Unitil (UTL) 10-K 1 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 29, 2018	Jun. 30, 2017
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
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		14,816,931
Entity Public Float			$ 665,078,163

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Revenues:
Gas	$ 194,000	$ 181,200	$ 202,600
Electric	206,200	196,100	218,000
Other	6,000	6,100	6,200
Total Operating Revenues	406,200	383,400	426,800
Operating Expenses:
Cost of Gas Sales	84,300	77,600	100,700
Cost of Electric Sales	114,000	108,000	132,500
Operation and Maintenance	70,200	66,300	67,100
Depreciation and Amortization	46,900	46,600	45,700
Taxes Other Than Income Taxes	21,100	19,600	17,700
Total Operating Expenses	336,500	318,100	363,700
Operating Income	69,700	65,300	63,100
Interest Expense, net	23,100	22,500	21,900
Other Expense (Income), net	100	300	(500)
Income Before Income Taxes	46,500	42,500	41,700
Income Taxes	17,537	15,354	15,443
Net Income Applicable to Common Shares	$ 29,000	$ 27,100	$ 26,300
Earnings per Common Share-Basic and Diluted	$ 2.06	$ 1.94	$ 1.89
Weighted Average Common Shares Outstanding-(Basic and Diluted)	14.1	14	13.9

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and Cash Equivalents	$ 8.9	$ 5.8
Accounts Receivable, net	67.4	52.9
Accrued Revenue	53.3	49.5
Exchange Gas Receivable	5.8	8.3
Gas Inventory	0.6	0.6
Materials and Supplies	6.9	6.8
Prepayments and Other	8.4	7.7
Total Current Assets	151.3	131.6
Utility Plant:
Gas	699.6	629.5
Electric	476.7	437.9
Common	67.4	35.8
Construction Work in Progress	35.5	70.2
Utility Plant	1,279.2	1,173.4
Less: Accumulated Depreciation	307.7	290
Net Utility Plant	971.5	883.4
Other Noncurrent Assets:
Regulatory Assets	109.6	104.1
Other Assets	9.5	9.1
Total Other Noncurrent Assets	119.1	113.2
TOTAL ASSETS	1,241.9	1,128.2
Current Liabilities:
Accounts Payable	41.5	32.4
Short-Term Debt	38.3	81.9
Long-Term Debt, Current Portion	29.8	16.8
Regulatory Liabilities	9.2	10.4
Energy Supply Obligations	9.7	12
Environmental Obligations	0.5	0.4
Capital Lease Obligations	3.1	3
Other Current Liabilities	18.9	20
Total Current Liabilities	151	176.9
Noncurrent Liabilities:
Retirement Benefit Obligations	150.1	149
Deferred Income Taxes, net	82.9	97.9
Cost of Removal Obligations	84.3	77
Regulatory Liabilities	48.9	2.6
Capital Lease Obligations	5.7	8.3
Environmental Obligations	1.6	1.5
Other Noncurrent Liabilities	4.3	5.1
Total Noncurrent Liabilities	377.8	341.4
Capitalization:
Long-Term Debt, Less Current Portion	376.3	316.8
Stockholders' Equity:
Common Equity (Outstanding 14,815,585 and 14,065,230 Shares)	275.8	240.7
Retained Earnings	60.8	52.2
Total Common Stock Equity	336.6	292.9
Preferred Stock	0.2	0.2
Total Stockholders' Equity	336.8	293.1
Total Capitalization	713.1	609.9
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,241.9	$ 1,128.2

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Common Equity Outstanding	14,815,585	14,065,230

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Activities:
Net Income	$ 29	$ 27.1	$ 26.3
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	46.9	46.6	45.7
Deferred Tax Provision	17.5	15.4	11.9
Changes in Working Capital Items:
Accounts Receivable	(14.5)	(5.4)	10.9
Accrued Revenue	(3.8)	(11.1)	10.1
Regulatory Liabilities	(1.2)	(5.2)	6.9
Exchange Gas Receivable	2.5	2.8	3.9
Accounts Payable	9.1	(0.9)	(10.9)
Other Changes in Working Capital Items	(1.8)	(1)	(2.4)
Deferred Regulatory and Other Charges	(6.1)	(5)	8.2
Other, net	8.6	5	4.5
Cash Provided by Operating Activities	86.2	68.3	115.1
Investing Activities:
Property, Plant and Equipment Additions	(119.3)	(98.1)	(103.9)
Cash Used In Investing Activities	(119.3)	(98.1)	(103.9)
Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net	(43.6)	39.9	12.7
Issuance of Long-Term Debt	89.3	30
Repayment of Long-Term Debt	(17.2)	(19)	(7.4)
(Decrease) Increase in Capital Lease Obligations	(2.5)	(2.8)	6.1
Net (Decrease) Increase in Exchange Gas Financing	(2.4)	(2.5)	(4)
Dividends Paid	(20.4)	(20)	(19.6)
Proceeds from Issuance of Common Stock	33	1.3	1.3
Cash Provided by (Used In) Financing Activities	36.2	26.9	(10.9)
Net Increase (Decrease) in Cash	3.1	(2.9)	0.3
Cash at Beginning of Year	5.8	8.7	8.4
Cash at End of Year	8.9	5.8	8.7
Supplemental Information:
Interest Paid	23	22.1	22.3
Income Taxes Paid		1.6	1.8
Payments on Capital Leases	3.3	3.4	1.1
Capital Expenditures Included in Accounts Payable	$ 1.1	0.3	$ 0.4
Non-Cash Additions to Property, Plant and Equipment		$ 3.5

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Dividend and Distribution Reinvestment and Share Purchase Plan	Registered Public Offering	Common Equity	Common EquityDividend and Distribution Reinvestment and Share Purchase Plan	Common EquityRegistered Public Offering	Retained Earnings
Beginning 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
Net Income	27.1						27.1
Dividends	(20)						(20)
Shares Issued Under Stock Plans	1.9			1.9
Issuance of Common Shares	1.3			1.3
Ending Balance at Dec. 31, 2016	292.9			240.7			52.2
Net Income	29						29
Dividends	(20.4)						(20.4)
Shares Issued Under Stock Plans	2.1			2.1
Issuance of Common Shares		$ 1.3	$ 31.7		$ 1.3	$ 31.7
Ending Balance at Dec. 31, 2017	$ 336.6			$ 275.8			$ 60.8

CONSOLIDATED STATEMENTS OF CHA7

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Dividends per Common Share	$ 1.44	$ 1.42	$ 1.40
Common stock, shares issued		32,095	36,265
Dividend and Distribution Reinvestment and Share Purchase Plan
Common stock, shares issued	26,256
Registered Public Offering
Common stock, shares issued	690,000

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies	Note 1: Summary of Significant Accounting Policies Nature of Operations non-regulated 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 and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated 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 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 deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. Dividends Cash and Cash Equivalents (ISO-NE) ISO-NE. 2-1/2 ISO-NE Allowance for Doubtful Accounts written-off shut-off. Accrued Revenue Accrued Revenue (millions) December 31, 2017 2016 Regulatory Assets—Current $ 39.5 $ 37.9 Unbilled Revenues 13.8 11.6 Total Accrued Revenue $ 53.3 $ 49.5 Exchange Gas Receivable Exchange Gas Receivable (millions) December 31, 2017 2016 Northern Utilities $ 5.4 $ 7.8 Fitchburg 0.4 0.5 Total Exchange Gas Receivable $ 5.8 $ 8.3 Gas Inventory Gas Inventory (millions) December 31, 2017 2016 Natural Gas $ 0.4 $ 0.3 Propane 0.1 0.2 Liquefied Natural Gas & Other 0.1 0.1 Total Gas Inventory $ 0.6 $ 0.6 Utility Plant Regulatory Accounting Regulatory Assets consist of the following (millions) December 31, 2017 2016 Retirement Benefits $ 84.5 $ 75.9 Energy Supply & Other Rate Adjustment Mechanisms 36.0 32.7 Deferred Storm Charges 7.2 9.6 Environmental 9.5 10.8 Income Taxes 6.5 7.3 Other 5.4 5.7 Total Regulatory Assets $ 149.1 $ 142.0 Less: Current Portion of Regulatory Assets (1) 39.5 37.9 Regulatory Assets—noncurrent $ 109.6 $ 104.1 (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, 2017 2016 Rate Adjustment Mechanisms $ 6.9 $ 6.2 Gas Pipeline Refund (Note 8) 2.3 6.8 Income Taxes (Note 9) 48.9 — Total Regulatory Liabilities 58.1 13.0 Less: Current Portion of Regulatory Liabilities 9.2 10.4 Regulatory Liabilities—noncurrent $ 48.9 $ 2.6 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, 2017 are $0.9 million of deferred storm charges to be recovered over the next year and $7.6 million of environmental and 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 through the purchase of European call option contracts. Any gains or losses resulting from these option contracts are passed through to customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause. As of December 31, 2017 and December 31, 2016, the Company had 0.6 billion and 2.0 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. Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of: Fair Value Description Balance Sheet Location December 31, December 31, Derivative Assets Natural Gas Futures / Options Contracts Prepayments and Other $ — $ 0.1 Natural Gas Futures / Options Contracts Other Noncurrent Assets — 0.3 Total Derivative Assets $ — $ 0.4 Derivative Liabilities Natural Gas Futures / Options Contracts Other Current Liabilities $ — $ — Natural Gas Futures / Options Contracts Other Noncurrent Liabilities — — Total Derivative Liabilities $ — $ — Twelve Months Ended 2017 2016 Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: Natural Gas Futures / Options Contracts $ 0.4 $ (0.1 ) Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings (1) Cost of Gas Sales $ — $ 0.3 (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, 2017 and 2016, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $3.6 million and $1.9 million, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, net. Fair Value of Marketable Securities (millions) December 31, 2017 2016 Equity Funds $ 2.1 $ 1.1 Fixed Income Funds 1.5 0.8 Total Marketable Securities $ 3.6 $ 1.9 Goodwill and Intangible Assets Energy Supply Obligations December 31, Energy Supply Obligations consist of the following: (millions) 2017 2016 Current: Exchange Gas Obligation $ 5.4 $ 7.8 Renewable Energy Portfolio Standards 4.0 3.9 Power Supply Contract Divestitures 0.3 0.3 Total Energy Supply Obligations—Current $ 9.7 $ 12.0 Noncurrent: Power Supply Contract Divestitures $ 0.9 $ 1.3 Total Energy Supply Obligations $ 10.6 $ 13.3 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 pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are operating. A recent round of long-term renewable energy procurements was conducted during 2016 and several contracts were finalized and submitted to MDPU for approval in 2017. These approvals remain pending. Additional procurements are expected in compliance with the Act to Promote Energy Diversity (2016). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism. Power Supply Contract Divestitures—Unitil Energy’s and Fitchburg’s customers are entitled 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). Retirement Benefit Obligations non-union non-qualified 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 Off-Balance Commitments and Contingencies Environmental Matters Recently Issued Pronouncements No. 2017-12, In May 2017, the FASB issued Accounting Standards Update ASU No. 2017-09, In March 2017, the FASB issued ASU No. 2017-07, In May 2014, the FASB issued ASU No. 2014-09, The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales. The Company intends to use the modified retrospective method when adopting the new standard on January 1, 2018. The Company expects that the impact of the new guidance will be immaterial to the Consolidated Financial Statements. Upon adoption of ASU 2014-09, In March 2016, the FASB issued ASU 2016-09, 2016-09 2016-09 In February 2016, the FASB issued ASU 2016-02, In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 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, 2017
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, 2017 2016 2017 2016 2017 2016 2017 2016 Total Operating Revenues $ 126.0 $ 125.8 $ 80.8 $ 74.5 $ 84.0 $ 78.8 $ 115.4 $ 104.3 Operating Income $ 26.1 $ 23.4 $ 10.5 $ 9.5 $ 9.5 $ 11.1 $ 23.6 $ 21.3 Net Income Applicable to Common $ 12.4 $ 10.9 $ 3.1 $ 2.5 $ 2.3 $ 3.5 $ 11.2 $ 10.2 Three Months Ended March 31, June 30, September 30, December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Per Share Data: Earnings Per Common Share $ 0.88 $ 0.78 $ 0.23 $ 0.18 $ 0.16 $ 0.25 $ 0.79 $ 0.73 Dividends Paid Per Common Share $ 0.360 $ 0.355 $ 0.360 $ 0.355 $ 0.360 $ 0.355 $ 0.360 $ 0.355

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Information	Note 3: Segment Information Unitil reports three segments: utility gas operations, utility electric operations and non-regulated. 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 Non-Regulated 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, 2017, 2016 and 2015 (millions): Year Ended December 31, 2017 Gas Electric Non- Other Total Revenues $ 194.0 $ 206.2 $ 6.0 $ — $ 406.2 Interest Income 0.7 1.0 0.1 0.6 2.4 Interest Expense 13.7 8.8 — 3.0 25.5 Depreciation & Amortization Expense 22.4 23.4 0.1 1.0 46.9 Income Tax Expense (Benefit) 10.7 7.5 0.7 (1.4 ) 17.5 Segment Profit 16.4 11.9 1.2 (0.5 ) 29.0 Segment Assets 714.3 476.9 6.7 44.0 1,241.9 Capital Expenditures 72.1 33.7 — 13.5 119.3 Year Ended December 31, 2016 Revenues $ 181.2 $ 196.1 $ 6.1 $ — $ 383.4 Interest Income 0.2 0.7 0.1 0.2 1.2 Interest Expense 13.3 8.3 — 2.1 23.7 Depreciation & Amortization Expense 21.9 23.8 0.1 0.8 46.6 Income Tax Expense (Benefit) 9.2 6.6 0.8 (1.2 ) 15.4 Segment Profit 14.5 11.1 1.1 0.4 27.1 Segment Assets 645.2 441.1 6.8 35.1 1,128.2 Capital Expenditures 57.0 30.1 — 11.0 98.1 Year Ended December 31, 2015 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 590.9 415.1 6.6 26.2 1,038.8 Capital Expenditures 64.9 29.9 0.1 9.0 103.9

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts	12 Months Ended
	Dec. 31, 2017
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 2017, 2016 and 2015, the Company recorded provisions for the energy commodity portion of bad debts of $1.3 million, $1.6 million and $2.6 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, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2015—2017 (millions): ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at Provision Recoveries Accounts Balance at Year Ended December 31, 2017 Electric $ 0.8 $ 1.8 $ 0.3 $ 2.0 $ 0.9 Gas 0.2 1.9 0.3 1.8 0.6 Other 0.1 — — — 0.1 $ 1.1 $ 3.7 $ 0.6 $ 3.8 $ 1.6 Year Ended December 31, 2016 Electric $ 0.6 $ 2.9 $ 0.3 $ 3.0 $ 0.8 Gas 0.5 1.7 0.3 2.3 0.2 Other 0.1 — — — 0.1 $ 1.2 $ 4.6 $ 0.6 $ 5.3 $ 1.1 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

Debt and Financing Arrangements

Debt and Financing Arrangements	12 Months Ended
	Dec. 31, 2017
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 certain Unitil subsidiaries 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 7.15% 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, 2017, in accordance with the covenants, these subsidiary companies had a combined amount of $238.3 million available for the payment of dividends and Unitil Corporation had $125.0 million available for the payment of dividends. As of December 31, 2017, the Company’s balance in Retained Earnings was $60.8 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2017 for the payment of dividends. Issuance of Long-Term Debt On August 1, 2016, Unitil Corporation completed a private placement of $30 million aggregate principal amount of 3.70% Senior Unsecured Notes due August 1, 2026 to institutional investors. The proceeds from the offering were used to repay short-term debt and for general corporate purposes. The Company incurred $0.3 million of costs associated with this issuance and these costs have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets. Debt Repayment The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2017 is: 2018 – $30.1 million; 2019 – $18.8 million; 2020 – $19.8 million; 2021 – $8.6 million; 2022 – $28.2 million and thereafter $303.9 million. Fair Value of Long-Term Debt Estimated Fair Value of Long-Term Debt (millions) December 31, 2017 2016 Estimated Fair Value of Long-Term Debt $ 457.1 $ 370.3 Details on long-term debt at December 31, 2017 and 2016 are shown below: Long-Term Debt (millions) December 31, 2017 2016 Unitil Corporation: 6.33% Senior Notes, Due May 1, 2022 $ 20.0 $ 20.0 3.70% Senior Notes, Due August 1, 2026 30.0 30.0 Unitil Energy First Mortgage Bonds: 5.24% Senior Secured Notes, Due March 2, 2020 15.0 15.0 8.49% Senior Secured Notes, Due October 14, 2024 7.5 9.0 6.96% Senior Secured Notes, Due September 1, 2028 20.0 20.0 8.00% Senior Secured Notes, Due May 1, 2031 15.0 15.0 6.32% Senior Secured Notes, Due September 15, 2036 15.0 15.0 Fitchburg: 6.75% Senior Notes, Due November 30, 2023 7.6 9.5 6.79% Senior Notes, Due October 15, 2025 10.0 10.0 3.52% Senior Notes, Due November 1, 2027 10.0 — 7.37% Senior Notes, Due January 15, 2029 12.0 12.0 5.90% Senior Notes, Due December 15, 2030 15.0 15.0 7.98% Senior Notes, Due June 1, 2031 14.0 14.0 4.32% Senior Notes, Due November 1, 2047 15.0 — Northern Utilities: 6.95% Senior Notes, Due December 3, 2018 10.0 20.0 5.29% Senior Notes, Due March 2, 2020 25.0 25.0 3.52% Senior Notes, Due November 1, 2027 20.0 — 7.72% Senior Notes, Due December 3, 2038 50.0 50.0 4.42% Senior Notes, Due October 15, 2044 50.0 50.0 4.32% Senior Notes, Due November 1, 2047 30.0 — Granite State: 7.15% Senior Notes, Due December 15, 2018 3.3 6.7 3.72% Senior Notes, Due November 1, 2027 15.0 — Unitil Realty Corp.: 8.00% Senior Secured Notes, Due August 1, 2017 — 0.4 Total Long-Term Debt 409.4 336.6 Less: Unamortized Debt Issuance Costs 3.3 3.0 Total Long-Term Debt, net of Unamortized Debt Issuance Costs 406.1 333.6 Less: Current Portion 29.8 16.8 Total Long-Term Debt, Less Current Portion $ 376.3 $ 316.8 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) 2017 2016 2015 Interest Expense Long-Term Debt $ 21.8 $ 21.8 $ 22.0 Short-Term Debt 2.5 1.4 0.9 Regulatory Liabilities 1.2 0.5 0.9 Subtotal Interest Expense 25.5 23.7 23.8 Interest Income Regulatory Assets (0.7 ) (0.3 ) (0.7 ) AFUDC (1) (1.7 ) (0.9 ) (1.2 ) Subtotal Interest Income (2.4 ) (1.2 ) (1.9 ) Total Interest Expense, net $ 23.1 $ 22.5 $ 21.9 (1) AFUDC—Allowance for Funds Used During Construction Credit Arrangements On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Facility”). The Credit Facility terminates October 4, 2020 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month one-time The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $234.9 million and $218.2 million for the years ended December 31, 2017 and December 31, 2016, respectively. Total gross repayments were $278.5 million and $178.3 million for the years ended December 31, 2017 and December 31, 2016, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2017 and December 31, 2016: Revolving Credit Facility (millions) December 31, 2017 2016 Limit $ 120.0 $ 120.0 Short-Term Borrowings Outstanding $ 38.3 $ 81.9 Letters of Credit Outstanding $ — $ 1.1 Available $ 81.7 $ 37.0 The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2017 and December 31, 2016, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. The weighted average interest rates on all short-term borrowings were 2.4%, 1.8%, and 1.5% during 2017, 2016, and 2015, respectively. Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services. 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, 2017, there are $2.7 million of current and $5.1 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 $8.5 million and $9.9 million of natural gas storage inventory at December 31, 2017 and 2016, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2017, which was payable in January 2018, was $3.1 million and recorded in Accounts Payable at December 31, 2017. The amount of natural gas inventory released in December 2016, which was payable in January 2017, was $2.1 million and recorded in Accounts Payable at December 31, 2016. 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, 2017, 2016 and 2015 amounted to $2.0 million, $1.8 million and $1.7 million respectively. Assets under capital leases amounted to approximately $15.0 million and $15.3 million as of December 31, 2017 and 2016, respectively, less accumulated amortization of $0.7 million and $1.0 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, 2017. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $5.7 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2017. $2.7 million of the current Capital Lease Obligations and $5.1 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 Capital 2018 $ 1,351 $ 3,087 2019 1,013 3,054 2020 842 2,496 2021 672 98 2022 397 14 2023 – 2027 220 — Total Payments $ 4,495 $ 8,749 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, 2017, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2018. The Company also guarantees the payment of principal, interest and other amounts payable on the 7.15% notes issued by Granite State. As of December 31, 2017, the principal amount outstanding for the 7.15% Granite State notes was $3.3 million.

Equity

Equity	12 Months Ended
	Dec. 31, 2017
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 14,065,230 and 14,815,585 shares of common stock outstanding at December 31, 2016 and December 31, 2017, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2016 and December 31, 2017. Unitil Corporation Common Stock Offering Dividend Reinvestment and Stock Purchase Plan Common Shares Repurchased, Cancelled and Retired 10b5-1 10b5-1 During 2017, 2016 and 2015, 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 2015 – 2017 in conjunction with the Stock Plan are presented in the following table: Issuance Date Shares Aggregate 1/26/15 40,010 $1.5 1/26/16 43,220 $1.6 4/19/16 800 <$0.1 1/30/17 34,930 $1.6 There were 89,326 and 93,747 non-vested 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 2017 and 2016 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) 2017 2016 Units Weighted Units Weighted Beginning Restricted Stock Units 43,345 $ 33.40 33,588 $ 31.83 Restricted Stock Units Granted 7,522 $ 50.23 8,505 $ 38.51 Dividend Equivalents Earned 1,357 $ 48.57 1,252 $ 41.00 Restricted Stock Units Settled — — — — Ending Restricted Stock Units 52,224 $ 36.22 43,345 $ 33.40 Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2017 and 2016 is $1.0 million and $0.8 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash. Preferred Stock There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2017 and December 31, 2016. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2017 and December 31, 2016, respectively. Earnings Per Share The following table reconciles basic and diluted earnings per share (EPS). (Millions except shares and per share data) 2017 2016 2015 Earnings Available to Common Shareholders $ 29.0 $ 27.1 $ 26.3 Weighted Average Common Shares Outstanding—Basic (000’s) 14,095 13,990 13,917 Plus: Diluted Effect of Incremental Shares (000’s) 7 6 3 Weighted Average Common Shares Outstanding—Diluted (000’s) 14,102 13,996 13,920 Earnings per Share—Basic and Diluted $ 2.06 $ 1.94 $ 1.89 The following table shows the number of weighted average non-vested 2017 2016 2015 Weighted Average Non-Vested 8,733 600 36,941

Energy Supply

Energy Supply	12 Months Ended
	Dec. 31, 2017
Energy Supply	Note 7: Energy Supply NATURAL GAS SUPPLY Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts. Northern Utilities’ C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2017, 80% of Unitil’s largest New Hampshire gas customers, representing 33% of Unitil’s New Hampshire gas therm sales and 69% of Unitil’s largest Maine customers, representing 24% of Unitil’s Maine gas therm sales, are purchasing gas supply from a third-party supplier. Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many large and some medium C&I customers purchase their gas supply 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. As of December 2017, 85% of Unitil’s largest Massachusetts gas customers, representing 29% of Unitil’s Massachusetts gas therm sales, are purchasing gas supply from third-party suppliers. The approved costs associated with natural gas supplied to 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), via over the road trucking of 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 under contracts of one year or less, and occasionally 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), via trucking of 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 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) Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2017, 77% of Unitil’s largest New Hampshire customers, representing 27% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales and 82% of Unitil’s largest Massachusetts customers, representing 33% of Unitil’s Massachusetts electric kWh 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 18% of Fitchburg’s customer base and customers in Ashby comprise another 5%. Buoyed by the municipal aggregations, 32% of Unitil’s residential customers in Massachusetts purchase their electricity from a third party supplier. In New Hampshire, the number of residential customers purchasing electricity from a third party supplier stands at 11%, down slightly relative to the past two years when 13% of Unitil’s residential customers in New Hampshire purchased their supply from third party suppliers. 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 to purchase electric supply from 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 and for 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 ISO-NE’s 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 ISO-NE ISO-NE ISO-NE ISO-NE 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 the purchase of clean energy and/or renewable energy certificates (“RECs”) pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (the “Green Communities Act”) of 2008 and An Act Relative to Competitively Priced Electricity in the Commonwealth of 2012, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are now operating. In 2016, the Company participated in a multi-state procurement for long-term renewable contracts and several contracts from this solicitation were executed and submitted to MDPU for approval in 2017. These approvals remain pending. Additional long-term clean energy contracts are expected in compliance with the Acts of 2016, An Act to Promote Energy Diversity (“Energy Diversity Act”). 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, 2017
Commitments and Contingencies	Note 8: Commitments and Contingencies Regulatory Matters Overview Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized 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, 2017. The remaining balance of these assets is $1.2 million as of December 31, 2017, 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 $0.9 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next four 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. Tax Cuts and Jobs Act of 2017 At the end of December 2017, the United States Congress voted and the President signed into law major federal tax law changes (TCJA) effective for tax year 2018. Among other things, the TCJA substantially reduces the corporate income tax rate to 21 percent, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, has or is in the process of issuing procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil is fully complying with these orders and will make any necessary changes to its rates as directed by the commissions. The FERC has not yet issued any procedural orders on this matter. The Company believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows. In Maine, Northern Utilities’ Maine division has a base rate case pending (described more fully below). The MPUC has issued a procedural order indicating that the tax law changes will be reflected in its calculation of final rates for the company. In New Hampshire, Northern Utilities’ New Hampshire division has a base rate case proceeding pending (described below), and the NHPUC issued an order directing the company to show how the tax changes can be effected within the schedule for the rate case. With respect to Unitil Energy, the NHPUC has directed the company to make a filing by April 1, 2018, showing the effect of the tax law changes on rates. In Massachusetts, the Attorney General filed a petition with the MDPU asking that it open an investigation to require the flow-through of the tax law changes in rates for all utilities subject to the MDPU’s jurisdiction. Fitchburg anticipates that the MDPU will issue an order on the Attorney General’s motion quickly, or, alternatively, issue an order establishing its own procedure for addressing the tax law changes. Fitchburg will comply fully with the MDPU and the Attorney General as this matter moves forward and make all rate changes necessary as directed by the MDPU. Rate Case Activity Unitil Energy—Base Rates— Fitchburg—Base Rates—Electric— On June 29, 2017, Fitchburg filed its compliance report on capital investments for calendar year 2016. On December 20, 2017, the MDPU approved the recovery of approximately $0.4 million, effective January 1, 2018, subject to further investigation and reconciliation. Fitchburg—Base Rates—Gas— Fitchburg—Gas Operations— one-year Northern Utilities—Base Rates—Maine— Build-out In addition to the distribution base rate increase, Northern Utilities is requesting to extend its Targeted Infrastructure Replacement Adjustment mechanism (TIRA). The TIRA is a capital cost recovery mechanism designed to recover the annual revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). This matter remains pending. Northern Utilities—Targeted Infrastructure Replacement Adjustment— Northern Utilities—Targeted Area Build-out Build-out Northern Utilities—Base Rates—New Hampshire— Northern Utilities reached a settlement agreement on temporary rates to produce an increase in annual revenues of approximately $1.6 million, effective with service rendered on and after August 1, 2017, and until a final, non-appealable In its initial petition, Northern Utilities requested approval to implement a multi-year rate plan, including a capital cost recovery mechanism, which will allow for recovery of the revenue requirements associated with future annual capital expenditures as defined under the plan through changes, or step adjustments, to Northern Utilities’ distribution rates without the need to file a general rate case prior to January 2021. This matter remains pending. Northern Utilities—Pipeline Refund— No. 524-A, Granite State—Base Rates— Other Matters NHPUC Energy Efficiency Resource Standard Proceeding— Unitil Energy—Electric Grid Modernization— Unitil Energy—Net Metering— time-of-use Fitchburg—Electric Operations— Fitchburg—Service Quality— Fitchburg—Solar Generation— Low-Income Fitchburg—Energy Diversity— Fitchburg—Clean Energy RFP— Fitchburg—Other— SREC-II, On May 11, 2016, the MDPU issued an Order commencing a rulemaking proceeding to adopt emergency regulations amending 220 C.M.R. § 18.00 et seq. (“Net Metering Regulations”). Specifically, the MDPU amended its Net Metering Regulations to implement the net metering provisions of An Act Relative to Solar Energy, St. 2016, c. 75, §§ 3-9, In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year pre-authorization, On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, FERC Transmission Formula Rate Proceedings— ISO-New 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 Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remain pending. The Company continues to believe these claims are without merit and will continue to defend itself vigorously. 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 is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2017, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Based on the Company’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations. Northern Utilities Manufactured Gas Plant Sites— mid-1800s mid-1900s. Northern Utilities has worked with the Maine Department of Environmental Protection (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required. The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five-year periods. The Environmental Obligations table below shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices. Fitchburg’s Manufactured Gas Plant Site— The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods. The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years ended December 31, 2017 and 2016. Environmental Obligations (millions) Fitchburg Northern Total 2017 2016 2017 2016 2017 2016 Total Balance at Beginning of Period $ 0.1 $ 1.2 $ 1.8 $ 1.6 $ 1.9 $ 2.8 Additions — — 0.4 1.8 0.4 1.8 Less: Payments / Reductions — 1.1 0.2 1.6 0.2 2.7 Total Balance at End of Period $ 0.1 $ 0.1 $ 2.0 $ 1.8 $ 2.1 $ 1.9 Less: Current Portion — 0.1 0.5 0.3 0.5 0.4 Noncurrent Balance at December 31, $ 0.1 $ — $ 1.5 $ 1.5 $ 1.6 $ 1.5

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
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, 2017, 2016 and 2015 are shown in the table below: ($000’s) 2017 2016 2015 Current Income Tax Provision Federal $ — $ — $ — State — — 3,530 Total Current Income Taxes — — 3,530 Deferred Income Provision Federal 13,675 11,209 12,413 State 3,862 4,145 (500 ) Total Deferred Income Taxes 17,537 15,354 11,913 Total Income Tax Expense $ 17,537 $ 15,354 $ 15,443 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: 2017 2016 2015 Statutory Federal Income Tax Rate 34 % 34 % 34 % Income Tax Effects of: State Income Taxes, net 6 4 5 Utility Plant Differences (1 ) (1 ) (2 ) Tax Credits (1 ) (1 ) (1 ) Other, net — — 1 Effective Income Tax Rate 38 % 36 % 37 % Temporary differences which gave rise to deferred tax assets and liabilities in 2017 and 2016, are shown below: Temporary Differences (000’s) 2017 2016 Deferred Tax Assets Retirement Benefit Obligations $ 38,915 $ 56,804 Net Operating Loss Carryforwards 12,686 23,921 Tax Credit Carryforwards 3,536 3,365 Other, net 1,155 1,426 Total Deferred Tax Assets $ 56,292 $ 85,516 Deferred Tax Liabilities Utility Plant Differences $ 127,932 $ 169,240 Regulatory Assets & Liabilities 9,323 10,594 Other, net 1,894 3,629 Total Deferred Tax Liabilities 139,149 183,463 Net Deferred Tax Liabilities $ 82,857 $ 97,947 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. In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction to the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with GAAP Accounting Standard 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) at the new 21% tax rate at which the ADIT will be realized in its reversing period. The Company recorded a Regulatory Liability in the amount of $48.9 million as a result of the ADIT revaluation. Subject to regulatory approval, the Company will pass back to ratepayers the excess ADIT according to the Average Rate Assumption Method (ARAM) as prescribed in the TCJA and IRS normalization rules. ARAM amortization refunds excess ADIT at the reversal rate of the underlying tax temporary timing difference. The Company’s regulators and the IRS are each expected to issue guidance in future periods that will determine the final disposition of the re-measurement of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the impact of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of the TCJA may change the amounts estimated. The Company filed its tax returns for the year ended December 31, 2016 with the Internal Revenue Service in September 2017 and generated additional federal net operating loss carryforward (NOLC) assets principally due to current tax repair deductions, tax depreciation and research and development deductions. In 2016, the Company recorded a benefit of approximately $0.7 million for New Hampshire business enterprise tax credits utilized in filing the Company’s 2015 tax return. For the year ended December 31, 2017, the Company decreased its federal NOLC $1.1 million in the calculation of its provisions for income taxes for the period and revalued the NOLC by $10.1 million for federal rate of 21% enacted in the TCJA. As of December 31, 2017, the Company had recorded cumulative federal and state NOLC assets of $12.7 million to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029. In addition, at December 31, 2017, the Company had $3.5 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable. The Company evaluated its tax positions at December 31, 2017 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, 2014; December 31, 2015; and December 31, 2016.

Retirement Benefit Plans

Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2017
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 The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations: 2017 2016 2015 Used to Determine Plan costs for years ended December 31: Discount Rate (1) 4.10 % 4.30 % 4.00 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Expected Long-term rate of return on plan assets 7.75 % 8.00 % 8.00 % Health Care Cost Trend Rate Assumed for Next Year 8.00 % 7.00 % 7.00 % Ultimate Health Care Cost Trend Rate 4.00 % 4.00 % 4.00 % Year that Ultimate Health Care Cost Trend Rate is reached 2025 2022 2018 Effect of 1% Increase in Health Care Cost Trend Rate (000’s) $ 1,625 $ 1,352 $ 1,383 Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) $ (1,238 ) $ (1,032 ) $ (1,040 ) (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 3.60 % 4.10 % 4.30 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Health Care Cost Trend Rate Assumed for Next Year 7.50 % 8.00 % 7.00 % Ultimate Health Care Cost Trend Rate 4.50 % 4.00 % 4.00 % Year that Ultimate Health care Cost Trend Rate is reached 2024 2025 2022 Effect of 1% Increase in Health Care Cost Trend Rate (000’s) $ 19,629 $ 19,471 $ 14,877 Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) $ (15,179 ) $ (15,153 ) $ (11,611 ) 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 2017, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $540,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2017 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 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service Cost $ 3,295 $ 3,402 $ 3,689 $ 2,974 $ 2,610 $ 2,622 $ 460 $ 162 $ 120 Interest Cost 6,057 5,945 5,392 3,913 3,232 2,918 392 386 330 Expected Return on Plan Assets (7,306 ) (7,257 ) (6,779 ) (1,347 ) (1,205 ) (1,093 ) — — — Prior Service Cost Amortization 263 263 265 1,399 1,486 1,682 189 189 85 Actuarial Loss Amortization 4,662 4,398 4,714 2,098 1,049 1,150 295 375 327 Sub-total 6,971 6,751 7,281 9,037 7,172 7,279 1,336 1,112 862 Amounts Capitalized or Deferred (3,122 ) (3,008 ) (3,397 ) (4,515 ) (3,351 ) (3,423 ) — — — NPBC Recognized $ 3,849 $ 3,743 $ 3,884 $ 4,522 $ 3,821 $ 3,856 $ 1,336 $ 1,112 $ 862 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 $6.1 million, $2.7 million and $0.7 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 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: 2017 2016 2017 2016 2017 2016 Plan Assets at Beginning of Year $ 91,058 $ 87,194 $ 16,606 $ 14,174 $ — $ — Actual Return on Plan Assets 12,731 3,618 1,907 792 — — Employer Contributions 4,100 5,146 4,000 4,000 34 34 Participant Contributions — — 126 61 — — Benefits Paid (5,574 ) (4,900 ) (2,405 ) (2,421 ) (34 ) (34 ) Plan Assets at End of Year $ 102,315 $ 91,058 $ 20,234 $ 16,606 $ — $ — Change in PBO: PBO at Beginning of Year $ 150,439 $ 140,816 $ 96,659 $ 76,249 $ 9,566 $ 9,177 Service Cost 3,295 3,402 2,974 2,610 460 162 Interest Cost 6,057 5,945 3,913 3,232 392 386 Participant Contributions — — 126 61 — — Plan Amendments 608 — — — — — Benefits Paid (5,574 ) (4,900 ) (2,405 ) (2,421 ) (34 ) (34 ) Actuarial (Gain) or Loss 12,096 5,176 (7,145 ) 16,928 1,339 (125 ) PBO at End of Year $ 166,921 $ 150,439 $ 94,122 $ 96,659 $ 11,723 $ 9,566 Funded Status: Assets vs PBO $ (64,606 ) $ (59,381 ) $ (73,888 ) $ (80,053 ) $ (11,723 ) $ (9,566 ) 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, net of deferred tax benefits, of $84.5 million and $75.9 million at December 31, 2017 and 2016, 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 $150.6 million and $135.2 million as of December 31, 2017 and 2016, respectively. The ABO for the SERP was $9.5 million and $6.9 million as of December 31, 2017 and 2016, 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 2018 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 2017 2016 2015 2017 2016 2015 2017 2016 2015 Employer Contributions $ 4,100 $ 5,146 $ 4,215 $ 4,000 $ 4,000 $ 4,000 $ 34 $ 34 $ 40 Participant Contributions $ — $ — $ — $ 126 $ 61 $ 63 $ — $ — $ — Benefit Payments $ 5,574 $ 4,900 $ 4,410 $ 2,405 $ 2,421 $ 2,515 $ 34 $ 34 $ 40 The following table represents estimated future benefit payments (000’s). Estimated Future Benefit Payments Pension PBOP SERP 2018 $ 5,510 $ 2,252 $ 87 2019 6,054 2,454 589 2020 6,314 2,635 580 2021 6,932 2,915 723 2022 6,986 3,130 712 2023 - 2027 44,677 19,349 4,062 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 Actual Allocation at 2017 2016 2015 Equity Funds 47 % 49 % 46 % 46 % Debt Funds 37 % 34 % 37 % 37 % Real Estate Fund 10 % 10 % 10 % 11 % Asset Allocation Fund (1) 6 % 6 % 7 % 6 % Other (2) — 1 % — — 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, 2017 pending payment of benefits. PBOP Plan Target Actual Allocation at 2017 2016 2015 Equity Funds 55 % 56 % 55 % 53 % Debt Funds 45 % 42 % 43 % 47 % Other (1) 0 % 2 % 2 % 0 % Total 100 % 100 % 100 % (1) Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds. The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.75% for 2017. 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, 2017 and 2016. 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. In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy. The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above. Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2017 and 2016 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2017 Pension Plan Assets: Mutual Funds: Equity Funds $ 50,373 $ 50,373 $ — $ — Fixed Income Funds 34,757 34,757 — — Asset Allocation Fund 6,398 6,398 — — Total Mutual Funds 91,528 91,528 — — Cash Equivalents 1,200 1,200 — Total Assets in the Fair Value Hierarchy $ 92,728 $ 92,728 $ — $ — Real Estate Fund–Measured at Net Asset Value 9,587 Total Assets $ 102,315 2016 Pension Plan Assets: Equity Funds $ 42,134 $ 42,134 $ — $ — Fixed Income Funds 33,924 33,924 — — Asset Allocation Fund 6,172 6,172 — — Total Assets in the Fair Value Hierarchy $ 82,230 $ 82,230 $ — $ — Real Estate Fund–Measured at Net Asset Value 8,828 Total Assets $ 91,058 Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments. Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2017 and 2016 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2017 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 8,419 $ 8,419 $ — $ — Equity Funds 11,415 11,415 Total Mutual Funds 19,834 19,834 Cash Equivalents 400 400 Total Assets $ 20,234 $ 20,234 $ — $ — 2016 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 7,078 $ 7,078 $ — $ — Equity Funds 9,128 9,128 Total Mutual Funds 16,206 16,206 Cash Equivalents 400 400 Total Assets $ 16,606 $ 16,606 $ — $ — Employee 401(k) Tax Deferred Savings Plan— The Company’s contributions to the 401(k) Plan were $2,434,000, $2,304,000 and $2,098,000 for the years ended December 31, 2017, 2016 and 2015, respectively.

Summary of Significant Accoun18

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Nature of Operations	Nature of Operations non-regulated 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 and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated
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
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 deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.
Dividends	Dividends
Cash and Cash Equivalents	Cash and Cash Equivalents (ISO-NE) ISO-NE. 2-1/2 ISO-NE
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts written-off shut-off.
Accrued Revenue	Accrued Revenue Accrued Revenue (millions) December 31, 2017 2016 Regulatory Assets—Current $ 39.5 $ 37.9 Unbilled Revenues 13.8 11.6 Total Accrued Revenue $ 53.3 $ 49.5
Exchange Gas Receivable	Exchange Gas Receivable Exchange Gas Receivable (millions) December 31, 2017 2016 Northern Utilities $ 5.4 $ 7.8 Fitchburg 0.4 0.5 Total Exchange Gas Receivable $ 5.8 $ 8.3
Gas Inventory	Gas Inventory Gas Inventory (millions) December 31, 2017 2016 Natural Gas $ 0.4 $ 0.3 Propane 0.1 0.2 Liquefied Natural Gas & Other 0.1 0.1 Total Gas Inventory $ 0.6 $ 0.6
Utility Plant	Utility Plant
Regulatory Accounting	Regulatory Accounting Regulatory Assets consist of the following (millions) December 31, 2017 2016 Retirement Benefits $ 84.5 $ 75.9 Energy Supply & Other Rate Adjustment Mechanisms 36.0 32.7 Deferred Storm Charges 7.2 9.6 Environmental 9.5 10.8 Income Taxes 6.5 7.3 Other 5.4 5.7 Total Regulatory Assets $ 149.1 $ 142.0 Less: Current Portion of Regulatory Assets (1) 39.5 37.9 Regulatory Assets—noncurrent $ 109.6 $ 104.1 (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, 2017 2016 Rate Adjustment Mechanisms $ 6.9 $ 6.2 Gas Pipeline Refund (Note 8) 2.3 6.8 Income Taxes (Note 9) 48.9 — Total Regulatory Liabilities 58.1 13.0 Less: Current Portion of Regulatory Liabilities 9.2 10.4 Regulatory Liabilities—noncurrent $ 48.9 $ 2.6 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, 2017 are $0.9 million of deferred storm charges to be recovered over the next year and $7.6 million of environmental and 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 through the purchase of European call option contracts. Any gains or losses resulting from these option contracts are passed through to customers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause. As of December 31, 2017 and December 31, 2016, the Company had 0.6 billion and 2.0 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. Fair Value Amount of Derivative Assets / Liabilities (millions) Offset in Regulatory Liabilities / Assets, as of: Fair Value Description Balance Sheet Location December 31, December 31, Derivative Assets Natural Gas Futures / Options Contracts Prepayments and Other $ — $ 0.1 Natural Gas Futures / Options Contracts Other Noncurrent Assets — 0.3 Total Derivative Assets $ — $ 0.4 Derivative Liabilities Natural Gas Futures / Options Contracts Other Current Liabilities $ — $ — Natural Gas Futures / Options Contracts Other Noncurrent Liabilities — — Total Derivative Liabilities $ — $ — Twelve Months Ended 2017 2016 Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: Natural Gas Futures / Options Contracts $ 0.4 $ (0.1 ) Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings (1) Cost of Gas Sales $ — $ 0.3 (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, 2017 and 2016, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $3.6 million and $1.9 million, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, net. Fair Value of Marketable Securities (millions) December 31, 2017 2016 Equity Funds $ 2.1 $ 1.1 Fixed Income Funds 1.5 0.8 Total Marketable Securities $ 3.6 $ 1.9
Goodwill and Intangible Assets	Goodwill and Intangible Assets
Energy Supply Obligations	Energy Supply Obligations December 31, Energy Supply Obligations consist of the following: (millions) 2017 2016 Current: Exchange Gas Obligation $ 5.4 $ 7.8 Renewable Energy Portfolio Standards 4.0 3.9 Power Supply Contract Divestitures 0.3 0.3 Total Energy Supply Obligations—Current $ 9.7 $ 12.0 Noncurrent: Power Supply Contract Divestitures $ 0.9 $ 1.3 Total Energy Supply Obligations $ 10.6 $ 13.3 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 pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are operating. A recent round of long-term renewable energy procurements was conducted during 2016 and several contracts were finalized and submitted to MDPU for approval in 2017. These approvals remain pending. Additional procurements are expected in compliance with the Act to Promote Energy Diversity (2016). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism. Power Supply Contract Divestitures—Unitil Energy’s and Fitchburg’s customers are entitled 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).
Retirement Benefit Obligations	Retirement Benefit Obligations non-union non-qualified 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 Off-Balance
Commitments and Contingencies	Commitments and Contingencies
Environmental Matters	Environmental Matters
Recently Issued Pronouncements	Recently Issued Pronouncements No. 2017-12, In May 2017, the FASB issued Accounting Standards Update ASU No. 2017-09, In March 2017, the FASB issued ASU No. 2017-07, In May 2014, the FASB issued ASU No. 2014-09, The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales. The Company intends to use the modified retrospective method when adopting the new standard on January 1, 2018. The Company expects that the impact of the new guidance will be immaterial to the Consolidated Financial Statements. Upon adoption of ASU 2014-09, In March 2016, the FASB issued ASU 2016-09, 2016-09 2016-09 In February 2016, the FASB issued ASU 2016-02, In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 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, 2017
Components of Accrued Revenue	The following table shows the components of Accrued Revenue as of December 31, 2017 and 2016. Accrued Revenue (millions) December 31, 2017 2016 Regulatory Assets—Current $ 39.5 $ 37.9 Unbilled Revenues 13.8 11.6 Total Accrued Revenue $ 53.3 $ 49.5
Components of Exchange Gas Receivable	The following table shows the components of Exchange Gas Receivable as of December 31, 2017 and 2016. Exchange Gas Receivable (millions) December 31, 2017 2016 Northern Utilities $ 5.4 $ 7.8 Fitchburg 0.4 0.5 Total Exchange Gas Receivable $ 5.8 $ 8.3
Components of Gas Inventory	The following table shows the components of Gas Inventory as of December 31, 2017 and 2016. Gas Inventory (millions) December 31, 2017 2016 Natural Gas $ 0.4 $ 0.3 Propane 0.1 0.2 Liquefied Natural Gas & Other 0.1 0.1 Total Gas Inventory $ 0.6 $ 0.6
Regulatory Assets	Regulatory Assets consist of the following (millions) December 31, 2017 2016 Retirement Benefits $ 84.5 $ 75.9 Energy Supply & Other Rate Adjustment Mechanisms 36.0 32.7 Deferred Storm Charges 7.2 9.6 Environmental 9.5 10.8 Income Taxes 6.5 7.3 Other 5.4 5.7 Total Regulatory Assets $ 149.1 $ 142.0 Less: Current Portion of Regulatory Assets (1) 39.5 37.9 Regulatory Assets—noncurrent $ 109.6 $ 104.1 (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, 2017 2016 Rate Adjustment Mechanisms $ 6.9 $ 6.2 Gas Pipeline Refund (Note 8) 2.3 6.8 Income Taxes (Note 9) 48.9 — Total Regulatory Liabilities 58.1 13.0 Less: Current Portion of Regulatory Liabilities 9.2 10.4 Regulatory Liabilities—noncurrent $ 48.9 $ 2.6
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, December 31, Derivative Assets Natural Gas Futures / Options Contracts Prepayments and Other $ — $ 0.1 Natural Gas Futures / Options Contracts Other Noncurrent Assets — 0.3 Total Derivative Assets $ — $ 0.4 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 2017 2016 Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: Natural Gas Futures / Options Contracts $ 0.4 $ (0.1 ) Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings (1) Cost of Gas Sales $ — $ 0.3 (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	Changes in the fair value of these investments are recorded in Other Expense, net. Fair Value of Marketable Securities (millions) December 31, 2017 2016 Equity Funds $ 2.1 $ 1.1 Fixed Income Funds 1.5 0.8 Total Marketable Securities $ 3.6 $ 1.9
Components of Energy Supply Obligations	The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets. December 31, Energy Supply Obligations consist of the following: (millions) 2017 2016 Current: Exchange Gas Obligation $ 5.4 $ 7.8 Renewable Energy Portfolio Standards 4.0 3.9 Power Supply Contract Divestitures 0.3 0.3 Total Energy Supply Obligations—Current $ 9.7 $ 12.0 Noncurrent: Power Supply Contract Divestitures $ 0.9 $ 1.3 Total Energy Supply Obligations $ 10.6 $ 13.3

Quarterly Financial Informati20

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information	Three Months Ended March 31, June 30, September 30, December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Total Operating Revenues $ 126.0 $ 125.8 $ 80.8 $ 74.5 $ 84.0 $ 78.8 $ 115.4 $ 104.3 Operating Income $ 26.1 $ 23.4 $ 10.5 $ 9.5 $ 9.5 $ 11.1 $ 23.6 $ 21.3 Net Income Applicable to Common $ 12.4 $ 10.9 $ 3.1 $ 2.5 $ 2.3 $ 3.5 $ 11.2 $ 10.2 Three Months Ended March 31, June 30, September 30, December 31, 2017 2016 2017 2016 2017 2016 2017 2016 Per Share Data: Earnings Per Common Share $ 0.88 $ 0.78 $ 0.23 $ 0.18 $ 0.16 $ 0.25 $ 0.79 $ 0.73 Dividends Paid Per Common Share $ 0.360 $ 0.355 $ 0.360 $ 0.355 $ 0.360 $ 0.355 $ 0.360 $ 0.355

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Significant Segment Financial Data	The following table provides significant segment financial data for the years ended December 31, 2017, 2016 and 2015 (millions): Year Ended December 31, 2017 Gas Electric Non- Other Total Revenues $ 194.0 $ 206.2 $ 6.0 $ — $ 406.2 Interest Income 0.7 1.0 0.1 0.6 2.4 Interest Expense 13.7 8.8 — 3.0 25.5 Depreciation & Amortization Expense 22.4 23.4 0.1 1.0 46.9 Income Tax Expense (Benefit) 10.7 7.5 0.7 (1.4 ) 17.5 Segment Profit 16.4 11.9 1.2 (0.5 ) 29.0 Segment Assets 714.3 476.9 6.7 44.0 1,241.9 Capital Expenditures 72.1 33.7 — 13.5 119.3 Year Ended December 31, 2016 Revenues $ 181.2 $ 196.1 $ 6.1 $ — $ 383.4 Interest Income 0.2 0.7 0.1 0.2 1.2 Interest Expense 13.3 8.3 — 2.1 23.7 Depreciation & Amortization Expense 21.9 23.8 0.1 0.8 46.6 Income Tax Expense (Benefit) 9.2 6.6 0.8 (1.2 ) 15.4 Segment Profit 14.5 11.1 1.1 0.4 27.1 Segment Assets 645.2 441.1 6.8 35.1 1,128.2 Capital Expenditures 57.0 30.1 — 11.0 98.1 Year Ended December 31, 2015 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 590.9 415.1 6.6 26.2 1,038.8 Capital Expenditures 64.9 29.9 0.1 9.0 103.9

Allowance for Doubtful Accoun22

Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2017
Allowance for Doubtful Accounts	The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2015—2017 (millions): ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at Provision Recoveries Accounts Balance at Year Ended December 31, 2017 Electric $ 0.8 $ 1.8 $ 0.3 $ 2.0 $ 0.9 Gas 0.2 1.9 0.3 1.8 0.6 Other 0.1 — — — 0.1 $ 1.1 $ 3.7 $ 0.6 $ 3.8 $ 1.6 Year Ended December 31, 2016 Electric $ 0.6 $ 2.9 $ 0.3 $ 3.0 $ 0.8 Gas 0.5 1.7 0.3 2.3 0.2 Other 0.1 — — — 0.1 $ 1.2 $ 4.6 $ 0.6 $ 5.3 $ 1.1 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

Debt and Financing Arrangemen23

Debt and Financing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value of Long Term Debt	Estimated Fair Value of Long-Term Debt (millions) December 31, 2017 2016 Estimated Fair Value of Long-Term Debt $ 457.1 $ 370.3
Details on Long Term Debt	Details on long-term debt at December 31, 2017 and 2016 are shown below: Long-Term Debt (millions) December 31, 2017 2016 Unitil Corporation: 6.33% Senior Notes, Due May 1, 2022 $ 20.0 $ 20.0 3.70% Senior Notes, Due August 1, 2026 30.0 30.0 Unitil Energy First Mortgage Bonds: 5.24% Senior Secured Notes, Due March 2, 2020 15.0 15.0 8.49% Senior Secured Notes, Due October 14, 2024 7.5 9.0 6.96% Senior Secured Notes, Due September 1, 2028 20.0 20.0 8.00% Senior Secured Notes, Due May 1, 2031 15.0 15.0 6.32% Senior Secured Notes, Due September 15, 2036 15.0 15.0 Fitchburg: 6.75% Senior Notes, Due November 30, 2023 7.6 9.5 6.79% Senior Notes, Due October 15, 2025 10.0 10.0 3.52% Senior Notes, Due November 1, 2027 10.0 — 7.37% Senior Notes, Due January 15, 2029 12.0 12.0 5.90% Senior Notes, Due December 15, 2030 15.0 15.0 7.98% Senior Notes, Due June 1, 2031 14.0 14.0 4.32% Senior Notes, Due November 1, 2047 15.0 — Northern Utilities: 6.95% Senior Notes, Due December 3, 2018 10.0 20.0 5.29% Senior Notes, Due March 2, 2020 25.0 25.0 3.52% Senior Notes, Due November 1, 2027 20.0 — 7.72% Senior Notes, Due December 3, 2038 50.0 50.0 4.42% Senior Notes, Due October 15, 2044 50.0 50.0 4.32% Senior Notes, Due November 1, 2047 30.0 — Granite State: 7.15% Senior Notes, Due December 15, 2018 3.3 6.7 3.72% Senior Notes, Due November 1, 2027 15.0 — Unitil Realty Corp.: 8.00% Senior Secured Notes, Due August 1, 2017 — 0.4 Total Long-Term Debt 409.4 336.6 Less: Unamortized Debt Issuance Costs 3.3 3.0 Total Long-Term Debt, net of Unamortized Debt Issuance Costs 406.1 333.6 Less: Current Portion 29.8 16.8 Total Long-Term Debt, Less Current Portion $ 376.3 $ 316.8
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) 2017 2016 2015 Interest Expense Long-Term Debt $ 21.8 $ 21.8 $ 22.0 Short-Term Debt 2.5 1.4 0.9 Regulatory Liabilities 1.2 0.5 0.9 Subtotal Interest Expense 25.5 23.7 23.8 Interest Income Regulatory Assets (0.7 ) (0.3 ) (0.7 ) AFUDC (1) (1.7 ) (0.9 ) (1.2 ) Subtotal Interest Income (2.4 ) (1.2 ) (1.9 ) Total Interest Expense, net $ 23.1 $ 22.5 $ 21.9 (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, 2017 and December 31, 2016: Revolving Credit Facility (millions) December 31, 2017 2016 Limit $ 120.0 $ 120.0 Short-Term Borrowings Outstanding $ 38.3 $ 81.9 Letters of Credit Outstanding $ — $ 1.1 Available $ 81.7 $ 37.0
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, 2017. The payments for capital leases consist of $3.1 million of current Capital Lease Obligations and $5.7 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2017. $2.7 million of the current Capital Lease Obligations and $5.1 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 Capital 2018 $ 1,351 $ 3,087 2019 1,013 3,054 2020 842 2,496 2021 672 98 2022 397 14 2023 – 2027 220 — Total Payments $ 4,495 $ 8,749

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Restricted Shares Issued in Conjunction with Stock Plan	Restricted Shares issued for 2015 – 2017 in conjunction with the Stock Plan are presented in the following table: Issuance Date Shares Aggregate 1/26/15 40,010 $1.5 1/26/16 43,220 $1.6 4/19/16 800 <$0.1 1/30/17 34,930 $1.6
Restricted Stock Units Issued	The equity portion of Restricted Stock Units activity during 2017 and 2016 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) 2017 2016 Units Weighted Units Weighted Beginning Restricted Stock Units 43,345 $ 33.40 33,588 $ 31.83 Restricted Stock Units Granted 7,522 $ 50.23 8,505 $ 38.51 Dividend Equivalents Earned 1,357 $ 48.57 1,252 $ 41.00 Restricted Stock Units Settled — — — — Ending Restricted Stock Units 52,224 $ 36.22 43,345 $ 33.40
Reconciliation of Basic and Diluted Earnings Per Share	Earnings Per Share The following table reconciles basic and diluted earnings per share (EPS). (Millions except shares and per share data) 2017 2016 2015 Earnings Available to Common Shareholders $ 29.0 $ 27.1 $ 26.3 Weighted Average Common Shares Outstanding—Basic (000’s) 14,095 13,990 13,917 Plus: Diluted Effect of Incremental Shares (000’s) 7 6 3 Weighted Average Common Shares Outstanding—Diluted (000’s) 14,102 13,996 13,920 Earnings per Share—Basic and Diluted $ 2.06 $ 1.94 $ 1.89
Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share	The following table shows the number of weighted average non-vested 2017 2016 2015 Weighted Average Non-Vested 8,733 600 36,941

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Environmental Obligations Recognized by Company	The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the years ended December 31, 2017 and 2016. Environmental Obligations (millions) Fitchburg Northern Total 2017 2016 2017 2016 2017 2016 Total Balance at Beginning of Period $ 0.1 $ 1.2 $ 1.8 $ 1.6 $ 1.9 $ 2.8 Additions — — 0.4 1.8 0.4 1.8 Less: Payments / Reductions — 1.1 0.2 1.6 0.2 2.7 Total Balance at End of Period $ 0.1 $ 0.1 $ 2.0 $ 1.8 $ 2.1 $ 1.9 Less: Current Portion — 0.1 0.5 0.3 0.5 0.4 Noncurrent Balance at December 31, $ 0.1 $ — $ 1.5 $ 1.5 $ 1.6 $ 1.5

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017, 2016 and 2015 are shown in the table below: ($000’s) 2017 2016 2015 Current Income Tax Provision Federal $ — $ — $ — State — — 3,530 Total Current Income Taxes — — 3,530 Deferred Income Provision Federal 13,675 11,209 12,413 State 3,862 4,145 (500 ) Total Deferred Income Taxes 17,537 15,354 11,913 Total Income Tax Expense $ 17,537 $ 15,354 $ 15,443
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: 2017 2016 2015 Statutory Federal Income Tax Rate 34 % 34 % 34 % Income Tax Effects of: State Income Taxes, net 6 4 5 Utility Plant Differences (1 ) (1 ) (2 ) Tax Credits (1 ) (1 ) (1 ) Other, net — — 1 Effective Income Tax Rate 38 % 36 % 37 %
Deferred Tax Assets and Liabilities	Temporary differences which gave rise to deferred tax assets and liabilities in 2017 and 2016, are shown below: Temporary Differences (000’s) 2017 2016 Deferred Tax Assets Retirement Benefit Obligations $ 38,915 $ 56,804 Net Operating Loss Carryforwards 12,686 23,921 Tax Credit Carryforwards 3,536 3,365 Other, net 1,155 1,426 Total Deferred Tax Assets $ 56,292 $ 85,516 Deferred Tax Liabilities Utility Plant Differences $ 127,932 $ 169,240 Regulatory Assets & Liabilities 9,323 10,594 Other, net 1,894 3,629 Total Deferred Tax Liabilities 139,149 183,463 Net Deferred Tax Liabilities $ 82,857 $ 97,947

Retirement Benefit Plans (Table

Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
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: 2017 2016 2015 Used to Determine Plan costs for years ended December 31: Discount Rate (1) 4.10 % 4.30 % 4.00 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Expected Long-term rate of return on plan assets 7.75 % 8.00 % 8.00 % Health Care Cost Trend Rate Assumed for Next Year 8.00 % 7.00 % 7.00 % Ultimate Health Care Cost Trend Rate 4.00 % 4.00 % 4.00 % Year that Ultimate Health Care Cost Trend Rate is reached 2025 2022 2018 Effect of 1% Increase in Health Care Cost Trend Rate (000’s) $ 1,625 $ 1,352 $ 1,383 Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) $ (1,238 ) $ (1,032 ) $ (1,040 ) (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 3.60 % 4.10 % 4.30 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Health Care Cost Trend Rate Assumed for Next Year 7.50 % 8.00 % 7.00 % Ultimate Health Care Cost Trend Rate 4.50 % 4.00 % 4.00 % Year that Ultimate Health care Cost Trend Rate is reached 2024 2025 2022 Effect of 1% Increase in Health Care Cost Trend Rate (000’s) $ 19,629 $ 19,471 $ 14,877 Effect of 1% Decrease in Health Care Cost Trend Rate (000’s) $ (15,179 ) $ (15,153 ) $ (11,611 )
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 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service Cost $ 3,295 $ 3,402 $ 3,689 $ 2,974 $ 2,610 $ 2,622 $ 460 $ 162 $ 120 Interest Cost 6,057 5,945 5,392 3,913 3,232 2,918 392 386 330 Expected Return on Plan Assets (7,306 ) (7,257 ) (6,779 ) (1,347 ) (1,205 ) (1,093 ) — — — Prior Service Cost Amortization 263 263 265 1,399 1,486 1,682 189 189 85 Actuarial Loss Amortization 4,662 4,398 4,714 2,098 1,049 1,150 295 375 327 Sub-total 6,971 6,751 7,281 9,037 7,172 7,279 1,336 1,112 862 Amounts Capitalized or Deferred (3,122 ) (3,008 ) (3,397 ) (4,515 ) (3,351 ) (3,423 ) — — — NPBC Recognized $ 3,849 $ 3,743 $ 3,884 $ 4,522 $ 3,821 $ 3,856 $ 1,336 $ 1,112 $ 862
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: 2017 2016 2017 2016 2017 2016 Plan Assets at Beginning of Year $ 91,058 $ 87,194 $ 16,606 $ 14,174 $ — $ — Actual Return on Plan Assets 12,731 3,618 1,907 792 — — Employer Contributions 4,100 5,146 4,000 4,000 34 34 Participant Contributions — — 126 61 — — Benefits Paid (5,574 ) (4,900 ) (2,405 ) (2,421 ) (34 ) (34 ) Plan Assets at End of Year $ 102,315 $ 91,058 $ 20,234 $ 16,606 $ — $ — Change in PBO: PBO at Beginning of Year $ 150,439 $ 140,816 $ 96,659 $ 76,249 $ 9,566 $ 9,177 Service Cost 3,295 3,402 2,974 2,610 460 162 Interest Cost 6,057 5,945 3,913 3,232 392 386 Participant Contributions — — 126 61 — — Plan Amendments 608 — — — — — Benefits Paid (5,574 ) (4,900 ) (2,405 ) (2,421 ) (34 ) (34 ) Actuarial (Gain) or Loss 12,096 5,176 (7,145 ) 16,928 1,339 (125 ) PBO at End of Year $ 166,921 $ 150,439 $ 94,122 $ 96,659 $ 11,723 $ 9,566 Funded Status: Assets vs PBO $ (64,606 ) $ (59,381 ) $ (73,888 ) $ (80,053 ) $ (11,723 ) $ (9,566 )
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 2017 2016 2015 2017 2016 2015 2017 2016 2015 Employer Contributions $ 4,100 $ 5,146 $ 4,215 $ 4,000 $ 4,000 $ 4,000 $ 34 $ 34 $ 40 Participant Contributions $ — $ — $ — $ 126 $ 61 $ 63 $ — $ — $ — Benefit Payments $ 5,574 $ 4,900 $ 4,410 $ 2,405 $ 2,421 $ 2,515 $ 34 $ 34 $ 40
Estimated Future Benefit Payments	The following table represents estimated future benefit payments (000’s). Estimated Future Benefit Payments Pension PBOP SERP 2018 $ 5,510 $ 2,252 $ 87 2019 6,054 2,454 589 2020 6,314 2,635 580 2021 6,932 2,915 723 2022 6,986 3,130 712 2023 - 2027 44,677 19,349 4,062
Pension Plans
Schedule of Allocation of Plan Assets	The actual investment allocations are shown in the tables below. Pension Plan Target Actual Allocation at 2017 2016 2015 Equity Funds 47 % 49 % 46 % 46 % Debt Funds 37 % 34 % 37 % 37 % Real Estate Fund 10 % 10 % 10 % 11 % Asset Allocation Fund (1) 6 % 6 % 7 % 6 % Other (2) — 1 % — — 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, 2017 pending payment of benefits. Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2017 and 2016 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2017 Pension Plan Assets: Mutual Funds: Equity Funds $ 50,373 $ 50,373 $ — $ — Fixed Income Funds 34,757 34,757 — — Asset Allocation Fund 6,398 6,398 — — Total Mutual Funds 91,528 91,528 — — Cash Equivalents 1,200 1,200 — Total Assets in the Fair Value Hierarchy $ 92,728 $ 92,728 $ — $ — Real Estate Fund–Measured at Net Asset Value 9,587 Total Assets $ 102,315 2016 Pension Plan Assets: Equity Funds $ 42,134 $ 42,134 $ — $ — Fixed Income Funds 33,924 33,924 — — Asset Allocation Fund 6,172 6,172 — — Total Assets in the Fair Value Hierarchy $ 82,230 $ 82,230 $ — $ — Real Estate Fund–Measured at Net Asset Value 8,828 Total Assets $ 91,058
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Allocation of Plan Assets	The actual investment allocations are shown in the tables below. PBOP Plan Target Actual Allocation at 2017 2016 2015 Equity Funds 55 % 56 % 55 % 53 % Debt Funds 45 % 42 % 43 % 47 % Other (1) 0 % 2 % 2 % 0 % Total 100 % 100 % 100 % (1) Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds. Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2017 and 2016 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of Quoted Significant Significant 2017 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 8,419 $ 8,419 $ — $ — Equity Funds 11,415 11,415 Total Mutual Funds 19,834 19,834 Cash Equivalents 400 400 Total Assets $ 20,234 $ 20,234 $ — $ — 2016 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 7,078 $ 7,078 $ — $ — Equity Funds 9,128 9,128 Total Mutual Funds 16,206 16,206 Cash Equivalents 400 400 Total Assets $ 16,606 $ 16,606 $ — $ —

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
	Feb. 02, 2018$ / shares	Dec. 31, 2017USD ($)$ / sharesBcf	Sep. 30, 2017$ / shares	Jun. 30, 2017$ / shares	Mar. 31, 2017$ / shares	Dec. 31, 2016USD ($)$ / sharesBcf	Sep. 30, 2016$ / shares	Jun. 30, 2016$ / shares	Mar. 31, 2016$ / shares	Dec. 31, 2017USD ($)EntitySubsidiarymi$ / sharesBcf	Dec. 31, 2016USD ($)$ / sharesBcf	Dec. 31, 2015$ / shares
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Entity										3
Length Of Pipeline | mi										86
Depreciation rate based on average depreciable property balance										3.45%	3.49%	3.57%
Common stock dividend paid per share | $ / shares		$ 0.360	$ 0.360	$ 0.360	$ 0.360	$ 0.355	$ 0.355	$ 0.355	$ 0.355	$ 1.44	$ 1.42	$ 1.40
Common stock dividend per share, declared | $ / shares										$ 1.44	$ 1.42	$ 1.40
Average interest rates										2.90%	2.18%	2.32%
Cost of removal obligation		$ 84,300,000				$ 77,000,000				$ 84,300,000	$ 77,000,000
Regulatory Assets		$ 149,100,000				$ 142,000,000				$ 149,100,000	$ 142,000,000
Number of Natural Gas Storage Outstanding | Bcf		0.6				2				0.6	2
Investments in trading securities		$ 3,600,000				$ 1,900,000				$ 3,600,000	$ 1,900,000
Intangible Assets, Purchase Adjustments										$ 2,300,000
Plant
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period										10 years
Bargain Purchase Adjustment
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period										1 year
Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	$ 1.46
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share | $ / shares										$ 0.360	$ 0.355	$ 0.350
Quarterly Dividends | Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	0.365
Increase in dividend declared amount per share | $ / shares	$ 0.005
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		2,900,000				2,800,000				$ 2,900,000	$ 2,800,000
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits		0				0				0	0
Deferred Storm Charges
Significant Accounting Policies [Line Items]
Regulatory Assets		7,200,000				$ 9,600,000				7,200,000	$ 9,600,000
Deferred Storm Charges | Recovered over Next Year
Significant Accounting Policies [Line Items]
Regulatory Assets		900,000								900,000
Environmental and Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory Assets		$ 7,600,000								$ 7,600,000
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary										3
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary										3

Components of Accrued Revenue (

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 53.3	$ 49.5
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	13.8	11.6
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 39.5	$ 37.9

Components of Exchange Gas Rece

Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Receivables [Line Items]
Total Exchange Gas Receivable	$ 5.8	$ 8.3
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	5.4	7.8
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.4	$ 0.5

Components of Gas Inventory (De

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.6	$ 0.6
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.3
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.1	$ 0.2

Regulatory Assets (Detail)

Regulatory Assets (Detail) - USD ($) $ in Millions		Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Assets		$ 149.1	$ 142
Less: Current Portion of Regulatory Assets	[1]	39.5	37.9
Regulatory Assets-noncurrent		109.6	104.1
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets		9.5	10.8
Other Assets
Regulatory Assets [Line Items]
Regulatory Assets		5.4	5.7
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets		84.5	75.9
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory Assets		7.2	9.6
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets		6.5	7.3
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets		$ 36	$ 32.7
[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, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 58.1	$ 13
Less: Current Portion of Regulatory Liabilities	9.2	10.4
Regulatory Liabilities-noncurrent	48.9	2.6
Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	6.9	6.2
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	2.3	$ 6.8
Income Tax Related Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 48.9

Fair Value Amount of Derivative

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) - Not Designated as Hedging Instruments - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative Assets
Derivative Assets		$ 0.4
Derivative Liabilities
Derivative Liabilities	$ 0	0
Natural Gas Futures Contract | Prepayments and Other
Derivative Assets
Derivative Assets		0.1
Natural Gas Futures Contract | Other Noncurrent Assets
Derivative Assets
Derivative Assets		0.3
Natural Gas Futures Contract | Other Current Liabilities
Derivative Liabilities
Derivative Liabilities	0	0
Natural Gas Futures 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, 2017	Dec. 31, 2016
Natural Gas Futures Contract
Regulatory Liabilities [Line Items]
Loss/(Gain) recognized in Regulatory Assets(Liabilities)		$ 0.4	$ (0.1)
Gas Purchase Costs
Regulatory Liabilities [Line Items]
Loss/(Gain) Reclassified into unaudited Consolidated Statement of Earnings	[1]		$ 0.3
[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, 2017	Dec. 31, 2016
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 3.6	$ 1.9
Fair Value, Inputs, Level 1
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	3.6	1.9
Fair Value, Inputs, Level 1 | Equity Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	2.1	1.1
Fair Value, Inputs, Level 1 | Fixed Income Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 1.5	$ 0.8

Components of Energy Supply Obl

Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 9.7	$ 12
Power Supply Contract Divestitures, Noncurrent	0.9	1.3
Total Energy Supply Obligations	10.6	13.3
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	5.4	7.8
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	4	3.9
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 0.3	$ 0.3

Quarterly Financial Informati38

Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 115.4	$ 84	$ 80.8	$ 126	$ 104.3	$ 78.8	$ 74.5	$ 125.8	$ 406.2	$ 383.4	$ 426.8
Operating Income	23.6	9.5	10.5	26.1	21.3	11.1	9.5	23.4	69.7	65.3	63.1
Net Income Applicable to Common	$ 11.2	$ 2.3	$ 3.1	$ 12.4	$ 10.2	$ 3.5	$ 2.5	$ 10.9	$ 29	$ 27.1	$ 26.3
Per Share Data:
Earnings Per Common Share	$ 0.79	$ 0.16	$ 0.23	$ 0.88	$ 0.73	$ 0.25	$ 0.18	$ 0.78	$ 2.06	$ 1.94	$ 1.89
Dividends Paid Per Common Share	$ 0.360	$ 0.360	$ 0.360	$ 0.360	$ 0.355	$ 0.355	$ 0.355	$ 0.355	$ 1.44	$ 1.42	$ 1.40

Segment Information - Additiona

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017SegmentEntityPipelinemi
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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 115,400	$ 84,000	$ 80,800	$ 126,000	$ 104,300	$ 78,800	$ 74,500	$ 125,800	$ 406,200	$ 383,400	$ 426,800
Interest Income									2,400	1,200	1,900
Interest Expense									25,500	23,700	23,800
Depreciation & Amortization Expense									46,900	46,600	45,700
Income Tax Expense (Benefit)									17,537	15,354	15,443
Segment Profit	11,200	$ 2,300	$ 3,100	$ 12,400	10,200	$ 3,500	$ 2,500	$ 10,900	29,000	27,100	26,300
Segment Assets	1,241,900				1,128,200				1,241,900	1,128,200	1,038,800
Capital Expenditures									119,300	98,100	103,900
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									194,000	181,200	202,600
Interest Income									700	200	800
Interest Expense									13,700	13,300	13,300
Depreciation & Amortization Expense									22,400	21,900	20,700
Income Tax Expense (Benefit)									10,700	9,200	10,200
Segment Profit									16,400	14,500	15,300
Segment Assets	714,300				645,200				714,300	645,200	590,900
Capital Expenditures									72,100	57,000	64,900
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									206,200	196,100	218,000
Interest Income									1,000	700	700
Interest Expense									8,800	8,300	8,800
Depreciation & Amortization Expense									23,400	23,800	24,000
Income Tax Expense (Benefit)									7,500	6,600	5,500
Segment Profit									11,900	11,100	8,700
Segment Assets	476,900				441,100				476,900	441,100	415,100
Capital Expenditures									33,700	30,100	29,900
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									600	200	300
Interest Expense									3,000	2,100	1,700
Depreciation & Amortization Expense									1,000	800	900
Income Tax Expense (Benefit)									(1,400)	(1,200)	(1,100)
Segment Profit									(500)	400	1,000
Segment Assets	44,000				35,100				44,000	35,100	26,200
Capital Expenditures									13,500	11,000	9,000
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									6,000	6,100	6,200
Interest Income									100	100	100
Depreciation & Amortization Expense									100	100	100
Income Tax Expense (Benefit)									700	800	800
Segment Profit									1,200	1,100	1,300
Segment Assets	$ 6,700				$ 6,800				$ 6,700	$ 6,800	6,600
Capital Expenditures											$ 100

Allowance for Doubtful Accoun41

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 3.7	$ 4.6	$ 5.3
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 1.3	$ 1.6	$ 2.6

Activity in Company's Allowance

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	$ 1.1	$ 1.2	$ 1.8
Provision	3.7	4.6	5.3
Recoveries	0.6	0.6	0.7
Accounts Written Off	3.8	5.3	6.6
Balance at End of Period	1.6	1.1	1.2
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.8	0.6	1.3
Provision	1.8	2.9	2.5
Recoveries	0.3	0.3	0.3
Accounts Written Off	2	3	3.5
Balance at End of Period	0.9	0.8	0.6
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.2	0.5	0.4
Provision	1.9	1.7	2.8
Recoveries	0.3	0.3	0.4
Accounts Written Off	1.8	2.3	3.1
Balance at End of Period	0.6	0.2	0.5
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 ($)	Nov. 01, 2017	Oct. 04, 2013	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 01, 2016	Oct. 30, 2015
Line of Credit Facility [Line Items]
Amount available for the payment of dividends			$ 125,000,000
Retained Earnings			$ 60,800,000	$ 52,200,000
Restriction on retained earnings for dividend payments			Therefore, there were no restrictions on the Company's Retained Earnings at December 31, 2017 for the payment of dividends.
Issuance of long-term debt	$ 700,000		$ 300,000
Long term debt repayments			$ 17,200,000	$ 19,000,000	$ 7,400,000
Weighted average interest rate on short term borrowings			2.40%	1.80%	1.50%
Capital lease obligation, current			$ 3,100,000	$ 3,000,000
Capital lease obligation, noncurrent			5,700,000	8,300,000
Accounts Payable			41,500,000	32,400,000
Total rental expense under operating leases			2,000,000	1,800,000	$ 1,700,000
Net Utility Plant			971,500,000	883,400,000
Guarantee outstanding			17,900,000
Financing Arrangements
Line of Credit Facility [Line Items]
Capital lease obligation, current			2,700,000
Capital lease obligation, noncurrent			5,100,000
Assets under Capital Leases
Line of Credit Facility [Line Items]
Net Utility Plant			15,000,000	15,300,000
Net Utility Plant, accumulated amortization			$ 700,000	1,000,000
Unitil Service Corp.
Line of Credit Facility [Line Items]
Capital lease obligation, total capitalized cost							$ 13,400,000
Capital lease obligation, maturity period			Sep. 30, 2020
Capital lease obligation, current			$ 2,700,000
Capital lease obligation, noncurrent			$ 5,100,000
Granite State Gas Transmission Inc
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			$ 8,500,000	9,900,000
Accounts Payable			$ 3,100,000	2,100,000
Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			65.00%
Unitil Corporation | Maximum
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization			70.00%
Unitil Energy, Fitchburg, Northern Utilities and Granite State
Line of Credit Facility [Line Items]
Amount available for the payment of dividends			$ 238,300,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility			120,000,000	120,000,000
Proceeds from lines of credit			234,900,000	218,200,000
Repayments of lines of credit			$ 278,500,000	$ 178,300,000
Credit Facility | Revolving Credit Facility
Line of Credit Facility [Line Items]
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
Revolving credit facility termination date		Oct. 4, 2020
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 December 31, 2017 and December 31, 2016, 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 (LIBOR)
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest		1.25%
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, maturity date			Dec. 15, 2018	Dec. 15, 2018
Long-term debt, stated interest rate			7.15%	7.15%
Senior Notes			$ 3,300,000
3.70% Senior Notes, Due August 1, 2026
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 30,000,000
Long-term debt, maturity date			Aug. 1, 2026	Aug. 1, 2026
Long-term debt, stated interest rate			3.70%	3.70%		3.70%
Bonds
Line of Credit Facility [Line Items]
Long term debt repayments			$ 17,200,000	$ 19,000,000	$ 7,400,000
Debt repayment, 2018			30,100,000
Debt repayment, 2019			18,800,000
Debt repayment, 2020			19,800,000
Debt repayment, 2021			8,600,000
Debt repayment, 2022			28,200,000
Debt repayment, Thereafter			$ 303,900,000
3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 20,000,000
Long-term debt, maturity date	Nov. 1, 2027		Nov. 1, 2027	Nov. 1, 2027
Long-term debt, stated interest rate	3.52%		3.52%	3.52%
3.52% Senior Notes, Due November 1, 2027 | Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 10,000,000
Long-term debt, maturity date	Nov. 1, 2027		Nov. 1, 2027	Nov. 1, 2027
Long-term debt, stated interest rate	3.52%		3.52%	3.52%
4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 30,000,000
Long-term debt, maturity date	Nov. 1, 2047		Nov. 1, 2047	Nov. 1, 2047
Long-term debt, stated interest rate	4.32%		4.32%	4.32%
4.32% Senior Notes, Due November 1, 2047 | Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 15,000,000
Long-term debt, maturity date	Nov. 1, 2047		Nov. 1, 2047	Nov. 1, 2047
Long-term debt, stated interest rate	4.32%		4.32%	4.32%
3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 15,000,000
Long-term debt, maturity date	Nov. 1, 2027		Nov. 1, 2027	Nov. 1, 2027
Long-term debt, stated interest rate	3.72%		3.72%	3.72%

Estimated Fair Value of Long Te

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 457.1	$ 370.3

Details on Long Term Debt (Deta

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total Long-Term Debt	$ 409.4	$ 336.6
Less: Unamortized Debt Issuance Costs	3.3	3
Long-Term Debt	406.1	333.6
Less: Current Portion	29.8	16.8
Total Long-Term Debt, Less Current Portion	376.3	316.8
Long-Term Debt	406.1	333.6
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Total Long-Term Debt	20	20
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt	30	30
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Senior Secured Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Total Long-Term Debt	7.5	9
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Total Long-Term Debt	20	20
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Total Long-Term Debt	15	15
Fitchburg Gas and Electric Light Company | 6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Total Long-Term Debt	7.6	9.5
Fitchburg Gas and Electric Light Company | 6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Total Long-Term Debt	10	10
Fitchburg Gas and Electric Light Company | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	10
Fitchburg Gas and Electric Light Company | 7.37% Senior Notes, Due January 15, 2029
Debt Instrument [Line Items]
Total Long-Term Debt	12	12
Fitchburg Gas and Electric Light Company | 5.90% Senior Notes, Due December 15, 2030
Debt Instrument [Line Items]
Total Long-Term Debt	15	15
Fitchburg Gas and Electric Light Company | 7.98% Senior Notes, Due June 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt	14	14
Fitchburg Gas and Electric Light Company | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt	15
Northern Utilities Inc | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	20
Northern Utilities Inc | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt	30
Northern Utilities Inc | 6.95% Senior Notes, Due December 3, 2018
Debt Instrument [Line Items]
Total Long-Term Debt	10	20
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt	25	25
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt	50	50
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt	50	50
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Total Long-Term Debt	3.3	6.7
Granite State Gas Transmission Inc | 3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	$ 15
Unitil Realty Corp | 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Total Long-Term Debt		$ 0.4

Details on Long Term Debt (Pare

Details on Long Term Debt (Parenthetical) (Detail)	Nov. 01, 2017	Dec. 31, 2017	Dec. 31, 2016	Aug. 01, 2016
6.33% Senior 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
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate		3.70%	3.70%	3.70%
Debt instrument due date		Aug. 1, 2026	Aug. 1, 2026
First Mortgage Bonds 5.24% Senior Secured Notes, 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% Senior Secured Notes, 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% Senior Secured Notes, 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% Senior Secured Notes, 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% Senior Secured Notes, 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% Senior 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
6.79% Senior 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
3.52% Senior Notes, Due November 1, 2027 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	3.52%	3.52%	3.52%
Debt instrument due date	Nov. 1, 2027	Nov. 1, 2027	Nov. 1, 2027
3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	3.52%	3.52%	3.52%
Debt instrument due date	Nov. 1, 2027	Nov. 1, 2027	Nov. 1, 2027
7.37% Senior 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
5.90% Senior 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
7.98% Senior 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
4.32% Senior Notes, Due November 1, 2047 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	4.32%	4.32%	4.32%
Debt instrument due date	Nov. 1, 2047	Nov. 1, 2047	Nov. 1, 2047
4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.32%	4.32%	4.32%
Debt instrument due date	Nov. 1, 2047	Nov. 1, 2047	Nov. 1, 2047
6.95% Senior Notes, 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, 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
3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	3.72%	3.72%	3.72%
Debt instrument due date	Nov. 1, 2027	Nov. 1, 2027	Nov. 1, 2027
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest Expense
Long-Term Debt		$ 21.8	$ 21.8	$ 22
Short-Term Debt		2.5	1.4	0.9
Regulatory Liabilities		1.2	0.5	0.9
Interest Expense		25.5	23.7	23.8
Interest Income
Interest income		(2.4)	(1.2)	(1.9)
Total Interest Expense, net		23.1	22.5	21.9
Regulatory Assets
Interest Income
Interest income		(0.7)	(0.3)	(0.7)
AFUDC and Other
Interest Income
Interest income	[1]	$ (1.7)	$ (0.9)	$ (1.2)
[1]	AFUDC-Allowance for Funds Used During Construction

Borrowing Limits Amounts Outsta

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 38,300,000	$ 81,900,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120,000,000	120,000,000
Short-Term Borrowings Outstanding	38,300,000	81,900,000
Letters of Credit Outstanding		1,100,000
Available revolving credit facility	$ 81,700,000	$ 37,000,000

Future Operating Lease Payment

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Operating leases
2,018	$ 1,351
2,019	1,013
2,020	842
2,021	672
2,022	397
2023 - 2027	220
Total Payments	4,495
Capital lease
2,018	3,087
2,019	3,054
2,020	2,496
2,021	98
2,022	14
2023 - 2027	0
Total Payments	$ 8,749

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($)	Jan. 29, 2018	Dec. 14, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Common stock, shares outstanding			14,815,585	14,065,230
Common stock, shares authorized			25,000,000	25,000,000
Common stock, shares issued				32,095	36,265
Proceeds from Issuance of Common Stock			$ 33,000,000	$ 1,300,000	$ 1,300,000
Common stock shares repurchase			1,686	1,949	1,981
Repurchase expense			$ 100,000	$ 100,000	$ 100,000
Share based compensation expense			$ 2,700,000	2,200,000	1,900,000
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			$ 1,000,000	800,000
Preferred Stock			200,000	200,000
Maximum
Class of Stock [Line Items]
Dividend declared			$ 100,000	100,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock, shares issued			26,256
Proceeds from Issuance of Common Stock			$ 1,300,000	$ 1,300,000	$ 1,300,000
Dividend and Distribution Reinvestment and Share Purchase Plan | Average
Class of Stock [Line Items]
Common stock price per share			$ 47.71
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued			26,256	32,095	36,265
Registered Public Offering
Class of Stock [Line Items]
Common stock, shares issued			690,000
Proceeds from Issuance of Common Stock			$ 31,700,000
Registered Public Offering | Common Stock
Class of Stock [Line Items]
Common stock, shares issued		690,000
Common stock price per share		$ 48.30
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			1,893	1,893
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			89,326	93,747
Restricted stock weighted average grant date fair value			$ 39.54	$ 35.29
Unrecognized share based compensation			$ 800,000
Share compensation recognition period			2 years 3 months 19 days
Forfeitures under the stock plan			831
Cancellations under the stock plan			0
Restricted Stock | Subsequent Event
Class of Stock [Line Items]
Restricted Stock Units Granted	37,510
Aggregate Market Value	$ 1,600,000
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%

Restricted Shares Issued in Con

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)shares
Period 1
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2015
Shares | shares	40,010
Aggregate Market Value | $	$ 1.5
Period 2
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2016
Shares | shares	43,220
Aggregate Market Value | $	$ 1.6
Period 3
Class of Stock [Line Items]
Issuance Date	Apr. 19, 2016
Shares | shares	800
Period 3 | Maximum
Class of Stock [Line Items]
Aggregate Market Value | $	$ 0.1
Period 4
Class of Stock [Line Items]
Issuance Date	Jan. 30, 2017
Shares | shares	34,930
Aggregate Market Value | $	$ 1.6

Restricted Stock Units Issued (

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Restricted Stock Units
Beginning Restricted Stock Units	43,345	33,588
Restricted Stock Units Granted	7,522	8,505
Dividend Equivalents Earned	1,357	1,252
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	52,224	43,345
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 33.40	$ 31.83
Restricted Stock Units Granted	50.23	38.51
Dividend Equivalents Earned	48.57	41
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	$ 36.22	$ 33.40

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, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders									$ 29	$ 27.1	$ 26.3
Weighted Average Common Shares Outstanding-Basic									14,095	13,990	13,917
Plus: Diluted Effect of Incremental Shares									7	6	3
Weighted Average Common Shares Outstanding-Diluted									14,102	13,996	13,920
Earnings per Share-Basic and Diluted	$ 0.79	$ 0.16	$ 0.23	$ 0.88	$ 0.73	$ 0.25	$ 0.18	$ 0.78	$ 2.06	$ 1.94	$ 1.89

Weighted Average Non Vested Res

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non Vested Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation	8,733	600	36,941

Energy Supply - Additional Info

Energy Supply - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017BcfMMBTU
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) $ in Millions

Dec. 20, 2017USD ($)

Oct. 31, 2017

Aug. 25, 2017MW

Aug. 18, 2017USD ($)

Aug. 01, 2017USD ($)

Jun. 21, 2017USD ($)

Jun. 05, 2017USD ($)

May 31, 2017USD ($)

Apr. 28, 2017

Apr. 25, 2017USD ($)

Apr. 20, 2017USD ($)

Oct. 31, 2016USD ($)

Aug. 19, 2016MW

Apr. 29, 2016USD ($)

Apr. 15, 2015USD ($)

Dec. 31, 2017USD ($)StateCustomer

Dec. 31, 2016USD ($)

Dec. 31, 2015

Jun. 30, 2027MW

Dec. 31, 2022MWh

Jun. 30, 2017MW

Jun. 23, 2017kW

Regulatory Assets [Line Items]

Regulatory Assets, Remaining Balance

$ 1.2

Accrued Revenue

53.3

$ 49.5

Regulatory Assets

$ 109.6

$ 104.1

Corporate income tax rate

34.00%

34.00%

34.00%

Current Portion of Regulatory Liabilities

$ 9.2

$ 10.4

Power capacity facility for small customers | kW

100

Tax Year 2018

Regulatory Assets [Line Items]

Corporate income tax rate

21.00%

Other Restructuring

Regulatory Assets [Line Items]

Accrued Revenue

$ 0.3

Regulatory Assets

$ 0.9

Cost recovery period, years

4 years

Northern Utilities Inc

Regulatory Assets [Line Items]

Increase in annual revenue

$ 0.7

$ 6

Amendment effective date

May 1, 2017

Annual TIRA Adjustment

$ 1.1

TIRA initial term

Four years

Pipeline refund received

$ 22

$ 19.7

Current Portion of Regulatory Liabilities

$ 2.3

Northern Utilities Inc | Maine

Regulatory Assets [Line Items]

Construction completion period

3 years

Number of new customers | Customer

1,000

Potential regulated operating revenue

$ 1

Grace period to receive refund

3 years

Northern Utilities Inc | Maine | Second TAB program

Regulatory Assets [Line Items]

Number of new customers | Customer

2,000

Potential regulated operating revenue

$ 2

Northern Utilities Inc | New Hampshire

Regulatory Assets [Line Items]

Increase in annual revenue

$ 1.6

Amendment effective date

Jul. 31, 2017

Deferred cost

$ 0.7

Grace period to receive refund

3 years

Northern Utilities Inc | New Hampshire | Natural Gas Distribution

Regulatory Assets [Line Items]

Increase in annual revenue

$ 4.7

Granite State Gas Transmission Inc | Gas Transportation and Storage

Regulatory Assets [Line Items]

Increase in annual revenue

$ 0.2

Amendment effective date

Aug. 1, 2017

Jul. 28, 2017

Unitil Energy Systems Inc | New Hampshire

Regulatory Assets [Line Items]

Permanent rate increase

$ 4.1

Unitil Energy Systems Inc | New Hampshire | Additional Rate Step Adjustments

Regulatory Assets [Line Items]

Permanent rate increase

$ 0.9

Fitchburg Gas and Electric Light Company

Regulatory Assets [Line Items]

Increase in annual revenue

$ 0.5

Recovery amount

0.9

Percentage of waiver approved on annual changes in the revenue requirement eligible for recovery

1.50%

Revenues sought approval to collect, deferred for recovery in future periods

$ 0.4

Percentage of waiver sought on annual changes in the revenue requirement eligible for recovery

3.00%

1.50%

Number of states with electric distribution companies | State

3

Fitchburg Gas and Electric Light Company | Solar Generation

Regulatory Assets [Line Items]

Power generation facility | MW

1.3

Expected completion date of facility

2017-11

Fitchburg Gas and Electric Light Company | Solar Generation | Solar Massachusetts Renewable Target Program

Regulatory Assets [Line Items]

Power generation capacity | MW

1,600

Fitchburg Gas and Electric Light Company | Minimum | Offshore Wind Energy

Regulatory Assets [Line Items]

Power generation facility | MW

400

Fitchburg Gas and Electric Light Company | Scenario Forecast

Regulatory Assets [Line Items]

Power generation capacity | MWh

9,450,000

Fitchburg Gas and Electric Light Company | Scenario Forecast | Offshore Wind Energy

Regulatory Assets [Line Items]

Power generation facility | MW

1,600

Fitchburg Gas and Electric Light Company | Electric base

Regulatory Assets [Line Items]

Increase in annual revenue

$ 2.1

Amendment effective date

Jan. 1, 2018

May 1, 2016

Jan. 1, 2017

Annual revenue adjustment

$ 0.4

$ 0.5

Fitchburg Gas and Electric Light Company | Gas base

Regulatory Assets [Line Items]

Increase in annual revenue

$ 1.6

Amendment effective date

May 1, 2016

Company's Liability for Environ

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 1.9	$ 2.8
Additions	0.4	1.8
Less: Payments / Reductions	0.2	2.7
Total Balance at End of Period	2.1	1.9
Less: Current Portion			$ 0.5	$ 0.4
Noncurrent Balance			1.6	1.5
Total Balance at End of period	1.9	2.8	2.1	1.9
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	0.1	1.2
Less: Payments / Reductions		1.1
Total Balance at End of Period	0.1	0.1
Less: Current Portion				0.1
Noncurrent Balance			0.1
Total Balance at End of period	0.1	1.2	0.1	0.1
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	1.8	1.6
Additions	0.4	1.8
Less: Payments / Reductions	0.2	1.6
Total Balance at End of Period	2	1.8
Less: Current Portion			0.5	0.3
Noncurrent Balance			1.5	1.5
Total Balance at End of period	$ 1.8	$ 1.6	$ 2	$ 1.8

Provisions for Federal and Stat

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Income Tax Provision
Federal	$ 0	$ 0	$ 0
State			3,530
Total Current Income Taxes			3,530
Deferred Income Provision
Federal	13,675	11,209	12,413
State	3,862	4,145	(500)
Total Deferred Income Taxes	17,537	15,354	11,913
Total Income Tax Expense	$ 17,537	$ 15,354	$ 15,443

Differences Between Provisions

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	34.00%	34.00%	34.00%
State Income Taxes, net	6.00%	4.00%	5.00%
Utility Plant Differences	(1.00%)	(1.00%)	(2.00%)
Tax Credits	(1.00%)	(1.00%)	(1.00%)
Other, net			1.00%
Effective Income Tax Rate	38.00%	36.00%	37.00%

Deferred Tax Assets and Liabili

Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets
Retirement Benefit Obligations	$ 38,915	$ 56,804
Net Operating Loss Carryforwards	12,686	23,921
Tax Credit Carryforwards	3,536	3,365
Other, net	1,155	1,426
Total Deferred Tax Assets	56,292	85,516
Deferred Tax Liabilities
Utility Plant Differences	127,932	169,240
Regulatory Assets & Liabilities	9,323	10,594
Other, net	1,894	3,629
Total Deferred Tax Liabilities	139,149	183,463
Net Deferred Tax Liabilities	$ 82,857	$ 97,947

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
Corporate federal income tax	34.00%	34.00%	34.00%
Regulatory Liability	$ 58,100	$ 13,000
Deferred tax assets, operating loss carryforwards, federal	1,100
Net Operating Loss Carryforwards	$ 12,686	23,921
NOL carryforward assets expiration date	2,029
Tax benefit for New Hampshire business enterprise tax credits		$ 700
Alternative minimum tax credit carryforwards	$ 3,500
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 48,900
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax	21.00%
Deferred tax assets, operating loss carryforwards, federal	$ 10,100
Federal, Maine, Massachusetts, and New Hampshire Tax Authorities
Income Taxes [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, 2014; December 31, 2015; and December 31, 2016.

Key Assumptions Used in Determi

Key Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	[1]	4.10%	4.30%	4.00%
Rate of Compensation Increase		3.00%	3.00%	3.00%
Expected Long-term rate of return on plan assets		7.75%	8.00%	8.00%
Health Care Cost Trend Rate Assumed for Next Year		8.00%	7.00%	7.00%
Ultimate Health Care Cost Trend Rate		4.00%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached		2,025	2,022	2,018
Effect of 1% Increase in Health Care Cost Trend Rate		$ 1,625	$ 1,352	$ 1,383
Effect of 1% Decrease in Health Care Cost Trend Rate		$ (1,238)	$ (1,032)	$ (1,040)
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate		3.60%	4.10%	4.30%
Rate of Compensation Increase		3.00%	3.00%	3.00%
Health Care Cost Trend Rate Assumed for Next Year		7.50%	8.00%	7.00%
Ultimate Health Care Cost Trend Rate		4.50%	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached		2,024	2,025	2,022
Effect of 1% Increase in Health Care Cost Trend Rate		$ 19,629	$ 19,471	$ 14,877
Effect of 1% Decrease in Health Care Cost Trend Rate		$ (15,179)	$ (15,153)	$ (11,611)
[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 Assumptions Used in Deter63

Key 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 ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
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		$ 540
Pension expense		7,000	$ 6,800	$ 7,300
Regulatory Assets		$ 149,100	142,000
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		$ 6,100
Accumulated Benefit Obligation		150,600	135,200
Company's contributions		4,100	5,146	4,215
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Amortizations related to Actuarial Loss and Prior Service Cost		2,700
Company's contributions		4,000	4,000	4,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Amortizations related to Actuarial Loss and Prior Service Cost		700
Accumulated Benefit Obligation		9,500	6,900
Company's contributions		34	34	40
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense		7,600	7,700	7,300
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory Assets		84,500	75,900
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Company's contributions		$ 2,434	$ 2,304	$ 2,098
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Long-term Return on Assets		7.75%	8.00%	8.00%
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3,295	$ 3,402	$ 3,689
Interest Cost	6,057	5,945	5,392
Expected Return on Plan Assets	(7,306)	(7,257)	(6,779)
Prior Service Cost Amortization	263	263	265
Actuarial Loss Amortization	4,662	4,398	4,714
Sub-total	6,971	6,751	7,281
Amounts Capitalized or Deferred	(3,122)	(3,008)	(3,397)
NPBC Recognized	3,849	3,743	3,884
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,974	2,610	2,622
Interest Cost	3,913	3,232	2,918
Expected Return on Plan Assets	(1,347)	(1,205)	(1,093)
Prior Service Cost Amortization	1,399	1,486	1,682
Actuarial Loss Amortization	2,098	1,049	1,150
Sub-total	9,037	7,172	7,279
Amounts Capitalized or Deferred	(4,515)	(3,351)	(3,423)
NPBC Recognized	4,522	3,821	3,856
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	460	162	120
Interest Cost	392	386	330
Prior Service Cost Amortization	189	189	85
Actuarial Loss Amortization	295	375	327
Sub-total	1,336	1,112	862
NPBC Recognized	$ 1,336	$ 1,112	$ 862

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 91,058	$ 87,194
Actual Return on Plan Assets	12,731	3,618
Employer Contributions	4,100	5,146	$ 4,215
Benefits Paid	(5,574)	(4,900)
Plan Assets at End of Year	102,315	91,058	87,194
PBO at Beginning of Year	150,439	140,816
Service Cost	3,295	3,402	3,689
Interest Cost	6,057	5,945	5,392
Plan Amendments	608
Benefits Paid	(5,574)	(4,900)	(4,410)
Actuarial (Gain) or Loss	12,096	5,176
PBO at End of Year	166,921	150,439	140,816
Funded Status: Assets vs PBO	(64,606)	(59,381)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	16,606	14,174
Actual Return on Plan Assets	1,907	792
Employer Contributions	4,000	4,000	4,000
Participant Contributions	126	61
Benefits Paid	(2,405)	(2,421)
Plan Assets at End of Year	20,234	16,606	14,174
PBO at Beginning of Year	96,659	76,249
Service Cost	2,974	2,610	2,622
Interest Cost	3,913	3,232	2,918
Participant Contributions	126	61	63
Benefits Paid	(2,405)	(2,421)	(2,515)
Actuarial (Gain) or Loss	(7,145)	16,928
PBO at End of Year	94,122	96,659	76,249
Funded Status: Assets vs PBO	(73,888)	(80,053)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	34	34	40
Benefits Paid	(34)	(34)
PBO at Beginning of Year	9,566	9,177
Service Cost	460	162	120
Interest Cost	392	386	330
Benefits Paid	(34)	(34)	(40)
Actuarial (Gain) or Loss	1,339	(125)
PBO at End of Year	11,723	9,566	$ 9,177
Funded Status: Assets vs PBO	$ (11,723)	$ (9,566)

Employer Contributions, Partici

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 4,100	$ 5,146	$ 4,215
Benefit Payments	5,574	4,900	4,410
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	4,000	4,000	4,000
Participant Contributions	126	61	63
Benefit Payments	2,405	2,421	2,515
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	34	34	40
Benefit Payments	$ 34	$ 34	$ 40

Estimated Future Benefit Paymen

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 5,510
2,019	6,054
2,020	6,314
2,021	6,932
2,022	6,986
2023 - 2027	44,677
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2,018	2,252
2,019	2,454
2,020	2,635
2,021	2,915
2,022	3,130
2023 - 2027	19,349
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2,018	87
2,019	589
2,020	580
2,021	723
2,022	712
2023 - 2027	$ 4,062

Actual Investment Allocations (

Actual Investment Allocations (Detail)		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			49.00%	46.00%	46.00%
Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			34.00%	37.00%	37.00%
Pension Plans | Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[1]		6.00%	7.00%	6.00%
Pension Plans | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[2]		1.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			56.00%	55.00%	53.00%
Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			42.00%	43.00%	47.00%
Other Postretirement Benefit Plans, Defined Benefit | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[3]		2.00%	2.00%	0.00%
Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			10.00%	10.00%	11.00%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		47.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		37.00%
Scenario Forecast | Pension Plans | Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	[1]	6.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		45.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Other
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	[3]	0.00%
Scenario Forecast | Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [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, 2017 pending payment of benefits.
[3]	Represents investments being held in cash equivalents as of December 31, 2017 and 2016 pending transfer into debt and equity funds.

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 102,315	$ 91,058	$ 87,194
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	91,528	82,230
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	50,373	42,134
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	34,757	33,924
Mutual Fund | Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	6,398	6,172
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	1,200
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	92,728
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	9,587	8,828
Fair Value, Inputs, Level 1 | Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	91,528	82,230
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	50,373	42,134
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	34,757	33,924
Fair Value, Inputs, Level 1 | Mutual Fund | Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	6,398	$ 6,172
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	1,200
Fair Value, Inputs, Level 1 | Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 92,728

Assets Measured at Fair Value71

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 20,234	$ 16,606	$ 14,174
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	400	400
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	19,834	16,206
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	8,419	7,078
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	11,415	9,128
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	20,234	16,606
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	400	400
Fair Value, Inputs, Level 1 | Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	19,834	16,206
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	8,419	7,078
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 11,415	$ 9,128