10-Q 1 d949536d10q.htm 10-Q

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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, 2015

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):

Large Accelerated filer |  | ¨ |  | Accelerated filer |  | x
Non-accelerated filer |  | ¨ (Do not check if a smaller reporting company) |  | Smaller reporting company |  | ¨

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 20, 2015
Common Stock, No par value |  | 13,975,142 Shares

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2015

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, 2015 and 2014 |  | 20
|  | Consolidated Balance Sheets, June 30, 2015, June 30, 2014 and December 31, 2014 |  | 21-22
|  | Consolidated Statements of Cash Flows - Six Months Ended June 30, 2015 and 2014 |  | 23
|  | Consolidated Statements of Changes in Common Stock Equity – Six Months Ended June 30, 2015 and 2014 |  | 24
|  | Notes to Consolidated Financial Statements |  | 25-47
Item 2. |  | Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations |  | 4-19
Item 3. |  | Quantitative and Qualitative Disclosures About Market Risk |  | 47
Item 4. |  | Controls and Procedures |  | 47
Part II. Other Information
Item 1. |  | Legal Proceedings |  | 48
Item 1A. |  | Risk Factors |  | 48
Item 2. |  | Unregistered Sales of Equity Securities and Use of Proceeds |  | 48
Item 3. |  | Defaults Upon Senior Securities |  | Inapplicable
Item 4. |  | Mine Safety Disclosures |  | Inapplicable
Item 5. |  | Other Information |  | 49
Item 6. |  | Exhibits |  | 49
Signatures |  | 51
Exhibits |  | 52

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CAUTIONARY STATEMENT

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

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

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

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

| • |  | customers’ preferred energy sources;

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

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

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

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

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

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

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

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

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

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

| • |  | catastrophic events;

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

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

| • |  | increased competition.

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

PART I. FINANCIAL INFORMATION

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

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:

| i) | Unitil Energy Systems, Inc. (Unitil Energy), which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, 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 102,700 electric customers and 77,900 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.

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Unitil had an investment in Net Utility Plant of $757.0 million at June 30, 2015. 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.

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Fitchburg is subject to revenue decoupling mechanisms (RDM). 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 RDM 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 RDM revenue targets may be adjusted as a result of rate cases that the Company files with the MDPU. The Company estimates that RDM applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

Rate Case Activity

Northern Utilities – Base Rates – Maine – On December 27, 2013, the MPUC approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also 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 2014 TIRA provided for an annual increase in base distribution revenue of $1.3 million, effective May 1, 2014. On February 27, 2015 Northern Utilities filed its second annual TIRA for rates effective May 1, 2015, seeking an annual increase in base distribution revenue of $1.2 million, effective May 1, 2015. The MPUC approved this filing on April 29, 2015.

Northern Utilities – Base Rates – New Hampshire – On April 21, 2014, the NHPUC approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue, effective May 1, 2014, and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. These permanent rates were reconciled to the date temporary rates were established, July 1, 2013. In addition, the settlement agreement provided for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provided for an annual increase in revenue of $1.4 million, effective May 1, 2014. On February 27, 2015 Northern Utilities’ New Hampshire division filed for a step increase of $1.8 million in base distribution revenue effective May 1, 2015. On April 28, 2015, the NHPUC approved the step increase.

Northern Utilities – Pipeline Refund – On May 12, 2010, Portland Natural Gas Transmission System (PNGTS) filed a Natural Gas Act Section 4 rate case with the FERC proposing increased pipeline rates of approximately 55 percent over the previously approved rate. The filing was docketed as RP10-729 and rates went into effect on December 1, 2010, subject to refund pending the determination in the rate proceeding. Northern Utilities and other long-term shippers on PNGTS opposed the proposed rate increase. On December 8, 2011, an Initial Decision was issued and on March 21, 2013, the FERC issued Opinion No. 524. Opinion No. 524 was appealed and the FERC issued Opinion No. 524-A on February 19, 2015 denying all appeals and ordering PNGTS to issue refunds to shippers within 60 days. 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 over a three year period to Northern Utilities’ customers in Maine and New Hampshire, as directed by the MPUC and NHPUC, respectively. The Company has recorded current and noncurrent Regulatory Liabilities of $11.1 million and $10.9 million, respectively, on its Consolidated Balance Sheets as of June 30, 2015.

Unitil Energy – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On April 30, 2014 the NHPUC approved Unitil Energy’s third and final step increase of $1.5 million in annual revenue effective May 1, 2014.

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Granite State – Base Rates – Granite State has in place a FERC approved amended settlement agreement under which it has been 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 27, 2014, Granite State filed to increase its rates and annual revenue by an additional $0.6 million beginning August 1, 2014. With this filing, Granite State reached the cost cap. The settlement agreement required Granite State to file a new FERC rate case by June 2015 with rates effective by January 1, 2016. On June 12, 2015, Granite State filed a second amended settlement agreement under which it will continue to be permitted each June to file for a rate adjustment to recover the revenue requirements associated with other specified capital investments in gas transmission projects up to a specific cost cap. The June 2015 filing proposed an annual revenue increase of $0.4 million, beginning August 1, 2015. A FERC decision is pending.

Fitchburg – Base Rates – Electric – On June 16, 2015 Fitchburg filed for a $3.8 million increase in electric base revenue which represents a 5.6 percent increase over 2014 test year operating electric revenues. The filing also included a request for approval of a capital cost recovery mechanism to recover prudently incurred additions to utility plant on an annual basis. The matter has been docketed by the MDPU and discovery has commenced. By statute, the MDPU is afforded ten months to act on a request for a rate increase. Accordingly, a decision is expected by the end of April, 2016.

Fitchburg – Base Rates – Gas – On June 16, 2015 Fitchburg filed for a $3.0 million increase in gas base revenue which represents an 8.3 percent increase over 2014 test year total gas operating revenues. The matter has been docketed by the MDPU and discovery has commenced. By statute, the MDPU is afforded ten months to act on a request for a rate increase. Accordingly, a decision is expected by the end of April, 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, 2015 and June 30, 2014 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.

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Earnings Overview

The Company’s Net Income was $1.7 million, or $0.12 per share, for the second quarter of 2015, an increase of $0.6 million, or $0.04 per share, compared to the second quarter of 2014. For the six months ended June 30, 2015, the Company reported Net Income of $15.3 million, an 11.7% increase over Net Income of $13.7 in the same six-month period in 2014. Earnings Per Share (EPS) for the six months ended June 30, 2015 were $1.10, an increase of $0.11 per share, compared to EPS of $0.99 for the same period of 2014. The Company’s earnings for 2015 were driven by increases in natural gas and electric sales and margins, partially offset by higher net operating expenses.

Natural gas sales margins were $18.1 million and $56.9 million in the three and six months ended June 30, 2015, respectively, resulting in increases of $1.8 million and $4.1 million, respectively, compared to the same periods in 2014. The increase in the second quarter primarily reflects higher natural gas distribution rates. For the six month period, natural gas sales margins were positively affected by higher therm unit sales of natural gas and higher distribution rates. For the six months ended June 30, 2015, gas therm sales increased 4.0% compared to the same period in 2014. The increase in gas therm sales in the Company’s utility service territories was driven by the colder winter weather in the first quarter of 2015 compared to 2014 coupled with strong growth in the number of customers. Based on weather data collected in the Company’s service areas, there were 2.7% more Heating Degree Days (HDD) in the first six months of 2015 compared to the same period in 2014 and 13.3% more HDD than normal. Weather-normalized gas therm sales are estimated to be up 3.2% in the first six months of 2015 compared to the same period in 2014. As of June 30, 2015, the number of total natural gas customers served has increased by 1.7% in the last twelve months.

Electric sales margins were $20.5 million and $41.7 million in the three and six months ended June 30, 2015, respectively, resulting in increases of $1.6 million and $3.6 million, respectively, compared to the same periods in 2014, reflecting higher electric distribution rates and higher sales volumes. Electric kilowatt-hour (kWh) sales increased 0.1% and 0.2% in the three and six month periods ended June 30, 2015 compared to the same periods in 2014.

Operation and Maintenance (O&M) expenses increased $1.0 million and $0.8 million for the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014. The increase in the three month period reflects higher compensation and benefit costs of $0.9 million and higher all other utility O&M costs, net of $0.1 million. The increase in O&M expenses in the six month period reflects higher compensation and benefit costs of $1.2 million and higher all other utility O&M costs, net of $0.3 million; partially offset by lower professional fees of $0.7 million.

Depreciation and Amortization expense increased $1.1 million and $2.3 million in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014. These increases reflect higher depreciation on normal utility plant assets in service, higher amortization of major storm restoration costs and an increase in all other amortization. The increases in the amortization of major storm restoration costs of $0.3 million and $0.7 million in the three and six month periods, respectively, is currently recovered in electric rates and reflected in electric sales margin.

Taxes Other Than Income Taxes decreased $0.4 million and $0.1 million in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014, primarily reflecting lower local property tax expense.

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Interest Expense, net increased $0.7 million and $1.3 million in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014, reflecting higher levels of long-term debt and lower 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, 2015, respectively, representing increases of $0.1 million each compared to the same periods in 2014.

At its January 2015, April 2015 and July 2015 meetings, Unitil’s Board of Directors declared quarterly dividends on the Company’s common stock of $0.35 per share, resulting in an increase in the effective annual dividend rate to $1.40 per share from $1.38 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, 2015 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas decreased 1.3% and increased 4.0% in the three and six month periods ended June 30, 2015, respectively, compared to the same periods in 2014. In the second quarter of 2015, sales to Residential and C&I customers decreased 3.4% and 0.8%, respectively, compared to the same period in 2014, reflecting warmer early spring weather in 2015 compared to 2014 and reduced usage by large C&I customers for production purposes, partially offset by growth in the number of customers served. For the six months ended June 30, 2015, sales to Residential and C&I customers increased 6.0% and 3.4%, respectively, compared to the same period in 2014. The increase in gas therm sales in the Company’s utility service territories was driven by the colder winter weather in the first quarter of 2015 compared to 2014 coupled with strong growth in the number of customers. Based on weather data collected in the Company’s service areas, there were 2.7% more Heating Degree Days (HDD) in the first six months of 2015 compared to the same period in 2014 and 13.3% more HDD than normal. Weather-normalized gas therm sales are estimated to be up 3.2% in the first six months of 2015 compared to the same period in 2014. As of June 30, 2015, the number of total natural gas customers served has increased by 1.7% in the last twelve months.

The following table details total firm therm sales for the three and six months ended June 30, 2015 and 2014, by major customer class:

Therm Sales (millions) |
|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |  |  | Change |  |  | % Change |  |  | 2015 |  |  | 2014 |  |  | Change |  |  | % Change |
Residential |  |  | 8.6 |  |  |  | 8.9 |  |  |  | (0.3 | ) |  |  | (3.4 | %) |  |  | 33.7 |  |  |  | 31.8 |  |  |  | 1.9 |  |  |  | 6.0 | %
Commercial / Industrial |  |  | 35.8 |  |  |  | 36.1 |  |  |  | (0.3 | ) |  |  | (0.8 | %) |  |  | 110.2 |  |  |  | 106.6 |  |  |  | 3.6 |  |  |  | 3.4 | %
Total |  |  | 44.4 |  |  |  | 45.0 |  |  |  | (0.6 | ) |  |  | (1.3 | %) |  |  | 143.9 |  |  |  | 138.4 |  |  |  | 5.5 |  |  |  | 4.0 | %

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, 2015 and 2014:

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Gas Operating Revenues and Sales Margin (millions) |
|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |  |  | $ Change |  |  | % Change |  |  | 2015 |  |  | 2014 |  |  | $ Change |  |  | % Change |
Gas Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 10.6 |  |  | $ | 10.6 |  |  | $ | — |  |  |  | — |  |  | $ | 51.1 |  |  | $ | 48.3 |  |  | $ | 2.8 |  |  |  | 5.8 | %
Commercial / Industrial |  |  | 17.0 |  |  |  | 15.2 |  |  |  | 1.8 |  |  |  | 11.8 | % |  |  | 76.8 |  |  |  | 70.1 |  |  |  | 6.7 |  |  |  | 9.6 | %
Total Gas Operating Revenue |  | $ | 27.6 |  |  | $ | 25.8 |  |  | $ | 1.8 |  |  |  | 7.0 | % |  | $ | 127.9 |  |  | $ | 118.4 |  |  | $ | 9.5 |  |  |  | 8.0 | %
Cost of Gas Sales |  | $ | 9.5 |  |  | $ | 9.5 |  |  | $ | — |  |  |  | — |  |  | $ | 71.0 |  |  | $ | 65.6 |  |  | $ | 5.4 |  |  |  | 8.2 | %
Gas Sales Margin |  | $ | 18.1 |  |  | $ | 16.3 |  |  | $ | 1.8 |  |  |  | 11.0 | % |  | $ | 56.9 |  |  | $ | 52.8 |  |  | $ | 4.1 |  |  |  | 7.8 | %

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 $18.1 million and $56.9 million in the three and six months ended June 30, 2015, respectively, resulting in increases of $1.8 million and $4.1 million, respectively, compared to the same periods in 2014. The increase in the second quarter primarily reflects higher natural gas distribution rates. For the six month period, approximately $2.6 million of the increase reflects higher natural gas distribution rates and $1.5 million of the increase reflects higher sales volumes related to colder than normal winter weather and customer growth.

The increase in Total Gas Operating Revenues of $1.8 million in the second quarter of 2015 reflects higher gas base rates, partially offset by lower sales volumes.

The increase in Total Gas Operating Revenues of $9.5 million in the first six months of 2015 reflects higher gas base rates of $4.1 million and higher cost of gas sales of $5.4 million, which are tracked and reconciled to costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales increased 0.1% and 0.2%, respectively in the three and six month periods ended June 30, 2015 compared to the same periods in 2014. Sales to Residential customers decreased 1.8% and 1.7%, respectively, in the three and six month periods ended June 30, 2015 compared to the same periods in 2014, reflecting lower average usage in 2015 compared to 2014. Sales to C&I customers increased 1.3% and 1.6%, respectively, in the three and six month periods ended June 30, 2015 compared to the same periods in 2014, driven by the addition of new customers. 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.

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The following table details total kWh sales for the three and six months ended June 30, 2015 and 2014 by major customer class:

kWh Sales (millions) |
|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |  |  | Change |  |  | % Change |  |  | 2015 |  |  | 2014 |  |  | Change |  |  | % Change |
Residential |  |  | 144.3 |  |  |  | 147.0 |  |  |  | (2.7 | ) |  |  | (1.8 | %) |  |  | 342.9 |  |  |  | 348.9 |  |  |  | (6.0 | ) |  |  | (1.7 | %)
Commercial / Industrial |  |  | 240.4 |  |  |  | 237.4 |  |  |  | 3.0 |  |  |  | 1.3 | % |  |  | 490.2 |  |  |  | 482.5 |  |  |  | 7.7 |  |  |  | 1.6 | %
Total |  |  | 384.7 |  |  |  | 384.4 |  |  |  | 0.3 |  |  |  | 0.1 | % |  |  | 833.1 |  |  |  | 831.4 |  |  |  | 1.7 |  |  |  | 0.2 | %

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, 2015 and 2014:

Electric Operating Revenues and Sales Margin (millions) |
|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |  |  | $ Change |  |  | % Change |  |  | 2015 |  |  | 2014 |  |  | $ Change |  |  | % Change |
Electric Operating Revenue: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  | $ | 27.6 |  |  | $ | 23.4 |  |  | $ | 4.2 |  |  |  | 17.9 | % |  | $ | 70.3 |  |  | $ | 58.2 |  |  | $ | 12.1 |  |  |  | 20.8 | %
Commercial / Industrial |  |  | 20.8 |  |  |  | 22.7 |  |  |  | (1.9 | ) |  |  | (8.4 | %) |  |  | 48.4 |  |  |  | 49.8 |  |  |  | (1.4 | ) |  |  | (2.8 | %)
Total Electric Operating Revenue |  | $ | 48.4 |  |  | $ | 46.1 |  |  | $ | 2.3 |  |  |  | 5.0 | % |  | $ | 118.7 |  |  | $ | 108.0 |  |  | $ | 10.7 |  |  |  | 9.9 | %
Cost of Electric Sales |  | $ | 27.9 |  |  | $ | 27.2 |  |  | $ | 0.7 |  |  |  | 2.6 | % |  | $ | 77.0 |  |  | $ | 69.9 |  |  | $ | 7.1 |  |  |  | 10.2 | %
Electric Sales Margin |  | $ | 20.5 |  |  | $ | 18.9 |  |  | $ | 1.6 |  |  |  | 8.5 | % |  | $ | 41.7 |  |  | $ | 38.1 |  |  | $ | 3.6 |  |  |  | 9.4 | %

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 $20.5 million and $41.7 million in the three and six months ended June 30, 2015, respectively, resulting in increases of $1.6 million and $3.6 million, respectively, compared to the same periods in 2014. For the second quarter, the increase reflects higher electric distribution rates of $1.4 million and higher sales of $0.2 million. For the six month period, approximately $3.3 million of the increase reflects higher electric distribution rates and $0.3 million of the increase reflects higher sales volumes related to the colder winter weather and customer growth.

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The increase in Total Electric Operating Revenues of $2.3 million in the second quarter of 2015 reflects higher electric base rates of $1.6 million and higher cost of electric sales of $0.7 million, which are tracked and reconciled to costs that are passed through directly to customers.

The increase in Total Electric Operating Revenues of $10.7 million in the first six months of 2015 reflects higher electric base rates of $3.6 million and higher cost of electric sales of $7.1 million, 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, 2015 and 2014:

Other Revenue (000’s) |
|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |  |  | $ Change |  |  | % Change |  |  | 2015 |  |  | 2014 |  |  | $ Change |  |  | % Change |
Other |  | $ | 1.5 |  |  | $ | 1.4 |  |  | $ | 0.1 |  |  |  | 7.1 | % |  | $ | 3.1 |  |  | $ | 3.0 |  |  | $ | 0.1 |  |  |  | 3.3 | %
Total Other Revenue |  | $ | 1.5 |  |  | $ | 1.4 |  |  | $ | 0.1 |  |  |  | 7.1 | % |  | $ | 3.1 |  |  | $ | 3.0 |  |  | $ | 0.1 |  |  |  | 3.3 | %

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues increased $0.1 million in each of the three and six month periods ended June 30, 2014, respectively, compared to the same periods in 2014. 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 was relatively unchanged in the second quarter of 2015 compared to the same period in 2014 and increased $5.4 million, or 8.2%, in the six months ended June 30, 2015, compared to the same period in 2014. The increase in the six month period reflects higher sales of natural gas and a decrease in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by lower wholesale natural gas prices. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

Cost of Electric Sales – Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales increased $0.7 million, or 2.6%, and $7.1 million, or 10.2%, in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014. These increases reflect higher wholesale electricity prices and higher electric sales, partially offset by 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.

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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 increased $1.0 million, or 6.5%, and $0.8 million, or 2.5%, for the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014. The increase in the three month period reflects higher compensation and benefit costs of $0.9 million and higher all other utility O&M costs, net of $0.1 million. The increase in O&M expenses in the six month period reflects higher compensation and benefit costs of $1.2 million and higher all other utility O&M costs, net of $0.3 million; partially offset by lower professional fees of $0.7 million.

Depreciation and Amortization – Depreciation and Amortization expense increased $1.1 million, or 10.8%, and $2.3 million, or 11.3%, in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014. The increase in the three month period reflects higher depreciation of $0.6 million on normal utility plant assets in service, higher amortization of major storm restoration costs of $0.3 million and an increase in all other amortization of $0.2 million. The increase in the six month period reflects higher depreciation of $1.3 million on normal utility plant assets in service, higher amortization of major storm restoration costs of $0.7 million and an increase in all other amortization of $0.3 million. The increases in the amortization of major storm restoration costs of $0.3 million and $0.7 million in the three and six month periods, respectively, is currently recovered in electric rates and reflected in electric sales margin.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes decreased $0.4 million, or 10.0%, and $0.1 million, or 1.2%, in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014, primarily reflecting lower local property tax expense.

Other Expense, net – Other Expense, net was relatively unchanged in the three and six months ended June 30, 2015 compared to the same periods in 2014.

Income Taxes – Federal and State Income Taxes increased by $0.5 million and $1.9 million for the three and six months ended June 30, 2015 compared to the same periods in 2014, reflecting higher pre-tax earnings in the current periods.

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.

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Interest Expense, net (Millions) |  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |  |  | Change |  |  | 2015 |  |  | 2014 |  |  | Change |
Interest Expense |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term Debt |  | $ | 5.5 |  |  | $ | 5.1 |  |  | $ | 0.4 |  |  | $ | 11.0 |  |  | $ | 10.1 |  |  | $ | 0.9 |
Short-term Debt |  |  | 0.2 |  |  |  | 0.3 |  |  |  | (0.1 | ) |  |  | 0.5 |  |  |  | 0.6 |  |  |  | (0.1 | )
Regulatory Liabilities |  |  | 0.3 |  |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.5 |  |  |  | 0.2 |  |  |  | 0.3 |
Subtotal Interest Expense |  |  | 6.0 |  |  |  | 5.5 |  |  |  | 0.5 |  |  |  | 12.0 |  |  |  | 10.9 |  |  |  | 1.1 |
Interest (Income) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | 0.1 |  |  |  | (0.1 | ) |  |  | 0.2 |  |  |  | 0.1 |  |  |  | (0.2 | ) |  |  | 0.3 |
AFUDC(1) and Other |  |  | (0.1 | ) |  |  | (0.1 | ) |  |  | — |  |  |  | (0.3 | ) |  |  | (0.2 | ) |  |  | (0.1 | )
Subtotal Interest (Income) |  |  | — |  |  |  | (0.2 | ) |  |  | 0.2 |  |  |  | (0.2 | ) |  |  | (0.4 | ) |  |  | 0.2 |
Total Interest Expense, net |  | $ | 6.0 |  |  | $ | 5.3 |  |  | $ | 0.7 |  |  | $ | 11.8 |  |  | $ | 10.5 |  |  | $ | 1.3 |

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

Interest Expense, net increased $0.7 million and $1.3 million in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014, reflecting higher levels of long-term debt and lower net interest income on regulatory assets.

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 bank borrowings, as needed, under its unsecured short-term 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.

On October 15, 2014, Northern Utilities completed a private placement of $50 million aggregate principal amount of 4.42% Senior Unsecured Notes due October 15, 2044 to institutional investors. The proceeds from the offering were used to repay short-term debt and for general corporate purposes.

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, 2015, June 30, 2014 and December 31, 2014, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

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On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 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 plus 1.375%. 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 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, 2015, June 30, 2014 and December 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4.)

On December 23, 2014, Standard & Poor’s Ratings Services assigned its “BBB+” issuer credit rating to Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy and Northern Utilities.

In April 2014, Unitil Service Corp. entered into a financing arrangement for information systems software and various technology equipment. The financing arrangement is structured as a capital lease obligation with maximum availability of $15 million. As of June 30, 2015, Unitil Service Corp. has received funding under this financing arrangement in the amount of $9.1 million, which was used to fund project costs.

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, 2015, there were approximately $20.1 million of guarantees outstanding and the longest term guarantee extends through April 2016.

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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 $6.8 million, $7.8 million and $15.1 million of natural gas storage inventory at June 30, 2015, June 30, 2014 and December 31, 2014, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2015 and payable in July 2015 is $0.1 million and is recorded in Accounts Payable at June 30, 2015. The amount of natural gas inventory released in June 2014 and payable in July 2014 was $0.2 million and is recorded in Accounts Payable at June 30, 2014. The amount of natural gas inventory released in December 2014 and payable in January 2015 was $1.0 million and was recorded in Accounts Payable at December 31, 2014.

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, 2015, the principal amount outstanding for the 8% Unitil Realty notes was $1.5 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of June 30, 2015, 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.

Cash Flows

Unitil’s utility operations, taken as a whole, are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The tables below summarize the major sources and uses of cash (in millions) for the six months ended June 30, 2015 compared to the same period in 2014.

|  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |
Cash Provided by Operating Activities |  | $ | 90.5 |  |  | $ | 63.6 |

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $90.5 million in the six months ended June 30, 2015, an increase of $26.9 million compared to the same period in 2014.

Cash flow from net income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $37.3 million in 2015 compared to $41.8 million in 2014, representing a decrease of $4.5 million. The increase in net income in the six months ended June 30, 2015 compared to the same period in 2014 is primarily attributable to increases in natural gas and electric sales margins as a result of base rate relief and higher gas unit sales from colder weather and customer growth. The increase in depreciation and amortization in 2015 compared to 2014 reflects higher utility depreciation from higher net utility plant in service and higher amortization from major storm restoration costs. The decrease in the deferred tax provision in 2015 compared to 2014 is primarily due to a deferred tax asset recorded in the second quarter of 2015 as a result of the $22.0 million pipeline refund from Portland Natural Gas Transmission System (PNGTS) (See Note 6).

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Changes in working capital items resulted in a $39.1 million source of cash in 2015 compared to a $22.2 million source of cash in 2014, representing an increase of $17.0 million. Sources of cash for Regulatory Liabilities were higher by $19.2 million in 2015 compared to 2014 driven by the current portion of the pipeline refund from PNGTS. Similarly, Taxes Payable were higher by $9.2 million in 2015 compared to 2014 driven by the pipeline refund. All other changes in working capital reflect normal variations from year-to-year.

Changes in Deferred Regulatory and Other Charges resulted in an increase in sources of cash of $11.8 million in 2015 compared to 2014 primarily driven by the long-term portion of the PNGTS refund of $10.9 million. Changes in Other, net resulted in an increase in sources of cash of $2.7 million.

|  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |
Cash (Used in) Investing Activities |  | $ | (38.5 | ) |  | $ | (29.1 | )

Cash (Used in) Investing Activities – Cash (Used in) Investing Activities was ($38.5) million in the six months ended June 30, 2015 compared to ($29.1) million in 2014. The actual capital spending in both 2015 and 2014 is representative of distribution utility capital expenditures for electric and gas utility system additions. The Company’s projected capital spending range for 2015 is $95 million to $100 million.

|  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |
Cash (Used in) Financing Activities |  | $ | (44.3 | ) |  | $ | (31.9 | )

Cash (Used in) Financing Activities – Cash (Used in) Financing Activities was ($44.3) million in the six months ended June 30, 2015 compared to ($31.9) million in 2014. The higher cash used in financing activities in 2015 is primarily a result of greater repayment of Short-Term Debt of $4.1 million, a decrease in Capital Lease financing of $2.8 million, and a net decrease in Exchange Gas Financing of $5.3 million.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. For a

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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 for the year ended December 31, 2014, as filed with the Securities and Exchange Commission on January 28, 2015.

LABOR RELATIONS

As of June 30, 2015, the Company and its subsidiaries had 509 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of June 30, 2015, a total of 162 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, 2015:

|  | Employees Covered |  |  | CBA Expiration |
Fitchburg |  |  | 45 |  |  |  | 05/31/2019 |
Northern Utilities NH Division |  |  | 34 |  |  |  | 06/05/2017 |
Northern Utilities ME Division/Granite State |  |  | 39 |  |  |  | 03/31/2017 |
Unitil Energy |  |  | 39 |  |  |  | 05/31/2018 |
Unitil Service |  |  | 5 |  |  |  | 05/31/2016 |

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, 2015 and June 30, 2014 were 1.58% and 1.55%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2015 and June 30, 2014 were 1.57% and 1.55%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2014 was 1.60%.

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.

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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.

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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, |
|  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |
Operating Revenues |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Gas |  | $ | 27.6 |  |  | $ | 25.8 |  |  | $ | 127.9 |  |  | $ | 118.4 |
Electric |  |  | 48.4 |  |  |  | 46.1 |  |  |  | 118.7 |  |  |  | 108.0 |
Other |  |  | 1.5 |  |  |  | 1.4 |  |  |  | 3.1 |  |  |  | 3.0 |
Total Operating Revenues |  |  | 77.5 |  |  |  | 73.3 |  |  |  | 249.7 |  |  |  | 229.4 |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of Gas Sales |  |  | 9.5 |  |  |  | 9.5 |  |  |  | 71.0 |  |  |  | 65.6 |
Cost of Electric Sales |  |  | 27.9 |  |  |  | 27.2 |  |  |  | 77.0 |  |  |  | 69.9 |
Operation and Maintenance |  |  | 16.3 |  |  |  | 15.3 |  |  |  | 33.2 |  |  |  | 32.4 |
Depreciation and Amortization |  |  | 11.3 |  |  |  | 10.2 |  |  |  | 22.7 |  |  |  | 20.4 |
Taxes Other Than Income Taxes |  |  | 3.6 |  |  |  | 4.0 |  |  |  | 8.5 |  |  |  | 8.6 |
Total Operating Expenses |  |  | 68.6 |  |  |  | 66.2 |  |  |  | 212.4 |  |  |  | 196.9 |
Operating Income |  |  | 8.9 |  |  |  | 7.1 |  |  |  | 37.3 |  |  |  | 32.5 |
Interest Expense, net |  |  | 6.0 |  |  |  | 5.3 |  |  |  | 11.8 |  |  |  | 10.5 |
Other Expense, net |  |  | 0.1 |  |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.2 |
Income Before Income Taxes |  |  | 2.8 |  |  |  | 1.7 |  |  |  | 25.3 |  |  |  | 21.8 |
Income Tax Expense |  |  | 1.1 |  |  |  | 0.6 |  |  |  | 10.0 |  |  |  | 8.1 |
Net Income |  | $ | 1.7 |  |  | $ | 1.1 |  |  | $ | 15.3 |  |  | $ | 13.7 |
Net Income Per Common Share (Basic and Diluted) |  | $ | 0.12 |  |  | $ | 0.08 |  |  | $ | 1.10 |  |  | $ | 0.99 |
Weighted Average Common Shares Outstanding – (Basic and Diluted) |  |  | 13.9 |  |  |  | 13.8 |  |  |  | 13.9 |  |  |  | 13.8 |
Dividends Declared Per Share of Common Stock |  | $ | 0.350 |  |  | $ | 0.345 |  |  | $ | 0.70 |  |  | $ | 0.69 |

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

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)

|  | June 30, |  |  | December 31, |
|  | 2015 |  |  | 2014 |  |  | 2014 |
ASSETS: |  |  |  |  |  |  |  |  |  |  |  |
Current Assets: |  |  |  |  |  |  |  |  |  |  |  |
Cash and Cash Equivalents |  | $ | 16.1 |  |  | $ | 12.0 |  |  | $ | 8.4 |
Accounts Receivable, net |  |  | 52.3 |  |  |  | 44.9 |  |  |  | 60.7 |
Accrued Revenue |  |  | 28.6 |  |  |  | 33.4 |  |  |  | 48.5 |
Exchange Gas Receivable |  |  | 7.2 |  |  |  | 8.3 |  |  |  | 15.0 |
Deferred Income Taxes |  |  | 15.2 |  |  |  | 1.5 |  |  |  | — |
Gas Inventory |  |  | 0.5 |  |  |  | 0.8 |  |  |  | 1.1 |
Materials and Supplies |  |  | 6.7 |  |  |  | 6.1 |  |  |  | 6.3 |
Prepayments and Other |  |  | 7.3 |  |  |  | 6.9 |  |  |  | 5.2 |
Total Current Assets |  |  | 133.9 |  |  |  | 113.9 |  |  |  | 145.2 |
Utility Plant: |  |  |  |  |  |  |  |  |  |  |  |
Gas |  |  | 532.1 |  |  |  | 483.9 |  |  |  | 522.9 |
Electric |  |  | 396.4 |  |  |  | 379.1 |  |  |  | 390.6 |
Common |  |  | 35.0 |  |  |  | 32.3 |  |  |  | 32.7 |
Construction Work in Progress |  |  | 57.4 |  |  |  | 34.3 |  |  |  | 42.6 |
Total Utility Plant |  |  | 1,020.9 |  |  |  | 929.6 |  |  |  | 988.8 |
Less: Accumulated Depreciation |  |  | 263.9 |  |  |  | 247.9 |  |  |  | 255.1 |
Net Utility Plant |  |  | 757.0 |  |  |  | 681.7 |  |  |  | 733.7 |
Other Noncurrent Assets: |  |  |  |  |  |  |  |  |  |  |  |
Regulatory Assets |  |  | 104.3 |  |  |  | 88.1 |  |  |  | 107.6 |
Other Assets |  |  | 16.2 |  |  |  | 16.9 |  |  |  | 13.7 |
Total Other Noncurrent Assets |  |  | 120.5 |  |  |  | 105.0 |  |  |  | 121.3 |
TOTAL ASSETS |  | $ | 1,011.4 |  |  | $ | 900.6 |  |  | $ | 1,000.2 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)

|  | June 30, |  |  | December 31, |
|  | 2015 |  |  | 2014 |  |  | 2014 |
LIABILITIES AND CAPITALIZATION: |  |  |  |  |  |  |  |  |  |  |  |
Current Liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Accounts Payable |  | $ | 19.0 |  |  | $ | 20.5 |  |  | $ | 44.2 |
Short-Term Debt |  |  | — |  |  |  | 35.0 |  |  |  | 29.3 |
Long-Term Debt, Current Portion |  |  | 4.1 |  |  |  | 2.5 |  |  |  | 4.0 |
Energy Supply Obligations |  |  | 13.8 |  |  |  | 12.3 |  |  |  | 22.1 |
Deferred Income Taxes |  |  | — |  |  |  | — |  |  |  | 3.1 |
Environmental Obligations |  |  | 3.4 |  |  |  | 6.4 |  |  |  | 3.5 |
Interest Payable |  |  | 3.5 |  |  |  | 3.1 |  |  |  | 3.5 |
Regulatory Liabilities |  |  | 31.2 |  |  |  | 13.0 |  |  |  | 8.7 |
Taxes Payable |  |  | 9.1 |  |  |  | 0.1 |  |  |  | 0.1 |
Other Current Liabilities |  |  | 10.4 |  |  |  | 9.7 |  |  |  | 10.9 |
Total Current Liabilities |  |  | 94.5 |  |  |  | 102.6 |  |  |  | 129.4 |
Noncurrent Liabilities: |  |  |  |  |  |  |  |  |  |  |  |
Deferred Income Taxes |  |  | 90.2 |  |  |  | 87.8 |  |  |  | 72.9 |
Cost of Removal Obligations |  |  | 68.1 |  |  |  | 60.8 |  |  |  | 63.8 |
Retirement Benefit Obligations |  |  | 123.5 |  |  |  | 80.8 |  |  |  | 118.6 |
Regulatory Liabilities |  |  | 11.0 |  |  |  | — |  |  |  | 0.1 |
Capital Lease Obligations |  |  | 9.5 |  |  |  | 5.6 |  |  |  | 7.5 |
Environmental Obligations |  |  | 2.0 |  |  |  | 2.0 |  |  |  | 2.0 |
Other Noncurrent Liabilities |  |  | 3.5 |  |  |  | 5.6 |  |  |  | 3.7 |
Total Noncurrent Liabilities |  |  | 307.8 |  |  |  | 242.6 |  |  |  | 268.6 |
Capitalization: |  |  |  |  |  |  |  |  |  |  |  |
Long-Term Debt, Less Current Portion |  |  | 328.6 |  |  |  | 284.6 |  |  |  | 328.9 |
Stockholders’ Equity: |  |  |  |  |  |  |  |  |  |  |  |
Common Equity (Authorized: 25,000,000 and Outstanding: 13,974,576, 13,895,777 and 13,916,026 Shares) |  |  | 236.4 |  |  |  | 233.6 |  |  |  | 234.7 |
Retained Earnings |  |  | 43.9 |  |  |  | 37.0 |  |  |  | 38.4 |
Total Common Stock Equity |  |  | 280.3 |  |  |  | 270.6 |  |  |  | 273.1 |
Preferred Stock |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.2 |
Total Stockholders’ Equity |  |  | 280.5 |  |  |  | 270.8 |  |  |  | 273.3 |
Total Capitalization |  |  | 609.1 |  |  |  | 555.4 |  |  |  | 602.2 |
Commitments and Contingencies (Notes 6 & 7) |  |  |  |  |  |  |  |  |  |  |  |
TOTAL LIABILITIES AND CAPITALIZATION |  | $ | 1,011.4 |  |  | $ | 900.6 |  |  | $ | 1,000.2 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)

|  | Six Months Ended June 30, |
|  | 2015 |  |  | 2014 |
Operating Activities: |  |  |  |  |  |  |  |
Net Income |  | $ | 15.3 |  |  | $ | 13.7 |
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: |  |  |  |  |  |  |  |
Depreciation and Amortization |  |  | 22.7 |  |  |  | 20.4 |
Deferred Tax Provision |  |  | (0.7 | ) |  |  | 7.7 |
Changes in Working Capital Items: |  |  |  |  |  |  |  |
Accounts Receivable |  |  | 8.4 |  |  |  | 7.3 |
Accrued Revenue |  |  | 19.9 |  |  |  | 23.2 |
Regulatory Liabilities |  |  | 22.5 |  |  |  | 3.3 |
Taxes Payable |  |  | 9.0 |  |  |  | (0.1 | )
Exchange Gas Receivable |  |  | 7.8 |  |  |  | 2.5 |
Accounts Payable |  |  | (25.2 | ) |  |  | (17.6 | )
Other Changes in Working Capital Items |  |  | (3.3 | ) |  |  | 3.6 |
Deferred Regulatory and Other Charges |  |  | 11.5 |  |  |  | (0.3 | )
Other, net |  |  | 2.6 |  |  |  | (0.1 | )
Cash Provided by Operating Activities |  |  | 90.5 |  |  |  | 63.6 |
Investing Activities: |  |  |  |  |  |  |  |
Property, Plant and Equipment Additions |  |  | (38.5 | ) |  |  | (29.1 | )
Cash (Used in) Investing Activities |  |  | (38.5 | ) |  |  | (29.1 | )
Financing Activities: |  |  |  |  |  |  |  |
Repayment of Short-Term Debt, net |  |  | (29.3 | ) |  |  | (25.2 | )
Repayment of Long-Term Debt |  |  | (0.2 | ) |  |  | (0.2 | )
Increase in Capital Lease Obligations |  |  | 1.9 |  |  |  | 4.7 |
Net Decrease in Exchange Gas Financing |  |  | (7.5 | ) |  |  | (2.2 | )
Dividends Paid |  |  | (9.8 | ) |  |  | (9.6 | )
Proceeds from Issuance of Common Stock, net |  |  | 0.6 |  |  |  | 0.6 |
Cash (Used in) Financing Activities |  |  | (44.3 | ) |  |  | (31.9 | )
Net Increase in Cash and Cash Equivalents |  |  | 7.7 |  |  |  | 2.6 |
Cash and Cash Equivalents at Beginning of Period |  |  | 8.4 |  |  |  | 9.4 |
Cash and Cash Equivalents at End of Period |  | $ | 16.1 |  |  | $ | 12.0 |
Supplemental Cash Flow Information: |  |  |  |  |  |  |  |
Interest Paid |  | $ | 12.0 |  |  | $ | 10.6 |
Income Taxes Paid |  | $ | 1.5 |  |  | $ | 0.3 |
Non-cash Investing Activity: |  |  |  |  |  |  |  |
Capital Expenditures Included in Accounts Payable |  | $ | 1.0 |  |  | $ | 0.4 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)

(UNAUDITED)

|  | Common Equity |  |  | Retained Earnings |  |  | Total |
Balance at January 1, 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 |
Balance at January 1, 2014 |  | $ | 232.1 |  |  | $ | 32.9 |  |  | $ | 265.0 |
Net Income |  |  |  |  |  |  | 13.7 |  |  |  | 13.7 |
Dividends on Common Shares |  |  |  |  |  |  | (9.6 | ) |  |  | (9.6 | )
Stock Compensation Plans |  |  | 0.9 |  |  |  |  |  |  |  | 0.9 |
Issuance of 18,877 Common Shares |  |  | 0.6 |  |  |  |  |  |  |  | 0.6 |
Balance at June 30, 2014 |  | $ | 233.6 |  |  | $ | 37.0 |  |  | $ | 270.6 |

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

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##### Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

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

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

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##### Table of Contents

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, 2015 are not necessarily indicative of results to be expected for the year ending December 31, 2015. 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, 2014, as filed with the Securities and Exchange Commission (SEC) on January 28, 2015, for a description of the Company’s Basis of Presentation.

Fair Value – The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:

Level 1 - |  | Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 - |  | Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3 - |  | Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

There have been no changes in the valuation techniques used during the current period.

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

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##### Table of Contents

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. Deferred income taxes are reflected as Deferred Income Taxes in Current Assets and Noncurrent Liabilities on the Consolidated Balance Sheets based on the nature of the underlying timing item.

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. As of June 30, 2015, June 30, 2014 and December 31, 2014, the Unitil subsidiaries had deposited $0.7 million, $8.8 million and $6.3 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, 2015, June 30, 2014 and December 31, 2014, there was $0.1 million, $0 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, as a result of the MDPU’s final rate order dated May 30, 2014, discussed below, the electric division of Fitchburg is 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 expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

The Allowance for Doubtful Accounts as of June 30, 2015, June 30, 2014 and December 31, 2014, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:

($ millions) |  | June 30, |  |  | December 31, |
|  | 2015 |  |  | 2014 |  |  | 2014 |
Allowance for Doubtful Accounts |  | $ | 2.0 |  |  | $ | 1.7 |  |  | $ | 1.8 |

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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, 2015, June 30, 2014 and December 31, 2014.

|  | June 30, |  |  | December 31, |
Accrued Revenue ($ millions) |  | 2015 |  |  | 2014 |  |  | 2014 |
Regulatory Assets – Current |  | $ | 22.6 |  |  | $ | 27.3 |  |  | $ | 37.8 |
Unbilled Revenues |  |  | 6.0 |  |  |  | 6.1 |  |  |  | 10.7 |
Total Accrued Revenue |  | $ | 28.6 |  |  | $ | 33.4 |  |  | $ | 48.5 |

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, 2015, June 30, 2014 and December 31, 2014.

|  | June 30, |  |  | December 31, |
Exchange Gas Receivable ($ millions) |  | 2015 |  |  | 2014 |  |  | 2014 |
Northern Utilities |  | $ | 6.7 |  |  | $ | 7.6 |  |  | $ | 14.2 |
Fitchburg |  |  | 0.5 |  |  |  | 0.7 |  |  |  | 0.8 |
Total Exchange Gas Receivable |  | $ | 7.2 |  |  | $ | 8.3 |  |  | $ | 15.0 |

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, 2015, June 30, 2014 and December 31, 2014.

|  | June 30, |  |  | December 31, |
Gas Inventory ($ millions) |  | 2015 |  |  | 2014 |  |  | 2014 |
Natural Gas |  | $ | 0.2 |  |  | $ | 0.5 |  |  | $ | 0.8 |
Propane |  |  | 0.2 |  |  |  | 0.1 |  |  |  | 0.2 |
Liquefied Natural Gas & Other |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.1 |
Total Gas Inventory |  | $ | 0.5 |  |  | $ | 0.8 |  |  | $ | 1.1 |

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, 2015, June 30, 2014 and December 31, 2014, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $68.1 million, $60.8 million, and $63.8 million, respectively.

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##### Table of Contents

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) |  | 2015 |  |  | 2014 |  |  | 2014 |
Retirement Benefits |  | $ | 65.1 |  |  | $ | 42.2 |  |  | $ | 65.1 |
Energy Supply & Other Regulatory Tracker Mechanisms |  |  | 17.4 |  |  |  | 17.7 |  |  |  | 31.0 |
Deferred Storm Charges |  |  | 18.6 |  |  |  | 22.3 |  |  |  | 21.2 |
Environmental |  |  | 10.9 |  |  |  | 10.6 |  |  |  | 11.0 |
Income Taxes |  |  | 9.1 |  |  |  | 10.4 |  |  |  | 9.7 |
Deferred Restructuring Costs |  |  | — |  |  |  | 4.7 |  |  |  | 1.6 |
Other |  |  | 5.8 |  |  |  | 7.5 |  |  |  | 5.8 |
Total Regulatory Assets |  | $ | 126.9 |  |  | $ | 115.4 |  |  | $ | 145.4 |
Less: Current Portion of Regulatory Assets(1) |  |  | 22.6 |  |  |  | 27.3 |  |  |  | 37.8 |
Regulatory Assets – noncurrent |  | $ | 104.3 |  |  | $ | 88.1 |  |  | $ | 107.6 |

(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) |  | 2015 |  |  | 2014 |  |  | 2014 |
Regulatory Tracker Mechanisms |  | $ | 20.2 |  |  | $ | 13.0 |  |  | $ | 8.8 |
Gas Pipeline Refund (Note 6) |  |  | 22.0 |  |  |  | — |  |  |  | — |
Total Regulatory Liabilities |  |  | 42.2 |  |  |  | 13.0 |  |  | $ | 8.8 |
Less: Current Portion of Regulatory Liabilities |  |  | 31.2 |  |  |  | 13.0 |  |  |  | 8.7 |
Regulatory Liabilities – noncurrent |  | $ | 11.0 |  |  | $ | — |  |  | $ | 0.1 |

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. 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.

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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. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of June 30, 2015, all futures contracts purchased under the prior program design were sold and the hedging portfolio now consists entirely of call option contracts.

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 Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of June 30, 2015, June 30, 2014 and December 31, 2014 the Company had 2.9 billion, 2.3 billion and 2.4 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s unaudited Consolidated Balance Sheets.

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Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of: |
|  |  |  | Fair Value |
Description |  | Balance Sheet Location |  | June 30, 2015 |  |  | June 30, 2014 |  |  | December 31, 2014 |
Derivative Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural Gas Options Contracts |  | Prepayments and Other |  | $ | — |  |  | $ | — |  |  | $ | — |
Natural Gas Options Contracts |  | Other Assets |  |  | 0.1 |  |  |  | — |  |  |  | 0.1 |
Total Derivative Assets |  |  |  | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |
Derivative Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural Gas Options Contracts |  | Other Current Liabilities |  | $ | — |  |  | $ | 0.1 |  |  | $ | — |
Natural Gas Options Contracts |  | Other Noncurrent Liabilities |  |  | — |  |  |  | 0.1 |  |  |  | — |
Total Derivative Liabilities |  |  |  | $ | — |  |  | $ | 0.2 |  |  | $ | — |

|  | Three Months Ended June 30, |  |  | Six Months Ended June 30, |
($ millions) |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural Gas Futures / Options Contracts |  | $ | — |  |  | $ | 0.4 |  |  | $ | — |  |  | $ | (0.5 | )
Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings(1): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of Gas Sales |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (0.9 | )

(1) | These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

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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) |  | 2015 |  |  | 2014 |  |  | 2014 |
Current: |  |  |  |  |  |  |  |  |  |  |  |
Exchange Gas Obligation |  | $ | 6.7 |  |  | $ | 7.6 |  |  | $ | 14.2 |
Renewable Energy Portfolio Standards |  |  | 6.7 |  |  |  | 4.0 |  |  |  | 7.4 |
Power Supply Contract Divestitures |  |  | 0.4 |  |  |  | 0.7 |  |  |  | 0.5 |
Total Energy Supply Obligations – Current |  |  | 13.8 |  |  |  | 12.3 |  |  |  | 22.1 |
Long-Term: |  |  |  |  |  |  |  |  |  |  |  |
Power Supply Contract Divestitures |  |  | 1.8 |  |  |  | 2.2 |  |  |  | 1.9 |
Total Energy Supply Obligations |  | $ | 15.6 |  |  | $ | 14.5 |  |  | $ | 24.0 |

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

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

Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling 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 current and noncurrent obligations related to these divestitures are recorded in Energy Supply Obligations and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

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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 one 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.

Recently Issued Pronouncements – On April 7, 2015, the FASB issued 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. The effective date of this pronouncement is for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

On May 28, 2014, the FASB issued ASU 2014-09 which 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.

Other than ASU 2015-03 and ASU 2014-09, 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
07/22/15 |  | 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
10/21/14 |  | 11/28/14 |  | 11/14/14 |  | $ 0.345
07/22/14 |  | 08/29/14 |  | 08/15/14 |  | $ 0.345
04/22/14 |  | 05/29/14 |  | 05/15/14 |  | $ 0.345
01/16/14 |  | 02/28/14 |  | 02/14/14 |  | $ 0.345

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NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and six months ended June 30, 2015 and June 30, 2014 and as of December 31, 2014 (millions):

Three Months Ended June 30, 2015 |  | Gas |  |  | Electric |  |  | Non- Regulated |  |  | Other |  |  | Total |
Revenues |  | $ | 27.6 |  |  | $ | 48.4 |  |  | $ | 1.5 |  |  | $ | — |  |  | $ | 77.5 |
Segment Profit (Loss) |  |  | (0.7 | ) |  |  | 1.9 |  |  |  | 0.3 |  |  |  | 0.2 |  |  |  | 1.7 |
Capital Expenditures |  |  | 15.7 |  |  |  | 7.3 |  |  |  | 0.1 |  |  |  | 2.3 |  |  |  | 25.4 |
Three Months Ended June 30, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 25.8 |  |  | $ | 46.1 |  |  | $ | 1.4 |  |  | $ | — |  |  | $ | 73.3 |
Segment Profit (Loss) |  |  | (0.7 | ) |  |  | 1.4 |  |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 1.1 |
Capital Expenditures |  |  | 13.3 |  |  |  | 5.0 |  |  |  | 0.2 |  |  |  | 1.4 |  |  |  | 19.9 |
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 |  |  | 22.9 |  |  |  | 11.7 |  |  |  | 0.1 |  |  |  | 3.8 |  |  |  | 38.5 |
Segment Assets |  |  | 587.4 |  |  |  | 410.9 |  |  |  | 6.0 |  |  |  | 7.1 |  |  |  | 1,011.4 |
Six Months Ended June 30, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Revenues |  | $ | 118.4 |  |  | $ | 108.0 |  |  | $ | 3.0 |  |  | $ | — |  |  | $ | 229.4 |
Segment Profit |  |  | 10.8 |  |  |  | 2.3 |  |  |  | 0.4 |  |  |  | 0.2 |  |  |  | 13.7 |
Capital Expenditures |  |  | 16.3 |  |  |  | 10.1 |  |  |  | 0.3 |  |  |  | 2.4 |  |  |  | 29.1 |
Segment Assets |  |  | 490.6 |  |  |  | 391.7 |  |  |  | 6.0 |  |  |  | 12.3 |  |  |  | 900.6 |
As of December 31, 2014 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Segment Assets |  | $ | 566.3 |  |  | $ | 414.1 |  |  | $ | 6.3 |  |  | $ | 13.5 |  |  | $ | 1,000.2 |

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NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt – On October 15, 2014, Northern Utilities completed a private placement of $50 million aggregate principal amount of 4.42% Senior Unsecured Notes due October 15, 2044 to institutional investors. The proceeds from the offering were used to repay short-term debt and for general corporate purposes.

Details on long-term debt at June 30, 2015, June 30, 2014 and December 31, 2014 are shown below:

($ millions) |  | June 30, |  |  | December 31, |
|  | 2015 |  |  | 2014 |  |  | 2014 |
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 |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
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 |  |  | 15.2 |  |  |  | 19.0 |  |  |  | 15.2 |
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, Inc.: |  |  |  |  |  |  |  |  |  |  |  |
Senior Notes: |  |  |  |  |  |  |  |  |  |  |  |
6.95% Senior Notes, 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, Due December 3, 2038 |  |  | 50.0 |  |  |  | 50.0 |  |  |  | 50.0 |
4.42% Senior Notes, Due October 15, 2044 |  |  | 50.0 |  |  |  | — |  |  |  | 50.0 |
Granite State Gas Transmission, Inc.: |  |  |  |  |  |  |  |  |  |  |  |
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 |  |  | 1.5 |  |  |  | 2.1 |  |  |  | 1.7 |
Total Long-Term Debt |  |  | 332.7 |  |  |  | 287.1 |  |  |  | 332.9 |
Less: Current Portion |  |  | 4.1 |  |  |  | 2.5 |  |  |  | 4.0 |
Total Long-term Debt, Less Current Portion |  | $ | 328.6 |  |  | $ | 284.6 |  |  | $ | 328.9 |

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

(millions) |  | June 30, |  |  | December 31, |
|  | 2015 |  |  | 2014 |  |  | 2014 |
Estimated Fair Value of Long-Term Debt |  | $ | 365.6 |  |  | $ | 338.5 |  |  | $ | 380.6 |

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 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 plus 1.375%. 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.

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The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of June 30, 2015, June 30, 2014 and December 31, 2014:

|  | Revolving Credit Facility (millions) |
|  | June 30, |  |  | December 31, |
|  | 2015 |  |  | 2014 |  |  | 2014 |
Limit |  | $ | 120.0 |  |  | $ | 120.0 |  |  | $ | 120.0 |
Outstanding |  | $ | — |  |  | $ | 35.0 |  |  | $ | 29.3 |
Available |  | $ | 120.0 |  |  | $ | 85.0 |  |  | $ | 90.7 |

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’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, 2015, June 30, 2014 and December 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4.)

On December 23, 2014, Standard & Poor’s Ratings Services assigned its “BBB+” issuer credit rating to Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy and Northern Utilities.

In April 2014, Unitil Service Corp. entered into a financing arrangement for information systems software and various technology equipment. The financing arrangement is structured as a capital lease obligation with maximum availability of $15 million. As of June 30, 2015, Unitil Service Corp. has received funding under this financing arrangement in the amount of $9.1 million, which was used to fund project costs.

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 $6.8 million, $7.8 million and $15.1 million of natural gas storage inventory at June 30, 2015, June 30, 2014 and December 31, 2014, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2015 and payable in July 2015 is $0.1 million and is recorded in Accounts Payable at June 30, 2015. The amount of natural gas inventory released in June 2014 and payable in July 2014 was $0.2 million and is recorded in Accounts Payable at June 30, 2014. The amount of natural gas inventory released in December 2014 and payable in January 2015 was $1.0 million and was recorded in Accounts Payable at December 31, 2014.

Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of June 30, 2015, there were approximately $20.1 million of guarantees outstanding and the longest term guarantee extends through April 2016.

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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, 2015, the principal amount outstanding for the 8% Unitil Realty notes was $1.5 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of June 30, 2015, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 13,895,777, 13,916,026 and 13,974,576 shares of common stock outstanding at June 30, 2014, December 31, 2014 and June 30, 2015, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first six months of 2015, the Company sold 19,411 shares of its common stock, at an average price of $34.04 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $661,000. 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

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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, 2015, 40,010 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.5 million. There were 80,588 and 67,334 non-vested shares under the Stock Plan as of June 30, 2015 and 2014, respectively. The weighted average grant date fair value of these shares was $33.14 and $28.51, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.5 million and $1.2 million for the six months ended June 30, 2015 and 2014, respectively. At June 30, 2015, there was approximately $1.3 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.8 years. There were 871 restricted shares forfeited and there were no cancellations under the Stock Plan during the six months ended June 30, 2015.

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, 2014 |  |  | 23,576 |  |  | $ | 29.90 |
Restricted Stock Units Granted |  |  | — |  |  |  | — |
Dividend Equivalents Earned |  |  | 486 |  |  | $ | 34.12 |
Restricted Stock Units Settled |  |  | — |  |  |  | — |
Restricted Stock Units as of June 30, 2015 |  |  | 24,062 |  |  | $ | 29.98 |

There were 15,225 Restricted Stock Units outstanding as of June 30, 2014 with a weighted average stock price of $28.97. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of June 30, 2015, June 30, 2014 and December 31, 2014 is $0.3 million, $0.2 million and $0.4 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 2,059 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2015. There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2014 and December 31, 2014. 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, 2015 and June 30, 2014, respectively.

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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, 2014 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2015.

Regulatory Matters

Northern Utilities – Base Rates – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also 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 2014 TIRA provided for an annual increase in base distribution revenue of $1.3 million, effective May 1, 2014. On February 27, 2015 Northern Utilities filed its second annual TIRA for rates effective May 1, 2015, seeking an annual increase in base distribution revenue of $1.2 million, effective May 1, 2015. The MPUC approved this filing on April 29, 2015.

Northern Utilities – Base Rates – New Hampshire – On April 21, 2014, the NHPUC approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue, effective May 1, 2014, and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. These permanent rates were reconciled to the date temporary rates were established, July 1, 2013. In addition, the settlement agreement provided for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provided for an annual increase in revenue of $1.4 million, effective May 1, 2014. On February 27, 2015 Northern Utilities’ New Hampshire division filed for a step increase of $1.8 million in base distribution revenue effective May 1, 2015. On April 28, 2015, the NHPUC approved the step increase.

Northern Utilities – Pipeline Refund – On May 12, 2010, Portland Natural Gas Transmission System (PNGTS) filed a Natural Gas Act Section 4 rate case with the FERC proposing increased pipeline rates of approximately 55 percent over the previously approved rate. The filing was docketed as RP10-729 and rates went into effect on December 1, 2010, subject to refund pending the determination in the rate proceeding. Northern Utilities and other long-term shippers on PNGTS opposed the proposed rate increase. On December 8, 2011, an Initial Decision was issued and on March 21, 2013, the FERC issued Opinion No. 524. Opinion No. 524 was appealed and the FERC issued Opinion No. 524-A on February 19, 2015 denying all appeals and ordering PNGTS to issue refunds to shippers within 60 days. 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 over a three year period to Northern Utilities’ customers in Maine and New Hampshire, as directed by the MPUC and NHPUC, respectively. The Company has recorded current and noncurrent Regulatory Liabilities of $11.1 million and $10.9 million, respectively, on its Consolidated Balance Sheets as of June 30, 2015.

Unitil Energy – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On April 30, 2014 the NHPUC approved Unitil Energy’s third and final step increase of $1.5 million in annual revenue effective May 1, 2014.

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Granite State – Base Rates – Granite State has in place a FERC approved amended settlement agreement under which it has been 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 27, 2014, Granite State filed to increase its rates and annual revenue by an additional $0.6 million beginning August 1, 2014. With this filing, Granite State reached the cost cap. The settlement agreement required Granite State to file a new FERC rate case by June 2015 with rates effective by January 1, 2016. On June 12, 2015, Granite State filed a second amended settlement agreement under which it will continue to be permitted each June to file for a rate adjustment to recover the revenue requirements associated with other specified capital investments in gas transmission projects up to a specific cost cap. The June 2015 filing proposed an annual revenue increase of $0.4 million, beginning August 1, 2015. A FERC decision is pending.

Fitchburg—Base Rates—Electric—On June 16, 2015 Fitchburg filed for a $3.8 million increase in electric base revenue which represents a 5.6 percent increase over 2014 test year operating electric revenues. The filing also included a request for approval of a capital cost recovery mechanism to recover prudently incurred additions to utility plant on an annual basis. The matter has been docketed by the MDPU and discovery has commenced. By statute, the MDPU is afforded ten months to act on a request for a rate increase. Accordingly, a decision is expected by the end of April, 2016.

Fitchburg—Base Rates—Gas—On June 16, 2015 Fitchburg filed for a $3.0 million increase in gas base revenue which represents an 8.3 percent increase over 2014 test year total gas operating revenues. The matter has been docketed by the MDPU and discovery has commenced. By statute, the MDPU is afforded ten months to act on a request for a rate increase. Accordingly, a decision is expected by the end of April, 2016.

Major Storms—Fitchburg and Unitil Energy

Thanksgiving 2014 Snow Storm—Both Fitchburg and Unitil Energy experienced a significant snow storm that began the afternoon of November 26, 2014 and ended the morning of November 27, 2014, Thanksgiving Day. Unitil Energy spent approximately $2.1 million for the repair and replacement of electric distribution systems damaged during the storm, including $0.4 million related to capital construction and $1.7 million for which Unitil Energy will seek recovery of through its approved storm reserve fund, subject to review by the NHPUC in a future regulatory proceeding. Fitchburg spent approximately $0.3 million for the repair and replacement of electric distribution systems damaged during the storm, including $0.1 million related to capital construction and $0.2 million in storm expense. As Fitchburg does not have an approved storm reserve fund, these expenses resulted in a pre-tax charge against 2014 earnings of $0.2 million. The Company does not believe these 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.

Fitchburg—Electric Operations—On November 24, 2014, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. All of the rates were approved effective January 1, 2015 for billing purposes, subject to reconciliation pending investigation by the MDPU. This matter remains pending.

Fitchburg—Gas Operations—On June 26, 2014, the Governor of Massachusetts signed into law a gas leak bill providing for the following, among other items: amends MDPU’s ability to fine gas companies for violations of gas pipeline safety rules consistent with federal law; establishes a uniform natural gas leak classification standard for the Commonwealth; provides that the MDPU investigate new programs and policies to facilitate customer conversions to natural gas; and

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establishes an infrastructure replacement program to address aging natural gas pipeline infrastructure. The infrastructure replacement program allows gas distribution companies to accelerate the replacement of eligible infrastructure in order to improve public safety or infrastructure reliability, and to reduce or potentially reduce lost and unaccounted for natural gas. The law also authorizes gas companies to begin to recover through rates the estimated costs associated with infrastructure plans once they are approved by the MDPU, subject to reconciliation to actual prudently incurred costs. Pursuant to this new law, on October 31, 2014, Fitchburg Gas filed with the MDPU a 20 year gas system enhancement plan to replace aging natural gas pipeline infrastructure. On April 30, 2015, the MDPU approved the Company’s plan and allowed the Company to collect $0.3 million to recover the estimated cost to be incurred in calendar year 2015, the first year of the program, to replace eligible leak-prone infrastructure, effective May 1, 2015.

Fitchburg – Service Quality – On March 1, 2015, Fitchburg submitted its 2014 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 its gas division except for the metric related to consumer complaints. As a result of penalty offsets earned, no net penalty was assessed. The electric division met or exceeded all metric benchmarks. On December 22, 2014, the MDPU approved Fitchburg’s 2011 electric division Service Quality Report as filed. On July 7, 2015, the MDPU approved Fitchburg’s 2013 gas division Service Quality Report as filed. Fitchburg’s 2012, 2013, and 2014 electric division Service Quality Reports remain pending, as does its 2014 gas division Service Quality Report.

Amendments to MDPU Service Quality Guidelines – On December 22, 2014, the MDPU issued an order adopting new Service Quality Guidelines. The new guidelines, which are to be implemented over several years, establish state-wide standards for most metrics, impose new methods for calculating penalty thresholds, eliminate the ability to offset subpar performance in one metric by exemplary performance in another, and add several new or enhanced metrics. The joint utilities have filed a motion with the MDPU to reconsider the adoption of state-wide standards and have requested reconsideration and clarification on other technical issues. The Company does not believe that the MDPU’s new Service Quality Guidelines will have a material adverse impact on the Company’s financial condition or results of operations.

Fitchburg – Other – On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, commenced an investigation of the incident, with which Fitchburg cooperated. The MDPU released its report of the incident on May 7, 2015, without finding of fault. No further action or investigation by the MDPU is anticipated. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in Fitchburg’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of Fitchburg’s bad debt, and the rate decisions in 2006 and 2007. On May 20, 2015, the MDPU issued its decision, allowing Fitchburg to retain the bad debt amounts that were previously collected in rates, and no refunds or other adjustments were required. This matter is now closed. The final decision did not have an impact on the Company’s consolidated financial statements.

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On December 23, 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.” On June 12, 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 will be 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. On November 5, 2014, the MDPU issued two inter-related orders regarding Grid Modernization. The first order provides guidance and filing requirements for the business case justification that the electric companies must file as part of their GMPs. The second order requires the electric companies to implement sufficient advanced metering functionality to enable the sale of electricity to Basic Service customers via time varying rates (rates which vary depending upon the period or time of day that the electricity is consumed). The MDPU determined that time varying rates will establish pricing signals that will enable customers to save money by altering usage patterns and reducing peak load, among other enumerated benefits. The electric companies’ initial GMPs are to be filed in August 2015. The MDPU is addressing in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles. These matters remain pending.

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 the Company’s financial position.

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 Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. The plaintiffs appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”), and the SJC has now upheld the lower Court’s order. Plaintiffs filed a renewed motion to certify a class under a different theory than previously argued. The Company filed its opposition to this motion and also filed a motion for summary judgment. Oral arguments on both motions were held in June 2015, and a decision is pending. The Town of Lunenburg has filed a separate action in the Court arising out of the December 2008 ice storm. The Court accepted the parties’ joint schedule with discovery continuing into 2016 and trial likely in late 2016. The Company continues to believe that both of these suits are without merit and will continue to defend itself vigorously.

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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, 2014 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2015.

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 believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of June 30, 2015, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you 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 that were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites.

The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. Final remediation activities in Portland are scheduled to commence in October 2015 with an anticipated completion in January 2016. In May 2014, the State of Maine completed its taking of the site via eminent domain for the expansion of the adjacent marine terminal. As a result of the outcome of negotiations with the State of Maine, future operation, maintenance and remedial costs have been accrued, to ensure that applicable remedial activities are completed.

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 a remedial design is being developed. Final remediation activities of the off-site location are anticipated to occur in the fall of 2015. Given the presence of sediment and need for an appropriate design, future remedial costs of $1.7 million have been accrued on the Company’s Consolidated Balance Sheets as of June 30, 2015, to ensure that applicable remedial activities are completed.

The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over succeeding seven-year periods, without carrying costs. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over succeeding five-year periods, without carrying costs.

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

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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 December 2014. The closure documentation for the site has been submitted and is being reviewed by regulators. A final regulatory determination is anticipated in the summer/fall of 2015. A limited sediment investigation, which commenced in late 2014, will be managed through the final determination. The Company’s estimate for this work is $5.5 million. As of June 30, 2015, $3.8 million was spent on this remediation project.

The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, 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, 2015 and 2014.

Environmental Obligations |  |  |  |  |  |  |  |  |
|  | ($ millions) |
|  | Fitchburg |  |  | Northern Utilities |  |  | Total |
|  | Six months ended June 30, |
|  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |
Total Balance at Beginning of Period |  | $ | 1.9 |  |  | $ | 12.0 |  |  | $ | 3.6 |  |  | $ | 2.8 |  |  | $ | 5.5 |  |  | $ | 14.8 |
Additions |  |  | 0.1 |  |  |  | 5.5 |  |  |  | 0.2 |  |  |  | 0.6 |  |  |  | 0.3 |  |  |  | 6.1 |
Less: Payments / Reductions |  |  | 0.2 |  |  |  | 12.3 |  |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.4 |  |  |  | 12.5 |
Total Balance at End of Period |  |  | 1.8 |  |  |  | 5.2 |  |  |  | 3.6 |  |  |  | 3.2 |  |  |  | 5.4 |  |  |  | 8.4 |
Less: Current Portion |  |  | 1.8 |  |  |  | 5.2 |  |  |  | 1.6 |  |  |  | 1.2 |  |  |  | 3.4 |  |  |  | 6.4 |
Noncurrent Balance at End of Period |  | $ | — |  |  | $ | — |  |  | $ | 2.0 |  |  | $ | 2.0 |  |  | $ | 2.0 |  |  | $ | 2.0 |

NOTE 8: INCOME TAXES

The Company filed its tax returns for the year ended December 31, 2013 with the Internal Revenue Service (IRS) in September 2014 and generated federal net operating loss (NOL) carryforward assets of $2.1 million principally due to bonus depreciation and targeted asset repair deductions. As of December 31, 2014, the Company had recorded cumulative federal and state

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NOL carryforward assets of $13.1 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2014, the Company had $2.1 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

The Company evaluated its tax positions at June 30, 2015 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, 2011; December 31, 2012; and December 31, 2013.

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, 2014 as filed with the SEC on January 28, 2015 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:

|  | 2015 |  |  | 2014 |
Used to Determine Plan Costs |  |  |  |  |  |  |  |
Discount Rate |  |  | 4.00 | % |  |  | 4.80 | %
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 |  |  | 6.00 | % |  |  | 7.00 | %
Ultimate Health Care Cost Trend Rate |  |  | 4.00 | % |  |  | 4.00 | %
Year that Ultimate Health Care Cost Trend Rate is reached |  |  | 2018 |  |  |  | 2018 |

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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, |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |
Service Cost |  | $ | 916 |  |  | $ | 751 |  |  | $ | 656 |  |  | $ | 497 |  |  | $ | 28 |  |  | $ | 14 |
Interest Cost |  |  | 1,343 |  |  |  | 1,273 |  |  |  | 729 |  |  |  | 672 |  |  |  | 78 |  |  |  | 68 |
Expected Return on Plan Assets |  |  | (1,694 | ) |  |  | (1,561 | ) |  |  | (273 | ) |  |  | (230 | ) |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 54 |  |  |  | 53 |  |  |  | 420 |  |  |  | 420 |  |  |  | 3 |  |  |  | 3 |
Actuarial Loss Amortization |  |  | 1,180 |  |  |  | 712 |  |  |  | 288 |  |  |  | 14 |  |  |  | 84 |  |  |  | 25 |
Sub-total |  |  | 1,799 |  |  |  | 1,228 |  |  |  | 1,820 |  |  |  | 1,373 |  |  |  | 193 |  |  |  | 110 |
Amounts Capitalized and Deferred |  |  | (875 | ) |  |  | (501 | ) |  |  | (881 | ) |  |  | (593 | ) |  |  | — |  |  |  | — |
Net Periodic Benefit Cost Recognized |  | $ | 924 |  |  | $ | 727 |  |  | $ | 939 |  |  | $ | 780 |  |  | $ | 193 |  |  | $ | 110 |
|  | Pension Plan |  |  | PBOP Plan |  |  | SERP |
Six Months Ended June 30, |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |
Service Cost |  | $ | 1,832 |  |  | $ | 1,502 |  |  | $ | 1,312 |  |  | $ | 994 |  |  | $ | 56 |  |  | $ | 28 |
Interest Cost |  |  | 2,686 |  |  |  | 2,546 |  |  |  | 1,458 |  |  |  | 1,344 |  |  |  | 156 |  |  |  | 136 |
Expected Return on Plan Assets |  |  | (3,388 | ) |  |  | (3,122 | ) |  |  | (546 | ) |  |  | (460 | ) |  |  | — |  |  |  | — |
Prior Service Cost Amortization |  |  | 108 |  |  |  | 106 |  |  |  | 840 |  |  |  | 840 |  |  |  | 6 |  |  |  | 6 |
Actuarial Loss Amortization |  |  | 2,360 |  |  |  | 1,424 |  |  |  | 576 |  |  |  | 28 |  |  |  | 168 |  |  |  | 50 |
Sub-total |  |  | 3,598 |  |  |  | 2,456 |  |  |  | 3,640 |  |  |  | 2,746 |  |  |  | 386 |  |  |  | 220 |
Amounts Capitalized and Deferred |  |  | (1,583 | ) |  |  | (844 | ) |  |  | (1,642 | ) |  |  | (1,065 | ) |  |  | — |  |  |  | — |
Net Periodic Benefit Cost Recognized |  | $ | 2,015 |  |  | $ | 1,612 |  |  | $ | 1,998 |  |  | $ | 1,681 |  |  | $ | 386 |  |  | $ | 220 |

Employer Contributions

As of June 30, 2015, the Company had made $1.8 million of contributions to its Pension Plan in 2015 and had not made any contributions to its PBOP Plan in 2015. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2015 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, 2015, the Company had made $23,300 of contributions to the SERP Plan in 2015. The Company presently anticipates contributing an additional $17,000 to the SERP Plan in 2015.

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, 2015. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of June 30, 2015 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

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There have been no changes in the Company’s internal 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, 2014 as filed with the SEC on January 28, 2015.

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, 2015.

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 1, 2015, 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 $76,000 in value of shares have been purchased or, if sooner, on May 1, 2016.

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

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The following table shows information regarding repurchases by the Company of shares of its common stock pursuant to the trading plan for each month in the quarter ended June 30, 2015.

|  | 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 |
4/1/15 – 4/30/15 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 2,925 |
5/1/15 – 5/31/15 |  |  | — |  |  |  | — |  |  |  | — |  |  | $ | 76,000 |
6/1/15 – 6/30/15 |  |  | 203 |  |  | $ | 33.90 |  |  |  | 203 |  |  | $ | 69,118 |
Total |  |  | 203 |  |  |  |  |  |  |  | 203 |  |  |  |  |

Item 5. | Other Information

On July 23, 2015, the Company issued a press release announcing its results of operations for the three- and six-month periods ended June 30, 2015. 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 23, 2015 Announcing Earnings For the Quarter Ended June 30, 2015. |  | 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

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101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document |  | Filed herewith
101.LAB |  | XBRL Taxonomy Extension Label Linkbase Document. |  | Filed herewith
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document. |  | Filed herewith

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SIGNATURES

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

|  | UNITIL CORPORATION
|  | (Registrant)
Date: July 23, 2015 |  | /s/ Mark H. Collin
|  | Mark H. Collin
|  | Chief Financial Officer
Date: July 23, 2015 |  | /s/ Laurence M. Brock
|  | Laurence M. Brock
|  | Chief Accounting Officer

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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 23, 2015 Announcing Earnings For the Quarter Ended June 30, 2015. |  | Filed herewith
101.INS |  | XBRL Instance Document. |  | Filed herewith
101.SCH |  | XBRL Taxonomy Extension Schema Document. |  | Filed herewith
101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document. |  | Filed herewith
101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document |  | Filed herewith
101.LAB |  | XBRL Taxonomy Extension Label Linkbase Document. |  | Filed herewith
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document. |  | Filed herewith

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