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Document and Entity Information - shares	9 Months Ended
Document and Entity Information - shares	Sep. 30, 2016	Oct. 17, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		14,060,490

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating Revenues
Gas	$ 22.1	$ 21.7	$ 124.1	$ 149.6
Electric	55.2	51.4	150.4	170.1
Other	1.5	1.6	4.6	4.7
Total Operating Revenues	78.8	74.7	279.1	324.4
Operating Expenses
Cost of Gas Sales	6.1	5.5	52.4	76.5
Cost of Electric Sales	29.6	29.2	84.3	106.2
Operation and Maintenance	15.5	16.8	48.6	50.0
Depreciation and Amortization	11.6	11.4	35.1	34.1
Taxes Other Than Income Taxes	4.9	4.5	14.7	13.0
Total Operating Expenses	67.7	67.4	235.1	279.8
Operating Income	11.1	7.3	44.0	44.6
Interest Expense, net	5.5	5.5	16.7	17.3
Other Expense, net	0.1		0.2	0.2
Income Before Income Taxes	5.5	1.8	27.1	27.1
Income Tax Expense	2.0	0.1	10.2	10.1
Net Income	$ 3.5	$ 1.7	$ 16.9	$ 17.0
Net Income Per Common Share (Basic and Diluted)	$ 0.25	$ 0.12	$ 1.21	$ 1.22
Weighted Average Common Shares Outstanding - (Basic and Diluted)	14.0	13.9	14.0	13.9
Dividends Declared Per Share of Common Stock	$ 0.355	$ 0.350	$ 1.065	$ 1.050

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Current Assets:
Cash and Cash Equivalents	$ 4.4	$ 8.7	$ 8.9
Accounts Receivable, net	43.1	49.8	45.4
Accrued Revenue	35.5	38.4	28.8
Exchange Gas Receivable	9.8	11.1	10.6
Taxes Refundable	1.3
Gas Inventory	0.6	0.8	0.6
Prepayments and Other	12.9	11.7	12.2
Total Current Assets	107.6	120.5	106.5
Utility Plant:
Gas	597.7	576.8	540.2
Electric	424.0	408.4	398.4
Common	35.7	35.5	35.4
Construction Work in Progress	89.6	59.9	77.6
Total Utility Plant	1,147.0	1,080.6	1,051.6
Less: Accumulated Depreciation	286.0	271.7	269.2
Net Utility Plant	861.0	808.9	782.4
Other Noncurrent Assets:
Regulatory Assets	96.5	99.6	102.8
Other Assets	7.3	9.8	10.8
Total Other Noncurrent Assets	103.8	109.4	113.6
TOTAL ASSETS	1,072.4	1,038.8	1,002.5
Current Liabilities:
Accounts Payable	23.1	33.3	21.2
Short-Term Debt	36.9	42.0	4.1
Long-Term Debt, Current Portion	17.0	17.1	3.8
Regulatory Liabilities	13.2	15.6	28.1
Energy Supply Obligations	13.2	14.6	15.8
Environmental Obligations	0.3	1.3	5.0
Capital Lease Obligations	3.1	3.1	0.5
Interest Payable	6.3	3.4	6.3
Taxes Payable		2.4	4.9
Other Current Liabilities	13.2	11.5	11.2
Total Current Liabilities	126.3	144.3	100.9
Noncurrent Liabilities:
Retirement Benefit Obligations	127.8	124.4	122.0
Deferred Income Taxes, net	99.6	87.5	79.2
Cost of Removal Obligations	77.4	70.1	69.9
Regulatory Liabilities	3.7	8.1	11.0
Capital Lease Obligations	9.0	11.0	12.1
Environmental Obligations	2.7	1.5	0.5
Other Noncurrent Liabilities	3.8	3.6	3.5
Total Noncurrent Liabilities	324.0	306.2	298.2
Capitalization:
Long-Term Debt, Less Current Portion	335.0	305.5	325.7
Stockholders' Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 14,060,147, 13,982,941 and 13,991,430 Shares)	239.9	237.5	236.8
Retained Earnings	47.0	45.1	40.7
Total Common Stock Equity	286.9	282.6	277.5
Preferred Stock	0.2	0.2	0.2
Total Stockholders' Equity	287.1	282.8	277.7
Total Capitalization	622.1	588.3	603.4
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,072.4	$ 1,038.8	$ 1,002.5

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Common Stock Authorized	25,000,000	25,000,000	25,000,000
Common Equity Outstanding	14,060,147	13,991,430	13,982,941

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating Activities:
Net Income	$ 16.9	$ 17.0
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	35.1	34.1
Deferred Tax Provision	12.8	3.6
Changes in Working Capital Items:
Accounts Payable	(10.2)	(23.0)
Accounts Receivable	6.7	15.3
Accrued Revenue	2.9	19.7
Exchange Gas Receivable	1.3	4.4
Regulatory Liabilities	(2.4)	19.4
Taxes Payable	(3.7)	4.8
Other Changes in Working Capital Items	2.2	2.9
Deferred Regulatory and Other Charges	(2.6)	8.4
Other, net	3.7	4.0
Cash Provided by Operating Activities	62.7	110.6
Investing Activities:
Property, Plant and Equipment Additions	(74.4)	(70.6)
Cash (Used in) Investing Activities	(74.4)	(70.6)
Financing Activities:
Repayment of Short-Term Debt, net	(5.1)	(25.2)
Repayment of Long-Term Debt	(0.5)	(0.4)
Issuance of Long-Term Debt	30.0
(Decrease) Increase in Capital Lease Obligations	(2.0)	4.1
Net Decrease in Exchange Gas Financing	(1.0)	(4.3)
Dividends Paid	(15.0)	(14.7)
Proceeds from Issuance of Common Stock, net	1.0	1.0
Cash Provided by (Used in) Financing Activities	7.4	(39.5)
Net (Decrease) Increase in Cash and Cash Equivalents	(4.3)	0.5
Cash and Cash Equivalents at Beginning of Period	8.7	8.4
Cash and Cash Equivalents at End of Period	4.4	8.9
Supplemental Cash Flow Information:
Interest Paid	14.2	14.9
Income Taxes Paid	1.6	1.8
Payments on Capital Leases	2.6	0.4
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 1.4	$ 1.2

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2014	$ 273.1	$ 234.7	$ 38.4
Net Income	17.0		17.0
Dividends on Common Shares	(14.7)		(14.7)
Stock Compensation Plans	1.1	1.1
Issuance of Common Shares, Value	1.0	1.0
Ending Balance at Sep. 30, 2015	277.5	236.8	40.7
Beginning Balance at Dec. 31, 2015	282.6	237.5	45.1
Net Income	16.9		16.9
Dividends on Common Shares	(15.0)		(15.0)
Stock Compensation Plans	1.4	1.4
Issuance of Common Shares, Value	1.0	1.0
Ending Balance at Sep. 30, 2016	$ 286.9	$ 239.9	$ 47.0

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Common stock, shares issued	24,697	27,776

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 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 subsidiaries of Unitil Resources.

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

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

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

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

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

Basis of Presentation – The accompanying unaudited Consolidated Financial Statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included and are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2016 are not necessarily indicative of results to be expected for the year ending December 31, 2016. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2015, as filed with the Securities and Exchange Commission (SEC) on January 28, 2016, for a description of the Company’s Basis of Presentation. Certain reclassifications of prior year data were made in the accompanying financial statements. These reclassifications were made to conform to the current year presentation.

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

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances 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 this Form 10-Q for the quarter ended September 30, 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 quarter ended September 30, 2016 resulted in a reduction of both “Current Assets” and “Noncurrent Liabilities” for all prior periods presented.

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. As of September 30, 2016, September 30, 2015 and December 31, 2015, the Unitil subsidiaries had deposited $3.5 million, $2.9 million and $2.3 million, respectively to satisfy their ISO-NE obligations.

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, including the level of customers enrolling in payment plans with the Company. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of September 30, 2016, September 30, 2015 and December 31, 2015, which is included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)

September 30,

December 31,

2016

2015

Allowance for Doubtful Accounts

1.2

2.0

1.2

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of September 30, 2016, September 30, 2015 and December 31, 2015.


	September 30,				December 31,
Accrued Revenue ($ millions)	2016		2015		2015
Regulatory Assets – Current	$	28.0	$	22.6	$	26.8
Unbilled Revenues		7.5		6.2		11.6

Total Accrued Revenue	$	35.5	$	28.8	$	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 September 30, 2016, September 30, 2015 and December 31, 2015.


	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2016		2015		2015
Northern Utilities	$	9.3	$	9.9	$	10.3
Fitchburg		0.5		0.7		0.8

Total Exchange Gas Receivable	$	9.8	$	10.6	$	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 September 30, 2016, September 30, 2015 and December 31, 2015.


	September 30,				December 31,
Gas Inventory ($ millions)	2016		2015		2015
Natural Gas	$	0.3	$	0.3	$	0.3
Propane		0.2		0.2		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.2

Total Gas Inventory	$	0.6	$	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 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 September 30, 2016, September 30, 2015 and December 31, 2015, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $77.4 million, $69.9 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 Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2016		2015		2015
Retirement Benefits	$	64.6	$	65.3	$	64.7
Energy Supply & Tracker Mechanisms		23.2		17.4		21.3
Deferred Storm Charges		11.0		16.9		15.4
Environmental		12.2		11.1		11.2
Income Taxes		7.7		8.9		8.5
Other		5.8		5.8		5.3

Total Regulatory Assets	$	124.5	$	125.4	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		28.0		22.6		26.8

Regulatory Assets – noncurrent	$	96.5	$	102.8	$	99.6

⁽¹⁾

Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.


	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2016		2015		2015
Tracker Mechanisms	$	8.5	$	17.1	$	8.0
Gas Pipeline Refund (Note 6)		8.4		22.0		15.7

Total Regulatory Liabilities		16.9		39.1		23.7
Less: Current Portion of Regulatory Liabilities		13.2		28.1		15.6

Regulatory Liabilities – noncurrent	$	3.7	$	11.0	$	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 September 30, 2016 are $4.1 million of deferred storm charges to be recovered over the next two and a half years and $8.4 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven and a half 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. The Company purchases call option contracts on NYMEX natural gas futures contracts for future winter period months.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas 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 Clause.

As of September 30, 2016, September 30, 2015 and December 31, 2015 the Company had 2.9 billion, 3.7 billion and 2.5 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

As of September 30, 2016, September 30, 2015 and December 31, 2015, the Company’s derivatives that are not designated as hedging instruments under FASB ASC 815-20 have a fair value of $0.2 million, $0.1 million and less than $0.1 million, respectively.

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 9.

At September 30, 2016, September 30, 2015 and December 31, 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, $0.7 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.


	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2016		2015		2015
Equity Funds	$	1.1	$	0.4	$	0.4
Fixed Income Funds		0.8		0.3		0.3

Total Marketable Securities	$	1.9	$	0.7	$	0.7

Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current and noncurrent Energy Supply Obligations on the Company’s Consolidated Balance Sheets.


	September 30,				December 31,
Energy Supply Obligations ($ millions)	2016		2015		2015
Current:
Exchange Gas Obligation	$	9.3	$	9.9	$	10.3
Renewable Energy Portfolio Standards		3.6		5.5		4.0
Power Supply Contract Divestitures		0.3		0.4		0.3

Total Energy Supply Obligations – Current		13.2		15.8		14.6
Long-Term:
Power Supply Contract Divestitures		1.4		1.7		1.6

Total Energy Supply Obligations	$	14.6	$	17.5	$	16.2

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

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

In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The generating facilities associated with two of these contracts have been constructed and are operating. Another contract has been approved by the MDPU and is pending facility construction and operation, which is anticipated to begin by the end of 2016. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker rate mechanism.

Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term 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 this Form 10-Q for the quarter ended September 30, 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 $3.0 million and $2.9 million as of September 30, 2015 and December 31, 2015, respectively.

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 is evaluating the impact that this new guidance will have 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 is evaluating the impact that this new guidance will have 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.

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 has evaluated all events or transactions through the date of this filing. During this period the Company did not have any material subsequent events that impacted its unaudited consolidated financial statements.

DIVIDENDS DECLARED PER SHARE

9 Months Ended

Sep. 30, 2016

DIVIDENDS DECLARED PER SHARE

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/19/16	11/28/16	11/14/16	$ 0.355
07/20/16	08/26/16	08/12/16	$ 0.355
04/20/16	05/27/16	05/13/16	$ 0.355
01/27/16	02/26/16	02/12/16	$ 0.355

10/21/15	11/27/15	11/13/15	$ 0.350
07/22/15	08/28/15	08/14/15	$ 0.350
04/22/15	05/28/15	05/14/15	$ 0.350
01/26/15	02/27/15	02/13/15	$ 0.350

SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2016

SEGMENT INFORMATION

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2016 and September 30, 2015 and as of December 31, 2015 (millions):


Three Months Ended September 30, 2016	Gas			Electric		Non- Regulated		Other		Total
Revenues	$	22.1		$	55.2	$	1.5	$	—	$	78.8
Segment Profit (Loss)		(2.2	)		5.3		0.3		0.1		3.5
Capital Expenditures		22.9			8.8		—		3.1		34.8

Three Months Ended September 30, 2015
Revenues	$	21.7		$	51.4	$	1.6	$	—	$	74.7
Segment Profit (Loss)		(1.4	)		2.5		0.3		0.3		1.7
Capital Expenditures		22.2			7.8		—		2.1		32.1

Nine Months Ended September 30, 2016
Revenues	$	124.1		$	150.4	$	4.6	$	—	$	279.1
Segment Profit		7.2			8.7		0.9		0.1		16.9
Capital Expenditures		44.8			21.8		—		7.8		74.4
Segment Assets		610.3			425.4		7.2		29.5		1,072.4

Nine Months Ended September 30, 2015
Revenues	$	149.6		$	170.1	$	4.7	$	—	$	324.4
Segment Profit		9.5			6.2		0.9		0.4		17.0
Capital Expenditures		45.1			19.5		0.1		5.9		70.6
Segment Assets		573.2			409.5		6.4		13.4		1,002.5

As of December 31, 2015
Segment Assets	$	590.9		$	415.1	$	6.5	$	26.3	$	1,038.8

- 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

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-Name Accounting Standards Codification
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+ Details

DEBT AND FINANCING ARRANGEMENTS

9 Months Ended

Sep. 30, 2016

DEBT AND FINANCING ARRANGEMENTS

NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Details on long-term debt at September 30, 2016, September 30, 2015 and December 31, 2015 are shown below:


($ millions)	September 30,				December 31,
	2016		2015		2015
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Notes, Due August 1, 2026		30.0		—		—

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

Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		11.4		15.2		11.4
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0

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

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

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		0.6		1.3		1.1

Total Long-Term Debt		355.0		332.5		325.5
Less: Unamortized Debt Issuance Costs		3.0		3.0		2.9

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		352.0		329.5		322.6
Less: Current Portion		17.0		3.8		17.1

Total Long-term Debt, Less Current Portion	$	335.0	$	325.7	$	305.5

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

($ millions)

September 30,

December 31,

2016

2015

Estimated Fair Value of Long-Term Debt

405.8

356.7

345.2

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 $148.3 million and $77.1 million for the nine months ended September 30, 2016 and September 30, 2015, respectively. Total gross repayments were $153.4 million and $102.3 million for the nine months ended September 30, 2016 and September 30, 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 September 30, 2016, September 30, 2015 and December 31, 2015:


	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2016		2015		2015
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	36.9	$	4.1	$	42.0
Letters of Credit Outstanding	$	1.1	$	—	$	—

Available	$	82.0	$	115.9	$	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 September 30, 2016, September 30, 2015 and December 31, 2015, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 5.)

The weighted average interest rates on all short-term borrowings were 1.7% and 1.6% for the nine months ended September 30, 2016 and September 30, 2015, respectively. The weighted average interest rate on all short-term borrowings for the twelve months ended December 31, 2015 was 1.5%.

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, structured as a capital lease obligation, for various information systems and technology equipment. 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 September 30, 2016, there are $2.6 million of current and $8.4 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $9.3 million, $9.9 million and $10.8 million of natural gas storage inventory at September 30, 2016, September 30, 2015 and December 31, 2015, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2016 and payable in October 2016 is $0.1 million and is recorded in Accounts Payable at September 30, 2016. The amount of natural gas inventory released in September 2015 and payable in October 2015 was $0.1 million and is recorded in Accounts Payable at September 30, 2015. The amount of natural gas inventory released in December 2015 and payable in January 2016 was $0.6 million and was recorded in Accounts Payable at December 31, 2015.

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 September 30, 2016, there were approximately $21.1 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 September 30, 2016, the principal amount outstanding for the 8% Unitil Realty notes was $0.6 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

COMMON STOCK AND PREFERRED STOCK

9 Months Ended

Sep. 30, 2016

COMMON STOCK AND PREFERRED STOCK

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

The Company had 13,982,941, 13,991,430 and 14,060,147 shares of common stock outstanding at September 30, 2015, December 31, 2015 and September 30, 2016, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2016, the Company sold 24,697 shares of its common stock, at an average price of $39.88 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $985,000. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

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

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

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an Award. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

On January 26, 2016, 43,220 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. On April 19, 2016, 800 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of less than $0.1 million. There were 95,506 and 80,588 non-vested shares under the Stock Plan as of September 30, 2016 and 2015, respectively. The weighted average grant date fair value of these shares was $35.30 and $33.14, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $2.0 million and $1.6 million for the nine months ended September 30, 2016 and 2015, respectively. At September 30, 2016, there was approximately $1.4 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.6 years. There were no forfeitures or cancellations under the Stock Plan during the nine months ended September 30, 2016.

Restricted Stock Units

Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2016 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2015		33,588	$	31.83
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		910	$	39.64
Restricted Stock Units Settled		—		—

Restricted Stock Units as of September 30, 2016		34,498	$	32.03

There were 24,294 Restricted Stock Units outstanding as of September 30, 2015 with a weighted average stock price of $30.04. On October 3, 2016, there were 12,150 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of September 30, 2016, September 30, 2015 and December 31, 2015 is $0.6 million, $0.4 million and $0.5 million, respectively, representing the fair value of liabilities associated with the portion of fully vested Restricted Stock Units that will be settled in cash.

Preferred Stock

There was $0.2 million, or 1,893 shares, and $0.2 million, or 1,898 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2016 and December 31, 2015, respectively. There was $0.2 million, or 2,009 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2015. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and nine month periods ended September 30, 2016 and September 30, 2015, respectively.

- 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

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

REGULATORY MATTERS

9 Months Ended

Sep. 30, 2016

REGULATORY MATTERS

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2015 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2016.

Rate Case Activity

Unitil Energy – Base Rates – On April 29, 2016 Unitil Energy filed for an increase in distribution base rates with the NHPUC. The Company is seeking 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 certain plant additions. On June 28, 2016 the NHPUC approved a settlement agreement between the Company, Commission Staff and the Officer 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 remaining issues in the rate case are pending investigation and decision by the NHPUC.

Fitchburg – Base Rates – Electric – On June 16, 2015, Fitchburg filed for a $3.8 million increase in its electric base revenue decoupling target, which represented a 5.6 percent increase over 2014 test year operating electric revenues. The filing included a request for approval of a capital cost recovery mechanism to recover additions to utility plant on an annual basis. An Order was issued on April 29, 2016 approving a $2.1 million increase effective May 1, 2016. The MDPU also approved a capital cost recovery mechanism. On July 1, 2016, Fitchburg made its first capital cost adjustment filing documenting its capital investments for calendar year 2015 and presenting the associated revenue requirements for recovery beginning January 1, 2017. This filing is under MDPU review.

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

Fitchburg – Base Rates – Gas – On June 16, 2015, Fitchburg filed for a $3.0 million increase in its gas base revenue decoupling target, which represents an 8.3 percent increase over 2014 test year total gas operating revenues. Hearings were completed and briefs filed. An Order was issued on April 29, 2016 approving a $1.6 million increase 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 calendar year 2016 under its approved 20 year gas system enhancement plan program. The plan was established pursuant to legislation that provided for the establishment of comprehensive replacement programs to address aging natural gas pipeline infrastructure. On April 29, 2016, the MDPU approved the Company’s request to collect in rates $0.9 million for the estimated costs of its cumulative capital investments for 2015 and 2016, effective May 1, 2016. Also on April 29, 2016, Fitchburg submitted its cost filing which documents the Company’s actual capital costs and final revenue requirement under the program for calendar year 2015. Any over or under-recovery of the Company’s 2015 revenue requirement will be reconciled in rates effective November 1, 2016. This matter remains pending.

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, provides for an annual increase in base distribution 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 of $5.0 million and $3.5 million, respectively, on its Consolidated Balance Sheets as of September 30, 2016.

Granite State – Base Rates – Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cost cap. On June 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 – Other – 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 over the next year and to prepare a final report with recommendations for the Commission. Unitil Energy is an active participant in the Working Group. This matter remains pending.

Pursuant to legislation that became effective in May 2016, the NHPUC has 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. Unitil Energy is an active participant in this proceeding.

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. Fitchburg’s 2015 gas division Service Quality Report remains pending.

MDPU Service Quality Guidelines – 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 pursuant to G.L. c. 164, § 1A(f), as amended by Chapter 75 of the Acts of 2016. The facility would be 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. The MDPU is expected to issue a decision on the petition by the end of 2016, and construction of facilities 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.

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 is expected during the fourth quarter of 2016. 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 are due October 28, 2016. The DOER’s implementation schedule includes filing emergency regulations by the end of the year, 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 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 are scheduled to file alternative proposals on October 11, 2016. These matters remain pending.

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 as of January 4, 2016. The Company does not believe this investigation will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December 2008. The Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remain pending. The Town of Lunenburg has filed a separate action in the Court arising out of the December 2008 ice storm. The Company continues to believe that both of these suits are without merit and will continue to defend itself vigorously. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these suits will not have a material impact on its financial position, operating results or cash flows.

ENVIRONMENTAL MATTERS

9 Months Ended

Sep. 30, 2016

ENVIRONMENTAL MATTERS

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2015 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2016.

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 September 30, 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.

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 future activities may be required.

Off-site sediment contamination attributed to the former Exeter MGP was remediated successfully in January 2016. The closure report submitted by Northern Utilities was accepted by the NH DES with minor water quality monitoring for a limited time period.

At the site in Somersworth, Northern Utilities submitted the investigative report requested by the NH DES in September 2016. Although the report is currently under review by the NH DES, a recommendation was advanced favoring a third round of on-site treatment of MGP residuals. Northern Utilities anticipates a decision by the NH DES on the recommendation by December 2016.

In Lewiston, on-site monitoring continues with a continued yet gradual reduction observed in the concentration of MGP residuals in the on-site groundwater.

Final remediation activities in Portland were completed in December 2015 and closure documentation was submitted to the ME DEP in June 2016. Northern Utilities anticipates the ME DEP will issue a Certificate of Completion for these activities by December 2016. Pursuant to an agreement between the State of Maine and Northern Utilities, future remedial activities necessitated as a result of development of the site will be primarily the responsibility of the State of Maine.

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

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

Fitchburg’s Manufactured Gas Plant Site – Fitchburg completed the scheduled site work at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the fourth quarter of 2014. The closure documentation for the site was submitted in December 2015 and is under review by the Massachusetts Department of Environmental Protection (MA DEP) with a decision anticipated by the fourth quarter of 2016.

The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs.

The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. Based on the Company’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the nine months ended September 30, 2016 and 2015.


Environmental Obligations
	($ millions)
	Fitchburg				Northern Utilities				Total
	Nine months ended September 30,
	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		—		—		0.9		1.9		0.9		1.9
Less: Payments / Reductions		0.1		0.3		0.6		1.6		0.7		1.9

Total Balance at End of Period		1.1		1.6		1.9		3.9		3.0		5.5

Less: Current Portion		0.1		1.6		0.2		3.4		0.3		5.0

Noncurrent Balance at End of Period	$	1.0	$	—	$	1.7	$	0.5	$	2.7	$	0.5

INCOME TAXES

9 Months Ended

Sep. 30, 2016

INCOME TAXES

NOTE 8: INCOME TAXES

The Company filed its tax returns for the year ended December 31, 2015 with the Internal Revenue Service (IRS) in September 2016. As of September 30, 2016, the Company had recorded cumulative federal Net Operating Loss (NOL) carryforward assets and Research and Development (R&D) credit carryforwards of $12.2 million to offset against taxes payable in future periods. If unused, the Company’s federal NOL carryforward assets will begin to expire in 2029, and the federal R&D credits will begin to expire in 2035. In addition, at September 30, 2016, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In 2015, the Company recognized a tax benefit of $63,000 and $288,000 for tax years 2014 and 2015, respectively, in the tax provision related to Federal research and development tax credits under the rules of section 41 of the Internal Revenue Code. The Company will continue to recognize a tax benefit on its incremental qualified research expenses and for the nine month period ended September 30, 2016 has recognized a tax benefit in the tax provision of $362,852 related to 2016 expenditures.

The Company evaluated its tax positions at September 30, 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.

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

RETIREMENT BENEFIT OBLIGATIONS

9 Months Ended

Sep. 30, 2016

RETIREMENT BENEFIT OBLIGATIONS

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2015 as filed with the SEC on January 28, 2016 for additional information regarding these plans.

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


	2016			2015
Used to Determine Plan Costs
Discount Rate		4.30	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		6.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2022			2018

The following tables provide the components of the Company’s Retirement plan costs ($000’s):


	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2016			2015			2016			2015			2016		2015
Service Cost	$	851		$	916		$	652		$	656		$	41	$	28
Interest Cost		1,486			1,343			808			729			96		78
Expected Return on Plan Assets		(1,814	)		(1,694	)		(301	)		(273	)		—		—
Prior Service Cost Amortization		66			54			372			420			47		2
Actuarial Loss Amortization		1,099			1,180			262			288			94		84

Sub-total		1,688			1,799			1,793			1,820			278		192
Amounts Capitalized and Deferred		(839	)		(927	)		(904	)		(921	)		—		—

Net Periodic Benefit Cost Recognized	$	849		$	872		$	889		$	899		$	278	$	192


	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,	2016			2015			2016			2015			2016		2015
Service Cost	$	2,553		$	2,748		$	1,956		$	1,968		$	123	$	84
Interest Cost		4,458			4,029			2,424			2,187			288		234
Expected Return on Plan Assets		(5,442	)		(5,082	)		(903	)		(819	)		—		—
Prior Service Cost Amortization		198			162			1,116			1,260			141		8
Actuarial Loss Amortization		3,297			3,540			786			864			282		252

Sub-total		5,064			5,397			5,379			5,460			834		578
Amounts Capitalized and Deferred		(2,246	)		(2,510	)		(2,508	)		(2,563	)		—		—

Net Periodic Benefit Cost Recognized	$	2,818		$	2,887		$	2,871		$	2,897		$	834	$	578

Employer Contributions

As of September 30, 2016, the Company had made $5.1 million and $2.8 million of contributions to its Pension Plan and PBOP Plan, respectively, in 2016. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2016 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of September 30, 2016, the Company had made $25,600 of benefit payments under the SERP Plan in 2016. The Company presently anticipates making an additional $8,500 of benefit payments under the SERP Plan in 2016.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 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.

Basis of Presentation

Income Taxes

Cash and Cash Equivalents

Allowance for Doubtful Accounts

($ millions)

September 30,

December 31,

2016

2015

Allowance for Doubtful Accounts

1.2

2.0

1.2

Accrued Revenue


	September 30,				December 31,
Accrued Revenue ($ millions)	2016		2015		2015
Regulatory Assets – Current	$	28.0	$	22.6	$	26.8
Unbilled Revenues		7.5		6.2		11.6

Total Accrued Revenue	$	35.5	$	28.8	$	38.4

Exchange Gas Receivable


	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2016		2015		2015
Northern Utilities	$	9.3	$	9.9	$	10.3
Fitchburg		0.5		0.7		0.8

Total Exchange Gas Receivable	$	9.8	$	10.6	$	11.1

Gas Inventory


	September 30,				December 31,
Gas Inventory ($ millions)	2016		2015		2015
Natural Gas	$	0.3	$	0.3	$	0.3
Propane		0.2		0.2		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.2

Total Gas Inventory	$	0.6	$	0.6	$	0.8

Utility Plant

Regulatory Accounting


	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2016		2015		2015
Retirement Benefits	$	64.6	$	65.3	$	64.7
Energy Supply & Tracker Mechanisms		23.2		17.4		21.3
Deferred Storm Charges		11.0		16.9		15.4
Environmental		12.2		11.1		11.2
Income Taxes		7.7		8.9		8.5
Other		5.8		5.8		5.3

Total Regulatory Assets	$	124.5	$	125.4	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		28.0		22.6		26.8

Regulatory Assets – noncurrent	$	96.5	$	102.8	$	99.6

⁽¹⁾

Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.


	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2016		2015		2015
Tracker Mechanisms	$	8.5	$	17.1	$	8.0
Gas Pipeline Refund (Note 6)		8.4		22.0		15.7

Total Regulatory Liabilities		16.9		39.1		23.7
Less: Current Portion of Regulatory Liabilities		13.2		28.1		15.6

Regulatory Liabilities – noncurrent	$	3.7	$	11.0	$	8.1

Derivatives

Investments in Marketable Securities


	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2016		2015		2015
Equity Funds	$	1.1	$	0.4	$	0.4
Fixed Income Funds		0.8		0.3		0.3

Total Marketable Securities	$	1.9	$	0.7	$	0.7

Energy Supply Obligations


	September 30,				December 31,
Energy Supply Obligations ($ millions)	2016		2015		2015
Current:
Exchange Gas Obligation	$	9.3	$	9.9	$	10.3
Renewable Energy Portfolio Standards		3.6		5.5		4.0
Power Supply Contract Divestitures		0.3		0.4		0.3

Total Energy Supply Obligations – Current		13.2		15.8		14.6
Long-Term:
Power Supply Contract Divestitures		1.4		1.7		1.6

Total Energy Supply Obligations	$	14.6	$	17.5	$	16.2

Debt Issuance Costs

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)

9 Months Ended

Sep. 30, 2016

Allowance for Doubtful Accounts Included in Accounts Receivable Net

($ millions)

September 30,

December 31,

2016

2015

Allowance for Doubtful Accounts

1.2

2.0

1.2

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of September 30, 2016, September 30, 2015 and December 31, 2015.


	September 30,				December 31,
Accrued Revenue ($ millions)	2016		2015		2015
Regulatory Assets – Current	$	28.0	$	22.6	$	26.8
Unbilled Revenues		7.5		6.2		11.6

Total Accrued Revenue	$	35.5	$	28.8	$	38.4

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of September 30, 2016, September 30, 2015 and December 31, 2015.


	September 30,				December 31,
Exchange Gas Receivable ($ millions)	2016		2015		2015
Northern Utilities	$	9.3	$	9.9	$	10.3
Fitchburg		0.5		0.7		0.8

Total Exchange Gas Receivable	$	9.8	$	10.6	$	11.1

Components of Gas Inventory

The following table shows the components of Gas Inventory as of September 30, 2016, September 30, 2015 and December 31, 2015.


	September 30,				December 31,
Gas Inventory ($ millions)	2016		2015		2015
Natural Gas	$	0.3	$	0.3	$	0.3
Propane		0.2		0.2		0.3
Liquefied Natural Gas & Other		0.1		0.1		0.2

Total Gas Inventory	$	0.6	$	0.6	$	0.8

Regulatory Assets


	September 30,				December 31,
Regulatory Assets consist of the following ($ millions)	2016		2015		2015
Retirement Benefits	$	64.6	$	65.3	$	64.7
Energy Supply & Tracker Mechanisms		23.2		17.4		21.3
Deferred Storm Charges		11.0		16.9		15.4
Environmental		12.2		11.1		11.2
Income Taxes		7.7		8.9		8.5
Other		5.8		5.8		5.3

Total Regulatory Assets	$	124.5	$	125.4	$	126.4
Less: Current Portion of Regulatory Assets⁽¹⁾		28.0		22.6		26.8

Regulatory Assets – noncurrent	$	96.5	$	102.8	$	99.6

⁽¹⁾

Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities


	September 30,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2016		2015		2015
Tracker Mechanisms	$	8.5	$	17.1	$	8.0
Gas Pipeline Refund (Note 6)		8.4		22.0		15.7

Total Regulatory Liabilities		16.9		39.1		23.7
Less: Current Portion of Regulatory Liabilities		13.2		28.1		15.6

Regulatory Liabilities – noncurrent	$	3.7	$	11.0	$	8.1

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.


	September 30,				December 31,
Fair Value of Marketable Securities ($ millions)	2016		2015		2015
Equity Funds	$	1.1	$	0.4	$	0.4
Fixed Income Funds		0.8		0.3		0.3

Total Marketable Securities	$	1.9	$	0.7	$	0.7

Components of Current and Noncurrent Energy Supply Obligations


	September 30,				December 31,
Energy Supply Obligations ($ millions)	2016		2015		2015
Current:
Exchange Gas Obligation	$	9.3	$	9.9	$	10.3
Renewable Energy Portfolio Standards		3.6		5.5		4.0
Power Supply Contract Divestitures		0.3		0.4		0.3

Total Energy Supply Obligations – Current		13.2		15.8		14.6
Long-Term:
Power Supply Contract Divestitures		1.4		1.7		1.6

Total Energy Supply Obligations	$	14.6	$	17.5	$	16.2

DIVIDENDS DECLARED PER SHARE (Tables)

9 Months Ended

Sep. 30, 2016

Schedule of Dividends Declared


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
10/19/16	11/28/16	11/14/16	$ 0.355
07/20/16	08/26/16	08/12/16	$ 0.355
04/20/16	05/27/16	05/13/16	$ 0.355
01/27/16	02/26/16	02/12/16	$ 0.355

10/21/15	11/27/15	11/13/15	$ 0.350
07/22/15	08/28/15	08/14/15	$ 0.350
04/22/15	05/28/15	05/14/15	$ 0.350
01/26/15	02/27/15	02/13/15	$ 0.350

SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2016

Significant Segment Financial Data

The following table provides significant segment financial data for the three and nine months ended September 30, 2016 and September 30, 2015 and as of December 31, 2015 (millions):


Three Months Ended September 30, 2016	Gas			Electric		Non- Regulated		Other		Total
Revenues	$	22.1		$	55.2	$	1.5	$	—	$	78.8
Segment Profit (Loss)		(2.2	)		5.3		0.3		0.1		3.5
Capital Expenditures		22.9			8.8		—		3.1		34.8

Three Months Ended September 30, 2015
Revenues	$	21.7		$	51.4	$	1.6	$	—	$	74.7
Segment Profit (Loss)		(1.4	)		2.5		0.3		0.3		1.7
Capital Expenditures		22.2			7.8		—		2.1		32.1

Nine Months Ended September 30, 2016
Revenues	$	124.1		$	150.4	$	4.6	$	—	$	279.1
Segment Profit		7.2			8.7		0.9		0.1		16.9
Capital Expenditures		44.8			21.8		—		7.8		74.4
Segment Assets		610.3			425.4		7.2		29.5		1,072.4

Nine Months Ended September 30, 2015
Revenues	$	149.6		$	170.1	$	4.7	$	—	$	324.4
Segment Profit		9.5			6.2		0.9		0.4		17.0
Capital Expenditures		45.1			19.5		0.1		5.9		70.6
Segment Assets		573.2			409.5		6.4		13.4		1,002.5

As of December 31, 2015
Segment Assets	$	590.9		$	415.1	$	6.5	$	26.3	$	1,038.8

DEBT AND FINANCING ARRANGEMENTS (Tables)

9 Months Ended

Sep. 30, 2016

Details on Long Term Debt

Details on long-term debt at September 30, 2016, September 30, 2015 and December 31, 2015 are shown below:


($ millions)	September 30,				December 31,
	2016		2015		2015
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Notes, Due August 1, 2026		30.0		—		—

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

Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		11.4		15.2		11.4
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0

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

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

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		0.6		1.3		1.1

Total Long-Term Debt		355.0		332.5		325.5
Less: Unamortized Debt Issuance Costs		3.0		3.0		2.9

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		352.0		329.5		322.6
Less: Current Portion		17.0		3.8		17.1

Total Long-term Debt, Less Current Portion	$	335.0	$	325.7	$	305.5

Fair Value of Long Term Debt

($ millions)

September 30,

December 31,

2016

2015

Estimated Fair Value of Long-Term Debt

405.8

356.7

345.2

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 September 30, 2016, September 30, 2015 and December 31, 2015:


	Revolving Credit Facility ($ millions)
	September 30,				December 31,
	2016		2015		2015
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	36.9	$	4.1	$	42.0
Letters of Credit Outstanding	$	1.1	$	—	$	—

Available	$	82.0	$	115.9	$	78.0

- 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

COMMON STOCK AND PREFERRED STOCK (Tables)

9 Months Ended

Sep. 30, 2016

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2016 in conjunction with the Stock Plan are presented in the following table:


Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2015		33,588	$	31.83
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		910	$	39.64
Restricted Stock Units Settled		—		—

Restricted Stock Units as of September 30, 2016		34,498	$	32.03

ENVIRONMENTAL MATTERS (Tables)

9 Months Ended

Sep. 30, 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 nine months ended September 30, 2016 and 2015.


Environmental Obligations
	($ millions)
	Fitchburg				Northern Utilities				Total
	Nine months ended September 30,
	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		—		—		0.9		1.9		0.9		1.9
Less: Payments / Reductions		0.1		0.3		0.6		1.6		0.7		1.9

Total Balance at End of Period		1.1		1.6		1.9		3.9		3.0		5.5

Less: Current Portion		0.1		1.6		0.2		3.4		0.3		5.0

Noncurrent Balance at End of Period	$	1.0	$	—	$	1.7	$	0.5	$	2.7	$	0.5

RETIREMENT BENEFIT OBLIGATIONS (Tables)

9 Months Ended

Sep. 30, 2016

Key Weighted Average Assumptions used in Determining Benefit Plan Costs and Obligations

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


	2016			2015
Used to Determine Plan Costs
Discount Rate		4.30	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.00	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		6.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2022			2018

Components of Retirement Plan Costs

The following tables provide the components of the Company’s Retirement plan costs ($000’s):


	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2016			2015			2016			2015			2016		2015
Service Cost	$	851		$	916		$	652		$	656		$	41	$	28
Interest Cost		1,486			1,343			808			729			96		78
Expected Return on Plan Assets		(1,814	)		(1,694	)		(301	)		(273	)		—		—
Prior Service Cost Amortization		66			54			372			420			47		2
Actuarial Loss Amortization		1,099			1,180			262			288			94		84

Sub-total		1,688			1,799			1,793			1,820			278		192
Amounts Capitalized and Deferred		(839	)		(927	)		(904	)		(921	)		—		—

Net Periodic Benefit Cost Recognized	$	849		$	872		$	889		$	899		$	278	$	192


	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,	2016			2015			2016			2015			2016		2015
Service Cost	$	2,553		$	2,748		$	1,956		$	1,968		$	123	$	84
Interest Cost		4,458			4,029			2,424			2,187			288		234
Expected Return on Plan Assets		(5,442	)		(5,082	)		(903	)		(819	)		—		—
Prior Service Cost Amortization		198			162			1,116			1,260			141		8
Actuarial Loss Amortization		3,297			3,540			786			864			282		252

Sub-total		5,064			5,397			5,379			5,460			834		578
Amounts Capitalized and Deferred		(2,246	)		(2,510	)		(2,508	)		(2,563	)		—		—

Net Periodic Benefit Cost Recognized	$	2,818		$	2,887		$	2,871		$	2,897		$	834	$	578

Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions, Bcf in Billions			9 Months Ended
	Dec. 31, 2015 USD ($) Bcf	Sep. 30, 2015 USD ($) Bcf	Sep. 30, 2016 USD ($) Subsidiary mi Bcf
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi			86
Cost of Removal Obligations	$ 70.1	$ 69.9	$ 77.4
Regulatory Assets	$ 126.4	$ 125.4	$ 124.5
Number of Natural Gas Storage Outstanding \| Bcf	2.5	3.7	2.9
Investments in trading securities	$ 0.7	$ 0.7	$ 1.9
Reduction of other assets	(2.9)	(3.0)
Reduction of long-term debt	(2.9)	(3.0)
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period			3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	2.3	2.9	$ 3.5
Not Designated as Hedging Instruments
Significant Accounting Policies [Line Items]
Derivative Assets, not designated as hedging instruments		0.1	0.2
Not Designated as Hedging Instruments \| Maximum
Significant Accounting Policies [Line Items]
Derivative Assets, not designated as hedging instruments	0.1
Deferred Storm Charges
Significant Accounting Policies [Line Items]
Regulatory Assets	$ 15.4	$ 16.9	11.0
Deferred Storm Charges \| Recovered over the next two and a half years
Significant Accounting Policies [Line Items]
Regulatory Assets			4.1
Environmental Costs Rate Case Costs And Other Expenditures \| Recovered over the next seven and a half years
Significant Accounting Policies [Line Items]
Regulatory Assets			$ 8.4
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary			3
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary			3

Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 1.2	$ 1.2	$ 2.0

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 35.5	$ 38.4	$ 28.8
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	7.5	11.6	6.2
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 28.0	$ 26.8	$ 22.6

Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Receivables [Line Items]
Total Exchange Gas Receivable	$ 9.8	$ 11.1	$ 10.6
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	9.3	10.3	9.9
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.5	$ 0.8	$ 0.7

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.6	$ 0.8	$ 0.6
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.2	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.3	0.3
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.2	$ 0.3	$ 0.2

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

Sep. 30, 2016

Dec. 31, 2015

Sep. 30, 2015

Regulatory Assets [Line Items]

Regulatory Assets

$ 124.5

$ 126.4

$ 125.4

Less: Current Portion of Regulatory Assets

^[1]

28.0

26.8

22.6

Regulatory Assets - noncurrent

96.5

99.6

102.8

Environmental Matters

Regulatory Assets [Line Items]

Regulatory Assets

12.2

11.2

11.1

Other Assets

Regulatory Assets [Line Items]

Regulatory Assets

5.8

5.3

5.8

Retirement Benefits

Regulatory Assets [Line Items]

Regulatory Assets

64.6

64.7

65.3

Deferred Storm Charges

Regulatory Assets [Line Items]

Regulatory Assets

11.0

15.4

16.9

Income Taxes

Regulatory Assets [Line Items]

Regulatory Assets

7.7

8.5

8.9

Energy Supply & Tracker Mechanisms

Regulatory Assets [Line Items]

Regulatory Assets

$ 23.2

$ 21.3

$ 17.4

[1]	Reflects amounts included in Accrued Revenue, discussed above, on the Company's Consolidated Balance Sheets.

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 16.9	$ 23.7	$ 39.1
Less: Current Portion of Regulatory Liabilities	13.2	15.6	28.1
Regulatory Liabilities-noncurrent	3.7	8.1	11.0
Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	8.5	8.0	17.1
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 8.4	$ 15.7	$ 22.0

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 1.9	$ 0.7	$ 0.7
Fair Value, Inputs, Level 1
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	1.9	0.7	0.7
Fair Value, Inputs, Level 1 \| Equity Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	1.1	0.4	0.4
Fair Value, Inputs, Level 1 \| Fixed Income Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 0.8	$ 0.3	$ 0.3

Components of Current and Noncurrent Energy Supply Obligations (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 13.2	$ 14.6	$ 15.8
Power Supply Contract Divestitures, Noncurrent	1.4	1.6	1.7
Total Energy Supply Obligations	14.6	16.2	17.5
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	9.3	10.3	9.9
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	3.6	4.0	5.5
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 0.3	$ 0.3	$ 0.4

Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended		9 Months Ended
Dividends Declared Per Share (Detail) - $ / shares	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Dividends Payable [Line Items]
Dividend Amount	$ 0.355	$ 0.350	$ 1.065	$ 1.050
Group One
Dividends Payable [Line Items]
Declaration Date			Oct. 19, 2016
Date Paid (Payable)			Nov. 28, 2016
Shareholder of Record Date			Nov. 14, 2016
Dividend Amount			$ 0.355
Group Two
Dividends Payable [Line Items]
Declaration Date			Jul. 20, 2016
Date Paid (Payable)			Aug. 26, 2016
Shareholder of Record Date			Aug. 12, 2016
Dividend Amount			$ 0.355
Group Three
Dividends Payable [Line Items]
Declaration Date			Apr. 20, 2016
Date Paid (Payable)			May 27, 2016
Shareholder of Record Date			May 13, 2016
Dividend Amount			$ 0.355
Group Four
Dividends Payable [Line Items]
Declaration Date			Jan. 27, 2016
Date Paid (Payable)			Feb. 26, 2016
Shareholder of Record Date			Feb. 12, 2016
Dividend Amount			$ 0.355
Group Five
Dividends Payable [Line Items]
Declaration Date			Oct. 21, 2015
Date Paid (Payable)			Nov. 27, 2015
Shareholder of Record Date			Nov. 13, 2015
Dividend Amount			$ 0.350
Group Six
Dividends Payable [Line Items]
Declaration Date			Jul. 22, 2015
Date Paid (Payable)			Aug. 28, 2015
Shareholder of Record Date			Aug. 14, 2015
Dividend Amount			$ 0.350
Group Seven
Dividends Payable [Line Items]
Declaration Date			Apr. 22, 2015
Date Paid (Payable)			May 28, 2015
Shareholder of Record Date			May 14, 2015
Dividend Amount			$ 0.350
Group Eight
Dividends Payable [Line Items]
Declaration Date			Jan. 26, 2015
Date Paid (Payable)			Feb. 27, 2015
Shareholder of Record Date			Feb. 13, 2015
Dividend Amount			$ 0.350

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 78.8	$ 74.7	$ 279.1	$ 324.4
Segment Profit (Loss)	3.5	1.7	16.9	17.0
Capital Expenditures	34.8	32.1	74.4	70.6
Segment Assets	1,072.4	1,002.5	1,072.4	1,002.5	$ 1,038.8
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	22.1	21.7	124.1	149.6
Segment Profit (Loss)	(2.2)	(1.4)	7.2	9.5
Capital Expenditures	22.9	22.2	44.8	45.1
Segment Assets	610.3	573.2	610.3	573.2	590.9
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	55.2	51.4	150.4	170.1
Segment Profit (Loss)	5.3	2.5	8.7	6.2
Capital Expenditures	8.8	7.8	21.8	19.5
Segment Assets	425.4	409.5	425.4	409.5	415.1
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit (Loss)	0.1	0.3	0.1	0.4
Capital Expenditures	3.1	2.1	7.8	5.9
Segment Assets	29.5	13.4	29.5	13.4	26.3
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	1.5	1.6	4.6	4.7
Segment Profit (Loss)	0.3	0.3	0.9	0.9
Capital Expenditures				0.1
Segment Assets	$ 7.2	$ 6.4	$ 7.2	$ 6.4	$ 6.5

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Debt Instrument [Line Items]
Total Long-Term Debt	$ 355.0	$ 325.5	$ 332.5
Less: Unamortized Debt Issuance Costs	3.0	2.9	3.0
Long-Term Debt	352.0	322.6	329.5
Less: Current Portion	17.0	17.1	3.8
Total Long-term Debt, Less Current Portion	335.0	305.5	325.7
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20.0	20.0	20.0
3.70% 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	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0	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	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	15.0
Fitchburg Gas and Electric Light Company \| 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	11.4	11.4	15.2
Fitchburg Gas and Electric Light Company \| 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0	12.0
Fitchburg Gas and Electric Light Company \| 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0	14.0
Fitchburg Gas and Electric Light Company \| 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company \| 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Northern Utilities Inc \| 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30.0	30.0	30.0
Northern Utilities Inc \| 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25.0	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	50.0
Northern Utilities Inc \| 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Senior Notes	50.0	50.0	50.0
Granite State Gas Transmission Inc \| 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10.0	10.0	10.0
Unitil Realty Corp \| 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 0.6	$ 1.1	$ 1.3

Details on Long Term Debt (Parenthetical) (Detail)	9 Months Ended		12 Months Ended
Details on Long Term Debt (Parenthetical) (Detail)	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%	6.33%
Debt instrument due date	May 01, 2022	May 01, 2022	May 01, 2022
3.70% Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate	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%	5.24%
Debt instrument due date	Mar. 02, 2020	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%	8.49%
Debt instrument due date	Oct. 14, 2024	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%	6.96%
Debt instrument due date	Sep. 01, 2028	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%	8.00%
Debt instrument due date	May 01, 2031	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%	6.32%
Debt instrument due date	Sep. 15, 2036	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%	6.75%
Debt instrument due date	Nov. 30, 2023	Nov. 30, 2023	Nov. 30, 2023
7.37% Notes, Due January 15, 2029 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%	7.37%
Debt instrument due date	Jan. 15, 2029	Jan. 15, 2029	Jan. 15, 2029
7.98% Notes, Due June 1, 2031 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%	7.98%
Debt instrument due date	Jun. 01, 2031	Jun. 01, 2031	Jun. 01, 2031
6.79% Notes, Due October 15, 2025 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%	6.79%
Debt instrument due date	Oct. 15, 2025	Oct. 15, 2025	Oct. 15, 2025
5.90% Notes, Due December 15, 2030 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%	5.90%
Debt instrument due date	Dec. 15, 2030	Dec. 15, 2030	Dec. 15, 2030
6.95% Senior Notes, Series A, Due December 3, 2018 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%	6.95%
Debt instrument due date	Dec. 03, 2018	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%	5.29%
Debt instrument due date	Mar. 02, 2020	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%	7.72%
Debt instrument due date	Dec. 03, 2038	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%	4.42%
Debt instrument due date	Oct. 15, 2044	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%	7.15%
Debt instrument due date	Dec. 15, 2018	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%	8.00%
Debt instrument due date	Aug. 01, 2017	Aug. 01, 2017	Aug. 01, 2017

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 405.8	$ 345.2	$ 356.7

Debt and Financing Arrangements - Additional Information (Detail) - USD ($)		9 Months Ended
	Oct. 04, 2013	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Oct. 30, 2015
Line of Credit Facility [Line Items]
Weighted average interest rate on short term borrowings		1.70%	1.60%	1.50%
Capital lease obligation, current fact already tagged		$ 3,100,000	$ 500,000	$ 3,100,000
Capital lease obligation, noncurrent fact already tagged		9,000,000	12,100,000	11,000,000
Accounts Payable		23,100,000	21,200,000	33,300,000
Guarantee outstanding		$ 21,100,000
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 fact already tagged		$ 2,600,000
Capital lease obligation, noncurrent fact already tagged		8,400,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Natural gas storage inventory		9,300,000	9,900,000	10,800,000
Accounts Payable		100,000	100,000	600,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility		120,000,000	120,000,000	120,000,000
Proceeds from lines of credit		148,300,000	77,100,000
Repayments of lines of credit		153,400,000	102,300,000
Letters of Credit Outstanding		$ 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 September 30, 2016, September 30, 2015 and December 31, 2015, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 5.)
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]
Senior Secured Notes		$ 600,000	1,300,000	1,100,000
7.15% Senior Notes, Due December 15, 2018 \| Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Senior Notes		$ 10,000,000	$ 10,000,000	$ 10,000,000

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 36,900,000	$ 42,000,000	$ 4,100,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility	120,000,000	120,000,000	120,000,000
Short-Term Borrowings Outstanding	36,900,000	42,000,000	4,100,000
Letters of Credit Outstanding	1,100,000
Available revolving credit facility	$ 82,000,000	$ 78,000,000	$ 115,900,000

Common Stock and Preferred Stock - Additional Information (Detail) - USD ($)				3 Months Ended		9 Months Ended		12 Months Ended
	Oct. 03, 2016	Apr. 19, 2016	Jan. 26, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Class of Stock [Line Items]
Common stock, shares outstanding				14,060,147	13,982,941	14,060,147	13,982,941	13,991,430
Common stock, shares issued						24,697	27,776
Proceeds from Issuance of Common Stock						$ 1,000,000	$ 1,000,000
Share based compensation expense						$ 2,000,000	1,600,000
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				$ 600,000	$ 400,000	$ 600,000	400,000	$ 500,000
Preferred Stock				200,000	200,000	200,000	200,000	$ 200,000
Maximum
Class of Stock [Line Items]
Dividend declared				$ 100,000	$ 100,000	$ 100,000	$ 100,000
Series 6 \| Unitil Energy Systems Inc
Class of Stock [Line Items]
Preferred stock, outstanding				1,893	2,009	1,893	2,009	1,898
Preferred Stock				$ 200,000	$ 200,000	$ 200,000	$ 200,000	$ 200,000
Dividend rate						6.00%	6.00%	6.00%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock						$ 985,000
Dividend and Distribution Reinvestment and Share Purchase Plan \| Average
Class of Stock [Line Items]
Common stock price per share				$ 39.88		$ 39.88
Dividend and Distribution Reinvestment and Share Purchase Plan \| Common Stock
Class of Stock [Line Items]
Common stock, shares issued						24,697
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period						4 years
Restricted stock non-vested				95,506	80,588	95,506	80,588
Restricted stock weighted average grant date fair value						$ 35.30	$ 33.14
Unrecognized share based compensation				$ 1,400,000		$ 1,400,000
Share compensation recognition period						2 years 7 months 6 days
Forfeitures or cancellations under the stock plan						0
Fully-vested restricted stock units issued		800	43,220
Aggregate Market Value			$ 1,600,000
Restricted Stock \| Maximum
Class of Stock [Line Items]
Restricted stock available for awards				677,500		677,500
Restricted stock that may be awarded in any one calendar year to any one participant				20,000		20,000
Aggregate Market Value		$ 100,000
Restricted Stock \| Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually						25.00%
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Fully-vested restricted stock units issued						0
Restricted stock units outstanding					24,294		24,294
Weighted-Average Stock Price					$ 30.04		$ 30.04
Restricted Stock Units (RSUs) \| Subsequent Event
Class of Stock [Line Items]
Fully-vested restricted stock units issued	12,150

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs)	9 Months Ended
	Sep. 30, 2016 $ / shares shares
Restricted Stock Units
Beginning Restricted Stock Units \| shares	33,588
Restricted Stock Units Granted \| shares	0
Dividend Equivalents Earned \| shares	910
Restricted Stock Units Settled \| shares	0
Ending Restricted Stock Units \| shares	34,498
Weighted-Average Stock Price
Beginning Restricted Stock Units \| $ / shares	$ 31.83
Restricted Stock Units Granted \| $ / shares	0
Dividend Equivalents Earned \| $ / shares	39.64
Restricted Stock Units Settled \| $ / shares	0
Ending Restricted Stock Units \| $ / shares	$ 32.03

Regulatory Matters - Additional Information (Detail) $ in Millions								9 Months Ended	12 Months Ended
	Aug. 19, 2016 MW	Jun. 28, 2016 USD ($)	Jun. 24, 2016 USD ($)	Apr. 29, 2016 USD ($)	Jun. 16, 2015 USD ($)	May 01, 2015 USD ($)	Apr. 15, 2015 USD ($)	Sep. 30, 2016 USD ($) State Customer	Dec. 31, 2014 USD ($)	Jun. 30, 2027 MW	Dec. 31, 2022 MWh	Jun. 30, 2017 MW	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)
Regulatory Assets [Line Items]
Current Portion of Regulatory Liabilities								$ 13.2					$ 15.6	$ 28.1
Regulatory Liabilities - non current								$ 3.7					$ 8.1	$ 11.0
Scenario Forecast
Regulatory Assets [Line Items]
Power generation capacity \| MWh											9,450,000
Fitchburg-Solar Generation
Regulatory Assets [Line Items]
Power generation facility \| MW	1.3
Expected completion date of facility	2017-11
Offshore Wind Energy \| Scenario Forecast
Regulatory Assets [Line Items]
Power generation facility \| MW										1,600		400
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Amendment effective date				May 01, 2016
Revenue requirement reconciled rates effective date				Nov. 01, 2016
Number of states with electric distribution companies \| State								3
Fitchburg Gas and Electric Light Company \| Cumulative capital investments for 2015 and 2016
Regulatory Assets [Line Items]
Recovery amount				$ 0.9
Fitchburg Gas and Electric Light Company \| Electric base
Regulatory Assets [Line Items]
Amendment effective date				May 01, 2016
Increase in annual revenue				$ 2.1	$ 3.8
Percentage of approved return on equity					5.60%
Fitchburg Gas and Electric Light Company \| Gas base
Regulatory Assets [Line Items]
Amendment effective date				May 01, 2016
Increase in annual revenue				$ 1.6	$ 3.0
Percentage of approved return on equity					8.30%
Northern Utilities Inc
Regulatory Assets [Line Items]
TIRA initial term								Four years
Amendment approved date								Apr. 28, 2016
Pipeline refund received							$ 22.0
Current Portion of Regulatory Liabilities								$ 5.0
Regulatory Liabilities - non current								$ 3.5
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 \| 2014 Step Adjustments
Regulatory Assets [Line Items]
Amendment effective date								May 01, 2014
Increase in annual revenue								$ 1.4
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
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
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, 2017
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

Environmental Matters - Additional Information (Detail)	9 Months Ended
Environmental Matters - Additional Information (Detail)	Sep. 30, 2016 USD ($)
New Hampshire \| Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	7 years
Maine \| Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	5 years
Environmental Matters
Site Contingency [Line Items]
Income (loss) incurred in excess of recorded amount	$ 0
Fitchburg Gas and Electric Light Company \| Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	7 years

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	$ 2.8	$ 5.5
Additions	0.9	1.9
Less: Payments / Reductions	0.7	1.9
Total Balance at End of period	3.0	5.5
Less: Current Portion			$ 0.3	$ 1.3	$ 5.0
Noncurrent Balance			2.7	1.5	0.5
Total Balance at End of period	3.0	5.5	3.0	2.8	5.5
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	1.2	1.9
Less: Payments / Reductions	0.1	0.3
Total Balance at End of period	1.1	1.6
Less: Current Portion			0.1		1.6
Noncurrent Balance			1.0
Total Balance at End of period	1.1	1.6	1.1	1.2	1.6
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of period	1.6	3.6
Additions	0.9	1.9
Less: Payments / Reductions	0.6	1.6
Total Balance at End of period	1.9	3.9
Less: Current Portion			0.2		3.4
Noncurrent Balance			1.7		0.5
Total Balance at End of period	$ 1.9	$ 3.9	$ 1.9	$ 1.6	$ 3.9

Income Taxes - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Alternative Minimum tax credit carryforwards	$ 1,500,000		$ 1,500,000
Income tax benefit	2,000,000	$ 100,000	10,200,000	$ 10,100,000
Federal Research and Development Tax Credit \| Tax Year 2014
Operating Loss Carryforwards [Line Items]
Income tax benefit					$ (63,000)
Federal Research and Development Tax Credit \| Tax Year 2015
Operating Loss Carryforwards [Line Items]
Income tax benefit					$ (288,000)
Federal Research and Development Tax Credit \| 2016 expenditures
Operating Loss Carryforwards [Line Items]
Income tax benefit			(362,852)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
NOL carryforward assets and Research and Development (R&D) credit carryforwards	$ 12,200,000		$ 12,200,000
NOL carryforward assets expiration date			2029
R&D credits expiration year			2035
Federal
Operating Loss Carryforwards [Line Items]
Tax examination description			The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2013; December 31, 2014; and December 31, 2015.

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - Benefit Plan Costs	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.30%	4.00%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	8.00%	8.00%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	6.00%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2022	2018

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension Plans
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	$ 851	$ 916	$ 2,553	$ 2,748
Interest Cost	1,486	1,343	4,458	4,029
Expected Return on Plan Assets	(1,814)	(1,694)	(5,442)	(5,082)
Prior Service Cost Amortization	66	54	198	162
Actuarial Loss Amortization	1,099	1,180	3,297	3,540
Sub-total	1,688	1,799	5,064	5,397
Amounts Capitalized and Deferred	(839)	(927)	(2,246)	(2,510)
Net Periodic Benefit Cost Recognized	849	872	2,818	2,887
Other Postretirement Benefit Plans, Defined Benefit
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	652	656	1,956	1,968
Interest Cost	808	729	2,424	2,187
Expected Return on Plan Assets	(301)	(273)	(903)	(819)
Prior Service Cost Amortization	372	420	1,116	1,260
Actuarial Loss Amortization	262	288	786	864
Sub-total	1,793	1,820	5,379	5,460
Amounts Capitalized and Deferred	(904)	(921)	(2,508)	(2,563)
Net Periodic Benefit Cost Recognized	889	899	2,871	2,897
Supplemental Employee Retirement Plans, Defined Benefit
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	41	28	123	84
Interest Cost	96	78	288	234
Prior Service Cost Amortization	47	2	141	8
Actuarial Loss Amortization	94	84	282	252
Sub-total	278	192	834	578
Net Periodic Benefit Cost Recognized	$ 278	$ 192	$ 834	$ 578

Retirement Benefit Obligations - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2016 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	$ 5,100,000
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	2,800,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Benefit payments under SERP Plan	25,600
Expected additional benefit payments under SERP Plan in 2016	$ 8,500