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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2016	Jan. 30, 2017	Jun. 30, 2016
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		14,066,399
Entity Public Float			$ 586,061,044

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues:
Gas	$ 181,200	$ 202,600	$ 201,400
Electric	196,100	218,000	218,700
Other	6,100	6,200	5,700
Total Operating Revenues	383,400	426,800	425,800
Operating Expenses:
Cost of Gas Sales	77,600	100,700	104,000
Cost of Electric Sales	108,000	132,500	137,900
Operation and Maintenance	66,300	67,100	64,600
Depreciation and Amortization	46,600	45,700	42,100
Taxes Other Than Income Taxes	19,600	17,700	17,200
Total Operating Expenses	318,100	363,700	365,800
Operating Income	65,300	63,100	60,000
Interest Expense, net	22,500	21,900	20,900
Other Expense (Income), net	300	(500)	400
Income Before Income Taxes	42,500	41,700	38,700
Income Taxes	15,354	15,443	13,995
Net Income Applicable to Common Shares	$ 27,100	$ 26,300	$ 24,700
Earnings per Common Share-Basic and Diluted	$ 1.94	$ 1.89	$ 1.79
Weighted Average Common Shares Outstanding-(Basic and Diluted)	14.0	13.9	13.8

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and Cash Equivalents	$ 5.8	$ 8.7
Accounts Receivable, net	52.9	49.8
Accrued Revenue	49.5	38.4
Exchange Gas Receivable	8.3	11.1
Gas Inventory	0.6	0.8
Prepayments and Other	14.5	11.7
Total Current Assets	131.6	120.5
Utility Plant:
Gas	629.5	576.8
Electric	437.9	408.4
Common	35.8	35.5
Construction Work in Progress	70.2	59.9
Utility Plant	1,173.4	1,080.6
Less: Accumulated Depreciation	290.0	271.7
Net Utility Plant	883.4	808.9
Other Noncurrent Assets:
Regulatory Assets	104.1	99.6
Other Assets	9.1	9.8
Total Other Noncurrent Assets	113.2	109.4
TOTAL ASSETS	1,128.2	1,038.8
Current Liabilities:
Accounts Payable	32.4	33.3
Short-Term Debt	81.9	42.0
Long-Term Debt, Current Portion	16.8	17.1
Regulatory Liabilities	10.4	15.6
Energy Supply Obligations	12.0	14.6
Environmental Obligations	0.4	1.3
Capital Lease Obligations	3.0	3.1
Other Current Liabilities	20.0	17.3
Total Current Liabilities	176.9	144.3
Noncurrent Liabilities:
Retirement Benefit Obligations	149.0	124.4
Deferred Income Taxes, net	97.9	87.5
Cost of Removal Obligations	77.0	70.1
Regulatory Liabilities	2.6	8.1
Capital Lease Obligations	8.3	11.0
Environmental Obligations	1.5	1.5
Other Noncurrent Liabilities	5.1	3.6
Total Noncurrent Liabilities	341.4	306.2
Capitalization:
Long-Term Debt, Less Current Portion	316.8	305.5
Stockholders' Equity:
Common Equity (Outstanding 14,065,230 and 13,991,430 Shares)	240.7	237.5
Retained Earnings	52.2	45.1
Total Common Stock Equity	292.9	282.6
Preferred Stock	0.2	0.2
Total Stockholders' Equity	293.1	282.8
Total Capitalization	609.9	588.3
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,128.2	$ 1,038.8

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015
Common Equity Outstanding	14,065,230	13,991,430

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Activities:
Net Income	$ 27.1	$ 26.3	$ 24.7
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	46.6	45.7	42.1
Deferred Tax Provision	15.4	11.9	14.4
Changes in Working Capital Items:
Accounts Receivable	(5.4)	10.9	(8.5)
Accrued Revenue	(11.1)	10.1	8.1
Regulatory Liabilities	(5.2)	6.9	(1.0)
Exchange Gas Receivable	2.8	3.9	(4.2)
Accounts Payable	(0.9)	(10.9)	6.1
Other Changes in Working Capital Items	(1.0)	(2.4)	6.5
Deferred Regulatory and Other Charges	(5.0)	8.2	(1.4)
Other, net	5.0	4.5	(2.8)
Cash Provided by Operating Activities	68.3	115.1	84.0
Investing Activities:
Property, Plant and Equipment Additions	(98.1)	(103.9)	(92.6)
Cash Used In Investing Activities	(98.1)	(103.9)	(92.6)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	39.9	12.7	(30.9)
Issuance of Long-Term Debt	30.0		50.0
Repayment of Long-Term Debt	(19.0)	(7.4)	(4.4)
(Decrease) Increase in Capital Lease Obligations	(2.8)	6.1	6.5
Net (Decrease) Increase in Exchange Gas Financing	(2.5)	(4.0)	4.4
Dividends Paid	(20.0)	(19.6)	(19.2)
Proceeds from Issuance of Common Stock	1.3	1.3	1.2
Cash Provided by (Used In) Financing Activities	26.9	(10.9)	7.6
Net (Decrease) Increase in Cash	(2.9)	0.3	(1.0)
Cash at Beginning of Year	8.7	8.4	9.4
Cash at End of Year	5.8	8.7	8.4
Supplemental Information:
Interest Paid	22.1	22.3	20.8
Income Taxes Paid	1.6	1.8	1.2
Payments on Capital Leases	3.4	1.1	0.6
Capital Expenditures Included in Accounts Payable	0.3	$ 0.4	$ 0.3
Non-Cash Additions to Property, Plant and Equipment	$ 3.5

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2013	$ 265.0	$ 232.1	$ 32.9
Net Income	24.7		24.7
Dividends	(19.2)		(19.2)
Shares Issued Under Stock Plans	1.4	1.4
Issuance of Common Shares	1.2	1.2
Ending Balance at Dec. 31, 2014	273.1	234.7	38.4
Net Income	26.3		26.3
Dividends	(19.6)		(19.6)
Shares Issued Under Stock Plans	1.5	1.5
Issuance of Common Shares	1.3	1.3
Ending Balance at Dec. 31, 2015	282.6	237.5	45.1
Net Income	27.1		27.1
Dividends	(20.0)		(20.0)
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

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Dividends per Common Share	$ 1.42	$ 1.40	$ 1.38
Common stock, shares issued	32,095	36,265	38,020

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Summary of Significant Accounting Policies

Note 1: Summary of Significant Accounting Policies

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

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

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

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

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

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

Basis of Presentation

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

Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and requires disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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


Level 1—		Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.

Level 2—		Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.

Level 3—		Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

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

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

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

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

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

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

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2016 – 3.49%, 2015 – 3.57% and 2014 – 3.56%.

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

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

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

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

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

For all periods presented in the Consolidated Financial Statements in this Form 10-K for the year ended December 31, 2016, deferred income taxes are reported as “Deferred Income Taxes” in the “Noncurrent Liabilities” section on the Consolidated Balance Sheets. Prior to adoption, the Company reported deferred income taxes in either the “Current Assets” or “Current Liabilities” and “Other Noncurrent Assets” or “Noncurrent Liabilities” sections on the Consolidated Balance Sheets, depending on whether the net current deferred income taxes and net noncurrent deferred income taxes were in an asset or liability position, respectively. The change in presentation for the year ended December 31, 2016 resulted in a reduction of both “Current Assets” and “Noncurrent Liabilities” for all prior periods presented.

Dividends—The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the year ended December 31, 2016 the Company paid quarterly dividends of $0.355 per share, resulting in an annual dividend rate of $1.42 per common share. For the years ended December 31, 2015 and 2014, the Company paid quarterly dividends of $0.350 and $0.345 per common share, respectively, resulting in annual dividend rates of $1.40 and $1.38 per common share, respectively. At its January 2017 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.36 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annual dividend rate to $1.44 per share from $1.42 per share.

Cash and Cash Equivalents—Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. On December 31, 2016 and 2015, the Unitil subsidiaries had deposited $2.8 million and $2.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities maintains an account used to implement its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of December 31, 2016 and 2015.

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

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” below) and unbilled revenues (see “Utility Revenue Recognition” above.) The following table shows the components of Accrued Revenue as of December 31, 2016 and 2015.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2016		2015
Regulatory Assets—Current	$	37.9	$	26.8
Unbilled Revenues		11.6		11.6

Total Accrued Revenue	$	49.5	$	38.4

Exchange Gas Receivable—Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of December 31, 2016 and 2015.


Exchange Gas Receivable (millions)	December 31,
Exchange Gas Receivable (millions)	2016		2015
Northern Utilities	$	7.8	$	10.3
Fitchburg		0.5		0.8

Total Exchange Gas Receivable	$	8.3	$	11.1

Gas Inventory—The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of December 31, 2016 and 2015.


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

Total Gas Inventory	$	0.6	$	0.8

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.18%, 2.32% and 1.56% in 2016, 2015 and 2014, respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31, 2016 and 2015, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $77.0 million and $70.1 million, respectively.

Regulatory Accounting—The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


Regulatory Assets consist of the following (millions)	December 31,
Regulatory Assets consist of the following (millions)	2016		2015
Retirement Benefits	$	75.9	$	64.7
Energy Supply & Other Regulatory Tracker Mechanisms		32.7		21.3
Deferred Storm Charges		9.6		15.4
Environmental		10.8		11.2
Income Taxes		7.3		8.5
Other		5.7		5.3

Total Regulatory Assets	$	142.0	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		37.9		26.8

Regulatory Assets—noncurrent	$	104.1	$	99.6

⁽¹⁾

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


Regulatory Liabilities consist of the following (millions)	December 31,
	2016		2015
Regulatory Tracker Mechanisms	$	6.2	$	8.0
Gas Pipeline Refund (Note 8)		6.8		15.7

Total Regulatory Liabilities		13.0		23.7
Less: Current Portion of Regulatory Liabilities		10.4		15.6

Regulatory Liabilities—noncurrent	$	2.6	$	8.1

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of December 31, 2016 are $3.3 million of deferred storm charges to be recovered over the next two and a half years and $8.6 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’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.

The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of December 31, 2015, all futures contracts purchased under the prior program design have been sold and the hedging portfolio now consists entirely of call option contracts.

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

As of December 31, 2016 and December 31, 2015, the Company had 2.0 billion and 2.5 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

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

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


		Fair Value
Description	Balance Sheet Location	December 31, 2016		December 31, 2015
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 December 31,
	2016			2015
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	(0.1	)	$	0.3

Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings⁽¹⁾:
Cost of Gas Sales	$	0.3		$	0.2

⁽¹⁾

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

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

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


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

Total Marketable Securities	$	1.9	$	0.7

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2016, the unamortized balance of the bargain purchase adjustment was $4.7 million, to be amortized over the next two years.

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


	December 31,
Energy Supply Obligations consist of the following: (millions)	2016		2015
Current:
Exchange Gas Obligation	$	7.8	$	10.3
Renewable Energy Portfolio Standards		3.9		4.0
Power Supply Contract Divestitures		0.3		0.3

Total Energy Supply Obligations—Current	$	12.0	$	14.6

Noncurrent:
Power Supply Contract Divestitures	$	1.3	$	1.6

Total Energy Supply Obligations	$	13.3	$	16.2

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 are expected to be finalized and submitted to MDPU for approval in 2017. 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).

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

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

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

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

Off-Balance Sheet Arrangements—As of December 31, 2016, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 5).

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2016, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8).

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2016, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Recently Issued Pronouncements—In April and March 2016, the FASB issued ASU 2016-10 and ASU 2016-08, respectively. ASU 2016-10 clarifies the implementation guidance on licensing and the identification of performance obligations considerations included in ASU 2014-09. ASU 2016-08 provides amendments to clarify the implementation guidance on principal versus agent considerations included in ASU 2014-09. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company will implement the standard in the first quarter of 2018 on a modified retrospective basis and it is not expected to have a material impact on the Company’s Consolidated Financial Statements.

In March 2016, the FASB issued ASU 2016-09, which provides for improvements to employee share-based payment accounting. ASU 2016-09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The Company does not expect that this new guidance will have a material impact on the Company’s Consolidated Financial Statements.

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

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

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

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

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

Quarterly Financial Information

12 Months Ended

Dec. 31, 2016

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,
	2016		2015		2016		2015		2016		2015		2016		2015
Total Operating Revenues	$	125.8	$	172.2	$	74.5	$	77.5	$	78.8	$	74.7	$	104.3	$	102.4
Operating Income	$	23.4	$	28.4	$	9.5	$	8.9	$	11.1	$	7.3	$	21.3	$	18.5
Net Income (Loss) Applicable to Common	$	10.9	$	13.6	$	2.5	$	1.7	$	3.5	$	1.7	$	10.2	$	9.3

	Per Share Data:
Earnings Per Common Share	$	0.78	$	0.98	$	0.18	$	0.12	$	0.25	$	0.12	$	0.73	$	0.67
Dividends Paid Per Common Share	$	0.355	$	0.350	$	0.355	$	0.350	$	0.355	$	0.350	$	0.355	$	0.350

Segment Information

12 Months Ended

Dec. 31, 2016

Segment Information

Note 3: Segment Information

Unitil reports three segments: utility gas operations, utility electric operations and non-regulated. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine.

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

Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to a national client base of large commercial and industrial customers. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated column below.

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

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

The following table provides significant segment financial data for the years ended December 31, 2016, 2015 and 2014 (millions):


Year Ended December 31, 2016	Gas		Electric		Non- Regulated		Other			Total

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

Year Ended December 31, 2014

Revenues	$	201.4	$	218.7	$	5.7	$	—		$	425.8

Interest Income		0.3		0.6		0.1		0.3			1.3

Interest Expense		11.5		9.1		—		1.6			22.2

Depreciation & Amortization Expense		18.8		22.3		—		1.0			42.1

Income Tax Expense (Benefit)		10.8		4.5		0.6		(1.9	)		14.0

Segment Profit		15.8		6.8		0.9		1.2			24.7

Segment Assets		564.9		412.6		6.3		13.2			997.0

Capital Expenditures		62.3		24.8		0.3		5.2			92.6

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Allowance for Doubtful Accounts

12 Months Ended

Dec. 31, 2016

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 2016, 2015 and 2014, the Company recorded provisions for the energy commodity portion of bad debts of $1.6 million, $2.6 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 2014—2016 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
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

Year Ended December 31, 2014
Electric	$	1.3	$	2.9	$	0.3	$	3.2	$	1.3
Gas		0.2		3.1		0.3		3.2		0.4
Other		0.1		—		—		—		0.1

	$	1.6	$	6.0	$	0.6	$	6.4	$	1.8

Debt and Financing Arrangements

12 Months Ended

Dec. 31, 2016

Debt and Financing Arrangements

Note 5: Debt and Financing Arrangements

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

Long-Term Debt and Interest Expense

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

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of 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 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, 2016, in accordance with the covenants, these subsidiary companies had a combined amount of $199.7 million available for the payment of dividends and Unitil Corporation had $83.4 million available for the payment of dividends. As of December 31, 2016, the Company’s balance in Retained Earnings was $52.2 million. Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2016 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.

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

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $19.0 million, $7.4 million, and $4.4 million in 2016, 2015, and 2014, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2016 is: 2017 – $17.2 million; 2018 – $30.1 million; 2019 – $18.8 million; 2020 – $19.8 million; 2021 – $8.6 million and thereafter $242.1 million.

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


Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2016		2015
Estimated Fair Value of Long-Term Debt	$	370.3	$	345.2

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


Long-Term Debt (millions)	December 31,
Long-Term Debt (millions)	2016		2015
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
3.70% Notes, Due August 1, 2026		30.0		—

Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		9.0		12.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0

Fitchburg Long-Term Notes:
6.75% Notes, Due November 30, 2023		9.5		11.4
6.79% Notes, Due October 15, 2025		10.0		10.0
7.37% Notes, Due January 15, 2029		12.0		12.0
5.90% Notes, Due December 15, 2030		15.0		15.0
7.98% Notes, Due June 1, 2031		14.0		14.0

Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		20.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0

Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		6.7		10.0

Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		0.4		1.1

Total Long-Term Debt		336.6		325.5
Less: Unamortized Debt Issuance Costs		3.0		2.9

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		333.6		322.6
Less: Current Portion		16.8		17.1

Total Long-Term Debt, Less Current Portion	$	316.8	$	305.5

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

Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset. A summary of interest expense and interest income is provided in the following table:


Interest Expense, net (millions)
	2016			2015			2014
Interest Expense
Long-Term Debt	$	21.8		$	22.0		$	20.5
Short-Term Debt		1.4			0.9			1.1
Regulatory Liabilities		0.5			0.9			0.6

Subtotal Interest Expense		23.7			23.8			22.2

Interest Income
Regulatory Assets		(0.3	)		(0.7	)		(0.6	)
AFUDC⁽¹⁾ and Other		(0.9	)		(1.2	)		(0.7	)

Subtotal Interest Income		(1.2	)		(1.9	)		(1.3	)

Total Interest Expense, net	$	22.5		$	21.9		$	20.9

⁽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 London Interbank Offered Rate (LIBOR) plus 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $218.2 million and $140.3 million for the years ended December 31, 2016 and December 31, 2015, respectively. Total gross repayments were $178.3 million and $127.6 million for the years ended December 31, 2016 and December 31, 2015, respectively. In the third quarter of 2016, the Company issued a standby letter of credit for $1.1 million. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2016 and December 31, 2015:


Revolving Credit Facility (millions)
	December 31,
	2016		2015
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	81.9	$	42.0
Letters of Credit Outstanding	$	1.1	$	0.0
Available	$	37.0	$	78.0

The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2016 and December 31, 2015, 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 1.8%, 1.5%, and 1.6% during 2016, 2015, and 2014, 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.

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, 2016, there are $2.6 million of current and $7.8 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 $9.9 million and $10.8 million of natural gas storage inventory at December 31, 2016 and 2015, respectively, related to these asset management agreements. 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. The amount of natural gas inventory released in December 2015, which was payable in January 2016, was $0.6 million and recorded in Accounts Payable at December 31, 2015.

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, 2016, 2015 and 2014 amounted to $1.8 million, $1.7 million and $1.3 million respectively.

Assets under capital leases amounted to approximately $11.3 million and $15.3 million as of December 31, 2016 and 2015, respectively, less accumulated amortization of $1.0 million and $0.8 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets.

The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2016. The payments for capital leases consist of $3.0 million of current Capital Lease Obligations and $8.3 million of noncurrent Capital Lease Obligations on the Company’s Consolidated Balance Sheets as of December 31, 2016. $2.6 million of the current Capital Lease Obligations and $7.8 million of the noncurrent Capital Lease Obligations reflect amounts under a financing arrangement entered into in April 2014 for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation.


Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2017	$	1,274	$	3,015
2018		926		2,973
2019		582		2,935
2020		405		2,373
2021		236		2
2022 – 2026		132		—

Total Payments	$	3,555	$	11,298

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, 2016, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2017.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of December 31, 2016, the principal amount outstanding for the 8% Unitil Realty notes was $0.4 million, and the principal amount outstanding for the 7.15% Granite State notes was $6.7 million.

Equity

12 Months Ended

Dec. 31, 2016

Equity

Note 6: Equity

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

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 13,991,430 and 14,065,230 shares of common stock outstanding at December 31, 2015 and December 31, 2016, respectively. The Company has 25,000,000 shares of common stock authorized as of December 31, 2015 and December 31, 2016.

Dividend Reinvestment and Stock Purchase Plan—During 2016, the Company sold 32,095 shares of its common stock, at an average price of $40.55 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.3 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. During 2015 and 2014, the Company raised $1.3 million and $1.2 million, respectively, through the issuance of 36,265 and 38,020 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on May 1, 2014, the Company may periodically repurchase shares of its common stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. (See Part II, Item 5, for additional information). During 2016, 2015 and 2014, the Company repurchased 1,949, 1,981 and 2,763 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.1 million, $0.1 million and $0.1 million in 2016, 2015 and 2014, respectively.

During 2016, 2015 and 2014, the Company did not cancel or retire any of its common stock.

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

Stock Plan—The Company maintains the Unitil Corporation Second Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an Award.

Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

Restricted Shares issued for 2014 – 2016 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/31/14	35,500	$1.1
1/26/15	40,010	$1.5
1/26/16	43,220	$1.6
4/19/16	800	<$0.1

There were 93,747 and 70,761 non-vested shares under the Stock Plan as of December 31, 2016 and 2015, respectively. The weighted average grant date fair value of these shares was $35.29 per share and $32.56 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $2.2 million, $1.9 million and $1.4 million in 2016, 2015 and 2014, respectively. At December 31, 2016, there was approximately $1.1 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were 2,315 restricted shares forfeited and zero restricted shares cancelled under the Stock Plan during 2016. On January 30, 2017, there were 34,930 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.6 million.

Restricted Stock Units

Restricted Stock Units, which are issued to members of the Company’s Board of Directors, earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units.

The equity portion of Restricted Stock Units activity during 2016 and 2015 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	2016				2015
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		33,588	$	31.83		23,576	$	29.90
Restricted Stock Units Granted		8,505	$	38.51		8,965	$	36.54
Dividend Equivalents Earned		1,252	$	41.00		1,047	$	35.01
Restricted Stock Units Settled		—		—		—		—

Ending Restricted Stock Units		43,345	$	33.40		33,588	$	31.83

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2016 and 2015 is $0.8 million and $0.5 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

Preferred Stock

There was $0.2 million, or 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2016. There was $0.2 million, or 1,898 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of December 31, 2015. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31, 2016 and December 31, 2015, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share (EPS).


(Millions except shares and per share data)	2016		2015		2014
Earnings Available to Common Shareholders	$	27.1	$	26.3	$	24.7

Weighted Average Common Shares Outstanding—Basic (000’s)		13,990		13,917		13,843
Plus: Diluted Effect of Incremental Shares (000’s)		6		3		4

Weighted Average Common Shares Outstanding—Diluted (000’s)		13,996		13,920		13,847

Earnings per Share—Basic and Diluted	$	1.94	$	1.89	$	1.79

The following table shows the number of weighted average non-vested restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.

2016

2015

2014

Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation

600

36,941

—

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6521494

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+ Details

Energy Supply

12 Months Ended

Dec. 31, 2016

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 2016, 78% of Unitil’s largest New Hampshire gas customers, representing 27% of Unitil’s New Hampshire gas sales and 66% of Unitil’s largest Maine customers, representing 26% of Unitil’s Maine gas 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 2016, 79% of Unitil’s largest Massachusetts gas customers, representing 30% of Unitil’s Massachusetts gas 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 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) markets for the purpose of facilitating wholesale electric power supply transactions, which are necessary to serve Unitil’s electric customers with their supply of electricity.

Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2016, 80% of Unitil’s largest New Hampshire customers, representing 26% of Unitil’s New Hampshire electric energy sales and 85% of Unitil’s largest Massachusetts customers, representing 34% of Unitil’s Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 19% of Fitchburg’s customer base and customers in Ashby comprise another 5%.

In New Hampshire, the number of residential customers purchasing from a third party supplier has increased significantly since 2014 and currently stands at 13% of residential customers. Notwithstanding this recent activity, most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs.

Regulated Electric Power Supply

In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts 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 settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

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

Regional Electric Transmission and Power Markets

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

Electric Power Supply Divestiture

In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Long-Term Renewable Contracts

Fitchburg has entered into long-term renewable contracts for 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 are currently under negotiation. These are expected to be finalized and submitted to MDPU for approval in 2017. 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

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies

Note 8: Commitments and Contingencies

Regulatory Matters

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

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 customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted. The MDPU, the NHPUC and the MPUC have each continued to approve these reconciling rate mechanisms which allow Fitchburg, Unitil Energy and Northern Utilities to recover their actual wholesale energy costs for electric power and natural gas.

In connection with the implementation of retail choice, Unitil Power and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31, 2016. The remaining balance of these assets is $1.6 million as of December 31, 2016, including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next year and $1.3 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the next five 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.

Rate Case Activity

Unitil Energy—Base Rates—On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the New Hampshire Public Utilities Commission (NHPUC). The Company’s filing seeks an increase in base rates of approximately $6.3 million or 3.6 percent above present rates. The Company also requested a long-term rate plan for the annual recovery in future years of the costs associated with utility plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the Office of Consumer Advocate on a $2.4 million temporary rate increase effective July 1, 2016. The temporary rate increase will remain in effect until a permanent rate increase decision is issued. Once a permanent rate is decided, it will be reconciled back to the effective date of the temporary rate increase. The Company is currently engaged in settlement discussions with the Commission and the Office of the Consumer Advocate on the remaining issues in the rate case. Any settlement in the rate case or additional investigation and litigation is expected to be completed for final approval by NHPUC by the end of April, 2017.

Fitchburg—Base Rates—Electric—On April 29, 2016 the Massachusetts Department of Public Utilities (MDPU) issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism, providing for annual adjustments to target revenues to account for capital spending. In 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and requesting $0.5 million of the associated revenue requirements for recovery beginning January 1, 2017. On December 27, 2016 the MDPU approved this filing subject to further investigation and reconciliation.

Fitchburg—Base Rates—Gas—On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg—Gas Operations—On October 31, 2015, Fitchburg submitted its second annual filing to recover the estimated costs to be incurred in 2016 under its approved 20 year gas system enhancement plan program. The program was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. Effective May 1, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments in the program through the end of 2016. On October 31, 2016, Fitchburg submitted its third annual filing to recover the estimated cost to be incurred in 2017 under the gas system enhancement plan program, seeking approval to collect an additional $0.9 million to recover the cumulative cost of investments in the program through the end of 2017. In addition, the Company seeks a waiver of the 1.5 percent cap on annual changes in the revenue requirement eligible for recovery. The MDPU’s decision on this request is pending and is expected by the end of April, 2017, for rates effective May 1, 2017.

Northern Utilities—Base Rates—Maine—The rate case settlement in Northern Utilities’ Maine division’s last rate case allowed the Company to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years and covers targeted capital expenditures in 2013 through 2016. The 2016 TIRA, for 2015 expenditures, was filed on February 29, 2016, and provides for an annual increase in distribution base revenue of $1.5 million, effective May 1, 2016, and was approved by the MPUC on April 28, 2016.

Northern Utilities—Targeted Area Build-out Program—Maine—On December 22, 2015 the MPUC approved a new Targeted Area Build-out program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine and is being initially piloted in the City of Saco. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. This pilot program is planned to be built out over the next three years and has the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco pilot area. The Company will continue to evaluate the success of the program and ways to economically reach new targeted service areas.

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

Northern Utilities—Pipeline Refund—On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers. In New Hampshire, the refund is being credited to all customers over a three year period as directed by the NHPUC. In Maine, the refund has been divided into two parts, as directed by the MPUC. Maine retail customers who purchase their gas directly from Northern Utilities are being credited their portion of the refund over a three year period. The second part of the refund was paid on October 5, 2015 as a one-time lump sum payment directly to marketers who transport gas on Northern Utilities’ distribution system. The Company has recorded current and noncurrent Regulatory Liabilities related to these refunds of $4.4 million and $2.4 million, respectively, on its Consolidated Balance Sheets as of December 31, 2016.

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

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding—In May 2015, the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard (“EERS”), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs.

Unitil Energy—Electric Grid Modernization—In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC has engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The report is expected to be filed in early 2017. Unitil Energy is an active participant in the Working Group. This matter remains pending.

Unitil Energy—Net Metering—Pursuant to legislation that became effective in May 2016, the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The legislation requires that a decision on this matter must be issued by the NHPUC by March 2, 2017. The NHPUC approved an extension of the current net metering tariffs on an interim basis until it issues its final decision on June 2, 2017. Unitil Energy is an active participant in this proceeding.

Fitchburg—Electric Operations—On November 17, 2016, Fitchburg submitted its 2016 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were given final approval by the MDPU on December 29, 2016, effective January 1, 2017.

Fitchburg—Service Quality—On March 1, 2016, Fitchburg submitted its 2015 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. Fitchburg’s annual gas and electric divisions’ Service Quality Reports for the periods up through 2014 have all been approved by the MDPU. On September 30, 2016 the MDPU approved Fitchburg’s 2015 electric division Service Quality Report as filed, and on November 22, 2016 the MDPU approved Fitchburg’s 2015 gas division Service Quality Report.

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

Fitchburg—Solar Generation—On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts. The proposal includes a cost recovery mechanism that would share the costs and benefits of the project among all Fitchburg customers. On October 27, 2016 a Settlement Agreement supporting the proposal was reached between the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. The Settlement Agreement was approved by the MDPU on November 9, 2016. Construction of the solar generating facility is expected to be completed by the end of November 2017.

Fitchburg—Energy Diversity—Governor Baker signed into law H4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC) to jointly and competitively solicit proposals for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016.

Fitchburg—Clean Energy RFP—Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposals for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016 and joint evaluation activities are ongoing. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations are underway for several proposed projects. Fitchburg’s final contracts will be subject to review and approval of the MDPU.

Fitchburg—Other—On September 23, 2016, the Massachusetts Department of Energy Resources (“DOER”) presented its Solar Incentive Straw Proposal in accordance with Chapter 75 of the Acts of 2016 which directed the DOER to develop a statewide solar incentive program to encourage the continued development of solar renewable energy generating sources by residential, commercial, governmental and industrial electricity customers throughout the commonwealth. The program would replace the state’s expiring solar incentive program, which uses solar renewable energy credits (“SRECs”) and is known as SREC-2, with a tariff program. The tariff would provide for incentive payments which would be net of energy value (i.e., total tariff rate minus value of energy). The program also includes a variety of tariff adders, including incentives for location, such as landfill site, for off-takers, such as a community aggregation program, and for other technologies, such as behind-the-meter storage. Cost recovery of tariff payments and administrative costs may be made through a fixed, non-bypassable monthly charge to all distribution customers. Comments on the straw proposal were filed on October 28, 2016. The DOER’s implementation schedule includes filing emergency regulations, conducting a rulemaking during winter 2017 to permanently promulgate emergency regulation, MDPU review of model tariffs in spring 2017, and final program implementation in summer 2017.

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, and to make additional clerical changes to the Net Metering Regulations. On July 15, 2016, the MDPU issued an order approving Final Net Metering Regulations. The distribution companies were required to submit draft net metering tariffs to comply with the new regulations, which they did on September 1, 2016. On January 6, 2017, the MDPU approved the model tariff and ordered the utilities to file compliance tariffs on January 20, 2017. This matter remains pending.

On August 23, 2016 the MDPU held a technical session to discuss its straw proposal for a monthly minimum reliability contribution (“MMRC”). The purpose of the MMRC is for all distribution company customers to contribute to the fixed costs that ensure the reliability, proper maintenance, and safety of the electric distribution system. Parties in the proceeding filed alternative proposals on October 11, 2016. On January 13, 2017, the MDPU issued an order noting that no consensus was reached with respect to its straw proposal. The MDPU stated that it has the authority to consider proposals for an MMRC and sets limitations on when and how it may approve such a proposal, and that it is each distribution company’s discretion whether to file an MMRC proposal and what such a proposal would include.

In December 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” In June 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP is a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filings are currently under MDPU review and remain pending.

On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its EES; and found that each Program Administrator’s Three-Year Plan is consistent with the Green Communities Act, the Guidelines, and Department precedent.

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

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The 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 that this suit is without merit and will continue to defend itself vigorously. The Town of Lunenburg filed a separate action in the Court arising out of the December 2008 ice storm. The Court granted the Company’s Motion for Summary Judgment on all counts in December 2016 and dismissed the Town’s complaint. The Court’s decision remains subject to a potential motion for reconsideration and appeal. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

Environmental Matters

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2016, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. 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—Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

Northern Utilities has worked with the Maine Department of Environmental Protection (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston, Portland and Scarborough sites, though on site monitoring continues and it is possible that future activities may be required.

In December 2016, the ME DEP issued a Certificate of Completion for the Portland remediation activities completed in early 2016. Pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the Portland site will be primarily the responsibility of the State of Maine.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. 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—Fitchburg has worked with the Massachusetts Department of Environmental Protection (MA DEP) to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.

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, 2016 and 2015.

Environmental Obligations


	(millions)
	Fitchburg				Northern Utilities				Total
	2016		2015		2016		2015		2016		2015
Total Balance at Beginning of Period	$	1.2	$	1.9	$	1.6	$	3.6	$	2.8	$	5.5
Additions		—		—		1.8		2.9		1.8		2.9
Less: Payments / Reductions		1.1		0.7		1.6		4.9		2.7		5.6

Total Balance at End of Period	$	0.1	$	1.2	$	1.8	$	1.6	$	1.9	$	2.8

Less: Current Portion		0.1		0.2		0.3		1.1		0.4		1.3

Noncurrent Balance at December 31,	$	—	$	1.0	$	1.5	$	0.5	$	1.5	$	1.5

Income Taxes

12 Months Ended

Dec. 31, 2016

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, 2016, 2015 and 2014 are shown in the table below:


	($000’s)
	2016		2015			2014
Current Income Tax Provision
Federal	$	—	$	—		$	—
State		—		3,530			(387	)

Total Current Income Taxes		—		3,530			(387	)

Deferred Income Provision
Federal		11,209		12,413			10,809
State		4,145		(500	)		3,573

Total Deferred Income Taxes		15,354		11,913			14,382

Total Income Tax Expense	$	15,354	$	15,443		$	13,995

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:


	2016			2015			2014
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		4			5			2
Utility Plant Differences		(1	)		(2	)		(1	)
Tax Credits		(1	)		(1	)		—
Other, net		—			1			1

Effective Income Tax Rate		36	%		37	%		36	%

Temporary differences which gave rise to deferred tax assets and liabilities in 2016 and 2015, are shown below:


Temporary Differences (000’s)	2016		2015
Deferred Tax Assets
Retirement Benefit Obligations	$	56,804	$	43,543
Net Operating Loss Carryforwards		23,921		10,500
Tax Credit Carryforwards		3,365		2,677
Other, net		1,426		4,019

Total Deferred Tax Assets	$	85,516	$	60,739

Deferred Tax Liabilities
Utility Plant Differences	$	169,240	$	142,412
Regulatory Assets & Liabilities		10,594		5,445
Other, net		3,629		348

Total Deferred Tax Liabilities		183,463		148,205

Net Deferred Tax Liabilities	$	97,947	$	87,466

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

The Company filed its tax returns for the year ended December 31, 2015 with the Internal Revenue Service in September 2016 and generated additional federal net operating loss (NOL) carryforward assets principally due to current tax repair deductions, tax depreciation and research and development deductions. The Company has recorded in 2016 a benefit of approximately $0.7 million for New Hampshire business enterprise tax credits utilized in filing the Company’s 2015 tax returns. For the year ended December 31, 2016, the Company generated additional $9.9 million and $2.1 million of federal and state NOL carryforward assets, respectively in the calculation of its provisions for income taxes for the period. As of December 31, 2016, the Company had recorded cumulative federal and state NOL carryforward assets of $23.9 million to offset against taxes payable in future periods. If unused, the Company’s NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2016, the Company had $3.4 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, 2016 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2013; December 31, 2014; and December 31, 2015.

Retirement Benefit Plans

12 Months Ended

Dec. 31, 2016

Retirement Benefit Plans

Note 10: Retirement Benefit Plans

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

•

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

•

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

•

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

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


	2016			2015			2014
Used to Determine Plan costs for years ended December 31:
Discount Rate⁽¹⁾		4.30	%		4.00	%		4.80	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2022			2018			2018
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,352		$	1,383		$	989
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(1,032	)	$	(1,040	)	$	(771	)

⁽¹⁾

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


Used to Determine Benefit Obligations at December 31:
Discount Rate		4.10	%		4.30	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
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)	$	19,471		$	14,877		$	15,325
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(15,153	)	$	(11,611	)	$	(11,829	)

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 2016, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $524,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2016 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
	2016			2015			2014			2016			2015			2014			2016		2015		2014

Service Cost	$	3,402		$	3,689		$	3,006		$	2,610		$	2,622		$	1,988		$	162	$	120	$	57

Interest Cost		5,945			5,392			5,092			3,232			2,918			2,686			386		330		272

Expected Return on Plan Assets		(7,257	)		(6,779	)		(6,245	)		(1,205	)		(1,093	)		(920	)		—		—		—

Prior Service Cost Amortization		263			265			211			1,486			1,682			1,682			189		85		11

Actuarial Loss Amortization		4,398			4,714			2,847			1,049			1,150			56			375		327		100


Sub-total		6,751			7,281			4,911			7,172			7,279			5,492			1,112		862		440

Amounts Capitalized or Deferred		(3,008	)		(3,397	)		(1,881	)		(3,351	)		(3,423	)		(2,270	)		—		—		—

NPBC Recognized	$	3,743		$	3,884		$	3,030		$	3,821		$	3,856		$	3,222		$	1,112	$	862	$	440

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 $5.0 million, $3.5 million and $0.5 million for the Pension, PBOP and SERP plans, respectively.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2016, 2015 and 2014 before capitalization and deferral was $6.8 million, $7.3 million and $4.9 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2016, 2015 and 2014 would have been $7.7 million, $7.3 million and $4.3 million respectively.

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


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2016			2015			2016			2015			2016			2015

Plan Assets at Beginning of Year	$	87,194		$	86,744		$	14,174		$	12,840		$	—		$	—

Actual Return on Plan Assets		3,618			645			792			(214	)		—			—

Employer Contributions		5,146			4,215			4,000			4,000			34			40

Participant Contributions		—			—			61			63			—			—

Benefits Paid		(4,900	)		(4,410	)		(2,421	)		(2,515	)		(34	)		(40	)

Plan Assets at End of Year	$	91,058		$	87,194		$	16,606		$	14,174		$	—		$	—


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2016			2015			2016			2015			2016			2015
Change in PBO:

PBO at Beginning of Year	$	140,816		$	136,662		$	76,249		$	73,923		$	9,177		$	7,965

Service Cost		3,402			3,689			2,610			2,622			162			120

Interest Cost		5,945			5,392			3,232			2,918			386			330

Participant Contributions		—			—			61			63			—			—

Plan Amendments		—			474			—			—			—			608

Benefits Paid		(4,900	)		(4,410	)		(2,421	)		(2,515	)		(34	)		(40	)

Actuarial (Gain) or Loss		5,176			(991	)		16,928			(762	)		(125	)		194

PBO at End of Year	$	150,439		$	140,816		$	96,659		$	76,249		$	9,566		$	9,177

Funded Status: Assets vs PBO	$	(59,381	)	$	(53,622	)	$	(80,053	)	$	(62,075	)	$	(9,566	)	$	(9,177	)

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 $75.9 million and $64.7 million at December 31, 2016 and 2015, 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 $135.2 million and $126.8 million as of December 31, 2016 and 2015, respectively. The ABO for the SERP was $6.9 million and $7.0 million as of December 31, 2016 and 2015, 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 2017 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
	2016		2015		2014		2016		2015		2014		2016		2015		2014
Employer Contributions	$	5,146	$	4,215	$	4,191	$	4,000	$	4,000	$	3,650	$	34	$	40	$	53
Participant Contributions	$	—	$	—	$	—	$	61	$	63	$	59	$	—	$	—	$	—
Benefit Payments	$	4,900	$	4,410	$	4,246	$	2,421	$	2,515	$	2,184	$	34	$	40	$	53

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2017	$	5,451	$	2,439	$	34
2018		5,475		2,690		33
2019		6,035		2,922		578
2020		6,288		3,138		569
2021		6,759		3,470		703
2022 - 2026		40,623		21,533		3,753

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


Pension Plan	Target Allocation 2017			Actual Allocation at December 31,
	Target Allocation 2017			2016			2015			2014
Equity Funds		47	%		46	%		46	%		49	%
Debt Funds		37	%		37	%		37	%		36	%
Real Estate Fund		10	%		10	%		11	%		10	%
Asset Allocation Fund⁽¹⁾		6	%		7	%		6	%		5	%

Total					100	%		100	%		100	%

(1)

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


PBOP Plan	Target Allocation 2017			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2017			2016			2015			2014
Equity Funds		55	%		55	%		53	%		56	%
Debt Funds		45	%		43	%		47	%		44	%
Other⁽¹⁾		0	%		2	%		0	%		0	%

Total					100	%		100	%		100	%

(1)

Represents investments being held in cash equivalents as of December 31, 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 8.00% for 2016. 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, 2016 and 2015. 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, 2016 and 2015 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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


2015
Pension Plan Assets:
Equity Funds	$	40,124	$	40,124	$	—	$	—
Fixed Income Funds		32,192		32,192		—		—
Asset Allocation Fund		5,527		5,527		—		—

Total Assets in the Fair Value Hierarchy	$	77,843	$	77,843	$	—	$	—

Real Estate Fund–Measured at Net Asset Value		9,351

Total Assets	$	87,194

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, 2016 and 2015 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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	$	—	$	—


2015
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	6,620	$	6,620	$	—	$	—
Equity Funds		7,554		7,554

Total Assets	$	14,174	$	14,174	$	—	$	—

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

The Company’s contributions to the 401(k) Plan were $2,304,000, $2,098,000 and $1,877,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Nature of Operations

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

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.

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

Utility Revenue Recognition

Revenue Recognition-Non-regulated Operations

Depreciation and Amortization

Stock-based Employee Compensation

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

Sales and Consumption Taxes

Income Taxes

Dividends

Cash and Cash Equivalents

Allowance for Doubtful Accounts

Accrued Revenue


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2016		2015
Regulatory Assets—Current	$	37.9	$	26.8
Unbilled Revenues		11.6		11.6

Total Accrued Revenue	$	49.5	$	38.4

Exchange Gas Receivable


Exchange Gas Receivable (millions)	December 31,
Exchange Gas Receivable (millions)	2016		2015
Northern Utilities	$	7.8	$	10.3
Fitchburg		0.5		0.8

Total Exchange Gas Receivable	$	8.3	$	11.1

Gas Inventory

Gas Inventory—The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of December 31, 2016 and 2015.


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

Total Gas Inventory	$	0.6	$	0.8

Utility Plant

Regulatory Accounting


Regulatory Assets consist of the following (millions)	December 31,
Regulatory Assets consist of the following (millions)	2016		2015
Retirement Benefits	$	75.9	$	64.7
Energy Supply & Other Regulatory Tracker Mechanisms		32.7		21.3
Deferred Storm Charges		9.6		15.4
Environmental		10.8		11.2
Income Taxes		7.3		8.5
Other		5.7		5.3

Total Regulatory Assets	$	142.0	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		37.9		26.8

Regulatory Assets—noncurrent	$	104.1	$	99.6

⁽¹⁾

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


Regulatory Liabilities consist of the following (millions)	December 31,
	2016		2015
Regulatory Tracker Mechanisms	$	6.2	$	8.0
Gas Pipeline Refund (Note 8)		6.8		15.7

Total Regulatory Liabilities		13.0		23.7
Less: Current Portion of Regulatory Liabilities		10.4		15.6

Regulatory Liabilities—noncurrent	$	2.6	$	8.1

Derivatives

As of December 31, 2016 and December 31, 2015, the Company had 2.0 billion and 2.5 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

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


		Fair Value
Description	Balance Sheet Location	December 31, 2016		December 31, 2015
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 December 31,
	2016			2015
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	(0.1	)	$	0.3

Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings⁽¹⁾:
Cost of Gas Sales	$	0.3		$	0.2

⁽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


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

Total Marketable Securities	$	1.9	$	0.7

Goodwill and Intangible Assets

Energy Supply Obligations


	December 31,
Energy Supply Obligations consist of the following: (millions)	2016		2015
Current:
Exchange Gas Obligation	$	7.8	$	10.3
Renewable Energy Portfolio Standards		3.9		4.0
Power Supply Contract Divestitures		0.3		0.3

Total Energy Supply Obligations—Current	$	12.0	$	14.6

Noncurrent:
Power Supply Contract Divestitures	$	1.3	$	1.6

Total Energy Supply Obligations	$	13.3	$	16.2

Debt Issuance Costs

Retirement Benefit Obligations

Off-Balance Sheet Arrangements

Commitments and Contingencies

Environmental Matters

Recently Issued Pronouncements

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

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2016 and 2015.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2016		2015
Regulatory Assets—Current	$	37.9	$	26.8
Unbilled Revenues		11.6		11.6

Total Accrued Revenue	$	49.5	$	38.4

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of December 31, 2016 and 2015.


Exchange Gas Receivable (millions)	December 31,
Exchange Gas Receivable (millions)	2016		2015
Northern Utilities	$	7.8	$	10.3
Fitchburg		0.5		0.8

Total Exchange Gas Receivable	$	8.3	$	11.1

Components of Gas Inventory

The following table shows the components of Gas Inventory as of December 31, 2016 and 2015.


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

Total Gas Inventory	$	0.6	$	0.8

Regulatory Assets


Regulatory Assets consist of the following (millions)	December 31,
Regulatory Assets consist of the following (millions)	2016		2015
Retirement Benefits	$	75.9	$	64.7
Energy Supply & Other Regulatory Tracker Mechanisms		32.7		21.3
Deferred Storm Charges		9.6		15.4
Environmental		10.8		11.2
Income Taxes		7.3		8.5
Other		5.7		5.3

Total Regulatory Assets	$	142.0	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		37.9		26.8

Regulatory Assets—noncurrent	$	104.1	$	99.6

⁽¹⁾

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

Regulatory Liabilities


Regulatory Liabilities consist of the following (millions)	December 31,
	2016		2015
Regulatory Tracker Mechanisms	$	6.2	$	8.0
Gas Pipeline Refund (Note 8)		6.8		15.7

Total Regulatory Liabilities		13.0		23.7
Less: Current Portion of Regulatory Liabilities		10.4		15.6

Regulatory Liabilities—noncurrent	$	2.6	$	8.1

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets

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


		Fair Value
Description	Balance Sheet Location	December 31, 2016		December 31, 2015
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 December 31,
	2016			2015
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts	$	(0.1	)	$	0.3

Amount of Loss / (Gain) Reclassified into the Consolidated Statements of Earnings⁽¹⁾:
Cost of Gas Sales	$	0.3		$	0.2

⁽¹⁾

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

Fair Value of Marketable Securities

These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, net.


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

Total Marketable Securities	$	1.9	$	0.7

Components of Energy Supply Obligations


	December 31,
Energy Supply Obligations consist of the following: (millions)	2016		2015
Current:
Exchange Gas Obligation	$	7.8	$	10.3
Renewable Energy Portfolio Standards		3.9		4.0
Power Supply Contract Divestitures		0.3		0.3

Total Energy Supply Obligations—Current	$	12.0	$	14.6

Noncurrent:
Power Supply Contract Divestitures	$	1.3	$	1.6

Total Energy Supply Obligations	$	13.3	$	16.2

Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information


	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2016		2015		2016		2015		2016		2015		2016		2015
Total Operating Revenues	$	125.8	$	172.2	$	74.5	$	77.5	$	78.8	$	74.7	$	104.3	$	102.4
Operating Income	$	23.4	$	28.4	$	9.5	$	8.9	$	11.1	$	7.3	$	21.3	$	18.5
Net Income (Loss) Applicable to Common	$	10.9	$	13.6	$	2.5	$	1.7	$	3.5	$	1.7	$	10.2	$	9.3

	Per Share Data:
Earnings Per Common Share	$	0.78	$	0.98	$	0.18	$	0.12	$	0.25	$	0.12	$	0.73	$	0.67
Dividends Paid Per Common Share	$	0.355	$	0.350	$	0.355	$	0.350	$	0.355	$	0.350	$	0.355	$	0.350

Segment Information (Tables)

12 Months Ended

Dec. 31, 2016

Significant Segment Financial Data

The following table provides significant segment financial data for the years ended December 31, 2016, 2015 and 2014 (millions):


Year Ended December 31, 2016	Gas		Electric		Non- Regulated		Other			Total

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

Year Ended December 31, 2014

Revenues	$	201.4	$	218.7	$	5.7	$	—		$	425.8

Interest Income		0.3		0.6		0.1		0.3			1.3

Interest Expense		11.5		9.1		—		1.6			22.2

Depreciation & Amortization Expense		18.8		22.3		—		1.0			42.1

Income Tax Expense (Benefit)		10.8		4.5		0.6		(1.9	)		14.0

Segment Profit		15.8		6.8		0.9		1.2			24.7

Segment Assets		564.9		412.6		6.3		13.2			997.0

Capital Expenditures		62.3		24.8		0.3		5.2			92.6

Allowance for Doubtful Accounts (Tables)

12 Months Ended

Dec. 31, 2016

Allowance for Doubtful Accounts

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2014—2016 (millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
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

Year Ended December 31, 2014
Electric	$	1.3	$	2.9	$	0.3	$	3.2	$	1.3
Gas		0.2		3.1		0.3		3.2		0.4
Other		0.1		—		—		—		0.1

	$	1.6	$	6.0	$	0.6	$	6.4	$	1.8

Debt and Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value of Long Term Debt


Estimated Fair Value of Long-Term Debt (millions)	December 31,
	2016		2015
Estimated Fair Value of Long-Term Debt	$	370.3	$	345.2

Details on Long Term Debt

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


Long-Term Debt (millions)	December 31,
Long-Term Debt (millions)	2016		2015
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0
3.70% Notes, Due August 1, 2026		30.0		—

Unitil Energy First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0
8.49% Series, Due October 14, 2024		9.0		12.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0

Fitchburg Long-Term Notes:
6.75% Notes, Due November 30, 2023		9.5		11.4
6.79% Notes, Due October 15, 2025		10.0		10.0
7.37% Notes, Due January 15, 2029		12.0		12.0
5.90% Notes, Due December 15, 2030		15.0		15.0
7.98% Notes, Due June 1, 2031		14.0		14.0

Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		20.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0
4.42% Senior Notes, Due October 15, 2044		50.0		50.0

Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		6.7		10.0

Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		0.4		1.1

Total Long-Term Debt		336.6		325.5
Less: Unamortized Debt Issuance Costs		3.0		2.9

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		333.6		322.6
Less: Current Portion		16.8		17.1

Total Long-Term Debt, Less Current Portion	$	316.8	$	305.5

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)
	2016			2015			2014
Interest Expense
Long-Term Debt	$	21.8		$	22.0		$	20.5
Short-Term Debt		1.4			0.9			1.1
Regulatory Liabilities		0.5			0.9			0.6

Subtotal Interest Expense		23.7			23.8			22.2

Interest Income
Regulatory Assets		(0.3	)		(0.7	)		(0.6	)
AFUDC⁽¹⁾ and Other		(0.9	)		(1.2	)		(0.7	)

Subtotal Interest Income		(1.2	)		(1.9	)		(1.3	)

Total Interest Expense, net	$	22.5		$	21.9		$	20.9

⁽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, 2016 and December 31, 2015:


Revolving Credit Facility (millions)
	December 31,
	2016		2015
Limit	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	81.9	$	42.0
Letters of Credit Outstanding	$	1.1	$	0.0
Available	$	37.0	$	78.0

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases


Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2017	$	1,274	$	3,015
2018		926		2,973
2019		582		2,935
2020		405		2,373
2021		236		2
2022 – 2026		132		—

Total Payments	$	3,555	$	11,298

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64930739&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

+ Details

Equity (Tables)

12 Months Ended

Dec. 31, 2016

Restricted Shares Issued in Conjunction with Stock Plan

Restricted Shares issued for 2014 – 2016 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
1/31/14	35,500	$1.1
1/26/15	40,010	$1.5
1/26/16	43,220	$1.6
4/19/16	800	<$0.1

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during 2016 and 2015 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	2016				2015
	Units		Weighted Average Stock Price		Units		Weighted Average Stock Price
Beginning Restricted Stock Units		33,588	$	31.83		23,576	$	29.90
Restricted Stock Units Granted		8,505	$	38.51		8,965	$	36.54
Dividend Equivalents Earned		1,252	$	41.00		1,047	$	35.01
Restricted Stock Units Settled		—		—		—		—

Ending Restricted Stock Units		43,345	$	33.40		33,588	$	31.83

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)	2016		2015		2014
Earnings Available to Common Shareholders	$	27.1	$	26.3	$	24.7

Weighted Average Common Shares Outstanding—Basic (000’s)		13,990		13,917		13,843
Plus: Diluted Effect of Incremental Shares (000’s)		6		3		4

Weighted Average Common Shares Outstanding—Diluted (000’s)		13,996		13,920		13,847

Earnings per Share—Basic and Diluted	$	1.94	$	1.89	$	1.79

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share

The following table shows the number of weighted average non-vested restricted shares that were not included in the above computation of EPS because the effect would have been antidilutive.

2016

2015

2014

Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation

600

36,941

—

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015.

Environmental Obligations


	(millions)
	Fitchburg				Northern Utilities				Total
	2016		2015		2016		2015		2016		2015
Total Balance at Beginning of Period	$	1.2	$	1.9	$	1.6	$	3.6	$	2.8	$	5.5
Additions		—		—		1.8		2.9		1.8		2.9
Less: Payments / Reductions		1.1		0.7		1.6		4.9		2.7		5.6

Total Balance at End of Period	$	0.1	$	1.2	$	1.8	$	1.6	$	1.9	$	2.8

Less: Current Portion		0.1		0.2		0.3		1.1		0.4		1.3

Noncurrent Balance at December 31,	$	—	$	1.0	$	1.5	$	0.5	$	1.5	$	1.5

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Provisions for Federal and State Income Taxes


	($000’s)
	2016		2015			2014
Current Income Tax Provision
Federal	$	—	$	—		$	—
State		—		3,530			(387	)

Total Current Income Taxes		—		3,530			(387	)

Deferred Income Provision
Federal		11,209		12,413			10,809
State		4,145		(500	)		3,573

Total Deferred Income Taxes		15,354		11,913			14,382

Total Income Tax Expense	$	15,354	$	15,443		$	13,995

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:


	2016			2015			2014
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, net		4			5			2
Utility Plant Differences		(1	)		(2	)		(1	)
Tax Credits		(1	)		(1	)		—
Other, net		—			1			1

Effective Income Tax Rate		36	%		37	%		36	%

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to deferred tax assets and liabilities in 2016 and 2015, are shown below:


Temporary Differences (000’s)	2016		2015
Deferred Tax Assets
Retirement Benefit Obligations	$	56,804	$	43,543
Net Operating Loss Carryforwards		23,921		10,500
Tax Credit Carryforwards		3,365		2,677
Other, net		1,426		4,019

Total Deferred Tax Assets	$	85,516	$	60,739

Deferred Tax Liabilities
Utility Plant Differences	$	169,240	$	142,412
Regulatory Assets & Liabilities		10,594		5,445
Other, net		3,629		348

Total Deferred Tax Liabilities		183,463		148,205

Net Deferred Tax Liabilities	$	97,947	$	87,466

Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

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:


	2016			2015			2014
Used to Determine Plan costs for years ended December 31:
Discount Rate⁽¹⁾		4.30	%		4.00	%		4.80	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2022			2018			2018
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	1,352		$	1,383		$	989
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(1,032	)	$	(1,040	)	$	(771	)

⁽¹⁾


Used to Determine Benefit Obligations at December 31:
Discount Rate		4.10	%		4.30	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%		3.00	%
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)	$	19,471		$	14,877		$	15,325
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(15,153	)	$	(11,611	)	$	(11,829	)

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
	2016			2015			2014			2016			2015			2014			2016		2015		2014

Service Cost	$	3,402		$	3,689		$	3,006		$	2,610		$	2,622		$	1,988		$	162	$	120	$	57

Interest Cost		5,945			5,392			5,092			3,232			2,918			2,686			386		330		272

Expected Return on Plan Assets		(7,257	)		(6,779	)		(6,245	)		(1,205	)		(1,093	)		(920	)		—		—		—

Prior Service Cost Amortization		263			265			211			1,486			1,682			1,682			189		85		11

Actuarial Loss Amortization		4,398			4,714			2,847			1,049			1,150			56			375		327		100


Sub-total		6,751			7,281			4,911			7,172			7,279			5,492			1,112		862		440

Amounts Capitalized or Deferred		(3,008	)		(3,397	)		(1,881	)		(3,351	)		(3,423	)		(2,270	)		—		—		—

NPBC Recognized	$	3,743		$	3,884		$	3,030		$	3,821		$	3,856		$	3,222		$	1,112	$	862	$	440

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:	2016			2015			2016			2015			2016			2015

Plan Assets at Beginning of Year	$	87,194		$	86,744		$	14,174		$	12,840		$	—		$	—

Actual Return on Plan Assets		3,618			645			792			(214	)		—			—

Employer Contributions		5,146			4,215			4,000			4,000			34			40

Participant Contributions		—			—			61			63			—			—

Benefits Paid		(4,900	)		(4,410	)		(2,421	)		(2,515	)		(34	)		(40	)

Plan Assets at End of Year	$	91,058		$	87,194		$	16,606		$	14,174		$	—		$	—


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2016			2015			2016			2015			2016			2015
Change in PBO:

PBO at Beginning of Year	$	140,816		$	136,662		$	76,249		$	73,923		$	9,177		$	7,965

Service Cost		3,402			3,689			2,610			2,622			162			120

Interest Cost		5,945			5,392			3,232			2,918			386			330

Participant Contributions		—			—			61			63			—			—

Plan Amendments		—			474			—			—			—			608

Benefits Paid		(4,900	)		(4,410	)		(2,421	)		(2,515	)		(34	)		(40	)

Actuarial (Gain) or Loss		5,176			(991	)		16,928			(762	)		(125	)		194

PBO at End of Year	$	150,439		$	140,816		$	96,659		$	76,249		$	9,566		$	9,177

Funded Status: Assets vs PBO	$	(59,381	)	$	(53,622	)	$	(80,053	)	$	(62,075	)	$	(9,566	)	$	(9,177	)

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
	2016		2015		2014		2016		2015		2014		2016		2015		2014
Employer Contributions	$	5,146	$	4,215	$	4,191	$	4,000	$	4,000	$	3,650	$	34	$	40	$	53
Participant Contributions	$	—	$	—	$	—	$	61	$	63	$	59	$	—	$	—	$	—
Benefit Payments	$	4,900	$	4,410	$	4,246	$	2,421	$	2,515	$	2,184	$	34	$	40	$	53

Estimated Future Benefit Payments

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2017	$	5,451	$	2,439	$	34
2018		5,475		2,690		33
2019		6,035		2,922		578
2020		6,288		3,138		569
2021		6,759		3,470		703
2022 - 2026		40,623		21,533		3,753

Pension Plans

Schedule of Allocation of Plan Assets

The actual investment allocations are shown in the tables below.


Pension Plan	Target Allocation 2017			Actual Allocation at December 31,
	Target Allocation 2017			2016			2015			2014
Equity Funds		47	%		46	%		46	%		49	%
Debt Funds		37	%		37	%		37	%		36	%
Real Estate Fund		10	%		10	%		11	%		10	%
Asset Allocation Fund⁽¹⁾		6	%		7	%		6	%		5	%

Total					100	%		100	%		100	%

(1)

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

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2016 and 2015 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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


2015
Pension Plan Assets:
Equity Funds	$	40,124	$	40,124	$	—	$	—
Fixed Income Funds		32,192		32,192		—		—
Asset Allocation Fund		5,527		5,527		—		—

Total Assets in the Fair Value Hierarchy	$	77,843	$	77,843	$	—	$	—

Real Estate Fund–Measured at Net Asset Value		9,351

Total Assets	$	87,194

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 Allocation 2017			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2017			2016			2015			2014
Equity Funds		55	%		55	%		53	%		56	%
Debt Funds		45	%		43	%		47	%		44	%
Other⁽¹⁾		0	%		2	%		0	%		0	%

Total					100	%		100	%		100	%

(1)

Represents investments being held in cash equivalents as of December 31, 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, 2016 and 2015 are as follows (000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31,		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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	$	—	$	—


2015
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	6,620	$	6,620	$	—	$	—
Equity Funds		7,554		7,554

Total Assets	$	14,174	$	14,174	$	—	$	—

Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, Bcf in Billions		1 Months Ended	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($) Bcf	Feb. 02, 2017 $ / shares	Dec. 31, 2016 USD ($) $ / shares Bcf	Sep. 30, 2016 $ / shares	Jun. 30, 2016 $ / shares	Mar. 31, 2016 $ / shares	Dec. 31, 2015 USD ($) $ / shares Bcf	Sep. 30, 2015 $ / shares	Jun. 30, 2015 $ / shares	Mar. 31, 2015 $ / shares	Dec. 31, 2016 USD ($) Entity Subsidiary mi $ / shares Bcf	Dec. 31, 2015 USD ($) $ / shares Bcf	Dec. 31, 2014 $ / shares
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Entity											3
Length Of Pipeline \| mi											86
Depreciation rate based on average depreciable property balance											3.49%	3.57%	3.56%
Common stock dividend paid per share \| $ / shares			$ 0.355	$ 0.355	$ 0.355	$ 0.355	$ 0.350	$ 0.350	$ 0.350	$ 0.350	$ 1.42	$ 1.40	$ 1.38
Common stock dividend per share, declared \| $ / shares											$ 1.42	$ 1.40	$ 1.38
Average interest rates											2.18%	2.32%	1.56%
Cost of removal obligation	$ 70,100,000		$ 77,000,000				$ 70,100,000				$ 77,000,000	$ 70,100,000
Regulatory Assets	$ 126,400,000		$ 142,000,000				$ 126,400,000				$ 142,000,000	$ 126,400,000
Number of Natural Gas Storage Outstanding \| Bcf	2.5		2.0				2.5				2.0	2.5
Investments in trading securities	$ 700,000		$ 1,900,000				$ 700,000				$ 1,900,000	$ 700,000
Intangible Assets, Purchase Adjustments											$ 4,700,000
Reduction of other assets	(2,900,000)
Reduction of long-term debt	(2,900,000)
Plant
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period											10 years
Bargain Purchase Adjustment
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period											2 years
Annual Electric Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM											27.00%
Annual Natural Gas Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM											11.00%
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period											3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	2,300,000		2,800,000				2,300,000				$ 2,800,000	2,300,000
Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared \| $ / shares		$ 1.44
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits	0		0				0				$ 0	$ 0
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share \| $ / shares											$ 0.355	$ 0.350	$ 0.345
Quarterly Dividends \| Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared \| $ / shares		0.36
Increase in dividend declared amount per share \| $ / shares		$ 0.005
Deferred Storm Charges
Significant Accounting Policies [Line Items]
Regulatory Assets	$ 15,400,000		9,600,000				$ 15,400,000				$ 9,600,000	$ 15,400,000
Deferred Storm Charges \| Period 4
Significant Accounting Policies [Line Items]
Regulatory Assets			3,300,000								3,300,000
Environmental and Rate Case Costs and Other Expenditures \| Recovered over the next seven and a half years
Significant Accounting Policies [Line Items]
Regulatory Assets			$ 8,600,000								$ 8,600,000
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary											3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary											3

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 49.5	$ 38.4
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	11.6	11.6
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 37.9	$ 26.8

Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Receivables [Line Items]
Total Exchange Gas Receivable	$ 8.3	$ 11.1
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	7.8	10.3
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.5	$ 0.8

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.6	$ 0.8
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.2
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.3
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.2	$ 0.3

Regulatory Assets (Detail) - USD ($)
$ in Millions

Dec. 31, 2016

Dec. 31, 2015

Regulatory Assets [Line Items]

Regulatory Assets

$ 142.0

$ 126.4

Less: Current Portion of Regulatory Assets

^[1]

37.9

26.8

Regulatory Assets-noncurrent

104.1

99.6

Environmental Matters

Regulatory Assets [Line Items]

Regulatory Assets

10.8

11.2

Other Assets

Regulatory Assets [Line Items]

Regulatory Assets

5.7

5.3

Retirement Benefits

Regulatory Assets [Line Items]

Regulatory Assets

75.9

64.7

Deferred Storm Charges

Regulatory Assets [Line Items]

Regulatory Assets

9.6

15.4

Income Taxes

Regulatory Assets [Line Items]

Regulatory Assets

7.3

8.5

Energy Supply & Tracker Mechanisms

Regulatory Assets [Line Items]

Regulatory Assets

$ 32.7

$ 21.3

[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) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.0	$ 23.7
Less: Current Portion of Regulatory Liabilities	10.4	15.6
Regulatory Liabilities-noncurrent	2.6	8.1
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	6.2	8.0
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 6.8	$ 15.7

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) - Not Designated as Hedging Instruments - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Assets
Derivative Assets	$ 0.4
Derivative Liabilities
Derivative Liabilities	0.0	$ 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	0.0
Natural Gas Futures Contract \| Other Noncurrent Liabilities
Derivative Liabilities
Derivative Liabilities	$ 0.0	$ 0.0

Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Cost of Gas Sales (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Natural Gas Futures Contract

Regulatory Liabilities [Line Items]

Loss/(Gain) recognized in Regulatory Assets(Liabilities)

$ (0.1)

$ 0.3

Gas Purchase Costs

Regulatory Liabilities [Line Items]

Loss/(Gain) Reclassified into unaudited Consolidated Statement of Earnings

^[1]

$ 0.3

$ 0.2

[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 (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 1.9	$ 0.7
Fair Value, Inputs, Level 1
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	1.9	0.7
Fair Value, Inputs, Level 1 \| Equity Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	1.1	0.4
Fair Value, Inputs, Level 1 \| Fixed Income Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 0.8	$ 0.3

Components of Current and Noncurrent Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 12.0	$ 14.6
Power Supply Contract Divestitures, Noncurrent	1.3	1.6
Total Energy Supply Obligations	13.3	16.2
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	7.8	10.3
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	3.9	4.0
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 0.3	$ 0.3

Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 104.3	$ 78.8	$ 74.5	$ 125.8	$ 102.4	$ 74.7	$ 77.5	$ 172.2	$ 383.4	$ 426.8	$ 425.8
Operating Income	21.3	11.1	9.5	23.4	18.5	7.3	8.9	28.4	65.3	63.1	60.0
Net Income (Loss) Applicable to Common	$ 10.2	$ 3.5	$ 2.5	$ 10.9	$ 9.3	$ 1.7	$ 1.7	$ 13.6	$ 27.1	$ 26.3	$ 24.7
Per Share Data:
Earnings Per Common Share	$ 0.73	$ 0.25	$ 0.18	$ 0.78	$ 0.67	$ 0.12	$ 0.12	$ 0.98	$ 1.94	$ 1.89	$ 1.79
Dividends Paid Per Common Share	$ 0.355	$ 0.355	$ 0.355	$ 0.355	$ 0.350	$ 0.350	$ 0.350	$ 0.350	$ 1.42	$ 1.40	$ 1.38

Segment Information - Additional Information (Detail)	12 Months Ended
Segment Information - Additional Information (Detail)	Dec. 31, 2016 Segment Entity Pipeline mi
Segment Reporting Information [Line Items]
No of segments \| Segment	3
No of subsidiaries \| Entity	3
Length Of Pipeline	86
Granite State Gas Transmission Inc
Segment Reporting Information [Line Items]
Length Of Pipeline	86
No of major pipeline \| Pipeline	3

Significant Segment Financial Data (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 104,300	$ 78,800	$ 74,500	$ 125,800	$ 102,400	$ 74,700	$ 77,500	$ 172,200	$ 383,400	$ 426,800	$ 425,800
Interest Income									1,200	1,900	1,300
Interest Expense									23,700	23,800	22,200
Depreciation & Amortization Expense									46,600	45,700	42,100
Income Tax Expense (Benefit)									15,354	15,443	13,995
Segment Profit	10,200	$ 3,500	$ 2,500	$ 10,900	9,300	$ 1,700	$ 1,700	$ 13,600	27,100	26,300	24,700
Segment Assets	1,128,200				1,038,800				1,128,200	1,038,800	997,000
Capital Expenditures									98,100	103,900	92,600
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									181,200	202,600	201,400
Interest Income									200	800	300
Interest Expense									13,300	13,300	11,500
Depreciation & Amortization Expense									21,900	20,700	18,800
Income Tax Expense (Benefit)									9,200	10,200	10,800
Segment Profit									14,500	15,300	15,800
Segment Assets	645,200				590,900				645,200	590,900	564,900
Capital Expenditures									57,000	64,900	62,300
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									196,100	218,000	218,700
Interest Income									700	700	600
Interest Expense									8,300	8,800	9,100
Depreciation & Amortization Expense									23,800	24,000	22,300
Income Tax Expense (Benefit)									6,600	5,500	4,500
Segment Profit									11,100	8,700	6,800
Segment Assets	441,100				415,100				441,100	415,100	412,600
Capital Expenditures									30,100	29,900	24,800
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									200	300	300
Interest Expense									2,100	1,700	1,600
Depreciation & Amortization Expense									800	900	1,000
Income Tax Expense (Benefit)									(1,200)	(1,100)	(1,900)
Segment Profit									400	1,000	1,200
Segment Assets	35,100				26,200				35,100	26,200	13,200
Capital Expenditures									11,000	9,000	5,200
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									6,100	6,200	5,700
Interest Income									100	100	100
Depreciation & Amortization Expense									100	100
Income Tax Expense (Benefit)									800	800	600
Segment Profit									1,100	1,300	900
Segment Assets	$ 6,800				$ 6,600				$ 6,800	6,600	6,300
Capital Expenditures										$ 100	$ 300

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 4.6	$ 5.3	$ 6.0
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 1.6	$ 2.6	$ 2.6

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	$ 1.2	$ 1.8	$ 1.6
Provision	4.6	5.3	6.0
Recoveries	0.6	0.7	0.6
Accounts Written Off	5.3	6.6	6.4
Balance at End of Period	1.1	1.2	1.8
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.6	1.3	1.3
Provision	2.9	2.5	2.9
Recoveries	0.3	0.3	0.3
Accounts Written Off	3.0	3.5	3.2
Balance at End of Period	0.8	0.6	1.3
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.5	0.4	0.2
Provision	1.7	2.8	3.1
Recoveries	0.3	0.4	0.3
Accounts Written Off	2.3	3.1	3.2
Balance at End of Period	0.2	0.5	0.4
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 Arrangements - Additional Information (Detail) - USD ($)		12 Months Ended
	Oct. 04, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Aug. 01, 2016	Oct. 30, 2015	Oct. 15, 2014
Line of Credit Facility [Line Items]
Amount available for the payment of dividends		$ 83,400,000
Retained Earnings		$ 52,200,000	$ 45,100,000
Restriction on retained earnings for dividend payments		Therefore, there were no restrictions on the Company's Retained Earnings at December 31, 2016 for the payment of dividends.
Issuance of long-term debt		$ 300,000
Long term debt repayments		$ 19,000,000	$ 7,400,000	$ 4,400,000
Weighted average interest rate on short term borrowings		1.80%	1.50%	1.60%
Capital lease obligation, current		$ 3,000,000	$ 3,100,000
Capital lease obligation, noncurrent		8,300,000	11,000,000
Accounts Payable		32,400,000	33,300,000
Total rental expense under operating leases		1,800,000	1,700,000	$ 1,300,000
Net Utility Plant		883,400,000	808,900,000
Guarantee outstanding		17,900,000
Assets under Capital Leases
Line of Credit Facility [Line Items]
Net Utility Plant		11,300,000	15,300,000
Net Utility Plant, accumulated amortization		1,000,000	800,000
Financing Arrangements
Line of Credit Facility [Line Items]
Capital lease obligation, current		2,600,000
Capital lease obligation, noncurrent		$ 7,800,000
Unitil Service Corp.
Line of Credit Facility [Line Items]
Capital lease obligation, total capitalized cost							$ 13,400,000
Capital lease obligation, maturity period		Oct. 30, 2015
Capital lease obligation, current		$ 2,600,000
Capital lease obligation, noncurrent		$ 7,800,000
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		$ 9,900,000	10,800,000
Accounts Payable		$ 2,100,000	600,000
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		$ 199,700,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility		120,000,000	120,000,000
Proceeds from lines of credit		218,200,000	140,300,000
Repayments of lines of credit		178,300,000	127,600,000
Letters of Credit Outstanding		$ 1,100,000	$ 0		$ 1,100,000
Credit Facility \| Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility termination date	Oct. 04, 2020
Revolving credit facility	$ 120,000,000
Sublimit for the issuance of standby letters of credit	25,000,000
Credit Facility by an aggregate additional amount	$ 30,000,000
Percentage of capitalization		The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2016 and December 31, 2015, 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%
8.00% Senior Secured Notes, Due August 1, 2017 \| Unitil Realty Corp
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate		8.00%	8.00%
Long-term debt, maturity date		Aug. 01, 2017	Aug. 01, 2017
Senior Secured Notes		$ 400,000	$ 1,100,000
7.15% Senior Notes, Due December 15, 2018 \| Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate		7.15%	7.15%
Long-term debt, maturity date		Dec. 15, 2018	Dec. 15, 2018
Senior Notes		$ 6,700,000	$ 10,000,000
3.70% Senior Unsecured Notes due August 1, 2026
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 30,000,000
Long-term debt, stated interest rate		3.70%				3.70%
Long-term debt, maturity date		Aug. 01, 2026
Senior Notes		$ 30,000,000
4.42% Senior Unsecured Notes due October 15, 2044 \| Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount								$ 50,000,000
Long-term debt, stated interest rate								4.42%
Long-term debt, maturity date		Oct. 15, 2044
Bonds
Line of Credit Facility [Line Items]
Long term debt repayments		$ 19,000,000	$ 7,400,000	$ 4,400,000
Debt repayment, 2017		17,200,000
Debt repayment, 2018		30,100,000
Debt repayment, 2019		18,800,000
Debt repayment, 2020		19,800,000
Debt repayment, 2021		8,600,000
Debt repayment, Thereafter		$ 242,100,000

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 370.3	$ 345.2

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total Long-Term Debt	$ 336.6	$ 325.5
Less: Unamortized Debt Issuance Costs	3.0	2.9
Long-Term Debt	333.6	322.6
Less: Current Portion	16.8	17.1
Total Long-Term Debt, Less Current Portion	316.8	305.5
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20.0	20.0
3.70% Senior Unsecured Notes due August 1, 2026
Debt Instrument [Line Items]
Senior Notes	30.0
Unitil Energy Systems Inc \| First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	9.0	12.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Fitchburg Gas and Electric Light Company \| 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	9.5	11.4
Fitchburg Gas and Electric Light Company \| 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0
Fitchburg Gas and Electric Light Company \| 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0
Fitchburg Gas and Electric Light Company \| 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Fitchburg Gas and Electric Light Company \| 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0
Northern Utilities Inc \| 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	20.0	30.0
Northern Utilities Inc \| 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25.0	25.0
Northern Utilities Inc \| 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50.0	50.0
Northern Utilities Inc \| 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Senior Notes	50.0	50.0
Granite State Gas Transmission Inc \| 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	6.7	10.0
Unitil Realty Corp \| 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 0.4	$ 1.1

Details on Long Term Debt (Parenthetical) (Detail)	12 Months Ended
Details on Long Term Debt (Parenthetical) (Detail)	Dec. 31, 2016	Dec. 31, 2015	Aug. 01, 2016
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%
Debt instrument due date	May 01, 2022	May 01, 2022
3.70% Senior Unsecured Notes due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate	3.70%		3.70%
Debt instrument due date	Aug. 01, 2026
First Mortgage Bonds 5.24% Series, Due March 2, 2020 \| Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%
Debt instrument due date	Mar. 02, 2020	Mar. 02, 2020
First Mortgage Bonds 8.49% Series, Due October 14, 2024 \| Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%
Debt instrument due date	Oct. 14, 2024	Oct. 14, 2024
First Mortgage Bonds 6.96% Series, Due September 1, 2028 \| Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%
Debt instrument due date	Sep. 01, 2028	Sep. 01, 2028
First Mortgage Bonds 8.00% Series, Due May 1, 2031 \| Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Debt instrument due date	May 01, 2031	May 01, 2031
First Mortgage Bonds 6.32% Series, Due September 15, 2036 \| Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%
Debt instrument due date	Sep. 15, 2036	Sep. 15, 2036
6.75% Notes, Due November 30, 2023 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%
Debt instrument due date	Nov. 30, 2023	Nov. 30, 2023
6.79% Notes, Due October 15, 2025 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%
Debt instrument due date	Oct. 15, 2025	Oct. 15, 2025
7.37% Notes, Due January 15, 2029 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%
Debt instrument due date	Jan. 15, 2029	Jan. 15, 2029
5.90% Notes, Due December 15, 2030 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%
Debt instrument due date	Dec. 15, 2030	Dec. 15, 2030
7.98% Notes, Due June 1, 2031 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%
Debt instrument due date	Jun. 01, 2031	Jun. 01, 2031
6.95% Senior Notes, Series A, Due December 3, 2018 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%
Debt instrument due date	Dec. 03, 2018	Dec. 03, 2018
5.29% Senior Notes, Due March 2, 2020 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%
Debt instrument due date	Mar. 02, 2020	Mar. 02, 2020
7.72% Senior Notes, Series B, Due December 3, 2038 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%
Debt instrument due date	Dec. 03, 2038	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.42%	4.42%
Debt instrument due date	Oct. 15, 2044	Oct. 15, 2044
7.15% Senior Notes, Due December 15, 2018 \| Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%
Debt instrument due date	Dec. 15, 2018	Dec. 15, 2018
8.00% Senior Secured Notes, Due August 1, 2017 \| Unitil Realty Corp
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Debt instrument due date	Aug. 01, 2017	Aug. 01, 2017

Summary of Interest Expense and Interest Income (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Interest Expense

Long-Term Debt

$ 21.8

$ 22.0

$ 20.5

Short-Term Debt

1.4

0.9

1.1

Regulatory Liabilities

0.5

0.9

0.6

Interest Expense

23.7

23.8

22.2

Interest Income

Interest income

(1.2)

(1.9)

(1.3)

Total Interest Expense, net

22.5

21.9

20.9

Regulatory Assets

Interest Income

Interest income

(0.3)

(0.7)

(0.6)

AFUDC and Other

Interest Income

Interest income

^[1]

$ (0.9)

$ (1.2)

$ (0.7)

[1]	AFUDC-Allowance for Funds Used During Construction

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 81,900,000		$ 42,000,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility	120,000,000		120,000,000
Short-Term Borrowings Outstanding	81,900,000		42,000,000
Letters of Credit Outstanding	1,100,000	$ 1,100,000	0
Available revolving credit facility	$ 37,000,000		$ 78,000,000

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) $ in Thousands	Dec. 31, 2016 USD ($)
Operating leases
2017	$ 1,274
2018	926
2019	582
2020	405
2021	236
2022 - 2026	132
Total Payments	3,555
Capital lease
2017	3,015
2018	2,973
2019	2,935
2020	2,373
2021	2
2022 - 2026	0
Total Payments	$ 11,298

Equity - Additional Information (Detail) - USD ($)		12 Months Ended
Equity - Additional Information (Detail) - USD ($)	Jan. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Common stock, shares outstanding		14,065,230	13,991,430
Common stock, shares authorized		25,000,000	25,000,000
Common stock, shares issued		32,095	36,265	38,020
Proceeds from Issuance of Common Stock		$ 1,300,000	$ 1,300,000	$ 1,200,000
Common stock shares repurchase		1,949	1,981	2,763
Repurchase expense		$ 100,000	$ 100,000	$ 100,000
Share based compensation expense		$ 2,200,000	1,900,000	1,400,000
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		$ 800,000	500,000
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]
Proceeds from Issuance of Common Stock		$ 1,300,000	$ 1,300,000	$ 1,200,000
Dividend and Distribution Reinvestment and Share Purchase Plan \| Average
Class of Stock [Line Items]
Common stock price per share		$ 40.55
Dividend and Distribution Reinvestment and Share Purchase Plan \| Common Stock
Class of Stock [Line Items]
Common stock, shares issued		32,095	36,265	38,020
Unitil Energy Systems Inc \| Series 6
Class of Stock [Line Items]
Preferred stock, outstanding		1,893	1,898
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		93,747	70,761
Restricted stock weighted average grant date fair value		$ 35.29	$ 32.56
Unrecognized share based compensation		$ 1,100,000
Share compensation recognition period		2 years 4 months 24 days
Forfeitures or cancellations under the stock plan		2,315
Restricted Stock \| Maximum
Class of Stock [Line Items]
Restricted stock available for awards		677,500
Restricted stock that may be awarded in any one calendar year to any one participant		20,000
Restricted Stock \| Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually		25.00%
Subsequent Event \| Restricted Stock
Class of Stock [Line Items]
Shares	34,930
Aggregate Market Value	$ 1,600,000

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($) shares
Period 1
Class of Stock [Line Items]
Issuance Date	Jan. 31, 2014
Shares \| shares	35,500
Aggregate Market Value \| $	$ 1.1
Period 2
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2015
Shares \| shares	40,010
Aggregate Market Value \| $	$ 1.5
Period 3
Class of Stock [Line Items]
Issuance Date	Jan. 26, 2016
Shares \| shares	43,220
Aggregate Market Value \| $	$ 1.6
Period 4
Class of Stock [Line Items]
Issuance Date	Apr. 19, 2016
Shares \| shares	800
Period 4 \| Maximum
Class of Stock [Line Items]
Aggregate Market Value \| $	$ 0.1

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Units
Beginning Restricted Stock Units	33,588	23,576
Restricted Stock Units Granted	8,505	8,965
Dividend Equivalents Earned	1,252	1,047
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	43,345	33,588
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 31.83	$ 29.90
Restricted Stock Units Granted	38.51	36.54
Dividend Equivalents Earned	41.00	35.01
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	$ 33.40	$ 31.83

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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders									$ 27.1	$ 26.3	$ 24.7
Weighted Average Common Shares Outstanding - Basic									13,990	13,917	13,843
Plus: Diluted Effect of Incremental Shares									6	3	4
Weighted Average Common Shares Outstanding - Diluted									13,996	13,920	13,847
Earnings per Share-Basic and Diluted	$ 0.73	$ 0.25	$ 0.18	$ 0.78	$ 0.67	$ 0.12	$ 0.12	$ 0.98	$ 1.94	$ 1.89	$ 1.79

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	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	600	36,941

Energy Supply - Additional Information (Detail)	12 Months Ended
Energy Supply - Additional Information (Detail)	Dec. 31, 2016 Bcf MMBTU
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities \| MMBTU	115,000,000,000
Natural gas, underground storage \| Bcf	3,600,000,000
Northern Utilities Inc \| Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities \| MMBTU	14,057
Natural gas, underground storage \| Bcf	0.33
Percentage of power supply requirement	50.00%
Power supply contract duration	12 months
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement	100.00%
Power supply contract duration	6 months

Commitments and Contingencies - Additional Information (Detail) $ in Millions							12 Months Ended
	Oct. 31, 2016 USD ($)	Aug. 19, 2016 MW	Jun. 28, 2016 USD ($)	Jun. 24, 2016 USD ($)	Apr. 29, 2016 USD ($)	Apr. 15, 2015 USD ($)	Dec. 31, 2016 USD ($) State Customer	Dec. 31, 2014 USD ($)	Jun. 30, 2027 MW	Dec. 31, 2022 MWh	Jun. 30, 2017 MW	Dec. 31, 2015 USD ($)
Regulatory Assets [Line Items]
Regulatory Assets, Remaining Balance							$ 1.6
Accrued Revenue							49.5					$ 38.4
Regulatory Assets							104.1					99.6
Current Portion of Regulatory Liabilities							10.4					15.6
Regulatory Liabilities - noncurrent							2.6					$ 8.1
Other Restructuring
Regulatory Assets [Line Items]
Accrued Revenue							0.3
Regulatory Assets							$ 1.3
Cost recovery period, years							5 years
Unitil Energy Systems Inc \| New Hampshire
Regulatory Assets [Line Items]
Increase in base rates, amount					$ 6.3
Percent of increase in total revenue					3.60%
Temporary rate increase			$ 2.4
Amendment effective date							Jul. 01, 2016
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Amendment effective date	May 01, 2017				May 01, 2016
Recovery amount	$ 0.9				$ 0.9
Percentage of waiver sought on annual changes in the revenue requirement eligible for recovery	1.50%
Number of states with electric distribution companies \| State							3
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 \| Electric base
Regulatory Assets [Line Items]
Amendment effective date					May 01, 2016		Jan. 01, 2017
Increase in annual revenue					$ 2.1
Recovery amount							$ 0.5
Fitchburg Gas and Electric Light Company \| Gas base
Regulatory Assets [Line Items]
Amendment effective date					May 01, 2016
Increase in annual revenue					$ 1.6
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 \| Offshore Wind Energy \| Scenario Forecast
Regulatory Assets [Line Items]
Power generation facility \| MW									1,600
Fitchburg Gas and Electric Light Company \| Offshore Wind Energy \| Scenario Forecast \| Minimum
Regulatory Assets [Line Items]
Power generation facility \| MW											400
Northern Utilities Inc
Regulatory Assets [Line Items]
Amendment effective date							May 01, 2014
Increase in annual revenue							$ 1.4
TIRA initial term							Four years
Amendment approved date							Apr. 28, 2016
Pipeline refund received						$ 22.0
Current Portion of Regulatory Liabilities							$ 4.4
Regulatory Liabilities - noncurrent							$ 2.4
Northern Utilities Inc \| First Annual Adjustment
Regulatory Assets [Line Items]
Annual TIRA Adjustment								$ 1.5
Annual TIRA Adjustment, effective date							May 01, 2016
Northern Utilities Inc \| New Hampshire
Regulatory Assets [Line Items]
Amendment effective date							May 01, 2015
Increase in annual revenue							$ 1.8
Grace period to receive refund							3 years
Northern Utilities Inc \| New Hampshire \| Natural Gas Distribution
Regulatory Assets [Line Items]
Increase in annual revenue							$ 4.6
Northern Utilities Inc \| Maine
Regulatory Assets [Line Items]
Construction completion period							3 years
Number of new customers \| Customer							1,000
Potential regulated operating revenue							$ 1.0
Grace period to receive refund							3 years
Date to receive a refund as one-time lump sum payment							Oct. 05, 2015
Granite State Gas Transmission Inc \| Gas Transportation and Storage
Regulatory Assets [Line Items]
Amendment effective date				Aug. 01, 2016
Increase in annual revenue				$ 0.3
Amendment approved date				Jul. 13, 2016

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	$ 2.8	$ 5.5
Additions	1.8	2.9
Less: Payments / Reductions	2.7	5.6
Total Balance at End of period	1.9	2.8
Less: Current Portion			$ 0.4	$ 1.3
Noncurrent Balance			1.5	1.5
Total Balance at End of period	2.8	5.5	1.9	2.8
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	1.2	1.9
Less: Payments / Reductions	1.1	0.7
Total Balance at End of period	0.1	1.2
Less: Current Portion			0.1	0.2
Noncurrent Balance				1.0
Total Balance at End of period	1.2	1.9	0.1	1.2
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	1.6	3.6
Additions	1.8	2.9
Less: Payments / Reductions	1.6	4.9
Total Balance at End of period	1.8	1.6
Less: Current Portion			0.3	1.1
Noncurrent Balance			1.5	0.5
Total Balance at End of period	$ 1.6	$ 3.6	$ 1.8	$ 1.6

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Income Tax Provision
Federal	$ 0	$ 0	$ 0
State		3,530	(387)
Total Current Income Taxes		3,530	(387)
Deferred Income Provision
Federal	11,209	12,413	10,809
State	4,145	(500)	3,573
Total Deferred Income Taxes	15,354	11,913	14,382
Total Income Tax Expense	$ 15,354	$ 15,443	$ 13,995

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	34.00%	34.00%	34.00%
State Income Taxes, net	4.00%	5.00%	2.00%
Utility Plant Differences	(1.00%)	(2.00%)	(1.00%)
Tax Credits	(1.00%)	(1.00%)
Other, net		1.00%	1.00%
Effective Income Tax Rate	36.00%	37.00%	36.00%

Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred Tax Assets
Retirement Benefit Obligations	$ 56,804	$ 43,543
Net Operating Loss Carryforwards	23,921	10,500
Tax Credit Carryforwards	3,365	2,677
Other, net	1,426	4,019
Total Deferred Tax Assets	85,516	60,739
Deferred Tax Liabilities
Utility Plant Differences	169,240	142,412
Regulatory Assets & Liabilities	10,594	5,445
Other, net	3,629	348
Total Deferred Tax Liabilities	183,463	148,205
Net Deferred Tax Liabilities	$ 97,947	$ 87,466

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Deferred state income tax expense (benefit)	$ 4,145	$ (500)	$ 3,573
Deferred tax assets, operating loss carryforwards, federal	9,900
Deferred tax assets, operating loss carryforwards, state	2,100
Net Operating Loss Carryforwards	23,921	10,500
Tax Credit Carryforwards	3,365	$ 2,677
New Hampshire Department of Revenue (Business Enterprise Tax)
Income Taxes [Line Items]
Deferred state income tax expense (benefit)	$ (700)
Internal Revenue Service (IRS)
Income Taxes [Line Items]
NOL carryforward assets expiration date	2029
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, 2013; December 31, 2014; and December 31, 2015.

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Benefit Plan Costs

Defined Benefit Plan Disclosure [Line Items]

Discount Rate

^[1]

4.30%

4.00%

4.80%

Rate of Compensation Increase

3.00%

Expected Long-term rate of return on plan assets

8.00%

Health Care Cost Trend Rate Assumed for Next Year

7.00%

8.00%

Ultimate Health Care Cost Trend Rate

4.00%

Year that Ultimate Health Care Cost Trend Rate is reached

2022

2018

Effect of 1% Increase in Health Care Cost Trend Rate

$ 1,352

$ 1,383

$ 989

Effect of 1% Decrease in Health Care Cost Trend Rate

$ (1,032)

$ (1,040)

$ (771)

Benefit Obligation

Defined Benefit Plan Disclosure [Line Items]

Discount Rate

4.10%

4.30%

4.00%

Rate of Compensation Increase

3.00%

Health Care Cost Trend Rate Assumed for Next Year

8.00%

7.00%

Ultimate Health Care Cost Trend Rate

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

$ 19,471

$ 14,877

$ 15,325

Effect of 1% Decrease in Health Care Cost Trend Rate

$ (15,153)

$ (11,611)

$ (11,829)

[1]

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Parenthetical) (Detail)	6 Months Ended
	Dec. 31, 2015
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.30%

Retirement Benefit Plans - Additional Information (Detail) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

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

$ 524

Pension expense

6,800

$ 7,300

$ 4,900

Regulatory Assets

$ 142,000

126,400

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

$ 5,000

Accumulated Benefit Obligation

135,200

126,800

Company's contributions

5,146

4,215

4,191

Other Postretirement Benefit Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Amortizations related to Actuarial Loss and Prior Service Cost

3,500

Company's contributions

4,000

3,650

Supplemental Employee Retirement Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Amortizations related to Actuarial Loss and Prior Service Cost

500

Accumulated Benefit Obligation

6,900

7,000

Company's contributions

Fair Value Of Plan Assets

Defined Benefit Plan Disclosure [Line Items]

Pension expense

7,700

7,300

4,300

Defined Benefit Obligations

Defined Benefit Plan Disclosure [Line Items]

Regulatory Assets

75,900

64,700

Four Zero One K Plan

Defined Benefit Plan Disclosure [Line Items]

Company's contributions

$ 2,304

$ 2,098

$ 1,877

Benefit Plan Costs

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Expected Long-term Return on Assets

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 Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3,402	$ 3,689	$ 3,006
Interest Cost	5,945	5,392	5,092
Expected Return on Plan Assets	(7,257)	(6,779)	(6,245)
Prior Service Cost Amortization	263	265	211
Actuarial Loss Amortization	4,398	4,714	2,847
Sub-total	6,751	7,281	4,911
Amounts Capitalized or Deferred	(3,008)	(3,397)	(1,881)
NPBC Recognized	3,743	3,884	3,030
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,610	2,622	1,988
Interest Cost	3,232	2,918	2,686
Expected Return on Plan Assets	(1,205)	(1,093)	(920)
Prior Service Cost Amortization	1,486	1,682	1,682
Actuarial Loss Amortization	1,049	1,150	56
Sub-total	7,172	7,279	5,492
Amounts Capitalized or Deferred	(3,351)	(3,423)	(2,270)
NPBC Recognized	3,821	3,856	3,222
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	162	120	57
Interest Cost	386	330	272
Prior Service Cost Amortization	189	85	11
Actuarial Loss Amortization	375	327	100
Sub-total	1,112	862	440
NPBC Recognized	$ 1,112	$ 862	$ 440

Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 87,194	$ 86,744
Actual Return on Plan Assets	3,618	645
Employer Contributions	5,146	4,215	$ 4,191
Benefits Paid	(4,900)	(4,410)	(4,246)
Plan Assets at End of Year	91,058	87,194	86,744
PBO at Beginning of Year	140,816	136,662
Service Cost	3,402	3,689	3,006
Interest Cost	5,945	5,392	5,092
Plan Amendments		474
Benefits Paid	(4,900)	(4,410)	(4,246)
Actuarial (Gain) or Loss	5,176	(991)
PBO at End of Year	150,439	140,816	136,662
Funded Status: Assets vs PBO	(59,381)	(53,622)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	14,174	12,840
Actual Return on Plan Assets	792	(214)
Employer Contributions	4,000	4,000	3,650
Participant Contributions	61	63	59
Benefits Paid	(2,421)	(2,515)	(2,184)
Plan Assets at End of Year	16,606	14,174	12,840
PBO at Beginning of Year	76,249	73,923
Service Cost	2,610	2,622	1,988
Interest Cost	3,232	2,918	2,686
Participant Contributions	61	63	59
Benefits Paid	(2,421)	(2,515)	(2,184)
Actuarial (Gain) or Loss	16,928	(762)
PBO at End of Year	96,659	76,249	73,923
Funded Status: Assets vs PBO	(80,053)	(62,075)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	34	40	53
Benefits Paid	(34)	(40)	(53)
PBO at Beginning of Year	9,177	7,965
Service Cost	162	120	57
Interest Cost	386	330	272
Plan Amendments		608
Benefits Paid	(34)	(40)	(53)
Actuarial (Gain) or Loss	(125)	194
PBO at End of Year	9,566	9,177	$ 7,965
Funded Status: Assets vs PBO	$ (9,566)	$ (9,177)

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 5,146	$ 4,215	$ 4,191
Benefit Payments	4,900	4,410	4,246
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	4,000	4,000	3,650
Participant Contributions	61	63	59
Benefit Payments	2,421	2,515	2,184
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	34	40	53
Benefit Payments	$ 34	$ 40	$ 53

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2016 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2017	$ 5,451
2018	5,475
2019	6,035
2020	6,288
2021	6,759
2022 - 2026	40,623
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2017	2,439
2018	2,690
2019	2,922
2020	3,138
2021	3,470
2022 - 2026	21,533
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2017	34
2018	33
2019	578
2020	569
2021	703
2022 - 2026	$ 3,753

Actual Investment Allocations (Detail)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

100.00%

Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

46.00%

49.00%

Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

37.00%

36.00%

Pension Plans | Equity And Debt Securities

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

^[1]

7.00%

6.00%

5.00%

Other Postretirement Benefit Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

100.00%

Other Postretirement Benefit Plans, Defined Benefit | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

55.00%

53.00%

56.00%

Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

43.00%

47.00%

44.00%

Other Postretirement Benefit Plans, Defined Benefit | Other

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

^[2]

2.00%

0.00%

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

^[2]

0.00%

Real Estate Funds | Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Actual Allocation

10.00%

11.00%

10.00%

Real Estate Funds | Scenario Forecast | 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, 2016 pending transfer into debt and equity funds.

Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 91,058	$ 87,194	$ 86,744
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	82,230	77,843
Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	42,134	40,124
Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	33,924	32,192
Mutual Fund \| Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	6,172	5,527
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	8,828	9,351
Fair Value, Inputs, Level 1 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	82,230	77,843
Fair Value, Inputs, Level 1 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	42,134	40,124
Fair Value, Inputs, Level 1 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	33,924	32,192
Fair Value, Inputs, Level 1 \| Mutual Fund \| Equity And Debt Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 6,172	$ 5,527

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 16,606	$ 14,174	$ 12,840
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	400
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	16,206
Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	7,078	6,620
Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	9,128	7,554
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	16,606	14,174
Fair Value, Inputs, Level 1 \| Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	400
Fair Value, Inputs, Level 1 \| Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	16,206
Fair Value, Inputs, Level 1 \| Mutual Fund \| Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	7,078	6,620
Fair Value, Inputs, Level 1 \| Mutual Fund \| Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 9,128	$ 7,554