Unitil (UTL) 10-Q 23 Jul 14 2014 Q2 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	6 Months Ended
	Jun. 30, 2014	Jul. 18, 2014
Document Information [Line Items]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Jun-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q2	'
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	'	13,897,549

Consolidated_Statements_of_Ear

Consolidated Statements of Earnings (USD $)	3 Months Ended		6 Months Ended
In Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating Revenues	'	'	'	'
Gas	$25.80	$22.10	$118.40	$92.90
Electric	46.1	42.9	108	88.8
Other	1.4	1.4	3	2.9
Total Operating Revenues	73.3	66.4	229.4	184.6
Operating Expenses	'	'	'	'
Cost of Gas Sales	9.5	8.7	65.6	49
Cost of Electric Sales	27.2	25	69.9	52.5
Operation and Maintenance	15.3	15.1	32.4	30.3
Depreciation and Amortization	10.2	9.5	20.4	19
Taxes Other Than Income Taxes	4	3.6	8.6	7.4
Total Operating Expenses	66.2	61.9	196.9	158.2
Operating Income	7.1	4.5	32.5	26.4
Interest Expense, net	5.3	4.6	10.5	9.2
Other Expense, net	0.1	0.1	0.2	0.2
Income (Loss) Before Income Taxes	1.7	-0.2	21.8	17
Income Tax Expense (Benefit)	0.6	-0.1	8.1	6.3
Net Income (Loss)	$1.10	($0.10)	$13.70	$10.70
Net Income (Loss) Per Common Share (Basic and Diluted)	$0.08	($0.01)	$0.99	$0.78
Weighted Average Common Shares Outstanding - (Basic and Diluted)	13.8	13.8	13.8	13.8
Dividends Declared Per Share of Common Stock	$0.35	$0.35	$0.69	$1.03

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Current Assets:	'	'	'
Cash and Cash Equivalents	$12	$9.40	$7.10
Accounts Receivable, net	44.9	52.2	40.8
Accrued Revenue	33.4	56.6	38.3
Exchange Gas Receivable	8.3	10.8	7.6
Gas Inventory	0.8	1.2	0.8
Deferred Income Taxes	1.5	'	'
Materials and Supplies	6.1	5	5.4
Prepayments and Other	6.9	4.8	5.6
Total Current Assets	113.9	140	105.6
Utility Plant:	'	'	'
Gas	483.9	477.3	431.6
Electric	379.1	375.6	359.1
Common	32.3	31.6	31.5
Construction Work in Progress	34.3	24.6	40.4
Total Utility Plant	929.6	909.1	862.6
Less: Accumulated Depreciation	247.9	243.5	237.2
Net Utility Plant	681.7	665.6	625.4
Other Noncurrent Assets:	'	'	'
Regulatory Assets	88.1	100.1	125.9
Other Assets	16.9	14.9	17.3
Total Other Noncurrent Assets	105	115	143.2
TOTAL ASSETS	900.6	920.6	874.2
Current Liabilities:	'	'	'
Accounts Payable	20.5	38.1	21.7
Short-Term Debt	35	60.2	24.5
Long-Term Debt, Current Portion	2.5	2.5	0.6
Energy Supply Obligations	12.3	14.4	9.8
Deferred Income Taxes	'	6.7	3.1
Dividends Declared and Payable	'	'	4.8
Environmental Obligations	6.4	1	1
Interest Payable	3.1	3.1	3.1
Regulatory Liabilities	13	9.7	13.3
Other Current Liabilities	9.8	9	8.7
Total Current Liabilities	102.6	144.7	90.6
Noncurrent Liabilities:	'	'	'
Deferred Income Taxes	87.8	73.2	54.4
Cost of Removal Obligations	60.8	57.3	54.7
Retirement Benefit Obligations	80.8	77.3	110.6
Capital Lease Obligations	5.6	0.2	0.4
Environmental Obligations	2	13.8	13.8
Other Noncurrent Liabilities	5.6	4.1	4.7
Total Noncurrent Liabilities	242.6	225.9	238.6
Capitalization:	'	'	'
Long-Term Debt, Less Current Portion	284.6	284.8	287
Common Stock Equity:	'	'	'
Common Equity (Outstanding 13,895,777, 13,822,318 and 13,841,400 Shares)	233.6	232.1	231
Retained Earnings	37	32.9	26.8
Total Common Stock Equity	270.6	265	257.8
Preferred Stock	0.2	0.2	0.2
Total Capitalization	555.4	550	545
TOTAL LIABILITIES AND CAPITALIZATION	$900.60	$920.60	$874.20

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Common Equity Outstanding	13,895,777	13,841,400	13,822,318

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013
Operating Activities:	'	'
Net Income	$13.70	$10.70
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:	'	'
Depreciation and Amortization	20.4	19
Deferred Tax Provision	7.7	5.8
Changes in Working Capital Items:	'	'
Accounts Receivable	7.3	6.9
Accrued Revenue	23.2	25.1
Regulatory Liabilities	3.3	6.5
Exchange Gas Receivable	2.5	1.8
Accounts Payable	-17.6	-11
Other Changes in Working Capital Items	3.5	-6.5
Deferred Regulatory and Other Charges	-0.3	7.6
Other, net	-0.1	4.4
Cash Provided by Operating Activities	63.6	70.3
Investing Activities:	'	'
Property, Plant and Equipment Additions	-29.1	-37
Cash (Used in) Investing Activities	-29.1	-37
Financing Activities:	'	'
Repayment of Short-Term Debt, net	-25.2	-24.9
Repayment of Long-Term Debt	-0.2	-0.2
Increase / (Decrease) in Capital Lease Obligations	4.7	-0.4
Net Decrease in Exchange Gas Financing	-2.2	-1.6
Dividends Paid	-9.6	-9.5
Proceeds from Issuance of Common Stock, net	0.6	0.6
Cash (Used in) Financing Activities	-31.9	-36
Net Increase (Decrease) in Cash and Cash Equivalents	2.6	-2.7
Cash and Cash Equivalents at Beginning of Period	9.4	9.8
Cash and Cash Equivalents at End of Period	12	7.1
Supplemental Cash Flow Information:	'	'
Interest Paid	10.6	10.4
Income Taxes Paid	0.3	0.8
Non-cash Investing Activity:	'	'
Capital Expenditures Included in Accounts Payable	$0.40	$1.80

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Common Stock Equity (USD $)	Total	Common Equity	Retained Earnings
In Millions
Beginning Balance at Dec. 31, 2012	$260.40	$230	$30.40
Net Income	10.7	'	10.7
Dividends on Common Shares	-14.3	'	-14.3
Stock Compensation Plans	0.4	0.4	'
Issuance of Common Shares	0.6	0.6	'
Ending Balance at Jun. 30, 2013	257.8	231	26.8
Beginning Balance at Dec. 31, 2013	265	232.1	32.9
Net Income	13.7	'	13.7
Dividends on Common Shares	-9.6	'	-9.6
Stock Compensation Plans	0.9	0.9	'
Issuance of Common Shares	0.6	0.6	'
Ending Balance at Jun. 30, 2014	$270.60	$233.60	$37

Consolidated_Statements_of_Cha1

Consolidated Statements of Changes in Common Stock Equity (Parenthetical)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Common Stock, Shares issued	18,877	20,477

Summary_of_Significant_Account

Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2014
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 results are expected to reflect the seasonal nature of the natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.
	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 six months ended June 30, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. 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, 2013, as filed with the Securities and Exchange Commission (SEC) on January 29, 2014, for a description of the Company’s Basis of Presentation.
	Fair Value –The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:
	Level 1 –		Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
	Level 2 –		Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
	Level 3 –		Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.
	To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
	Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.
	There have been no changes in the valuation techniques used during the current period.
	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. Deferred income taxes are reflected as Deferred Income Taxes in Current and Noncurrent Liabilities on the Consolidated Balance Sheets based on the nature of the underlying timing item.
	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. As of June 30, 2014, June 30, 2013 and December 31, 2013, the Unitil subsidiaries had deposited $8.8 million, $4.8 million and $7.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. As of June 30, 2014, June 30, 2013 and December 31, 2013, there was $0, $0.7 million and $0, respectively, deposited for this purpose.
	Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, as a result of the MDPU’s final rate order dated May 30, 2014, discussed below, the electric division of Fitchburg is authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.
	The Allowance for Doubtful Accounts as of June 30, 2014, June 30, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:
	($ millions)
			June 30,								December 31,
			2014				2013				2013
	Allowance for Doubtful Accounts		$	1.7			$	2.4			$	1.6
	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 June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Accrued Revenue ($ millions)		2014				2013				2013
	Regulatory Assets – Current		$	27.3			$	31.6			$	43.6
	Unbilled Revenues			6.1				6.7				13
	Total Accrued Revenue		$	33.4			$	38.3			$	56.6
	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 June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Exchange Gas Receivable ($ millions)		2014				2013				2013
	Northern Utilities		$	7.6			$	7			$	9.8
	Fitchburg			0.7				0.6				1
	Total Exchange Gas Receivable		$	8.3			$	7.6			$	10.8
	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 June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Gas Inventory ($ millions)		2014				2013				2013
	Natural Gas		$	0.5			$	0.4			$	0.8
	Propane			0.1				0.3				0.3
	Liquefied Natural Gas & Other			0.2				0.1				0.1
	Total Gas Inventory		$	0.8			$	0.8			$	1.2
	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 June 30, 2014, June 30, 2013 and December 31, 2013, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $60.8 million, $54.7 million, and $57.3 million, respectively. Included in Construction Work in Progress at June 30, 2014 is approximately $5.0 million related to the development of a new customer information system.
	Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.
			June 30,								December 31,
	Regulatory Assets consist of the following ($ millions)		2014				2013				2013
	Energy Supply & Other Regulatory Tracker Mechanisms		$	17.7			$	19.3			$	32.5
	Deferred Restructuring Costs			4.7				14.5				9.3
	Retirement Benefit			42.2				62.5				42.6
	Income Taxes			10.4				9.5				11.9
	Environmental			10.6				16.7				16.1
	Deferred Storm Charges			22.3				28.1				25.6
	Other			7.5				6.9				5.7
	Total Regulatory Assets		$	115.4			$	157.5			$	143.7
	Less: Current Portion of Regulatory Assets(1)			27.3				31.6				43.6
	Regulatory Assets – noncurrent		$	88.1			$	125.9			$	100.1
	(1)	Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.
			June 30,								December 31,
	Regulatory Liabilities consist of the following ($ millions)		2014				2013				2013
	Regulatory Tracker Mechanisms		$	13			$	13.3			$	9.7
	Total Regulatory Liabilities		$	13			$	13.3			$	9.7
	Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Derivatives – The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.
The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of June 30, 2014, all futures contracts purchased under the prior program design were sold and the hedging portfolio now consists entirely of call option contracts.
Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.
As of June 30, 2014, June 30, 2013 and December 31, 2013 the Company had 2.3 billion, 1.8 billion and 1.8 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.
The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.
Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
				Fair Value
Description		Balance Sheet Location		June 30,				June 30,				December 31,
				2014				2013				2013
Derivative Assets
Natural Gas Futures/Options Contracts		Prepayments and Other		$	—			$	—			$	0.1
Natural Gas Futures/Options Contracts		Other Assets			—				—				0.1
Total Derivative Assets				$	—			$	—			$	0.2
Derivative Liabilities
Natural Gas Futures/Options Contracts		Other Current Liabilities		$	0.1			$	0.3			$	—
Natural Gas Futures/Options Contracts		Other Noncurrent Liabilities			0.1				0.1				—
Total Derivative Liabilities				$	0.2			$	0.4			$	—
		Three Months								Six Months
		Ended								Ended
		June 30,								June 30,
($ millions)		2014				2013				2014				2013
Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures / Options Contracts		$	0.4			$	0.9			$	(0.5	)		$	0.6
Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings(1):
Cost of Gas Sales		$	—			$	—			$	(0.9	)		$	0.9
(1)	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.
Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current Energy Supply Obligations and the noncurrent amount of Energy Supply Obligations which is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.
		June 30,								December 31,
Energy Supply Obligations ($ millions)		2014				2013				2013
Current:
Exchange Gas Obligation		$	7.6			$	7			$	9.8
Renewable Energy Portfolio Standards			4				1.9				3.7
Power Supply Contract Divestitures			0.7				0.9				0.9
Total Energy Supply Obligations – Current		$	12.3			$	9.8			$	14.4
Long-Term:
Power Supply Contract Divestitures		$	2.2			$	2.9			$	2.5
Total Energy Supply Obligations		$	14.5			$	12.7			$	16.9
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.
Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling 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).
Massachusetts Green Communities Act – 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 facility associated with one of these contracts has been constructed and is operating. The other contracts have been approved by the MDPU and are pending facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg recovers its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.
Recently Issued Pronouncements – On May 28, 2014, the FASB issued ASU 2014-09 which 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, 2016. The Company does not expect that the adoption of the new guidance will have a material impact on the Company’s Consolidated Financial Statements.
Other than ASU 2014-09, 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.
Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. The Company has reclassified the funding of regulatory-approved major storm cost reserves from Operation and Maintenance expense to Depreciation and Amortization expense on the Company’s Consolidated Statements of Earnings. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

Dividends_Declared_Per_Share

Dividends Declared Per Share	6 Months Ended
	Jun. 30, 2014
Dividends Declared Per Share	'
	NOTE 2 – DIVIDENDS DECLARED PER SHARE
	Declaration	Date Paid (Payable)	Shareholder of		Dividend Amount
	Date		Record Date
	7/22/14	8/29/14		8/15/14	$ 0.345
	4/22/14	5/29/14		5/15/14	$ 0.345
	1/16/14	2/28/14		2/14/14	$ 0.345
	9/18/13	11/15/13		11/1/13	$ 0.345
	6/5/13	8/15/13		8/1/13	$ 0.345
	3/28/13	5/15/13		5/1/13	$ 0.345
	1/17/13	2/15/13		2/1/13	$ 0.345

Segment_Information

Segment Information	6 Months Ended
	Jun. 30, 2014
Segment Information	'
	NOTE 3 – SEGMENT INFORMATION
	The following table provides significant segment financial data for the three and six months ended June 30, 2014 and June 30, 2013 and as of December 31, 2013 (Millions):
		Electric		Gas			Other		Non-Regulated		Total
	Three Months Ended June 30, 2014
	Revenues	$	46.1	$	25.8		$	—	$	1.4	$	73.3
	Segment Profit (Loss)		1.4		(0.7	)		0.2		0.2		1.1
	Capital Expenditures		5		13.3			1.4		0.2		19.9
	Three Months Ended June 30, 2013
	Revenues	$	42.9	$	22.1		$	—	$	1.4	$	66.4
	Segment Profit (Loss)		1.4		(2.3	)		0.6		0.2		(0.1	)
	Capital Expenditures		3.4		17.6			1.6		—		22.6
	Six Months Ended June 30, 2014
	Revenues	$	108	$	118.4		$	—	$	3	$	229.4
	Segment Profit		2.3		10.8			0.2		0.4		13.7
	Capital Expenditures		10.1		16.3			2.4		0.3		29.1
	Segment Assets		391.6		490.6			12.3		6.1		900.6
	Six Months Ended June 30, 2013
	Revenues	$	88.8	$	92.9		$	—	$	2.9	$	184.6
	Segment Profit		3.4		6			0.7		0.6		10.7
	Capital Expenditures		10.4		24.5			2.1		—		37
	Segment Assets		405.7		456.8			5.3		6.4		874.2
	As of December 31, 2013
	Segment Assets	$	502.3	$	402.8		$	6.2	$	9.3	$	920.6

Debt_and_Financing_Arrangement

Debt and Financing Arrangements	6 Months Ended
	Jun. 30, 2014
Debt and Financing Arrangements	'
	NOTE 4 – DEBT AND FINANCING ARRANGEMENTS
	Long-Term Debt
	Details on long-term debt at June 30, 2014, June 30, 2013 and December 31, 2013 are shown below ($ Millions):
		June 30,				December 31,
		2014		2013		2013
	Unitil Corporation Senior Notes:
	6.33% Notes, Due May 1, 2022	$	20	$	20	$	20
	Unitil Energy Systems, Inc.:
	First Mortgage Bonds:
	5.24% Series, Due March 2, 2020		15		15		15
	8.49% Series, Due October 14, 2024		15		15		15
	6.96% Series, Due September 1, 2028		20		20		20
	8.00% Series, Due May 1, 2031		15		15		15
	6.32% Series, Due September 15, 2036		15		15		15
	Fitchburg Gas and Electric Light Company:
	Long-Term Notes:
	6.75% Notes, Due November 30, 2023		19		19		19
	7.37% Notes, Due January 15, 2029		12		12		12
	7.98% Notes, Due June 1, 2031		14		14		14
	6.79% Notes, Due October 15, 2025		10		10		10
	5.90% Notes, Due December 15, 2030		15		15		15
	Northern Utilities, Inc.:
	Senior Notes:
	6.95% Senior Notes, Due December 3, 2018		30		30		30
	5.29% Senior Notes, Due March 2, 2020		25		25		25
	7.72% Senior Notes, Due December 3, 2038		50		50		50
	Granite State Gas Transmission, Inc.:
	Senior Notes:
	7.15% Senior Notes, Due December 15, 2018		10		10		10
	Unitil Realty Corp.:
	Senior Secured Notes:
	8.00% Notes, Due Through August 1, 2017		2.1		2.6		2.3
	Total Long-Term Debt		287.1		287.6		287.3
	Less: Current Portion		2.5		0.6		2.5
	Total Long-term Debt, Less Current Portion	$	284.6	$	287	$	284.8
	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)	June 30,				December 31,
		2014		2013		2013
	Estimated Fair Value of Long-Term Debt	$	338.5	$	333.2	$	327.3
	Credit Arrangements
	On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.375%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.
	The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of June 30, 2014, June 30, 2013 and December 31, 2013:
		Revolving Credit Facility (millions)
		June 30,				December 31,
		2014		2013		2013
	Limit	$	120.0	$	60.0	$	120.0
	Outstanding	$	35	$	24.5	$	60.2
	Available	$	85	$	35.5	$	59.8
	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 June 30, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
	In April 2014, Unitil Service Corp. entered into an arrangement for the financing of the construction and installation of a customer information system, including software and equipment. The financing arrangement is structured as a capital lease obligation with maximum availability of $15 million. As of June 30, 2014, Unitil Service Corp. has received funding under this financing arrangement in the amount of $5.0 million, which was used to fund project costs.
	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 $7.8 million, $7.2 million and $12.5 million of natural gas storage inventory at June 30, 2014, June 30, 2013 and December 31, 2013, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2014 and payable in July 2014 is $0.2 million and is recorded in Accounts Payable at June 30, 2014. The amount of natural gas inventory released in June 2013 and payable in July 2013 was $0.1 million and was recorded in Accounts Payable at June 30, 2013. The amount of natural gas inventory released in December 2013 and payable in January 2014 was $2.7 million and was recorded in Accounts Payable at December 31, 2013.
	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 June 30 2014, there were approximately $28.5 million of guarantees outstanding and the longest term guarantee extends through April 2015.
	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 June 30, 2014, the principal amount outstanding for the 8% Unitil Realty notes was $2.1 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of June 30, 2014, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Common_Stock_and_Preferred_Sto

Common Stock and Preferred Stock	6 Months Ended
	Jun. 30, 2014
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 13,895,777, 13,822,318 and 13,841,400 shares of common stock outstanding at June 30, 2014, June 30, 2013 and December 31, 2013, respectively.
	Dividend Reinvestment and Stock Purchase Plan – During the six months of 2014, the Company sold 18,877 shares of its common stock, at an average price of $32.07 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $605,000. 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. Awards may be grossed up to offset the participant’s tax obligations in connection with the 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 31, 2014, 35,500 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.1 million. There were 67,334 and 53,480 non-vested shares under the Stock Plan as of June 30, 2014 and 2013, respectively. The weighted average grant date fair value of these shares was $28.51 and $25.99, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.2 million and $0.5 million for the six months ended June 30, 2014 and 2013, respectively. At June 30, 2014, there was approximately $1.0 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.8 years. There were no forfeitures or cancellations under the Stock Plan during the six months ended June 30, 2014.
	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 six months ended June 30, 2014 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, 2013		14,903	$	28.9
	Restricted Stock Units Granted		—		—
	Dividend Equivalents Earned		322	$	32.08
	Restricted Stock Units Settled		—		—
	Restricted Stock Units as of June 30, 2014		15,225	$	28.97
	There were 3,977 Restricted Stock Units (equity portion) outstanding as of June 30, 2014 with a weighted average stock price of $27.42. The fair value of liabilities associated with the cash portion of fully-vested Restricted Stock Units is approximately $0.2 million, less than $0.1 million and approximately $0.2 million as of June 30, 2014, June 30, 2013 and December 31, 2013, respectively, and is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.
	Preferred Stock
	There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of June 30, 2014, June 30, 2013 and December 31, 2013. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and six month periods ended June 30, 2014 and June 30, 2013, respectively.

Regulatory_Matters

Regulatory Matters	6 Months Ended
	Jun. 30, 2014
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, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.
	Regulatory Matters
	Northern Utilities – Base Rates – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed 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 settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan (SQP) that Northern Utilities has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern Utilities will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP. On February 28, 2014 Northern Utilities filed its first annual TIRA for rates effective May 1, 2014, seeking an annual increase in base distribution revenue of $1.3 million. This filing was approved by the MPUC on April 29, 2014. TIRA filings in future periods are projected to result in annual increases in revenue of approximately $1.0 million each year.
	Northern Utilities – Base Rates – New Hampshire – On April 21, 2014, the NHPUC approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. In addition, the settlement agreement provides for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provides for an annual increase in revenue of $1.4 million, effective May 1, 2014. The 2015 step adjustment is for a projected annual increase in revenue of approximately $1.4 million, effective May 1, 2015. The settlement agreement also provides for Earning Sharing where Northern Utilities would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement provides that the Company’s next filing of a distribution base rate case is to be based on an historic test year of no earlier than twelve months ending December 31, 2016. The newly-approved rates will be reconciled to the effective date temporary rates were established, July 1, 2013.
	Unitil Energy – Base Rates – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On April 30, 2014 the NHPUC approved Unitil Energy’s third and final step increase of $1.5 million in annual revenue effective May 1, 2014.
	Granite State – Base Rates – Granite State has in place a FERC approved rate 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. On June 27, 2014, Granite State filed to increase its rates and annual revenue by an additional $0.6 million beginning August 1, 2014. With this filing, Granite State has reached the settlement agreement cost cap. The FERC accepted this filing on June 18, 2014 and the new rates will be effective August 1, 2014 as proposed.
	Fitchburg – Electric Base Rates – In July 2013, Fitchburg filed a rate case with the MDPU requesting an increase of $6.7 million in electric base revenue. A final rate order was issued by the MDPU on May 30, 2014 for rates effective June 1, 2014, approving a $5.6 million increase in electric base revenue, or 9.5% over 2012 test year operating revenue. The MDPU approved a 9.7% return on equity and a common equity ratio of 48%. As part of the increase in base revenue, the MDPU approved the recovery, over three years, of $5.0 million of previously deferred emergency storm repair costs incurred in 2011 as a result of Hurricane Irene and the October snow storm and in 2012 as a result of Superstorm Sandy. In addition, the MDPU approved an expanded storm resiliency vegetation management program at an annual funding amount of $0.5 million. The MDPU also approved the recovery of $0.9 million over a five-year period of past due amounts associated with hardship accounts that are protected from shut-off. The impact of the rate order on previously capitalized or deferred items was not material.
	Major Storms – Fitchburg and Unitil Energy
	Fitchburg – 2011 Storm Cost Deferral and 2012 Storm Costs - As part of its May 30, 2014 order approving a base rate increase for Fitchburg, the MDPU approved the recovery over three years, without carrying charges, of $5.0 million of costs of repair for damage due to severe storms, including previously deferred costs incurred in 2011, as well as costs incurred in 2012 as a result of Superstorm Sandy.
	Unitil Energy – 2012 Storm Costs – On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.
	Fitchburg – Electric Operations – On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation pending investigation by the MDPU. On June 4, 2014, the MDPU issued a final order approving Fitchburg’s annual reconciliation filing. Other cost factors are pending final approval.
	Fitchburg – Gas Operations – On June 26, 2014, the Governor of Massachusetts signed into law a gas leak bill providing for the following, among other items: amends DPU’s ability to fine gas companies for violations of gas pipeline safety rules consistent with federal law; establishes a uniform natural gas leak classification standard for the Commonwealth; provides that the DPU investigate new programs and policies to facilitate customer conversions to natural gas; and establishes an infrastructure replacement program to address aging natural gas pipeline infrastructure. It is expected the MDPU will open a proceeding to address and implement changes resulting from this new law in the near future.
	Fitchburg – Service Quality – On March 1, 2014, Fitchburg submitted its 2013 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for its gas division. The electric division met or exceeded all metric benchmarks except for two measures relating to the performance of certain individual distribution circuits as compared to the performance of the system as a whole. As a result of penalty offsets earned in six metrics where company performance exceeded the benchmark measure, however, no penalties are due.
	On December 11, 2012, the MDPU opened an investigation into the service quality provided by the gas and electric distribution companies in Massachusetts and the Service Quality Guidelines currently in effect. The order invited comments on a variety of topics related to service quality. After review of all the comments and discovery responses, on July 11, 2014, the MDPU issued an order containing proposed revisions to their Service Quality Guidelines. Comments are due within 30 days of their order and reply comments are due 15 days thereafter. The Department proposes several changes to its Service Quality standards. The changes apply in various ways to the different metrics but, in sum, they involve three interrelated purposes: (1) increasing the level of performance required by companies through new approaches for calculating penalty thresholds and the elimination of offsets; (2) establishing statewide standards applicable to all companies; and (3) updating the standards to eliminate unnecessary or outdated metrics and adding new metrics to align company incentives with the MDPU’s policy objectives. This initial determination may be subject to modification upon the receipt of comments by interested parties.
	Fitchburg – Other – On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, has commenced an investigation of the incident, with which Fitchburg is cooperating. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition or results of operations.
	On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in the Company’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. Briefs were filed in June 2013. This matter remains pending before the MDPU.
	On July 2, 2008, the Governor of Massachusetts signed into law “The Green Communities Act” (the GC Act), an energy policy statute designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs. Several regulatory proceedings have been initiated to implement various provisions of the GC Act, including provisions for each distribution company to file enhanced three-year energy efficiency investment plans, plans to establish smart grid pilot programs, proposals to purchase long-term contracts for renewable energy, special tariffs to allow the net metering of customer-owned renewable generation, and terms and conditions for purchasing supplier receivables. Fitchburg’s first two three-year energy efficiency investment plans, plans to establish smart grid pilot programs, and net metering tariffs have been approved by the MDPU. Fitchburg’s proposal for a long term contract for renewable energy was approved by the MDPU, and the facility has been constructed and is now operating. Fitchburg’s costs associated with the contract are recovered through a MDPU approved tariff. Terms and conditions for purchasing supplier receivables are under review in a separately designated docket.
	On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth,” which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. The Act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisitions for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU also opened a proceeding, as mandated by the Act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor. On December 17, 2013, the MDPU issued an order establishing the new rate design allocation methodologies. The Act also requires electric distribution companies to participate in joint solicitations and enter into additional long-term renewable contracts for 4% of distribution company load. A Request For Proposal for a long-term renewable energy contract, jointly prepared by Fitchburg and the other utility companies in consultation with the Massachusetts Attorney General and the Massachusetts Department of Energy Resources and approved by the MDPU, was issued in the Spring of 2013. After analysis and contract negotiations, contracts for six projects were awarded and submitted for MDPU approval. Three of the contracts were terminated during the approval process, and the MDPU approved the remaining three contracts. Fitchburg’s costs associated with these contracts will be recovered through a MDPU approved tariff.
	On December 23, 2013 the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. On June 12, 2014 the Department issued a further order as a result of its investigation. It sets forth a requirement that each electric distribution company submit a ten-year strategic grid modernization plan (“GMP”) within nine months of the issuance of a Final Order in related, but still ongoing, MDPU proceedings. As part of the GMP, each company must include a five-year short-term investment plan (“STIP”), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP will be a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the company should have proceeded with these investments. Also on June 12, 2014, the MPDU issued an order setting forth its initial policy with respect to time varying rates, finding that the provision of basic energy service should be designed as time varying rates for all rate classes following the deployment of advanced metering functionality. This initial determination may be subject to modification upon the receipt of comments by interested parties. The MDPU also proposes to address in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles (EVs). These matters remain pending.
	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 the Company’s financial position.
	In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC accepted the matter for review, briefs have been submitted and oral arguments have been held. The decision of the SJC is pending. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the SJC in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

Environmental_Matters

Environmental Matters	6 Months Ended
	Jun. 30, 2014
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, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.
	The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of June 30, 2014, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.
	Northern Utilities Manufactured Gas Plant Sites – Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites that were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.
	Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. In May 2014, the State of Maine completed its taking of the site via eminent domain for the expansion of the adjacent marine terminal. As a result of the outcome of negotiations with the State, future operation, maintenance and remedial costs have been accrued, to ensure that applicable remedial activities are completed.
	The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.
	Included in Environmental Obligations on the Company’s Consolidated Balance Sheets at June 30, 2014, June 30, 2013 and December 31, 2013 are $1.2 million, $1.0 million and $1.0 million, respectively, of current accrued liabilities, and $2.0 million, $1.8 million and $1.8 million, respectively, of non-current accrued liabilities 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 began work on the permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the second quarter of 2014. Work is expected to be completed in the fourth quarter of 2014. During the second quarter of 2014, the Company updated its estimate for remediation of this site based upon revised estimates from the consultant performing the work. Consequently, the Company’s previously recorded estimate for this work was adjusted from $12.0 million to $5.5 million, with $0.3 million having already been spent in 2014. Included in Environmental Obligations on the Company’s Consolidated Balance Sheet at June 30, 2014, June 30, 2013 and December 31, 2013 are $5.2 million, $0 and $0, respectively of current accrued liabilities, and $0, $12.0 million and $12.0 million, respectively, of non-current accrued liabilities 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 this environmental remediation cost is 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.

Income_Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2014
Income Taxes	'
	NOTE 8: INCOME TAXES
	The Company filed its tax returns for the year ended December 31, 2012 with the Internal Revenue Service (IRS) in September 2013 and generated federal net operating loss (NOL) carryforward assets of $6.6 million principally due to bonus depreciation and targeted asset repair deductions. As of December 31, 2013, the Company had recorded cumulative federal and state NOL carryforward assets of $17.4 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2013, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.
	The Company evaluated its tax positions at June 30, 2014 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, 2010; December 31, 2011; and December 31, 2012.
	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

Retirement Benefit Obligations	6 Months Ended
	Jun. 30, 2014
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, 2013 as filed with the SEC on January 29, 2014 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:
		2014			2013
	Used to Determine Plan Costs
	Discount Rate		4.8	%		4	%
	Rate of Compensation Increase		3	%		3	%
	Expected Long-term rate of return on plan assets		8	%		8.5	%
	Health Care Cost Trend Rate Assumed for Next Year		7	%		8	%
	Ultimate Health Care Cost Trend Rate		4	%		4	%
	Year that Ultimate Health Care Cost Trend Rate is reached		2018			2017
	The following tables provide the components of the Company’s Retirement plan costs ($000’s):
		Pension Plan						PBOP Plan						SERP
	Three Months Ended June 30,	2014			2013			2014			2013			2014		2013
	Service Cost	$	751		$	894		$	497		$	631		$	14	$	18
	Interest Cost		1,273			1,141			672			612			68		60
	Expected Return on Plan Assets		(1,561	)		(1,489	)		(230	)		(180	)		—		—
	Prior Service Cost Amortization		53			52			420			425			3		3
	Actuarial Loss Amortization		712			1,056			14			196			25		46
	Sub-total		1,228			1,654			1,373			1,684			110		127
	Amounts Capitalized and Deferred		(501	)		(768	)		(593	)		(678	)		—		—
	Net Periodic Benefit Cost Recognized	$	727		$	886		$	780		$	1,006		$	110	$	127
		Pension Plan						PBOP Plan						SERP
	Six Months Ended June 30,	2014			2013			2014			2013			2014		2013
	Service Cost	$	1,502		$	1,787		$	994		$	1,262		$	28	$	36
	Interest Cost		2,546			2,283			1,344			1,224			136		121
	Expected Return on Plan Assets		(3,122	)		(2,978	)		(460	)		(361	)		—		—
	Prior Service Cost Amortization		106			104			840			850			6		6
	Actuarial Loss Amortization		1,424			2,115			28			393			50		92
	Sub-total		2,456			3,311			2,746			3,368			220		255
	Amounts Capitalized and Deferred		(844	)		(1,384	)		(1,065	)		(1,447	)		—		—
	Net Periodic Benefit Cost Recognized	$	1,612		$	1,927		$	1,681		$	1,921		$	220	$	255
	Employer Contributions
	As of June 30, 2014, the Company had made $1.9 million of contributions to its Pension Plan in 2014 and had not made any contributions to its PBOP Plan in 2014. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2014 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in rates for these Pension and PBOP Plan costs.
	As of June 30, 2014, the Company had made $26,000 of contributions to the SERP Plan in 2014. The Company presently anticipates contributing an additional $27,000 to the SERP Plan in 2014.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2014
Nature of Operations	'
	Nature of Operations – Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource Inc. and Usource L.L.C. are subsidiaries of Unitil Resources.
	The Company’s results are expected to reflect the seasonal nature of the natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.
	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	'
	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 six months ended June 30, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. 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, 2013, as filed with the Securities and Exchange Commission (SEC) on January 29, 2014, for a description of the Company’s Basis of Presentation.
Fair Value	'
	Fair Value –The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:
	Level 1 –		Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
	Level 2 –		Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
	Level 3 –		Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.
	To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
	Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.
	There have been no changes in the valuation techniques used during the current period.
Income Taxes	'
	Income Taxes – The Company is subject to Federal and State income taxes as well as various other business taxes. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s Consolidated Balance Sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with the FASB Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.
	Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. Deferred income taxes are reflected as Deferred Income Taxes in Current and Noncurrent Liabilities on the Consolidated Balance Sheets based on the nature of the underlying timing item.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations. As of June 30, 2014, June 30, 2013 and December 31, 2013, the Unitil subsidiaries had deposited $8.8 million, $4.8 million and $7.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. As of June 30, 2014, June 30, 2013 and December 31, 2013, there was $0, $0.7 million and $0, respectively, deposited for this purpose.
Allowance for Doubtful Accounts	'
	Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, as a result of the MDPU’s final rate order dated May 30, 2014, discussed below, the electric division of Fitchburg is authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.
	The Allowance for Doubtful Accounts as of June 30, 2014, June 30, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:
	($ millions)
			June 30,								December 31,
			2014				2013				2013
	Allowance for Doubtful Accounts		$	1.7			$	2.4			$	1.6
Accrued Revenue	'
	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 June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Accrued Revenue ($ millions)		2014				2013				2013
	Regulatory Assets – Current		$	27.3			$	31.6			$	43.6
	Unbilled Revenues			6.1				6.7				13
	Total Accrued Revenue		$	33.4			$	38.3			$	56.6
Exchange Gas Receivable	'
	Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Exchange Gas Receivable ($ millions)		2014				2013				2013
	Northern Utilities		$	7.6			$	7			$	9.8
	Fitchburg			0.7				0.6				1
	Total Exchange Gas Receivable		$	8.3			$	7.6			$	10.8
Gas Inventory	'
	Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Gas Inventory ($ millions)		2014				2013				2013
	Natural Gas		$	0.5			$	0.4			$	0.8
	Propane			0.1				0.3				0.3
	Liquefied Natural Gas & Other			0.2				0.1				0.1
	Total Gas Inventory		$	0.8			$	0.8			$	1.2
Utility Plant	'
	Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The 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 June 30, 2014, June 30, 2013 and December 31, 2013, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $60.8 million, $54.7 million, and $57.3 million, respectively. Included in Construction Work in Progress at June 30, 2014 is approximately $5.0 million related to the development of a new customer information system.
Regulatory Accounting	'
	Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.
			June 30,								December 31,
	Regulatory Assets consist of the following ($ millions)		2014				2013				2013
	Energy Supply & Other Regulatory Tracker Mechanisms		$	17.7			$	19.3			$	32.5
	Deferred Restructuring Costs			4.7				14.5				9.3
	Retirement Benefit			42.2				62.5				42.6
	Income Taxes			10.4				9.5				11.9
	Environmental			10.6				16.7				16.1
	Deferred Storm Charges			22.3				28.1				25.6
	Other			7.5				6.9				5.7
	Total Regulatory Assets		$	115.4			$	157.5			$	143.7
	Less: Current Portion of Regulatory Assets(1)			27.3				31.6				43.6
	Regulatory Assets – noncurrent		$	88.1			$	125.9			$	100.1
	(1)	Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.
			June 30,								December 31,
	Regulatory Liabilities consist of the following ($ millions)		2014				2013				2013
	Regulatory Tracker Mechanisms		$	13			$	13.3			$	9.7
	Total Regulatory Liabilities		$	13			$	13.3			$	9.7
	Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Derivatives	'
	Derivatives – The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.
	The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of June 30, 2014, all futures contracts purchased under the prior program design were sold and the hedging portfolio now consists entirely of call option contracts.
	Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.
	As of June 30, 2014, June 30, 2013 and December 31, 2013 the Company had 2.3 billion, 1.8 billion and 1.8 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.
	The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.
	Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
					Fair Value
	Description		Balance Sheet Location		June 30,				June 30,				December 31,
					2014				2013				2013
	Derivative Assets
	Natural Gas Futures/Options Contracts		Prepayments and Other		$	—			$	—			$	0.1
	Natural Gas Futures/Options Contracts		Other Assets			—				—				0.1
	Total Derivative Assets				$	—			$	—			$	0.2
	Derivative Liabilities
	Natural Gas Futures/Options Contracts		Other Current Liabilities		$	0.1			$	0.3			$	—
	Natural Gas Futures/Options Contracts		Other Noncurrent Liabilities			0.1				0.1				—
	Total Derivative Liabilities				$	0.2			$	0.4			$	—
			Three Months								Six Months
			Ended								Ended
			June 30,								June 30,
	($ millions)		2014				2013				2014				2013
	Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
	Natural Gas Futures / Options Contracts		$	0.4			$	0.9			$	(0.5	)		$	0.6
	Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings(1):
	Cost of Gas Sales		$	—			$	—			$	(0.9	)		$	0.9
	(1)	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.
Energy Supply Obligations	'
	Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current Energy Supply Obligations and the noncurrent amount of Energy Supply Obligations which is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.
			June 30,								December 31,
	Energy Supply Obligations ($ millions)		2014				2013				2013
	Current:
	Exchange Gas Obligation		$	7.6			$	7			$	9.8
	Renewable Energy Portfolio Standards			4				1.9				3.7
	Power Supply Contract Divestitures			0.7				0.9				0.9
	Total Energy Supply Obligations – Current		$	12.3			$	9.8			$	14.4
	Long-Term:
	Power Supply Contract Divestitures		$	2.2			$	2.9			$	2.5
	Total Energy Supply Obligations		$	14.5			$	12.7			$	16.9
	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.
	Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling 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).
	Massachusetts Green Communities Act – 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 facility associated with one of these contracts has been constructed and is operating. The other contracts have been approved by the MDPU and are pending facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg recovers its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.
Recently Issued Pronouncements	'
	Recently Issued Pronouncements – On May 28, 2014, the FASB issued ASU 2014-09 which 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, 2016. The Company does not expect that the adoption of the new guidance will have a material impact on the Company’s Consolidated Financial Statements.
	Other than ASU 2014-09, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.
Subsequent Events	'
	Subsequent Events – The Company 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.
Reclassifications	'
	Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. The Company has reclassified the funding of regulatory-approved major storm cost reserves from Operation and Maintenance expense to Depreciation and Amortization expense on the Company’s Consolidated Statements of Earnings. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2014
Allowance for Doubtful Accounts Included in Accounts Receivable Net	'
	The Allowance for Doubtful Accounts as of June 30, 2014, June 30, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:
	($ millions)
			June 30,								December 31,
			2014				2013				2013
	Allowance for Doubtful Accounts		$	1.7			$	2.4			$	1.6
Components of Accrued Revenue	'
	The following table shows the components of Accrued Revenue as of June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Accrued Revenue ($ millions)		2014				2013				2013
	Regulatory Assets – Current		$	27.3			$	31.6			$	43.6
	Unbilled Revenues			6.1				6.7				13
	Total Accrued Revenue		$	33.4			$	38.3			$	56.6
Components of Exchange Gas Receivable	'
	The following table shows the components of Exchange Gas Receivable as of June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Exchange Gas Receivable ($ millions)		2014				2013				2013
	Northern Utilities		$	7.6			$	7			$	9.8
	Fitchburg			0.7				0.6				1
	Total Exchange Gas Receivable		$	8.3			$	7.6			$	10.8
Components of Gas Inventory	'
	The following table shows the components of Gas Inventory as of June 30, 2014, June 30, 2013 and December 31, 2013.
			June 30,								December 31,
	Gas Inventory ($ millions)		2014				2013				2013
	Natural Gas		$	0.5			$	0.4			$	0.8
	Propane			0.1				0.3				0.3
	Liquefied Natural Gas & Other			0.2				0.1				0.1
	Total Gas Inventory		$	0.8			$	0.8			$	1.2
Regulatory Assets	'
			June 30,								December 31,
	Regulatory Assets consist of the following ($ millions)		2014				2013				2013
	Energy Supply & Other Regulatory Tracker Mechanisms		$	17.7			$	19.3			$	32.5
	Deferred Restructuring Costs			4.7				14.5				9.3
	Retirement Benefit			42.2				62.5				42.6
	Income Taxes			10.4				9.5				11.9
	Environmental			10.6				16.7				16.1
	Deferred Storm Charges			22.3				28.1				25.6
	Other			7.5				6.9				5.7
	Total Regulatory Assets		$	115.4			$	157.5			$	143.7
	Less: Current Portion of Regulatory Assets(1)			27.3				31.6				43.6
	Regulatory Assets – noncurrent		$	88.1			$	125.9			$	100.1
	(1)	Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.
Regulatory Liabilities	'
			June 30,								December 31,
	Regulatory Liabilities consist of the following ($ millions)		2014				2013				2013
	Regulatory Tracker Mechanisms		$	13			$	13.3			$	9.7
	Total Regulatory Liabilities		$	13			$	13.3			$	9.7
Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets	'
	Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
					Fair Value
	Description		Balance Sheet Location		June 30,				June 30,				December 31,
					2014				2013				2013
	Derivative Assets
	Natural Gas Futures/Options Contracts		Prepayments and Other		$	—			$	—			$	0.1
	Natural Gas Futures/Options Contracts		Other Assets			—				—				0.1
	Total Derivative Assets				$	—			$	—			$	0.2
	Derivative Liabilities
	Natural Gas Futures/Options Contracts		Other Current Liabilities		$	0.1			$	0.3			$	—
	Natural Gas Futures/Options Contracts		Other Noncurrent Liabilities			0.1				0.1				—
	Total Derivative Liabilities				$	0.2			$	0.4			$	—
Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Purchased Gas	'
			Three Months								Six Months
			Ended								Ended
			June 30,								June 30,
	($ millions)		2014				2013				2014				2013
	Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
	Natural Gas Futures / Options Contracts		$	0.4			$	0.9			$	(0.5	)		$	0.6
	Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings(1):
	Cost of Gas Sales		$	—			$	—			$	(0.9	)		$	0.9
	(1)	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.
Components of Energy Supply Obligations	'
			June 30,								December 31,
	Energy Supply Obligations ($ millions)		2014				2013				2013
	Current:
	Exchange Gas Obligation		$	7.6			$	7			$	9.8
	Renewable Energy Portfolio Standards			4				1.9				3.7
	Power Supply Contract Divestitures			0.7				0.9				0.9
	Total Energy Supply Obligations – Current		$	12.3			$	9.8			$	14.4
	Long-Term:
	Power Supply Contract Divestitures		$	2.2			$	2.9			$	2.5
	Total Energy Supply Obligations		$	14.5			$	12.7			$	16.9

Dividends_Declared_Per_Share_T

Dividends Declared Per Share (Tables)	6 Months Ended
	Jun. 30, 2014
Schedule of Dividends Declared	'
	Declaration	Date Paid (Payable)	Shareholder of		Dividend Amount
	Date		Record Date
	7/22/14	8/29/14		8/15/14	$ 0.345
	4/22/14	5/29/14		5/15/14	$ 0.345
	1/16/14	2/28/14		2/14/14	$ 0.345
	9/18/13	11/15/13		11/1/13	$ 0.345
	6/5/13	8/15/13		8/1/13	$ 0.345
	3/28/13	5/15/13		5/1/13	$ 0.345
	1/17/13	2/15/13		2/1/13	$ 0.345

Segment_Information_Tables

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2014
Significant Segment Financial Data	'
	The following table provides significant segment financial data for the three and six months ended June 30, 2014 and June 30, 2013 and as of December 31, 2013 (Millions):
		Electric		Gas			Other		Non-Regulated		Total
	Three Months Ended June 30, 2014
	Revenues	$	46.1	$	25.8		$	—	$	1.4	$	73.3
	Segment Profit (Loss)		1.4		(0.7	)		0.2		0.2		1.1
	Capital Expenditures		5		13.3			1.4		0.2		19.9
	Three Months Ended June 30, 2013
	Revenues	$	42.9	$	22.1		$	—	$	1.4	$	66.4
	Segment Profit (Loss)		1.4		(2.3	)		0.6		0.2		(0.1	)
	Capital Expenditures		3.4		17.6			1.6		—		22.6
	Six Months Ended June 30, 2014
	Revenues	$	108	$	118.4		$	—	$	3	$	229.4
	Segment Profit		2.3		10.8			0.2		0.4		13.7
	Capital Expenditures		10.1		16.3			2.4		0.3		29.1
	Segment Assets		391.6		490.6			12.3		6.1		900.6
	Six Months Ended June 30, 2013
	Revenues	$	88.8	$	92.9		$	—	$	2.9	$	184.6
	Segment Profit		3.4		6			0.7		0.6		10.7
	Capital Expenditures		10.4		24.5			2.1		—		37
	Segment Assets		405.7		456.8			5.3		6.4		874.2
	As of December 31, 2013
	Segment Assets	$	502.3	$	402.8		$	6.2	$	9.3	$	920.6

Debt_and_Financing_Arrangement1

Debt and Financing Arrangements (Tables)	6 Months Ended
	Jun. 30, 2014
Details on Long Term Debt	'
	Details on long-term debt at June 30, 2014, June 30, 2013 and December 31, 2013 are shown below ($ Millions):
		June 30,				December 31,
		2014		2013		2013
	Unitil Corporation Senior Notes:
	6.33% Notes, Due May 1, 2022	$	20	$	20	$	20
	Unitil Energy Systems, Inc.:
	First Mortgage Bonds:
	5.24% Series, Due March 2, 2020		15		15		15
	8.49% Series, Due October 14, 2024		15		15		15
	6.96% Series, Due September 1, 2028		20		20		20
	8.00% Series, Due May 1, 2031		15		15		15
	6.32% Series, Due September 15, 2036		15		15		15
	Fitchburg Gas and Electric Light Company:
	Long-Term Notes:
	6.75% Notes, Due November 30, 2023		19		19		19
	7.37% Notes, Due January 15, 2029		12		12		12
	7.98% Notes, Due June 1, 2031		14		14		14
	6.79% Notes, Due October 15, 2025		10		10		10
	5.90% Notes, Due December 15, 2030		15		15		15
	Northern Utilities, Inc.:
	Senior Notes:
	6.95% Senior Notes, Due December 3, 2018		30		30		30
	5.29% Senior Notes, Due March 2, 2020		25		25		25
	7.72% Senior Notes, Due December 3, 2038		50		50		50
	Granite State Gas Transmission, Inc.:
	Senior Notes:
	7.15% Senior Notes, Due December 15, 2018		10		10		10
	Unitil Realty Corp.:
	Senior Secured Notes:
	8.00% Notes, Due Through August 1, 2017		2.1		2.6		2.3
	Total Long-Term Debt		287.1		287.6		287.3
	Less: Current Portion		2.5		0.6		2.5
	Total Long-term Debt, Less Current Portion	$	284.6	$	287	$	284.8
Estimated Fair Value of Long Term Debt	'
	(Millions)	June 30,				December 31,
		2014		2013		2013
	Estimated Fair Value of Long-Term Debt	$	338.5	$	333.2	$	327.3
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 June 30, 2014, June 30, 2013 and December 31, 2013:
		Revolving Credit Facility (millions)
		June 30,				December 31,
		2014		2013		2013
	Limit	$	120.0	$	60.0	$	120.0
	Outstanding	$	35	$	24.5	$	60.2
	Available	$	85	$	35.5	$	59.8

Common_Stock_and_Preferred_Sto1

Common Stock and Preferred Stock (Tables)	6 Months Ended
	Jun. 30, 2014
Restricted Stock Units Issued	'
	The equity portion of Restricted Stock Units activity during the six months ended June 30, 2014 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, 2013		14,903	$	28.9
	Restricted Stock Units Granted		—		—
	Dividend Equivalents Earned		322	$	32.08
	Restricted Stock Units Settled		—		—
	Restricted Stock Units as of June 30, 2014		15,225	$	28.97

Retirement_Benefit_Obligations1

Retirement Benefit Obligations (Tables)	6 Months Ended
	Jun. 30, 2014
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:
		2014			2013
	Used to Determine Plan Costs
	Discount Rate		4.8	%		4	%
	Rate of Compensation Increase		3	%		3	%
	Expected Long-term rate of return on plan assets		8	%		8.5	%
	Health Care Cost Trend Rate Assumed for Next Year		7	%		8	%
	Ultimate Health Care Cost Trend Rate		4	%		4	%
	Year that Ultimate Health Care Cost Trend Rate is reached		2018			2017
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 June 30,	2014			2013			2014			2013			2014		2013
	Service Cost	$	751		$	894		$	497		$	631		$	14	$	18
	Interest Cost		1,273			1,141			672			612			68		60
	Expected Return on Plan Assets		(1,561	)		(1,489	)		(230	)		(180	)		—		—
	Prior Service Cost Amortization		53			52			420			425			3		3
	Actuarial Loss Amortization		712			1,056			14			196			25		46
	Sub-total		1,228			1,654			1,373			1,684			110		127
	Amounts Capitalized and Deferred		(501	)		(768	)		(593	)		(678	)		—		—
	Net Periodic Benefit Cost Recognized	$	727		$	886		$	780		$	1,006		$	110	$	127
		Pension Plan						PBOP Plan						SERP
	Six Months Ended June 30,	2014			2013			2014			2013			2014		2013
	Service Cost	$	1,502		$	1,787		$	994		$	1,262		$	28	$	36
	Interest Cost		2,546			2,283			1,344			1,224			136		121
	Expected Return on Plan Assets		(3,122	)		(2,978	)		(460	)		(361	)		—		—
	Prior Service Cost Amortization		106			104			840			850			6		6
	Actuarial Loss Amortization		1,424			2,115			28			393			50		92
	Sub-total		2,456			3,311			2,746			3,368			220		255
	Amounts Capitalized and Deferred		(844	)		(1,384	)		(1,065	)		(1,447	)		—		—
	Net Periodic Benefit Cost Recognized	$	1,612		$	1,927		$	1,681		$	1,921		$	220	$	255

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
	mi	Bcf	Bcf
	Bcf
Significant Accounting Policies [Line Items]	'	'	'
Length Of Pipeline	86	'	'
Cost of removal obligation	$60.80	$57.30	$54.70
Construction Work in Progress	34.3	24.6	40.4
Number of Natural Gas Storage Outstanding	2.3	1.8	1.8
Maximum	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Cash equivalents maturity period	'3 months	'	'
Customer information system	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Construction Work in Progress	5	'	'
ISO-NE Obligations	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Cash Deposits	8.8	7.3	4.8
Natural Gas Hedging Program	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Cash Deposits	$0	$0	$0.70
Utilities	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Number of Subsidiaries	3	'	'
Other Subsidiaries	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Number of Subsidiaries	3	'	'

Allowance_for_Doubtful_Account

Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Valuation Allowance [Line Items]	'	'	'
Allowance for Doubtful Accounts	$1.70	$1.60	$2.40

Components_of_Accrued_Revenue_

Components of Accrued Revenue (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Deferred Revenue Arrangement [Line Items]	'	'	'
Accrued Revenue	$33.40	$56.60	$38.30
Unbilled Revenues	'	'	'
Deferred Revenue Arrangement [Line Items]	'	'	'
Accrued Revenue	6.1	13	6.7
Regulatory Asset	'	'	'
Deferred Revenue Arrangement [Line Items]	'	'	'
Accrued Revenue	$27.30	$43.60	$31.60

Exchange_Gas_Receivable_Detail

Exchange Gas Receivable (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Receivables [Line Items]	'	'	'
Total Exchange Gas Receivable	$8.30	$10.80	$7.60
Northern Utilities Inc	'	'	'
Receivables [Line Items]	'	'	'
Total Exchange Gas Receivable	7.6	9.8	7
Fitchburg Gas and Electric Light Company	'	'	'
Receivables [Line Items]	'	'	'
Total Exchange Gas Receivable	$0.70	$1	$0.60

Components_of_Gas_Inventory_De

Components of Gas Inventory (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Public Utilities, Inventory [Line Items]	'	'	'
Weighted average cost inventory amount	$0.80	$1.20	$0.80
Natural Gas	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Weighted average cost inventory amount	0.5	0.8	0.4
Propane	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Weighted average cost inventory amount	0.1	0.3	0.3
Liquefied Natural Gas & Other	'	'	'
Public Utilities, Inventory [Line Items]	'	'	'
Weighted average cost inventory amount	$0.20	$0.10	$0.10

Regulatory_Assets_Detail

Regulatory Assets (Detail) (USD $)	Jun. 30, 2014		Dec. 31, 2013		Jun. 30, 2013
In Millions, unless otherwise specified
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	$115.40		$143.70		$157.50
Less: Current Portion of Regulatory Assets	27.3	[1]	43.6	[1]	31.6	[1]
Regulatory Assets - noncurrent	88.1		100.1		125.9
Environmental Matters	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	10.6		16.1		16.7
Retirement Benefit	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	42.2		42.6		62.5
Income Taxes	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	10.4		11.9		9.5
Electric Utilities	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	22.3		25.6		28.1
Other Assets	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	7.5		5.7		6.9
Energy Supply & Other Regulatory Tracker Mechanisms	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	17.7		32.5		19.3
Deferred Restructuring Costs	'		'		'
Regulatory Assets [Line Items]	'		'		'
Regulatory Assets	$4.70		$9.30		$14.50
[1]	Reflects amounts included in Accrued Revenue, discussed above, on the Company's Consolidated Balance Sheets.

Regulatory_Liabilities_Detail

Regulatory Liabilities (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Regulatory Liabilities [Line Items]	'	'	'
Regulatory Liabilities	$13	$9.70	$13.30
Regulatory Tracker Mechanisms	'	'	'
Regulatory Liabilities [Line Items]	'	'	'
Regulatory Liabilities	$13	$9.70	$13.30

Fair_Value_Amount_of_Derivativ

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) (Not Designated as Hedging Instrument, USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Derivative Assets	'	'	'
Derivative Assets	'	$0.20	'
Derivative Liabilities	'	'	'
Derivative Liabilities	0.2	'	0.4
Natural Gas Future/Options Contract | Prepayments and Other	'	'	'
Derivative Assets	'	'	'
Derivative Assets	'	0.1	'
Natural Gas Future/Options Contract | Other Assets	'	'	'
Derivative Assets	'	'	'
Derivative Assets	'	0.1	'
Natural Gas Future/Options Contract | Other Current Liabilities	'	'	'
Derivative Liabilities	'	'	'
Derivative Liabilities	0.1	'	0.3
Natural Gas Future/Options Contract | Other Noncurrent Liabilities	'	'	'
Derivative Liabilities	'	'	'
Derivative Liabilities	$0.10	'	$0.10

Regulatory_Assets_Liabilities_

Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Cost of Gas Sales (Detail) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014		Jun. 30, 2013
Natural Gas Future/Options Contract	'	'	'		'
Regulatory Assets [Line Items]	'	'	'		'
Loss/(Gain) recognized in Regulatory Assets	$0.40	$0.90	($0.50)		$0.60
Gas Purchase Costs	'	'	'		'
Regulatory Assets [Line Items]	'	'	'		'
Loss/(Gain) Reclassified into unaudited Consolidated Statement of Earnings	'	'	($0.90)	[1]	$0.90	[1]
[1]	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Energy_Supply_Obligations_Deta

Energy Supply Obligations (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Contractual Obligation [Line Items]	'	'	'
Energy Supply Obligations	$12.30	$14.40	$9.80
Total Energy Supply Obligations	14.5	16.9	12.7
Exchange Gas Obligation	'	'	'
Contractual Obligation [Line Items]	'	'	'
Energy Supply Obligations	7.6	9.8	7
Renewable Energy Portfolio Standards	'	'	'
Contractual Obligation [Line Items]	'	'	'
Energy Supply Obligations	4	3.7	1.9
Power Supply Contract Divestitures	'	'	'
Contractual Obligation [Line Items]	'	'	'
Energy Supply Obligations	0.7	0.9	0.9
Energy Supply Obligations	$2.20	$2.50	$2.90

Dividends_Declared_Per_Share_D

Dividends Declared Per Share (Detail) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Dividends Payable [Line Items]	'	'	'	'
Dividend Amount	$0.35	$0.35	$0.69	$1.03
Group One	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	22-Jul-14	'
Date Paid (Payable)	'	'	29-Aug-14	'
Shareholder of Record Date	'	'	15-Aug-14	'
Dividend Amount	'	'	$0.35	'
Group Two	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	22-Apr-14	'
Date Paid (Payable)	'	'	29-May-14	'
Shareholder of Record Date	'	'	15-May-14	'
Dividend Amount	'	'	$0.35	'
Group Three	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	16-Jan-14	'
Date Paid (Payable)	'	'	28-Feb-14	'
Shareholder of Record Date	'	'	14-Feb-14	'
Dividend Amount	'	'	$0.35	'
Group Four	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	18-Sep-13	'
Date Paid (Payable)	'	'	15-Nov-13	'
Shareholder of Record Date	'	'	1-Nov-13	'
Dividend Amount	'	'	$0.35	'
Group Five	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	5-Jun-13	'
Date Paid (Payable)	'	'	15-Aug-13	'
Shareholder of Record Date	'	'	1-Aug-13	'
Dividend Amount	'	'	$0.35	'
Group Six	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	28-Mar-13	'
Date Paid (Payable)	'	'	15-May-13	'
Shareholder of Record Date	'	'	1-May-13	'
Dividend Amount	'	'	$0.35	'
Group Seven	'	'	'	'
Dividends Payable [Line Items]	'	'	'	'
Declaration Date	'	'	17-Jan-13	'
Date Paid (Payable)	'	'	15-Feb-13	'
Shareholder of Record Date	'	'	1-Feb-13	'
Dividend Amount	'	'	$0.35	'

Significant_Segment_Financial_

Significant Segment Financial Data (Detail) (USD $)	3 Months Ended		6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]	'	'	'	'	'
Revenues	$73.30	$66.40	$229.40	$184.60	'
Segment Profit (Loss)	1.1	-0.1	13.7	10.7	'
Capital Expenditures	19.9	22.6	29.1	37	'
Identifiable Segment Assets	900.6	874.2	900.6	874.2	920.6
Electricity	'	'	'	'	'
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]	'	'	'	'	'
Revenues	46.1	42.9	108	88.8	'
Segment Profit (Loss)	1.4	1.4	2.3	3.4	'
Capital Expenditures	5	3.4	10.1	10.4	'
Identifiable Segment Assets	391.6	405.7	391.6	405.7	502.3
Gas Segment	'	'	'	'	'
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]	'	'	'	'	'
Revenues	25.8	22.1	118.4	92.9	'
Segment Profit (Loss)	-0.7	-2.3	10.8	6	'
Capital Expenditures	13.3	17.6	16.3	24.5	'
Identifiable Segment Assets	490.6	456.8	490.6	456.8	402.8
All Other Segments	'	'	'	'	'
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]	'	'	'	'	'
Segment Profit (Loss)	0.2	0.6	0.2	0.7	'
Capital Expenditures	1.4	1.6	2.4	2.1	'
Identifiable Segment Assets	12.3	5.3	12.3	5.3	6.2
Unregulated Operation	'	'	'	'	'
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]	'	'	'	'	'
Revenues	1.4	1.4	3	2.9	'
Segment Profit (Loss)	0.2	0.2	0.4	0.6	'
Capital Expenditures	0.2	'	0.3	'	'
Identifiable Segment Assets	$6.10	$6.40	$6.10	$6.40	$9.30

Details_on_Long_Term_Debt_Deta

Details on Long Term Debt (Detail) (USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	$287.10	$287.30	$287.60
Less: Current Portion	2.5	2.5	0.6
Total Long-term Debt, Less Current Portion	284.6	284.8	287
6.33% Notes, Due May 1, 2022	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	20	20	20
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	15	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	15	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	20	20	20
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	15	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	15	15	15
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	19	19	19
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	12	12	12
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	14	14	14
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	10	10	10
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030	'	'	'
Debt Instrument [Line Items]	'	'	'
Long-Term Debt	15	15	15
Northern Utilities Inc | 6.95% Senior Notes, Due December 3, 2018	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	30	30	30
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	25	25	25
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	50	50	50
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	10	10	10
Unitil Realty Corp | 8.00% Senior Secured Notes, Due Through August 1, 2017	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Secured Notes	$2.10	$2.30	$2.60

Details_on_Long_Term_Debt_Pare

Details on Long Term Debt (Parenthetical) (Detail)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
6.33% Notes, Due May 1, 2022	'	'	'
Debt Instrument [Line Items]	'	'	'
Stated interest rate	6.33%	6.33%	6.33%
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%
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%
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%
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%
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%
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%
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%
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%
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%
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%
6.95% Senior Notes, Due December 3, 2018 | Northern Utilities Inc	'	'	'
Debt Instrument [Line Items]	'	'	'
Stated interest rate	6.95%	6.95%	6.95%
5.29% Senior Notes, Due March 2, 2020 | Northern Utilities Inc	'	'	'
Debt Instrument [Line Items]	'	'	'
Stated interest rate	5.29%	5.29%	5.29%
7.72% Senior Notes, Due December 3, 2038 | Northern Utilities Inc	'	'	'
Debt Instrument [Line Items]	'	'	'
Stated interest rate	7.72%	7.72%	7.72%
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%
8.00% Senior Secured Notes, Due Through August 1, 2017 | Unitil Realty Corp	'	'	'
Debt Instrument [Line Items]	'	'	'
Stated interest rate	8.00%	8.00%	8.00%

Estimated_Fair_Value_of_Long_T

Estimated Fair Value of Long Term Debt (Detail) (Fair Value, Inputs, Level 2, USD $)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Fair Value, Inputs, Level 2	'	'	'
Debt Instrument [Line Items]	'	'	'
Estimated Fair Value of Long-Term Debt	$338.50	$327.30	$333.20

Debt_and_Financing_Arrangement2

Debt and Financing Arrangements - Additional Information (Detail) (USD $)

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

Apr. 30, 2014

Oct. 04, 2013

Jun. 30, 2014

Dec. 31, 2013

Oct. 04, 2013

Jun. 30, 2013

Oct. 04, 2013

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

Jun. 30, 2014

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Capital Lease Obligations

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

Revolving Credit Facility

8.00% Senior Secured Notes, Due Through August 1, 2017

8.00% Senior Secured Notes, Due Through August 1, 2017

8.00% Senior Secured Notes, Due Through August 1, 2017

8.00% Senior Secured Notes, Due Through August 1, 2017

7.15% Senior Notes, Due December 15, 2018

7.15% Senior Notes, Due December 15, 2018

7.15% Senior Notes, Due December 15, 2018

7.15% Senior Notes, Due December 15, 2018

London Interbank Offered Rate

Unitil Realty Corp

Unitil Realty Corp

Unitil Realty Corp

Unitil Realty Corp

Granite State Gas Transmission Inc

Granite State Gas Transmission Inc

Granite State Gas Transmission Inc

Granite State Gas Transmission Inc

Debt Outstanding, Principal Amount

Debt Outstanding, Principal Amount

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving credit facility expiration date

'

'

'

'

'

'

'

4-Oct-18

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility, maximum borrowing capacity

'

'

'

'

'

'

$15

'

$120

$120

$120

$60

'

'

'

'

'

'

'

'

'

Sublimit for the issuance of standby letters of credit

'

'

'

'

'

'

'

'

'

'

25

'

'

'

'

'

'

'

'

'

'

Credit facility, daily fluctuating rate of interest

'

'

'

'

'

'

'

'

'

'

'

'

1.38%

'

'

'

'

'

'

'

'

Credit Facility by an aggregate additional amount

'

'

'

'

'

'

'

'

'

'

30

'

'

'

'

'

'

'

'

'

'

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 Unitilbs Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At June 30, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from capital lease obligation

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural gas storage inventory

'

'

'

7.8

12.5

7.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts Payable

20.5

38.1

21.7

0.2

2.7

0.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Guarantee outstanding

28.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior Secured Notes

'

'

'

'

'

'

'

'

'

'

'

'

'

2.1

2.3

2.6

2.1

'

'

'

'

Senior Notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$10

$10

$10

$10

Borrowing_Limits_Amounts_Outst

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) (Revolving Credit Facility, USD $)	Jun. 30, 2014	Dec. 31, 2013	Oct. 04, 2013	Jun. 30, 2013
In Millions, unless otherwise specified
Revolving Credit Facility	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Revolving credit facility	$120	$120	$120	$60
Outstanding revolving credit facility	35	60.2	'	24.5
Available revolving credit facility	$85	$59.80	'	$35.50

Common_Stock_and_Preferred_Sto2

Common Stock and Preferred Stock - Additional Information (Detail) (USD $)

6 Months Ended

3 Months Ended

6 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Maximum

Maximum

Maximum

Maximum

Dividend and Distribution Reinvestment and Share Purchase Plan

Restricted Stock

Restricted Stock

Restricted Stock

Restricted Stock Units (RSUs)

Unitil Energy Systems Inc

Unitil Energy Systems Inc

Unitil Energy Systems Inc

Maximum

Series 6

Series 6

Series 6

Class of Stock [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares outstanding

13,895,777

13,822,318

13,841,400

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, share issued

'

'

'

'

'

'

'

18,877

'

'

'

'

'

'

'

Common stock price per share

'

'

'

'

'

'

'

$32.07

'

'

'

'

'

'

'

Proceed from issuance of common stock

$600,000

$600,000

'

'

'

'

'

$605,000

'

'

'

'

'

'

'

Restricted stock available for awards

'

'

'

'

'

'

'

'

'

'

677,500

'

'

'

'

Restricted stock that may be awarded in any one calendar year to any one participant

'

'

'

'

'

'

'

'

'

'

20,000

'

'

'

'

Restricted stock vesting period

'

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

Restricted stock vesting percentage annually

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

Restricted stock issue date

'

'

'

'

'

'

'

'

31-Jan-14

'

'

'

'

'

'

Restricted stock issued

35,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted stock grant date market value

1,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted stock non-vested

'

'

'

'

'

'

'

'

67,334

53,480

'

'

'

'

'

Restricted stock weighted average grant date fair value

'

'

'

'

'

'

'

'

$28.51

$25.99

'

'

'

'

'

Share based compensation expense

1,200,000

500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized share based compensation

'

'

'

'

'

'

'

'

1,000,000

'

'

'

'

'

'

Share compensation recognition period

'

'

'

'

'

'

'

'

'2 years 9 months 18 days

'

'

'

'

'

'

Forfeitures or cancellations under the stock plan

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

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 cash portion of fully vested RSUs

200,000

'

200,000

'

100,000

'

100,000

'

'

'

'

'

'

'

'

Weighted-Average Stock Price

'

'

'

'

'

'

'

'

'

'

'

$27.42

'

'

'

Restricted stock units outstanding

'

'

'

'

'

'

'

'

'

'

'

3,977

'

'

'

Preferred stock, outstanding

'

'

'

'

'

'

'

'

'

'

'

'

2,250

2,250

2,250

Preferred Stock

200,000

200,000

200,000

'

'

'

'

'

'

'

'

'

200,000

200,000

200,000

Dividend rate

'

'

'

'

'

'

'

'

'

'

'

'

6.00%

6.00%

6.00%

Dividend declared

'

'

'

$100,000

$100,000

$100,000

$100,000

'

'

'

'

'

'

'

'

Restricted_Stock_Units_Issued_

Restricted Stock Units Issued (Detail) (Restricted Stock, USD $)	6 Months Ended
	Jun. 30, 2014
Restricted Stock	'
Restricted Stock Units	'
Beginning Restricted Stock Units	14,903
Restricted Stock Units Granted	'
Dividend Equivalents Earned	322
Restricted Stock Units Settled	'
Ending Restricted Stock Units	15,225
Weighted-Average Stock Price	'
Beginning Restricted Stock Units	$28.90
Restricted Stock Units Granted	'
Dividend Equivalents Earned	$32.08
Restricted Stock Units Settled	'
Ending Restricted Stock Units	$28.97

Regulatory_Matters_Additional_

Regulatory Matters - Additional Information (Detail) (USD $)

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

0 Months Ended

1 Months Ended

6 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

6 Months Ended

Feb. 28, 2014

Dec. 27, 2013

Apr. 21, 2013

Jun. 30, 2014

Dec. 27, 2013

Apr. 21, 2013

Jun. 30, 2014

Apr. 21, 2013

Dec. 27, 2013

Jun. 30, 2014

Apr. 30, 2014

Jun. 30, 2014

Apr. 25, 2013

Apr. 25, 2013

Apr. 25, 2013

30-May-14

Jul. 31, 2013

Jun. 30, 2014

30-May-14

Jul. 31, 2013

Jun. 27, 2014

Jun. 30, 2014

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Northern Utilities Inc

Unitil Energy Systems Inc

Unitil Energy Systems Inc

Unitil Energy Systems Inc

Unitil Energy Systems Inc

Unitil Energy Systems Inc

Fitchburg Gas and Electric Light Company

Fitchburg Gas and Electric Light Company

Fitchburg Gas and Electric Light Company

Fitchburg Gas and Electric Light Company

Fitchburg Gas and Electric Light Company

Granite State Gas Transmission Inc

Granite State Gas Transmission Inc

New Hampshire

New Hampshire

New Hampshire

Maine

Maine

Storm Costs

Storm Costs

Storm Costs

Storm Costs

Gas Transportation and Storage

Gas Transportation and Storage

Natural Gas Distribution

Regulatory Matters [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in annual revenue

'

'

$1,400,000

$1,000,000

'

$1,400,000

'

$4,600,000

$3,800,000

'

'

'

'

'

'

$5,600,000

$6,700,000

'

'

'

'

'

Amendment effective date

'

'

'

'May 1, 2014

'

'

'May 1, 2015

'

'

'January 1, 2014

'

'May 1, 2014

'

'

'

'

'

'June 1, 2014

'

'

'

'August 1, 2014

TIRA initial term

'

'

'

'Four years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of eligibility for earnings

'

10.00%

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of earnings shared equally

'

11.00%

11.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Service quality plan penalties imposed

'

'

'

'

500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

First annual TIRA Adjustment

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

First annual TIRA Adjustment, effective date

'

'

'

'May 1, 2014

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percent of increase in annual revenue

'

'

'

'

'

9.50%

'

'

'

'

'

'

'

'

'

9.50%

'

'

'

'

'

'

Adjustment to recover the increased spending for vegetation management program and reliability enhancement program and a proposed storm resiliency program

'

'

'

'

'

'

'

'

'

'

1,500,000

'

'

'

'

'

'

'

'

'

'

'

Settlement agreement date

'

'

'

'

'

'

'

'

'

'

1-May-16

'

'

'

'

'

'

'

'

'

'

'

Annual revenue increase in rate adjustments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

'

Percentage of approved return on equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.70%

'

'

'

'

'

Percentage of approved common equity ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

48.00%

'

'

'

'

'

Cost recovery period, years

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'5 years

'

'3 years

'3 years

'

'

Deferred emergency storm repair costs incurred

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

'

'

Annual funding amount approved

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

500,000

'

'

'

'

'

Recovery amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,300,000

'

900,000

'

'

'

'

'

Storm expenditures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$5,000,000

'

'

'

Interest rate allowed by regulators on the unrecovered amount of storm costs which have been approved for recovery through rate adjustments

'

'

'

'

'

'

'

'

'

'

'

'

4.52%

'

'

'

'

'

'

'

'

'

Environmental_Matters_Addition

Environmental Matters - Additional Information (Detail) (USD $)	6 Months Ended
In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Site Contingency [Line Items]	'	'	'
Environmental obligations, Current	$6.40	$1	$1
Environmental obligations, Non-current	2	13.8	13.8
Northern Utilities Inc	'	'	'
Site Contingency [Line Items]	'	'	'
Environmental obligations, Current	1.2	1	1
Environmental obligations, Non-current	2	1.8	1.8
Fitchburg Gas and Electric Light Company | Environmental Clean Up Costs	'	'	'
Site Contingency [Line Items]	'	'	'
Environmental obligations, Current	5.2	0	0
Environmental obligations, Non-current	0	12	12
Environmental obligations	12	'	'
Environmental obligations, spent during the year	0.3	'	'
Fitchburg Gas and Electric Light Company | Environmental Restoration Costs	'	'	'
Site Contingency [Line Items]	'	'	'
Amortization period for environmental costs	'7 years	'	'
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	'	'
Revised Estimate | Fitchburg Gas and Electric Light Company | Environmental Clean Up Costs	'	'	'
Site Contingency [Line Items]	'	'	'
Environmental obligations	$5.50	'	'

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified		Federal	Federal and State	State and Local Jurisdiction	Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]	'	'	'	'	'
Net Operating Loss carryforward assets	'	'	$17.40	'	$6.60
NOL carryforward assets expiration date	'	'	'	'2019	'2029
Alternative Minimum tax credit carryforwards	$1.50	'	'	'	'
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, 2010; December 31, 2011; and December 31, 2012.	'	'	'

Key_Weighted_Average_Assumptio

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) (Benefit Plan Costs)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Benefit Plan Costs	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'
Discount Rate	4.80%	4.00%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	8.00%	8.50%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	8.00%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	'2018	'2017

Components_of_Retirement_Plan_

Components of Retirement Plan Costs (Detail) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Plans	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]	'	'	'	'
Service Cost	$751	$894	$1,502	$1,787
Interest Cost	1,273	1,141	2,546	2,283
Expected Return on Plan Assets	-1,561	-1,489	-3,122	-2,978
Prior Service Cost Amortization	53	52	106	104
Actuarial Loss Amortization	712	1,056	1,424	2,115
Sub-total	1,228	1,654	2,456	3,311
Amounts Capitalized and Deferred	-501	-768	-844	-1,384
Net Periodic Benefit Cost Recognized	727	886	1,612	1,927
Other Postretirement Benefit Plans, Defined Benefit	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]	'	'	'	'
Service Cost	497	631	994	1,262
Interest Cost	672	612	1,344	1,224
Expected Return on Plan Assets	-230	-180	-460	-361
Prior Service Cost Amortization	420	425	840	850
Actuarial Loss Amortization	14	196	28	393
Sub-total	1,373	1,684	2,746	3,368
Amounts Capitalized and Deferred	-593	-678	-1,065	-1,447
Net Periodic Benefit Cost Recognized	780	1,006	1,681	1,921
Supplemental Employee Retirement Plans, Defined Benefit	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]	'	'	'	'
Service Cost	14	18	28	36
Interest Cost	68	60	136	121
Prior Service Cost Amortization	3	3	6	6
Actuarial Loss Amortization	25	46	50	92
Sub-total	110	127	220	255
Net Periodic Benefit Cost Recognized	$110	$127	$220	$255

Retirement_Benefit_Obligations2

Retirement Benefit Obligations - Additional Information (Detail) (USD $)	6 Months Ended
	Jun. 30, 2014
Pension Plans	'
Defined Benefit Plan Disclosure [Line Items]	'
Contributions to benefit plan	$1,900,000
Other Postretirement Benefit Plans, Defined Benefit	'
Defined Benefit Plan Disclosure [Line Items]	'
Contributions to benefit plan	0
Supplemental Employee Retirement Plans, Defined Benefit	'
Defined Benefit Plan Disclosure [Line Items]	'
Contributions to benefit plan	26,000
Expected additional contribution to SERP plan	$27,000