Unitil (UTL) 10-K 28 Jan 16 2015 FY Annual report Financial data

Document and Entity Information

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	2,015
Document Fiscal Period Focus	FY
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	755,001
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

CONSOLIDATED STATEMENTS OF EARN

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

CONSOLIDATED BALANCE SHEETS

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

CONSOLIDATED BALANCE SHEETS (Pa

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

CONSOLIDATED STATEMENTS OF CASH

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)	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
Other, net	4.2	(2.6)	3.1
Cash Provided by Operating Activities	115.1	84	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
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)	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)	(0.4)
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

CONSOLIDATED STATEMENTS OF CHAN

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	$ 30.4
Net Income	21.6		21.6
Dividends	(19.1)		(19.1)
Shares Issued Under Stock Plans	1	1
Issuance of Common Shares	1.1	1.1
Ending Balance at Dec. 31, 2013	265	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

CONSOLIDATED STATEMENTS OF CHA7

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

Summary of Significant Accounti

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 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 Use of Estimates Fair Value 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 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 Depreciation and Amortization Stock-based Employee Compensation Sales and Consumption Taxes Income Taxes 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 Cash and Cash Equivalents Allowance for Doubtful Accounts Accrued Revenue 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 (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 (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 Regulatory Accounting 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 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 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 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 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 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 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 Commitments and Contingencies Environmental Matters Recently Issued Pronouncements 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

Quarterly Financial Information

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

Segment Information

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

Allowance for Doubtful Accounts

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 Provision Recoveries Accounts Balance at 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

Debt and Financing Arrangements

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 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 Debt Repayment 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 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 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.

Equity

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 Common Shares Repurchased, Cancelled and Retired During 2015, 2014 and 2013, the Company did not cancel or retire any of its common stock. Stock-Based Compensation Plans Stock Plan 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 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.

Energy Supply

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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies	Note 8: Commitments and Contingencies Regulatory Matters Overview— 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— Northern Utilities—Base Rates—New Hampshire— Northern Utilities—Pipeline Refund— Unitil Energy—Base Rates— Granite State—Base Rates— Fitchburg—Base Rates—Electric— 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— 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— Northern Utilities—Other— Fitchburg—Electric Operations— On November 17, 2015, Fitchburg submitted its 2015 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were 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— Fitchburg—Service Quality— Amendments to MDPU Service Quality Guidelines— Fitchburg—Other— 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— 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 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 — 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 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

Income Taxes

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.

Retirement Benefit Plans

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 2016 Actual Allocation at 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 2016 Actual Allocation at 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 Quoted Significant Significant 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 Unfunded Redemption Redemption 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 Quoted Significant Significant 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’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.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Nature of Operations	Nature of Operations 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
Use of Estimates	Use of Estimates
Fair Value	Fair Value 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 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
Depreciation and Amortization	Depreciation and Amortization
Stock-based Employee Compensation	Stock-based Employee Compensation
Sales and Consumption Taxes	Sales and Consumption Taxes
Income Taxes	Income Taxes 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
Cash and Cash Equivalents	Cash and Cash Equivalents
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts
Accrued Revenue	Accrued Revenue 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 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 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
Regulatory Accounting	Regulatory Accounting 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 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 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 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
Energy Supply Obligations	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 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 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
Commitments and Contingencies	Commitments and Contingencies
Environmental Matters	Environmental Matters
Recently Issued Pronouncements	Recently Issued Pronouncements 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

Summary of Significant Accoun19

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 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

Quarterly Financial Informati20

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

Segment Information (Tables)

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

Allowance for Doubtful Accoun22

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 Provision Recoveries Accounts Balance at 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

Debt and Financing Arrangemen23

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

Equity (Tables)

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 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

Commitments and Contingencies (

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 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

Income Taxes (Tables)

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

Retirement Benefit Plans (Table

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 2016 Actual Allocation at 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 2016 Actual Allocation at 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 Unfunded Redemption Redemption 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 Quoted Significant Significant 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 Quoted Significant Significant 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 $ — $ —

Summary of Significant Accoun28

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, 2015USD ($)$ / sharesBcf	Sep. 30, 2015$ / shares	Jun. 30, 2015$ / shares	Mar. 31, 2015$ / shares	Dec. 31, 2014USD ($)$ / sharesBcf	Sep. 30, 2014$ / shares	Jun. 30, 2014$ / shares	Mar. 31, 2014$ / shares	Dec. 31, 2015USD ($)EntitySubsidiarymi$ / sharesBcf	Dec. 31, 2014USD ($)$ / sharesBcf	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

Components of Accrued Revenue (

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

Exchange Gas Receivable (Detail

Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Receivables [Line Items]
Total Exchange Gas Receivable	$ 11.1	$ 15
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

Components of Gas Inventory (De

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

Regulatory Assets (Detail)

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
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
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.

Regulatory Liabilities (Detail)

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	$ 8.8
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 15.7

Fair Value Amount of Derivative

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
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
Natural Gas Options Contract | Other Noncurrent Liabilities
Derivative Liabilities
Derivative Liabilities	$ 0	$ 0

Regulatory Assets Liabilities a

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.

Fair Value of Marketable Securi

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
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

Energy Supply Obligations (Deta

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
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	7.4
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 0.3	$ 0.5

Quarterly Financial Informati38

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	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

Segment Information - Additiona

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015SegmentEntityPipelinemi
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

Significant Segment Financial D

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

Allowance for Doubtful Accoun41

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	$ 4.6
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 2.6	$ 2.6	$ 1.4

Activity in Company's Allowance

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	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
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

Debt and Financing Arrangemen43

Debt and Financing Arrangements - Additional Information (Detail) - USD ($)	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. 1, 2017	Aug. 1, 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. 4, 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. 4, 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%

Estimated Fair Value of Long Te

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

Details on Long Term Debt (Deta

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
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	20
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15	15
Long-Term Debt	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	12	15
Long-Term Debt	12	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20	20
Long-Term Debt	20	20
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15	15
Long-Term Debt	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15	15
Long-Term Debt	15	15
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	12
Long-Term Debt	12	12
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14	14
Long-Term Debt	14	14
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10	10
Long-Term Debt	10	10
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15	15
Long-Term Debt	15	15
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30	30
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25	25
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50	50
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Senior Notes	50	50
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10	10
Unitil Realty Corp | 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 1.1	$ 1.7

Details on Long Term Debt (Pare

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 1, 2022	May 1, 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. 2, 2020	Mar. 2, 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. 1, 2028	Sep. 1, 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 1, 2031	May 1, 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. 1, 2031	Jun. 1, 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. 3, 2018	Dec. 3, 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. 2, 2020	Mar. 2, 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. 3, 2038	Dec. 3, 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. 1, 2017	Aug. 1, 2017

Summary of Interest Expense and

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	$ 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
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

Borrowing Limits Amounts Outsta

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

Future Operating Lease Payment

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Operating leases
2,016	$ 1,326
2,017	1,048
2,018	698
2,019	355
2,020	180
2021 - 2025	125
Total Payments	3,732
Capital lease
2,016	3,060
2,017	2,937
2,018	2,891
2,019	2,851
2,020	2,357
2021 - 2025	0
Total Payments	$ 14,096

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($)	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

Restricted Shares Issued in Con

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)shares
Period 1
Class of Stock [Line Items]
Issuance Date	Feb. 4, 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

Restricted Stock Units Issued (

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

Reconciliation of Basic and Dil

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

Energy Supply - Additional Info

Energy Supply - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015BcfMMBTU
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

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($)

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 1, 2014

TIRA initial term

Four years

First annual TIRA Adjustment, effective date

May 1, 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. 1, 2014

Grace period to receive refund

3 years

Date to receive a refund as one-time lump sum payment

Oct. 5, 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 1, 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 1, 2014

Date to receive a refund as one-time lump sum payment

May 1, 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. 1, 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 1, 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. 1, 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

Company's Liability for Environ

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
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
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
Total Balance at End of period	1.9	12	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
Total Balance at End of period	$ 3.6	$ 2.8	$ 1.6	$ 3.6

Provisions for Federal and Stat

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

Differences Between Provisions

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%

Deferred Tax Assets and Liabili

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)

Deferred Tax Assets and Liabi60

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

Income Taxes - Additional Infor

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	2,029
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.

Key Weighted Average Assumption

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		2,018	2,018	2,017
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		2,022	2,018	2,018
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.

Key Weighted Average Assumpti63

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%

Retirement Benefit Plans - Addi

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.

Components of Retirement Plan C

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

Summary of Information on Plans

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)

Employer Contributions, Partici

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

Estimated Future Benefit Paymen

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Pension Plans
Schedule of Pension Expected Future Benefit Payments [Line Items]
2,016	$ 5,181
2,017	5,522
2,018	5,560
2,019	6,086
2,020	6,345
2021 - 2025	37,857
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2,016	2,178
2,017	2,318
2,018	2,503
2,019	2,700
2,020	2,866
2021 - 2025	17,932
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2,016	426
2,017	421
2,018	416
2,019	475
2,020	469
2021 - 2025	$ 3,027

Actual Investment Allocations (

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.

Assets Measured at Fair Value o

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

Fair Value of Pension Plan Inve

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.

Summary of Changes in the Fair

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.

Assets Measured at Fair Value73

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