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Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2013	Jul. 19, 2013
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013
Document Fiscal Year Focus	2013
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		13,822,660

Consolidated Statements of Earnings - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Operating Revenues
Gas	$ 22.1	$ 22.7	$ 92.9	$ 86.9
Electric	42.9	44.8	88.8	93.5
Other	1.4	1.3	2.9	2.6
Total Operating Revenues	66.4	68.8	184.6	183.0
Operating Expenses
Purchased Gas	8.1	9.4	47.8	45.9
Purchased Electricity	23.4	25.7	49.7	56.8
Operation and Maintenance	15.4	14.9	30.7	28.3
Conservation & Load Management	2.2	2.3	4.0	4.2
Depreciation and Amortization	9.2	8.7	18.6	17.0
Provisions (Benefit) for Taxes:
Local Property and Other	3.6	3.5	7.4	7.2
Federal and State Income	(0.1)		6.3	5.3
Total Operating Expenses	61.8	64.5	164.5	164.7
Operating Income	4.6	4.3	20.1	18.3
Non-Operating Expenses	0.1		0.2	0.1
Income Before Interest Expense	4.5	4.3	19.9	18.2
Interest Expense, Net	4.6	4.6	9.2	9.5
Net Income (Loss)	(0.1)	(0.3)	10.7	8.7
Less: Dividends on Preferred Stock		0.1		0.1
Earnings (Loss) Applicable to Common Shareholders	$ (0.1)	$ (0.4)	$ 10.7	$ 8.6
Weighted Average Common Shares Outstanding - Basic (000's)	13,768	12,331	13,758	11,624
Weighted Average Common Shares Outstanding - Diluted (000's)	13,768	12,331	13,760	11,627
Earnings Per Common Share (Basic and Diluted)	$ (0.01)	$ (0.03)	$ 0.78	$ 0.74
Dividends Declared Per Share of Common Stock	$ 0.345	$ 0.345	$ 1.035	$ 1.035

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Utility Plant:
Electric	$ 359.1	$ 356.9	$ 345.9
Gas	431.6	424.4	393.4
Common	31.5	30.9	30.6
Construction Work in Progress	40.4	21.0	24.9
Total Utility Plant	862.6	833.2	794.8
Less: Accumulated Depreciation	237.2	232.0	226.2
Net Utility Plant	625.4	601.2	568.6
Current Assets:
Cash	7.1	9.8	6.8
Accounts Receivable, net	40.8	47.7	33.2
Accrued Revenue	38.3	63.4	41.5
Exchange Gas Receivable	7.6	9.4	8.5
Gas Inventory	0.8	1.1	0.6
Materials and Supplies	5.4	4.1	4.1
Prepayments and Other	5.6	4.2	6.0
Total Current Assets	105.6	139.7	100.7
Noncurrent Assets:
Regulatory Assets	125.9	134.6	135.3
Other Noncurrent Assets	17.3	16.8	20.1
Total Noncurrent Assets	143.2	151.4	155.4
TOTAL ASSETS	874.2	892.3	824.7
Capitalization:
Common Stock Equity	257.8	260.4	254.7
Preferred Stock	0.2	0.2	2.0
Long-Term Debt, Less Current Portion	287.0	287.3	287.6
Total Capitalization	545.0	547.9	544.3
Current Liabilities:
Long-Term Debt, Current Portion	0.6	0.5	0.5
Accounts Payable	21.7	32.7	17.4
Short-Term Debt	24.5	49.4	5.0
Energy Supply Contract Obligations	9.8	13.8	17.2
Current Deferred Income Taxes	3.1	13.4	3.7
Dividends Declared and Payable	4.8		4.8
Interest Payable	3.1	3.1	3.0
Regulatory Liabilities	13.3	6.8	8.0
Other Current Liabilities	9.7	11.4	10.8
Total Current Liabilities	90.6	131.1	70.4
Noncurrent Liabilities:
Energy Supply Contract Obligations	2.9	3.3	3.8
Noncurrent Deferred Income Taxes	54.4	38.7	48.1
Cost of Removal Obligations	54.7	51.4	48.6
Retirement Benefit Obligations	110.6	103.7	91.1
Environmental Obligations	13.8	13.8	14.5
Other Noncurrent Liabilities	2.2	2.4	3.9
Total Noncurrent Liabilities	238.6	213.3	210.0
TOTAL CAPITALIZATION AND LIABILITIES	$ 874.2	$ 892.3	$ 824.7

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Operating Activities:
Net Income	$ 10.7	$ 8.7
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	18.6	17.0
Deferred Tax Provision	5.8	5.3
Changes in Working Capital Items:
Accounts Receivable	6.9	11.9
Accrued Revenue	25.1	21.2
Regulatory Liabilities	6.5	(3.2)
Exchange Gas Receivable	1.8	5.0
Accounts Payable	(11.0)	(9.9)
Other Changes in Working Capital Items	(6.5)	(6.1)
Deferred Regulatory and Other Charges	7.6	4.1
Other, net	4.8	(1.1)
Cash Provided by Operating Activities	70.3	52.9
Investing Activities:
Property, Plant and Equipment Additions	(37.0)	(23.9)
Cash (Used in) Investing Activities	(37.0)	(23.9)
Financing Activities:
Repayment of Short-Term Debt	(24.9)	(82.9)
Repayment of Long-Term Debt	(0.2)	(0.2)
Net Decrease in Exchange Gas Financing	(1.6)	(4.5)
Dividends Paid	(9.5)	(7.6)
Proceeds from Issuance of Common Stock, net	0.6	66.0
Other, net	(0.4)	(0.5)
Cash (Used in) Financing Activities	(36.0)	(29.7)
Net Decrease in Cash	(2.7)	(0.7)
Cash at Beginning of Period	9.8	7.5
Cash at End of Period	7.1	6.8
Supplemental Cash Flow Information:
Interest Paid	10.4	10.8
Income Taxes Paid	0.8	0.6
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 1.8	$ 1.3

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2013

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 of operations are expected to reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions between years may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions in both the winter and summer seasons.

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 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. The results of operations for the three and six months ended June 30, 2013 are not necessarily indicative of results to be expected for the year ending December 31, 2013. 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, 2012, as filed with the Securities and Exchange Commission (SEC) on January 30, 2013, for a description of the Company’s Basis of Presentation.

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 Financial Accounting Standards Board (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)	2013		2012		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	19.3	$	30.4	$	41.0
Deferred Restructuring Costs		14.5		21.3		20.1
Retirement Benefit Obligations		62.5		55.1		62.5
Income Taxes		9.5		10.8		10.2
Environmental Obligations		16.7		16.9		16.8
Deferred Storm Charges		28.1		26.2		27.8
Other		6.9		9.8		8.1

Total Regulatory Assets	$	157.5	$	170.5	$	186.5
Less: Current Portion of Regulatory Assets⁽¹⁾		31.6		35.2		51.9

Regulatory Assets – noncurrent	$	125.9	$	135.3	$	134.6

⁽¹⁾	Reflects amounts included in Accrued Revenue, discussed below, on the Company’s unaudited Consolidated Balance Sheets.


	June 30,				December 31,
Regulatory Liabilities consist of the following (millions)	2013		2012		2012
Regulatory Tracker Mechanisms	$	13.3	$	8.0	$	6.8

Total Regulatory Liabilities	$	13.3	$	8.0	$	6.8

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.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. The above table shows the amounts recorded in Regulatory Liabilities subsequent to these reclassifications.

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, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Accrued Revenue ($millions)	2013		2012		2012
Regulatory Assets – Current	$	31.6	$	35.2	$	51.9
Unbilled Revenues		6.7		6.3		11.5

Total Accrued Revenue	$	38.3	$	41.5	$	63.4

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, 2013, June 30, 2012 and December 31, 2012, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $54.7 million, $48.6 million, and $51.4 million, respectively. Prior to December 31, 2012, the cost of removal amounts had been recorded in Accumulated Depreciation on the Consolidated Balance Sheets.

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, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Gas Inventory ($millions)	2013		2012		2012
Natural Gas	$	0.4	$	0.1	$	0.6
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.8	$	0.6	$	1.1

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. Prior to March 31, 2013, the exchange gas amounts had been recorded in Gas Inventory on the Company’s Consolidated Balance Sheets. 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, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Exchange Gas Receivable ($millions)	2013		2012		2012
Northern Utilities	$	7.0	$	8.0	$	8.7
Fitchburg		0.6		0.5		0.7

Total Exchange Gas Receivable	$	7.6	$	8.5	$	9.4

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

Gas Inventory Obligation – 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. 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.

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).

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.


	June 30,				December 31,
Energy Supply Obligations ($millions)	2013		2012		2012
Current:
Exchange Gas Obligation	$	7.0	$	8.0	$	8.7
Power Supply Contract Divestitures		0.9		4.7		0.9
Renewable Energy Portfolio Standards		1.9		4.5		4.2

Total Energy Supply Obligations – Current	$	9.8	$	17.2	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.9	$	3.8	$	3.3

Total Energy Supply Obligations	$	12.7	$	21.0	$	17.1

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.

Derivatives – The Company has a regulatory approved hedging program for Northern Utilities designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases natural gas options and futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to the associated delivery month. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. 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 Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of June 30, 2013, June 30, 2012 and December 31, 2012, the Company had 1.8 billion, 1.8 billion and 1.9 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. As discussed above, the change in fair value related to these derivatives is recorded initially as a regulatory asset or liability then reclassified into Purchased Gas in accordance with the recovery mechanism. The tables below include disclosure of the derivative assets and liabilities and the reclassifications from their corresponding regulatory liabilities and assets, respectively into Purchased Gas. 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 Other Current Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

Liability Derivatives ($ millions)


Fair Value Amount of Derivative Liabilities (millions) Offset in Regulatory Assets, as of:
		Fair Value
Description	Balance Sheet Location	June 30, 2013		June 30, 2012		December 31, 2012
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	0.3	$	1.5	$	0.7

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.1		—		—

Total Derivative Liabilities		$	0.4	$	1.5	$	0.7


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.9	$	0.1	$	0.6	$	1.4
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽¹⁾:
Purchased Gas	$	—	$	0.6	$	0.9	$	2.2

⁽¹⁾	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

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. 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, 2013, June 30, 2012 and December 31, 2012, which are included in Accounts Receivable, net on the accompanying unaudited Consolidated Balance Sheets, were as follows:


	June 30,				December 31,
	2013		2012		2012
Allowance for Doubtful Accounts	$	2.4	$	2.9	$	1.9

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 Current and Noncurrent Deferred Income Taxes on the Company’s Consolidated Balance Sheets based on the nature of the underlying timing item. Prior to December 31, 2012, deferred income taxes were reflected as a single amount on the Consolidated Balance Sheets.

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 Consolidated Financial Statements.

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. Most significant has been the reclassification of certain regulatory tracker mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities, the reclassification of cost of removal costs associated with asset retirements from Accumulated Depreciation to Cost of Removal Obligations, the reclassification of exchange gas amounts from Gas Inventory to Exchange Gas Receivable and the segregation of Deferred Income Taxes to current and noncurrent amounts on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting, Utility Plant, Exchange Gas Receivable and Income Taxes, respectively.

Recently Issued Pronouncements – There are no recently issued pronouncements applicable to the Company that have not already been adopted.

Dividends Declared Per Share

6 Months Ended

Jun. 30, 2013

Dividends Declared Per Share

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration

Date

Date Paid

(Payable)

Shareholder of

Record Date

Dividend

Amount

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

09/19/12

11/15/12

11/01/12

0.345

06/06/12

08/15/12

08/01/12

0.345

03/22/12

05/15/12

05/01/12

0.345

01/17/12

02/15/12

02/01/12

0.345

Common Stock and Preferred Stock

6 Months Ended

Jun. 30, 2013

Common Stock and Preferred Stock

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

Common Stock

The Company’s common stock trades under the symbol “UTL”.

The Company had 13,822,318, 13,758,805 and 13,780,601 of common shares outstanding at June 30, 2013, June 30, 2012 and December 31, 2012, respectively.

Unitil Corporation Common Stock Offering – On May 16, 2012, the Company issued and sold 2,760,000 shares of its common stock at a price of $25.25 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering were approximately $65.7 million and were used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan – During the first six months of 2013, the Company sold 20,477 shares of its common stock, at an average price of $28.27 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) Plan resulting in net proceeds of approximately $579,000. 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 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.

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. 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 February 4, 2013, 21,240 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of $564,134. There were 53,480 and 53,942 non-vested shares under the Stock Plan as of June 30, 2013 and 2012, respectively. The weighted average grant date fair value of these shares was $25.99 and $24.67, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $0.5 million and $1.0 million for the six months ended June 30, 2013 and 2012, respectively. At June 30, 2013, there was approximately $0.9 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.7 years. There were no forfeitures or cancellations under the Stock Plan during the six months ended June 30, 2013.

There were no Restricted Stock Units issued under the Stock Plan during the six months ended June 30, 2013. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of June 30, 2013, June 30, 2012 and December 31, 2012 is less than $0.1 million, zero and less than $0.1 million, respectively, representing the fair value of liabilities associated with the portion of fully vested Restricted Stock Units that will be settled in cash.

Preferred Stock

Details on preferred stock at June 30, 2013, June 30, 2012 and December 31, 2012 are shown below:


	June 30,				December 31,
	2013		2012		2012
Preferred Stock
Unitil Energy Preferred Stock, Non-Redeemable, Non-Cumulative:
6.00% Series, $100 Par Value,	$	0.2	$	0.2	$	0.2
Fitchburg Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value		—		0.8		—
8.00% Series, $100 Par Value		—		1.0		—

Total Preferred Stock	$	0.2	$	2.0	$	0.2

There were 2,250 shares of Unitil Energy’s 6.00% Series Preferred Stock outstanding at June 30, 2013, June 30, 2012 and December 31, 2012.

There were 7,823 shares of Fitchburg’s 5.125% Series Preferred Stock and 9,654 shares of Fitchburg’s 8.00% Series Preferred Stock outstanding at June 30, 2012. On December 1, 2012, Fitchburg redeemed and retired the two outstanding issues of its Redeemable, Cumulative Preferred Stock. The 8.00% Series was redeemed at par (aggregate par value of $965,400). The 5.125% Series was redeemed at par plus a premium of 1.28% (aggregate value of $792,313). Fitchburg used operating cash to effect this transaction.

There were less than $0.1 million of total dividends declared on Preferred Stock in the three and six months ended June 30, 2013, respectively, and $0.1 million of total dividends declared on Preferred Stock in the three and six months ended June 30, 2012, 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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+ Details

Long-Term Debt, Credit Arrangements and Guarantees

6 Months Ended

Jun. 30, 2013

Long-Term Debt, Credit Arrangements and Guarantees

NOTE 4 – LONG-TERM DEBT, CREDIT ARRANGEMENTS AND GUARANTEES

Long-Term Debt

Details on long-term debt at June 30, 2013, June 30, 2012 and December 31, 2012 are shown below ($ Millions):


	June 30,				December 31,
	2013		2012		2012
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		2.6		3.1		2.8

Total Long-Term Debt		287.6		288.1		287.8
Less: Current Portion		0.6		0.5		0.5

Total Long-term Debt, Less Current Portion	$	287.0	$	287.6	$	287.3

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,

2013

2012

Estimated Fair Value of Long-Term Debt

333.2

341.6

349.7

Credit Arrangements

Unitil has an unsecured revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the credit facility is currently $60 million, which the Company believes will be sufficient until its expected renewal.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of June 30, 2013, June 30, 2012 and December 31, 2012:


	Revolving Credit Facility (millions)
	June 30,				December 31,
	2013		2012		2012
Limit	$	60.0	$	115.0	$	60.0
Outstanding	$	24.5	$	5.0	$	49.4
Available	$	35.5	$	110.0	$	10.6

The revolving credit facility contains customary terms and conditions for credit facilities of this type, including, without limitation, covenants restricting the Company’s ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a covenant restricting the Company’s ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of June 30, 2013, June 30, 2012 and December 31, 2012, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

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 were obligations of $7.2 million, $8.0 million and $10.7 million outstanding at June 30, 2013, June 30, 2012 and December 31, 2012, respectively, related to these asset management agreements. The amount of natural gas inventory released in June 2013 and payable in July 2013 is $0.1 million and is recorded in Accounts Payable at June 30, 2013. There were no amounts of natural gas inventory released in June 2012 and payable in July 2012 that were recorded in Accounts Payable at June 30, 2012. The amount of natural gas inventory released in December 2012 and payable in January 2013 is $2.1 million and is recorded in Accounts Payable at December 31, 2012.

Guarantees

The Company also 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, 2013, there were approximately $13.5 million of guarantees outstanding and the longest term guarantee extends through February 2014.

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, 2013, the principal amount outstanding for the 8% Unitil Realty notes was $2.6 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, 2013, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Segment Information

6 Months Ended

Jun. 30, 2013

Segment Information

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and six months ended June 30, 2013 and June 30, 2012 (Millions):


Three Months Ended June 30, 2013	Electric		Gas			Other		Non- Regulated		Total
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

Three Months Ended June 30, 2012
Revenues	$	44.8	$	22.7		$	—	$	1.3	$	68.8
Segment Profit (Loss)		1.4		(2.2	)		0.1		0.3		(0.4	)
Capital Expenditures		4.1		10.0			0.7		—		14.8

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

Six Months Ended June 30, 2012
Revenues	$	93.5	$	86.9		$	—	$	2.6	$	183.0
Segment Profit (Loss)		2.6		5.4			—		0.6		8.6
Capital Expenditures		9.4		13.1			1.4		—		23.9
Segment Assets		398.3		416.1			3.3		7.0		824.7

- 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.

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+ Details

Regulatory Matters

6 Months Ended

Jun. 30, 2013

Regulatory Matters

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2012 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 30, 2013.

Regulatory Matters

Granite State – Base Rates – Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to gas transmission plant projects. In June 2013, Granite State submitted to the FERC its next incremental annual rate adjustment, in the amount of $0.4 million, with rates to be effective August 1, 2013. A rate order from the FERC on this matter is expected in late July 2013.

Unitil Energy – Base Rates – On April 26, 2011, the New Hampshire Public Utilities Commission (NHPUC) approved a rate settlement with a permanent increase of $5.2 million in annual revenue effective July 1, 2010, and an additional increase of $5.0 million in annual revenue effective May 1, 2011. The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with step increases in annual revenue on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. Unitil Energy’s first step increase was approved as filed, effective May 1, 2012. Unitil Energy’s second step increase of $2.8 million went into effect on May 1, 2013, which included rate increases to recover capital improvements, increased spending for its vegetation management and reliability enhancement programs and an increase in its storm reserve fund.

Northern Utilities – Base Rates Filed – In April 2013, Northern Utilities filed two separate rate cases, with the NHPUC and MPUC, requesting approval to increase its natural gas distribution base rates. In New Hampshire, the Company requested an increase of $5.2 million in gas distribution base revenue or approximately 9.4 percent over test year operating revenue. In Maine, the Company requested an increase of $4.6 million in gas distribution base revenue or approximately 6.3 percent over test year operating revenue. Both filings include proposed multi-year rate plans that include cost tracking mechanisms to recover future capital costs associated with Northern Utilities’ infrastructure replacements and safety and reliability improvements to the natural gas distribution system. Northern Utilities has been authorized to implement temporary rates in New Hampshire to collect a $2.5 million increase (annualized) in gas distribution revenue, effective July 1, 2013. These rate case filings are subject to regulatory review and approval with final rate orders expected in the first half of 2014. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, July 1, 2013.

Fitchburg – Electric Base Rates Filed – In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or approximately 11.5 percent over test year operating revenue. Included in the amount of this annual increase is approximately $2.1million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to two severe storms in 2011, Tropical Storm Irene and the October snowstorm, and Superstorm Sandy in 2012. The filing includes a proposed modified revenue decoupling mechanism by means of either a capital cost adjustment mechanism or a multi-year rate plan featuring a revenue cap index. The filing also includes a proposed major storm reserve fund to address the costs of future major storms by collecting $2.8 million per year through a reconciling storm recovery adjustment factor beginning January 1, 2015. The rate case filing is subject to regulatory review and approval with final rate orders expected in the second quarter of 2014.

Major Storms – Fitchburg and Unitil Energy

Superstorm Sandy – On October 29-30, 2012, a severe storm struck the Eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.7 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm, including $0.3 million and $0.4 million related to capital construction for Fitchburg and Unitil Energy, respectively. The amount and timing of the cost recovery of these storm restoration expenditures for Fitchburg will be determined in its rate case. The cost recovery for Unitil Energy has been approved as discussed below. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

Fitchburg – Storm Cost Deferral – On May 1, 2012 the MDPU approved Fitchburg’s request to defer $4.3 million of storm costs associated with two severe storms which occurred in 2011, and Fitchburg is seeking recovery of these costs in the electric rate case it filed in July 2013.

Unitil Energy – 2012 Storm Costs – On March 14, 2013, Unitil Energy filed a petition with the NHPUC to increase its storm recovery adjustment factor effective May 1, 2013, to recover approximately $2.3 million of costs to repair damage to its electrical system resulting from Superstorm Sandy. On April 25, 2013, the NHPUC approved the recovery of these costs over a five-year period with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, to be applied to the uncollected balance through the recovery period.

Fitchburg – Electric Operations – On November 30, 2012, 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. All of the rates were approved effective January 1, 2013 for billing purposes, subject to reconciliation pending investigation by the MDPU. The reconciliation of costs and revenues for transition and transmission was approved on May 14, 2013. The reconciliation of costs and revenues for other surcharge and cost factors remains pending.

Fitchburg – Service Quality – On March 1, 2013, Fitchburg submitted its 2012 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. On March 29, 2013, the MDPU issued its order approving the 2011 Service Quality Report for Fitchburg’s gas division. The 2010-2012 Service Quality reports for Fitchburg’s electric division remain pending.

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 MDPU investigation will review existing and potential new reliability, safety, and customer satisfaction metrics; potential penalties for downed wire response; potential clean energy metrics; penalty provisions, including penalty offsets for superior performance in other metrics for poor performance on a different metric; and review of historic data for use in establishing service quality benchmarks. Fitchburg has been an active participant in this docket, which remains pending.

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 has 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, net metering tariffs and proposals to purchase long-term contracts for renewable energy have been approved by the MDPU. Terms and conditions for purchasing supplier receivables is 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. This 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 has 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 August 6, 2012, the Governor of Massachusetts also signed into law “An Act Relative to the Emergency Response of Public Utilities”, which establishes a new storm trust fund and requires that penalties levied by the MDPU for violations of its emergency preparedness rules be credited to customers.

Unitil Corporation – FERC Audit – On November 3, 2011, the FERC commenced an audit of Unitil Corporation, including its associated service company and its electric and natural gas distribution companies. Among other requirements, the audit evaluated the Company’s compliance with: i) cross-subsidization restrictions on affiliate transactions; ii) regulations under the Energy Policy Act of 2005; and the iii) uniform system of accounts for centralized service companies. The final audit report was issued on February 28, 2013 and the Company submitted its plan to address the audit findings and implement the audit recommendations on March 29, 2013. The Company submitted its quarterly progress update on the implementation of the audit recommendations on April 30, 2013. On June 5, 2013 the FERC advised the Company that the audit is complete; no further action is required by the Company. The audit findings did not have an impact on the Company’s financial condition or results of operations.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impact on 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 Company continues to believe the suit is without merit and will continue to defend itself vigorously.

Environmental Matters

6 Months Ended

Jun. 30, 2013

Environmental Matters

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2012 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 30, 2013.

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 compliance with applicable environmental and safety laws and regulations, and the Company believes that as of June 30, 2013, 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.

Fitchburg’s Manufactured Gas Plant Site – Fitchburg is in the process of developing long-range plans for a feasible permanent remediation solution of a former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts, including alternatives for re-use of the site. Included in Environmental Obligations on the Company’s unaudited Consolidated Balance Sheets at June 30, 2013 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was 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.

Northern Utilities Manufactured Gas Plant Sites – Northern Utilities has an extensive program to identify, investigate and remediate former 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 currently underway. Additionally, Northern Utilities has executed an Option Agreement with New Yard, LLC which establishes conditions for finalizing a long-term lease on the property to redevelop the Portland site as a boat repair facility with lease proceeds being used to offset remediation costs. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs until all 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 Sheet at June 30, 2013 are accrued liabilities totaling $1.8 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $1.0 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at June 30, 2013 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.

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, 2013

Income Taxes

NOTE 8: INCOME TAXES

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.

The Company filed its tax returns for the year ended December 31, 2011 with the Internal Revenue Service (IRS) in September 2012. As of December 31, 2012, the Company had recorded cumulative federal and state net operating loss (NOL) carryforward assets of $8.5 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, 2012, 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, 2013 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by the FASB Codification is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2009; December 31, 2010; and December 31, 2011.

Retirement Benefit Obligations

6 Months Ended

Jun. 30, 2013

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, 2012 as filed with the SEC on January 30, 2013 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:


	2013			2012
Used to Determine Plan Costs
Discount Rate		4.00	%		4.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			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,	2013			2012			2013			2012			2013		2012
Service Cost	$	894		$	807		$	631		$	517		$	18	$	72
Interest Cost		1,141			1,158			612			576			60		53
Expected Return on Plan Assets		(1,489	)		(1,347	)		(180	)		(174	)		—		—
Prior Service Cost Amortization		52			47			425			432			3		3
Transition Obligation Amortization		—			—			—			5			—		—
Actuarial Loss Amortization		1,056			904			196			32			46		16

Sub-total		1,654			1,569			1,684			1,388			127		144
Amounts Capitalized and Deferred		(768	)		(725	)		(678	)		(560	)		—		—

Net Periodic Benefit Cost Recognized	$	886		$	844		$	1,006		$	828		$	127	$	144


	Pension Plan						PBOP Plan						SERP
Six Months Ended June 30,	2013			2012			2013			2012			2013		2012
Service Cost	$	1,787		$	1,613		$	1,262		$	1,033		$	36	$	144
Interest Cost		2,283			2,317			1,224			1,151			121		106
Expected Return on Plan Assets		(2,978	)		(2,695	)		(361	)		(348	)		—		—
Prior Service Cost Amortization		104			94			850			864			6		6
Transition Obligation Amortization		—			—			—			11			—		—
Actuarial Loss Amortization		2,115			1,808			393			65			92		32

Sub-total		3,311			3,137			3,368			2,776			255		288
Amounts Capitalized and Deferred		(1,384	)		(1,281	)		(1,447	)		(980	)		—		—

Net Periodic Benefit Cost Recognized	$	1,927		$	1,856		$	1,921		$	1,796		$	255	$	288

Employer Contributions

As of June 30, 2013, the Company had not made any contributions to its Pension and PBOP Plans in 2013. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2013 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of June 30, 2013, the Company had made $26,000 of contributions to the SERP Plan in 2013. The Company presently anticipates contributing an additional $27,000 to the SERP Plan in 2013.

Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2013

Nature of Operations

Basis of Presentation

Regulatory Accounting


	June 30,				December 31,
Regulatory Assets consist of the following (millions)	2013		2012		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	19.3	$	30.4	$	41.0
Deferred Restructuring Costs		14.5		21.3		20.1
Retirement Benefit Obligations		62.5		55.1		62.5
Income Taxes		9.5		10.8		10.2
Environmental Obligations		16.7		16.9		16.8
Deferred Storm Charges		28.1		26.2		27.8
Other		6.9		9.8		8.1

Total Regulatory Assets	$	157.5	$	170.5	$	186.5
Less: Current Portion of Regulatory Assets⁽¹⁾		31.6		35.2		51.9

Regulatory Assets – noncurrent	$	125.9	$	135.3	$	134.6

⁽¹⁾	Reflects amounts included in Accrued Revenue, discussed below, on the Company’s unaudited Consolidated Balance Sheets.


	June 30,				December 31,
Regulatory Liabilities consist of the following (millions)	2013		2012		2012
Regulatory Tracker Mechanisms	$	13.3	$	8.0	$	6.8

Total Regulatory Liabilities	$	13.3	$	8.0	$	6.8

Accrued Revenue


	June 30,				December 31,
Accrued Revenue ($millions)	2013		2012		2012
Regulatory Assets – Current	$	31.6	$	35.2	$	51.9
Unbilled Revenues		6.7		6.3		11.5

Total Accrued Revenue	$	38.3	$	41.5	$	63.4

Utility Plant

Gas Inventory


	June 30,				December 31,
Gas Inventory ($millions)	2013		2012		2012
Natural Gas	$	0.4	$	0.1	$	0.6
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.8	$	0.6	$	1.1

Exchange Gas Receivable


	June 30,				December 31,
Exchange Gas Receivable ($millions)	2013		2012		2012
Northern Utilities	$	7.0	$	8.0	$	8.7
Fitchburg		0.6		0.5		0.7

Total Exchange Gas Receivable	$	7.6	$	8.5	$	9.4

Energy Supply Obligations


	June 30,				December 31,
Energy Supply Obligations ($millions)	2013		2012		2012
Current:
Exchange Gas Obligation	$	7.0	$	8.0	$	8.7
Power Supply Contract Divestitures		0.9		4.7		0.9
Renewable Energy Portfolio Standards		1.9		4.5		4.2

Total Energy Supply Obligations – Current	$	9.8	$	17.2	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.9	$	3.8	$	3.3

Total Energy Supply Obligations	$	12.7	$	21.0	$	17.1

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.

Derivatives

Liability Derivatives ($ millions)


Fair Value Amount of Derivative Liabilities (millions) Offset in Regulatory Assets, as of:
		Fair Value
Description	Balance Sheet Location	June 30, 2013		June 30, 2012		December 31, 2012
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	0.3	$	1.5	$	0.7

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.1		—		—

Total Derivative Liabilities		$	0.4	$	1.5	$	0.7


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.9	$	0.1	$	0.6	$	1.4
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽¹⁾:
Purchased Gas	$	—	$	0.6	$	0.9	$	2.2

⁽¹⁾	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Allowance for Doubtful Accounts


	June 30,				December 31,
	2013		2012		2012
Allowance for Doubtful Accounts	$	2.4	$	2.9	$	1.9

Income Taxes

Subsequent Events

Reclassifications

Recently Issued Pronouncements

Recently Issued Pronouncements – There are no recently issued pronouncements applicable to the Company that have not already been adopted.

Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2013

Regulatory Assets


	June 30,				December 31,
Regulatory Assets consist of the following (millions)	2013		2012		2012
Energy Supply & Other Regulatory Tracker Mechanisms	$	19.3	$	30.4	$	41.0
Deferred Restructuring Costs		14.5		21.3		20.1
Retirement Benefit Obligations		62.5		55.1		62.5
Income Taxes		9.5		10.8		10.2
Environmental Obligations		16.7		16.9		16.8
Deferred Storm Charges		28.1		26.2		27.8
Other		6.9		9.8		8.1

Total Regulatory Assets	$	157.5	$	170.5	$	186.5
Less: Current Portion of Regulatory Assets⁽¹⁾		31.6		35.2		51.9

Regulatory Assets – noncurrent	$	125.9	$	135.3	$	134.6

⁽¹⁾	Reflects amounts included in Accrued Revenue, discussed below, on the Company’s unaudited Consolidated Balance Sheets.

Regulatory Liabilities


	June 30,				December 31,
Regulatory Liabilities consist of the following (millions)	2013		2012		2012
Regulatory Tracker Mechanisms	$	13.3	$	8.0	$	6.8

Total Regulatory Liabilities	$	13.3	$	8.0	$	6.8

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of June 30, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Accrued Revenue ($millions)	2013		2012		2012
Regulatory Assets – Current	$	31.6	$	35.2	$	51.9
Unbilled Revenues		6.7		6.3		11.5

Total Accrued Revenue	$	38.3	$	41.5	$	63.4

Components of Gas Inventory

The following table shows the components of Gas Inventory as of June 30, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Gas Inventory ($millions)	2013		2012		2012
Natural Gas	$	0.4	$	0.1	$	0.6
Propane		0.3		0.4		0.4
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.8	$	0.6	$	1.1

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of June 30, 2013, June 30, 2012 and December 31, 2012.


	June 30,				December 31,
Exchange Gas Receivable ($millions)	2013		2012		2012
Northern Utilities	$	7.0	$	8.0	$	8.7
Fitchburg		0.6		0.5		0.7

Total Exchange Gas Receivable	$	7.6	$	8.5	$	9.4

Components of Energy Supply Obligations


	June 30,				December 31,
Energy Supply Obligations ($millions)	2013		2012		2012
Current:
Exchange Gas Obligation	$	7.0	$	8.0	$	8.7
Power Supply Contract Divestitures		0.9		4.7		0.9
Renewable Energy Portfolio Standards		1.9		4.5		4.2

Total Energy Supply Obligations – Current	$	9.8	$	17.2	$	13.8
Long-Term:
Power Supply Contract Divestitures	$	2.9	$	3.8	$	3.3

Total Energy Supply Obligations	$	12.7	$	21.0	$	17.1

Fair Value Amount of Derivative Liabilities Offset in Regulatory Assets


Fair Value Amount of Derivative Liabilities (millions) Offset in Regulatory Assets, as of:
		Fair Value
Description	Balance Sheet Location	June 30, 2013		June 30, 2012		December 31, 2012
Derivative Liabilities
Natural Gas Futures Contracts	Other Current Liabilities	$	0.3	$	1.5	$	0.7

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.1		—		—

Total Derivative Liabilities		$	0.4	$	1.5	$	0.7

Regulatory Assets (Liabilities) and Reclassification from Regulatory Asset (Liabilities) into Purchased Gas


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.9	$	0.1	$	0.6	$	1.4
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽¹⁾:
Purchased Gas	$	—	$	0.6	$	0.9	$	2.2

⁽¹⁾	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Allowance for Doubtful Accounts Included in Accounts Receivable, Net


	June 30,				December 31,
	2013		2012		2012
Allowance for Doubtful Accounts	$	2.4	$	2.9	$	1.9

Dividends Declared Per Share (Tables)

6 Months Ended

Jun. 30, 2013

Schedule of Dividends Declared

Declaration

Date

Date Paid

(Payable)

Shareholder of

Record Date

Dividend

Amount

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

09/19/12

11/15/12

11/01/12

0.345

06/06/12

08/15/12

08/01/12

0.345

03/22/12

05/15/12

05/01/12

0.345

01/17/12

02/15/12

02/01/12

0.345

Common Stock and Preferred Stock (Tables)

6 Months Ended

Jun. 30, 2013

Details on Preferred Stock

Details on preferred stock at June 30, 2013, June 30, 2012 and December 31, 2012 are shown below:


	June 30,				December 31,
	2013		2012		2012
Preferred Stock
Unitil Energy Preferred Stock, Non-Redeemable, Non-Cumulative:
6.00% Series, $100 Par Value,	$	0.2	$	0.2	$	0.2
Fitchburg Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value		—		0.8		—
8.00% Series, $100 Par Value		—		1.0		—

Total Preferred Stock	$	0.2	$	2.0	$	0.2

Long-Term Debt, Credit Arrangements and Guarantees (Tables)

6 Months Ended

Jun. 30, 2013

Details on Long Term Debt

Details on long-term debt at June 30, 2013, June 30, 2012 and December 31, 2012 are shown below ($ Millions):


	June 30,				December 31,
	2013		2012		2012
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		2.6		3.1		2.8

Total Long-Term Debt		287.6		288.1		287.8
Less: Current Portion		0.6		0.5		0.5

Total Long-term Debt, Less Current Portion	$	287.0	$	287.6	$	287.3

Fair Value of Long Term Debt

(Millions)

June 30,

December 31,

2013

2012

Estimated Fair Value of Long-Term Debt

333.2

341.6

349.7

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, 2013, June 30, 2012 and December 31, 2012:


	Revolving Credit Facility (millions)
	June 30,				December 31,
	2013		2012		2012
Limit	$	60.0	$	115.0	$	60.0
Outstanding	$	24.5	$	5.0	$	49.4
Available	$	35.5	$	110.0	$	10.6

- 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=6584090&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

Segment Information (Tables)

6 Months Ended

Jun. 30, 2013

Significant Segment Financial Data

The following table provides significant segment financial data for the three and six months ended June 30, 2013 and June 30, 2012 (Millions):


Three Months Ended June 30, 2013	Electric		Gas			Other		Non- Regulated		Total
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

Three Months Ended June 30, 2012
Revenues	$	44.8	$	22.7		$	—	$	1.3	$	68.8
Segment Profit (Loss)		1.4		(2.2	)		0.1		0.3		(0.4	)
Capital Expenditures		4.1		10.0			0.7		—		14.8

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

Six Months Ended June 30, 2012
Revenues	$	93.5	$	86.9		$	—	$	2.6	$	183.0
Segment Profit (Loss)		2.6		5.4			—		0.6		8.6
Capital Expenditures		9.4		13.1			1.4		—		23.9
Segment Assets		398.3		416.1			3.3		7.0		824.7

Retirement Benefit Obligations (Tables)

6 Months Ended

Jun. 30, 2013

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:


	2013			2012
Used to Determine Plan Costs
Discount Rate		4.00	%		4.60	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			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,	2013			2012			2013			2012			2013		2012
Service Cost	$	894		$	807		$	631		$	517		$	18	$	72
Interest Cost		1,141			1,158			612			576			60		53
Expected Return on Plan Assets		(1,489	)		(1,347	)		(180	)		(174	)		—		—
Prior Service Cost Amortization		52			47			425			432			3		3
Transition Obligation Amortization		—			—			—			5			—		—
Actuarial Loss Amortization		1,056			904			196			32			46		16

Sub-total		1,654			1,569			1,684			1,388			127		144
Amounts Capitalized and Deferred		(768	)		(725	)		(678	)		(560	)		—		—

Net Periodic Benefit Cost Recognized	$	886		$	844		$	1,006		$	828		$	127	$	144


	Pension Plan						PBOP Plan						SERP
Six Months Ended June 30,	2013			2012			2013			2012			2013		2012
Service Cost	$	1,787		$	1,613		$	1,262		$	1,033		$	36	$	144
Interest Cost		2,283			2,317			1,224			1,151			121		106
Expected Return on Plan Assets		(2,978	)		(2,695	)		(361	)		(348	)		—		—
Prior Service Cost Amortization		104			94			850			864			6		6
Transition Obligation Amortization		—			—			—			11			—		—
Actuarial Loss Amortization		2,115			1,808			393			65			92		32

Sub-total		3,311			3,137			3,368			2,776			255		288
Amounts Capitalized and Deferred		(1,384	)		(1,281	)		(1,447	)		(980	)		—		—

Net Periodic Benefit Cost Recognized	$	1,927		$	1,856		$	1,921		$	1,796		$	255	$	288

Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions, Bcf in Billions	6 Months Ended
	Jun. 30, 2013 USD ($) Bcf mi Entity Segment	Dec. 31, 2012 USD ($) Bcf	Jun. 30, 2012 USD ($) Bcf
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi	86
Cost of removal obligation \| $	$ 54.7	$ 51.4	$ 48.6
Number of Natural Gas Storage Outstanding \| Bcf	1.8	1.9	1.8
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Entity	3
Other Subsidiaries
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Segment	3

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

Jun. 30, 2013

Dec. 31, 2012

Jun. 30, 2012

Regulatory Assets [Line Items]

Regulatory Assets

$ 157.5

$ 186.5

$ 170.5

Less: Current Portion of Regulatory Assets

^[1]

31.6

51.9

35.2

Regulatory Assets - noncurrent

125.9

134.6

135.3

Restructuring Charges | Energy Supply & Other Regulatory Tracker Mechanisms

Regulatory Assets [Line Items]

Regulatory Assets

19.3

41.0

30.4

Restructuring Charges | Deferred Restructuring Costs

Regulatory Assets [Line Items]

Regulatory Assets

14.5

20.1

21.3

Retirement Benefit Obligations

Regulatory Assets [Line Items]

Regulatory Assets

62.5

55.1

Income Taxes

Regulatory Assets [Line Items]

Regulatory Assets

9.5

10.2

10.8

Electric Utilities

Regulatory Assets [Line Items]

Regulatory Assets

28.1

27.8

26.2

Other Assets

Regulatory Assets [Line Items]

Regulatory Assets

6.9

8.1

9.8

Environmental Matters

Regulatory Assets [Line Items]

Regulatory Assets

$ 16.7

$ 16.8

$ 16.9

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

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.3	$ 6.8	$ 8.0
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.3	$ 6.8	$ 8.0

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 38.3	$ 63.4	$ 41.5
Regulatory Asset
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	31.6	51.9	35.2
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 6.7	$ 11.5	$ 6.3

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.8	$ 1.1	$ 0.6
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.6	0.1
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.4	0.4
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.1	$ 0.1	$ 0.1

Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Receivables [Line Items]
Total Exchange Gas Receivable	$ 7.6	$ 9.4	$ 8.5
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	7.0	8.7	8.0
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.6	$ 0.7	$ 0.5

Energy Supply Obligations (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 9.8	$ 13.8	$ 17.2
Energy Supply Obligations	2.9	3.3	3.8
Total Energy Supply Obligations	12.7	17.1	21.0
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations	7.0	8.7	8.0
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations	0.9	0.9	4.7
Energy Supply Obligations	2.9	3.3	3.8
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 1.9	$ 4.2	$ 4.5

Fair Value Amount of Derivative Liabilities Offset in Regulatory Assets (Detail) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Derivative Liabilities
Natural Gas Futures Contracts	$ 0.4	$ 0.7	$ 1.5
Natural Gas Contracts \| Other Current Liabilities
Derivative Liabilities
Natural Gas Futures Contracts	0.3	$ 0.7	$ 1.5
Natural Gas Contracts \| Other Noncurrent Liabilities
Derivative Liabilities
Natural Gas Futures Contracts	$ 0.1

Regulatory Assets (Liabilities) and Reclassification from Regulatory Asset (Liabilities) into Purchased Gas (Detail) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Natural Gas Future Contract

Regulatory Assets [Line Items]

Loss (Gain) recognized in Regulatory Assets

$ 0.9

$ 0.1

$ 0.6

$ 1.4

Gas Purchase Costs

Regulatory Assets [Line Items]

Loss Reclassified into unaudited Consolidated Statement of Earnings

^[1]

$ 0.6

$ 0.9

$ 2.2

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

Allowance for Doubtful Accounts Included in Accounts Receivable, Net (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 2.4	$ 1.9	$ 2.9

Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended		6 Months Ended
Dividends Declared Per Share (Detail) - $ / shares	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Dividends Payable [Line Items]
Dividend Amount	$ 0.345	$ 0.345	$ 1.035	$ 1.035
Group One
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 Two
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 Three
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
Group Four
Dividends Payable [Line Items]
Declaration Date			Sep. 19, 2012
Date Paid (Payable)			Nov. 15, 2012
Shareholder of Record Date			Nov. 01, 2012
Dividend Amount			$ 0.345
Group Five
Dividends Payable [Line Items]
Declaration Date			Jun. 06, 2012
Date Paid (Payable)			Aug. 15, 2012
Shareholder of Record Date			Aug. 01, 2012
Dividend Amount			$ 0.345
Group Six
Dividends Payable [Line Items]
Declaration Date			Mar. 22, 2012
Date Paid (Payable)			May 15, 2012
Shareholder of Record Date			May 01, 2012
Dividend Amount			$ 0.345
Group Seven
Dividends Payable [Line Items]
Declaration Date			Jan. 17, 2012
Date Paid (Payable)			Feb. 15, 2012
Shareholder of Record Date			Feb. 01, 2012
Dividend Amount			$ 0.345

Common Stock and Preferred Stock - Additional Information (Detail)	1 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended
	May 16, 2012 USD ($) $ / shares shares	Jun. 30, 2013 USD ($) shares	Jun. 30, 2012 USD ($) shares	Jun. 30, 2013 USD ($) yr $ / shares shares	Jun. 30, 2012 USD ($) $ / shares shares	Dec. 31, 2012 USD ($) shares
Class of Stock [Line Items]
Common stock, shares outstanding \| shares		13,822,318	13,758,805	13,822,318	13,758,805	13,780,601
Proceed from issuance of common stock \| $				$ 600,000	$ 66,000,000
Dividend declared \| $			$ 100,000		100,000
Maximum
Class of Stock [Line Items]
Dividend declared \| $		$ 100,000	100,000	100,000	100,000
Restricted Stock Unit
Class of Stock [Line Items]
Fair value of liabilities associated with fully vested RSUs that will be settled in cash \| $			$ 0		$ 0
Restricted Stock Unit \| Maximum
Class of Stock [Line Items]
Fair value of liabilities associated with fully vested RSUs that will be settled in cash \| $		$ 100,000		$ 100,000		$ 100,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period				4 years
Restricted stock vesting percentage annually				25.00%
Restricted stock issue date				Feb. 04, 2013
Restricted stock issued \| shares				21,240
Restricted stock grant date market value \| $				$ 564,134
Restricted stock non-vested \| shares		53,480	53,942	53,480	53,942
Restricted stock weighted average grant date fair value \| $ / shares				$ 25.99	$ 24.67
Share based compensation expense \| $				$ 500,000	$ 1,000,000
Unrecognized share based compensation \| $		$ 900,000		$ 900,000
Share compensation recognition period \| yr				2.7
Forfeitures or cancellations under the stock plan \| shares				0
Restricted Stock \| Maximum
Class of Stock [Line Items]
Restricted stock available for Awards \| shares		677,500		677,500
Restricted stock that may be awarded in any one calendar year to any one participant \| shares		20,000		20,000
Series 8 \| Fitchburg Gas and Electric Light Company
Class of Stock [Line Items]
Preferred stock, outstanding \| shares			9,654		9,654
Redeemable, Cumulative Preferred Stock \| $						$ 965,400
Dividend rate						8.00%
Series 5 \| Fitchburg Gas and Electric Light Company
Class of Stock [Line Items]
Preferred stock, outstanding \| shares			7,823		7,823
Redeemable, Cumulative Preferred Stock \| $						$ 792,313
Dividend rate						5.125%
Preferred Stock premium percentage						1.28%
Common Stock Offering
Class of Stock [Line Items]
Common stock, share issued \| shares	2,760,000
Common stock price per share \| $ / shares	$ 25.25
Proceed from issuance of common stock \| $	$ 65,700,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock, share issued \| shares		20,477		20,477
Common stock price per share \| $ / shares				$ 28.27
Proceed from issuance of common stock \| $				$ 579,000
Restricted Stock Units Issued
Class of Stock [Line Items]
Restricted stock units issued \| shares		0		0
Series 6 \| Unitil Energy Systems Inc
Class of Stock [Line Items]
Preferred stock, outstanding \| shares		2,250	2,250	2,250	2,250	2,250

Details on Preferred Stock (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Preferred Units [Line Items]
Preferred Stock	$ 0.2	$ 0.2	$ 2.0
Unitil Energy Systems Inc \| Nonredeemable Preferred Stock \| Noncumulative Preferred Stock \| Series 6
Preferred Units [Line Items]
Preferred Stock	$ 0.2	$ 0.2	0.2
Fitchburg Gas and Electric Light Company \| Redeemable Preferred Stock \| Cumulative Preferred Stock \| Series 5
Preferred Units [Line Items]
Preferred Stock			0.8
Fitchburg Gas and Electric Light Company \| Redeemable Preferred Stock \| Cumulative Preferred Stock \| Series 8
Preferred Units [Line Items]
Preferred Stock			$ 1.0

Details on Preferred Stock (Parenthetical) (Detail) - $ / shares	6 Months Ended		12 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Unitil Energy Systems Inc \| Noncumulative Preferred Stock \| Series 6 \| Nonredeemable Preferred Stock
Preferred Units [Line Items]
Dividend rate	6.00%	6.00%	6.00%
Preferred Stock Par Value	$ 100	$ 100	$ 100
Fitchburg Gas and Electric Light Company \| Series 5
Preferred Units [Line Items]
Dividend rate			5.125%
Fitchburg Gas and Electric Light Company \| Series 8
Preferred Units [Line Items]
Dividend rate			8.00%
Fitchburg Gas and Electric Light Company \| Cumulative Preferred Stock \| Series 5 \| Redeemable Preferred Stock
Preferred Units [Line Items]
Dividend rate	5.125%	5.125%	5.125%
Preferred Stock Par Value	$ 100	$ 100	$ 100
Fitchburg Gas and Electric Light Company \| Cumulative Preferred Stock \| Series 8 \| Redeemable Preferred Stock
Preferred Units [Line Items]
Dividend rate	8.00%	8.00%	8.00%
Preferred Stock Par Value	$ 100	$ 100	$ 100

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Debt Instrument [Line Items]
Long-Term Debt	$ 287.6	$ 287.8	$ 288.1
Less: Current Portion	0.6	0.5	0.5
Total Long-term Debt, Less Current Portion	287.0	287.3	287.6
Senior Notes Six Point Three Three Percent Due May One Twenty Twenty Two
Debt Instrument [Line Items]
Senior Notes	20.0	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds Five Point Two Four Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Four Nine Percent Due October Fourteen Twenty Twenty Four
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Nine Six Percent Due September One Twenty Twenty Eight
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Zero Zero Percent Due May One Twenty Thirty One
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Three Two Percent Due September Fifteen Twenty Thirty Six
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Five Percent Due November Thirty Twenty Twenty Three
Debt Instrument [Line Items]
Long-Term Debt	19.0	19.0	19.0
Fitchburg Gas and Electric Light Company \| Notes Seven Point Three Seven Percent Due January Fifteen Twenty Twenty Nine
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0	12.0
Fitchburg Gas and Electric Light Company \| Notes Seven Point Nine Eight Percent Due June One Twenty Thirty One
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0	14.0
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Nine Percent Due October Fifteen Twenty Twenty Five
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company \| Notes Five Point Nine Zero Percent Due December Fifteen Twenty Thirty
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Northern Utilities Inc \| Senior Notes Six Point Nine Five Percent Due December Three Twenty Eighteen
Debt Instrument [Line Items]
Senior Notes	30.0	30.0	30.0
Northern Utilities Inc \| Senior Notes Five Point Two Nine Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Senior Notes	25.0	25.0	25.0
Northern Utilities Inc \| Senior Notes Seven Point Seven Two Percent Due December Three Twenty Thirty Eight
Debt Instrument [Line Items]
Senior Notes	50.0	50.0	50.0
Granite State Gas Transmission Inc \| Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen
Debt Instrument [Line Items]
Senior Notes	10.0	10.0	10.0
Unitil Realty Corp \| Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen
Debt Instrument [Line Items]
Senior Secured Notes	$ 2.6	$ 2.8	$ 3.1

Details on Long Term Debt (Parenthetical) (Detail)	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Senior Notes Six Point Three Three Percent Due May One Twenty Twenty Two
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%	6.33%
Unitil Energy Systems Inc \| First Mortgage Bonds Five Point Two Four Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%	5.24%
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Four Nine Percent Due October Fourteen Twenty Twenty Four
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%	8.49%
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Nine Six Percent Due September One Twenty Twenty Eight
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%	6.96%
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Zero Zero Percent Due May One Twenty Thirty One
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%	8.00%
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Three Two Percent Due September Fifteen Twenty Thirty Six
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%	6.32%
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Five Percent Due November Thirty Twenty Twenty Three
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%	6.75%
Fitchburg Gas and Electric Light Company \| Notes Seven Point Three Seven Percent Due January Fifteen Twenty Twenty Nine
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%	7.37%
Fitchburg Gas and Electric Light Company \| Notes Seven Point Nine Eight Percent Due June One Twenty Thirty One
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%	7.98%
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Nine Percent Due October Fifteen Twenty Twenty Five
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%	6.79%
Fitchburg Gas and Electric Light Company \| Notes Five Point Nine Zero Percent Due December Fifteen Twenty Thirty
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%	5.90%
Northern Utilities Inc \| Senior Notes Six Point Nine Five Percent Due December Three Twenty Eighteen
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%	6.95%
Northern Utilities Inc \| Senior Notes Five Point Two Nine Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%	5.29%
Northern Utilities Inc \| Senior Notes Seven Point Seven Two Percent Due December Three Twenty Thirty Eight
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%	7.72%
Granite State Gas Transmission Inc \| Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%	7.15%
Unitil Realty Corp \| Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen
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, 2013	Dec. 31, 2012	Jun. 30, 2012
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 333.2	$ 349.7	$ 341.6

Long Term Debt, Credit Arrangements and Guarantees - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012
Line of Credit Facility [Line Items]
Accounts Payable	$ 21.7	$ 32.7	$ 17.4
Guarantee outstanding	$ 13.5
Guarantee end date	Feb. 28, 2014
Northern Utilities Inc
Line of Credit Facility [Line Items]
Outstanding inventory	$ 7.2	10.7	8.0
Accounts Payable	$ 0.1	2.1	0.0
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date	Oct. 08, 2013
Revolving credit facility	$ 60.0	60.0	115.0
Percentage of capitalization	The revolving credit agreement also contains a covenant restricting the Company's ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of June 30, 2013, June 30, 2012 and December 31, 2012, the Company was in compliance with the financial covenants contained in the revolving credit agreement.
Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen \| Unitil Realty Corp
Line of Credit Facility [Line Items]
Senior Secured Notes	$ 2.6	2.8	3.1
Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen \| Debt Outstanding, Principal Amount \| Unitil Realty Corp
Line of Credit Facility [Line Items]
Senior Secured Notes	2.6
Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen \| Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Senior Notes	10.0	$ 10.0	$ 10.0
Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen \| Debt Outstanding, Principal Amount \| Granite State Gas Transmission Inc
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, 2013	Dec. 31, 2012	Jun. 30, 2012
Debt Instrument [Line Items]
Revolving credit facility	$ 60.0	$ 60.0	$ 115.0
Outstanding revolving credit facility	24.5	49.4	5.0
Available revolving credit facility	$ 35.5	$ 10.6	$ 110.0

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 66.4	$ 68.8	$ 184.6	$ 183.0
Segment Profit (Loss)	(0.1)	(0.4)	10.7	8.6
Capital Expenditures	22.6	14.8	37.0	23.9
Segment Assets	874.2	824.7	874.2	824.7	$ 892.3
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	42.9	44.8	88.8	93.5
Segment Profit (Loss)	1.4	1.4	3.4	2.6
Capital Expenditures	3.4	4.1	10.4	9.4
Segment Assets	405.7	398.3	405.7	398.3
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	22.1	22.7	92.9	86.9
Segment Profit (Loss)	(2.3)	(2.2)	6.0	5.4
Capital Expenditures	17.6	10.0	24.5	13.1
Segment Assets	456.8	416.1	456.8	416.1
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit (Loss)	0.6	0.1	0.7
Capital Expenditures	1.6	0.7	2.1	1.4
Segment Assets	5.3	3.3	5.3	3.3
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	1.4	1.3	2.9	2.6
Segment Profit (Loss)	0.2	0.3	0.6	0.6
Segment Assets	$ 6.4	$ 7.0	$ 6.4	$ 7.0

Regulatory Matters - Additional Information (Detail) $ in Millions	1 Months Ended							6 Months Ended
	Jul. 31, 2013 USD ($)	Jun. 30, 2013 USD ($)	Apr. 30, 2013 USD ($) LegalMatter	Apr. 25, 2013	Oct. 31, 2012 USD ($)	May 01, 2012 USD ($)	Apr. 26, 2011 USD ($)	Jun. 30, 2013 USD ($)	Mar. 14, 2013 USD ($)
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Recovery of damage of electrical system					$ 1.1
Construction expenditures					0.3
Storm expenditures						$ 4.3
Fitchburg Gas and Electric Light Company \| Subsequent Event
Regulatory Assets [Line Items]
Increase in annual revenue	$ 6.7
Percent of increase in annual revenue	11.50%
Storm recovery adjustment factor amount	$ 2.8
Fitchburg Gas and Electric Light Company \| Subsequent Event \| Storm Costs
Regulatory Assets [Line Items]
Increase in annual revenue	$ 2.1
Unitil Energy Systems Inc
Regulatory Assets [Line Items]
Settlement agreement date								May 01, 2016
Adjustment to recover the increased spending for vegetation management program and reliability enhancement program and a proposed storm resiliency program								$ 2.8
Recovery of damage of electrical system					2.7
Construction expenditures					$ 0.4
Unitil Energy Systems Inc \| Storm Costs
Regulatory Assets [Line Items]
Recovery of damage of electrical system									$ 2.3
Cost recovery period, years				5 years
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 \| Year One Policy
Regulatory Assets [Line Items]
Increase in annual revenue							$ 5.2
Amendment effective date							July 1, 2010
Unitil Energy Systems Inc \| Year Two Policy
Regulatory Assets [Line Items]
Increase in annual revenue							$ 5.0
Amendment effective date							May 1, 2011
Northern Utilities Inc
Regulatory Assets [Line Items]
Increase in annual revenue			$ 2.5
Amendment effective date			July 1, 2013
Number of cases filed \| LegalMatter			2
Northern Utilities Inc \| New Hampshire
Regulatory Assets [Line Items]
Increase in annual revenue			$ 5.2
Percent of increase in annual revenue			9.40%
Northern Utilities Inc \| Maine
Regulatory Assets [Line Items]
Increase in annual revenue			$ 4.6
Percent of increase in annual revenue			6.30%
Granite State Gas Transmission Inc \| Gas Transportation and Storage
Regulatory Assets [Line Items]
Annual revenue increase in rate adjustments		$ 0.4

Environmental Matters - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2013 USD ($)
New Hampshire \| Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	7 years
Maine \| Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	5 years
Fitchburg Gas and Electric Light Company \| Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	7 years
Fitchburg Gas and Electric Light Company \| Environmental Clean Up Costs
Site Contingency [Line Items]
Environmental obligations	$ 12.0
Northern Utilities Inc
Site Contingency [Line Items]
Environmental obligations	1.8
Northern Utilities Inc \| Other Current Liabilities
Site Contingency [Line Items]
Environmental obligations	1.0
Environmental Matters
Site Contingency [Line Items]
Income (loss) incurred in excess of recorded amount	$ 0.0

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Cumulative alternative minimum tax credit carryforwards		$ 1.5
Federal and State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward assets		$ 8.5
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date		2019
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date		2029
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, 2009; December 31, 2010; and December 31, 2011.

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - Benefit Plan Costs	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.00%	4.60%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	8.50%	8.50%
Health Care Cost Trend Rate Assumed for Next Year	8.00%	6.50%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2017	2017

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Plans
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	$ 894	$ 807	$ 1,787	$ 1,613
Interest Cost	1,141	1,158	2,283	2,317
Expected Return on Plan Assets	(1,489)	(1,347)	(2,978)	(2,695)
Prior Service Cost Amortization	52	47	104	94
Actuarial Loss Amortization	1,056	904	2,115	1,808
Sub-total	1,654	1,569	3,311	3,137
Amounts Capitalized and Deferred	(768)	(725)	(1,384)	(1,281)
Net Periodic Benefit Cost Recognized	886	844	1,927	1,856
Other Postretirement Benefit Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	631	517	1,262	1,033
Interest Cost	612	576	1,224	1,151
Expected Return on Plan Assets	(180)	(174)	(361)	(348)
Prior Service Cost Amortization	425	432	850	864
Transition Obligation Amortization		5		11
Actuarial Loss Amortization	196	32	393	65
Sub-total	1,684	1,388	3,368	2,776
Amounts Capitalized and Deferred	(678)	(560)	(1,447)	(980)
Net Periodic Benefit Cost Recognized	1,006	828	1,921	1,796
Supplemental Employee Retirement Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	18	72	36	144
Interest Cost	60	53	121	106
Prior Service Cost Amortization	3	3	6	6
Actuarial Loss Amortization	46	16	92	32
Sub-total	127	144	255	288
Net Periodic Benefit Cost Recognized	$ 127	$ 144	$ 255	$ 288

Retirement Benefit Obligations - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2013 USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	$ 0
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