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Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2014	Jul. 18, 2014
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2014
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 Earnings - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating Revenues
Gas	$ 25.8	$ 22.1	$ 118.4	$ 92.9
Electric	46.1	42.9	108.0	88.8
Other	1.4	1.4	3.0	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	49.0
Cost of Electric Sales	27.2	25.0	69.9	52.5
Operation and Maintenance	15.3	15.1	32.4	30.3
Depreciation and Amortization	10.2	9.5	20.4	19.0
Taxes Other Than Income Taxes	4.0	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	17.0
Income Tax Expense (Benefit)	0.6	(0.1)	8.1	6.3
Net Income (Loss)	$ 1.1	$ (0.1)	$ 13.7	$ 10.7
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	$ 0.345	$ 0.345	$ 0.690	$ 1.035

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Current Assets:
Cash and Cash Equivalents	$ 12.0	$ 9.4	$ 7.1
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	5.0	5.4
Prepayments and Other	6.9	4.8	5.6
Total Current Assets	113.9	140.0	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	105.0	115.0	143.2
TOTAL ASSETS	900.6	920.6	874.2
Current Liabilities:
Accounts Payable	20.5	38.1	21.7
Short-Term Debt	35.0	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	1.0	1.0
Interest Payable	3.1	3.1	3.1
Regulatory Liabilities	13.0	9.7	13.3
Other Current Liabilities	9.8	9.0	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	2.0	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	287.0
Common Stock Equity:
Common Equity (Outstanding 13,895,777, 13,822,318 and 13,841,400 Shares)	233.6	232.1	231.0
Retained Earnings	37.0	32.9	26.8
Total Common Stock Equity	270.6	265.0	257.8
Preferred Stock	0.2	0.2	0.2
Total Capitalization	555.4	550.0	545.0
TOTAL LIABILITIES AND CAPITALIZATION	$ 900.6	$ 920.6	$ 874.2

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

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Operating Activities:
Net Income	$ 13.7	$ 10.7
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	20.4	19.0
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)	(11.0)
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)	(37.0)
Cash (Used in) Investing Activities	(29.1)	(37.0)
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)	(36.0)
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	12.0	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	$ 0.4	$ 1.8

Consolidated Statements of Changes in Common Stock Equity - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2012	$ 260.4	$ 230.0	$ 30.4
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	231.0	26.8
Beginning Balance at Dec. 31, 2013	265.0	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	$ 270.6	$ 233.6	$ 37.0

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

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

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

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		13.0

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	$	7.0	$	9.8
Fitchburg		0.7		0.6		1.0

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	$	13.0	$	13.3	$	9.7

Total Regulatory Liabilities	$	13.0	$	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, 2014		June 30, 2013		December 31, 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 Ended June 30,				Six Months Ended 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	$	7.0	$	9.8
Renewable Energy Portfolio Standards		4.0		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

6 Months Ended

Jun. 30, 2014

Dividends Declared Per Share

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date		Dividend Amount
07/22/14	08/29/14		08/15/14	$ 0.345
04/22/14	05/29/14		05/15/14	$ 0.345
01/16/14	02/28/14		02/14/14	$ 0.345

09/18/13	11/15/13		11/01/13	$ 0.345
06/05/13	08/15/13		08/01/13	$ 0.345
03/28/13	05/15/13		05/01/13	$ 0.345
01/17/13	02/15/13		02/01/13	$ 0.345

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		5.0		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	$	108.0	$	118.4		$	—	$	3.0	$	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			0.7		0.6		10.7
Capital Expenditures		10.4		24.5			2.1		—		37.0
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

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
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-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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+ Details

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	$	20.0	$	20.0	$	20.0

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

Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0

Northern Utilities, Inc.:
Senior Notes:
6.95% Senior Notes, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0

Granite State Gas Transmission, Inc.:
Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0		10.0

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		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	$	287.0	$	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	$	35.0	$	24.5	$	60.2
Available	$	85.0	$	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 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	$	28.90
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.

- Definition

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

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Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

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

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

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

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		4.80	%		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

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 Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2014

Nature of Operations

Basis of Presentation

Fair Value


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

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

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

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

Income Taxes

Cash and Cash Equivalents

Allowance for Doubtful Accounts

($ millions)

June 30,

December 31,

2014

2013

Allowance for Doubtful Accounts

1.7

2.4

1.6

Accrued Revenue


	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		13.0

Total Accrued Revenue	$	33.4	$	38.3	$	56.6

Exchange Gas Receivable


	June 30,				December 31,
Exchange Gas Receivable ($ millions)	2014		2013		2013
Northern Utilities	$	7.6	$	7.0	$	9.8
Fitchburg		0.7		0.6		1.0

Total Exchange Gas Receivable	$	8.3	$	7.6	$	10.8

Gas Inventory


	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

Regulatory Accounting


	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	$	13.0	$	13.3	$	9.7

Total Regulatory Liabilities	$	13.0	$	13.3	$	9.7

Derivatives


Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
		Fair Value
Description	Balance Sheet Location	June 30, 2014		June 30, 2013		December 31, 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 Ended June 30,				Six Months Ended 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


	June 30,				December 31,
Energy Supply Obligations ($ millions)	2014		2013		2013
Current:
Exchange Gas Obligation	$	7.6	$	7.0	$	9.8
Renewable Energy Portfolio Standards		4.0		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

Recently Issued Pronouncements

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

Reclassifications

Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2014

Allowance for Doubtful Accounts Included in Accounts Receivable Net

($ millions)

June 30,

December 31,

2014

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		13.0

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	$	7.0	$	9.8
Fitchburg		0.7		0.6		1.0

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	$	13.0	$	13.3	$	9.7

Total Regulatory Liabilities	$	13.0	$	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, 2014		June 30, 2013		December 31, 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 Ended June 30,				Six Months Ended 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	$	7.0	$	9.8
Renewable Energy Portfolio Standards		4.0		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 (Tables)

6 Months Ended

Jun. 30, 2014

Schedule of Dividends Declared


Declaration Date	Date Paid (Payable)	Shareholder of Record Date		Dividend Amount
07/22/14	08/29/14		08/15/14	$ 0.345
04/22/14	05/29/14		05/15/14	$ 0.345
01/16/14	02/28/14		02/14/14	$ 0.345

09/18/13	11/15/13		11/01/13	$ 0.345
06/05/13	08/15/13		08/01/13	$ 0.345
03/28/13	05/15/13		05/01/13	$ 0.345
01/17/13	02/15/13		02/01/13	$ 0.345

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		5.0		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	$	108.0	$	118.4		$	—	$	3.0	$	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			0.7		0.6		10.7
Capital Expenditures		10.4		24.5			2.1		—		37.0
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 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	$	20.0	$	20.0	$	20.0

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

Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0

Northern Utilities, Inc.:
Senior Notes:
6.95% Senior Notes, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0

Granite State Gas Transmission, Inc.:
Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0		10.0

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		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	$	287.0	$	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	$	35.0	$	24.5	$	60.2
Available	$	85.0	$	35.5	$	59.8

- Definition

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

+ References

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

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

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

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

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=34725769&loc=d3e28878-108400

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

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

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

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

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

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	$	28.90
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 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		4.80	%		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 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 Accounting Policies - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2014 USD ($) Bcf mi Entity Segment	Dec. 31, 2013 USD ($) Bcf	Jun. 30, 2013 USD ($) Bcf
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi	86
Cost of removal obligation	$ 60.8	$ 57.3	$ 54.7
Construction Work in Progress	$ 34.3	$ 24.6	$ 40.4
Number of Natural Gas Storage Outstanding \| Bcf	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	$ 5.0
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	$ 0.0	$ 0.7
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Entity	3
Other Subsidiaries
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Segment	3

Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 1.7	$ 1.6	$ 2.4

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 33.4	$ 56.6	$ 38.3
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	6.1	13.0	6.7
Regulatory Asset
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 27.3	$ 43.6	$ 31.6

Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Receivables [Line Items]
Total Exchange Gas Receivable	$ 8.3	$ 10.8	$ 7.6
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	7.6	9.8	7.0
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.7	$ 1.0	$ 0.6

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.8	$ 1.2	$ 0.8
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	$ 0.2	$ 0.1	$ 0.1

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

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

Regulatory Assets [Line Items]

Regulatory Assets

$ 115.4

$ 143.7

$ 157.5

Less: Current Portion of Regulatory Assets

^[1]

27.3

43.6

31.6

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

$ 4.7

$ 9.3

$ 14.5

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

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.0	$ 9.7	$ 13.3
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.0	$ 9.7	$ 13.3

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Derivative Assets
Derivative Assets		$ 0.2
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	$ 0.1		$ 0.1

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

3 Months Ended

6 Months Ended

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

$ 0.4

$ 0.9

$ (0.5)

$ 0.6

Gas Purchase Costs

Regulatory Assets [Line Items]

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

^[1]

$ (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 (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 12.3	$ 14.4	$ 9.8
Total Energy Supply Obligations	14.5	16.9	12.7
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations	7.6	9.8	7.0
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations	4.0	3.7	1.9
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations	0.7	0.9	0.9
Energy Supply Obligations	$ 2.2	$ 2.5	$ 2.9

Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended		6 Months Ended
Dividends Declared Per Share (Detail) - $ / shares	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Dividends Payable [Line Items]
Dividend Amount	$ 0.345	$ 0.345	$ 0.690	$ 1.035
Group One
Dividends Payable [Line Items]
Declaration Date			Jul. 22, 2014
Date Paid (Payable)			Aug. 29, 2014
Shareholder of Record Date			Aug. 15, 2014
Dividend Amount			$ 0.345
Group Two
Dividends Payable [Line Items]
Declaration Date			Apr. 22, 2014
Date Paid (Payable)			May 29, 2014
Shareholder of Record Date			May 15, 2014
Dividend Amount			$ 0.345
Group Three
Dividends Payable [Line Items]
Declaration Date			Jan. 16, 2014
Date Paid (Payable)			Feb. 28, 2014
Shareholder of Record Date			Feb. 14, 2014
Dividend Amount			$ 0.345
Group Four
Dividends Payable [Line Items]
Declaration Date			Sep. 18, 2013
Date Paid (Payable)			Nov. 15, 2013
Shareholder of Record Date			Nov. 01, 2013
Dividend Amount			$ 0.345
Group Five
Dividends Payable [Line Items]
Declaration Date			Jun. 05, 2013
Date Paid (Payable)			Aug. 15, 2013
Shareholder of Record Date			Aug. 01, 2013
Dividend Amount			$ 0.345
Group Six
Dividends Payable [Line Items]
Declaration Date			Mar. 28, 2013
Date Paid (Payable)			May 15, 2013
Shareholder of Record Date			May 01, 2013
Dividend Amount			$ 0.345
Group Seven
Dividends Payable [Line Items]
Declaration Date			Jan. 17, 2013
Date Paid (Payable)			Feb. 15, 2013
Shareholder of Record Date			Feb. 01, 2013
Dividend Amount			$ 0.345

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	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	$ 73.3	$ 66.4	$ 229.4	$ 184.6
Segment Profit (Loss)	1.1	(0.1)	13.7	10.7
Capital Expenditures	19.9	22.6	29.1	37.0
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	108.0	88.8
Segment Profit (Loss)	1.4	1.4	2.3	3.4
Capital Expenditures	5.0	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	6.0
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	3.0	2.9
Segment Profit (Loss)	0.2	0.2	0.4	0.6
Capital Expenditures	0.2		0.3
Identifiable Segment Assets	$ 6.1	$ 6.4	$ 6.1	$ 6.4	$ 9.3

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Debt Instrument [Line Items]
Long-Term Debt	$ 287.1	$ 287.3	$ 287.6
Less: Current Portion	2.5	2.5	0.6
Total Long-term Debt, Less Current Portion	284.6	284.8	287.0
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20.0	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company \| 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	19.0	19.0	19.0
Fitchburg Gas and Electric Light Company \| 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0	12.0
Fitchburg Gas and Electric Light Company \| 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0	14.0
Fitchburg Gas and Electric Light Company \| 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company \| 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Northern Utilities Inc \| 6.95% Senior Notes, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30.0	30.0	30.0
Northern Utilities Inc \| 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25.0	25.0	25.0
Northern Utilities Inc \| 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50.0	50.0	50.0
Granite State Gas Transmission Inc \| 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10.0	10.0	10.0
Unitil Realty Corp \| 8.00% Senior Secured Notes, Due Through August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 2.1	$ 2.3	$ 2.6

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 Term Debt (Detail) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 338.5	$ 327.3	$ 333.2

Debt and Financing Arrangements - Additional Information (Detail) - USD ($) $ in Millions		6 Months Ended
	Oct. 04, 2013	Jun. 30, 2014	Apr. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Line of Credit Facility [Line Items]
Proceeds from capital lease obligation		$ 5.0
Accounts Payable		20.5		$ 38.1	$ 21.7
Guarantee outstanding		28.5
Northern Utilities Inc
Line of Credit Facility [Line Items]
Natural gas storage inventory		7.8		12.5	7.2
Accounts Payable		0.2		2.7	0.1
Capital Lease Obligations
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity			$ 15.0
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date	Oct. 04, 2018
Line of credit facility, maximum borrowing capacity	$ 120.0	$ 120.0		120.0	60.0
Sublimit for the issuance of standby letters of credit	25.0
Credit Facility by an aggregate additional amount	$ 30.0
Percentage of capitalization		The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At June 30, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
Revolving Credit Facility \| London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	1.375%
8.00% Senior Secured Notes, Due Through August 1, 2017 \| Unitil Realty Corp
Line of Credit Facility [Line Items]
Senior Secured Notes		$ 2.1		2.3	2.6
8.00% Senior Secured Notes, Due Through August 1, 2017 \| Unitil Realty Corp \| Debt Outstanding, Principal Amount
Line of Credit Facility [Line Items]
Senior Secured Notes		2.1
7.15% Senior Notes, Due December 15, 2018 \| Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Senior Notes		10.0		$ 10.0	$ 10.0
7.15% Senior Notes, Due December 15, 2018 \| Granite State Gas Transmission Inc \| Debt Outstanding, Principal Amount
Line of Credit Facility [Line Items]
Senior Notes		$ 10.0

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - Revolving Credit Facility - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013	Oct. 04, 2013	Jun. 30, 2013
Debt Instrument [Line Items]
Revolving credit facility	$ 120.0	$ 120.0	$ 120.0	$ 60.0
Outstanding revolving credit facility	35.0	60.2		24.5
Available revolving credit facility	$ 85.0	$ 59.8		$ 35.5

- Definition

The carrying value as of the balance sheet date of the current and noncurrent portions of long-term obligations drawn from a line of credit, which is a bank's commitment to make loans up to a specific amount. Examples of items that might be included in the application of this element may consist of letters of credit, standby letters of credit, and revolving credit arrangements, under which borrowings can be made up to a maximum amount as of any point in time conditional on satisfaction of specified terms before, as of and after the date of drawdowns on the line. Includes short-term obligations that would normally be classified as current liabilities but for which (a) postbalance sheet date issuance of a long term obligation to refinance the short term obligation on a long term basis, or (b) the enterprise has entered into a financing agreement that clearly permits the enterprise to refinance the short-term obligation on a long term basis and the following conditions are met (1) the agreement does not expire within 1 year and is not cancelable by the lender except for violation of an objectively determinable provision, (2) no violation exists at the BS date, and (3) the lender has entered into the financing agreement is expected to be financially capable of honoring the agreement.

+ References + Details

Common Stock and Preferred Stock - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Class of Stock [Line Items]
Common stock, shares outstanding	13,895,777	13,822,318	13,895,777	13,822,318	13,841,400
Proceed from issuance of common stock			$ 600,000	$ 600,000
Restricted stock issued			35,500
Restricted stock grant date market value			$ 1,100,000
Share based compensation expense			$ 1,200,000	500,000
Percentage of fully-vested restricted stock units that Directors will receive in common shares when settled			70.00%
Percentage of fully-vested restricted stock units that Directors will receive in cash when settled			30.00%
Fair value of liabilities associated with cash portion of fully vested RSUs	$ 200,000		$ 200,000		$ 200,000
Preferred Stock	200,000	$ 200,000	200,000	200,000	$ 200,000
Maximum
Class of Stock [Line Items]
Fair value of liabilities associated with cash portion of fully vested RSUs		100,000		100,000
Dividend declared	$ 100,000	$ 100,000	$ 100,000	$ 100,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock, share issued	18,877		18,877
Common stock price per share			$ 32.07
Proceed from issuance of common stock			$ 605,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period			4 years
Restricted stock vesting percentage annually			25.00%
Restricted stock issue date			Jan. 31, 2014
Restricted stock non-vested	67,334	53,480	67,334	53,480
Restricted stock weighted average grant date fair value			$ 28.51	$ 25.99
Unrecognized share based compensation	$ 1,000,000		$ 1,000,000
Share compensation recognition period			2 years 9 months 18 days
Forfeitures or cancellations under the stock plan			0
Restricted Stock \| Maximum
Class of Stock [Line Items]
Restricted stock available for awards	677,500		677,500
Restricted stock that may be awarded in any one calendar year to any one participant	20,000		20,000
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Weighted-Average Stock Price	$ 27.42		$ 27.42
Restricted stock units outstanding	3,977		3,977
Unitil Energy Systems Inc \| Series 6
Class of Stock [Line Items]
Preferred stock, outstanding	2,250	2,250	2,250	2,250	2,250
Preferred Stock	$ 200,000	$ 200,000	$ 200,000	$ 200,000	$ 200,000
Dividend rate			6.00%	6.00%	6.00%

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

Regulatory Matters - Additional Information (Detail) - USD ($)								1 Months Ended	6 Months Ended
	Jun. 27, 2014	May 30, 2014	Apr. 30, 2014	Feb. 28, 2014	Dec. 27, 2013	Apr. 25, 2013	Apr. 21, 2013	Jul. 31, 2013	Jun. 30, 2014
Northern Utilities Inc
Regulatory Matters [Line Items]
Increase in annual revenue							$ 1,400,000		$ 1,000,000
Amendment effective date									May 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
Northern Utilities Inc \| New Hampshire
Regulatory Matters [Line Items]
Increase in annual revenue							$ 1,400,000
Amendment effective date									May 1, 2015
Percent of increase in annual revenue							9.50%
Northern Utilities Inc \| New Hampshire \| Natural Gas Distribution
Regulatory Matters [Line Items]
Increase in annual revenue							$ 4,600,000
Northern Utilities Inc \| Maine
Regulatory Matters [Line Items]
Increase in annual revenue					$ 3,800,000
Amendment effective date									January 1, 2014
Unitil Energy Systems Inc
Regulatory Matters [Line Items]
Amendment effective date									May 1, 2014
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			May 01, 2016
Interest rate allowed by regulators on the unrecovered amount of storm costs which have been approved for recovery through rate adjustments						4.52%
Unitil Energy Systems Inc \| Storm Costs
Regulatory Matters [Line Items]
Cost recovery period, years						5 years
Recovery amount						$ 2,300,000
Fitchburg Gas and Electric Light Company
Regulatory Matters [Line Items]
Increase in annual revenue		$ 5,600,000						$ 6,700,000
Amendment effective date									June 1, 2014
Percent of increase in annual revenue		9.50%
Percentage of approved return on equity								9.70%
Percentage of approved common equity ratio								48.00%
Cost recovery period, years								5 years
Annual funding amount approved								$ 500,000
Recovery amount								$ 900,000
Fitchburg Gas and Electric Light Company \| Storm Costs
Regulatory Matters [Line Items]
Cost recovery period, years		3 years						3 years
Deferred emergency storm repair costs incurred								$ 5,000,000
Storm expenditures		$ 5,000,000
Granite State Gas Transmission Inc \| Gas Transportation and Storage
Regulatory Matters [Line Items]
Amendment effective date									August 1, 2014
Annual revenue increase in rate adjustments	$ 600,000

Environmental Matters - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Site Contingency [Line Items]
Environmental obligations, Current	$ 6.4	$ 1.0	$ 1.0
Environmental obligations, Non-current	2.0	13.8	13.8
Northern Utilities Inc
Site Contingency [Line Items]
Environmental obligations, Current	1.2	1.0	1.0
Environmental obligations, Non-current	2.0	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	0.0
Environmental obligations, Non-current	0.0	$ 12.0	$ 12.0
Environmental obligations	12.0
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	$ 0.0
Revised Estimate \| Fitchburg Gas and Electric Light Company \| Environmental Clean Up Costs
Site Contingency [Line Items]
Environmental obligations	$ 5.5

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Alternative Minimum tax credit carryforwards		$ 1.5
Federal
Operating Loss Carryforwards [Line Items]
Tax examination description	The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2010; December 31, 2011; and December 31, 2012.
Federal and State
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets		$ 17.4
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date		2019
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets		$ 6.6
NOL carryforward assets expiration date		2029

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
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 Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	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 Obligations - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2014 USD ($)
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