10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

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 offices)	(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, No Par Value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No   x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K  x

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.

Large accelerated filer  ¨      Accelerated filer   x      Non-accelerated filer  ¨      Smaller reporting company  ¨

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

Based on the closing price of the registrant’s common stock on June 30, 2015, the aggregate market value of common stock held by non-affiliates of the registrant was $452,207,259.

The number of shares of the registrant’s common stock outstanding was 13,992,817 as of January 25, 2016.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on April 20, 2016 are incorporated by reference into Part III of this Report

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2015

Table of Contents

Item	Description	Page
	PART I
1.	Business		2
	Unitil Corporation		2
	Operations		3
	Rates and Regulation		5
	Natural Gas Supply		7
	Electric Power Supply		7
	Environmental Matters		9
	Employees		10
	Available Information		10
	Investor Information		10
1A.	Risk Factors		11
1B.	Unresolved Staff Comments		17
2.	Properties		17
3.	Legal Proceedings		18
4.	Mine Safety Disclosures		18
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		19
6.	Selected Financial Data		22
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)		23
7A.	Quantitative and Qualitative Disclosures about Market Risk		43
8.	Financial Statements and Supplementary Data		44
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		88
9A.	Controls and Procedures		88
9B.	Other Information		88
	PART III
10.	Directors, Executive Officers and Corporate Governance		89
11.	Executive Compensation		89
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		89
13.	Certain Relationships and Related Transactions, and Director Independence		89
14.	Principal Accountant Fees and Services		89
	PART IV
15.	Exhibits and Financial Statement Schedules		90
	SIGNATURES
	Signatures		94

CAUTIONARY STATEMENT

This report and the documents incorporated by reference into this report contain statements that may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, 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 future operations of the Company (as such term is defined in Part I, Item I (Business)), 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 Part I, 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, gas and electric energy commodities and transmission and transportation capacity and the Company’s ability to recover energy supply costs in its rates;

• customers’ preferred energy sources;

• severe storms and the Company’s ability to recover storm 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 counterparty’s obligations (including those of its insurers and lenders);

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

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

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

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

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

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

• catastrophic events;

• the Company’s ability to retain its existing customers and attract new customers; 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, except as required by law. 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.

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PART I

Item 1. Business

UNITIL CORPORATION

In this Annual Report on Form 10-K, the “Company”, “Unitil”, “we”, and “our” refer to Unitil Corporation and its subsidiaries, unless the context requires otherwise. Unitil is a public utility holding company and was incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:

Company Name	State and Year of Organization	Principal Business
Unitil Energy Systems, Inc. (Unitil Energy)	NH - 1901	Electric Distribution Utility
Fitchburg Gas and Electric Light Company (Fitchburg)	MA - 1852	Electric & Natural Gas Distribution Utility
Northern Utilities, Inc. (Northern Utilities)	NH - 1979	Natural Gas Distribution Utility
Granite State Gas Transmission, Inc. (Granite State)	NH - 1955	Natural Gas Transmission Pipeline
Unitil Power Corp. (Unitil Power)	NH - 1984	Wholesale Electric Power Utility
Unitil Service Corp. (Unitil Service)	NH - 1984	Utility Service Company
Unitil Realty Corp. (Unitil Realty)	NH - 1986	Real Estate Management
Unitil Resources, Inc. (Unitil Resources)	NH - 1993	Non-regulated Energy Services
Usource Inc. and Usource L.L.C. (collectively Usource)	DE - 2000	Energy Brokering Services

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.

Unitil’s principal business is the local distribution of electricity and natural gas to approximately 182,000 customers throughout its service territories in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities: i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord, ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts, and iii) 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. In addition, Unitil is the parent company of Granite State, an interstate natural gas transmission pipeline company that provides interstate natural gas pipeline access and transportation services to Northern Utilities in its New Hampshire and Maine service territory. Together, Unitil’s three distribution utilities serve approximately 103,300 electric customers and 78,700 natural gas customers.

	Customers Served as of December 31, 2015
	Residential		Commercial & Industrial (C&I)		Total
Electric:
Unitil Energy		63,462		11,056		74,518
Fitchburg		24,982		3,769		28,751
Total Electric		88,444		14,825		103,269
Natural Gas:
Northern Utilities		47,247		15,823		63,070
Fitchburg		14,023		1,656		15,679
Total Natural Gas		61,270		17,479		78,749
Total Customers Served		149,714		32,304		182,018

Unitil’s distribution utilities had an investment in Net Utility Plant of $808.9 million at December 31, 2015. Unitil’s total operating revenue was $426.8 million in 2015. Unitil’s operating revenue is substantially derived from regulated natural gas and electric distribution utility operations.

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A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy, but currently has limited business and operating activities. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy in 2003 and divested of substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with those contracts.

Unitil also has three other wholly-owned non-utility 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 and energy supply 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. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are indirect subsidiaries that are wholly-owned by Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. For segment information relating to each segment’s revenue, earnings and assets, see Note 3 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report. All of the Company’s revenues are attributable to customers in the United States of America and all its long-lived assets are located in the United States of America.

OPERATIONS

Natural Gas Operations

Unitil’s natural gas operations include gas distribution utility operations and interstate gas transmission pipeline operations, discussed below. Revenue from Unitil’s gas operations was $202.6 million for 2015, which represents about 47% of Unitil’s total operating revenue.

Natural Gas Distribution Utility Operations

Unitil’s natural gas distribution operations are conducted through two of the Company’s operating utilities, Northern Utilities and Fitchburg. The primary business of Unitil’s natural gas utility operations is the local distribution of natural gas to customers in its service territories in New Hampshire, Massachusetts and Maine. As a result of a restructuring of the gas utility industry, Northern Utilities’ Commercial and Industrial (C&I) customers and Fitchburg’s residential and C&I customers have the opportunity to purchase their natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through Northern Utilities and Fitchburg under regulated rates and tariffs. Northern Utilities and Fitchburg purchase natural gas from unaffiliated wholesale suppliers and recover the actual costs of these natural gas supplies on a pass-through basis through reconciling rate mechanisms that are periodically adjusted.

Natural gas is supplied and distributed by Northern Utilities to approximately 63,000 customers in 44 New Hampshire and southern Maine communities, from Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine in the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include healthcare, education, government and retail. Northern Utilities’ industrial base includes manufacturers in the auto, housing, rubber, printing, textile, pharmaceutical, electronics, wire and food production industries as well as a military installation. Northern Utilities’ 2015 gas operating revenue was $165.3 million, of which approximately 38% was derived from residential firm sales and 62% from C&I firm sales.

Natural gas is supplied and distributed by Fitchburg to approximately 15,700 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries. Fitchburg’s 2015 gas operating revenue was $31.0 million, of which approximately 52% was derived from residential firm sales and 48% from C&I firm sales.

Gas Transmission Pipeline Operations

Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State

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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. Granite State had operating revenue of $6.3 million for 2015. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and to third-party marketers.

Electric Distribution Utility Operations

Unitil’s electric distribution operations are conducted through two of the Company’s utilities, Unitil Energy and Fitchburg. Revenue from Unitil’s electric utility operations was $218.0 million for 2015, which represents about 51% of Unitil’s total operating revenue.

The primary business of Unitil’s electric utility operations is the local distribution of electricity to customers in its service territory in New Hampshire and Massachusetts. As a result of electric industry restructuring in New Hampshire and Massachusetts, Unitil’s customers are free to contract for their supply of electricity with third-party suppliers. The distribution utilities continue to deliver that supply of electricity over their distribution systems. Both Unitil Energy and Fitchburg supply electricity to those customers who do not obtain their supply from third-party suppliers, with the approved costs associated with electricity supplied by the distribution utilities being recovered on a pass-through basis under periodically adjusted rates.

Unitil Energy distributes electricity to approximately 74,500 customers in New Hampshire in the capital city of Concord as well as parts of 12 surrounding towns and all or part of 18 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. Unitil Energy’s service territory consists of approximately 408 square miles. In addition, Unitil Energy’s service territory encompasses retail trading and recreation centers for the central and southeastern parts of the state and includes the Hampton Beach recreational area. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wire and plastics, healthcare and education. Unitil Energy’s 2015 electric operating revenue was $154.7 million, of which approximately 57% was derived from residential sales and 43% from C&I sales.

Fitchburg is engaged in the distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. Fitchburg’s service territory encompasses approximately 170 square miles. Electricity is supplied and distributed by Fitchburg to approximately 28,800 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. Fitchburg’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries and educational institutions. Fitchburg’s 2015 electric operating revenue was $63.3 million, of which approximately 60% was derived from residential sales and 40% from C&I sales.

Seasonality

The Company’s results of operations are expected to 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.

Unitil Energy, Fitchburg and Northern Utilities are not dependent on a single customer or a few customers for their electric and natural gas sales.

Non-Regulated and Other Non-Utility Operations

Unitil’s non-regulated operations are conducted through Usource, a subsidiary of Unitil Resources. Usource provides energy brokering and advisory services to a national client base of large commercial and industrial customers. Revenue from Unitil’s non-regulated operations was $6.2 million in 2015.

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The results of Unitil’s other non-utility subsidiaries, Unitil Service and Unitil Realty, and the holding company, are included in the Company’s consolidated results of operations. The results of these non-utility operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and are reported, after intercompany eliminations, in Other segment income. For segment information, see Note 3 (Segment Information) to the Consolidated Financial Statements included in Part II, Item 8 (Financial Statements and Supplementary Data) of this report.

RATES AND REGULATION

Rate Case Activity

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. The 2015 TIRA provided for an annual increase in base distribution revenue of $1.2 million, effective May 1, 2015.

Northern Utilities—Base Rates—New Hampshire—On April 21, 2014, the New Hampshire Public Utilities Commission (NHPUC) approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue, effective May 1, 2014. 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. The 2015 step adjustment provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015 the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund will be credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities will be credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities of $7.6 million and $8.1 million, respectively, on its Consolidated Balance Sheets as of December 31, 2015.

Unitil Energy—Base Rates—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. The third and final step increase of $1.5 million in annual revenue was effective May 1, 2014.

Granite State—Base Rates—Granite State had in place a FERC approved amended settlement agreement under which it had 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. The final rate adjustment under this agreement was effective August 1, 2014. Granite State has received FERC approval of a second amended settlement agreement under which it will continue to be permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a cost cap. The FERC approval of the second amended settlement included a rate increase of $0.4 million, effective August 1, 2015.

Fitchburg—Base Rates—Electric—On May 30, 2014, the Massachusetts Department of Public Utilities (MDPU) approved a $5.6 million increase in Fitchburg’s base revenue decoupling target, effective

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June 1, 2014. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 and 2012. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off. The impact of the rate order on previously capitalized or deferred items was not material.

On June 16, 2015, Fitchburg filed for a $3.8 million increase in electric base revenue decoupling target, which represents a 5.6 percent increase over 2014 test year operating electric revenues. The filing included a request for approval of a capital cost recovery mechanism to recover prudently incurred additions to utility plant on an annual basis. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. 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 decoupling target, which represents an 8.3 percent increase over 2014 test year total gas operating revenues. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of April, 2016.

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 NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and MPUC. Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

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

As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most of Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

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

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Also see Regulatory Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

NATURAL GAS SUPPLY

Unitil manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

Northern Utilities’ C&I customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities’ larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. Fitchburg’s residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies from third-party suppliers, while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. The approved costs associated with the acquisition of such wholesale natural gas supplies for customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

Regulated Natural Gas Supply

Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), to truck supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.6 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

Fitchburg purchases natural gas under contracts from producers and marketers on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round transportation and 0.33 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

ELECTRIC POWER SUPPLY

The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil’s power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2015, 79% of Unitil’s largest

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New Hampshire customers, representing 26% of total New Hampshire electric energy sales, and 88% of Unitil’s largest Massachusetts customers, representing 34% of total Massachusetts electric energy sales; are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base and customers in Ashby comprise another 5%. In New Hampshire, the number of residential customers purchasing from a third party supplier has increased more than tenfold in the past three years and stands at 13% of residential customers. Notwithstanding this activity, most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts with various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

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 and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

8

Long-Term Renewable Contracts

Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

ENVIRONMENTAL MATTERS

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 December 31, 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. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough. Northern Utilities has worked with the 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, Dover, Somersworth, Portsmouth, Lewiston and Scarborough sites, though future activities may be required.

The site in Portland has been investigated and remedial activities have largely been completed. Final remediation activities were completed in the fourth quarter of 2015, and closure documentation will be prepared for submittal to the regulatory agency in the first half of 2016. In the second quarter of 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 this taking, and pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the site will be primarily the responsibility of the State of Maine.

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 remediation activities in Exeter commenced in the fourth quarter of 2015. The anticipated completion of these activities is in the first quarter of 2016.

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

Fitchburg’s Manufactured Gas Plant Site—Fitchburg completed the scheduled site work at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the fourth quarter of 2014. The closure documentation for the site was submitted in the fourth quarter of 2015 and is under review by the Massachusetts Department of Environmental Protection.

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.

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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.

Also, see Environmental Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

EMPLOYEES

As of December 31, 2015, the Company and its subsidiaries had 500 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of December 31, 2015, a total of 159 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 December 31, 2015:

	Employees Covered		CBA Expiration
Fitchburg		44		05/31/2019
Northern Utilities NH Division		34		06/05/2017
Northern Utilities ME Division/Granite State		38		03/31/2017
Unitil Energy		38		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.

AVAILABLE INFORMATION

The Internet address for the Company’s website is www.unitil.com. On the Investors section of the Company’s website, the Company makes available, free of charge, its Securities and Exchange Commission (SEC) reports, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other reports, as well as amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practical after the Company electronically files such material with, or furnishes such material to, the SEC.

The Company’s current Code of Ethics was approved by Unitil’s Board of Directors on January 15, 2004. This Code of Ethics, along with any amendments or waivers, is also available on Unitil’s website.

Unitil’s common stock is listed on the New York Stock Exchange under the ticker symbol “UTL”.

INVESTOR INFORMATION

Annual Meeting

The Company’s annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Wednesday, April 20, 2016, at 11:30 a.m.

Transfer Agent

The Company’s transfer agent, Computershare Investor Services, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, and the distribution of Unitil’s dividends and IRS Form 1099-DIV. Shareholders may contact Computershare at:

Computershare Investor Services

P.O. Box 30170

College Station, TX 77842-3170

Telephone: 800-736-3001

www.computershare.com/investor

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Investor Relations

For information about the Company, you may call the Company directly, toll-free, at: 800-999-6501 and ask for the Investor Relations Representative; visit the Investors page at www.unitil.com; or contact the transfer agent, Computershare, at the number listed above.

Special Services & Shareholder Programs Available to Holders of Record

If a shareholder’s shares of our common stock are registered directly in the shareholder’s name with the Company’s transfer agent, the shareholder is considered a holder of record of the shares. The following services and programs are available to shareholders of record:

• Internet Account Access is available at www.computershare.com/investor.

• Dividend Reinvestment and Stock Purchase Plan:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

• Dividend Direct Deposit Service:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

• Direct Registration:

For information, please contact Computershare at 800-935-9330 or the Company’s Investor Relations Representative at 800-999-6501.

Item 1A. Risk Factors

Risks Relating to Our Business

The Company is subject to comprehensive regulation, which could adversely impact the rates it is able to charge, its authorized rate of return and its ability to recover costs. In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company, which could adversely affect the Company’s financial condition and results of operations.

The Company is subject to comprehensive regulation by federal regulatory authorities (including the FERC) and state regulatory authorities (including the NHPUC, MDPU and MPUC). These authorities regulate many aspects of the Company’s operations, including the rates that the Company can charge customers, the Company’s authorized rates of return, the Company’s ability to recover costs from its customers, construction and maintenance of the Company’s facilities, the Company’s safety protocols and procedures, including environmental compliance, the Company’s ability to issue securities, the Company’s accounting matters, and transactions between the Company and its affiliates. The Company is unable to predict the impact on its financial condition and results of operations from the regulatory activities of any of these regulatory authorities. Changes in regulations, the imposition of additional regulations or regulatory decisions particular to the Company could adversely affect the Company’s financial condition and results of operations.

The Company’s ability to obtain rate adjustments to maintain its current authorized rates of return depends upon action by regulatory authorities under applicable statutes, rules and regulations. These regulatory authorities are authorized to leave the Company’s rates unchanged, to grant increases in such rates or to order decreases in such rates. The Company may be unable to obtain favorable rate adjustments or to maintain its current authorized rates of return, which could adversely affect its financial condition and results of operations.

Regulatory authorities also have authority with respect to the Company’s ability to recover its electricity and natural gas supply costs, as incurred by Unitil Power, Unitil Energy, Fitchburg, and Northern Utilities. If the Company is unable to recover a significant amount of these costs, or if the Company’s recovery of these costs is significantly delayed, then the Company’s financial condition and results or operations could be adversely affected.

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In addition, certain regulatory authorities have the statutory authority to impose financial penalties and other sanctions on the Company if the Company is found to have violated statutes, rules or regulations governing its utility operations. Any such penalties or sanctions could adversely affect the Company’s financial condition and results of operations.

The Company’s electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may adversely affect the Company’s customers and correspondingly the Company’s financial condition and results of operations.

The Company’s business is influenced by the economic activity within its service territory. The level of economic activity in the Company’s electric and natural gas distribution service territories directly affects the Company’s business. As a result, adverse changes in the economy may adversely affect the Company’s financial condition and results or operations. Economic downturns or periods of high electric and gas supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. This focus on conservation, energy efficiency and self-generation may result in a decline in electricity and gas sales in our service territories. If any such declines were to occur without corresponding adjustments in rates, then our revenues would be reduced and our future growth prospects would be limited. In addition, a period of prolonged economic weakness could impact customers’ ability to pay bills in a timely manner and increase customer bankruptcies, which may lead to increased bad debt expenses or other adverse effects on our financial position, results of operations and/or cash flows.

The Company may not be able to obtain financing, or may not be able to obtain financing on acceptable terms, which could adversely affect the Company’s financial condition and results of operations.

The Company requires capital to fund utility plant additions, working capital and other utility expenditures. While the Company derives the capital necessary to meet these requirements primarily from internally-generated funds, the Company supplements internally-generated funds by incurring short-term and long-term debt, as needed. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. A downgrade of our credit rating or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

The Company’s short-term debt revolving credit facility typically has variable interest rates. Therefore, an increase or decrease in interest rates will increase or decrease the Company’s interest expense associated with its revolving credit facility. An increase in the Company’s interest expense could adversely affect the Company’s financial condition and results of operations. As of December 31, 2015, the Company had approximately $42.0 million in short-term debt outstanding under its revolving credit facility. Additionally, if the lending counterparties under the Company’s current credit facility are unwilling or unable to meet their funding obligations, then the Company may be unable to, or limited in its ability to, incur short-term debt under its credit facility. This could hinder or prevent the Company from meeting its current and future capital needs, which could correspondingly adversely affect the Company’s financial condition and results or operations.

Also, from time to time, the Company repays portions of its short-term debt with the proceeds it receives from long-term debt financings or equity financings. General economic conditions, conditions in the capital and credit markets and the Company’s operating and financial performance could negatively affect the Company’s ability to obtain such financings or the terms of such financings, which could correspondingly adversely affect the Company’s financial condition and results of operations. The Company’s long-term debt typically has fixed interest rates. Therefore, changes in interest rates will not affect the Company’s interest expense associated with its presently outstanding fixed rate long-term debt. However, an increase or decrease in interest rates may increase or decrease the Company’s interest expense associated with any new fixed rate long-term debt issued by the Company, which could adversely affect the Company’s financial condition and results of operations.

In addition, the Company may need to use a significant portion of its cash flow to repay its short-term debt and long-term debt, which would limit the amount of cash it has available for working capital, capital expenditures and other general corporate purposes and could adversely affect its financial condition and results of operations.

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Declines in the valuation of capital markets could require the Company to make substantial cash contributions to cover its pension and other post-retirement benefit obligations. If the Company is unable to recover a significant amount of pension and other post-retirement benefit obligation costs in its rates, or if the Company’s recovery of these costs in its rates is significantly delayed, then the Company’s financial condition and results of operations could be adversely affected.

The amount of cash contributions the Company is required to make in respect of its pension and other post-retirement benefit obligations is dependent upon the valuation of the capital markets. Adverse changes in the valuation of the capital markets could result in the Company being required to make substantial cash contributions in respect to these obligations. These cash contributions could have an adverse effect on the Company’s financial condition and results of operations if the Company is unable to recover such costs in rates or if such recovery is significantly delayed. Please see the section entitled Critical Accounting Policies—Retirement Benefit Obligations in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 10 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements for a more detailed discussion of the Company’ pension obligations.

The terms of the Company’s and its subsidiaries’ indebtedness restrict the Company’s and its subsidiaries’ business operations (including their ability to incur material amounts of additional indebtedness), which could adversely affect the Company’s financial condition and results of operations.

The terms of the Company’s and its subsidiaries’ indebtedness impose various restrictions on the Company’s business operations, including the ability of the Company and its subsidiaries to incur additional indebtedness. These restrictions could adversely affect the Company’s financial condition and results of operations. See the sections entitled Liquidity, Commitments and Capital Requirements in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements for a more detailed discussion of these restrictions.

A significant amount of the Company’s sales are temperature sensitive. Because of this, mild winter and summer temperatures could decrease the Company’s sales, which could adversely affect the Company’s financial condition and results of operations. Also, the Company’s sales may vary from year to year depending on weather conditions, and the Company’s results of operations generally reflect seasonality.

The Company estimates that approximately 70% of its annual natural gas sales are temperature sensitive. Therefore, mild winter temperatures could decrease the amount of natural gas sold by the Company, which could adversely affect the Company’s financial condition and results of operations. The Company’s electric sales also are temperature sensitive, but less so than its natural gas sales. The highest usage of electricity typically occurs in the summer months (due to air conditioning demand) and the winter months (due to heating-related and lighting requirements). Therefore, mild summer temperatures and mild winter temperatures could decrease the amount of electricity sold by the Company, which could adversely affect the Company’s financial condition and results of operations. Also, because of this temperature sensitivity, sales by the Company’s distribution utilities vary from year to year, depending on weather conditions.

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.

13

Unitil is a public utility holding company and has no operating income of its own. The Company’s ability to pay dividends on its common stock is dependent on dividends and other payments received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure that its current annual dividend will be paid in the future.

The ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil depends on, among other things:

• the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

• the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

• the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

• limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory authorities.

In addition, before the Company can pay dividends on its common stock, it has to satisfy its debt obligations and comply with any statutory or contractual limitations.

As of January 27, 2016, the Company’s current annual dividend is $1.42 per share of common stock, payable quarterly. The Company’s Board of Directors reviews Unitil’s dividend policy periodically in light of a number of business and financial factors, including those referred to above, and the Company cannot assure the amount of dividends, if any, that may be paid in the future.

A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity and electric transmission capacity may impair the Company’s ability to meet customers’ existing and future requirements.

In order to meet existing and future customer demands for natural gas and electricity, the Company must acquire sufficient supplies of natural gas and electricity. In addition, the Company must contract for reliable and adequate upstream transmission and transportation capacity for its distribution systems while considering the dynamics of the natural gas interstate pipelines and storage, the electric transmission markets and its own on-system resources. The Company’s financial condition or results of operations may be adversely affected if the future availability of natural gas and electric supply were insufficient to meet future customer demands for natural gas and electricity.

The Company’s electric and natural gas distribution activities (including storing natural gas and supplemental gas supplies) involve numerous hazards and operating risks that may result in accidents and other operating risks and costs. Any such accident or costs could adversely affect the Company’s financial position or results of operations.

Inherent in the Company’s electric and natural gas distribution activities are a variety of hazards and operating risks, including leaks, explosions, electrocutions and mechanical problems. These hazards and risks could result in loss of human life, significant damage to property, environmental pollution, damage to natural resources and impairment of the Company’s operations, which could adversely affect the Company’s financial position or results of operations.

The Company maintains insurance against some, but not all, of these risks and losses in accordance with customary industry practice. The location of pipelines, storage facilities and electric distribution equipment near populated areas (including residential areas, commercial business centers and industrial sites) could increase the level of damages associated with these hazards and operating risks. The occurrence of any of these events could adversely affect the Company’s financial position or results of operations.

14

The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and its costs of compliance are significant. New, or changes to existing, environmental regulation, including those related to climate change or greenhouse gas emissions, and the incurrence of environmental liabilities could adversely affect the Company’s financial condition and results of operations.

The Company’s utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources, and the health and safety of the Company’s employees. The Company’s utility operations also may be subject to new and emerging federal, state and local legislative and regulatory initiatives related to climate change or greenhouse gas emissions including the U.S. Environmental Protection Agency’s mandatory greenhouse gas reporting rule. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties and other sanctions; imposition of remedial requirements; and issuance of injunctions to ensure future compliance. Liability under certain environmental laws and regulations is strict, joint and several in nature. Although the Company believes it is in material compliance with all applicable environmental and safety laws and regulations, we cannot assure you that the Company will not incur significant costs and liabilities in the future. Moreover, it is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations, including those related to climate change or greenhouse gas emissions, could result in increased environmental compliance costs.

Catastrophic events could adversely affect the Company’s financial condition and results of operations.

The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could inhibit the Company’s ability to deliver electric or natural gas to its customers for an extended period, which could adversely affect the Company’s financial condition and results of operations. Also, if the Company is unable to recover a significant amount of costs associated with catastrophic events in its rates, or if the Company’s recovery of such costs in its rates is significantly delayed, then the Company’s financial condition and results or operations may be adversely affected.

The Company’s operational and information systems on which it relies to conduct its business and serve customers could fail to function properly due to technological problems, a cyber-attack, acts of terrorism, severe weather, a solar event, an electromagnetic event, a natural disaster, the age and condition of information technology assets, human error, or other reasons, that could disrupt the Company’s operations and cause the Company to incur unanticipated losses and expense.

The operation of the Company’s extensive electricity and natural gas systems rely on evolving information technology systems and network infrastructures that are likely to become more complex as new technologies and systems are developed. The Company’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of transactions, many of which are highly complex. The failure of these information systems and networks could significantly disrupt operations; result in outages and/or damages to the Company’s assets or operations or those of third parties on which it relies; and subject the Company to claims by customers or third parties, any of which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

The Company’s information systems, including its financial information, operational systems, metering, and billing systems, require constant maintenance, modification, and updating, which can be costly and increases the risk of errors and malfunction. Any disruptions or deficiencies in existing information systems, or disruptions, delays or deficiencies in the modification or implementation of new information systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively impact the effectiveness of the Company’s control environment, and/or the Company’s ability to timely file required regulatory reports. Despite implementation of security and mitigation measures, all of the Company’s technology systems are vulnerable to impairment or failure due to cyber-attacks, computer viruses, human errors, acts of war or terrorism and other reasons. If the Company’s information technology systems were to fail or be materially impaired, the Company might be unable to fulfill critical business functions and serve its customers, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

15

In the ordinary course of its business, the Company collects and retains sensitive electronic data including personal identification information about customers and employees, customer energy usage, and other confidential information. The theft, damage, or improper disclosure of sensitive electronic data through security breaches or other means could subject the Company to penalties for violation of applicable privacy laws or claims from third parties and could harm the Company’s reputation and adversely affect the Company’s financial condition and results of operations.

In addition, the Company’s electric and natural gas distribution and transmission delivery systems are part of an interconnected regional grid and pipeline system. If these neighboring interconnected systems were to be disrupted due to cyber-attacks, computer viruses, human errors, acts of war or terrorism or other reasons, the Company’s operations and its ability to serve its customers would be adversely affected, which could have a material effect on the Company’s financial condition, results of operations, and cash flows.

The inability to attract and retain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, could have an adverse effect on the Company’s operations.

The success of our business depends on the leadership of our executive officers and other key employees to implement our business strategies. The inability to maintain a qualified workforce including, but not limited to, executive officers, key employees and employees with specialized skills, may negatively affect our ability to service our existing or new customers, or successfully manage our business or achieve our business objectives. There may not be sufficiently skilled employees available internally to replace employees when they retire or otherwise leave active employment. Shortages of certain highly skilled employees may also mean that qualified employees are not available externally to replace these employees when they are needed. In addition, shortages in highly skilled employees coupled with competitive pressures may require the Company to incur additional employee recruiting and compensation expenses.

The Company may be adversely impacted by work stoppages, labor disputes, and/or pandemic illness to which it may not able to promptly respond.

Approximately one-third of the Company’s employees are represented by labor unions and are covered by collective bargaining agreements. Disputes with the unions over terms and conditions of the agreements could result in instability in the Company’s labor relationships and work stoppages that could impact the timely delivery of natural gas and electricity, which could strain relationships with customers and state regulators and cause a loss of revenues. The Company’s collective bargaining agreements may also increase the cost of employing its union workforce, affect its ability to continue offering market-based salaries and employee benefits, limit its flexibility in dealing with its workforce, and limit its ability to change work rules and practices and implement other efficiency-related improvements to successfully compete in today’s challenging marketplace, which may negatively affect the Company’s financial condition and results of operations.

Additionally, pandemic illness could result in part, or all, of the Company’s workforce being unable to operate or maintain the Company’s infrastructure or perform other tasks necessary to conduct the Company’s business. A slow or inadequate response to this type of event may adversely affect the Company’s financial condition and results of operations.

The Company’s business could be adversely affected if it is unable to retain its existing customers or attract new customers, or if customers’ demand for its current products and services significantly decreases.

The success of the Company’s business depends, in part, on its ability to maintain and increase its customer base and the demand that those customers have for the Company’s products and services. The Company’s failure to maintain or increase its customer base and/or customer demand for its products and services could adversely affect its financial condition and results of operations.

The natural gas and electric supply requirements of the Company’s customers are fulfilled by the Company or, in some instances and as allowed by state regulatory authorities, by third-party suppliers who contract directly with customers. In either scenario, significant increases in natural gas and electricity commodity prices may negatively impact the Company’s ability to attract new customers and grow its customer base.

16

Developments in distributed generation, energy conservation, power generation and energy storage could affect the Company’s revenues and the timing of the recovery of the Company’s costs. Advancements in power generation technology are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy storage technology, including batteries and fuel cells, could also better position customers to meet their around-the-clock electricity requirements. Such developments could reduce customer purchases of electricity, but may not necessarily reduce the Company’s investment and operating requirements due to the Company’s obligation to serve customers, including those self-supply customers whose equipment has failed for any reason, to provide the power they need. In addition, since a portion of the Company’s costs are recovered through charges based upon the volume of power delivered, reductions in electricity deliveries will affect the timing of the Company’s recovery of those costs and may require changes to the Company’s rate structures.

The financial performance of the Company’s non-regulated energy brokering business, Usource, may be adversely affected if suppliers and/or customers default in their performance under multi-year energy brokering contracts or by competition from other energy brokers.

Usource provides energy brokering and consulting services to a national client base of large commercial and industrial customers. Revenues from this business are primarily derived from brokering fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts. Usource’s customers and/or the suppliers providing energy to Usource’s customers may default in their performance under multi-year energy brokering contracts, which could adversely affect the Company’s financial condition and results of operations. In addition, Usource may lose market share to other energy brokers which could adversely affect the Company’s financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2015, Unitil owned, through its natural gas and electric distribution utilities, five utility operation centers located in New Hampshire, Maine and Massachusetts. In addition, the Company’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the 12 acres of land on which it is located. In 2015, the Company completed its acquisition of a property for its new Maine Gas Distribution Operations Center (See Note 8 to the accompanying Consolidated Financial Statements).

The following tables detail certain of the Company’s natural gas and electric operations properties.

Natural Gas Operations

	Northern Utilities				Fitchburg		Granite State		Total
Description	NH		ME
Underground Natural Gas Mains—Miles		528		557		275		—		1,360
Natural Gas Transmission Pipeline—Miles		—		—		—		86		86
Service Pipes		22,707		21,212		10,924		—		54,843

Electric Operations

Description	Unitil Energy		Fitchburg		Total
Primary Transmission and Distribution Pole Miles—Overhead		1,270		443		1,713
Conduit Distribution Bank Miles—Underground		216		62		278
Transmission and Distribution Substations		33		16		49
Capacity of Transmission and Distribution Substations		225,900 kVa		438,200 kVa		664,100 kVa

The Company’s natural gas operations property includes two liquid propane gas plants and two liquid natural gas plants. Northern Utilities also owns a propane air gas plant and an LNG storage and vaporization facility. Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility, both of which are located on land owned by Fitchburg in north central Massachusetts.

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Northern Utilities’ gas mains are primarily made up of polyethylene plastic (77%), coated and wrapped cathodically protected steel (16%), cast/wrought iron (4%), and unprotected bare and coated steel (3%). Fitchburg’s gas mains are primarily made up of steel (47%), polyethylene plastic (32%), and cast iron (21%).

Granite State’s underground natural gas transmission pipeline, regulated by the FERC, is located primarily in Maine and New Hampshire.

Unitil Energy’s electric substations are located on land owned by Unitil Energy or land occupied by Unitil Energy pursuant to perpetual easements in the southeastern seacoast and state capital regions of New Hampshire. Unitil Energy’s electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by Unitil Energy without objection by the owners. In the case of certain distribution lines, Unitil Energy owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone companies.

The physical utility properties of Unitil Energy, with certain exceptions, and its franchises are subject to its indenture of mortgage and deed of trust under which the respective series of first mortgage bonds of Unitil Energy are outstanding.

Fitchburg’s electric substations, with minor exceptions, are located in north central Massachusetts on land owned by Fitchburg or occupied by Fitchburg pursuant to perpetual easements. Fitchburg’s electric distribution lines and gas mains are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, express or implied through use by Fitchburg without objection by the owners.

The Company believes that its facilities are currently adequate for their intended uses.

Item 3. Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The 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 upheld the lower Court’s order. Subsequently, 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. On July 27, 2015, the Court issued its decision allowing class certification and denying the Company’s motion for summary judgment. The Company appealed this decision to the SJC, and on October 15, 2015, the SJC granted the Company’s motion for direct review of the case, and it is being briefed by the parties and set for oral argument during the first quarter of 2016. 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. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol “UTL.” As of December 31, 2015, there were 1,443 shareholders of record of our common stock.

Common Stock Data

Dividends per Common Share	2015		2014
1st Quarter	$	0.350	$	0.345
2nd Quarter		0.350		0.345
3rd Quarter		0.350		0.345
4th Quarter		0.350		0.345
Total for Year	$	1.40	$	1.38

See also “Dividends” in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) below.

	2015				2014
Price Range of Common Stock	High/Ask		Low/Bid		High/Ask		Low/Bid
1st Quarter	$	39.00	$	32.99	$	33.22	$	29.05
2nd Quarter	$	35.29	$	32.63	$	34.84	$	31.62
3rd Quarter	$	37.59	$	32.75	$	34.00	$	31.02
4th Quarter	$	38.75	$	33.75	$	38.55	$	31.07

Information regarding securities authorized for issuance under our equity compensation plans, as of December 31, 2015, is set forth in the table below.

Equity Compensation Plan Information

	(a)		(b)		(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders(1)		—		—		416,691
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		416,691

NOTES: (also see Note 6 to the accompanying Consolidated Financial Statements)

⁽¹⁾  Consists of the Second Amended and Restated 2003 Stock Plan (the Plan). On April 19, 2012, shareholders approved the Plan, and a total of 677,500 shares of our common stock were reserved for issuance pursuant to awards of restricted stock, restricted stock units and common stock under the Plan. A total of 262,595 shares of restricted stock have been awarded and 1,106 restricted stock units have been settled and issued as shares of common stock by Plan participants through December 31, 2015. As of December 31, 2015, a total of 2,892 shares of restricted stock were forfeited and once again became available for issuance under the Plan.

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Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2010 with the Peer Group index, comprised of the S&P 500 Utilities Index, and the S&P 500 index. The graph assumes that the value of the investment in the Company’s common stock and each index (including reinvestment of dividends) was $100 on December 31, 2010.

Comparative Five-Year Total Returns

NOTE:

⁽¹⁾ The graph above assumes $100 invested on December 31, 2010, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P 500 Utilities Index.

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Unregistered Sales of Equity Securities and Uses of Proceeds

There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2015.

Issuer Purchases of Equity Securities

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted and announced 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.

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 December 31, 2015.

Period	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
10/1/15 – 10/31/15		1,419	$	36.61		1,419	$	10,781
11/1/15 – 11/30/15		—		—		—	$	10,781
12/1/15 – 12/31/15		53	$	35.32		53	$	8,909
Total		1,472	$	36.56		1,472

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Item 6. Selected Financial Data

	For the Years Ended December 31, (all data in millions except customers served, shares, % and per share data)
	2015			2014			2013			2012			2011
Customers Served (Year-End):
Electric:
Residential		88,444			88,012			87,692			87,062			86,780
Commercial & Industrial		14,825			14,740			14,701			14,612			14,574
Total Electric		103,269			102,752			102,393			101,674			101,354
Natural Gas:
Residential		61,270			60,236			57,616			56,745			55,663
Commercial & Industrial		17,479			17,624			18,304			16,977			16,232
Total Natural Gas		78,749			77,860			75,920			73,722			71,895
Total Customers Served		182,018			180,612			178,313			175,396			173,249
Electric and Gas Sales:
Electric Distribution Sales (kWh)		1,667.7			1,679.0			1,668.3			1,653.8			1,682.1
Firm Natural Gas Distribution Sales (Therms)		219.4			216.2			200.7			181.3			186.9
Consolidated Statements of Earnings:
Operating Revenue	$	426.8		$	425.8		$	366.9		$	353.1		$	352.8
Operating Income		63.1			60.0			53.5			47.5			47.2
Interest Expense, net		21.9			20.9			18.8			18.1			20.4
Other (Income) Expense, net		(0.5	)		0.4			0.4			0.2			0.4
Income Before Income Taxes		41.7			38.7			34.3			29.2			26.4
Income Taxes		15.4			14.0			12.7			11.0			10
Net Income		26.3			24.7			21.6			18.2			16.4
Dividends on Preferred Stock		—			—			—			0.1			0.1
Earnings Applicable to Common Shareholders	$	26.3		$	24.7		$	21.6		$	18.1		$	16.3
Earnings Per Average Share:	$	1.89		$	1.79		$	1.57		$	1.43		$	1.50
Common Stock—(Diluted Weighted Average Outstanding, 000’s)		13,920			13,847			13,775			12,672			10,883
Dividends Declared Per Share	$	1.40		$	1.38		$	1.38		$	1.38		$	1.38
Book Value Per Share (Year-End)	$	20.20		$	19.62		$	19.14		$	18.90		$	17.50
Balance Sheet Data (as of December 31,):
Utility Plant	$	1,080.6		$	988.8		$	909.1		$	833.2		$	776.9
Capital Lease Obligations(1)	$	14.1		$	8.0		$	0.6		$	1.0		$	1.5
Total Assets	$	1,046.4		$	1,000.2		$	920.6		$	892.3		$	856.1
Capitalization:
Common Stock Equity	$	282.6		$	273.1		$	265.0		$	260.4		$	191.7
Preferred Stock		0.2			0.2			0.2			0.2			2.0
Long-Term Debt, less current portion		308.1			328.9			284.8			287.3			287.8
Total Capitalization	$	590.9		$	602.2		$	550.0		$	547.9		$	481.5
Current Portion of Long-Term Debt	$	17.4		$	4.0		$	2.5		$	0.5		$	0.5
Short-Term Debt	$	42.0		$	29.3		$	60.2		$	49.4		$	87.9
Capital Structure Ratios (as of December 31,):
Common Stock Equity		48	%		45	%		48	%		48	%		40	%
Long-Term Debt, less current portion		52	%		55	%		52	%		52	%		60	%

⁽¹⁾  Includes amounts due within one year.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Note references are to the Notes to the Consolidated Financial Statements included in Item 8, below.)

OVERVIEW

Unitil is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005.

Unitil’s principal business is the local distribution of electricity and natural gas to approximately 182,000 customers throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

i) Unitil Energy, which provides electric service in the southeastern seacoast and state capital regions of New Hampshire;

ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and

iii) Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area.

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 103,300 electric customers and 78,700 natural gas customers in their service territory.

In addition, Unitil is the parent company of Granite State, a natural gas transmission pipeline, regulated by the FERC, 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 North American pipeline supplies.

The distribution utilities are local “pipes and wires” operating companies, and Unitil had an investment in Net Utility Plant of $808.9 million at December 31, 2015. Unitil’s total revenue was $426.8 million in 2015, which 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 affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are derived from the return on investment in the three distribution utilities and Granite State.

Unitil also conducts non-regulated operations principally through Usource, which is wholly-owned by Unitil Resources. Usource provides energy brokering and consulting services to a national client base of large commercial and industrial customers. Usource’s total revenues were $6.2 million in 2015. The Company’s other subsidiaries include Unitil Service, which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, and Unitil Realty, which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

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 NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and 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.

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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, and earn a return on their capital investment in utility assets. In addition, the Company’s distribution utilities and its natural gas transmission pipeline company may also recover certain base rate costs, including capital project spending and enhanced reliability and vegetation management programs, through annual step adjustments and cost tracker rate mechanisms.

As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most of Unitil’s 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.

Also see Regulatory Matters shown below and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on rates and regulation.

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

RESULTS OF OPERATIONS

The following discussion of the Company’s financial condition and results of operations should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Part II, Item 8 of this report.

The Company’s results of operations are expected to 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 on decoupled sales volumes.

Net Income and EPS Overview

2015 Compared to 2014—The Company’s Net Income was $26.3 million, or $1.89 per share, for the year ended December 31, 2015, an increase of $1.6 million, or $0.10 per share, compared to 2014. The Company’s earnings for 2015 were driven by increases in natural gas and electric sales margins partially offset by higher utility operating expenses.

Natural gas sales margin was $101.9 million in 2015, resulting in an increase of $4.5 million compared to 2014. Natural gas sales margin was positively affected by higher therm unit sales in 2015, a growing customer base and higher distribution rates compared to 2014. Therm sales of natural gas increased

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1.5% in 2015 compared to 2014. The impact of growth in the number of customers year over year was partially offset by warmer weather in 2015 compared to the prior year. For the full year, based on weather data collected in the Company’s service areas, there were 2.3% fewer Heating Degree Days in 2015. Estimated weather-normalized gas therm sales, excluding decoupled sales, were up four percent in 2015, led by a year over year increase of eight percent in gas therm sales to large Commercial and Industrial (C&I) customers.

Electric sales margin was $85.5 million in 2015, resulting in an increase of $4.7 million compared to 2014. The increase in electric sales margin primarily reflects higher electric distribution rates. Electric kilowatt-hour (kWh) sales decreased 0.7% in 2015 compared to 2014, reflecting a decrease in average use per customer for Residential customers, partially offset by an increase in electric sales to C&I customers.

Total Operation & Maintenance (O&M) expenses increased $2.5 million in 2015 compared to 2014. The change in O&M expenses reflects higher compensation and benefit costs of $3.5 million partially offset by lower professional fees of $0.3 million and lower all other utility O&M costs, net of $0.7 million.

Depreciation and Amortization expense increased $3.6 million in 2015 compared to 2014, reflecting higher depreciation of $2.4 million on normal utility plant assets in service, higher amortization of major storm restoration costs of $0.9 million and an increase in all other amortization of $0.3 million. The increase in major storm restoration cost amortization is currently recovered in electric rates and reflected in electric sales margin.

Taxes Other Than Income Taxes increased $0.5 million in 2015 compared to 2014, primarily reflecting higher local property tax expense.

Interest Expense, net increased $1.0 million in 2015 compared to 2014 reflecting higher levels of long-term debt and higher interest expense on regulatory liabilities.

Other (Income) Expense, net changed from an expense of $0.4 million in 2014 to income of $0.5 million in 2015. This change was the result of the recognition of a pre-tax gain of $0.9 million in the fourth quarter of 2015 on the sale of property.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $6.2 million in 2015, representing an increase of $0.5 million compared to 2014. Usource’s revenues are primarily derived from fees billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

Income Taxes increased $1.4 million in 2015 due to higher pre-tax earnings in 2015 compared to 2014.

In 2015, Unitil’s annual common dividend was $1.40 per share, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2016 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.3550 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.42 per share from $1.40 per share.

2014 Compared to 2013—The Company’s Net Income was $24.7 million, or $1.79 per share, for the year ended December 31, 2014, an increase of $3.1 million, or $0.22 per share, compared to 2013. The 14.0% increase in 2014 earnings was driven by higher natural gas and electric sales margins partially offset by changes in operating expenses.

A more detailed discussion of the Company’s 2015 and 2014 results of operations and a year-to-year comparison of changes in financial position are presented below.

Gas Sales, Revenues and Margin

Therm Sales—Unitil’s total therm sales of natural gas increased 1.5% in 2015 compared to 2014. Sales to residential and C&I customers increased 1.1% and 1.6%, respectively, in 2015 compared to 2014.

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The impact of growth in the number of customers year over year was partially offset by warmer weather in 2015 compared to the prior year. The average number of natural gas customers served has increased by 1.8% compared to the prior year. For the full year, based on weather data collected in the Company’s service areas, there were 2.3% fewer Heating Degree Days in 2015. Estimated weather-normalized gas therm sales, excluding decoupled sales, were up four percent in 2015, led by a year over year increase of eight percent in gas therm sales to large C&I customers.

Unitil’s total therm sales of natural gas increased 7.7% in 2014 compared to 2013. The increase in gas therm sales in the Company’s utility service territories was driven by the colder winter and spring weather in 2014 compared to 2013 coupled with strong growth in the number of new customers. Based on weather data collected in the Company’s service areas, there were 5.9% more Heating Degree Days in 2014 compared to 2013. Weather-normalized gas therm sales, excluding decoupled sales, were estimated to be up 5.2% in 2014 compared to 2013.

The following table details total therm sales for the last three years, by major customer class:

Therm Sales (millions)							Change
							2015 vs. 2014					2014 vs. 2013
	2015		2014		2013		Therms		%			Therms		%
Residential		45.2		44.7		39.8		0.5		1.1	%		4.9		12.3	%
Commercial & Industrial		174.2		171.5		160.9		2.7		1.6	%		10.6		6.6	%
Total Therm Sales		219.4		216.2		200.7		3.2		1.5	%		15.5		7.7	%

Gas Operating Revenues and Sales Margin—The following table details total Gas Operating Revenue and Sales Margin for the last three years by major customer class:

Gas Operating Revenues and Sales Margin (millions)
							Change
							2015 vs. 2014						2014 vs. 2013
	2015		2014		2013		$			%			$		%
Gas Operating Revenue:
Residential	$	78.5	$	80.0	$	68.5	$	(1.5	)		(1.9	%)	$	11.5		16.8	%
Commercial & Industrial		124.1		121.4		101.9		2.7			2.2	%		19.5		19.1	%
Total Gas Operating Revenue	$	202.6	$	201.4	$	170.4	$	1.2			0.6	%	$	31.0		18.2	%
Cost of Gas Sales	$	100.7	$	104.0	$	85.2	$	(3.3	)		(3.2	%)	$	18.8		22.1	%
Gas Sales Margin	$	101.9	$	97.4	$	85.2	$	4.5			4.6	%	$	12.2		14.3	%

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 customers, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue. Sales margin can be reconciled to Operating Income, a GAAP measure, by including Operation and Maintenance, Depreciation and Amortization and Taxes Other Than Income Taxes for each segment in the analysis.

Natural gas sales margin was $101.9 million in 2015, resulting in an increase of $4.5 million compared to 2014. Approximately $3.4 million of the increase reflects higher natural gas distribution rates and $1.1 million of the increase reflects higher sales volumes related to customer growth, net of the impact of warmer weather in 2015.

The increase in Total Gas Operating Revenues of $1.2 million, or 0.6%, in 2015 compared to 2014 reflects higher gas base rates and sales volumes, partially offset by lower costs of gas sales, which are tracked and reconciled to costs that are passed through directly to customers.

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Natural gas sales margin was $97.4 million in 2014, resulting in an increase of $12.2 million compared to 2013. Approximately $7.6 million of the increase reflects higher natural gas distribution rates and $4.6 million of the increase reflects higher sales volumes related to the colder than normal weather and customer growth.

The increase in Total Gas Operating Revenues of $31.0 million, or 18.2%, in 2014 compared to 2013 reflects higher gas base rates and higher costs of gas sales, 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 decreased 0.7% in 2015 compared to 2014. Sales to residential customers decreased 2.4% in 2015 compared to 2014, reflecting a decrease in average use per customer. Sales to C&I customers increased 0.5% in 2015 compared to 2014, reflecting the addition of new customers. The average number of natural gas customers served has increased by 0.5% compared to the prior year. As discussed above, sales margins derived from revenue decoupled unit sales (representing approximately 27% of total annual sales volume) are not sensitive to changes in kWh sales.

Unitil’s total electric kWh sales increased 0.6% in 2014 compared to 2013. Sales to residential customers decreased 0.5% in 2014 compared to 2013, reflecting the effect of milder summer weather in 2014, partially offset by colder than normal winter weather earlier in 2014.

The following table details total kWh sales for the last three years by major customer class:

kWh Sales (millions)							Change
							2015 vs. 2014						2014 vs. 2013
	2015		2014		2013		kWh			%			kWh			%
Residential		671.4		687.6		690.9		(16.2	)		(2.4	%)		(3.3	)		(0.5	%)
Commercial & Industrial		996.3		991.4		977.4		4.9			0.5	%		14.0			1.4	%
Total kWh Sales		1,667.7		1,679.0		1,668.3		(11.3	)		(0.7	%)		10.7			0.6	%

Electric Operating Revenues and Sales Margin—The following table details Total Electric Operating Revenue and Sales Margin for the last three years by major customer class:

Electric Operating Revenues and Sales Margin (millions)
							Change
							2015 vs. 2014						2014 vs. 2013
	2015		2014		2013		$			%			$		%
Electric Operating Revenue:
Residential	$	125.9	$	118.0	$	104.1	$	7.9			6.7	%	$	13.9		13.4	%
Commercial & Industrial		92.1		100.7		86.6		(8.6	)		(8.5	%)		14.1		16.3	%
Total Electric Operating Revenue	$	218.0	$	218.7	$	190.7	$	(0.7	)		(0.3	%)	$	28.0		14.7	%
Cost of Electric Sales	$	132.5	$	137.9	$	114.5	$	(5.4	)		(3.9	%)	$	23.4		20.4	%
Electric Sales Margin	$	85.5	$	80.8	$	76.2	$	4.7			5.8	%	$	4.6		6.0	%

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 customers 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.

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Electric sales margin was $85.5 million in 2015, resulting in an increase of $4.7 million compared to 2014. Higher electric distribution rates of $5.0 million and the positive impact of $0.7 million resulting from warmer summer weather in 2015 were partially offset by approximately $1.0 million of lower electric sales margin, reflecting lower average usage in 2015.

The decrease in Total Electric Operating Revenue of $0.7 million, or 0.3%, in 2015 compared to 2014 reflects lower costs of electric sales, which are tracked costs that are passed through directly to customers, partially offset by higher electric distribution rates.

Electric sales margin was $80.8 million in 2014, resulting in an increase of $4.6 million compared to 2013. Approximately $4.4 million of the increase reflects higher electric distribution rates and $0.2 million reflects higher sales volume due to growth in customers.

The increase in Total Electric Operating Revenue of $28.0 million, or 14.7%, in 2014 compared to 2013 reflects higher electric distribution rates and higher costs of electric sales, which are tracked costs that are passed through directly to customers.

Operating Revenue—Other

Total Other Operating Revenue is comprised of revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues in 2015 were $6.2 million, an increase of $0.5 million compared to 2014. Usource’s revenues in 2014 were $5.7 million, a decrease of $0.1 million compared to 2013. As an energy broker and advisor, Usource assists business customers with the procurement and contracting for electricity and natural gas in competitive energy markets. Usource’s revenues are primarily derived from fees billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

The following table details total Other Revenue for the last three years:

Other Revenue (millions)
							Change
							2015 vs. 2014					2014 vs. 2013
	2015		2014		2013		$		%			$			%
Usource	$	6.2	$	5.7	$	5.8	$	0.5		8.8	%	$	(0.1	)		(1.7	%)
Total Other Revenue	$	6.2	$	5.7	$	5.8	$	0.5		8.8	%	$	(0.1	)		(1.7	%)

Operating Expenses

Cost of Gas Sales—Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales decreased $3.3 million, or 3.2%, in 2015 compared to 2014. This decrease reflects lower wholesale natural gas prices and decreased spending on energy efficiency programs, partially offset by higher sales of natural gas and a decrease in the amount of natural gas purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

In 2014, Cost of Gas Sales increased $18.8 million, or 22.1%, compared to 2013. This increase reflects higher sales of natural gas, increased spending on energy efficiency programs and higher wholesale natural gas prices.

Cost of Electric Sales—Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales decreased $5.4 million, or 3.9%, in 2015 compared to 2014. This decrease reflects lower electric kWh sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

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In 2014, Cost of Electric Sales increased $23.4 million, or 20.4%, compared to 2013. This increase reflects higher wholesale electricity prices, increased spending on energy efficiency programs and higher electric kWh sales.

Operation and Maintenance—O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s non-regulated business activities. Total O&M expenses increased $2.5 million, or 3.9%, in 2015 compared to 2014. The change in O&M expenses reflects higher compensation and benefit costs of $3.5 million partially offset by lower professional fees of $0.3 million and lower all other utility O&M costs, net of $0.7 million. The decrease in utility operating costs includes $0.8 million in lower electric and natural gas maintenance costs and higher all other utility operating costs, net of $0.1 million.

In 2014, total O&M expenses increased $4.4 million, or 7.3%, compared to 2013. The change in O&M expenses reflects higher compensation and benefit costs of $2.8 million and higher utility operating costs of $1.6 million. The increase in utility operating costs in 2014 includes $0.7 million in higher electric and natural gas maintenance costs, $0.6 million in higher bad debt expense and higher all other utility operating costs, net of $0.3 million.

Depreciation and Amortization—Depreciation and Amortization expense increased $3.6 million, or 8.6%, in 2015 compared to 2014, reflecting higher depreciation of $2.4 million on normal utility plant assets in service, higher amortization of major storm restoration costs of $0.9 million and an increase in all other amortization of $0.3 million. The increase in major storm restoration cost amortization is currently recovered in electric rates and reflected in electric sales margin.

In 2014, Depreciation and Amortization expense increased $3.6 million, or 9.4%, compared to 2013, reflecting higher depreciation of $2.2 million on higher utility plant assets in service, higher amortization of major storm restoration costs of $1.3 million and an increase in all other amortization of $0.1 million. The increase in major storm restoration cost amortization is currently recovered in electric rates and reflected in electric sales margin.

Taxes Other Than Income Taxes—Taxes Other Than Income Taxes increased $0.5 million, or 2.9%, in 2015 compared to 2014, primarily reflecting higher local property tax expense.

In 2014, Taxes Other Than Income Taxes increased $2.2 million, or 14.7%, compared to 2013, reflecting higher local property taxes on higher levels of utility plant in service.

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. Certain reconciling rate mechanisms used by the Company’s distribution utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated (See Note 5 to the accompanying Consolidated Financial Statements).

Interest Expense, net increased $1.0 million, or 4.8%, in 2015 compared to 2014 reflecting higher levels of long-term debt and higher interest expense on regulatory liabilities.

In 2014, Interest Expense, net increased $2.1 million, or 11.2%, compared to 2013 reflecting lower net interest income on regulatory assets and higher interest on long-term debt, related to the issuance of $50 million in Senior Unsecured Notes by Northern Utilities in October 2014.

Other (Income) Expense, net

Other (Income) Expense, net changed from an expense of $0.4 million in 2014 to income of $0.5 million in 2015. This change was the result of the recognition of a pre-tax gain of $0.9 million in the fourth quarter of 2015 on the sale of property (See Note 8 to the accompanying Consolidated Financial Statements).

Other (Income) Expense, net, was essentially unchanged in 2014 compared to 2013.

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Income Taxes

Income Taxes increased $1.4 million in 2015 compared to 2014 due to higher pre-tax earnings in 2015 compared to 2014 (See Note 9 to the accompanying Consolidated Financial Statements).

In 2014, Income Taxes increased $1.3 million compared to 2013 due to higher pre-tax earnings in 2014 compared to 2013.

LIQUIDITY, COMMITMENTS AND CAPITAL REQUIREMENTS

Sources of Capital

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

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the “Cash Pool”). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility. At December 31, 2015 and December 31, 2014, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

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 new borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate (LIBOR) plus 1.375%. 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.

On July 24, 2015, the Company entered into the First Amendment to the Credit Facility. The First Amendment provides for an extension of the scheduled termination date to October 4, 2020, reduces the daily fluctuating rate of interest per annum equal to one-month LIBOR plus 1.25%, and reduces other customary credit facility fees. All other terms and conditions of the Credit Facility, including affirmative and negative covenants, remain substantially unchanged.

The Company utilizes the credit facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $140.3 million and $179.4 million for the years ended December 31, 2015 and December 31, 2014, respectively. Total gross repayments were $127.6 million and $210.3 million for the years ended December 31, 2015 and December 31, 2014, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2015 and December 31, 2014:

Revolving Credit Facility (millions)
	December 31,
	2015		2014
Limit	$	120.0	$	120.0
Outstanding	$	42.0	$	29.3
Available	$	78.0	$	90.7

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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 December 31, 2015 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 5.)

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

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2015, there are $2.6 million of current and $10.4 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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

Contractual Obligations

The table below lists the Company’s known specified contractual obligations as of December 31, 2015.

			Payments Due by Period
Contractual Obligations (millions) as of December 31, 2015	Total		2016		2017- 2018		2019- 2020		2021 & Beyond
Long-Term Debt	$	325.5	$	17.4	$	47.3	$	38.6	$	222.2
Interest on Long-Term Debt		246.7		21.2		38.4		31.8		155.3
Gas Supply Contracts		247.7		42.4		58.9		27.9		118.5
Electric Supply Contracts		13.0		1.2		2.5		2.5		6.8
Other (Including Capital and Operating Lease Obligations)		17.8		4.4		7.6		5.7		0.1
Total Contractual Cash Obligations	$	850.7	$	86.6	$	154.7	$	106.5	$	502.9

The Company and its subsidiaries have material energy supply commitments that are discussed in Note 7 to the accompanying Consolidated Financial Statements. Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year.

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 December 31, 2015, there were approximately $19.3 million of guarantees outstanding and the longest term guarantee extends through August 2016.

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

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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 $10.8 million and $15.1 million of natural gas storage inventory at December 31, 2015 and 2014, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2015, which was payable in January 2016, was $0.6 million and recorded in Accounts Payable at December 31, 2015. The amount of natural gas inventory released in December 2014, which was payable in January 2015, was $1.0 million and 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 December 31, 2014, the principal amount outstanding for the 8% Unitil Realty notes was $1.1 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Benefit Plan Funding

The Company, along with its subsidiaries, made cash contributions to its Pension Plan in the amounts of $4.2 million in each of 2015 and 2014. The Company, along with its subsidiaries, contributed $4.0 million and $3.7 million to Voluntary Employee Benefit Trusts (VEBTs) in 2015 and 2014, respectively. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in 2016 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these benefit plans. See Note 10 (Retirement Benefit Plans) to the accompanying Consolidated Financial Statements.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Additionally, as of December 31, 2015, there were approximately $19.3 million of guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities outstanding and the longest term guarantee extends through August 2016. See Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

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 2015 and 2014.

	2015		2014
Cash Provided by Operating Activities	$	115.1	$	84.0

Cash Provided by Operating Activities—Cash Provided by Operating Activities was $115.1 million in 2015, an increase of $31.1 million compared to 2014.

Cash flow from net income, adjusted for the total of non-cash charges to depreciation, amortization and deferred taxes, was $83.9 million in 2015 compared to $81.2 million in 2014, reflecting an increase of $2.7 million. The increase in net income of $1.6 million in 2015 compared to 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 and customer growth. The increase in depreciation and amortization of $3.6 million 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 of ($2.5) million in 2015 compared to 2014 is primarily due to a deferred tax asset recorded in 2015 related to the pipeline refund from Portland Natural Gas Transmission System (PNGTS) (See Note 8). This was partially offset by the use of a portion of federal net operating loss carryforwards.

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Changes in working capital items resulted in a $17.8 million source of cash in 2015 compared to a $7.0 million source of cash in 2014, representing an increase of $10.8 million. Changes in Regulatory Liabilities resulted in an increase in sources of cash of $7.9 million in 2015 compared to 2014, primarily driven by the current portion of the PNGTS to be refunded to customers (see Note 8) of $7.6 million as of December 31, 2015. All other changes in working capital reflect normal variations from year-to-year, including changes in underlying commodity prices.

Changes in Deferred Regulatory and Other Charges resulted in an increase in sources of cash of $10.8 million in 2015 compared to 2014, primarily driven by the long-term portion of the PNGTS refund of $8.1 million as of December 31, 2015. The change in Other, net in 2015 compared to 2014 was $6.8 million.

	2015			2014
Cash (Used in) Investing Activities	$	(103.9	)	$	(92.6	)

Cash (Used in) Investing Activities—Cash Used in Investing Activities was ($103.9) million in 2015 compared to ($92.6) million in 2014. The actual capital spending in both 2015 and 2014 is related to utility capital expenditures for electric and gas utility system additions. The Company’s projected capital spending range for 2016 is $95 million to $100 million.

	2015			2014
Cash (Used in) Provided by Financing Activities	$	(10.9	)	$	7.6

Cash (Used in) Provided by Financing Activities—Cash (Used in) Provided by Financing Activities was ($10.9) million in 2015 compared to $7.6 million in 2014. The higher cash used in financing activities in 2015 compared to 2014 is primarily attributable to lesser proceeds from the issuance of long-term debt of ($50.0) million, greater repayment of long-term debt of ($3.0) million and a net decrease in Exchange Gas Financing of ($8.4) million, partially offset by greater proceeds from short-term debt of $43.6 million.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the Company and its subsidiaries issue long-term debt contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions, business combinations and covenants restricting the ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets. See Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

Unitil’s 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 December 31, 2015 and December 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

The Company and its subsidiaries are currently in compliance with all such covenants in these debt instruments.

DIVIDENDS

Unitil’s annual common dividend was $1.40 per common share in 2015 and $1.38 per common share in both 2014 and 2013. Unitil’s dividend policy is reviewed periodically by the Board of Directors. Unitil

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has maintained an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January 2016 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.3550 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.42 from $1.40. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. In addition, the ability of the Company’s subsidiaries to pay dividends or make distributions to Unitil, and, therefore, Unitil’s ability to pay dividends, depends on, among other things:

• the actual and projected earnings and cash flow, capital requirements and general financial condition of the Company’s subsidiaries;

• the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by the Company’s subsidiaries;

• the restrictions on the payment of dividends contained in the existing loan agreements of the Company’s subsidiaries and that may be contained in future debt agreements of the Company’s subsidiaries, if any; and

• limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.

In addition, before the Company can pay dividends on its common stock, it has to satisfy its debt obligations and comply with any statutory or contractual limitations. See Financial Covenants and Restrictions, above, as well as Note 5 (Debt and Financing Arrangements) to the accompanying Consolidated Financial Statements.

LEGAL PROCEEDINGS

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The 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 upheld the lower Court’s order. Subsequently, 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. On July 27, 2015, the Court issued its decision allowing class certification and denying the Company’s motion for summary judgment. The Company appealed this decision to the SJC, and on October 15, 2015, the SJC granted the Company’s motion for direct review of the case, and it is being briefed by the parties and set for oral argument during the first quarter of 2016. 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. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

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REGULATORY MATTERS

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The Maine Public Utilities Commission (MPUC), the Massachusetts Department of Public Utilities (MDPU), and the New Hampshire Public Utilities Commission (NHPUC) have each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31, 2015. The remaining balance of these assets is $1.9 million as of December 31, 2015, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $1.6 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next six years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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. The 2015 TIRA provided for an annual increase in base distribution revenue of $1.2 million, effective May 1, 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. 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. The 2015 step adjustment provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015 the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015.

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As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund will be credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities will be credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities of $7.6 million and $8.1 million, respectively, on its Consolidated Balance Sheets as of December 31, 2015.

Unitil Energy—Base Rates—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. The third and final step increase of $1.5 million in annual revenue was effective May 1, 2014.

Granite State—Base Rates—Granite State had in place a FERC approved amended settlement agreement under which it had 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. The final rate adjustment under this agreement was effective August 1, 2014. Granite State has received FERC approval of a second amended settlement agreement under which it will continue to be permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a cost cap. The FERC approval of the second amended settlement included a rate increase of $0.4 million, effective August 1, 2015.

Fitchburg—Base Rates—Electric—On May 30, 2014, the Massachusetts Department of Public Utilities (MDPU) approved a $5.6 million increase in Fitchburg’s base revenue decoupling target, effective June 1, 2014. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 and 2012. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off. The impact of the rate order on previously capitalized or deferred items was not material.

On June 16, 2015, Fitchburg filed for a $3.8 million increase in electric base revenue decoupling target, which represents a 5.6 percent increase over 2014 test year operating electric revenues. The filing included a request for approval of a capital cost recovery mechanism to recover prudently incurred additions to utility plant on an annual basis. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. 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 decoupling target, which represents an 8.3 percent increase over 2014 test year total gas operating revenues. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of April, 2016.

Major Storms—Fitchburg and Unitil Energy

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

Unitil Energy—2012 Storm Costs—On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over

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a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Thanksgiving 2014 Snow Storm—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 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.

NHPUC Energy Efficiency Resource Standard Proceeding—On May 8, 2015, the NHPUC issued an order of notice commencing a proceeding to establish an Energy Efficiency Resource Standard, an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. In this proceeding the Commission will define the savings targets and address issues related to public and private funding; program cost recovery; lost-revenue recovery (e.g. decoupling); performance-based incentives and penalties; program administration; and evaluation, measurement, and verification. Initial comments were filed by interested parties on December 9, 2015, and the matter remains pending.

Northern Utilities—Other—In the fourth quarter of 2015, Northern Utilities completed the transition into a new Distribution Operations Center (DOC) for its operations in Portland, Maine. The new property includes an existing building and is located at 376 Riverside Industrial Parkway in Portland, Maine. On September 19, 2014, Northern Utilities sold its existing DOC facility located at 1075 Forest Avenue in Portland, Maine. While the new DOC facility was being renovated, Northern Utilities leased back its existing DOC facility from the new owner. The new DOC facility was needed due to space limitations at the existing DOC. In recent years Northern Utilities’ gas expansion initiative and the work associated with it resulted in staff, company vehicles, and material storage additions to a facility that could not adequately handle these additions. Northern Utilities recognized a net gain on sale of the Forest Avenue property of $0.9 million in the fourth quarter of 2015.

Fitchburg—Electric Operations—On November 24, 2014, Fitchburg submitted its 2014 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were approved, subject to investigation and reconciliation, effective January 1, 2015 for billing purposes, and given final approval by the MDPU on June 16, 2015.

On November 17, 2015, Fitchburg submitted its 2015 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were approved, subject to investigation and reconciliation, effective January 1, 2016 for billing purposes, and given final approval by the MDPU on December 29, 2015.

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 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

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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. The second annual filing, to recover the estimated costs to be incurred in calendar year 2016, was made on October 31, 2015. The Company seeks approval to collect in rates $0.9 million for the costs of its cumulative capital investments for 2015 and 2016, effective May 1, 2016. This matter remains pending.

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 July 7, 2015, the MDPU approved Fitchburg’s 2013 gas division Service Quality Report as filed. On October 21, 2015, the MDPU approved Fitchburg’s 2012 electric division Service Quality Report as filed. On November 25, 2015, the MDPU approved Fitchburg’s 2014 gas division Service Quality Report as filed. Fitchburg’s 2013 and 2014 electric division Service Quality Reports remain pending.

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 filed a motion with the MDPU to reconsider the adoption of state-wide standards and requested reconsideration and clarification on other technical issues. On December 18, 2015, the MDPU issued its order on the motion to reconsider, and issued revised guidelines. The new guidelines reverse the change to state-wide standards in favor of the company specific standards currently in place, eliminate several metric and reporting requirements and revise several existing metrics in addition to the changes noted above. 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 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.

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-

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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 provided guidance and filing requirements for the business case justification that the electric companies must file as part of their GMPs. The second order required 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. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filing are currently under the MDPU’s review. The MDPU is addressing in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles. These matters remain pending.

FERC Transmission Formula Rate Proceeding—On December 28, 2015, FERC issued an order, pursuant to section 206 of the Federal Power Act, instituting a proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin as of January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

ENVIRONMENTAL MATTERS

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 December 31, 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 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. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough. Northern Utilities has worked with the 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, Dover, Somersworth, Portsmouth, Lewiston and Scarborough sites, though future activities may be required.

The site in Portland has been investigated and remedial activities have largely been completed. Final remediation activities were completed in the fourth quarter of 2015, and closure documentation will be prepared for submittal to the regulatory agency in the first half of 2016. In the second quarter of 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 this taking, and pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the site will be primarily the responsibility of the State of Maine.

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

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remediation activities in Exeter commenced in the fourth quarter of 2015. The anticipated completion of these activities is in the first quarter of 2016.

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

Fitchburg’s Manufactured Gas Plant Site—Fitchburg completed the scheduled site work at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the fourth quarter of 2014. The closure documentation for the site was submitted in the fourth quarter of 2015 and is under review by the Massachusetts Department of Environmental Protection.

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.

Also, see Environmental Matters in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) and Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements for additional information on Environmental Matters.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s Consolidated Financial Statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the financial statements and Note 1: Summary of Significant Accounting Policies.

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 MDPU, Unitil Energy is regulated by the NHPUC and Northern Utilities is regulated by the 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 Financial Accounting Standards Board Accounting Standards Codification (FASB Codification). In accordance with 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.

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The FASB Codification specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets.” If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities.”

The Company’s principal regulatory assets and liabilities are included on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided in Note 1 thereto. 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.

Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates.

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

Allowance for Doubtful Accounts—The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric 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. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

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Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of its employees. The Company also sponsors an unfunded retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The FASB Codification requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates.

The Company’s RBO and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For the year ended December 31, 2015, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $472,000 in the Net Periodic Benefit Cost for the Pension Plan. Similarly, a change of 0.50% in the expected long-term rate of return on plan assets would have resulted in an increase or decrease of approximately $424,000 in the Net Periodic Benefit Cost for the Pension Plan. For the year ended December 31, 2015, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $1,383,000. Similarly, a 1.0% decrease in the assumption of health care cost trend rates would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $1,040,000. (See Note 10 to the accompanying Consolidated Financial Statements).

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

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

Depreciation—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements.

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Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2015, the Company is not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

Refer to “Recently Issued Pronouncements” in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.

For further information regarding the foregoing matters, see Note 1 (Summary of Significant Accounting Policies), Note 9 (Income Taxes), Note 7 (Energy Supply), Note 10 (Retirement Benefit Plans) and Note 8 (Commitment and Contingencies) to the Consolidated Financial Statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Please also refer to Part I, Item 1A. “Risk Factors”.

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 rate on short-term borrowings was 1.5%, 1.6%, and 1.8% during 2015, 2014, and 2013, respectively.

COMMODITY PRICE RISK

Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed in the section entitled Rates and Regulation in Part I, Item 1 (Business) and in Note 8 (Commitments and Contingencies) to the accompanying Consolidated Financial Statements, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Unitil Corporation

We have audited the accompanying consolidated balance sheets of Unitil Corporation and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of earnings, changes in common stock equity, and cash flows for the years then ended. We also have audited the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Unitil Corporation and subsidiaries as of December 31, 2015 and 2014, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Boston, MA

January 28, 2016

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Unitil Corporation and subsidiaries:

We have audited the accompanying consolidated statements of earnings, cash flows and changes in common stock equity of Unitil Corporation for the year ended December 31, 2013. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Unitil Corporation and subsidiaries for the year ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ RSM US LLP

Boston, Massachusetts

January 29, 2014

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CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

Year Ended December 31,	2015			2014		2013
Operating Revenues:
Gas	$	202.6		$	201.4	$	170.4
Electric		218.0			218.7		190.7
Other		6.2			5.7		5.8
Total Operating Revenues		426.8			425.8		366.9
Operating Expenses:
Cost of Gas Sales		100.7			104.0		85.2
Cost of Electric Sales		132.5			137.9		114.5
Operation and Maintenance		67.1			64.6		60.2
Depreciation and Amortization		45.7			42.1		38.5
Taxes Other Than Income Taxes		17.7			17.2		15.0
Total Operating Expenses		363.7			365.8		313.4
Operating Income		63.1			60.0		53.5
Interest Expense, net		21.9			20.9		18.8
Other (Income) Expense, net		(0.5	)		0.4		0.4
Income Before Income Taxes		41.7			38.7		34.3
Income Taxes		15.4			14.0		12.7
Net Income Applicable to Common Shares	$	26.3		$	24.7	$	21.6
Earnings per Common Share—Basic and Diluted	$	1.89		$	1.79	$	1.57
Weighted Average Common Shares Outstanding—(Basic and Diluted)		13.9			13.8		13.8

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

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CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS

December 31,	2015		2014
Current Assets:
Cash and Cash Equivalents	$	8.7	$	8.4
Accounts Receivable, net		49.8		60.7
Accrued Revenue		38.4		48.5
Exchange Gas Receivable		11.1		15.0
Gas Inventory		0.8		1.1
Deferred Income Taxes		4.7		—
Prepayments and Other		12.4		11.5
Total Current Assets		125.9		145.2
Utility Plant:
Gas		576.8		522.9
Electric		408.4		390.6
Common		35.5		32.7
Construction Work in Progress		59.9		42.6
Utility Plant		1,080.6		988.8
Less: Accumulated Depreciation		271.7		255.1
Net Utility Plant		808.9		733.7
Other Noncurrent Assets:
Regulatory Assets		99.6		107.6
Other Assets		12.0		13.7
Total Other Noncurrent Assets		111.6		121.3
TOTAL ASSETS	$	1,046.4	$	1,000.2

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

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CONSOLIDATED BALANCE SHEETS (cont.) (Millions, except number of shares)

LIABILITIES AND CAPITALIZATION

December 31,	2015		2014
Current Liabilities:
Accounts Payable	$	33.3	$	44.2
Short-Term Debt		42.0		29.3
Long-Term Debt, Current Portion		17.4		4.0
Regulatory Liabilities		15.6		8.7
Energy Supply Obligations		14.6		22.1
Environmental Obligations		1.3		3.5
Capital Lease Obligations		3.1		0.5
Deferred Income Taxes		—		3.1
Taxes Payable		2.4		0.1
Other Current Liabilities		14.9		13.9
Total Current Liabilities		144.6		129.4
Noncurrent Liabilities:
Deferred Income Taxes		92.2		72.9
Cost of Removal Obligations		70.1		63.8
Retirement Benefit Obligations		124.4		118.6
Regulatory Liabilities		8.1		0.1
Capital Lease Obligations		11.0		7.5
Environmental Obligations		1.5		2.0
Other Noncurrent Liabilities		3.6		3.7
Total Noncurrent Liabilities		310.9		268.6
Capitalization:
Long-Term Debt, Less Current Portion		308.1		328.9
Stockholders’ Equity:
Common Equity (Outstanding 13,991,430 and 13,916,026 Shares)		237.5		234.7
Retained Earnings		45.1		38.4
Total Common Stock Equity		282.6		273.1
Preferred Stock		0.2		0.2
Total Stockholders’ Equity		282.8		273.3
Total Capitalization		590.9		602.2
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION	$	1,046.4	$	1,000.2

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions)

Year Ended December 31,	2015			2014			2013
Operating Activities:
Net Income	$	26.3		$	24.7		$	21.6
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		45.7			42.1			38.5
Deferred Taxes Provision		11.9			14.4			12.3
Changes in Working Capital Items:
Accounts Receivable		10.9			(8.5	)		(4.5	)
Accrued Revenue		10.1			8.1			6.8
Regulatory Liabilities		6.9			(1.0	)		2.9
Taxes Refundable / Payable		2.3			(0.1	)		(0.5	)
Exchange Gas Receivable		3.9			(4.2	)		(1.4	)
Accounts Payable		(10.9	)		6.1			5.4
Other Changes in Working Capital Items		(5.4	)		6.6			(2.9	)
Deferred Regulatory and Other Charges		9.2			(1.6	)		15.0
Other, net		4.2			(2.6	)		3.1
Cash Provided by Operating Activities		115.1			84.0			96.3
Investing Activities:
Property, Plant and Equipment Additions		(103.9	)		(92.6	)		(89.5	)
Cash Used In Investing Activities		(103.9	)		(92.6	)		(89.5	)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net		12.7			(30.9	)		10.8
Issuance of Long-Term Debt		—			50.0			—
Repayment of Long-Term Debt		(7.4	)		(4.4	)		(0.5	)
Increase / (Decrease) in Capital Lease Obligations		6.1			6.5			(0.7	)
Net (Decrease) Increase in Exchange Gas Financing		(4.0	)		4.4			1.2
Dividends Paid		(19.6	)		(19.2	)		(19.1	)
Proceeds from Issuance of Common Stock		1.3			1.2			1.1
Cash (Used In) Provided by Financing Activities		(10.9	)		7.6			(7.2	)
Net Increase (Decrease) in Cash		0.3			(1.0	)		(0.4	)
Cash at Beginning of Year		8.4			9.4			9.8
Cash at End of Year	$	8.7		$	8.4		$	9.4
Supplemental Information:
Interest Paid	$	22.3		$	20.8		$	20.8
Income Taxes Paid	$	1.8		$	1.2		$	0.8
Payments on Capital Leases	$	1.1		$	0.6		$	0.7
Capital Expenditures Included in Accounts Payable	$	0.4		$	0.3		$	0.7

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

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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Millions, except shares data)

	Common Equity		Retained Earnings			Total
Balance at January 1, 2013	$	230.0	$	30.4		$	260.4
Net Income for 2013				21.6			21.6
Dividends ($1.38 per Common Share)				(19.1	)		(19.1	)
Shares Issued Under Stock Plans		1.0					1.0
Issuance of 39,559 Common Shares		1.1					1.1
Balance at December 31, 2013		232.1		32.9			265.0
Net Income for 2014				24.7			24.7
Dividends ($1.38 per Common Share)				(19.2	)		(19.2	)
Shares Issued Under Stock Plans		1.4					1.4
Issuance of 38,020 Common Shares		1.2					1.2
Balance at December 31, 2014		234.7		38.4			273.1
Net Income for 2015				26.3			26.3
Dividends ($1.40 per Common Share)				(19.6	)		(19.6	)
Shares Issued Under Stock Plans		1.5					1.5
Issuance of 36,265 Common Shares		1.3					1.3
Balance at December 31, 2015	$	237.5	$	45.1		$	282.6

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

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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 wholly-owned 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 capital city areas 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 Maine to the Lewiston-Auburn area 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 an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine, New Hampshire and Massachusetts. 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 a national client base of large commercial and industrial customers.

Basis of Presentation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation.

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

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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.

Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates.

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

Revenue Recognition—Non-regulated Operations—Usource, Unitil’s competitive energy brokering subsidiary, records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2015 – 3.57%, 2014 – 3.56% and 2013 – 3.59%.

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Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes—The Company bills its customers 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 Consolidated Statements of Earnings.

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

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

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2015 the Company paid quarterly dividends of $0.350 per share, resulting in an annual dividend rate of $1.40 per common share. For the years ended December 31, 2014 and 2013, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend rate of $1.38 per common share. At its January 2016 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.3550 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.42 per share from $1.40 per share.

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2015 and 2014, the Unitil subsidiaries had deposited $2.3 million and $6.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2015 and 2014.

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

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calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric 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. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2015 and 2014.

Accrued Revenue (millions)	December 31,
	2015		2014
Regulatory Assets—Current	$	26.8	$	37.8
Unbilled Revenues		11.6		10.7
Total Accrued Revenue	$	38.4	$	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 December 31, 2015 and 2014.

Exchange Gas Receivable (millions)	December 31,
	2015		2014
Northern Utilities	$	10.3	$	14.2
Fitchburg		0.8		0.8
Total Exchange Gas Receivable	$	11.1	$	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 December 31, 2015 and 2014.

Gas Inventory (millions)	December 31,
	2015		2014
Natural Gas	$	0.3	$	0.8
Propane		0.3		0.2
Liquefied Natural Gas & Other		0.2		0.1
Total Gas Inventory	$	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 average interest rates applied to AFUDC were 2.32%, 1.56% and 1.92% in 2015, 2014 and 2013, respectively. 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 December 31, 2015 and 2014, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $70.1 million and $63.8 million, respectively.

Regulatory Accounting—The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy

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and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the 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.

Regulatory Assets consist of the following (millions)	December 31,
	2015		2014
Retirement Benefits	$	64.7	$	65.1
Energy Supply & Other Regulatory Tracker Mechanisms		21.3		31.0
Deferred Storm Charges		15.4		21.2
Environmental		11.2		11.0
Income Taxes		8.5		9.7
Deferred Restructuring Costs		—		1.6
Other		5.3		5.8
Total Regulatory Assets	$	126.4	$	145.4
Less: Current Portion of Regulatory Assets(1)		26.8		37.8
Regulatory Assets—noncurrent	$	99.6	$	107.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions)	December 31,
	2015		2014
Regulatory Tracker Mechanisms	$	8.0	$	8.8
Gas Pipeline Refund (Note 8)		15.7		—
Total Regulatory Liabilities		23.7		8.8
Less: Current Portion of Regulatory Liabilities		15.6		8.7
Regulatory Liabilities—noncurrent	$	8.1	$	0.1

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2015 are $6.6 million of deferred storm charges to be recovered over the next two and a half years and $7.4 million of rate case costs and other expenditures to be recovered over the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives—The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification.

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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 December 31, 2015, all futures contracts purchased under the prior program design have been 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 customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of December 31, 2015 and December 31, 2014, the Company had 2.5 billion and 2.4 billion cubic feet (BCF), respectively, outstanding in natural gas purchase 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 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 Consolidated Balance Sheets.

Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of:

		Fair Value
Description	Balance Sheet Location	December 31, 2015		December 31, 2014
Derivative Assets
Natural Gas Futures / Options Contracts	Prepayments and Other	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Assets		—		0.1
Total Derivative Assets		$	—	$	0.1
Derivative Liabilities
Natural Gas Futures / Options Contracts	Other Current Liabilities	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	—

	Twelve Months Ended December 31,
	2015		2014
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	0.3	$	(0.7	)
Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.2	$	(0.8	)

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

Investments in Marketable Securities—In 2015, the Company established a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 10).

At December 31, 2015 and 2014, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Prepayments and Other, are $0.7 million and $0, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Fair Value of Marketable Securities (millions)	December 31,
	2015		2014
Equity Funds	$	0.4	$	—
Fixed Income Funds		0.3		—
Total Marketable Securities	$	0.7	$	—

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2015, the unamortized balance of the bargain purchase adjustment was $7.2 million, to be amortized over the next three years.

Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.

	December 31,
Energy Supply Obligations consist of the following: (millions)	2015		2014
Current:
Exchange Gas Obligation	$	10.3	$	14.2
Renewable Energy Portfolio Standards		4.0		7.4
Power Supply Contract Divestitures		0.3		0.5
Total Energy Supply Obligations—Current	$	14.6	$	22.1
Noncurrent:
Power Supply Contract Divestitures	$	1.6	$	1.9
Total Energy Supply Obligations	$	16.2	$	24.0

Exchange Gas Obligation—As discussed above, 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

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legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets.

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

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

Massachusetts Green Communities Act—In compliance with the Massachusetts Green Communities Act, discussed below in Note 8, Commitments and Contingencies, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The generating facility associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements—As of December 31, 2015, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2015, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

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Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2015, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements—In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2017 and interim periods within those annual periods with earlier application permitted as of the beginning of the fiscal year of adoption. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In November 2015, the FASB issued ASU 2015-17 which simplifies the presentation of deferred income taxes in a classified statement of financial position. Current generally accepted accounting principles (GAAP) require an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. ASU 2015-17 amends current GAAP to require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods with earlier application permitted as of the beginning of an interim or annual reporting period. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In August 2015, the FASB issued ASU 2015-13 which clarifies the Normal Purchases and Normal Sales scope exception to certain electricity contracts. ASU 2015-13 specifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract. This pronouncement is effective upon its issuance. The Company has adopted this new guidance and it had no impact on the Company’s Consolidated Financial Statements.

In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In July 2015, the FASB issued ASU 2015-11 which provides authoritative guidance requiring inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. This pronouncement is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

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In May 2015, the FASB issued ASU 2015-07 which provides authoritative guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all periods presented. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In April 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. ASU 2015-03 does not contain guidance for debt issuance costs related to line-of-credit arrangements. Consequently, in August 2015, the FASB issued ASU 2015-15 to add paragraphs indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The effective date of these pronouncements is for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

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

Subsequent Events—The Company evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that impacted its Consolidated Financial Statements.

Note 2: Quarterly Financial Information (unaudited; millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented.

	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2015		2014		2015		2014		2015		2014		2015		2014
Total Operating Revenues	$	172.2	$	156.1	$	77.5	$	73.3	$	74.7	$	76.6	$	102.4	$	119.8
Operating Income	$	28.4	$	25.4	$	8.9	$	7.1	$	7.3	$	7.4	$	18.5	$	20.1
Net Income (Loss) Applicable to Common	$	13.6	$	12.6	$	1.7	$	1.1	$	1.7	$	1.6	$	9.3	$	9.4
	Per Share Data:
Earnings Per Common Share	$	0.98	$	0.91	$	0.12	$	0.08	$	0.12	$	0.11	$	0.67	$	0.69
Dividends Paid Per Common Share	$	0.350	$	0.345	$	0.350	$	0.345	$	0.350	$	0.345	$	0.350	$	0.345

Note 3: Segment Information

Unitil reports three segments: utility gas operations, utility electric operations and non-regulated. 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 Maine to the Lewiston-Auburn area 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.

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Granite State is 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 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 transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers.

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 a national client base of large commercial and industrial customers. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated column below.

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the FERC, NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

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The following table provides significant segment financial data for the years ended December 31, 2015, 2014 and 2013 (millions):

Year Ended December 31, 2015	Gas		Electric		Non- Regulated		Other			Total
Revenues	$	202.6	$	218.0	$	6.2	$	—		$	426.8
Interest Income		0.8		0.7		0.1		0.3			1.9
Interest Expense		13.3		8.8		—		1.7			23.8
Depreciation & Amortization Expense		20.7		24.0		0.1		0.9			45.7
Income Tax Expense (Benefit)		10.2		5.5		0.8		(1.1	)		15.4
Segment Profit		15.3		8.7		1.3		1.0			26.3
Segment Assets		596.7		416.8		6.6		26.3			1,046.4
Capital Expenditures		64.9		29.9		0.1		9.0			103.9
Year Ended December 31, 2014
Revenues	$	201.4	$	218.7	$	5.7	$	—		$	425.8
Interest Income		0.3		0.6		0.1		0.3			1.3
Interest Expense		11.5		9.1		—		1.6			22.2
Depreciation & Amortization Expense		18.8		22.3		—		1.0			42.1
Income Tax Expense (Benefit)		10.8		4.5		0.6		(1.9	)		14.0
Segment Profit		15.8		6.8		0.9		1.2			24.7
Segment Assets		566.3		414.1		6.3		13.5			1,000.2
Capital Expenditures		62.3		24.8		0.3		5.2			92.6
Year Ended December 31, 2013
Revenues	$	170.4	$	190.7	$	5.8	$	—		$	366.9
Interest Income		0.5		2.2		0.1		0.4			3.2
Interest Expense		11.0		9.5		—		1.5			22.0
Depreciation & Amortization Expense		17.2		20.3		—		1.0			38.5
Income Tax Expense (Benefit)		7.5		5.1		0.8		(0.7	)		12.7
Segment Profit		12.5		7.6		1.2		0.3			21.6
Segment Assets		502.3		402.8		6.2		9.3			920.6
Capital Expenditures		61.1		23.6		—		4.8			89.5

Note 4: Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2015, 2014 and 2013, the Company recorded provisions for the energy commodity portion of bad debts of $2.6 million, $2.6 million and $1.4 million, respectively. These provisions were recognized in Cost of Gas Sales and Cost of Electric Sales expense as the associated electric and gas utility revenues were billed. Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling 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.

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The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2013—2015 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2015
Electric	$	1.3	$	2.5	$	0.3	$	3.5	$	0.6
Gas		0.4		2.8		0.4		3.1		0.5
Other		0.1		—		—		—		0.1
	$	1.8	$	5.3	$	0.7	$	6.6	$	1.2
Year Ended December 31, 2014
Electric	$	1.3	$	2.9	$	0.3	$	3.2	$	1.3
Gas		0.2		3.1		0.3		3.2		0.4
Other		0.1		—		—		—		0.1
	$	1.6	$	6.0	$	0.6	$	6.4	$	1.8
Year Ended December 31, 2013
Electric	$	1.1	$	2.6	$	0.2	$	2.6	$	1.3
Gas		0.7		2.0		0.2		2.7		0.2
Other		0.1		—		—		—		0.1
	$	1.9	$	4.6	$	0.4	$	5.3	$	1.6

Note 5: Debt and Financing Arrangements

The Company funds a portion of its operations through the issuance of long-term debt and through short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow:

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants—The agreements under which the long-term debt of Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations, as described below.

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of Unitil Energy and Fitchburg or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met; including that Unitil Energy have sufficient

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available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets. The Granite State notes are guaranteed by Unitil for the payment of principal, interest and other amounts payable. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2015, in accordance with the covenants, these subsidiary companies had a combined amount of $163.1 million available for the payment of dividends and Unitil Corporation had $194.6 million available for the payment of dividends. As of December 31, 2015, the Company’s balance in Retained Earnings was $45.1 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2015 for the payment of dividends.

Issuance of 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.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $7.4 million, $4.4 million, and $0.5 million in 2015, 2014, and 2013, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2015 is: 2016 – $17.4 million; 2017 – $17.2 million; 2018 – $30.1 million; 2019 – $18.8 million; 2020 – $19.8 million and thereafter $222.2 million.

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

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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.

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2015		2014
Estimated Fair Value of Long-Term Debt	$	345.2	$	380.6

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

Long-Term Debt (millions)	December 31,
	2015		2014
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		12.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0
Fitchburg Long-Term Notes:
6.75% Notes, Due November 30, 2023		11.4		15.2
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		1.1		1.7
Total Long-Term Debt		325.5		332.9
Less: Current Portion		17.4		4.0
Total Long-Term Debt, Less Current Portion	$	308.1	$	328.9

Interest Expense, net—Interest expense is presented in the 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 monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

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A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2015			2014			2013
Interest Expense
Long-Term Debt	$	22.0		$	20.5		$	20.2
Short-Term Debt		0.9			1.1			1.2
Regulatory Liabilities		0.9			0.6			0.6
Subtotal Interest Expense		23.8			22.2			22.0
Interest Income
Regulatory Assets		(0.7	)		(0.6	)		(2.3	)
AFUDC(1) and Other		(1.2	)		(0.7	)		(0.9	)
Subtotal Interest Income		(1.9	)		(1.3	)		(3.2	)
Total Interest Expense, net	$	21.9		$	20.9		$	18.8

⁽¹⁾  AFUDC—Allowance for Funds Used During Construction

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 new 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.

On July 24, 2015, the Company entered into the First Amendment to the Credit Facility. The First Amendment provides for an extension of the scheduled termination date to October 4, 2020, reduces the daily fluctuating rate of interest per annum equal to one-month LIBOR plus 1.25%, and reduces other customary credit facility fees. All other terms and conditions of the Credit Facility, including affirmative and negative covenants, remain substantially unchanged.

The Company utilizes the credit facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $140.3 million and $179.4 million for the years ended December 31, 2015 and December 31, 2014, respectively. Total gross repayments were $127.6 million and $210.3 million for the years ended December 31, 2015 and December 31, 2014, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2015 and December 31, 2014:

Revolving Credit Facility (millions)
	December 31,
	2015		2014
Limit	$	120.0	$	120.0
Outstanding	$	42.0	$	29.3
Available	$	78.0	$	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

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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 December 31, 2015 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 5.)

The weighted average interest rates on all short-term borrowings were 1.5%, 1.6%, and 1.8% during 2015, 2014, and 2013, respectively.

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

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2015, there are $2.6 million of current and $10.4 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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 $10.8 million and $15.1 million of natural gas storage inventory at December 31, 2015 and 2014, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2015, which was payable in January 2016, was $0.6 million and recorded in Accounts Payable at December 31, 2015. The amount of natural gas inventory released in December 2014, which was payable in January 2015, was $1.0 million and recorded in Accounts Payable at December 31, 2014.

Leases

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.

Total rental expense under operating leases charged to operations for the years ended December 31, 2015, 2014 and 2013 amounted to $1.7 million, $1.3 million and $1.2 million respectively.

Assets under capital leases amounted to approximately $15.3 million and $9.7 million as of December 31, 2015 and 2014, respectively, less accumulated amortization of $0.8 million and $0.8 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2015. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $11.0 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2015. $2.6 million of the current Capital Lease Obligations and $10.4 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2016	$	1,326	$	3,060
2017		1,048		2,937
2018		698		2,891
2019		355		2,851
2020		180		2,357
2021 – 2025		125		—
Total Payments	$	3,732	$	14,096

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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 December 31, 2015, there were approximately $19.3 million of guarantees outstanding and the longest term guarantee extends through August 2016.

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 December 31, 2015, the principal amount outstanding for the 8% Unitil Realty notes was $1.1 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Note 6: Equity

The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding. Details regarding these forms of capitalization follow:

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 13,916,026 and 13,991,430 shares of common stock outstanding at December 31, 2014 and December 31, 2015, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2014 and December 31, 2015.

Dividend Reinvestment and Stock Purchase Plan—During 2015, the Company sold 36,265 shares of its common stock, at an average price of $34.77 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.3 million. 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. During 2014 and 2013, the Company raised $1.2 million and $1.1 million, respectively, through the issuance of 38,020 and 39,559 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—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, 2014, the Company may 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. (See Part II, Item 5, for additional information). During 2015, 2014 and 2013, the Company repurchased 1,981, 2,763 and 2,969 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.1 million, $0.1 million and $0.1 million in 2015, 2014 and 2013, respectively.

During 2015, 2014 and 2013, the Company did not cancel or retire any of its common stock.

Stock-Based Compensation Plans—Unitil maintains a stock plan. The Company accounts for its stock-based compensation plan in accordance with the provisions of the FASB Codification and measures compensation costs at fair value at the date of grant. Details of the plan are as follows:

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.

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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.

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.

Restricted Shares issued for 2013 – 2015 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
2/4/13	21,240	$0.6
1/31/14	35,500	$1.1
1/26/15	40,010	$1.5

There were 70,761 and 67,334 non-vested shares under the Stock Plan as of December 31, 2015 and 2014, respectively. The weighted average grant date fair value of these shares was $32.56 per share and $28.51 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $1.9 million, $1.4 million and $0.7 million in 2015, 2014 and 2013, respectively. At December 31, 2015, there was approximately $1.1 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were 871 restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2015. On January 26, 2016, there were 43,220 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, 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 2015 and 2014 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2015				2014
	Units		Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		23,576	$	29.90		14,903		$	28.90
Restricted Stock Units Granted		8,965	$	36.54		9,078		$	31.23
Dividend Equivalents Earned		1,047	$	35.01		701		$	33.18
Restricted Stock Units Settled		—		—		(1,106	)	$	29.49
Ending Restricted Stock Units		33,588	$	31.83		23,576		$	29.90

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Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2015 and 2014 is $0.5 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 1,898 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2015. There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2014. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2015 and December 31, 2014, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data)	2015		2014		2013
Earnings Available to Common Shareholders	$	26.3	$	24.7	$	21.6
Weighted Average Common Shares Outstanding—Basic (000’s)		13,917		13,843		13,773
Plus: Diluted Effect of Incremental Shares (000’s)		3		4		2
Weighted Average Common Shares Outstanding—Diluted (000’s)		13,920		13,847		13,775
Earnings per Share—Basic and Diluted	$	1.89	$	1.79	$	1.57

For 2015, 2014 and 2013, respectively, 36,941, 0 and 4,481 weighted average non-vested restricted shares were not included in the above computation because the effect would have been antidilutive.

Note 7: Energy Supply

Natural Gas Supply

Unitil manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

Northern Utilities’ Commercial and Industrial (C&I) customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities’ larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. Fitchburg’s residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies from third-party suppliers, while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. The approved costs associated with the acquisition of such wholesale natural gas supplies for customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

Regulated Natural Gas Supply

Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), to truck supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.6 billion cubic

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feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

Fitchburg purchases natural gas under contracts from producers and marketers on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round transportation and 0.33 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

Electric Power Supply

The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil’s power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2015, 79% of Unitil’s largest New Hampshire customers, representing 26% of total New Hampshire electric energy sales, and 88% of Unitil’s largest Massachusetts customers, representing 34% of total Massachusetts electric energy sales; are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base and customers in Ashby comprise another 5%. In New Hampshire, the number of residential customers purchasing from a third party supplier has increased more than tenfold in the past three years and stands at 13% of residential customers. Notwithstanding this activity, most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts with various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

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The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

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 and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Long-Term Renewable Contracts

Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Note 8: Commitments and Contingencies

Regulatory Matters

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MPUC, the MDPU, and the NHPUC have each continued to approve these

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reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31, 2015. The remaining balance of these assets is $1.9 million as of December 31, 2015, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $1.6 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next six years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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. The 2015 TIRA provided for an annual increase in base distribution revenue of $1.2 million, effective May 1, 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. 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. The 2015 step adjustment provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015 the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund will be credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities will be credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities of $7.6 million and $8.1 million, respectively, on its Consolidated Balance Sheets as of December 31, 2015.

Unitil Energy—Base Rates—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. The third and final step increase of $1.5 million in annual revenue was effective May 1, 2014.

Granite State—Base Rates—Granite State had in place a FERC approved amended settlement agreement under which it had 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. The final rate adjustment under this agreement was effective August 1, 2014. Granite State has received FERC approval of a second amended settlement agreement under which it will continue to be

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permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a cost cap. The FERC approval of the second amended settlement included a rate increase of $0.4 million, effective August 1, 2015.

Fitchburg—Base Rates—Electric—On May 30, 2014, the Massachusetts Department of Public Utilities (MDPU) approved a $5.6 million increase in Fitchburg’s base revenue decoupling target, effective June 1, 2014. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 and 2012. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off. The impact of the rate order on previously capitalized or deferred items was not material.

On June 16, 2015, Fitchburg filed for a $3.8 million increase in electric base revenue decoupling target, which represents a 5.6 percent increase over 2014 test year operating electric revenues. The filing included a request for approval of a capital cost recovery mechanism to recover prudently incurred additions to utility plant on an annual basis. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. 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 decoupling target, which represents an 8.3 percent increase over 2014 test year total gas operating revenues. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of April, 2016.

Major Storms—Fitchburg and Unitil Energy

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

Unitil Energy—2012 Storm Costs—On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Thanksgiving 2014 Snow Storm—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 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.

NHPUC Energy Efficiency Resource Standard Proceeding—On May 8, 2015, the NHPUC issued an order of notice commencing a proceeding to establish an Energy Efficiency Resource Standard, an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. In this proceeding the Commission will define the savings targets and address issues related to public and private funding; program cost recovery; lost-revenue recovery (e.g. decoupling); performance-based incentives and penalties; program administration; and evaluation, measurement, and verification. Initial comments were filed by interested parties on December 9, 2015, and the matter remains pending.

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Northern Utilities—Other—In the fourth quarter of 2015, Northern Utilities completed the transition into a new Distribution Operations Center (DOC) for its operations in Portland, Maine. The new property includes an existing building and is located at 376 Riverside Industrial Parkway in Portland, Maine. On September 19, 2014, Northern Utilities sold its existing DOC facility located at 1075 Forest Avenue in Portland, Maine. While the new DOC facility was being renovated, Northern Utilities leased back its existing DOC facility from the new owner. The new DOC facility was needed due to space limitations at the existing DOC. In recent years Northern Utilities’ gas expansion initiative and the work associated with it resulted in staff, company vehicles, and material storage additions to a facility that could not adequately handle these additions. Northern Utilities recognized a net gain on sale of the Forest Avenue property of $0.9 million in the fourth quarter of 2015.

Fitchburg—Electric Operations—On November 24, 2014, Fitchburg submitted its 2014 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were approved, subject to investigation and reconciliation, effective January 1, 2015 for billing purposes, and given final approval by the MDPU on June 16, 2015.

On November 17, 2015, Fitchburg submitted its 2015 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were approved, subject to investigation and reconciliation, effective January 1, 2016 for billing purposes, and given final approval by the MDPU on December 29, 2015.

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 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. The second annual filing, to recover the estimated costs to be incurred in calendar year 2016, was made on October 31, 2015. The Company seeks approval to collect in rates $0.9 million for the costs of its cumulative capital investments for 2015 and 2016, effective May 1, 2016. This matter remains pending.

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 July 7, 2015, the MDPU approved Fitchburg’s 2013 gas division Service Quality Report as filed. On October 21, 2015, the MDPU approved Fitchburg’s 2012 electric division Service Quality Report as filed. On November 25, 2015, the MDPU approved Fitchburg’s 2014 gas division Service Quality Report as filed. Fitchburg’s 2013 and 2014 electric division Service Quality Reports remain pending.

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 filed a motion with the MDPU to

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reconsider the adoption of state-wide standards and requested reconsideration and clarification on other technical issues. On December 18, 2015, the MDPU issued its order on the motion to reconsider, and issued revised guidelines. The new guidelines reverse the change to state-wide standards in favor of the company specific standards currently in place, eliminate several metric and reporting requirements and revise several existing metrics in addition to the changes noted above. 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.

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 provided guidance and filing requirements for the business case justification that the electric companies must file as part of their GMPs. The second order required 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. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filing are currently under the MDPU’s review. The MDPU is addressing in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles. These matters remain pending.

FERC Transmission Formula Rate Proceeding—On December 28, 2015, FERC issued an order, pursuant to section 206 of the Federal Power Act, instituting a proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own

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transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin as of January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The 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 SJC, and the SJC upheld the lower Court’s order. Subsequently, 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. On July 27, 2015, the Court issued its decision allowing class certification and denying the Company’s motion for summary judgment. The Company appealed this decision to the SJC, and on October 15, 2015, the SJC granted the Company’s motion for direct review of the case, and it is being briefed by the parties and set for oral argument during the first quarter of 2016. 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. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

Environmental Matters

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 December 31, 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. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough. Northern Utilities has worked with the 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, Dover, Somersworth, Portsmouth, Lewiston and Scarborough sites, though future activities may be required.

The site in Portland has been investigated and remedial activities have largely been completed. Final remediation activities were completed in the fourth quarter of 2015, and closure documentation will be

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prepared for submittal to the regulatory agency in the first half of 2016. In the second quarter of 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 this taking, and pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the site will be primarily the responsibility of the State of Maine.

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 remediation activities in Exeter commenced in the fourth quarter of 2015. The anticipated completion of these activities is in the first quarter of 2016.

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

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

Fitchburg’s Manufactured Gas Plant Site—Fitchburg completed the scheduled site work at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the fourth quarter of 2014. The closure documentation for the site was submitted in the fourth quarter of 2015 and is under review by the Massachusetts Department of Environmental Protection.

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 years ended December 31, 2015 and 2014.

Environmental Obligations

	(millions)
	Fitchburg				Northern Utilities				Total
	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		—		—		2.9		1.3		2.9		1.3
Less: Payments / Reductions		0.7		10.1		4.9		0.5		5.6		10.6
Total Balance at End of Period	$	1.2	$	1.9	$	1.6	$	3.6	$	2.8	$	5.5
Less: Current Portion		0.2		1.9		1.1		1.6		1.3		3.5
Noncurrent Balance at December 31, 2014	$	1.0	$	—	$	0.5	$	2.0	$	1.5	$	2.0

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Note 9: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2015, 2014 and 2013 are shown in the table below:

	($000’s)
	2015			2014			2013
Current Federal Tax Provision (Benefit)
Operating Income	$	3,710		$	3,179		$	—
Current Benefit of Operating Loss Carryforwards		(3,710	)		(3,179	)		—
Total Current Federal Tax Provision (Benefit)		—			—			—
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		17,924			10,649			28,907
Net Operating Loss Carryforwards / (Carrybacks)		2,374			2,589			(8,053	)
Regulatory Assets and Liabilities		(6,101	)		(5,946	)		(11,483	)
Other, net		(1,784	)		3,517			681
Total Deferred Federal Tax Provision (Benefit)		12,413			10,809			10,052
Total Federal Tax Provision		12,413			10,809			10,052
State
Current		3,530			(387	)		386
Deferred		(500	)		3,573			2,214
Total State Tax Provision		3,030			3,186			2,600
Total Provision for Federal and State Income Taxes	$	15,443		$	13,995		$	12,652

The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:

	2015			2014			2013
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		5			2			5
Utility Plant Differences		(2	)		(1	)		(2	)
Tax Credits and Other, net		—			1			—
Effective Income Tax Rate		37	%		36	%		37	%

Temporary differences which gave rise to current deferred tax assets and liabilities in 2015 and 2014, are shown below:

Current Deferred Income Taxes (000’s)	2015			2014
Accrued Revenue, Current Portion	$	5,090		$	(3,038	)
Other, net		(348	)		(90	)
Total Current Deferred Income Tax Assets (Liabilities)	$	4,742		$	(3,128	)

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2015 and 2014, are shown below:

Noncurrent Deferred Income Taxes (000’s)	2015			2014
Utility Plant Differences	$	141,185		$	120,534
Retirement Benefit Obligations		(43,543	)		(44,829	)
Net Operating Loss Carryforwards		(10,500	)		(13,122	)
Regulatory Assets & Liabilities		10,535			12,740
AMT Tax Credit Carryforwards		(2,677	)		(2,139	)
Other, net		(2,792	)		(314	)
Total Noncurrent Deferred Income Tax Liabilities	$	92,208		$	72,870

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The Company is subject to federal and state income taxes as well as various other business taxes. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company 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 that gave rise to the revision become known.

The Company filed its tax returns for the year ended December 31, 2014 with the Internal Revenue Service in September 2015 and generated additional federal net operating loss (NOL) carryforward assets principally due to current tax repair deductions, tax depreciation and research and development deductions. For the year ended December 31, 2015, the Company utilized $3.7 million of its federal NOL carryforward assets in the calculation of its provisions for income taxes for the period. As of December 31, 2015, the Company had recorded cumulative federal NOL carryforward assets of $11.3 million to offset against taxes payable in future periods. If unused, the Company’s federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2015, the Company had $2.1 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In 2015, Unitil recognized a tax benefit of $63,000 in the tax provision related to Federal research and development tax credits under the rules of section 41 of the Internal Revenue Code, which the Company claimed on its 2014 tax return filed in September of 2015. The Company will continue to recognize a tax benefit on its incremental qualified research expenses and has recognized a tax benefit in the tax provision of $288,000 related to 2015 expenditures.

The Company evaluated its tax positions at December 31, 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, 2012; December 31, 2013; and December 31, 2014.

Note 10: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:

• The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

• The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified retirement plan, with participation limited to executives selected by the Board of Directors.

Effective with the acquisitions of Northern Utilities and Granite State, the Company assumed the assets and obligations of the Northern Utilities and Granite State pension plans with respect to active union employees. All other active employees of Northern Utilities and Granite State effectively became members of the Company’s Pension Plan as of the acquisitions closing date.

Certain employees of Northern Utilities qualified for participation in the Company’s PBOP Plan effective with the acquisition closing date.

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

	2015			2014			2013
Used to Determine Plan costs for years ended December 31:
Discount Rate(1)		4.00	%		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2018			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,383		$	989		$	1,169
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(1,040	)	$	(771	)	$	(895	)

⁽¹⁾  As a result of the addition of a plan participant to the SERP in July 2015, the Company was required to update the discount rate used in determining SERP costs for the remainder of 2015. Based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves at that time, the Company assumed a discount rate of 4.30% for the SERP from July through December of 2015.

Used to Determine Benefit Obligations at December 31:
Discount Rate		4.30	%		4.00	%		4.80	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2022			2018			2018
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	14,877		$	15,325		$	9,957
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(11,611	)	$	(11,829	)	$	(7,942	)

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2015, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $472,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2015 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

The following table provides the components of the Company’s Retirement plan costs (000’s):

	Pension Plan									PBOP Plan									SERP
	2015			2014			2013			2015			2014			2013			2015		2014		2013
Service Cost	$	3,689		$	3,006		$	3,573		$	2,622		$	1,988		$	2,523		$	120	$	57	$	73
Interest Cost		5,392			5,092			4,567			2,918			2,686			2,448			330		272		241
Expected Return on Plan Assets		(6,779	)		(6,245	)		(5,955	)		(1,093	)		(920	)		(722	)		—		—		—
Prior Service Cost Amortization		265			211			208			1,682			1,682			1,701			85		11		11
Actuarial Loss Amortization		4,714			2,847			4,229			1,150			56			786			327		100		184
Sub-total		7,281			4,911			6,622			7,279			5,492			6,736			862		440		509
Amounts Capitalized or Deferred		(3,397	)		(1,881	)		(2,929	)		(3,423	)		(2,270	)		(3,010	)		—		—		—
NPBC Recognized	$	3,884		$	3,030		$	3,693		$	3,856		$	3,222		$	3,726		$	862	$	440	$	509

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The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company’s Retirement plan costs or as a reduction of regulatory assets over the next fiscal year is $4.7 million, $2.5 million and $0.3 million for the Pension, PBOP and SERP plans, respectively.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2015, 2014 and 2013 before capitalization and deferral was $7.3 million, $4.9 million and $6.6 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2015, 2014 and 2013 would have been $7.3 million, $4.3 million and $6.6 million respectively.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2015			2014			2015			2014			2015			2014
Plan Assets at Beginning of Year	$	86,744		$	82,551		$	12,840		$	10,829		$	—		$	—
Actual Return on Plan Assets		645			4,248			(214	)		486			—			—
Employer Contributions		4,215			4,191			4,000			3,650			40			53
Participant Contributions		—			—			63			59			—			—
Benefits Paid		(4,410	)		(4,246	)		(2,515	)		(2,184	)		(40	)		(53	)
Plan Assets at End of Year	$	87,194		$	86,744		$	14,174		$	12,840		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	136,662		$	108,295		$	73,923		$	56,899		$	7,965		$	5,857
Service Cost		3,689			3,006			2,622			1,988			120			57
Interest Cost		5,392			5,092			2,918			2,686			330			272
Participant Contributions		—			—			63			59			—			—
Plan Amendments		474			—			—			—			608			—
Benefits Paid		(4,410	)		(4,246	)		(2,515	)		(2,184	)		(40	)		(53	)
Actuarial (Gain) or Loss		(991	)		24,515			(762	)		14,475			194			1,832
PBO at End of Year	$	140,816		$	136,662		$	76,249		$	73,923		$	9,177		$	7,965
Funded Status: Assets vs PBO	$	(53,622	)	$	(49,918	)	$	(62,075	)	$	(61,083	)	$	(9,177	)	$	(7,965	)

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets of $64.7 million and $65.1 million at December 31, 2015 and 2014, respectively, to account for the future collection of these plan obligations in electric and gas rates.

83

The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $126.8 million and $121.8 million as of December 31, 2015 and 2014, respectively. The ABO for the SERP was $7.0 million and $6.3 million as of December 31, 2015 and 2014, respectively. For the PBOP Plan, the ABO and PBO are the same.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2016 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

	Pension Plan						PBOP Plan						SERP
	2015		2014		2013		2015		2014		2013		2015		2014		2013
Employer Contributions	$	4,215	$	4,191	$	3,700	$	4,000	$	3,650	$	3,280	$	40	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	63	$	59	$	36	$	—	$	—	$	—
Benefit Payments	$	4,410	$	4,246	$	3,764	$	2,515	$	2,184	$	1,942	$	40	$	53	$	53

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2016	$	5,181	$	2,178	$	426
2017		5,522		2,318		421
2018		5,560		2,503		416
2019		6,086		2,700		475
2020		6,345		2,866		469
2021 - 2025		37,857		17,932		3,027

The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 47% in common stock equities, 37% in fixed income securities, 10% in real estate securities and 6% in a combined equity and debt fund. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2016			Actual Allocation at December 31,
				2015			2014			2013
Equity Funds		47	%		46	%		49	%		54	%
Debt Funds		37	%		37	%		36	%		32	%
Real Estate Fund		10	%		11	%		10	%		1	%
Asset Allocation Fund(1)		6	%		6	%		5	%		5	%
Other(2)		0	%		0	%		0	%		8	%
Total					100	%		100	%		100	%

(1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

(2) Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

PBOP Plan	Target Allocation 2016			Actual Allocation at December 31,
				2015			2014			2013
Equity Funds		55	%		53	%		56	%		57	%
Debt Funds		45	%		47	%		44	%		43	%
Total					100	%		100	%		100	%

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The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.00% for 2015. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2015 and 2014. Please also see Note 1 for a discussion of the Company’s fair value accounting policy.

Equity, Fixed Income, Index and Asset Allocation Funds

These investments are valued based on quoted prices from active markets. These securities are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Cash Equivalents

These investments are valued at cost, which approximates fair value, and are categorized in Level 1.

Real Estate Fund

These investments are valued at net asset value (NAV) per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity and are categorized in Level 3.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2015 and 2014 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2015
Pension Plan Assets:
Equity Funds	$	40,124	$	40,124	$	—	$	—
Fixed Income Funds		32,192		32,192		—		—
Asset Allocation Fund		5,527		5,527		—		—
Real Estate Fund		9,351		—		—		9,351
Total Assets	$	87,194	$	77,843	$	—	$	9,351
2014
Pension Plan Assets:
Equity Funds	$	42,760	$	42,760	$	—	$	—
Fixed Income Funds		31,136		31,136		—		—
Asset Allocation Fund		4,676		4,676		—		—
Real Estate Fund		8,172		—		—		8,172
Total Assets	$	86,744	$	78,572	$	—	$	8,172

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The following tables set forth additional disclosures of Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2015 and 2014 (000’s):

	Fair Value Estimated Using NAV Per Share
Description	Fair Value		Unfunded Commitment		Redemption Frequency		Redemption Notice Period
	December 31, 2015
SEI Core Property Collective Investment Trust Fund(1)	$	9,351	$	—		Quarterly		65 days
	December 31, 2014
SEI Core Property Collective Investment Trust Fund(1)	$	8,172	$	—		Quarterly		65 days

⁽¹⁾  The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

The table below sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the years ended December 31, 2015 and 2014 (000’s):

Level 3 Assets—SEI Core Property Collective Investment Trust Fund
	December 31,
	2015		2014
Beginning Balance	$	8,172	$	1,125
Actual Return on Investments:
Related to Investments Held at Year-End		1,179		672
Related to Investments Sold During the Year		—		—
Total Return on Investments		1,179		672
Purchases, Sales and Settlements		—		6,375
Ending Balance	$	9,351	$	8,172

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2015 and 2014 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2015
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	6,620	$	6,620	$	—	$	—
Equity Funds		7,554		7,554
Total Assets	$	14,174	$	14,174	$	—	$	—
2014
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	5,661	$	5,661	$	—	$	—
Index Funds		5,313		5,313
Equity Funds		1,866		1,866
Total Assets	$	12,840	$	12,840	$	—	$	—

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Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $2,098,000, $1,877,000 and $1,678,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure 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, conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of December 31, 2015. Based on this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2015 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective.

Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).

Under the supervision and with the participation of management, including the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, Unitil management has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, based upon criteria established in the “Internal Control–Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, Unitil management concluded that Unitil’s internal control over financial reporting was effective as of December 31, 2015.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2015, as stated in their report which appears in Part II, Item 8 herein.

Changes in Internal Control over Financial Reporting

There have been no changes in Unitil’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the fiscal quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, Unitil’s internal control 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.

Item 9B. Other Information

On January 28, 2016, the Company issued a press release announcing its results of operations for the quarter and year ended December 31, 2015. The press release is furnished with this Annual Report on Form 10-K as Exhibit 99.1.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information required by this Item is set forth in the “Proposal 1: Election of Directors” section and the “Description of Management” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016. Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934, is set forth in the “Corporate Governance and Policies of the Board—Section 16(a) Beneficial Ownership Reporting Compliance” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016. Information regarding the Company’s Audit Committee is set forth in the “Committees of the Board—Audit Committee” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016. Information regarding the Company’s Code of Ethics is set forth in the “Corporate Governance and Policies of the Board—Code of Ethics” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016. Information regarding procedures by which shareholders may recommend nominees to the Company’s Board of Directors is set forth in the “Corporate Governance and Policies of the Board—Nominations” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016.

Item 11. Executive Compensation

Information required by this Item is set forth in the “Compensation Discussion and Analysis” and “Compensation of Named Executive Officers” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this Item is set forth in the “Beneficial Ownership” section of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016, as well as the Equity Compensation Plan Information table in Part II, Item 5 of this Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this Item is set forth in the “Corporate Governance and Policies of the Board—Transactions with Related Persons” and the “Corporate Governance and Policies of the Board—Director Independence” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016.

Item 14. Principal Accountant Fees and Services

Information required by this Item is set forth in the “Audit Committee Report—Principal Accountant Fees and Services” and the “Audit Committee Report—Audit Committee Pre-Approval Policy” sections of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2016.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) and (2)—LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:

• Reports of Independent Registered Public Accounting Firms

• Consolidated Statements of Earnings for the years ended December 31, 2015, 2014 and 2013

• Consolidated Balance Sheets—December 31, 2015 and 2014

• Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013

• Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2015, 2014 and 2013

• Notes to Consolidated Financial Statements

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.

(3)—LIST OF EXHIBITS

Exhibit Number		Description of Exhibit	Reference*
	2.1	Stock Purchase Agreement among Nisource Inc., Bay State Gas Company and Unitil Corporation.	Exhibit 2.1 to Form 8-K dated February 15, 2008 (SEC File No. 1-8858)
	3.1	Articles of Incorporation of Unitil Corporation.	Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984
	3.2	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on March 4, 1992.	Exhibit 3.2 to Form 10-K for 1991 (SEC File No. 1-8858)
	3.3	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on September 23, 2008.	Exhibit 3.3 to Form S-3/A Registration Statement No. 333-152823 dated November 25, 2008
	3.4	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on April 27, 2011.	Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 333-168394, dated January 28, 2014
	3.5	Third Amended and Restated By-Laws of Unitil Corporation.	Exhibit 3.1 to Form 8-K dated December 12, 2013 (SEC File No. 1-8858)
	4.1	Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958.	Exhibit 4.1 to Form 10-K for 2002 (SEC File No. 1-8858)

90

Exhibit Number		Description of Exhibit	Reference*
	4.2	Fitchburg Note Agreement dated November 30, 1993 for the 6.75% Notes due November 23, 2023.	Exhibit 4.18 to Form 10-K for 1993 (SEC File No. 1-8858)
	4.3	Fitchburg Note Agreement dated January 26, 1999 for the 7.37% Notes due January 15, 2029.	Exhibit 4.25 to Form 10-K for 1999 (SEC File No. 1-8858)
	4.4	Fitchburg Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031.	Exhibit 4.6 to Form 10-Q for June 30, 2001 (SEC File No. 1-8858)
	4.5	Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for the 8.00% Senior Secured Notes due August 1, 2017.	Exhibit 4.22 to Form 10-K for 1997 (SEC File No. 1-8858)
	4.6	Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025.	Exhibit 4.7 to Form 10-K for 2003 (SEC File No. 1-8858)
	4.7	Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030.	**
	4.8	Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006.	**
	4.9	Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022.	**
	4.10	Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December 3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038.	Exhibit 4.1 to Form 8-K dated December 3, 2008 (SEC File No. 1-8858)
	4.11	Granite State Note Purchase Agreement, dated as of December 15, 2008, for the 7.15% Senior Notes due December 15, 2018.	Exhibit 99.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
	4.12	Northern Utilities Note Purchase Agreement, dated as of March 2, 2010, for the 5.29% Senior Notes, due March 2, 2020.	Exhibit 4.1 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
	4.13	Fourteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of March 2, 2010.	Exhibit 4.4 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
	4.14	Northern Utilities form of Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
	4.15	Northern Utilities form of Note issued pursuant to the Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
	10.1	Unitil System Agreement dated June 19, 1986 providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.	Exhibit 10.9 to Form 10-K for 1986 (SEC File No. 1-8858)
	10.2	Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.	Exhibit 10.8 to Form 10-K for 1987 (SEC File No. 1-8858)
	10.3	Transmission Agreement between Unitil Power Corp. and Public Service Company of New Hampshire, effective November 11, 1992.	Exhibit 10.6 to Form 10-K for 1993 (SEC File No. 1-8858)

91

Exhibit Number		Description of Exhibit	Reference*
	10.4***	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.2 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.5***	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.3 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.6***	Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2007.	Exhibit 10.4 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.7***	Unitil Corporation Management Incentive Plan (amended and restated as of June 5, 2013).	Exhibit 10.2 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
	10.8	Entitlement Sale and Administrative Services Agreement with Select Energy.	Exhibit 10.14 to Form 10-K for 1999 (SEC File No. 1-8858)
	10.9***	Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 10.1 to Form 8-K dated April 19, 2012 (SEC File No. 1-8858)
	10.10***	Form of Restricted Stock Unit Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
	10.11***	Form of Restricted Stock Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 4.8 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
	10.12***	Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement.	Exhibit 10.1 to Form 10-Q for September 30, 2004 (SEC File No. 1-8858)
	10.13***	Unitil Corporation Tax Deferred Savings and Investment Plan, as amended to date	Exhibit 10.13 to Form 10-K for 2013 (SEC File No. 1-8858)
	10.14***	Employment Agreement effective November 1, 2015 between Unitil Corporation and Robert G. Schoenberger	Exhibit 10.1 to Form 8-K dated October 21, 2015 (SEC File No. 1-8858)
	10.15	Amended and Restated Credit Agreement dated as of October 4, 2013 by and among Unitil Corporation and Bank of America, N.A.	Exhibit 10.1 to Form 8-K dated October 4, 2013 (SEC File No. 1-8858)
	10.16	First Amendment to Amended and Restated Credit Agreement dated as of July 24, 2015 by and among Unitil Corporation, Bank of America, N.A., and the other parties thereto.	Exhibit 10.1 to Form 8-K dated July 24, 2015 (SEC File No. 1-8858)
	10.17	Parent Guaranty of Unitil Corporation for the Granite State 7.15% Senior Notes due December 15, 2018.	Exhibit 10.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
	10.18***	Unitil Corporation—Compensation of Directors.	Exhibit 10.18 to Form 10-K for 2014 (SEC File No. 1-8858)
	10.19***	Unitil Corporation Incentive Plan (amended and restated as of January 26, 2015)	Exhibit 10.1 to Form 10-Q for March 31, 2015 (SEC File No. 1-8858)

92

Exhibit Number		Description of Exhibit	Reference*
	11.1	Statement Re: Computation in Support of Earnings per Share for the Company.	Filed herewith
	12.1	Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company.	Filed herewith
	21.1	Statement Re: Subsidiaries of Registrant.	Filed herewith
	23.1	Consent of Independent Registered Public Accounting Firm.	Filed herewith
	23.2	Consent of Independent Registered Public Accounting Firm.	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 January 28, 2016 Announcing Earnings For the Quarter and Year Ended December 31, 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

* The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

** In accordance with Item 601(b)(4)(iii)(A) of Federal Securities Regulation S-K, the instrument defining the debt of the Registrant and its subsidiary, described above, has been omitted but will be furnished to the Commission upon request.

*** These exhibits represent a management contract or compensatory plan.

93

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	UNITIL CORPORATION
Date January 28, 2016	By	/s/    ROBERT G. SCHOENBERGER
		Robert G. Schoenberger
		Chairman of the Board of Directors, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/S/    ROBERT G.SCHOENBERGER         Robert G. Schoenberger	Principal Executive Officer; Director	January 28, 2016
/S/    MARK H. COLLIN         Mark H. Collin	Principal Financial Officer	January 28, 2016
/S/    LAURENCE M. BROCK         Laurence M. Brock	Principal Accounting Officer	January 28, 2016
/S/    ALBERT H. ELFNER, III         Albert H. Elfner, III	Director	January 28, 2016
/S/    M. BRIAN O’SHAUGHNESSY         M. Brian O’Shaughnessy	Director	January 28, 2016
/S/    DR. SARAH P. VOLL         Dr. Sarah P. Voll	Director	January 28, 2016
/S/    EBEN S. MOULTON         Eben S. Moulton	Director	January 28, 2016
/S/    DAVID P. BROWNELL         David P. Brownell	Director	January 28, 2016
/S/    EDWARD F. GODFREY         Edward F. Godfrey	Director	January 28, 2016
/S/    MICHAEL B. GREEN         Michael B. Green	Director	January 28, 2016
/S/    DR. ROBERT V. ANTONUCCI         Dr. Robert V. Antonucci	Director	January 28, 2016
/S/    LISA CRUTCHFIELD         Lisa Crutchfield	Director	January 28, 2016
/S/    DAVID A. WHITELEY           David A. Whiteley	Director	January 28, 2016

94

EXHIBIT INDEX

Exhibit Number		Description of Exhibit	Reference*
	2.1	Stock Purchase Agreement among Nisource Inc., Bay State Gas Company and Unitil Corporation.	Exhibit 2.1 to Form 8-K dated February 15, 2008 (SEC File No. 1-8858)
	3.1	Articles of Incorporation of Unitil Corporation.	Exhibit 3.1 to Form S-14 Registration Statement No. 2-93769 dated October 12, 1984
	3.2	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on March 4, 1992.	Exhibit 3.2 to Form 10-K for 1991 (SEC File No. 1-8858)
	3.3	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on September 23, 2008.	Exhibit 3.3 to Form S-3/A Registration Statement No. 333-152823 dated November 25, 2008
	3.4	Articles of Amendment to the Articles of Incorporation Filed with the Secretary of State of the State of New Hampshire on April 27, 2011.	Exhibit 4.4 to Post-Effective Amendment No. 1 to Form S-3 Registration Statement No. 333-168394, dated January 28, 2014
	3.5	Third Amended and Restated By-Laws of Unitil Corporation.	Exhibit 3.1 to Form 8-K dated December 12, 2013 (SEC File No. 1-8858)
	4.1	Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958.	Exhibit 4.1 to Form 10-K for 2002 (SEC File No. 1-8858)
	4.2	Fitchburg Note Agreement dated November 30, 1993 for the 6.75% Notes due November 23, 2023.	Exhibit 4.18 to Form 10-K for 1993 (SEC File No. 1-8858)
	4.3	Fitchburg Note Agreement dated January 26, 1999 for the 7.37% Notes due January 15, 2029.	Exhibit 4.25 to Form 10-K for 1999 (SEC File No. 1-8858)
	4.4	Fitchburg Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031.	Exhibit 4.6 to Form 10-Q for June 30, 2001 (SEC File No. 1-8858)
	4.5	Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for the 8.00% Senior Secured Notes due August 1, 2017.	Exhibit 4.22 to Form 10-K for 1997 (SEC File No. 1-8858)
	4.6	Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025.	Exhibit 4.7 to Form 10-K for 2003 (SEC File No. 1-8858)
	4.7	Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030.	**
	4.8	Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006.	**

95

Exhibit Number		Description of Exhibit	Reference*
	4.9	Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022.	**
	4.10	Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December 3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038.	Exhibit 4.1 to Form 8-K dated December 3, 2008 (SEC File No. 1-8858)
	4.11	Granite State Note Purchase Agreement, dated as of December 15, 2008, for the 7.15% Senior Notes due December 15, 2018.	Exhibit 99.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
	4.12	Northern Utilities Note Purchase Agreement, dated as of March 2, 2010, for the 5.29% Senior Notes, due March 2, 2020.	Exhibit 4.1 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
	4.13	Fourteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of March 2, 2010.	Exhibit 4.4 to Form 8-K dated March 2, 2010 (SEC File No. 1-8858)
	4.14	Northern Utilities form of Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.1 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
	4.15	Northern Utilities form of Note issued pursuant to the Note Purchase Agreement, dated as of October 15, 2014, for the 4.42% Senior Notes, due October 15, 2044.	Exhibit 4.2 to Form 8-K dated October 15, 2014 (SEC File No. 1-8858)
	10.1	Unitil System Agreement dated June 19, 1986 providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.	Exhibit 10.9 to Form 10-K for 1986 (SEC File No. 1-8858)
	10.2	Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.	Exhibit 10.8 to Form 10-K for 1987 (SEC File No. 1-8858)
	10.3	Transmission Agreement between Unitil Power Corp. and Public Service Company of New Hampshire, effective November 11, 1992.	Exhibit 10.6 to Form 10-K for 1993 (SEC File No. 1-8858)
	10.4***	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.2 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.5***	Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.3 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.6***	Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2007.	Exhibit 10.4 to Form 8-K dated June 19, 2008 (SEC File No. 1-8858)
	10.7***	Unitil Corporation Management Incentive Plan (amended and restated as of June 5, 2013).	Exhibit 10.2 to Form 8-K dated June 5, 2013 (SEC File No. 1-8858)
	10.8	Entitlement Sale and Administrative Services Agreement with Select Energy.	Exhibit 10.14 to Form 10-K for 1999 (SEC File No. 1-8858)
	10.9***	Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 10.1 to Form 8-K dated April 19, 2012 (SEC File No. 1-8858)

96

Exhibit Number		Description of Exhibit	Reference*
	10.10***	Form of Restricted Stock Unit Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 4.7 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
	10.11***	Form of Restricted Stock Agreement under the Unitil Corporation Second Amended and Restated 2003 Stock Plan	Exhibit 4.8 to Form S-8 Registration Statement No. 333-184849 dated November 9, 2012
	10.12***	Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement.	Exhibit 10.1 to Form 10-Q for September 30, 2004 (SEC File No. 1-8858)
	10.13***	Unitil Corporation Tax Deferred Savings and Investment Plan, as amended to date	Exhibit 10.13 to Form 10-K for 2013 (SEC File No. 1-8858)
	10.14***	Employment Agreement effective November 1, 2015 between Unitil Corporation and Robert G. Schoenberger	Exhibit 10.1 to Form 8-K dated October 21, 2015 (SEC File No. 1-8858)
	10.15	Amended and Restated Credit Agreement dated as of October 4, 2013 by and among Unitil Corporation and Bank of America, N.A.	Exhibit 10.1 to Form 8-K dated October 4, 2013 (SEC File No. 1-8858)
	10.16	First Amendment to Amended and Restated Credit Agreement dated as of July 24, 2015 by and among Unitil Corporation, Bank of America, N.A., and the other parties thereto.	Exhibit 10.1 to Form 8-K dated July 24, 2015 (SEC File No. 1-8858)
	10.17	Parent Guaranty of Unitil Corporation for the Granite State 7.15% Senior Notes due December 15, 2018.	Exhibit 10.1 to Form 8-K dated December 15, 2008 (SEC File No. 1-8858)
	10.18***	Unitil Corporation—Compensation of Directors.	Exhibit 10.18 to Form 10-K for 2014 (SEC File No. 1-8858)
	10.19***	Unitil Corporation Incentive Plan (amended and restated as of January 26, 2015)	Exhibit 10.1 to Form 10-Q for March 31, 2015 (SEC File No. 1-8858)
	11.1	Statement Re: Computation in Support of Earnings per Share for the Company.	Filed herewith
	12.1	Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company.	Filed herewith
	21.1	Statement Re: Subsidiaries of Registrant.	Filed herewith
	23.1	Consent of Independent Registered Public Accounting Firm.	Filed herewith
	23.2	Consent of Independent Registered Public Accounting Firm.	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

97

Exhibit Number		Description of Exhibit	Reference*
	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 January 28, 2016 Announcing Earnings For the Quarter and Year Ended December 31, 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

* The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

** In accordance with Item 601(b)(4)(iii)(A) of Federal Securities Regulation S-K, the instrument defining the debt of the Registrant and its subsidiary, described above, has been omitted but will be furnished to the Commission upon request.

*** These exhibits represent a management contract or compensatory plan.

98

EX-11.1

Exhibit 11.1

UNITIL CORPORATION

COMPUTATION IN SUPPORT OF EARNINGS PER SHARE

	Year Ended December 31,
	2015		2014		2013
EARNINGS PER SHARE (000’s, except per share data)
Net Income	$	26,264	$	24,758	$	21,629
Less: Dividend Requirements on Preferred Stock		12		14		14
Net Income Applicable to Common Stock	$	26,252	$	24,744	$	21,615
Average Number of Common Shares Outstanding—Basic		13,917		13,843		13,773
Dilutive Effect of Stock Options and Restricted Stock		3		4		2
Average Number of Common Shares Outstanding—Diluted		13,920		13,847		13,775
Earnings Per Share—Basic	$	1.89	$	1.79	$	1.57
Earnings Per Share—Diluted	$	1.89	$	1.79	$	1.57

EX-12.1

Exhibit 12.1

UNITIL CORPORATION

COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31,
	2015		2014		2013		2012		2011
(000’s, except ratios)
Earnings:
Net Income, per Consolidated Statement of Earnings	$	26,264	$	24,758	$	21,629	$	18,196	$	16,439
Federal and State Income Taxes included in Operations		15,456		13,995		12,652		10,976		10,025
Interest on Long-Term Debt		21,692		20,301		19,907		19,948		19,987
Amortization of Debt Discount Expense		299		286		302		324		340
Other Interest		1,763		1,661		1,737		2,003		1,760
Total	$	65,474	$	61,001	$	56,227	$	51,447	$	48,551
Fixed Charges:
Interest of Long-Term Debt	$	21,692	$	20,301	$	19,907	$	19,948	$	19,987
Amortization of Debt Discount Expense		299		286		302		324		340
Other Interest		1,763		1,661		1,737		2,003		1,760
Pre-tax Preferred Stock Dividend Requirements		19		22		22		165		211
Total	$	23,773	$	22,270	$	21,968	$	22,440	$	22,298
Ratio of Earnings to Fixed Charges		2.75		2.74		2.56		2.29		2.18

EX-21.1

Exhibit 21.1

Subsidiaries of Registrant

The Company or the registrant has eight wholly-owned subsidiaries, seven of which are corporations organized under the laws of the State of New Hampshire: Unitil Energy Systems, Inc., Northern Utilities, Inc., Granite State Gas Transmission, Inc., Unitil Power Corp., Unitil Realty Corp., Unitil Resources, Inc. and Unitil Service Corp. The eighth, Fitchburg Gas and Electric Light Company, is organized under the laws of the State of Massachusetts. Usource, Inc., which is a corporation organized under the laws of the State of Delaware, is a wholly-owned subsidiary of Unitil Resources, Inc. Usource, Inc. is the sole member of Usource L.L.C., which is a corporation organized under the laws of the State of Delaware.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements Nos. 333-180316 and 333-168394 on Form S-3 and Nos. 333-184849 and 333-42266 on Form S-8 of our report dated January 28, 2016, relating to the consolidated financial statements of Unitil Corporation and subsidiaries and the effectiveness of Unitil Corporation’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Unitil Corporation and subsidiaries for the year ended December 31, 2015.

/s/ Deloitte & Touche LLP

January 28, 2016

Boston, Massachusetts

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statements on Form S-3 (File Nos. 333-180316 and 333-168394) and Form S-8 (File Nos. 333-184849 and 333-42266) of Unitil Corporation and subsidiaries of our report dated January 29, 2014, relating to our audit of the consolidated statements of earnings, cash flows and changes in common stock equity for the year ended December 31, 2013, included in this Annual Report on Form 10-K of Unitil Corporation and Subsidiaries for the year ended December 31, 2015.

/s/ RSM US LLP

Boston, Massachusetts

January 28, 2016

EX-31.1

Exhibit 31.1

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert G. Schoenberger, certify that:

1) I have reviewed this annual report on Form 10-K of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 28, 2016

/s/ Robert G. Schoenberger

Robert G. Schoenberger

Chief Executive Officer and President

EX-31.2

Exhibit 31.2

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark H. Collin, certify that:

1) I have reviewed this annual report on Form 10-K of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 28, 2016

/s/ Mark H. Collin

Mark H. Collin

Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Laurence M. Brock, certify that:

1) I have reviewed this annual report on Form 10-K of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 28, 2016

/s/ Laurence M. Brock

Laurence M. Brock

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Unitil Corporation (the “Company”) on Form 10-K for the year ending December 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned Robert G. Schoenberger, Chief Executive Officer and President, Mark H. Collin, Chief Financial Officer and Laurence M. Brock, Chief Accounting Officer, certifies, to the best knowledge and belief of the signatory, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Signature	Capacity	Date
/s/ Robert G. Schoenberger Robert G. Schoenberger	Chief Executive Officer and President	January 28, 2016
/s/ Mark H. Collin Mark H. Collin	Chief Financial Officer	January 28, 2016
/s/ Laurence M. Brock Laurence M. Brock	Chief Accounting Officer	January 28, 2016

EX-99.1

Page 1 of 3

FOR RELEASE

Exhibit 99.1

UNITIL REPORTS YEAR-END EARNINGS

HAMPTON, N.H., JANUARY 28, 2016—Unitil Corporation (NYSE: UTL) (www.unitil.com) today announced Net Income of $26.3 million, or $1.89 per share, for the year ended December 31, 2015, an increase of $1.6 million, or $0.10 per share, compared to 2014. The Company’s earnings for the twelve months ended December 31, 2015 were driven by increases in natural gas and electric sales margins partially offset by higher utility operating expenses. Net Income for the three months ended December 31, 2015 was $9.3 million, or $0.67 per share, compared to Net Income of $9.4 million, or $0.69 per share, for the same period in 2014.

“We had another solid year in 2015 as earnings increased by 6%,” said Robert G. Schoenberger, Unitil’s Chairman and Chief Executive Officer. “We continue to experience strong growth in our gas and electric businesses. Reflecting confidence in our business plan, on January 27, 2016 the Company’s Board of Directors raised the quarterly dividend to $0.3550 per share, increasing the annual dividend from $1.40 to $1.42 per share.”

Natural gas sales margins were $28.8 million and $101.9 million in the three and twelve months ended December 31, 2015, respectively, resulting in a decrease of $0.6 million and an increase of $4.5 million, respectively, compared to the same periods in 2014. The decrease in natural gas sales margin in the three month period reflects lower therm sales of natural gas driven by warmer winter weather in the fourth quarter of 2015 compared to 2014. For the twelve month period, natural gas sales margin was positively affected by higher therm unit sales in 2015, a growing customer base and higher distribution rates compared to 2014. Therm sales of natural gas increased 1.5% in the twelve months ended December 31, 2015 compared to 2014. The impact of growth in the number of customers year over year was partially offset by warmer weather in 2015 compared to the prior year. For the full year, based on weather data collected in the Company’s service areas, there were 2.3% fewer Heating Degree Days in 2015. Estimated weather-normalized gas therm sales, excluding decoupled sales, were up four percent in 2015, led by a year over year increase of eight percent in gas therm sales to large Commercial and Industrial (C&I) customers.

Electric sales margins were $21.6 million and $85.5 million in the three and twelve months ended December 31, 2015, respectively, resulting in increases of $1.5 million and $4.7 million, respectively, compared to the same periods in 2014. The increase in electric sales margin for the twelve month period primarily reflects higher electric distribution rates. Electric kilowatt-hour (kWh) sales decreased 0.7% in 2015 compared to 2014, reflecting a decrease in average use per customer for Residential customers, partially offset by an increase in electric sales to C&I customers.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $6.2 million in 2015, an increase of $0.5 million compared to 2014.

Operation and Maintenance (O&M) expenses increased $1.8 million and $2.5 million in the three and twelve months ended December 31, 2015, respectively, compared to the same periods in 2014. The increase in O&M expenses primarily reflects higher compensation and benefit costs.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 2 of 3

Depreciation, Amortization, Property Taxes and other expenses increased $0.2 million and $3.2 million in the three and twelve months ended December 31, 2015, respectively, compared to the same periods in 2014, reflecting higher utility plant assets in service, amortization of storm restoration costs and property taxes, partially offset by the recognition of a pre-tax gain of $0.9 million in the fourth quarter of 2015 on the sale of property.

Interest Expense, net decreased $0.8 million and increased $1.0 million in the three and twelve months ended December 31, 2015, respectively, compared to the same periods in 2014. The decrease in the three month period reflects higher interest income on regulatory assets. The increase in the twelve month period reflects higher levels of long-term debt and higher interest expense on regulatory liabilities.

Income Taxes increased $1.4 million in 2015 compared to 2014 reflecting higher pre-tax earnings in 2015.

At its January 2016 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.3550 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.42 from $1.40. This dividend declaration continues an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

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

The Company will hold a quarterly conference call to discuss fourth quarter and full year 2015 results on Thursday, January 28, 2016, at 2:00 p.m. Eastern Time. This call is being webcast and can be accessed in the Investor Relations section of Unitil’s website, www.unitil.com.

About Unitil Corporation

Unitil Corporation provides energy for life by safely and reliably delivering natural gas and electricity in New England. We are committed to the communities we serve and to developing people, business practices, and technologies that lead to the delivery of dependable, more efficient energy. Unitil Corporation is a public utility holding company with operations in Maine, New Hampshire and Massachusetts. Together, Unitil’s operating utilities serve approximately 103,300 electric customers and 78,700 natural gas customers. Other subsidiaries include Usource, Unitil’s non-regulated business segment. For more information about our people, technologies, and community involvement please visit www.unitil.com.

Forward-Looking Statements

This press release may contain forward-looking statements. All statements, other than statements of historical fact, included in this press release are forward-looking statements. Forward-looking statements include declarations regarding Unitil’s beliefs and current expectations. These forward-looking statements are subject to the 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 the following: Unitil’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters); fluctuations in the supply of, the demand for, and the prices of, gas and electric energy commodities and transmission and transportation capacity and Unitil’s ability to recover energy supply costs in its rates; customers’ preferred energy sources; severe storms and Unitil’s ability to recover storm costs in its rates; general economic conditions; variations in weather; long-term global climate change; Unitil’s ability to retain its existing customers and attract new customers; increased competition; and other risks detailed in Unitil’s filings with the Securities and Exchange Commission. These forward looking statements speak only as of the date they are made. Unitil undertakes no obligation, and does not intend, to update these forward-looking statements.

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

Page 3 of 3

For more information please contact:

David Chong—Investor Relations	Alec O’Meara—Media Relations
Phone: 603-773-6499	Phone: 603-773-6404
Email: chong@unitil.com	Email: omeara@unitil.com

Selected financial data for 2015 and 2014 is presented in the following table:

Unitil Corporation—Condensed Consolidated Financial Data
(Millions, except Per Share data) (Unaudited)
	Three Months Ended December 31,							Twelve Months Ended December 31,
	2015		2014		Change			2015		2014		Change
Gas Therm Sales:
Residential		8.9		10.2		(12.7	%)		45.2		44.7		1.1	%
Commercial/Industrial		40.6		42.6		(4.7	%)		174.2		171.5		1.6	%
Total Gas Therm Sales		49.5		52.8		(6.3	%)		219.4		216.2		1.5	%
Electric kWh Sales:
Residential		143.0		155.1		(7.8	%)		671.4		687.6		(2.4	%)
Commercial/Industrial		231.3		237.1		(2.4	%)		996.3		991.4		0.5	%
Total Electric kWh Sales		374.3		392.2		(4.6	%)		1,667.7		1,679.0		(0.7	%)
Gas Revenues	$	53.0	$	62.1	$	(9.1	)	$	202.6	$	201.4	$	1.2
Cost of Gas Sales		24.2		32.7		(8.5	)		100.7		104.0		(3.3	)
Gas Sales Margin		28.8		29.4		(0.6	)		101.9		97.4		4.5
Electric Revenues		47.9		56.5		(8.6	)		218.0		218.7		(0.7	)
Cost of Electric Sales		26.3		36.4		(10.1	)		132.5		137.9		(5.4	)
Electric Sales Margin		21.6		20.1		1.5			85.5		80.8		4.7
Usource Revenues		1.5		1.2		0.3			6.2		5.7		0.5
Total Sales Margin:		51.9		50.7		1.2			193.6		183.9		9.7
Operation & Maintenance Expenses		17.1		15.3		1.8			67.1		64.6		2.5
Depreciation, Amortization, Property Taxes & Other		15.6		15.4		0.2			62.9		59.7		3.2
Interest Expense, net		4.6		5.4		(0.8	)		21.9		20.9		1.0
Income Before Income Taxes		14.6		14.6		—			41.7		38.7		3.0
Income Tax Expense		5.3		5.2		0.1			15.4		14.0		1.4
Net Income	$	9.3	$	9.4	$	(0.1	)	$	26.3	$	24.7	$	1.6
Earnings Per Share	$	0.67	$	0.69	$	(0.02	)	$	1.89	$	1.79	$	0.10

6 Liberty Lane West

Hampton, NH 03842

T 603.772.0775

www.unitil.com

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Jan. 25, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		13,992,817
Entity Public Float			$ 452,207,259

XML

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues:
Gas	$ 202,600	$ 201,400	$ 170,400
Electric	218,000	218,700	190,700
Other	6,200	5,700	5,800
Total Operating Revenues	426,800	425,800	366,900
Operating Expenses:
Cost of Gas Sales	100,700	104,000	85,200
Cost of Electric Sales	132,500	137,900	114,500
Operation and Maintenance	67,100	64,600	60,200
Depreciation and Amortization	45,700	42,100	38,500
Taxes Other Than Income Taxes	17,700	17,200	15,000
Total Operating Expenses	363,700	365,800	313,400
Operating Income	63,100	60,000	53,500
Interest Expense, net	21,900	20,900	18,800
Other (Income) Expense, net	(500)	400	400
Income Before Income Taxes	41,700	38,700	34,300
Income Taxes	15,443	13,995	12,652
Net Income Applicable to Common Shares	$ 26,300	$ 24,700	$ 21,600
Earnings per Common Share-Basic and Diluted	$ 1.89	$ 1.79	$ 1.57
Weighted Average Common Shares Outstanding-(Basic and Diluted)	13.9	13.8	13.8

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current Assets:
Cash and Cash Equivalents	$ 8,700	$ 8,400
Accounts Receivable, net	49,800	60,700
Accrued Revenue	38,400	48,500
Exchange Gas Receivable	11,100	15,000
Gas Inventory	800	1,100
Deferred Income Taxes	4,700
Prepayments and Other	12,400	11,500
Total Current Assets	125,900	145,200
Utility Plant:
Gas	576,800	522,900
Electric	408,400	390,600
Common	35,500	32,700
Construction Work in Progress	59,900	42,600
Utility Plant	1,080,600	988,800
Less: Accumulated Depreciation	271,700	255,100
Net Utility Plant	808,900	733,700
Other Noncurrent Assets:
Regulatory Assets	99,600	107,600
Other Assets	12,000	13,700
Total Other Noncurrent Assets	111,600	121,300
TOTAL ASSETS	1,046,400	1,000,200
Current Liabilities:
Accounts Payable	33,300	44,200
Short-Term Debt	42,000	29,300
Long-Term Debt, Current Portion	17,400	4,000
Regulatory Liabilities	15,600	8,700
Energy Supply Obligations	14,600	22,100
Environmental Obligations	1,300	3,500
Capital Lease Obligations	3,100	500
Deferred Income Taxes		3,100
Taxes Payable	2,400	100
Other Current Liabilities	14,900	13,900
Total Current Liabilities	144,600	129,400
Noncurrent Liabilities:
Deferred Income Taxes	92,208	72,870
Cost of Removal Obligations	70,100	63,800
Retirement Benefit Obligations	124,400	118,600
Regulatory Liabilities	8,100	100
Capital Lease Obligations	11,000	7,500
Environmental Obligations	1,500	2,000
Other Noncurrent Liabilities	3,600	3,700
Total Noncurrent Liabilities	310,900	268,600
Capitalization:
Long-Term Debt, Less Current Portion	308,100	328,900
Stockholders' Equity:
Common Equity (Outstanding 13,991,430 and 13,916,026 Shares)	237,500	234,700
Retained earnings	45,100	38,400
Total Common Stock Equity	282,600	273,100
Preferred Stock	200	200
Total Stockholders' Equity	282,800	273,300
Total Capitalization	$ 590,900	$ 602,200
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,046,400	$ 1,000,200

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014
Common Equity Outstanding	13,991,430	13,916,026

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Activities:
Net Income	$ 26.3	$ 24.7	$ 21.6
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	45.7	42.1	38.5
Deferred Taxes Provision	11.9	14.4	12.3
Changes in Working Capital Items:
Accounts Receivable	10.9	(8.5)	(4.5)
Accrued Revenue	10.1	8.1	6.8
Regulatory Liabilities	6.9	(1.0)	2.9
Taxes Refundable / Payable	2.3	(0.1)	(0.5)
Exchange Gas Receivable	3.9	(4.2)	(1.4)
Accounts Payable	(10.9)	6.1	5.4
Other Changes in Working Capital Items	(5.4)	6.6	(2.9)
Deferred Regulatory and Other Charges	9.2	(1.6)	15.0
Other, net	4.2	(2.6)	3.1
Cash Provided by Operating Activities	115.1	84.0	96.3
Investing Activities:
Property, Plant and Equipment Additions	(103.9)	(92.6)	(89.5)
Cash Used In Investing Activities	(103.9)	(92.6)	(89.5)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	12.7	(30.9)	10.8
Issuance of Long-Term Debt		50.0
Repayment of Long-Term Debt	(7.4)	(4.4)	(0.5)
Increase / (Decrease) in Capital Lease Obligations	6.1	6.5	(0.7)
Net (Decrease) Increase in Exchange Gas Financing	(4.0)	4.4	1.2
Dividends Paid	(19.6)	(19.2)	(19.1)
Proceeds from Issuance of Common Stock	1.3	1.2	1.1
Cash (Used In) Provided by Financing Activities	(10.9)	7.6	(7.2)
Net Increase (Decrease) in Cash	0.3	(1.0)	(0.4)
Cash at Beginning of Year	8.4	9.4	9.8
Cash at End of Year	8.7	8.4	9.4
Supplemental Information:
Interest Paid	22.3	20.8	20.8
Income Taxes Paid	1.8	1.2	0.8
Payments on Capital Leases	1.1	0.6	0.7
Capital Expenditures Included in Accounts Payable	$ 0.4	$ 0.3	$ 0.7

XML

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2012	$ 260.4	$ 230.0	$ 30.4
Net Income	21.6		21.6
Dividends	(19.1)		(19.1)
Shares Issued Under Stock Plans	1.0	1.0
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2013	265.0	232.1	32.9
Net Income	24.7		24.7
Dividends	(19.2)		(19.2)
Shares Issued Under Stock Plans	1.4	1.4
Issuance of Common Shares	1.2	1.2
Ending Balance at Dec. 31, 2014	273.1	234.7	38.4
Net Income	26.3		26.3
Dividends	(19.6)		(19.6)
Shares Issued Under Stock Plans	1.5	1.5
Issuance of Common Shares	1.3	1.3
Ending Balance at Dec. 31, 2015	$ 282.6	$ 237.5	$ 45.1

XML

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividends per Common Share	$ 1.40	$ 1.38	$ 1.38
Common stock, shares issued	36,265	38,020	39,559

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Summary of Significant Accounting Policies

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 wholly-owned 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 capital city areas 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 Maine to the Lewiston-Auburn area 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 an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine, New Hampshire and Massachusetts. 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 a national client base of large commercial and industrial customers.

Basis of Presentation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation.

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

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.

Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates.

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

Revenue Recognition—Non-regulated Operations—Usource, Unitil’s competitive energy brokering subsidiary, records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2015 – 3.57%, 2014 – 3.56% and 2013 – 3.59%.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes—The Company bills its customers 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 Consolidated Statements of Earnings.

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

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

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2015 the Company paid quarterly dividends of $0.350 per share, resulting in an annual dividend rate of $1.40 per common share. For the years ended December 31, 2014 and 2013, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend rate of $1.38 per common share. At its January 2016 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.3550 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.42 per share from $1.40 per share.

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2015 and 2014, the Unitil subsidiaries had deposited $2.3 million and $6.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2015 and 2014.

Allowance for Doubtful Accounts—The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric 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. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2015 and 2014.

Accrued Revenue (millions)	December 31,
	2015		2014
Regulatory Assets—Current	$	26.8	$	37.8
Unbilled Revenues		11.6		10.7
Total Accrued Revenue	$	38.4	$	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 December 31, 2015 and 2014.

Exchange Gas Receivable (millions)	December 31,
	2015		2014
Northern Utilities	$	10.3	$	14.2
Fitchburg		0.8		0.8
Total Exchange Gas Receivable	$	11.1	$	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 December 31, 2015 and 2014.

Gas Inventory (millions)	December 31,
	2015		2014
Natural Gas	$	0.3	$	0.8
Propane		0.3		0.2
Liquefied Natural Gas & Other		0.2		0.1
Total Gas Inventory	$	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 average interest rates applied to AFUDC were 2.32%, 1.56% and 1.92% in 2015, 2014 and 2013, respectively. 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 December 31, 2015 and 2014, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $70.1 million and $63.8 million, respectively.

Regulatory Accounting—The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the 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.

Regulatory Assets consist of the following (millions)	December 31,
	2015		2014
Retirement Benefits	$	64.7	$	65.1
Energy Supply & Other Regulatory Tracker Mechanisms		21.3		31.0
Deferred Storm Charges		15.4		21.2
Environmental		11.2		11.0
Income Taxes		8.5		9.7
Deferred Restructuring Costs		—		1.6
Other		5.3		5.8
Total Regulatory Assets	$	126.4	$	145.4
Less: Current Portion of Regulatory Assets(1)		26.8		37.8
Regulatory Assets—noncurrent	$	99.6	$	107.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions)	December 31,
	2015		2014
Regulatory Tracker Mechanisms	$	8.0	$	8.8
Gas Pipeline Refund (Note 8)		15.7		—
Total Regulatory Liabilities		23.7		8.8
Less: Current Portion of Regulatory Liabilities		15.6		8.7
Regulatory Liabilities—noncurrent	$	8.1	$	0.1

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2015 are $6.6 million of deferred storm charges to be recovered over the next two and a half years and $7.4 million of rate case costs and other expenditures to be recovered over the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

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

The Company has 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 December 31, 2015, all futures contracts purchased under the prior program design have been 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 customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of December 31, 2015 and December 31, 2014, the Company had 2.5 billion and 2.4 billion cubic feet (BCF), respectively, outstanding in natural gas purchase 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 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 Consolidated Balance Sheets.

Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of:

		Fair Value
Description	Balance Sheet Location	December 31, 2015		December 31, 2014
Derivative Assets
Natural Gas Futures / Options Contracts	Prepayments and Other	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Assets		—		0.1
Total Derivative Assets		$	—	$	0.1
Derivative Liabilities
Natural Gas Futures / Options Contracts	Other Current Liabilities	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	—

	Twelve Months Ended December 31,
	2015		2014
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	0.3	$	(0.7	)
Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.2	$	(0.8	)

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

Investments in Marketable Securities—In 2015, the Company established a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 10).

At December 31, 2015 and 2014, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Prepayments and Other, are $0.7 million and $0, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Fair Value of Marketable Securities (millions)	December 31,
	2015		2014
Equity Funds	$	0.4	$	—
Fixed Income Funds		0.3		—
Total Marketable Securities	$	0.7	$	—

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2015, the unamortized balance of the bargain purchase adjustment was $7.2 million, to be amortized over the next three years.

Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.

	December 31,
Energy Supply Obligations consist of the following: (millions)	2015		2014
Current:
Exchange Gas Obligation	$	10.3	$	14.2
Renewable Energy Portfolio Standards		4.0		7.4
Power Supply Contract Divestitures		0.3		0.5
Total Energy Supply Obligations—Current	$	14.6	$	22.1
Noncurrent:
Power Supply Contract Divestitures	$	1.6	$	1.9
Total Energy Supply Obligations	$	16.2	$	24.0

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

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

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

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

Massachusetts Green Communities Act—In compliance with the Massachusetts Green Communities Act, discussed below in Note 8, Commitments and Contingencies, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The generating facility associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements—As of December 31, 2015, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2015, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2015, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements—In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2017 and interim periods within those annual periods with earlier application permitted as of the beginning of the fiscal year of adoption. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In November 2015, the FASB issued ASU 2015-17 which simplifies the presentation of deferred income taxes in a classified statement of financial position. Current generally accepted accounting principles (GAAP) require an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. ASU 2015-17 amends current GAAP to require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods with earlier application permitted as of the beginning of an interim or annual reporting period. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In August 2015, the FASB issued ASU 2015-13 which clarifies the Normal Purchases and Normal Sales scope exception to certain electricity contracts. ASU 2015-13 specifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract. This pronouncement is effective upon its issuance. The Company has adopted this new guidance and it had no impact on the Company’s Consolidated Financial Statements.

In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In July 2015, the FASB issued ASU 2015-11 which provides authoritative guidance requiring inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. This pronouncement is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In May 2015, the FASB issued ASU 2015-07 which provides authoritative guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all periods presented. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In April 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. ASU 2015-03 does not contain guidance for debt issuance costs related to line-of-credit arrangements. Consequently, in August 2015, the FASB issued ASU 2015-15 to add paragraphs indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The effective date of these pronouncements is for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

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

Subsequent Events—The Company evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that impacted its Consolidated Financial Statements.

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Quarterly Financial Information

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information

Note 2: Quarterly Financial Information (unaudited; millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented.

	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2015		2014		2015		2014		2015		2014		2015		2014
Total Operating Revenues	$	172.2	$	156.1	$	77.5	$	73.3	$	74.7	$	76.6	$	102.4	$	119.8
Operating Income	$	28.4	$	25.4	$	8.9	$	7.1	$	7.3	$	7.4	$	18.5	$	20.1
Net Income (Loss) Applicable to Common	$	13.6	$	12.6	$	1.7	$	1.1	$	1.7	$	1.6	$	9.3	$	9.4
	Per Share Data:
Earnings Per Common Share	$	0.98	$	0.91	$	0.12	$	0.08	$	0.12	$	0.11	$	0.67	$	0.69
Dividends Paid Per Common Share	$	0.350	$	0.345	$	0.350	$	0.345	$	0.350	$	0.345	$	0.350	$	0.345

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Segment Information

12 Months Ended

Dec. 31, 2015

Segment Information

Note 3: Segment Information

Unitil reports three segments: utility gas operations, utility electric operations and non-regulated. 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 Maine to the Lewiston-Auburn area 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.

Granite State is 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 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 transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers.

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 a national client base of large commercial and industrial customers. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated column below.

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the FERC, NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

The following table provides significant segment financial data for the years ended December 31, 2015, 2014 and 2013 (millions):

Year Ended December 31, 2015	Gas		Electric		Non- Regulated		Other			Total
Revenues	$	202.6	$	218.0	$	6.2	$	—		$	426.8
Interest Income		0.8		0.7		0.1		0.3			1.9
Interest Expense		13.3		8.8		—		1.7			23.8
Depreciation & Amortization Expense		20.7		24.0		0.1		0.9			45.7
Income Tax Expense (Benefit)		10.2		5.5		0.8		(1.1	)		15.4
Segment Profit		15.3		8.7		1.3		1.0			26.3
Segment Assets		596.7		416.8		6.6		26.3			1,046.4
Capital Expenditures		64.9		29.9		0.1		9.0			103.9
Year Ended December 31, 2014
Revenues	$	201.4	$	218.7	$	5.7	$	—		$	425.8
Interest Income		0.3		0.6		0.1		0.3			1.3
Interest Expense		11.5		9.1		—		1.6			22.2
Depreciation & Amortization Expense		18.8		22.3		—		1.0			42.1
Income Tax Expense (Benefit)		10.8		4.5		0.6		(1.9	)		14.0
Segment Profit		15.8		6.8		0.9		1.2			24.7
Segment Assets		566.3		414.1		6.3		13.5			1,000.2
Capital Expenditures		62.3		24.8		0.3		5.2			92.6
Year Ended December 31, 2013
Revenues	$	170.4	$	190.7	$	5.8	$	—		$	366.9
Interest Income		0.5		2.2		0.1		0.4			3.2
Interest Expense		11.0		9.5		—		1.5			22.0
Depreciation & Amortization Expense		17.2		20.3		—		1.0			38.5
Income Tax Expense (Benefit)		7.5		5.1		0.8		(0.7	)		12.7
Segment Profit		12.5		7.6		1.2		0.3			21.6
Segment Assets		502.3		402.8		6.2		9.3			920.6
Capital Expenditures		61.1		23.6		—		4.8			89.5

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Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2015

Allowance for Doubtful Accounts

Note 4: Allowance for Doubtful Accounts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2015, 2014 and 2013, the Company recorded provisions for the energy commodity portion of bad debts of $2.6 million, $2.6 million and $1.4 million, respectively. These provisions were recognized in Cost of Gas Sales and Cost of Electric Sales expense as the associated electric and gas utility revenues were billed. Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling 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.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2013—2015 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2015
Electric	$	1.3	$	2.5	$	0.3	$	3.5	$	0.6
Gas		0.4		2.8		0.4		3.1		0.5
Other		0.1		—		—		—		0.1
	$	1.8	$	5.3	$	0.7	$	6.6	$	1.2
Year Ended December 31, 2014
Electric	$	1.3	$	2.9	$	0.3	$	3.2	$	1.3
Gas		0.2		3.1		0.3		3.2		0.4
Other		0.1		—		—		—		0.1
	$	1.6	$	6.0	$	0.6	$	6.4	$	1.8
Year Ended December 31, 2013
Electric	$	1.1	$	2.6	$	0.2	$	2.6	$	1.3
Gas		0.7		2.0		0.2		2.7		0.2
Other		0.1		—		—		—		0.1
	$	1.9	$	4.6	$	0.4	$	5.3	$	1.6

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Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2015

Debt and Financing Arrangements

Note 5: Debt and Financing Arrangements

The Company funds a portion of its operations through the issuance of long-term debt and through short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow:

Long-Term Debt and Interest Expense

Long-Term Debt Structure and Covenants—The agreements under which the long-term debt of Unitil and its utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations, as described below.

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of Unitil Energy and Fitchburg or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met; including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets. The Granite State notes are guaranteed by Unitil for the payment of principal, interest and other amounts payable. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.

Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2015, in accordance with the covenants, these subsidiary companies had a combined amount of $163.1 million available for the payment of dividends and Unitil Corporation had $194.6 million available for the payment of dividends. As of December 31, 2015, the Company’s balance in Retained Earnings was $45.1 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2015 for the payment of dividends.

Issuance of 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.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $7.4 million, $4.4 million, and $0.5 million in 2015, 2014, and 2013, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2015 is: 2016 – $17.4 million; 2017 – $17.2 million; 2018 – $30.1 million; 2019 – $18.8 million; 2020 – $19.8 million and thereafter $222.2 million.

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.

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2015		2014
Estimated Fair Value of Long-Term Debt	$	345.2	$	380.6

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

Long-Term Debt (millions)	December 31,
	2015		2014
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		12.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0
Fitchburg Long-Term Notes:
6.75% Notes, Due November 30, 2023		11.4		15.2
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		1.1		1.7
Total Long-Term Debt		325.5		332.9
Less: Current Portion		17.4		4.0
Total Long-Term Debt, Less Current Portion	$	308.1	$	328.9

Interest Expense, net—Interest expense is presented in the 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 monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2015			2014			2013
Interest Expense
Long-Term Debt	$	22.0		$	20.5		$	20.2
Short-Term Debt		0.9			1.1			1.2
Regulatory Liabilities		0.9			0.6			0.6
Subtotal Interest Expense		23.8			22.2			22.0
Interest Income
Regulatory Assets		(0.7	)		(0.6	)		(2.3	)
AFUDC(1) and Other		(1.2	)		(0.7	)		(0.9	)
Subtotal Interest Income		(1.9	)		(1.3	)		(3.2	)
Total Interest Expense, net	$	21.9		$	20.9		$	18.8

⁽¹⁾  AFUDC—Allowance for Funds Used During Construction

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 new 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.

On July 24, 2015, the Company entered into the First Amendment to the Credit Facility. The First Amendment provides for an extension of the scheduled termination date to October 4, 2020, reduces the daily fluctuating rate of interest per annum equal to one-month LIBOR plus 1.25%, and reduces other customary credit facility fees. All other terms and conditions of the Credit Facility, including affirmative and negative covenants, remain substantially unchanged.

The Company utilizes the credit facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $140.3 million and $179.4 million for the years ended December 31, 2015 and December 31, 2014, respectively. Total gross repayments were $127.6 million and $210.3 million for the years ended December 31, 2015 and December 31, 2014, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2015 and December 31, 2014:

Revolving Credit Facility (millions)
	December 31,
	2015		2014
Limit	$	120.0	$	120.0
Outstanding	$	42.0	$	29.3
Available	$	78.0	$	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 December 31, 2015 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 5.)

The weighted average interest rates on all short-term borrowings were 1.5%, 1.6%, and 1.8% during 2015, 2014, and 2013, respectively.

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

In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of December 31, 2015, there are $2.6 million of current and $10.4 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

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 $10.8 million and $15.1 million of natural gas storage inventory at December 31, 2015 and 2014, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2015, which was payable in January 2016, was $0.6 million and recorded in Accounts Payable at December 31, 2015. The amount of natural gas inventory released in December 2014, which was payable in January 2015, was $1.0 million and recorded in Accounts Payable at December 31, 2014.

Leases

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.

Total rental expense under operating leases charged to operations for the years ended December 31, 2015, 2014 and 2013 amounted to $1.7 million, $1.3 million and $1.2 million respectively.

Assets under capital leases amounted to approximately $15.3 million and $9.7 million as of December 31, 2015 and 2014, respectively, less accumulated amortization of $0.8 million and $0.8 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2015. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $11.0 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2015. $2.6 million of the current Capital Lease Obligations and $10.4 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2016	$	1,326	$	3,060
2017		1,048		2,937
2018		698		2,891
2019		355		2,851
2020		180		2,357
2021 – 2025		125		—
Total Payments	$	3,732	$	14,096

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 December 31, 2015, there were approximately $19.3 million of guarantees outstanding and the longest term guarantee extends through August 2016.

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 December 31, 2015, the principal amount outstanding for the 8% Unitil Realty notes was $1.1 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

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Equity

12 Months Ended

Dec. 31, 2015

Equity

Note 6: Equity

The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding. Details regarding these forms of capitalization follow:

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 13,916,026 and 13,991,430 shares of common stock outstanding at December 31, 2014 and December 31, 2015, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2014 and December 31, 2015.

Dividend Reinvestment and Stock Purchase Plan—During 2015, the Company sold 36,265 shares of its common stock, at an average price of $34.77 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.3 million. 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. During 2014 and 2013, the Company raised $1.2 million and $1.1 million, respectively, through the issuance of 38,020 and 39,559 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—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, 2014, the Company may 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. (See Part II, Item 5, for additional information). During 2015, 2014 and 2013, the Company repurchased 1,981, 2,763 and 2,969 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.1 million, $0.1 million and $0.1 million in 2015, 2014 and 2013, respectively.

During 2015, 2014 and 2013, the Company did not cancel or retire any of its common stock.

Stock-Based Compensation Plans—Unitil maintains a stock plan. The Company accounts for its stock-based compensation plan in accordance with the provisions of the FASB Codification and measures compensation costs at fair value at the date of grant. Details of the plan are as follows:

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.

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.

Restricted Shares issued for 2013 – 2015 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
2/4/13	21,240	$0.6
1/31/14	35,500	$1.1
1/26/15	40,010	$1.5

There were 70,761 and 67,334 non-vested shares under the Stock Plan as of December 31, 2015 and 2014, respectively. The weighted average grant date fair value of these shares was $32.56 per share and $28.51 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $1.9 million, $1.4 million and $0.7 million in 2015, 2014 and 2013, respectively. At December 31, 2015, there was approximately $1.1 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were 871 restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2015. On January 26, 2016, there were 43,220 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, 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 2015 and 2014 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2015				2014
	Units		Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		23,576	$	29.90		14,903		$	28.90
Restricted Stock Units Granted		8,965	$	36.54		9,078		$	31.23
Dividend Equivalents Earned		1,047	$	35.01		701		$	33.18
Restricted Stock Units Settled		—		—		(1,106	)	$	29.49
Ending Restricted Stock Units		33,588	$	31.83		23,576		$	29.90

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2015 and 2014 is $0.5 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 1,898 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2015. There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2014. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2015 and December 31, 2014, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data)	2015		2014		2013
Earnings Available to Common Shareholders	$	26.3	$	24.7	$	21.6
Weighted Average Common Shares Outstanding—Basic (000’s)		13,917		13,843		13,773
Plus: Diluted Effect of Incremental Shares (000’s)		3		4		2
Weighted Average Common Shares Outstanding—Diluted (000’s)		13,920		13,847		13,775
Earnings per Share—Basic and Diluted	$	1.89	$	1.79	$	1.57

For 2015, 2014 and 2013, respectively, 36,941, 0 and 4,481 weighted average non-vested restricted shares were not included in the above computation because the effect would have been antidilutive.

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Energy Supply

12 Months Ended

Dec. 31, 2015

Energy Supply

Note 7: Energy Supply

Natural Gas Supply

Unitil manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.

Northern Utilities’ Commercial and Industrial (C&I) customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities’ larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. Fitchburg’s residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies from third-party suppliers, while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. The approved costs associated with the acquisition of such wholesale natural gas supplies for customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings.

Regulated Natural Gas Supply

Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), to truck supplies to storage facilities within Northern Utilities’ service territory.

Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.6 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas.

Fitchburg purchases natural gas under contracts from producers and marketers on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg’s service territory.

Fitchburg has available under firm contract 14,057 MMbtu per day of year-round transportation and 0.33 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

Electric Power Supply

The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil’s power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2015, 79% of Unitil’s largest New Hampshire customers, representing 26% of total New Hampshire electric energy sales, and 88% of Unitil’s largest Massachusetts customers, representing 34% of total Massachusetts electric energy sales; are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 17% of Fitchburg’s customer base and customers in Ashby comprise another 5%. In New Hampshire, the number of residential customers purchasing from a third party supplier has increased more than tenfold in the past three years and stands at 13% of residential customers. Notwithstanding this activity, most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts with various wholesale suppliers.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for 100% of the supply requirements.

Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential, small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure.

Regional Electric Transmission and Power Markets

Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated, reliable power system operation and a supportive business environment for the development of competitive electric markets.

Electric Power Supply Divestiture

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 and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Long-Term Renewable Contracts

Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies

Note 8: Commitments and Contingencies

Regulatory Matters

Overview—Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms.

As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MPUC, the MDPU, and the NHPUC have each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power 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 and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31, 2015. The remaining balance of these assets is $1.9 million as of December 31, 2015, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $1.6 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next six years. Unitil’s distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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. The 2015 TIRA provided for an annual increase in base distribution revenue of $1.2 million, effective May 1, 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. 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. The 2015 step adjustment provided for an annual increase of $1.8 million in revenue effective May 1, 2015.

Northern Utilities—Pipeline Refund—On February 19, 2015 the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund will be credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities will be credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities of $7.6 million and $8.1 million, respectively, on its Consolidated Balance Sheets as of December 31, 2015.

Unitil Energy—Base Rates—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. The third and final step increase of $1.5 million in annual revenue was effective May 1, 2014.

Granite State—Base Rates—Granite State had in place a FERC approved amended settlement agreement under which it had 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. The final rate adjustment under this agreement was effective August 1, 2014. Granite State has received FERC approval of a second amended settlement agreement under which it will continue to be permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a cost cap. The FERC approval of the second amended settlement included a rate increase of $0.4 million, effective August 1, 2015.

Fitchburg—Base Rates—Electric—On May 30, 2014, the Massachusetts Department of Public Utilities (MDPU) approved a $5.6 million increase in Fitchburg’s base revenue decoupling target, effective June 1, 2014. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 and 2012. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off. The impact of the rate order on previously capitalized or deferred items was not material.

On June 16, 2015, Fitchburg filed for a $3.8 million increase in electric base revenue decoupling target, which represents a 5.6 percent increase over 2014 test year operating electric revenues. The filing included a request for approval of a capital cost recovery mechanism to recover prudently incurred additions to utility plant on an annual basis. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. 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 decoupling target, which represents an 8.3 percent increase over 2014 test year total gas operating revenues. Discovery and hearings have been completed and briefs have been filed. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of April, 2016.

Major Storms—Fitchburg and Unitil Energy

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

Unitil Energy—2012 Storm Costs—On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Thanksgiving 2014 Snow Storm—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 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.

NHPUC Energy Efficiency Resource Standard Proceeding—On May 8, 2015, the NHPUC issued an order of notice commencing a proceeding to establish an Energy Efficiency Resource Standard, an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. In this proceeding the Commission will define the savings targets and address issues related to public and private funding; program cost recovery; lost-revenue recovery (e.g. decoupling); performance-based incentives and penalties; program administration; and evaluation, measurement, and verification. Initial comments were filed by interested parties on December 9, 2015, and the matter remains pending.

Northern Utilities—Other—In the fourth quarter of 2015, Northern Utilities completed the transition into a new Distribution Operations Center (DOC) for its operations in Portland, Maine. The new property includes an existing building and is located at 376 Riverside Industrial Parkway in Portland, Maine. On September 19, 2014, Northern Utilities sold its existing DOC facility located at 1075 Forest Avenue in Portland, Maine. While the new DOC facility was being renovated, Northern Utilities leased back its existing DOC facility from the new owner. The new DOC facility was needed due to space limitations at the existing DOC. In recent years Northern Utilities’ gas expansion initiative and the work associated with it resulted in staff, company vehicles, and material storage additions to a facility that could not adequately handle these additions. Northern Utilities recognized a net gain on sale of the Forest Avenue property of $0.9 million in the fourth quarter of 2015.

Fitchburg—Electric Operations—On November 24, 2014, Fitchburg submitted its 2014 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were approved, subject to investigation and reconciliation, effective January 1, 2015 for billing purposes, and given final approval by the MDPU on June 16, 2015.

On November 17, 2015, Fitchburg submitted its 2015 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were approved, subject to investigation and reconciliation, effective January 1, 2016 for billing purposes, and given final approval by the MDPU on December 29, 2015.

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 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. The second annual filing, to recover the estimated costs to be incurred in calendar year 2016, was made on October 31, 2015. The Company seeks approval to collect in rates $0.9 million for the costs of its cumulative capital investments for 2015 and 2016, effective May 1, 2016. This matter remains pending.

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 July 7, 2015, the MDPU approved Fitchburg’s 2013 gas division Service Quality Report as filed. On October 21, 2015, the MDPU approved Fitchburg’s 2012 electric division Service Quality Report as filed. On November 25, 2015, the MDPU approved Fitchburg’s 2014 gas division Service Quality Report as filed. Fitchburg’s 2013 and 2014 electric division Service Quality Reports remain pending.

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 filed a motion with the MDPU to reconsider the adoption of state-wide standards and requested reconsideration and clarification on other technical issues. On December 18, 2015, the MDPU issued its order on the motion to reconsider, and issued revised guidelines. The new guidelines reverse the change to state-wide standards in favor of the company specific standards currently in place, eliminate several metric and reporting requirements and revise several existing metrics in addition to the changes noted above. 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.

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 provided guidance and filing requirements for the business case justification that the electric companies must file as part of their GMPs. The second order required 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. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filing are currently under the MDPU’s review. The MDPU is addressing in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles. These matters remain pending.

FERC Transmission Formula Rate Proceeding—On December 28, 2015, FERC issued an order, pursuant to section 206 of the Federal Power Act, instituting a proceeding concerning the justness and reasonableness of ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates and to develop formula rate protocols for these rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that this proceeding results in any changes to the rates being charged, a refund period will begin as of January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The 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 SJC, and the SJC upheld the lower Court’s order. Subsequently, 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. On July 27, 2015, the Court issued its decision allowing class certification and denying the Company’s motion for summary judgment. The Company appealed this decision to the SJC, and on October 15, 2015, the SJC granted the Company’s motion for direct review of the case, and it is being briefed by the parties and set for oral argument during the first quarter of 2016. 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. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

Environmental Matters

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 December 31, 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. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough. Northern Utilities has worked with the 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, Dover, Somersworth, Portsmouth, Lewiston and Scarborough sites, though future activities may be required.

The site in Portland has been investigated and remedial activities have largely been completed. Final remediation activities were completed in the fourth quarter of 2015, and closure documentation will be prepared for submittal to the regulatory agency in the first half of 2016. In the second quarter of 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 this taking, and pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the site will be primarily the responsibility of the State of Maine.

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 remediation activities in Exeter commenced in the fourth quarter of 2015. The anticipated completion of these activities is in the first quarter of 2016.

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

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

Fitchburg’s Manufactured Gas Plant Site—Fitchburg completed the scheduled site work at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the fourth quarter of 2014. The closure documentation for the site was submitted in the fourth quarter of 2015 and is under review by the Massachusetts Department of Environmental Protection.

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 years ended December 31, 2015 and 2014.

Environmental Obligations

	(millions)
	Fitchburg				Northern Utilities				Total
	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		—		—		2.9		1.3		2.9		1.3
Less: Payments / Reductions		0.7		10.1		4.9		0.5		5.6		10.6
Total Balance at End of Period	$	1.2	$	1.9	$	1.6	$	3.6	$	2.8	$	5.5
Less: Current Portion		0.2		1.9		1.1		1.6		1.3		3.5
Noncurrent Balance at December 31, 2014	$	1.0	$	—	$	0.5	$	2.0	$	1.5	$	2.0

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Taxes

Note 9: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2015, 2014 and 2013 are shown in the table below:

	($000’s)
	2015			2014			2013
Current Federal Tax Provision (Benefit)
Operating Income	$	3,710		$	3,179		$	—
Current Benefit of Operating Loss Carryforwards		(3,710	)		(3,179	)		—
Total Current Federal Tax Provision (Benefit)		—			—			—
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		17,924			10,649			28,907
Net Operating Loss Carryforwards / (Carrybacks)		2,374			2,589			(8,053	)
Regulatory Assets and Liabilities		(6,101	)		(5,946	)		(11,483	)
Other, net		(1,784	)		3,517			681
Total Deferred Federal Tax Provision (Benefit)		12,413			10,809			10,052
Total Federal Tax Provision		12,413			10,809			10,052
State
Current		3,530			(387	)		386
Deferred		(500	)		3,573			2,214
Total State Tax Provision		3,030			3,186			2,600
Total Provision for Federal and State Income Taxes	$	15,443		$	13,995		$	12,652

The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:

	2015			2014			2013
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		5			2			5
Utility Plant Differences		(2	)		(1	)		(2	)
Tax Credits and Other, net		—			1			—
Effective Income Tax Rate		37	%		36	%		37	%

Temporary differences which gave rise to current deferred tax assets and liabilities in 2015 and 2014, are shown below:

Current Deferred Income Taxes (000’s)	2015			2014
Accrued Revenue, Current Portion	$	5,090		$	(3,038	)
Other, net		(348	)		(90	)
Total Current Deferred Income Tax Assets (Liabilities)	$	4,742		$	(3,128	)

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2015 and 2014, are shown below:

Noncurrent Deferred Income Taxes (000’s)	2015			2014
Utility Plant Differences	$	141,185		$	120,534
Retirement Benefit Obligations		(43,543	)		(44,829	)
Net Operating Loss Carryforwards		(10,500	)		(13,122	)
Regulatory Assets & Liabilities		10,535			12,740
AMT Tax Credit Carryforwards		(2,677	)		(2,139	)
Other, net		(2,792	)		(314	)
Total Noncurrent Deferred Income Tax Liabilities	$	92,208		$	72,870

The Company is subject to federal and state income taxes as well as various other business taxes. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. Periodically, the Company 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 that gave rise to the revision become known.

The Company filed its tax returns for the year ended December 31, 2014 with the Internal Revenue Service in September 2015 and generated additional federal net operating loss (NOL) carryforward assets principally due to current tax repair deductions, tax depreciation and research and development deductions. For the year ended December 31, 2015, the Company utilized $3.7 million of its federal NOL carryforward assets in the calculation of its provisions for income taxes for the period. As of December 31, 2015, the Company had recorded cumulative federal NOL carryforward assets of $11.3 million to offset against taxes payable in future periods. If unused, the Company’s federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2015, the Company had $2.1 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In 2015, Unitil recognized a tax benefit of $63,000 in the tax provision related to Federal research and development tax credits under the rules of section 41 of the Internal Revenue Code, which the Company claimed on its 2014 tax return filed in September of 2015. The Company will continue to recognize a tax benefit on its incremental qualified research expenses and has recognized a tax benefit in the tax provision of $288,000 related to 2015 expenditures.

The Company evaluated its tax positions at December 31, 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, 2012; December 31, 2013; and December 31, 2014.

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Retirement Benefit Plans

12 Months Ended

Dec. 31, 2015

Retirement Benefit Plans

Note 10: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows:

• The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

• The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

• The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified retirement plan, with participation limited to executives selected by the Board of Directors.

Effective with the acquisitions of Northern Utilities and Granite State, the Company assumed the assets and obligations of the Northern Utilities and Granite State pension plans with respect to active union employees. All other active employees of Northern Utilities and Granite State effectively became members of the Company’s Pension Plan as of the acquisitions closing date.

Certain employees of Northern Utilities qualified for participation in the Company’s PBOP Plan effective with the acquisition closing date.

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

	2015			2014			2013
Used to Determine Plan costs for years ended December 31:
Discount Rate(1)		4.00	%		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2018			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,383		$	989		$	1,169
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(1,040	)	$	(771	)	$	(895	)

⁽¹⁾  As a result of the addition of a plan participant to the SERP in July 2015, the Company was required to update the discount rate used in determining SERP costs for the remainder of 2015. Based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves at that time, the Company assumed a discount rate of 4.30% for the SERP from July through December of 2015.

Used to Determine Benefit Obligations at December 31:
Discount Rate		4.30	%		4.00	%		4.80	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2022			2018			2018
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	14,877		$	15,325		$	9,957
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(11,611	)	$	(11,829	)	$	(7,942	)

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2015, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $472,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2015 was based on the expected long-term increase in compensation costs for personnel covered by the plans.

The following table provides the components of the Company’s Retirement plan costs (000’s):

	Pension Plan									PBOP Plan									SERP
	2015			2014			2013			2015			2014			2013			2015		2014		2013
Service Cost	$	3,689		$	3,006		$	3,573		$	2,622		$	1,988		$	2,523		$	120	$	57	$	73
Interest Cost		5,392			5,092			4,567			2,918			2,686			2,448			330		272		241
Expected Return on Plan Assets		(6,779	)		(6,245	)		(5,955	)		(1,093	)		(920	)		(722	)		—		—		—
Prior Service Cost Amortization		265			211			208			1,682			1,682			1,701			85		11		11
Actuarial Loss Amortization		4,714			2,847			4,229			1,150			56			786			327		100		184
Sub-total		7,281			4,911			6,622			7,279			5,492			6,736			862		440		509
Amounts Capitalized or Deferred		(3,397	)		(1,881	)		(2,929	)		(3,423	)		(2,270	)		(3,010	)		—		—		—
NPBC Recognized	$	3,884		$	3,030		$	3,693		$	3,856		$	3,222		$	3,726		$	862	$	440	$	509

The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company’s Retirement plan costs or as a reduction of regulatory assets over the next fiscal year is $4.7 million, $2.5 million and $0.3 million for the Pension, PBOP and SERP plans, respectively.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2015, 2014 and 2013 before capitalization and deferral was $7.3 million, $4.9 million and $6.6 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2015, 2014 and 2013 would have been $7.3 million, $4.3 million and $6.6 million respectively.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2015			2014			2015			2014			2015			2014
Plan Assets at Beginning of Year	$	86,744		$	82,551		$	12,840		$	10,829		$	—		$	—
Actual Return on Plan Assets		645			4,248			(214	)		486			—			—
Employer Contributions		4,215			4,191			4,000			3,650			40			53
Participant Contributions		—			—			63			59			—			—
Benefits Paid		(4,410	)		(4,246	)		(2,515	)		(2,184	)		(40	)		(53	)
Plan Assets at End of Year	$	87,194		$	86,744		$	14,174		$	12,840		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	136,662		$	108,295		$	73,923		$	56,899		$	7,965		$	5,857
Service Cost		3,689			3,006			2,622			1,988			120			57
Interest Cost		5,392			5,092			2,918			2,686			330			272
Participant Contributions		—			—			63			59			—			—
Plan Amendments		474			—			—			—			608			—
Benefits Paid		(4,410	)		(4,246	)		(2,515	)		(2,184	)		(40	)		(53	)
Actuarial (Gain) or Loss		(991	)		24,515			(762	)		14,475			194			1,832
PBO at End of Year	$	140,816		$	136,662		$	76,249		$	73,923		$	9,177		$	7,965
Funded Status: Assets vs PBO	$	(53,622	)	$	(49,918	)	$	(62,075	)	$	(61,083	)	$	(9,177	)	$	(7,965	)

The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss).

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets of $64.7 million and $65.1 million at December 31, 2015 and 2014, respectively, to account for the future collection of these plan obligations in electric and gas rates.

The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $126.8 million and $121.8 million as of December 31, 2015 and 2014, respectively. The ABO for the SERP was $7.0 million and $6.3 million as of December 31, 2015 and 2014, respectively. For the PBOP Plan, the ABO and PBO are the same.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2016 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

The following table represents employer contributions, participant contributions and benefit payments (000’s).

	Pension Plan						PBOP Plan						SERP
	2015		2014		2013		2015		2014		2013		2015		2014		2013
Employer Contributions	$	4,215	$	4,191	$	3,700	$	4,000	$	3,650	$	3,280	$	40	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	63	$	59	$	36	$	—	$	—	$	—
Benefit Payments	$	4,410	$	4,246	$	3,764	$	2,515	$	2,184	$	1,942	$	40	$	53	$	53

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2016	$	5,181	$	2,178	$	426
2017		5,522		2,318		421
2018		5,560		2,503		416
2019		6,086		2,700		475
2020		6,345		2,866		469
2021 - 2025		37,857		17,932		3,027

The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 47% in common stock equities, 37% in fixed income securities, 10% in real estate securities and 6% in a combined equity and debt fund. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2016			Actual Allocation at December 31,
				2015			2014			2013
Equity Funds		47	%		46	%		49	%		54	%
Debt Funds		37	%		37	%		36	%		32	%
Real Estate Fund		10	%		11	%		10	%		1	%
Asset Allocation Fund(1)		6	%		6	%		5	%		5	%
Other(2)		0	%		0	%		0	%		8	%
Total					100	%		100	%		100	%

(1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

(2) Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

PBOP Plan	Target Allocation 2016			Actual Allocation at December 31,
				2015			2014			2013
Equity Funds		55	%		53	%		56	%		57	%
Debt Funds		45	%		47	%		44	%		43	%
Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.00% for 2015. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2015 and 2014. Please also see Note 1 for a discussion of the Company’s fair value accounting policy.

Equity, Fixed Income, Index and Asset Allocation Funds

These investments are valued based on quoted prices from active markets. These securities are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Cash Equivalents

These investments are valued at cost, which approximates fair value, and are categorized in Level 1.

Real Estate Fund

These investments are valued at net asset value (NAV) per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity and are categorized in Level 3.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2015 and 2014 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2015
Pension Plan Assets:
Equity Funds	$	40,124	$	40,124	$	—	$	—
Fixed Income Funds		32,192		32,192		—		—
Asset Allocation Fund		5,527		5,527		—		—
Real Estate Fund		9,351		—		—		9,351
Total Assets	$	87,194	$	77,843	$	—	$	9,351
2014
Pension Plan Assets:
Equity Funds	$	42,760	$	42,760	$	—	$	—
Fixed Income Funds		31,136		31,136		—		—
Asset Allocation Fund		4,676		4,676		—		—
Real Estate Fund		8,172		—		—		8,172
Total Assets	$	86,744	$	78,572	$	—	$	8,172

The following tables set forth additional disclosures of Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2015 and 2014 (000’s):

	Fair Value Estimated Using NAV Per Share
Description	Fair Value		Unfunded Commitment		Redemption Frequency		Redemption Notice Period
	December 31, 2015
SEI Core Property Collective Investment Trust Fund(1)	$	9,351	$	—		Quarterly		65 days
	December 31, 2014
SEI Core Property Collective Investment Trust Fund(1)	$	8,172	$	—		Quarterly		65 days

⁽¹⁾  The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

The table below sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the years ended December 31, 2015 and 2014 (000’s):

Level 3 Assets—SEI Core Property Collective Investment Trust Fund
	December 31,
	2015		2014
Beginning Balance	$	8,172	$	1,125
Actual Return on Investments:
Related to Investments Held at Year-End		1,179		672
Related to Investments Sold During the Year		—		—
Total Return on Investments		1,179		672
Purchases, Sales and Settlements		—		6,375
Ending Balance	$	9,351	$	8,172

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2015 and 2014 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2015
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	6,620	$	6,620	$	—	$	—
Equity Funds		7,554		7,554
Total Assets	$	14,174	$	14,174	$	—	$	—
2014
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	5,661	$	5,661	$	—	$	—
Index Funds		5,313		5,313
Equity Funds		1,866		1,866
Total Assets	$	12,840	$	12,840	$	—	$	—

Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company common stock fund.

The Company’s contributions to the 401(k) Plan were $2,098,000, $1,877,000 and $1,678,000 for the years ended December 31, 2015, 2014 and 2013, respectively.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Nature of Operations

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 wholly-owned 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 capital city areas 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 Maine to the Lewiston-Auburn area 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 an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine, New Hampshire and Massachusetts. 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 a national client base of large commercial and industrial customers.

Principles of Consolidation

Principles of Consolidation—The Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation.

Use of Estimates

Use of Estimates—The preparation of 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 requires 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. Actual results could differ from those estimates.

Fair Value

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.

Utility Revenue Recognition

Utility Revenue Recognition—Utility revenues are recognized according to regulations and are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates.

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

Revenue Recognition-Non-regulated Operations

Revenue Recognition—Non-regulated Operations—Usource, Unitil’s competitive energy brokering subsidiary, records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period.

Depreciation and Amortization

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2015 – 3.57%, 2014 – 3.56% and 2013 – 3.59%.

Stock-based Employee Compensation

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 6).

Sales and Consumption Taxes

Sales and Consumption Taxes—The Company bills its customers 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 Consolidated Statements of Earnings.

Income Taxes

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

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

Dividends

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2015 the Company paid quarterly dividends of $0.350 per share, resulting in an annual dividend rate of $1.40 per common share. For the years ended December 31, 2014 and 2013, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend rate of $1.38 per common share. At its January 2016 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.3550 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.42 per share from $1.40 per share.

Cash and Cash Equivalents

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2015 and 2014, the Unitil subsidiaries had deposited $2.3 million and $6.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2015 and 2014.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts—The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric 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. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

Accrued Revenue

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2015 and 2014.

Accrued Revenue (millions)	December 31,
	2015		2014
Regulatory Assets—Current	$	26.8	$	37.8
Unbilled Revenues		11.6		10.7
Total Accrued Revenue	$	38.4	$	48.5

Exchange Gas Receivable

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 December 31, 2015 and 2014.

Exchange Gas Receivable (millions)	December 31,
	2015		2014
Northern Utilities	$	10.3	$	14.2
Fitchburg		0.8		0.8
Total Exchange Gas Receivable	$	11.1	$	15.0

Gas Inventory

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 December 31, 2015 and 2014.

Gas Inventory (millions)	December 31,
	2015		2014
Natural Gas	$	0.3	$	0.8
Propane		0.3		0.2
Liquefied Natural Gas & Other		0.2		0.1
Total Gas Inventory	$	0.8	$	1.1

Utility Plant

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 average interest rates applied to AFUDC were 2.32%, 1.56% and 1.92% in 2015, 2014 and 2013, respectively. 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 December 31, 2015 and 2014, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $70.1 million and $63.8 million, respectively.

Regulatory Accounting

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 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.

Regulatory Assets consist of the following (millions)	December 31,
	2015		2014
Retirement Benefits	$	64.7	$	65.1
Energy Supply & Other Regulatory Tracker Mechanisms		21.3		31.0
Deferred Storm Charges		15.4		21.2
Environmental		11.2		11.0
Income Taxes		8.5		9.7
Deferred Restructuring Costs		—		1.6
Other		5.3		5.8
Total Regulatory Assets	$	126.4	$	145.4
Less: Current Portion of Regulatory Assets(1)		26.8		37.8
Regulatory Assets—noncurrent	$	99.6	$	107.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities consist of the following (millions)	December 31,
	2015		2014
Regulatory Tracker Mechanisms	$	8.0	$	8.8
Gas Pipeline Refund (Note 8)		15.7		—
Total Regulatory Liabilities		23.7		8.8
Less: Current Portion of Regulatory Liabilities		15.6		8.7
Regulatory Liabilities—noncurrent	$	8.1	$	0.1

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2015 are $6.6 million of deferred storm charges to be recovered over the next two and a half years and $7.4 million of rate case costs and other expenditures to be recovered over the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives

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 December 31, 2015, all futures contracts purchased under the prior program design have been 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 customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of December 31, 2015 and December 31, 2014, the Company had 2.5 billion and 2.4 billion cubic feet (BCF), respectively, outstanding in natural gas purchase 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 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 Consolidated Balance Sheets.

Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of:

		Fair Value
Description	Balance Sheet Location	December 31, 2015		December 31, 2014
Derivative Assets
Natural Gas Futures / Options Contracts	Prepayments and Other	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Assets		—		0.1
Total Derivative Assets		$	—	$	0.1
Derivative Liabilities
Natural Gas Futures / Options Contracts	Other Current Liabilities	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	—

	Twelve Months Ended December 31,
	2015		2014
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	0.3	$	(0.7	)
Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.2	$	(0.8	)

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

Investments in Marketable Securities

Investments in Marketable Securities—In 2015, the Company established a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 10).

At December 31, 2015 and 2014, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Prepayments and Other, are $0.7 million and $0, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Fair Value of Marketable Securities (millions)	December 31,
	2015		2014
Equity Funds	$	0.4	$	—
Fixed Income Funds		0.3		—
Total Marketable Securities	$	0.7	$	—

Goodwill and Intangible Assets

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2015, the unamortized balance of the bargain purchase adjustment was $7.2 million, to be amortized over the next three years.

Energy Supply Obligations

Energy Supply Obligations—The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.

	December 31,
Energy Supply Obligations consist of the following: (millions)	2015		2014
Current:
Exchange Gas Obligation	$	10.3	$	14.2
Renewable Energy Portfolio Standards		4.0		7.4
Power Supply Contract Divestitures		0.3		0.5
Total Energy Supply Obligations—Current	$	14.6	$	22.1
Noncurrent:
Power Supply Contract Divestitures	$	1.6	$	1.9
Total Energy Supply Obligations	$	16.2	$	24.0

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

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

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

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

Massachusetts Green Communities Act—In compliance with the Massachusetts Green Communities Act, discussed below in Note 8, Commitments and Contingencies, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The generating facility associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Retirement Benefit Obligations

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union employees. For union employees, the Pension Plan was closed on various dates between December 31, 2010 and June 1, 2013, depending on the various Collective Bargaining Agreements of each union. The Company also sponsors a non-qualified retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).

Off-Balance Sheet Arrangements

Off-Balance Sheet Arrangements—As of December 31, 2015, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2015, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2015, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements

Recently Issued Pronouncements—In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2017 and interim periods within those annual periods with earlier application permitted as of the beginning of the fiscal year of adoption. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In November 2015, the FASB issued ASU 2015-17 which simplifies the presentation of deferred income taxes in a classified statement of financial position. Current generally accepted accounting principles (GAAP) require an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position. ASU 2015-17 amends current GAAP to require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. This pronouncement is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods with earlier application permitted as of the beginning of an interim or annual reporting period. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In August 2015, the FASB issued ASU 2015-13 which clarifies the Normal Purchases and Normal Sales scope exception to certain electricity contracts. ASU 2015-13 specifies that the use of locational marginal pricing by an independent system operator does not constitute net settlement of a contract. This pronouncement is effective upon its issuance. The Company has adopted this new guidance and it had no impact on the Company’s Consolidated Financial Statements.

In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements.

In July 2015, the FASB issued ASU 2015-11 which provides authoritative guidance requiring inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. This pronouncement is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In May 2015, the FASB issued ASU 2015-07 which provides authoritative guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all periods presented. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

In April 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. ASU 2015-03 does not contain guidance for debt issuance costs related to line-of-credit arrangements. Consequently, in August 2015, the FASB issued ASU 2015-15 to add paragraphs indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The effective date of these pronouncements is for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company does not expect this new guidance to have a material impact on the Company’s Consolidated Financial Statements.

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

Subsequent Events

Subsequent Events—The Company evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that impacted its Consolidated Financial Statements.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2015 and 2014.

Accrued Revenue (millions)	December 31,
	2015		2014
Regulatory Assets—Current	$	26.8	$	37.8
Unbilled Revenues		11.6		10.7
Total Accrued Revenue	$	38.4	$	48.5

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2015 and 2014.

Exchange Gas Receivable (millions)	December 31,
	2015		2014
Northern Utilities	$	10.3	$	14.2
Fitchburg		0.8		0.8
Total Exchange Gas Receivable	$	11.1	$	15.0

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2015 and 2014.

Gas Inventory (millions)	December 31,
	2015		2014
Natural Gas	$	0.3	$	0.8
Propane		0.3		0.2
Liquefied Natural Gas & Other		0.2		0.1
Total Gas Inventory	$	0.8	$	1.1

Regulatory Assets

Regulatory Assets consist of the following (millions)	December 31,
	2015		2014
Retirement Benefits	$	64.7	$	65.1
Energy Supply & Other Regulatory Tracker Mechanisms		21.3		31.0
Deferred Storm Charges		15.4		21.2
Environmental		11.2		11.0
Income Taxes		8.5		9.7
Deferred Restructuring Costs		—		1.6
Other		5.3		5.8
Total Regulatory Assets	$	126.4	$	145.4
Less: Current Portion of Regulatory Assets(1)		26.8		37.8
Regulatory Assets—noncurrent	$	99.6	$	107.6

⁽¹⁾  Reflects amounts included in Accrued Revenue on the Company’s Consolidated Balance Sheets and in the Accrued Revenue table shown above.

Regulatory Liabilities

Regulatory Liabilities consist of the following (millions)	December 31,
	2015		2014
Regulatory Tracker Mechanisms	$	8.0	$	8.8
Gas Pipeline Refund (Note 8)		15.7		—
Total Regulatory Liabilities		23.7		8.8
Less: Current Portion of Regulatory Liabilities		15.6		8.7
Regulatory Liabilities—noncurrent	$	8.1	$	0.1

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets

Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of:

		Fair Value
Description	Balance Sheet Location	December 31, 2015		December 31, 2014
Derivative Assets
Natural Gas Futures / Options Contracts	Prepayments and Other	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Assets		—		0.1
Total Derivative Assets		$	—	$	0.1
Derivative Liabilities
Natural Gas Futures / Options Contracts	Other Current Liabilities	$	—	$	—
Natural Gas Futures / Options Contracts	Other Noncurrent Liabilities		—		—
Total Derivative Liabilities		$	—	$	—

Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Purchased Gas

	Twelve Months Ended December 31,
	2015		2014
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	0.3	$	(0.7	)
Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.2	$	(0.8	)

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

Fair Value of Marketable Securities

These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied.

Fair Value of Marketable Securities (millions)	December 31,
	2015		2014
Equity Funds	$	0.4	$	—
Fixed Income Funds		0.3		—
Total Marketable Securities	$	0.7	$	—

Components of Energy Supply Obligations

	December 31,
Energy Supply Obligations consist of the following: (millions)	2015		2014
Current:
Exchange Gas Obligation	$	10.3	$	14.2
Renewable Energy Portfolio Standards		4.0		7.4
Power Supply Contract Divestitures		0.3		0.5
Total Energy Supply Obligations—Current	$	14.6	$	22.1
Noncurrent:
Power Supply Contract Divestitures	$	1.6	$	1.9
Total Energy Supply Obligations	$	16.2	$	24.0

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Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information

	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2015		2014		2015		2014		2015		2014		2015		2014
Total Operating Revenues	$	172.2	$	156.1	$	77.5	$	73.3	$	74.7	$	76.6	$	102.4	$	119.8
Operating Income	$	28.4	$	25.4	$	8.9	$	7.1	$	7.3	$	7.4	$	18.5	$	20.1
Net Income (Loss) Applicable to Common	$	13.6	$	12.6	$	1.7	$	1.1	$	1.7	$	1.6	$	9.3	$	9.4
	Per Share Data:
Earnings Per Common Share	$	0.98	$	0.91	$	0.12	$	0.08	$	0.12	$	0.11	$	0.67	$	0.69
Dividends Paid Per Common Share	$	0.350	$	0.345	$	0.350	$	0.345	$	0.350	$	0.345	$	0.350	$	0.345

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Significant Segment Financial Data

The following table provides significant segment financial data for the years ended December 31, 2015, 2014 and 2013 (millions):

Year Ended December 31, 2015	Gas		Electric		Non- Regulated		Other			Total
Revenues	$	202.6	$	218.0	$	6.2	$	—		$	426.8
Interest Income		0.8		0.7		0.1		0.3			1.9
Interest Expense		13.3		8.8		—		1.7			23.8
Depreciation & Amortization Expense		20.7		24.0		0.1		0.9			45.7
Income Tax Expense (Benefit)		10.2		5.5		0.8		(1.1	)		15.4
Segment Profit		15.3		8.7		1.3		1.0			26.3
Segment Assets		596.7		416.8		6.6		26.3			1,046.4
Capital Expenditures		64.9		29.9		0.1		9.0			103.9
Year Ended December 31, 2014
Revenues	$	201.4	$	218.7	$	5.7	$	—		$	425.8
Interest Income		0.3		0.6		0.1		0.3			1.3
Interest Expense		11.5		9.1		—		1.6			22.2
Depreciation & Amortization Expense		18.8		22.3		—		1.0			42.1
Income Tax Expense (Benefit)		10.8		4.5		0.6		(1.9	)		14.0
Segment Profit		15.8		6.8		0.9		1.2			24.7
Segment Assets		566.3		414.1		6.3		13.5			1,000.2
Capital Expenditures		62.3		24.8		0.3		5.2			92.6
Year Ended December 31, 2013
Revenues	$	170.4	$	190.7	$	5.8	$	—		$	366.9
Interest Income		0.5		2.2		0.1		0.4			3.2
Interest Expense		11.0		9.5		—		1.5			22.0
Depreciation & Amortization Expense		17.2		20.3		—		1.0			38.5
Income Tax Expense (Benefit)		7.5		5.1		0.8		(0.7	)		12.7
Segment Profit		12.5		7.6		1.2		0.3			21.6
Segment Assets		502.3		402.8		6.2		9.3			920.6
Capital Expenditures		61.1		23.6		—		4.8			89.5

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Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2015

Allowance for Doubtful Accounts

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2013—2015 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS

	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2015
Electric	$	1.3	$	2.5	$	0.3	$	3.5	$	0.6
Gas		0.4		2.8		0.4		3.1		0.5
Other		0.1		—		—		—		0.1
	$	1.8	$	5.3	$	0.7	$	6.6	$	1.2
Year Ended December 31, 2014
Electric	$	1.3	$	2.9	$	0.3	$	3.2	$	1.3
Gas		0.2		3.1		0.3		3.2		0.4
Other		0.1		—		—		—		0.1
	$	1.6	$	6.0	$	0.6	$	6.4	$	1.8
Year Ended December 31, 2013
Electric	$	1.1	$	2.6	$	0.2	$	2.6	$	1.3
Gas		0.7		2.0		0.2		2.7		0.2
Other		0.1		—		—		—		0.1
	$	1.9	$	4.6	$	0.4	$	5.3	$	1.6

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Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value of Long Term Debt

Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2015		2014
Estimated Fair Value of Long-Term Debt	$	345.2	$	380.6

Details on Long Term Debt

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

Long-Term Debt (millions)	December 31,
	2015		2014
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		12.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0
Fitchburg Long-Term Notes:
6.75% Notes, Due November 30, 2023		11.4		15.2
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0
Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		1.1		1.7
Total Long-Term Debt		325.5		332.9
Less: Current Portion		17.4		4.0
Total Long-Term Debt, Less Current Portion	$	308.1	$	328.9

Summary of Interest Expense and Interest Income

A summary of interest expense and interest income is provided in the following table:

Interest Expense, net (millions)
	2015			2014			2013
Interest Expense
Long-Term Debt	$	22.0		$	20.5		$	20.2
Short-Term Debt		0.9			1.1			1.2
Regulatory Liabilities		0.9			0.6			0.6
Subtotal Interest Expense		23.8			22.2			22.0
Interest Income
Regulatory Assets		(0.7	)		(0.6	)		(2.3	)
AFUDC(1) and Other		(1.2	)		(0.7	)		(0.9	)
Subtotal Interest Income		(1.9	)		(1.3	)		(3.2	)
Total Interest Expense, net	$	21.9		$	20.9		$	18.8

⁽¹⁾  AFUDC—Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility

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

Revolving Credit Facility (millions)
	December 31,
	2015		2014
Limit	$	120.0	$	120.0
Outstanding	$	42.0	$	29.3
Available	$	78.0	$	90.7

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2015. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $11.0 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2015. $2.6 million of the current Capital Lease Obligations and $10.4 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.

Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2016	$	1,326	$	3,060
2017		1,048		2,937
2018		698		2,891
2019		355		2,851
2020		180		2,357
2021 – 2025		125		—
Total Payments	$	3,732	$	14,096

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Equity (Tables)

12 Months Ended

Dec. 31, 2015

Restricted Shares Issued in Conjunction with Stock Plan

Restricted Shares issued for 2013 – 2015 in conjunction with the Stock Plan are presented in the following table:

Issuance Date	Shares	Aggregate Market Value (millions)
2/4/13	21,240	$0.6
1/31/14	35,500	$1.1
1/26/15	40,010	$1.5

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during 2015 and 2014 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	2015				2014
	Units		Weighted Average Stock Price		Units			Weighted Average Stock Price
Beginning Restricted Stock Units		23,576	$	29.90		14,903		$	28.90
Restricted Stock Units Granted		8,965	$	36.54		9,078		$	31.23
Dividend Equivalents Earned		1,047	$	35.01		701		$	33.18
Restricted Stock Units Settled		—		—		(1,106	)	$	29.49
Ending Restricted Stock Units		33,588	$	31.83		23,576		$	29.90

Reconciliation of Basic and Diluted Earnings Per Share

The following table reconciles basic and diluted earnings per share.

(Millions except shares and per share data)	2015		2014		2013
Earnings Available to Common Shareholders	$	26.3	$	24.7	$	21.6
Weighted Average Common Shares Outstanding—Basic (000’s)		13,917		13,843		13,773
Plus: Diluted Effect of Incremental Shares (000’s)		3		4		2
Weighted Average Common Shares Outstanding—Diluted (000’s)		13,920		13,847		13,775
Earnings per Share—Basic and Diluted	$	1.89	$	1.79	$	1.57

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Environmental Obligations

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years ended December 31, 2015 and 2014.

Environmental Obligations

	(millions)
	Fitchburg				Northern Utilities				Total
	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		—		—		2.9		1.3		2.9		1.3
Less: Payments / Reductions		0.7		10.1		4.9		0.5		5.6		10.6
Total Balance at End of Period	$	1.2	$	1.9	$	1.6	$	3.6	$	2.8	$	5.5
Less: Current Portion		0.2		1.9		1.1		1.6		1.3		3.5
Noncurrent Balance at December 31, 2014	$	1.0	$	—	$	0.5	$	2.0	$	1.5	$	2.0

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Provisions for Federal and State Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2015, 2014 and 2013 are shown in the table below:

	($000’s)
	2015			2014			2013
Current Federal Tax Provision (Benefit)
Operating Income	$	3,710		$	3,179		$	—
Current Benefit of Operating Loss Carryforwards		(3,710	)		(3,179	)		—
Total Current Federal Tax Provision (Benefit)		—			—			—
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		17,924			10,649			28,907
Net Operating Loss Carryforwards / (Carrybacks)		2,374			2,589			(8,053	)
Regulatory Assets and Liabilities		(6,101	)		(5,946	)		(11,483	)
Other, net		(1,784	)		3,517			681
Total Deferred Federal Tax Provision (Benefit)		12,413			10,809			10,052
Total Federal Tax Provision		12,413			10,809			10,052
State
Current		3,530			(387	)		386
Deferred		(500	)		3,573			2,214
Total State Tax Provision		3,030			3,186			2,600
Total Provision for Federal and State Income Taxes	$	15,443		$	13,995		$	12,652

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate

The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:

	2015			2014			2013
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		5			2			5
Utility Plant Differences		(2	)		(1	)		(2	)
Tax Credits and Other, net		—			1			—
Effective Income Tax Rate		37	%		36	%		37	%

Deferred Income Taxes Assets Liabilities Current

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to current deferred tax assets and liabilities in 2015 and 2014, are shown below:

Current Deferred Income Taxes (000’s)	2015			2014
Accrued Revenue, Current Portion	$	5,090		$	(3,038	)
Other, net		(348	)		(90	)
Total Current Deferred Income Tax Assets (Liabilities)	$	4,742		$	(3,128	)

Deferred Income Taxes Assets liabilities Noncurrent

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2015 and 2014, are shown below:

Noncurrent Deferred Income Taxes (000’s)	2015			2014
Utility Plant Differences	$	141,185		$	120,534
Retirement Benefit Obligations		(43,543	)		(44,829	)
Net Operating Loss Carryforwards		(10,500	)		(13,122	)
Regulatory Assets & Liabilities		10,535			12,740
AMT Tax Credit Carryforwards		(2,677	)		(2,139	)
Other, net		(2,792	)		(314	)
Total Noncurrent Deferred Income Tax Liabilities	$	92,208		$	72,870

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Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2015

Key Assumptions used in Determining Benefit Plan Costs and Obligations

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

	2015			2014			2013
Used to Determine Plan costs for years ended December 31:
Discount Rate(1)		4.00	%		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2018			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,383		$	989		$	1,169
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(1,040	)	$	(771	)	$	(895	)

⁽¹⁾  As a result of the addition of a plan participant to the SERP in July 2015, the Company was required to update the discount rate used in determining SERP costs for the remainder of 2015. Based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves at that time, the Company assumed a discount rate of 4.30% for the SERP from July through December of 2015.

Used to Determine Benefit Obligations at December 31:
Discount Rate		4.30	%		4.00	%		4.80	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2022			2018			2018
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	14,877		$	15,325		$	9,957
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(11,611	)	$	(11,829	)	$	(7,942	)

Components of Retirement Plan Costs

The following table provides the components of the Company’s Retirement plan costs (000’s):

	Pension Plan									PBOP Plan									SERP
	2015			2014			2013			2015			2014			2013			2015		2014		2013
Service Cost	$	3,689		$	3,006		$	3,573		$	2,622		$	1,988		$	2,523		$	120	$	57	$	73
Interest Cost		5,392			5,092			4,567			2,918			2,686			2,448			330		272		241
Expected Return on Plan Assets		(6,779	)		(6,245	)		(5,955	)		(1,093	)		(920	)		(722	)		—		—		—
Prior Service Cost Amortization		265			211			208			1,682			1,682			1,701			85		11		11
Actuarial Loss Amortization		4,714			2,847			4,229			1,150			56			786			327		100		184
Sub-total		7,281			4,911			6,622			7,279			5,492			6,736			862		440		509
Amounts Capitalized or Deferred		(3,397	)		(1,881	)		(2,929	)		(3,423	)		(2,270	)		(3,010	)		—		—		—
NPBC Recognized	$	3,884		$	3,030		$	3,693		$	3,856		$	3,222		$	3,726		$	862	$	440	$	509

Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s):

	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2015			2014			2015			2014			2015			2014
Plan Assets at Beginning of Year	$	86,744		$	82,551		$	12,840		$	10,829		$	—		$	—
Actual Return on Plan Assets		645			4,248			(214	)		486			—			—
Employer Contributions		4,215			4,191			4,000			3,650			40			53
Participant Contributions		—			—			63			59			—			—
Benefits Paid		(4,410	)		(4,246	)		(2,515	)		(2,184	)		(40	)		(53	)
Plan Assets at End of Year	$	87,194		$	86,744		$	14,174		$	12,840		$	—		$	—
Change in PBO:
PBO at Beginning of Year	$	136,662		$	108,295		$	73,923		$	56,899		$	7,965		$	5,857
Service Cost		3,689			3,006			2,622			1,988			120			57
Interest Cost		5,392			5,092			2,918			2,686			330			272
Participant Contributions		—			—			63			59			—			—
Plan Amendments		474			—			—			—			608			—
Benefits Paid		(4,410	)		(4,246	)		(2,515	)		(2,184	)		(40	)		(53	)
Actuarial (Gain) or Loss		(991	)		24,515			(762	)		14,475			194			1,832
PBO at End of Year	$	140,816		$	136,662		$	76,249		$	73,923		$	9,177		$	7,965
Funded Status: Assets vs PBO	$	(53,622	)	$	(49,918	)	$	(62,075	)	$	(61,083	)	$	(9,177	)	$	(7,965	)

Employer Contributions, Participant Contributions and Benefit Payments

The following table represents employer contributions, participant contributions and benefit payments (000’s).

	Pension Plan						PBOP Plan						SERP
	2015		2014		2013		2015		2014		2013		2015		2014		2013
Employer Contributions	$	4,215	$	4,191	$	3,700	$	4,000	$	3,650	$	3,280	$	40	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	63	$	59	$	36	$	—	$	—	$	—
Benefit Payments	$	4,410	$	4,246	$	3,764	$	2,515	$	2,184	$	1,942	$	40	$	53	$	53

Estimated Future Benefit Payments

The following table represents estimated future benefit payments (000’s).

Estimated Future Benefit Payments
	Pension		PBOP		SERP
2016	$	5,181	$	2,178	$	426
2017		5,522		2,318		421
2018		5,560		2,503		416
2019		6,086		2,700		475
2020		6,345		2,866		469
2021 - 2025		37,857		17,932		3,027

Actual Investment Allocations

The actual investment allocations are shown in the tables below.

Pension Plan	Target Allocation 2016			Actual Allocation at December 31,
				2015			2014			2013
Equity Funds		47	%		46	%		49	%		54	%
Debt Funds		37	%		37	%		36	%		32	%
Real Estate Fund		10	%		11	%		10	%		1	%
Asset Allocation Fund(1)		6	%		6	%		5	%		5	%
Other(2)		0	%		0	%		0	%		8	%
Total					100	%		100	%		100	%

(1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

(2) Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

PBOP Plan	Target Allocation 2016			Actual Allocation at December 31,
				2015			2014			2013
Equity Funds		55	%		53	%		56	%		57	%
Debt Funds		45	%		47	%		44	%		43	%
Total					100	%		100	%		100	%

Fair Value of Pension Plan Investments Estimated using Net Asset Value

The following tables set forth additional disclosures of Pension Plan investments whose fair value is estimated using net asset value per share as of December 31, 2015 and 2014 (000’s):

	Fair Value Estimated Using NAV Per Share
Description	Fair Value		Unfunded Commitment		Redemption Frequency		Redemption Notice Period
	December 31, 2015
SEI Core Property Collective Investment Trust Fund(1)	$	9,351	$	—		Quarterly		65 days
	December 31, 2014
SEI Core Property Collective Investment Trust Fund(1)	$	8,172	$	—		Quarterly		65 days

⁽¹⁾  The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

Summary of Changes in the Fair Value of the Pension Plan Level 3 Assets

The table below sets forth a summary of changes in the fair value of the Pension Plan’s Level 3 assets for the years ended December 31, 2015 and 2014 (000’s):

Level 3 Assets—SEI Core Property Collective Investment Trust Fund
	December 31,
	2015		2014
Beginning Balance	$	8,172	$	1,125
Actual Return on Investments:
Related to Investments Held at Year-End		1,179		672
Related to Investments Sold During the Year		—		—
Total Return on Investments		1,179		672
Purchases, Sales and Settlements		—		6,375
Ending Balance	$	9,351	$	8,172

Pension Plans

Assets Measured at Fair Value on Recurring Basis

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2015 and 2014 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2015
Pension Plan Assets:
Equity Funds	$	40,124	$	40,124	$	—	$	—
Fixed Income Funds		32,192		32,192		—		—
Asset Allocation Fund		5,527		5,527		—		—
Real Estate Fund		9,351		—		—		9,351
Total Assets	$	87,194	$	77,843	$	—	$	9,351
2014
Pension Plan Assets:
Equity Funds	$	42,760	$	42,760	$	—	$	—
Fixed Income Funds		31,136		31,136		—		—
Asset Allocation Fund		4,676		4,676		—		—
Real Estate Fund		8,172		—		—		8,172
Total Assets	$	86,744	$	78,572	$	—	$	8,172

Other Postretirement Benefit Plans, Defined Benefit

Assets Measured at Fair Value on Recurring Basis

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2015 and 2014 are as follows (000’s):

	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
2015
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	6,620	$	6,620	$	—	$	—
Equity Funds		7,554		7,554
Total Assets	$	14,174	$	14,174	$	—	$	—
2014
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	5,661	$	5,661	$	—	$	—
Index Funds		5,313		5,313
Equity Funds		1,866		1,866
Total Assets	$	12,840	$	12,840	$	—	$	—

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Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, Bcf in Billions	1 Months Ended	3 Months Ended								12 Months Ended
	Jan. 28, 2016 $ / shares	Dec. 31, 2015 USD ($) $ / shares Bcf	Sep. 30, 2015 $ / shares	Jun. 30, 2015 $ / shares	Mar. 31, 2015 $ / shares	Dec. 31, 2014 USD ($) $ / shares Bcf	Sep. 30, 2014 $ / shares	Jun. 30, 2014 $ / shares	Mar. 31, 2014 $ / shares	Dec. 31, 2015 USD ($) Entity Subsidiary mi $ / shares Bcf	Dec. 31, 2014 USD ($) $ / shares Bcf	Dec. 31, 2013 $ / shares
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Entity										3
Length Of Pipeline | mi										86
Depreciation rate based on average depreciable property balance										3.57%	3.56%	3.59%
Common stock dividend paid per share | $ / shares		$ 0.350	$ 0.350	$ 0.350	$ 0.350	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 1.40	$ 1.38	$ 1.38
Common stock dividend per share, declared | $ / shares										$ 1.40	$ 1.38	$ 1.38
Average interest rates										2.32%	1.56%	1.92%
Cost of removal obligation		$ 70,100,000				$ 63,800,000				$ 70,100,000	$ 63,800,000
Regulatory Assets		$ 126,400,000				$ 145,400,000				$ 126,400,000	$ 145,400,000
Number of Natural Gas Storage Outstanding | Bcf		2.5				2.4				2.5	2.4
Investments in trading securities		$ 700,000				$ 0				$ 700,000	$ 0
Intangible Assets, Purchase Adjustments										$ 7,200,000
Plant
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period										10 years
Bargain Purchase Adjustment
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period										3 years
Annual Electric Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM										27.00%
Annual Natural Gas Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM										11.00%
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period										3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits		2,300,000				6,300,000				$ 2,300,000	6,300,000
Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	$ 1.42
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits		0				0				$ 0	$ 0
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share | $ / shares										$ 0.350	$ 0.345	$ 0.345
Quarterly Dividends | Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	0.3550
Increase in dividend declared amount per share | $ / shares	$ 0.005
Deferred Storm Charges
Significant Accounting Policies [Line Items]
Regulatory Assets		15,400,000				$ 21,200,000				$ 15,400,000	$ 21,200,000
Deferred Storm Charges | Recovered over the next two and a half years
Significant Accounting Policies [Line Items]
Regulatory Assets		6,600,000								6,600,000
Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory Assets		$ 7,400,000								$ 7,400,000
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary										3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary										3

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Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 38.4	$ 48.5
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	26.8	37.8
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 11.6	$ 10.7

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Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Receivables [Line Items]
Total Exchange Gas Receivable	$ 11.1	$ 15.0
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	10.3	14.2
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.8	$ 0.8

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Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.8	$ 1.1
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.2	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.8
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.3	$ 0.2

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Regulatory Assets (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory Assets		$ 126.4	$ 145.4
Less: Current Portion of Regulatory Assets	[1]	26.8	37.8
Regulatory Assets-noncurrent		99.6	107.6
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets		11.2	11.0
Other Assets
Regulatory Assets [Line Items]
Regulatory Assets		5.3	5.8
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets		64.7	65.1
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory Assets		15.4	21.2
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets		8.5	9.7
Energy Supply & Other Regulatory Tracker Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets		$ 21.3	31.0
Deferred Restructuring Costs
Regulatory Assets [Line Items]
Regulatory Assets			$ 1.6

[1] Reflects amounts included in Accrued Revenue on the Company's Consolidated Balance Sheets and in the Accrued Revenue table shown above.

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Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 23.7	$ 8.8
Less: Current Portion of Regulatory Liabilities	15.6	8.7
Regulatory Liabilities-noncurrent	8.1	0.1
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	8.0	$ 8.8
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 15.7

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Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative Assets
Derivative Assets		$ 0.1
Derivative Liabilities
Derivative Liabilities	$ 0.0	0.0
Natural Gas Options Contract | Other Noncurrent Assets
Derivative Assets
Derivative Assets		0.1
Natural Gas Options Contract | Other Current Liabilities
Derivative Liabilities
Derivative Liabilities	0.0	0.0
Natural Gas Options Contract | Other Noncurrent Liabilities
Derivative Liabilities
Derivative Liabilities	$ 0.0	$ 0.0

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Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Cost of Gas Sales (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Natural Gas Options Contract
Regulatory Assets [Line Items]
Loss/(Gain) recognized in Regulatory Assets(Liabilities)		$ 0.3	$ (0.7)
Gas Purchase Costs
Regulatory Assets [Line Items]
Loss/(Gain) Reclassified into unaudited Consolidated Statement of Earnings	[1]	$ 0.2	$ (0.8)

[1] These amounts are offset in the Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

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Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 0.7	$ 0.0
Fair Value, Inputs, Level 1
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	0.7
Fair Value, Inputs, Level 1 | Equity Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	0.4
Fair Value, Inputs, Level 1 | Fixed Income Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 0.3

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Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 14.6	$ 22.1
Power Supply Contract Divestitures, Noncurrent	1.6	1.9
Total Energy Supply Obligations	16.2	24.0
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	10.3	14.2
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	4.0	7.4
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 0.3	$ 0.5

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Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 102.4	$ 74.7	$ 77.5	$ 172.2	$ 119.8	$ 76.6	$ 73.3	$ 156.1	$ 426.8	$ 425.8	$ 366.9
Operating Income	18.5	7.3	8.9	28.4	20.1	7.4	7.1	25.4	63.1	60.0	53.5
Net Income (Loss) Applicable to Common	$ 9.3	$ 1.7	$ 1.7	$ 13.6	$ 9.4	$ 1.6	$ 1.1	$ 12.6	$ 26.3	$ 24.7	$ 21.6
Per Share Data:
Earnings Per Common Share	$ 0.67	$ 0.12	$ 0.12	$ 0.98	$ 0.69	$ 0.11	$ 0.08	$ 0.91	$ 1.89	$ 1.79	$ 1.57
Dividends Paid Per Common Share	$ 0.350	$ 0.350	$ 0.350	$ 0.350	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 1.40	$ 1.38	$ 1.38

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015 Segment Entity Pipeline mi
Segment Reporting Information [Line Items]
No of segments | Segment	3
No of subsidiaries | Entity	3
Length Of Pipeline	86
Granite State Gas Transmission Inc
Segment Reporting Information [Line Items]
Length Of Pipeline	86
No of major pipeline | Pipeline	3

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Significant Segment Financial Data (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 102,400	$ 74,700	$ 77,500	$ 172,200	$ 119,800	$ 76,600	$ 73,300	$ 156,100	$ 426,800	$ 425,800	$ 366,900
Interest Income									1,900	1,300	3,200
Interest Expense									23,800	22,200	22,000
Depreciation & Amortization Expense									45,700	42,100	38,500
Income Tax Expense (Benefit)									15,443	13,995	12,652
Segment Profit	9,300	$ 1,700	$ 1,700	$ 13,600	9,400	$ 1,600	$ 1,100	$ 12,600	26,300	24,700	21,600
Segment Assets	1,046,400				1,000,200				1,046,400	1,000,200	920,600
Capital Expenditures									103,900	92,600	89,500
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									202,600	201,400	170,400
Interest Income									800	300	500
Interest Expense									13,300	11,500	11,000
Depreciation & Amortization Expense									20,700	18,800	17,200
Income Tax Expense (Benefit)									10,200	10,800	7,500
Segment Profit									15,300	15,800	12,500
Segment Assets	596,700				566,300				596,700	566,300	502,300
Capital Expenditures									64,900	62,300	61,100
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									218,000	218,700	190,700
Interest Income									700	600	2,200
Interest Expense									8,800	9,100	9,500
Depreciation & Amortization Expense									24,000	22,300	20,300
Income Tax Expense (Benefit)									5,500	4,500	5,100
Segment Profit									8,700	6,800	7,600
Segment Assets	416,800				414,100				416,800	414,100	402,800
Capital Expenditures									29,900	24,800	23,600
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									300	300	400
Interest Expense									1,700	1,600	1,500
Depreciation & Amortization Expense									900	1,000	1,000
Income Tax Expense (Benefit)									(1,100)	(1,900)	(700)
Segment Profit									1,000	1,200	300
Segment Assets	26,300				13,500				26,300	13,500	9,300
Capital Expenditures									9,000	5,200	4,800
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									6,200	5,700	5,800
Interest Income									100	100	100
Depreciation & Amortization Expense									100
Income Tax Expense (Benefit)									800	600	800
Segment Profit									1,300	900	1,200
Segment Assets	$ 6,600				$ 6,300				6,600	6,300	$ 6,200
Capital Expenditures									$ 100	$ 300

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Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 5.3	$ 6.0	$ 4.6
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 2.6	$ 2.6	$ 1.4

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Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	$ 1.8	$ 1.6	$ 1.9
Provision	5.3	6.0	4.6
Recoveries	0.7	0.6	0.4
Accounts Written Off	6.6	6.4	5.3
Balance at End of Period	1.2	1.8	1.6
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	1.3	1.3	1.1
Provision	2.5	2.9	2.6
Recoveries	0.3	0.3	0.2
Accounts Written Off	3.5	3.2	2.6
Balance at End of Period	0.6	1.3	1.3
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.4	0.2	0.7
Provision	2.8	3.1	2.0
Recoveries	0.4	0.3	0.2
Accounts Written Off	3.1	3.2	2.7
Balance at End of Period	0.5	0.4	0.2
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.1	0.1	0.1
Balance at End of Period	$ 0.1	$ 0.1	$ 0.1

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Debt and Financing Arrangements - Additional Information (Detail) - USD ($)			12 Months Ended
	Jul. 24, 2015	Oct. 04, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Oct. 30, 2015	Oct. 15, 2014
Line of Credit Facility [Line Items]
Amount available for the payment of dividends			$ 194,600,000
Retained earnings			$ 45,100,000	$ 38,400,000
Restriction on retained earnings for dividend payments			There were no restrictions on the Company's Retained Earnings at December 31, 2015 for the payment of dividends
Long term debt repayments			$ 7,400,000	$ 4,400,000	$ 500,000
Weighted average interest rate on short term borrowings			1.50%	1.60%	1.80%
Capital lease obligation, total capitalized cost						$ 13,400,000
Capital lease obligation, maturity period			Sep. 30, 2020
Accounts Payable			$ 33,300,000	$ 44,200,000
Total rental expense under operating leases			1,700,000	1,300,000	$ 1,200,000
Net Utility Plant			808,900,000	733,700,000
Capital lease obligations, current			3,100,000	500,000
Capital lease obligations, Noncurrent			11,000,000	7,500,000
Guarantee outstanding			19,300,000
Assets under Capital Leases
Line of Credit Facility [Line Items]
Net Utility Plant			15,300,000	9,700,000
Net Utility Plant, accumulated amortization			$ 800,000	800,000
Unitil Corporation | Maximum
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			70.00%
Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			65.00%
Northern Utilities Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			65.00%
Natural gas storage inventory			$ 10,800,000	15,100,000
Accounts Payable			$ 600,000	1,000,000
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			65.00%
Unitil Energy, Fitchburg, Northern Utilities and Granite State
Line of Credit Facility [Line Items]
Amount available for the payment of dividends			$ 163,100,000
Financing Arrangements
Line of Credit Facility [Line Items]
Capital lease obligations, current			2,600,000
Capital lease obligations, Noncurrent			10,400,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility			120,000,000	120,000,000
Proceeds from lines of credit			140,300,000	179,400,000
Repayments of lines of credit			$ 127,600,000	$ 210,300,000
4.42% Senior Unsecured Notes due October 15, 2044 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount							$ 50,000,000
Long-term debt, stated interest rate							4.42%
Long-term debt, maturity date			Oct. 15, 2044
8.00% Senior Secured Notes, Due August 1, 2017 | Unitil Realty Corp
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate			8.00%	8.00%
Long-term debt, maturity date			Aug. 01, 2017	Aug. 01, 2017
Senior Secured Notes			$ 1,100,000	$ 1,700,000
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate			7.15%	7.15%
Long-term debt, maturity date			Dec. 15, 2018	Dec. 15, 2018
Senior Notes			$ 10,000,000	$ 10,000,000
Bonds
Line of Credit Facility [Line Items]
Long term debt repayments			7,400,000	$ 4,400,000	$ 500,000
Debt repayment, 2016			17,400,000
Debt repayment, 2017			17,200,000
Debt repayment, 2018			30,100,000
Debt repayment, 2019			18,800,000
Debt repayment, 2020			19,800,000
Debt repayment, Thereafter			$ 222,200,000
Credit Facility | Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date		Oct. 04, 2018
Revolving credit facility		$ 120,000,000
Sublimit for the issuance of standby letters of credit		25,000,000
Credit Facility by an aggregate additional amount		$ 30,000,000
Percentage of capitalization			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.
Credit Facility | Revolving Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest		1.375%
Credit Facility | Amended Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date	Oct. 04, 2020
Credit Facility | Amended Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	1.25%

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Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 345.2	$ 380.6

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Details on Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-Term Debt	$ 325.5	$ 332.9
Less: Current Portion	17.4	4.0
Total Long-term Debt, Less Current Portion	308.1	328.9
Long-Term Debt	325.5	332.9
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	12.0	15.0
Long-Term Debt	12.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0
Long-Term Debt	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Long-Term Debt	15.0	15.0
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	11.4	15.2
Long-Term Debt	11.4	15.2
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0
Long-Term Debt	12.0	12.0
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0
Long-Term Debt	14.0	14.0
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0
Long-Term Debt	10.0	10.0
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Long-Term Debt	15.0	15.0
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30.0	30.0
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25.0	25.0
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50.0	50.0
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Senior Notes	50.0	50.0
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10.0	10.0
Unitil Realty Corp | 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 1.1	$ 1.7

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Details on Long Term Debt (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%
Debt instrument due date	May 01, 2022	May 01, 2022
First Mortgage Bonds 5.24% Series, Due March 2, 2020 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%
Debt instrument due date	Mar. 02, 2020	Mar. 02, 2020
First Mortgage Bonds 8.49% Series, Due October 14, 2024 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%
Debt instrument due date	Oct. 14, 2024	Oct. 14, 2024
First Mortgage Bonds 6.96% Series, Due September 1, 2028 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%
Debt instrument due date	Sep. 01, 2028	Sep. 01, 2028
First Mortgage Bonds 8.00% Series, Due May 1, 2031 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Debt instrument due date	May 01, 2031	May 01, 2031
First Mortgage Bonds 6.32% Series, Due September 15, 2036 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%
Debt instrument due date	Sep. 15, 2036	Sep. 15, 2036
6.75% Notes, Due November 30, 2023 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%
Debt instrument due date	Nov. 30, 2023	Nov. 30, 2023
7.37% Notes, Due January 15, 2029 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%
Debt instrument due date	Jan. 15, 2029	Jan. 15, 2029
7.98% Notes, Due June 1, 2031 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%
Debt instrument due date	Jun. 01, 2031	Jun. 01, 2031
6.79% Notes, Due October 15, 2025 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%
Debt instrument due date	Oct. 15, 2025	Oct. 15, 2025
5.90% Notes, Due December 15, 2030 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%
Debt instrument due date	Dec. 15, 2030	Dec. 15, 2030
6.95% Senior Notes, Series A, Due December 3, 2018 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%
Debt instrument due date	Dec. 03, 2018	Dec. 03, 2018
5.29% Senior Notes, Due March 2, 2020 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%
Debt instrument due date	Mar. 02, 2020	Mar. 02, 2020
7.72% Senior Notes, Series B, Due December 3, 2038 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%
Debt instrument due date	Dec. 03, 2038	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.42%	4.42%
Debt instrument due date	Oct. 15, 2044	Oct. 15, 2044
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%
Debt instrument due date	Dec. 15, 2018	Dec. 15, 2018
8.00% Senior Secured Notes, Due August 1, 2017 | Unitil Realty Corp
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Debt instrument due date	Aug. 01, 2017	Aug. 01, 2017

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Summary of Interest Expense and Interest Income (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest Expense
Long-Term Debt		$ 22.0	$ 20.5	$ 20.2
Short-Term Debt		0.9	1.1	1.2
Regulatory Liabilities		0.9	0.6	0.6
Interest Expense		23.8	22.2	22.0
Interest Income
Interest income		(1.9)	(1.3)	(3.2)
Total Interest Expense, net		21.9	20.9	18.8
Regulatory Assets
Interest Income
Interest income		(0.7)	(0.6)	(2.3)
AFUDC and Other
Interest Income
Interest income	[1]	$ (1.2)	$ (0.7)	$ (0.9)

[1] AFUDC-Allowance for Funds Used During Construction

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Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - Revolving Credit Facility - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving credit facility	$ 120,000,000	$ 120,000,000
Outstanding revolving credit facility	42,000,000	29,300,000
Available revolving credit facility	$ 78,000,000	$ 90,700,000

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Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Operating leases
2016	$ 1,326
2017	1,048
2018	698
2019	355
2020	180
2021 - 2025	125
Total Payments	3,732
Capital lease
2016	3,060
2017	2,937
2018	2,891
2019	2,851
2020	2,357
2021 - 2025	0
Total Payments	$ 14,096

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Equity - Additional Information (Detail) - USD ($)		12 Months Ended
	Jan. 26, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Common stock, shares outstanding		13,991,430	13,916,026
Common stock, share authorized		25,000,000	25,000,000
Common stock, shares issued		36,265	38,020	39,559
Proceeds from Issuance of Common Stock		$ 1,300,000	$ 1,200,000	$ 1,100,000
Common stock shares repurchase		1,981	2,763	2,969
Repurchase expense		$ 100,000	$ 100,000	$ 100,000
Share based compensation expense		$ 1,900,000	1,400,000	$ 700,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled		70.00%
Percentage of fully-vested restricted stock units that directors will receive in cash when settled		30.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash		$ 500,000	400,000
Preferred Stock		200,000	200,000
Maximum
Class of Stock [Line Items]
Dividend declared		$ 100,000	$ 100,000
Non Vested Restricted Stock
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share		36,941	0	4,481
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock		$ 1,300,000	$ 1,200,000	$ 1,100,000
Dividend and Distribution Reinvestment and Share Purchase Plan | Average
Class of Stock [Line Items]
Common stock price per share		$ 34.77
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued		36,265	38,020	39,559
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding		1,898	2,250
Preferred Stock		$ 200,000	$ 200,000
Dividend rate		6.00%	6.00%
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period		4 years
Restricted stock non-vested		70,761	67,334
Restricted stock weighted average grant date fair value		$ 32.56	$ 28.51
Unrecognized share based compensation		$ 1,100,000
Share compensation recognition period		2 years 4 months 24 days
Forfeitures or cancellations under the stock plan		871
Restricted Stock | Maximum
Class of Stock [Line Items]
Restricted stock available for awards		677,500
Restricted stock that may be awarded in any one calendar year to any one participant		20,000
Restricted Stock | Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually		25.00%
Subsequent Event | Restricted Stock
Class of Stock [Line Items]
Shares	43,220
Aggregate Market Value	$ 1,600,000

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Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) shares
Period 1
Class of Stock [Line Items]
Issuance Date	Feb. 04, 2013
Shares | shares	21,240
Aggregate Market Value | $	$ 0.6
Period 2
Class of Stock [Line Items]
Issuance Date	Jan. 31, 2014
Shares | shares	35,500
Aggregate Market Value | $	$ 1.1
Period 3
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2015
Shares | shares	40,010
Aggregate Market Value | $	$ 1.5

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Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Restricted Stock Units
Beginning Restricted Stock Units	23,576	14,903
Restricted Stock Units Granted	8,965	9,078
Dividend Equivalents Earned	1,047	701
Restricted Stock Units Settled		(1,106)
Ending Restricted Stock Units	33,588	23,576
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 29.90	$ 28.90
Restricted Stock Units Granted	36.54	31.23
Dividend Equivalents Earned	35.01	33.18
Restricted Stock Units Settled		29.49
Ending Restricted Stock Units	$ 31.83	$ 29.90

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Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders	$ 9.3	$ 1.7	$ 1.7	$ 13.6	$ 9.4	$ 1.6	$ 1.1	$ 12.6	$ 26.3	$ 24.7	$ 21.6
Weighted Average Common Shares Outstanding - Basic									13,917	13,843	13,773
Plus: Diluted Effect of Incremental Shares									3	4	2
Weighted Average Common Shares Outstanding - Diluted									13,920	13,847	13,775
Earnings per Share-Basic and Diluted	$ 0.67	$ 0.12	$ 0.12	$ 0.98	$ 0.69	$ 0.11	$ 0.08	$ 0.91	$ 1.89	$ 1.79	$ 1.57

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Energy Supply - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015 Bcf MMBTU
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities | MMBTU	115,000,000,000
Natural gas, underground storage | Bcf	3,600,000,000
Northern Utilities Inc | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities | MMBTU	14,057
Natural gas, underground storage | Bcf	0.33
Percentage of power supply requirement	50.00%
Power supply contract duration	12 months
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement	100.00%
Power supply contract duration	6 months

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Commitments and Contingencies - Additional Information (Detail) - USD ($)									3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 16, 2015	Apr. 15, 2015	Nov. 26, 2014	May. 30, 2014	Apr. 30, 2014	Apr. 21, 2014	Dec. 27, 2013	Apr. 25, 2013	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory Assets, Remaining Balance									$ 1,900,000		$ 1,900,000
Accrued Revenue									38,400,000		38,400,000	$ 48,500,000
Regulatory Assets									99,600,000		99,600,000	107,600,000
Current Portion of Regulatory Liabilities									15,600,000		15,600,000	8,700,000
Regulatory Liabilities - noncurrent									8,100,000		$ 8,100,000	$ 100,000
Maine | Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs											5 years
New Hampshire | Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs											7 years
Other Restructuring
Regulatory Assets [Line Items]
Accrued Revenue									300,000		$ 300,000
Regulatory Assets									1,600,000		$ 1,600,000
Cost recovery period, years											6 years
Environmental Matters
Regulatory Assets [Line Items]
Income (loss) incurred in excess of recorded amount											$ 0
Northern Utilities Inc
Regulatory Assets [Line Items]
Increase in annual revenue						$ 1,400,000
Amendment effective date											May 01, 2014
TIRA initial term											Four years
First annual TIRA Adjustment, effective date							May 01, 2014
Pipeline refund received		$ 22,000,000
Current Portion of Regulatory Liabilities									7,600,000		$ 7,600,000
Regulatory Liabilities - noncurrent									8,100,000		$ 8,100,000
Northern Utilities Inc | Maine
Regulatory Assets [Line Items]
Increase in annual revenue							$ 3,800,000
Amendment effective date											Jan. 01, 2014
Grace period to receive refund											3 years
Date to receive a refund as one-time lump sum payment											Oct. 05, 2015
Net gain on sale of property									900,000
Northern Utilities Inc | New Hampshire
Regulatory Assets [Line Items]
Increase in annual revenue						1,800,000
Amendment effective date											May 01, 2015
Grace period to receive refund											3 years
Northern Utilities Inc | New Hampshire | Natural Gas Distribution
Regulatory Assets [Line Items]
Increase in annual revenue						$ 4,600,000
Unitil Energy Systems Inc
Regulatory Assets [Line Items]
Amendment effective date											May 01, 2014
Date to receive a refund as one-time lump sum payment					May 01, 2016
Adjustment to recover the increased spending for vegetation management program and reliability enhancement program and a proposed storm resiliency program					$ 1,500,000
Interest rate allowed by regulators on the unrecovered amount of storm costs which have been approved for recovery through rate adjustments								4.52%
Construction expenditures			$ 400,000
Recovery of damage of electrical system			1,700,000
Unitil Energy Systems Inc | Storm Costs
Regulatory Assets [Line Items]
Cost recovery period, years								5 years
Recovery amount								$ 2,300,000
Storm expenditures			2,100,000
Granite State Gas Transmission Inc | Gas Transportation and Storage
Regulatory Assets [Line Items]
Increase in annual revenue										$ 400,000
Amendment effective date										Aug. 01, 2015
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Cost recovery period, years				5 years
Increase in annual revenue				$ 5,600,000
Amendment effective date											May 01, 2016
Percentage of approved return on equity				9.70%
Percentage of approved common equity ratio				48.00%
Annual funding amount approved				$ 500,000
Recovery amount				$ 900,000
Storm expenditures			200,000
Construction expenditures			100,000
Fitchburg Gas and Electric Light Company | Amendment Agreement [Member]
Regulatory Assets [Line Items]
Amendment effective date											Jun. 01, 2014
Fitchburg Gas and Electric Light Company | Cumulative capital investments for April 30, 2015
Regulatory Assets [Line Items]
Recovery amount									300,000		$ 300,000
Fitchburg Gas and Electric Light Company | Cumulative capital investments for 2015 and 2016
Regulatory Assets [Line Items]
Recovery amount									$ 900,000		$ 900,000
Fitchburg Gas and Electric Light Company | Electric base
Regulatory Assets [Line Items]
Increase in annual revenue	$ 3,800,000
Percentage of approved return on equity	5.60%
Fitchburg Gas and Electric Light Company | Gas base
Regulatory Assets [Line Items]
Increase in annual revenue	$ 3,000,000
Percentage of approved return on equity	8.30%
Fitchburg Gas and Electric Light Company | Storm Costs
Regulatory Assets [Line Items]
Cost recovery period, years				3 years
Deferred emergency storm repair costs incurred				$ 5,000,000
Storm expenditures			$ 300,000	$ 5,000,000

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Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	$ 5.5	$ 14.8
Additions	2.9	1.3
Less: Payments / Reductions	5.6	10.6
Total Balance at End of period	2.8	5.5
Less: Current Portion			$ 1.3	$ 3.5
Noncurrent Balance			1.5	2.0
Total Balance at End of period	5.5	14.8	2.8	5.5
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	1.9	12.0
Less: Payments / Reductions	0.7	10.1
Total Balance at End of period	1.2	1.9
Less: Current Portion			0.2	1.9
Noncurrent Balance			1.0
Total Balance at End of period	1.9	12.0	1.2	1.9
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	3.6	2.8
Additions	2.9	1.3
Less: Payments / Reductions	4.9	0.5
Total Balance at End of period	1.6	3.6
Less: Current Portion			1.1	1.6
Noncurrent Balance			0.5	2.0
Total Balance at End of period	$ 3.6	$ 2.8	$ 1.6	$ 3.6

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Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	$ 12,413	$ 10,809	$ 10,052
Total Federal Tax Provision	12,413	10,809	10,052
State
Current	3,530	(387)	386
Deferred	(500)	3,573	2,214
Total State Tax Provision	3,030	3,186	2,600
Total Provision for Federal and State Income Taxes	15,443	13,995	12,652
Operating Loss Carryforwards
Current Federal Tax Provision (Benefit)
Current Federal Tax Provision (Benefit)	(3,710)	(3,179)
Utility Plant Differences
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	17,924	10,649	28,907
Net Operating Loss Carryforwards Carrybacks
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	2,374	2,589	(8,053)
Regulatory Assets and Liabilities
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	(6,101)	(5,946)	(11,483)
Other, net
Deferred Federal Tax Provision (Benefit)
Deferred Federal Tax Provision (Benefit)	(1,784)	3,517	$ 681
Operating Income
Current Federal Tax Provision (Benefit)
Current Federal Tax Provision (Benefit)	$ 3,710	$ 3,179

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Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	34.00%	34.00%	34.00%
State Income Taxes, net	5.00%	2.00%	5.00%
Utility Plant Differences	(2.00%)	(1.00%)	(2.00%)
Tax Credits and Other, net		1.00%
Effective Income Tax Rate	37.00%	36.00%	37.00%

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Deferred Tax Assets and Liabilities, Current (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current Deferred Income Taxes
Accrued Revenue, Current Portion	$ 5,090	$ (3,038)
Other, net	(348)	(90)
Total Current Deferred Income Tax Assets (Liabilities)	$ 4,742	$ (3,128)

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Deferred Tax Assets and Liabilities Current, Non Current (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Schedule of Deferred Tax Assets and Liabilities [Line Items]
Utility Plant Differences	$ 141,185	$ 120,534
Retirement Benefit Obligations	(43,543)	(44,829)
Net Operating Loss Carryforwards	(10,500)	(13,122)
Regulatory Assets & Liabilities	10,535	12,740
AMT Tax Credit Carryforwards	(2,677)	(2,139)
Other, net	(2,792)	(314)
Total Noncurrent Deferred Income Tax Liabilities	$ 92,208	$ 72,870

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Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Federal NOL carryforward assets utilized	$ 3,700,000
Cumulative federal NOL carryforward assets available to offset against taxes payable	11,300,000
Alternative Minimum tax credit carryforwards	2,677,000	$ 2,139,000
Income tax benefit	15,443,000	$ 13,995,000	$ 12,652,000
Federal Research and Development Tax Credit | 2014 expenditures
Operating Loss Carryforwards [Line Items]
Income tax benefit	63,000
Federal Research and Development Tax Credit | 2015 expenditures
Operating Loss Carryforwards [Line Items]
Income tax benefit	$ 288,000
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date	2029
Federal
Operating Loss Carryforwards [Line Items]
Tax examination description	The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2012; December 31, 2013; and December 31, 2014.

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Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	[1]	4.00%	4.80%	4.00%
Rate of Compensation Increase		3.00%	3.00%	3.00%
Expected Long-term rate of return on plan assets		8.00%	8.00%	8.50%
Health Care Cost Trend Rate Assumed for Next Year		7.00%	8.00%	8.00%
Ultimate Health Care Cost Trend Rate		4.00%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached		2018	2018	2017
Effect of 1% Increase in Health Care Cost Trend Rate		$ 1,383	$ 989	$ 1,169
Effect of 1% Decrease in Health Care Cost Trend Rate		$ (1,040)	$ (771)	$ (895)
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		4.30%	4.00%	4.80%
Rate of Compensation Increase		3.00%	3.00%	3.00%
Health Care Cost Trend Rate Assumed for Next Year		7.00%	7.00%	8.00%
Ultimate Health Care Cost Trend Rate		4.00%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached		2022	2018	2018
Effect of 1% Increase in Health Care Cost Trend Rate		$ 14,877	$ 15,325	$ 9,957
Effect of 1% Decrease in Health Care Cost Trend Rate		$ (11,611)	$ (11,829)	$ (7,942)

[1] As a result of the addition of a plan participant to the SERP in July 2015, the Company was required to update the discount rate used in determining SERP costs for the remainder of 2015. Based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves at that time, the Company assumed a discount rate of 4.30% for the SERP from July through December of 2015.

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Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Parenthetical) (Detail)	6 Months Ended
	Dec. 31, 2015
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.30%

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Retirement Benefit Plans - Additional Information (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Change in Discount Rate			0.25%
Increase or decrease of Net Periodic Benefit Cost (NPBC) due to change in the discount rate			$ 472,000
Pension expense			7,300,000	$ 4,900,000	$ 6,600,000
Regulatory Assets			$ 126,400,000	145,400,000
Defined Benefit Plan, Expected Long-term Rate-of-Return on Assets Assumption			The desired investment objective is a long-term rate of return on assets that is approximately 5 - 6% greater than the assumed rate of inflation as measured by the Consumer Price Index.
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Amortizations related to Actuarial Loss and Prior Service Cost			$ 4,700,000
Accumulated Benefit Obligation			126,800,000	121,800,000
Company's contributions			4,215,000	4,191,000	3,700,000
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Amortizations related to Actuarial Loss and Prior Service Cost			2,500,000
Company's contributions			4,000,000	3,650,000	3,280,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Amortizations related to Actuarial Loss and Prior Service Cost			300,000
Accumulated Benefit Obligation			7,000,000	6,300,000
Company's contributions			40,000	53,000	53,000
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense			7,300,000	4,300,000	6,600,000
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory Assets			64,700,000	65,100,000
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Company's contributions			$ 2,098,000	$ 1,877,000	$ 1,678,000
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Long-term Return on Assets			8.00%	8.00%	8.50%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations		47.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations		37.00%
Scenario Forecast | Pension Plans | Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	[1]	6.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations		55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations		45.00%
Real Estate Funds | Scenario Forecast | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations		10.00%

[1] Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

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Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	$ 3,689	$ 3,006	$ 3,573
Interest Cost	5,392	5,092	4,567
Expected Return on Plan Assets	(6,779)	(6,245)	(5,955)
Prior Service Cost Amortization	265	211	208
Actuarial Loss Amortization	4,714	2,847	4,229
Sub-total	7,281	4,911	6,622
Amounts Capitalized or Deferred	(3,397)	(1,881)	(2,929)
NPBC Recognized	3,884	3,030	3,693
Other Postretirement Benefit Plans, Defined Benefit
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	2,622	1,988	2,523
Interest Cost	2,918	2,686	2,448
Expected Return on Plan Assets	(1,093)	(920)	(722)
Prior Service Cost Amortization	1,682	1,682	1,701
Actuarial Loss Amortization	1,150	56	786
Sub-total	7,279	5,492	6,736
Amounts Capitalized or Deferred	(3,423)	(2,270)	(3,010)
NPBC Recognized	3,856	3,222	3,726
Supplemental Employee Retirement Plans, Defined Benefit
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	120	57	73
Interest Cost	330	272	241
Prior Service Cost Amortization	85	11	11
Actuarial Loss Amortization	327	100	184
Sub-total	862	440	509
NPBC Recognized	$ 862	$ 440	$ 509

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Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Plan Assets at Beginning of Year	$ 86,744	$ 82,551
Actual Return on Plan Assets	645	4,248
Employer Contributions	4,215	4,191	$ 3,700
Benefits Paid	(4,410)	(4,246)	(3,764)
Plan Assets at End of Year	87,194	86,744	82,551
PBO at Beginning of Year	136,662	108,295
Service Cost	3,689	3,006	3,573
Interest Cost	5,392	5,092	4,567
Plan Amendments	474
Benefits Paid	(4,410)	(4,246)	(3,764)
Actuarial (Gain) or Loss	(991)	24,515
PBO at End of Year	140,816	136,662	108,295
Funded Status: Assets vs PBO	(53,622)	(49,918)
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Plan Assets at Beginning of Year	12,840	10,829
Actual Return on Plan Assets	(214)	486
Employer Contributions	4,000	3,650	3,280
Participant Contributions	63	59	36
Benefits Paid	(2,515)	(2,184)	(1,942)
Plan Assets at End of Year	14,174	12,840	10,829
PBO at Beginning of Year	73,923	56,899
Service Cost	2,622	1,988	2,523
Interest Cost	2,918	2,686	2,448
Participant Contributions	63	59	36
Benefits Paid	(2,515)	(2,184)	(1,942)
Actuarial (Gain) or Loss	(762)	14,475
PBO at End of Year	76,249	73,923	56,899
Funded Status: Assets vs PBO	(62,075)	(61,083)
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Employer Contributions	40	53	53
Benefits Paid	(40)	(53)	(53)
PBO at Beginning of Year	7,965	5,857
Service Cost	120	57	73
Interest Cost	330	272	241
Plan Amendments	608
Benefits Paid	(40)	(53)	(53)
Actuarial (Gain) or Loss	194	1,832
PBO at End of Year	9,177	7,965	$ 5,857
Funded Status: Assets vs PBO	$ (9,177)	$ (7,965)

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Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 4,215	$ 4,191	$ 3,700
Benefit Payments	4,410	4,246	3,764
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	4,000	3,650	3,280
Participant Contributions	63	59	36
Benefit Payments	2,515	2,184	1,942
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	40	53	53
Benefit Payments	$ 40	$ 53	$ 53

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Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2015 USD ($)
Pension Plans
Schedule of Pension Expected Future Benefit Payments [Line Items]
2016	$ 5,181
2017	5,522
2018	5,560
2019	6,086
2020	6,345
2021 - 2025	37,857
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2016	2,178
2017	2,318
2018	2,503
2019	2,700
2020	2,866
2021 - 2025	17,932
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2016	426
2017	421
2018	416
2019	475
2020	469
2021 - 2025	$ 3,027

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Actual Investment Allocations (Detail)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Pension Plans | Equity Funds
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			46.00%	49.00%	54.00%
Pension Plans | Fixed Income Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			37.00%	36.00%	32.00%
Pension Plans | Equity And Debt Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation	[1]		6.00%	5.00%	5.00%
Pension Plans | Other
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation	[2]		0.00%	0.00%	8.00%
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			53.00%	56.00%	57.00%
Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			47.00%	44.00%	43.00%
Scenario Forecast | Pension Plans | Equity Funds
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation		47.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation		37.00%
Scenario Forecast | Pension Plans | Equity And Debt Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation	[1]	6.00%
Scenario Forecast | Pension Plans | Other
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation	[2]	0.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation		55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation		45.00%
Real Estate Funds | Pension Plans
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Actual Allocation			11.00%	10.00%	1.00%
Real Estate Funds | Scenario Forecast | Pension Plans
Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]
Target Allocation		10.00%

[1] Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.

[2] Represents investments being held in cash equivalents as of December 31, 2013 pending transfer into a Real Estate Fund.

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Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	$ 87,194	$ 86,744
Equity Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	40,124	42,760
Fixed Income Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	32,192	31,136
Equity And Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	5,527	4,676
Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	77,843	78,572
Fair Value, Inputs, Level 1 | Equity Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	40,124	42,760
Fair Value, Inputs, Level 1 | Fixed Income Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	32,192	31,136
Fair Value, Inputs, Level 1 | Equity And Debt Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	5,527	4,676
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	9,351	8,172
Real Estate Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	9,351	8,172
Real Estate Funds | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets measured at fair value on recurring basis	$ 9,351	$ 8,172

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Fair Value of Pension Plan Investments Estimated using Net Asset Value (Detail) - SEI Core Property Collective Investment Trust Fund - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	[1]	$ 9,351	$ 8,172
Unfunded Commitment	[1]	$ 0	$ 0
Redemption on Frequency	[1]	Quarterly	Quarterly
Redemption on Notice Period	[1]	65 days	65 days

[1] The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

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Summary of Changes in the Fair Value of the Pension Plan Level 3 Assets (Detail) - SEI Core Property Collective Investment Trust Fund - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	[1]	$ 8,172
Actual Return on Investments:
Plan Assets at End of Year	[1]	9,351	$ 8,172
Fair Value, Inputs, Level 3
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year		8,172	1,125
Actual Return on Investments:
Related to Investments Held at Year-End		1,179	672
Related to Investments Sold During the Year		0	0
Total Return on Investments		1,179	672
Purchases, Sales and Settlements			6,375
Plan Assets at End of Year		$ 9,351	$ 8,172

[1] The SEI Core Property Collective Investment Trust Fund, through the SEI Core Property Fund, seeks both current income and long-term capital appreciation through investing in underlying funds that acquire, manage, and dispose of commercial real estate properties.

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Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	$ 14,174	$ 12,840
Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	6,620	5,661
Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis		5,313
Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	7,554	1,866
Fair Value, Inputs, Level 1
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	14,174	12,840
Fair Value, Inputs, Level 1 | Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	6,620	5,661
Fair Value, Inputs, Level 1 | Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis		5,313
Fair Value, Inputs, Level 1 | Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	$ 7,554	$ 1,866