2		22.6		26.8

Regulatory Assets – noncurrent	$	98.1	$	104.3	$	99.6

⁽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)	2016		2015		2015
Tracker Mechanisms	$	11.0	$	20.2	$	8.0
Gas Pipeline Refund (Note 6)		8.6		22.0		15.7

Total Regulatory Liabilities		19.6		42.2		23.7
Less: Current Portion of Regulatory Liabilities		15.9		31.2		15.6

Regulatory Liabilities – noncurrent	$	3.7	$	11.0	$	8.1

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, 2016 are $4.9 million of deferred storm charges to be recovered over the next two and a half years and $8.4 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven and a half 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 a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. The Company purchases call option contracts on NYMEX natural gas futures contracts for future winter period months.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas 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 Clause.

As of June 30, 2016, June 30, 2015 and December 31, 2015 the Company had 2.4 billion, 2.9 billion and 2.5 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

As of June 30, 2016, June 30, 2015 and December 31, 2015, the Company’s derivatives that are not designated as hedging instruments under FASB ASC 815-20 have a fair value of $0.2 million, $0.1 million and less than $0.1 million, respectively.

Investments in Marketable Securities – In 2015, the Company established a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 9.

At June 30, 2016, June 30, 2015 and December 31, 2015, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $1.9 million, $0.7 million and $0.7 million, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, net.


	June 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2016		2015		2015
Equity Funds	$	1.1	$	0.4	$	0.4
Fixed Income Funds		0.8		0.3		0.3

Total Marketable Securities	$	1.9	$	0.7	$	0.7

Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current and noncurrent Energy Supply Obligations on the Company’s Consolidated Balance Sheets.


	June 30,				December 31,
Energy Supply Obligations ($ millions)	2016		2015		2015
Current:
Exchange Gas Obligation	$	7.6	$	6.7	$	10.3
Renewable Energy Portfolio Standards		4.9		6.7		4.0
Power Supply Contract Divestitures		0.3		0.4		0.3

Total Energy Supply Obligations – Current		12.8		13.8		14.6
Long-Term:
Power Supply Contract Divestitures		1.4		1.8		1.6

Total Energy Supply Obligations	$	14.2	$	15.6	$	16.2

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.

In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The generating facilities associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker rate 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).

Massachusetts Green Communities Act – In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with two of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Debt Issuance Costs – In the first quarter of 2016, the Company adopted Accounting Standards Update (ASU) 2015-03, which requires entities to present debt issuance costs related to a debt liability as a direct deduction from the carrying amount of that debt liability on the balance sheet as opposed to being presented as a deferred charge, and ASU 2015-15, which adds paragraphs to ASU 2015-03 indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line of credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings on the line of credit arrangement.

For all periods presented in this Form 10-Q for the quarter ended June 30, 2016, unamortized debt issuance costs related to the Company’s long-term debt are reported on the Consolidated Balance Sheets as a reduction of the carrying value of the related debt. Prior to adoption, the Company reported the unamortized debt issuance costs in “Other Assets” on the Consolidated Balance Sheets. The change in presentation resulted in a reduction of “Other Assets” and “Long-Term Debt” of $3.0 million and $2.9 million as of June 30, 2015 and December 31, 2015, respectively.

Recently Issued Pronouncements – In April and March 2016, the FASB issued ASU 2016-10 and ASU 2016-08, respectively. ASU 2016-10 clarifies the implementation guidance on licensing and the identification of performance obligations considerations included in ASU 2014-09. ASU 2016-08 provides amendments to clarify the implementation guidance on principal versus agent considerations included in ASU 2014-09. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In March 2016, the FASB issued ASU 2016-09, which provides for improvements to employee share-based payment accounting. ASU 2016-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In February 2016, the FASB issued ASU 2016-02, which replaces the existing guidance in Accounting Standard Codification 840, Leases. ASU 2016-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. ASU 2016-02 requires a dual approach for lessee accounting under which a lessee would account for leases as finance (also referred to as capital) leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use asset and corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the right-of-use asset and for operating leases the lessee would recognize straight-line total lease expense. The Company is evaluating the impact that this new guidance will have 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 that impacted its unaudited consolidated financial statements.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
07/20/16	08/26/16	08/12/16	$ 0.355
04/20/16	05/27/16	05/13/16	$ 0.355
01/27/16	02/26/16	02/12/16	$ 0.355

10/21/15	11/27/15	11/13/15	$ 0.350
07/22/15	08/28/15	08/14/15	$ 0.350
04/22/15	05/28/15	05/14/15	$ 0.350
01/26/15	02/27/15	02/13/15	$ 0.350

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and six months ended June 30, 2016 and June 30, 2015 and as of December 31, 2015 (millions):


Three Months Ended June 30, 2016	Gas			Electric		Non- Regulated		Other		Total
Revenues	$	28.9		$	44.1	$	1.5	$	—	$	74.5
Segment Profit (Loss)		—			2.1		0.3		0.1		2.5
Capital Expenditures		18.8			7.3		—		2.2		28.3

Three Months Ended June 30, 2015
Revenues	$	27.6		$	48.4	$	1.5	$	—	$	77.5
Segment Profit (Loss)		(0.7	)		1.9		0.3		0.2		1.7
Capital Expenditures		15.6			7.3		0.1		2.3		25.3

Six Months Ended June 30, 2016
Revenues	$	102.0		$	95.2	$	3.1	$	—	$	200.3
Segment Profit		9.4			3.4		0.6		—		13.4
Capital Expenditures		21.9			13.0		—		4.7		39.6
Segment Assets		593.8			419.4		7.0		31.5		1,051.7

Six Months Ended June 30, 2015
Revenues	$	127.9		$	118.7	$	3.1	$	—	$	249.7
Segment Profit		10.9			3.7		0.6		0.1		15.3
Capital Expenditures		22.8			11.7		0.1		3.8		38.4
Segment Assets		573.8			406.5		6.0		7.6		993.9

As of December 31, 2015
Segment Assets	$	590.9		$	415.1	$	6.5	$	26.3	$	1,038.8

NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Details on long-term debt at June 30, 2016, June 30, 2015 and December 31, 2015 are shown below:


($ millions)	June 30,				December 31,
	2016		2015		2015
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0

Unitil Energy Systems, Inc.:
First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0		15.0
8.49% Series, Due October 14, 2024		12.0		15.0		12.0
6.96% Series, Due September 1, 2028		20.0		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0		15.0

Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		11.4		15.2		11.4
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0

Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0		50.0

Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0		10.0

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		0.8		1.5		1.1

Total Long-Term Debt		325.2		332.7		325.5
Less: Unamortized Debt Issuance Costs		2.8		3.0		2.9

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		322.4		329.7		322.6
Less: Current Portion		17.2		3.8		17.1

Total Long-term Debt, Less Current Portion	$	305.2	$	325.9	$	305.5

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,

2016

2015

Estimated Fair Value of Long-Term Debt

372.8

365.6

345.2

Credit Arrangements

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


	Revolving Credit Facility ($ millions)
	June 30,				December 31,
	2016		2015		2015
Limit	$	120.0	$	120.0	$	120.0
Outstanding	$	54.2	$	0.0	$	42.0
Available	$	65.8	$	120.0	$	78.0

The weighted average interest rates on all short-term borrowings were 1.7% and 1.6% for the six months ended June 30, 2016 and June 30, 2015, respectively. The weighted average interest rate on all short-term borrowings for the twelve months ended December 31, 2015 was 1.5%.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services.

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 13,974,576, 13,991,430 and 14,052,096 shares of common stock outstanding at June 30, 2015, December 31, 2015 and June 30, 2016, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first six months of 2016, the Company sold 16,646 shares of its common stock, at an average price of $39.58 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $659,000. 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 26, 2016, 43,220 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. On April 19, 2016, 800 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of less than $0.1 million. There were 95,506 and 80,588 non-vested shares under the Stock Plan as of June 30, 2016 and 2015, respectively. The weighted average grant date fair value of these shares was $35.30 and $33.14, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.8 million and $1.5 million for the six months ended June 30, 2016 and 2015, respectively. At June 30, 2016, there was approximately $1.6 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. There were no forfeitures or cancellations under the Stock Plan during the six months ended June 30, 2016.

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, 2015 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2015		33,588	$	31.83
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		604	$	39.66
Restricted Stock Units Settled		—		—

Restricted Stock Units as of June 30, 2016		34,192	$	31.97

There were 24,062 Restricted Stock Units outstanding as of June 30, 2015 with a weighted average stock price of $29.98. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of June 30, 2016, June 30, 2015 and December 31, 2015 is $0.6 million, $0.3 million and $0.5 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 1,898 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2016 and December 31, 2015. There was $0.2 million, or 2,059 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2015. 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, 2016 and June 30, 2015, 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, 2015 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2016.

Rate Case Activity

The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The remaining issues in the rate case are pending investigation and decision by the NHPUC.

Fitchburg – 2011 Storm Cost Deferral and 2012 Storm Costs – As part of its May 30, 2014 order approving a base rate increase for Fitchburg, the MDPU approved the recovery over three years, without carrying charges, of $5.0 million of costs of repair for damage due to severe storms, including previously deferred costs incurred in 2011, as well as costs incurred in 2012 as a result of Superstorm Sandy.

Unitil Energy – 2012 Storm Costs – On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy, in October 2012, over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period. Thanksgiving 2014 Snow Storm – Unitil Energy requested recovery of $1.7 million for the repair of damage due to this storm through its approved storm reserve fund. On July 1, 2016, the NHPUC Staff issued a letter indicating that the Company’s filing is in compliance with prior NHPUC orders.

The Company does not believe that its storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

NHPUC Energy Efficiency Resource Standard Proceeding – In May 2015 the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard, an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. In this proceeding the Commission will define the savings targets and address issues related to public and private funding; program cost recovery; lost-revenue recovery (e.g. decoupling); performance-based incentives and penalties; program administration; and evaluation measurement, and verification. Initial and reply comments were filed by interested parties. On April 27, 2016, the parties filed a settlement which remains pending.

Other Matters

Unitil Energy – Other – 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 has engaged a consultant to direct a Working Group to investigate these issues over the next year and to prepare a final report with recommendations for the Commission. Unitil Energy is an active participant in the Working Group. This matter remains pending.

Pursuant to legislation that became effective in May 2016, the NHPUC has opened a proceeding to consider alternatives to the net metering tariffs currently in place. The legislation requires that a decision on this matter must be issued by the NHPUC by March 2, 2017. Unitil Energy is an active participant in this proceeding.

Fitchburg – Service Quality – On March 1, 2016, Fitchburg submitted its 2015 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. On November 25, 2015, the MDPU approved Fitchburg’s 2014 gas division Service Quality Report as filed. On March 10, 2016, the MDPU approved Fitchburg’s 2013 electric division Service Quality Report as filed. On July 12, 2016, the MDPU approved Fitchburg’s 2014 electric division Service Quality Report as filed. Fitchburg’s 2015 gas and electric division Service Quality Reports remain pending.

MDPU Service Quality Guidelines – In December 2015, the MDPU issued its final order adopting new and revised Service Quality Guidelines. The Company has generally been able to meet or exceed the performance metrics of the previous Service Quality Guidelines and believes that it will continue to meet or exceed the performance metrics under the new and revised Guidelines.

Fitchburg – Other – 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. These filings are currently under MDPU review and remain pending.

On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its EES; 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 Proceeding – On December 28, 2015, FERC issued an order, pursuant to Section 206 of the Federal Power Act, instituting a proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin as of January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Town of Lunenburg has filed a separate action in the Court arising out of the December 2008 ice storm. The Company continues to believe that both of these suits are without merit and will continue to defend itself vigorously. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

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, 2015 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2016.

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, 2016, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

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 the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston, Portland and Scarborough sites, though future activities may be required.

Although remediation at the site in Exeter has been substantially completed, sediment contamination attributed to the former MGP was identified off-site. This off-site location has been investigated and associated remediation activities were completed in January 2016. The closure report, submitted by Northern Utilities in May 2016, remains under review by the NH DES.

At the site in Somersworth, the NH DES in February 2016 requested that Northern Utilities prepare a work plan to investigate an on-site, groundwater impact. The work plan was submitted in April 2016 and subsequently approved in June 2016. The investigation is expected to be completed by October 2016.

In Lewiston, on-site monitoring continues. Following the completion of 10-year maintenance activities in early 2016, Northern Utilities requested an engineering study to determine closure estimates for the ongoing monitoring in Lewiston. The closure estimates were submitted In May 2016 with the recommendation that monitoring continue for another 10-year time period after which a review will be conducted.

The site in Portland has been investigated and remedial activities have largely been completed. Final remediation activities were completed in the fourth quarter of 2015, and closure documentation will be submitted to the ME DEP in the third quarter of 2016. The State of Maine completed its taking of the site via eminent domain for the expansion of the adjacent International Marine Terminal in the second quarter of 2014. As a result of this taking, and pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the site will be primarily the responsibility of the State of Maine.

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, without carrying costs. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods, without carrying costs.

The Environmental Obligations (Table A 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 completed the scheduled site work at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the fourth quarter of 2014. The closure documentation for the site was submitted in the fourth quarter of 2015 and is under review by the Massachusetts Department of Environmental Protection (MA DEP) with a decision anticipated by the fourth quarter of 2016.

The Environmental Obligations (Table A 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, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. 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.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the six months ended June 30, 2016 and 2015.


Environmental Obligations
	($ millions)
	Fitchburg				Northern Utilities				Total
	Six months ended June 30,
	2016		2015		2016		2015		2016		2015
Total Balance at Beginning of Period	$	1.2	$	1.9	$	1.6	$	3.6	$	2.8	$	5.5
Additions		—		0.1		0.9		0.2		0.9		0.3
Less: Payments / Reductions		0.1		0.2		0.6		0.2		0.7		0.4

Total Balance at End of Period		1.1		1.8		1.9		3.6		3.0		5.4

Less: Current Portion		0.1		1.8		0.2		1.6		0.3		3.4

Noncurrent Balance at End of Period	$	1.0	$	—	$	1.7	$	2.0	$	2.7	$	2.0

NOTE 8: INCOME TAXES

The Company filed its tax returns for the year ended December 31, 2014 with the Internal Revenue Service (IRS) in September 2015. As of December 31, 2015, the Company had recorded cumulative federal NOL carryforward assets and Research and Development (R&D) credit carryforwards of $11.3 million to offset against taxes payable in future periods. If unused, the Company’s federal NOL carryforward assets will begin to expire in 2029, and the federal R&D credits will begin to expire in 2035. In addition, at December 31, 2015, the Company had $2.1 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In 2015, the Company recognized a tax benefit of $63,000 and $288,000 for tax years 2014 and 2015, respectively, in the tax provision related to Federal research and development tax credits under the rules of section 41 of the Internal Revenue Code. The Company will continue to recognize a tax benefit on its incremental qualified research expenses and for the six month period ended June 30, 2016 has recognized a tax benefit in the tax provision of $241,900 related to 2016 expenditures.

The Company evaluated its tax positions at June 30, 2016 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, 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, 2012; December 31, 2013; and December 31, 2014.

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

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2015 as filed with the SEC on January 28, 2016 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:


	2016			2015
Used to Determine Plan Costs
Discount Rate		4.30	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		6.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2022			2018

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended June 30,	2016			2015			2016			2015			2016		2015
Service Cost	$	851		$	916		$	652		$	656		$	41	$	28
Interest Cost		1,486			1,343			808			729			96		78
Expected Return on Plan Assets		(1,814	)		(1,694	)		(301	)		(273	)		—		—
Prior Service Cost Amortization		66			54			372			420			47		3
Actuarial Loss Amortization		1,099			1,180			262			288			94		84

Sub-total		1,688			1,799			1,793			1,820			278		193
Amounts Capitalized and Deferred		(797	)		(875	)		(867	)		(881	)		—		—

Net Periodic Benefit Cost Recognized	$	891		$	924		$	926		$	939		$	278	$	193


	Pension Plan						PBOP Plan						SERP
Six Months Ended June 30,	2016			2015			2016			2015			2016		2015
Service Cost	$	1,702		$	1,832		$	1,304		$	1,312		$	82	$	56
Interest Cost		2,972			2,686			1,616			1,458			192		156
Expected Return on Plan Assets		(3,628	)		(3,388	)		(602	)		(546	)		—		—
Prior Service Cost Amortization		132			108			744			840			94		6
Actuarial Loss Amortization		2,198			2,360			524			576			188		168

Sub-total		3,376			3,598			3,586			3,640			556		386
Amounts Capitalized and Deferred		(1,407	)		(1,583	)		(1,604	)		(1,642	)		—		—

Net Periodic Benefit Cost Recognized	$	1,969		$	2,015		$	1,982		$	1,998		$	556	$	386

Employer Contributions

As of June 30, 2016, the Company had made $2.0 million and $1.6 million of contributions to its Pension Plan and PBOP Plan, respectively, in 2016. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2016 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of June 30, 2016, the Company had made $17,100 of benefit payments under the SERP Plan in 2016. The Company presently anticipates making an additional $17,000 of benefit payments under the SERP Plan in 2016.

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, 2016. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of June 30, 2016 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 controls 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 controls over financial reporting. The Company plans to implement a new customer information system; the project is in process and the timing of the implementation is subject to the completion of user testing and system acceptance.

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, 2015 as filed with the SEC on January 28, 2016.

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, 2016.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

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 2, 2016, 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 $75,000 in value of shares have been purchased or, if sooner, on May 2, 2017.

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, 2016.


	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
4/1/16 – 4/30/16		—		—		—	$	832
5/1/16 – 5/31/16		—		—		—	$	75,000
6/1/16 – 6/30/16		154	$	40.21		154	$	68,808

Total		154				154

Item 5.

Other Information

On July 21, 2016, the Company issued a press release announcing its results of operations for the three- and six-month periods ended June 30, 2016. 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 21, 2016 Announcing Earnings For the Quarter Ended June 30, 2016.	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 21, 2016		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: July 21, 2016		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer

EXHIBIT INDEX


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 21, 2016 Announcing Earnings For the Quarter Ended June 30, 2016.	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