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Document And Entity Information - USD ($)	12 Months Ended
Dec. 31, 2011	Jan. 30, 2012	Jun. 30, 2011
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
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		10,955,671
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Public Float			$ 282,734,913

Consolidated Statements Of Earnings - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Revenues:
Gas	$ 159.2	$ 150.1	$ 152.8
Electric	188.1	203.7	209.9
Other	5.5	4.6	4.3
Total Operating Revenues	352.8	358.4	367.0
Operating Expenses:
Purchased Gas	89.1	90.5	96.4
Purchased Electricity	114.2	137.7	151.6
Operation and Maintenance	51.5	48.8	44.7
Conservation & Load Management	8.5	8.8	5.0
Depreciation and Amortization	29.3	28.9	27.4
Provisions for Taxes:
Local Property and Other	13.0	11.2	10.4
Federal and State Income	10.0	4.5	5.4
Total Operating Expenses	315.6	330.4	340.9
Operating Income	37.2	28.0	26.1
Other Non-Operating Expenses	0.4	0.3	0.3
Income Before Interest Expense	36.8	27.7	25.8
Interest Expense, net	20.4	18.1	15.8
Net Income	16.4	9.6	10.0
Less Dividends on Preferred Stock	0.1	0.1	0.1
Earnings Applicable to Common Shareholders	$ 16.3	$ 9.5	$ 9.9
Average Common Shares Outstanding (000's)-Basic	10,880	10,823	9,647
Average Common Shares Outstanding (000's)-Diluted	10,883	10,824	9,647
Earnings per Common Share-Basic and Diluted	$ 1.50	$ 0.88	$ 1.03

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Utility Plant:
Electric	$ 333.3	$ 321.5
Gas	382.3	360.1
Common	29.8	30.2
Construction Work in Progress	28.3	16.6
Utility Plant	773.7	728.4
Less: Accumulated Depreciation	263.0	251.9
Net Utility Plant	510.7	476.5
Current Assets:
Cash	7.5	8.9
Accounts Receivable, net	44.2	36.9
Accrued Revenue	56.6	46.7
Refundable Taxes		7.5
Gas Inventory	14.8	10.6
Material and Supplies	3.6	2.9
Prepayments and Other	4.5	3.6
Total Current Assets	131.2	117.1
Noncurrent Assets:
Regulatory Assets	139.8	143.0
Other Noncurrent Assets	18.5	23.0
Total Noncurrent Assets	158.3	166.0
TOTAL ASSETS	800.2	759.6
Capitalization:
Common Stock Equity	191.7	189.0
Preferred Stock	2.0	2.0
Long-Term Debt, Less Current Portion	287.8	288.3
Total Capitalization	481.5	479.3
Current Liabilities:
Long-Term Debt, Current Portion	0.5	0.5
Accounts Payable	26.4	26.5
Short-Term Debt	87.9	66.8
Energy Supply Contract Obligations	21.1	17.0
Taxes Payable	1.0
Other Current Liabilities	17.5	16.1
Total Current Liabilities	154.4	126.9
Deferred Income Taxes	46.3	43.8
Noncurrent Liabilities:
Energy Supply Contract Obligations	4.2	12.6
Retirement Benefit Obligations	91.2	74.0
Environmental Obligations	14.5	14.5
Other Noncurrent Liabilities	8.1	8.5
Total Noncurrent Liabilities	118.0	109.6
TOTAL CAPITALIZATION AND LIABILITIES	$ 800.2	$ 759.6

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Activities:
Net Income	$ 16.4	$ 9.6	$ 10.0
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	29.3	28.9	27.4
Deferred Taxes Provision	8.7	10.5	7.1
Changes in Working Capital Items:
Accounts Receivable	(7.3)	(3.4)	6.2
Accrued Revenue	(9.9)	(2.7)	12.9
Taxes Refundable / Payable	8.5	(5.8)	1.5
Gas Inventory	(4.2)	3.7	17.3
Accounts Payable	(0.1)	1.4	(3.4)
Other Changes in Working Capital Items	(0.7)	(5.3)	(5.1)
Deferred Regulatory and Other Charges	7.5	(4.5)	(26.0)
Other, net	(2.3)	(6.5)	3.0
Cash Provided by Operating Activities	45.9	25.9	50.9
Investing Activities:
Property, Plant and Equipment Additions	(57.1)	(49.6)	(58.7)
Acquisitions, net (See Note 2)			(6.9)
Cash (Used In) Investing Activities	(57.1)	(49.6)	(65.6)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	21.1	2.3	(9.6)
Proceeds from Issuance (Repayment) of Long-Term Debt, net	(0.5)	39.5	(0.4)
Net Increase (Decrease) in Gas Inventory Financing	4.6	(2.2)	(21.8)
Dividends Paid	(15.2)	(15.0)	(13.2)
Proceeds from Issuance of Common Stock	1.0	0.9	56.4
Other, net	(1.2)	(0.6)	(0.5)
Cash Provided by Financing Activities	9.8	24.9	10.9
Net Increase (Decrease) in Cash	(1.4)	1.2	(3.8)
Cash at Beginning of Year	8.9	7.7	11.5
Cash at End of Year	7.5	8.9	7.7
Supplemental Information:
Interest Paid	21.2	20.5	19.3
Income Taxes (Refunded) Paid	$ (7.3)	$ 2.3	$ (3.8)

Consolidated Statements Of Changes In Common Stock Equity - USD ($) $ in Millions	Common Equity [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2008	$ 102.7	$ 36.8	$ 139.5
Net Income		10.0	10.0
Dividends		(13.2)	(13.2)
Shares Issued Under Stock Plans	0.4		0.4
Issuance of Common Shares	0.9		0.9
Issuance of Common Shares	55.5		55.5
Balance at Dec. 31, 2009	159.5	33.6	193.1
Net Income		9.6	9.6
Dividends		(15.0)	(15.0)
Shares Issued Under Stock Plans	0.4		0.4
Issuance of Common Shares	0.9		0.9
Balance at Dec. 31, 2010	160.8	28.2	189.0
Net Income		16.4	16.4
Dividends		(15.2)	(15.2)
Shares Issued Under Stock Plans	0.5		0.5
Issuance of Common Shares	1.0		1.0
Balance at Dec. 31, 2011	$ 162.3	$ 29.4	$ 191.7

- Definition

This element represents the amount of recognized equity-based compensation during the period, that is, the amount recognized as expense in the income statement (or as asset if compensation is capitalized). Alternate captions include the words "stock-based compensation".

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- Definition

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

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-Appendix A

+ Details

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

Note 1: Summary of Significant Accounting Policies

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

The Company's results will reflect the seasonal nature of the natural gas distribution business. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher due to heating-related requirements, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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

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

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

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

Basis of Presentation

Principles of Consolidation—The Company's consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation.

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 Accounting Standards Codification (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.


	December 31,
Regulatory Assets consist of the following (millions)	2011		2010
Energy Supply Contract Obligations	$	12.9	$	21.7
Deferred Restructuring Costs		21.8		25.0

Subtotal—Restructuring Related Items		34.7		46.7
Retirement Benefit Obligations		55.3		47.1
Income Taxes		10.9		12.7
Environmental Obligations		17.5		20.3
Deferred Storm Charges		22.4		21.0
Other		17.8		10.9

Total Regulatory Assets	$	158.6	$	158.7
Less: Current Portion of Regulatory Assets ⁽¹⁾		18.8		15.7

Regulatory Assets—noncurrent	$	139.8	$	143.0

⁽¹⁾

Reflects amounts included in Accrued Revenue on the Company's Consolidated Balance Sheets.

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.

Cash—Cash includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company's cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil's affiliates Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil's affiliates provide cash deposits covering approximately 2-1/2 months of outstanding obligations. On December 31, 2011 and 2010, the Unitil affiliates had deposited $4.6 million and $7.0 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. On December 31, 2011 and 2010, there was $2.6 million and $1.5 million, respectively, deposited for this purpose.

Goodwill and Intangible Assets—As a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the Acquisitions, as authorized by regulators. As of December 31, 2011, the unamortized balance of the bargain purchase adjustment was $17.1 million, to be amortized over the next seven years.

Off-Balance Sheet Arrangements—As of December 31, 2011, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases (See Note 3).

Derivatives—The Company has a regulatory commission 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 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 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), 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 December 31, 2011 and December 31, 2010, the Company had 1.6 billion and 1.3 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 then reclassified to Purchased Gas in accordance with the recovery mechanism. The tables below include disclosure of the Regulatory Asset and reclassifications from the Regulatory Asset into Purchased Gas.

Fair Value Amount (millions) Offset in Regulatory Assets ⁽¹⁾, as of:


		Fair Value
Description	Balance Sheet Location	December 31, 2011		December 31, 2010
Natural Gas Futures Contracts	Other Current Liabilities	$	1.7	$	0.8
Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.6		0.2

Total		$	2.3	$	1.0

⁽¹⁾	The current portion of Regulatory Assets is recorded as Accrued Revenue on the Company's Consolidated Balance Sheets.


	Twelve Months Ended December 31,
(millions)	2011		2010
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	2.9	$	3.9

Amount of Loss Reclassified into Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	1.6	$	5.2

⁽ ² ⁾

These amounts are offset in the Consolidated Statements of Earnings with the recognition of accrued revenue as a component of Gas Operating Revenue and therefore there is no effect on earnings.

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

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of the Company's Massachusetts combination electric and natural gas distribution utility, Fitchburg. Revenue decoupling is the term given to the elimination of the dependency of a utility's distribution revenue on the volume of electricity or natural gas sales. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company's other electric and natural gas distribution utilities are not subject to RDM.

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

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.

Retirement Benefit Obligations—The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of its employees. The Company also sponsors an unfunded retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company, and an employee 401(k) savings plan. Additionally, the Company sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates. (See Note 9).

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

Commitments and Contingencies—The Company's accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2011, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company's consolidated financial statements below. (See Note 5).

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.28%, 2.25% and 3.24% in 2011, 2010 and 2009, respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of and the cost of removal, less salvage, are 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, depreciation amounts to provide for future negative salvage value. At December 31, 2011 and 2010, the Company estimates that the negative salvage value of future retirements recorded on the consolidated balance sheets in Accumulated Depreciation is $46.5 million and $40.8 million, respectively.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company's fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company's consolidated financial statements. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2011 – 3.43%, 2010 – 3.99% and 2009 – 4.02%.

Gas Inventory—The weighted average cost methodology is used to value natural gas in storage.

Environmental Matters—The Company's past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company has recovered or will recover substantially all of the costs of the environmental remediation work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2011, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 5, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company's financial position if those amounts are not recoverable in regulatory rate mechanisms.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation using the fair value-based method (See Note 2).

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

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

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company's 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.

Dividends—The Company's dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors. For the years ended December 31, 2011, 2010 and 2009, the Company paid a dividend at an annual rate of $1.38 per common share.

Other Recently Issued Pronouncements—In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-11, "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities." The amendments in this ASU require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The Company does not expect that the adoption of ASU 2011-11 will have a significant, if any, impact on the Company's Consolidated Financial Statements.

In May 2011, the FASB issued ASU No. 2011-04, "Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS", (ASU 2011-04). This update changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited, and requires prospective application. The Company does not expect that the adoption of ASU 2011-04 will have a significant, if any, impact on the Company's Consolidated Financial Statements.

Subsequent Events—The Company evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that 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.

Equity

12 Months Ended

Dec. 31, 2011

Equity [Abstract]

Equity

Note 2: Equity

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

Common Stock

The Company's common stock trades under the symbol, "UTL." On April 21, 2011, the Company's shareholders approved an increase in the authorized shares of the Company's common stock. Shareholders approved an amendment to the Company's Articles of Incorporation to increase the authorized number of shares of the Company's common stock, from 16,000,000 shares to 25,000,000 shares in the aggregate. The Company had 10,954,065, and 10,890,262 of common shares outstanding at December 31, 2011 and December 31, 2010, respectively.

Dividend Reinvestment and Stock Purchase Plan—During 2011, the Company sold 39,473 shares of its common stock, at an average price of $24.97 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.0 million. The DRP provides participants in the plan a method for investing cash dividends on the Company's common stock and cash payments in additional shares of the Company's common stock. During 2010 and 2009, the Company raised $0.9 million and $0.9 million, respectively, of additional common equity through the issuance of 41,455 and 43,615 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Shares Repurchased, Cancelled and Retired—Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on March 24, 2011, the Company may periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors' annual retainer. (See Part II, Item 5 for additional information). During 2011, 2010 and 2009, the Company repurchased 8,765, 3,225 and 3,619 shares of its common stock, respectively, pursuant to the Rule 10b5-1 trading plan. The expense recognized by the Company for these repurchases was $0.2 million, $0.1 million and $0.1 million in 2011, 2010 and 2009, respectively.

During 2011, 2010 and 2009, the Company did not cancel or retire any of its common stock.

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

Stock Plan—The Company maintains the Amended and Restated Unitil Corporation 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors from the eligible Participants to receive an annual award of restricted shares of Company common stock. The Compensation Committee has the power 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. 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 the 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. The maximum number of shares of restricted stock available for awards to participants under the Stock Plan is 177,500. The maximum aggregate number of shares of restricted stock 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 proportionate adjustments to prevent dilution or enlargement of rights, including, without limitation, an adjustment in the maximum number and kinds of shares available for awards and in the annual award limit.

Restricted shares issued for 2009 – 2011 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
2/17/09	32,260	$0.7
2/5/10	12,520	$0.3
2/9/11	24,330	$0.6

The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $0.7 million, $0.5 million and $0.7 million in 2011, 2010 and 2009, respectively. There were 33,731 and 29,521 non-vested shares under the Stock Plan as of December 31, 2011 and 2010, respectively. The weighted average grant date fair value of these shares was $21.93 per share and $21.77 per share, respectively. At December 31, 2011, there was approximately $0.9 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.4 years. There were no forfeitures or cancellations under the Stock Plan during 2011.

The Stock Plan also includes restricted stock units as a type of award that the Company may grant to the Company's employees, Directors or consultants. There were no restricted stock units issued under the Stock Plan during 2011.

Unitil Corporation 1998 Stock Option Plan—The "Unitil Corporation 1998 Stock Option Plan" became effective on December 11, 1998 and was terminated by the Board of Directors on January 16, 2003. There was no compensation expense associated with this plan in 2011, 2010 and 2009. The plan has remained in effect solely for the purposes of the continued administration of any options outstanding under the plan. No further grants of options have been made under this plan since it was terminated by the Board of Directors in 2003. As of December 31, 2011, 2010 and 2009, there was no aggregate intrinsic value of the options exercisable. As of December 31, 2011, all options under this plan have expired.


	2011					2010					2009
	Number of Shares			Average Exercise Price		Number of Shares			Average Exercise Price		Number of Shares			Average Exercise Price
Beginning Options Outstanding		33,000		$	25.88		63,500		$	28.90		97,200		$	27.16
Options Granted		—			—		—			—		—			—
Options Exercised		—			—		—			—		—			—
Options Forfeited / Expired		(33,000	)	$	25.88		(30,500	)	$	32.17		(33,700	)	$	23.88

Ending Options Outstanding		—		$	—		33,000		$	25.88		63,500		$	28.90

Options Vested and Exercisable- end of year		—		$	—		33,000		$	25.88		63,500		$	28.90

Preferred Stock

Two of Unitil's distribution companies, Unitil Energy and Fitchburg, have an aggregate of $2.0 million of preferred stock outstanding. At December 31, 2011, Unitil Energy has $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock series outstanding and Fitchburg has two series of Redeemable, Cumulative Preferred Stock outstanding, $0.8 million of 5.125% Series and $1.0 million of 8.00% Series.

Fitchburg is required to offer to redeem annually a given number of shares of each series of Redeemable, Cumulative Preferred Stock and to purchase such shares that shall have been tendered by holders of the respective stock. In addition, Fitchburg may opt to redeem the Redeemable, Cumulative Preferred Stock at a given redemption price, plus accrued dividends.

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2011, 2010 and 2009 related to the annual redemption offer were $8,600, $25,000 and $26,000, respectively. The aggregate amount of sinking fund requirements of the Redeemable, Cumulative Preferred Stock for each of the five years following 2011 is $117,000 per year.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.


(Millions except shares and per share data)	2011		2010		2009
Earnings Available to Common Shareholders	$	16.3	$	9.5	$	9.9

Weighted Average Common Shares Outstanding—Basic (000's)		10,880		10,823		9,647
Plus: Diluted Effect of Incremental Shares (000's)		3		1		—
Weighted Average Common Shares Outstanding—Diluted (000's)		10,883		10,824		9,647

Earnings per Share—Basic and Diluted	$	1.50	$	0.88	$	1.03

Weighted average options to purchase 33,000 and 63,500 shares of common stock were outstanding during 2010 and 2009, respectively, but were not included in the computation of Weighted Average Common Shares Outstanding for purposes of computing diluted earnings per share, because the effect would have been antidilutive. Additionally, 1,642, 6,164 and 28,963 weighted average non-vested restricted shares for 2011, 2010 and 2009, respectively, were not included in the above computation because the effect would have been antidilutive.

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

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-Name Accounting Principles Board Opinion (APB)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 29, 30, 31
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Long-Term Debt, Credit Arrangements, Leases And Guarantees

12 Months Ended

Dec. 31, 2011

Long-Term Debt, Credit Arrangements, Leases And Guarantees [Abstract]

Long-Term Debt, Credit Arrangements, Leases And Guarantees

Note 3: Long-Term Debt, Credit Arrangements, Leases and Guarantees

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

Long-Term Debt and Interest Expense

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

The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt's negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of Unitil Energy and Fitchburg or certain other actions against Unitil subsidiaries.

Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met, including that Unitil Energy have sufficient available net bondable plant to issue the securities and projected earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt's negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary's long-term debt agreements. Each of the Fitchburg, Northern Utilities and Granite State default provisions are not triggered by the actions or defaults of Unitil or any of its other subsidiaries.

The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets. The Granite State notes are guaranteed by Unitil for the payment of principal, interest and other amounts payable. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.

At December 31, 2011, there were no restrictions on Unitil's Retained Earnings for the payment of common dividends. Unitil Energy, Fitchburg, Northern Utilities and Granite State pay dividends to their sole shareholder, Unitil Corporation, and these dividends are the primary source of cash for the payment of dividends to Unitil's common shareholders.

Debt Repayment—The total aggregate amount of debt repayments relating to bond issues and normal scheduled long-term debt repayments amounted to $462,055, $426,643, and $393,946 in 2011, 2010, and 2009, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2011 is: 2012 – $500,405; 2013 – $541,938; 2014 – $2,486,919; 2015 – $4,035,633; and 2016 – $17,421,724, respectively.

Long-Term Debt Issuances

On March 2, 2010, both Unitil Energy and Northern Utilities closed long-term financings:

(i)

Unitil Energy closed $15,000,000 of First Mortgage Bonds, through a private placement marketing process to institutional investors. The First Mortgage Bonds have a coupon rate of 5.24% and have a final maturity of ten years. Unitil Energy used the net proceeds from this long-term financing to repay short-term debt and for general corporate purposes.

(ii)

Northern Utilities closed $25,000,000 of Senior Unsecured Notes, through a private placement marketing process to institutional investors. The Senior Unsecured Notes have a coupon rate of 5.29% and have a final maturity of ten years. Northern Utilities used the net proceeds from this long-term financing to repay short-term debt and for general corporate purposes.

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. 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 for December 2011. The carrying value of the Company's long-term debt at December 31, 2011 is $288.3 million. The fair value of the Company's long-term debt at December 31, 2011 is estimated to be approximately $338.7 million. Costs, including prepayment costs, associated with the early settlement of long-term debt are not taken into consideration in determining fair value.

Details on long-term debt at December 31, 2011 and 2010 are shown below:


	December 31,
Long-Term Debt (millions)	2011		2010
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0

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

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

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

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

Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		3.3		3.8

Total Long-Term Debt		288.3		288.8
Less: Current Portion		0.5		0.5

Total Long-Term Debt, Less Current Portion	$	287.8	$	288.3

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

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

A summary of interest expense and interest income is provided in the following table:


Interest Expense, net (millions)
	2011			2010			2009
Interest Expense
Long-term Debt	$	20.3		$	20.0		$	18.2
Short-term Debt		1.7			1.7			2.1
Regulatory Liabilities		—			0.3			0.3

Subtotal Interest Expense		22.0			22.0			20.6

Interest Income
Regulatory Assets		(1.1	)		(3.5	)		(3.6	)
AFUDC⁽¹⁾ and Other		(0.5	)		(0.4	)		(1.2	)

Subtotal Interest Income		(1.6	)		(3.9	)		(4.8	)

Total Interest Expense, net	$	20.4		$	18.1		$	15.8

⁽¹⁾

AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

Unitil has a revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit facility was $115.0 million at December 31, 2011 and $80.0 million at December 31, 2010. There was $87.9 million and $66.8 million in short-term debt outstanding through bank borrowings under the revolving credit facility at December 31, 2011 and December 31, 2010, respectively. The total amount of credit available under the Company's revolving credit facility was $27.1 million and $13.2 million at December 31, 2011 and December 31, 2010, respectively. 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 December 31, 2011 and December 31, 2010, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

On October 12, 2011, Unitil entered into the Fifth Amendment agreement with Bank of America, N.A., as administrative agent, and a syndicate of other lenders party thereto, further amending the revolving credit agreement dated as of November 26, 2008. The revolving credit agreement was previously amended on January 2, 2009, March 16, 2009, October 13, 2009 and October 8, 2010 to, among other things, increase the maximum borrowings under the facility, provide for a base rate interest rate option, reflect letter of credit availability, modify certain financial reporting requirements and extend the scheduled termination date of the facility. The Fifth Amendment agreement increased the maximum borrowings under the facility to $115 million, changed the additional interest margin applicable to borrowings at a fluctuating rate of interest per annum equal to the daily London Interbank Offered Rate from 2.00% to 1.75%, and changed the annual letter of credit fee from 1.625% of the daily amount available to be drawn under letters of credit issued under the credit facility to 1.500% of such daily amount.

The weighted average interest rates on all short-term borrowings were 2.2%, 2.3%, and 3.4% during 2011, 2010, and 2009, respectively.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $14.9 million and $11.7 million outstanding at December 31, 2011 and 2010, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2011, which was payable in January 2012, is $2.5 million and recorded in Accounts Payable at December 31, 2011. The amount of natural gas inventory released in December 2010, which was payable in January 2011, is $3.9 million and recorded in Accounts Payable at December 31, 2010.

Leases

Unitil's subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.

Total rental expense under operating leases charged to operations for the years ended December 31, 2011, 2010 and 2009 amounted to $1.4 million, $1.0 million and $1.0 million respectively. Fitchburg leases its operations facility in Fitchburg, Massachusetts under an operating lease, with a primary term through January 31, 2013. The lease agreement allows for three additional five-year renewal periods at the option of Fitchburg.

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2011:


Year Ending December 31, (000's)	Operating Leases		Capital Leases
2012	$	1,187	$	829
2013		822		513
2014		584		161
2015		474		28
2016		240		9
2017 – 2021		178		—

Total Payments	$	3,485	$	1,540

Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company's policy is to limit the duration of these guarantees. As of December 31, 2011, there were approximately $37.2 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 December 31, 2011, the principal amount outstanding for the 8% Unitil Realty notes was $3.3 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Energy Supply	12 Months Ended
Energy Supply	Dec. 31, 2011
Energy Supply [Abstract]
Energy Supply	Note 4: Energy Supply Natural Gas Supply Unitil manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts. Fitchburg's residential and C&I business customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors. Many large and some medium C&I customers purchase their supplies from third-party suppliers, while most of Fitchburg's residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. Northern Utilities' C&I customers have the opportunity to purchase their natural gas supply from third-party gas supply vendors, and third-party supply is prevalent among Northern Utilities' larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. The approved costs associated with the acquisition of such wholesale natural gas supplies for customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically-adjusted rates and are included in Purchased Gas in the Consolidated Statements of Earnings. On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered the Company's electric and natural gas distribution utility, Fitchburg, to refund $4.6 million of natural gas costs, plus interest. The MDPU's original order, issued in 2009, found that Fitchburg had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU's prior approval and that Fitchburg's natural gas purchasing practices were imprudent. The Company appealed the MDPU's decision to the SJC. The SJC's decision vacates the MDPU's order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU's original order. As a result of the decision, the Regulatory Liability has been adjusted and the Company recognized a pre-tax credit of $4.7 million in the fourth quarter of 2011. This credit is recognized on the Company's 2011 Consolidated Statement of Earnings as a $4.5 million reduction in Purchased Gas expense and a reduction of $0.2 million in Interest Expense, net. Regulated Natural Gas Supply Fitchburg purchases natural gas under contracts of one year or less, as well as from producers and marketers on the spot market. Fitchburg arranges for gas delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, or in the case of liquefied natural gas (LNG) or liquefied propane gas (LPG), to truck supplies to storage facilities within Fitchburg's service territory. Fitchburg has available under firm contract 14,057 MMbtu per day for transportation and underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and a LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas. Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas delivery to its system through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of LNG, to truck supplies to storage facilities within Northern Utilities' service territory. Northern Utilities has available under firm contract 100,000 MMbtu per day of year-round and seasonal transportation capacity to its distribution facilities, and 3.4 Bcf of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas. Electric Power Supply The restructuring of the electric utility industry in New Hampshire required the divestiture of Unitil's power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility energy service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the ISO New England, Inc. (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil's customers. As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil's customers in both New Hampshire and Massachusetts have the opportunity to purchase their electric supply from competitive third-party energy suppliers. As of December 2011, 106 or 71% of Unitil's largest New Hampshire customers, representing 25% of total New Hampshire electric energy sales, and 28 or 93% of Unitil's largest Massachusetts customers, representing 33% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. Regulated Electric Power Supply In order to provide regulated electric supply service to their customers, Unitil's electric distribution utilities enter into load-following wholesale electric power supply contracts with various wholesale suppliers. Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Currently, all Basic Service power supply contracts for large general accounts are three months in duration and provide 100% of supply requirements. Basic Service power supply contracts for residential, small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Unitil Energy procures Default Service supply for its large general service accounts through competitive solicitations for power contracts of three months in duration for 100% of supply requirements. Unitil Energy procures Default Service supply for its other customers through a series of two one-year contracts and two two-year contracts, each providing 25% of the total supply requirements of the group. The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure. Regional Electric Transmission and Power Markets Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economic manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. The ISO-NE tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated power system operation in a reliable manner and a supportive business environment for the development of competitive electric markets. Electric Power Supply Divestiture In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Commitments And Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments And Contingencies

Note 5: Commitments and Contingencies

Regulatory Matters

Overview (Unitil Energy, Fitchburg, and Northern Utilities)—Unitil's distribution utilities deliver electricity and/or natural gas to customers in the Company's service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. As a result of the restructuring of the utility industry in New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next one to three years, is $34.7 million as of December 31, 2011 including $12.4 million recorded in Current Assets as Accrued Revenue on the Company's Consolidated Balance Sheet. Unitil's distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Fitchburg—Increase in Base Rates Approved—On August 1, 2011, the MDPU issued and order approving increases of $3.3 million and $3.7 million in annual distribution revenues for Fitchburg's electric and gas divisions, respectively. The MDPU also approved revenue decoupling mechanisms and a return on equity of 9.2% for both the electric and gas divisions of Fitchburg. The rate increase for Fitchburg's electric division included the recovery of $11.4 million of previously deferred emergency storm restoration costs associated with the December 2008 ice storm, which costs are to be amortized and recovered over seven (7) years without carrying costs. The order provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Granite State—Increase in Base Rates Approved—On January 31, 2011, the FERC approved a settlement agreement providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. Subsequently, on August 31, 2011, the FERC approved an amendment to the settlement agreement which provides for an additional increase of approximately $0.5 million in Granite State's annual revenues effective August 1, 2011. Under the amended settlement agreement, beginning in 2012, Granite State is permitted to file limited annual rate adjustment filings to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects. The limited rate adjustments would be effective August 1 of each year, and are projected to conclude in 2014 when the major projects will be completed. The annual revenue increases for the limited rate adjustments are estimated to be approximately $0.5 million each year during 2012 through 2014.

Unitil Energy—Increase in Base Rates Approved—On April 26, 2011, the NHPUC approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue effective July 1, 2010, and provides for 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 estimated future increases of $1.5 million to $2.0 million in annual revenue to occur on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy's continued capital improvements to its distribution system. The rate plan allows Unitil to file for additional rate relief if its return on equity is less than 7% and a sharing of earnings with customers if its return on equity is greater than 10% in a calendar year. The settlement provides for a return on equity of 9.67%, a common equity ratio of 45.45% and an overall weighted cost of capital of 8.39% to determine changes to distribution rate levels.

The settlement approved Unitil Energy's proposal for an augmented vegetation management program and reliability enhancement program. Under the augmented vegetation management program, Unitil Energy will be increasing its vegetation management spending from a test-year spending level of approximately $0.7 million to $3.1 million per year by 2013. Under the new reliability enhancement program, Unitil Energy will spend $1.8 million annually towards targeted projects designed to enhance system reliability. The funding for both of these programs is included in the future rate increases discussed above.

The settlement provides for recovery of deferred December 2008 ice storm and February 2010 wind storm costs of approximately $7.6 million, including carrying charges. These costs will be recovered over eight years in the form of a tariff surcharge. Finally, the settlement establishes a major storm reserve of $400,000 annually, which will be used to recover costs associated with responding to and recovering from future qualifying major storm events.

Northern Utilities—Base Rate Case Filings—In May 2011, 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 and Maine, respectively.

On November 29, 2011, the MPUC approved a comprehensive settlement agreement providing for a $7.8 million permanent increase in annual distribution revenue for Northern Utilities' Maine operations, effective January 1, 2012, and an additional permanent increase in annual distribution revenue of $0.85 million to recover the costs of 2011 cast iron pipe replacement capital spending effective May 1, 2012. The settlement is inclusive of an earlier settlement for a temporary rate increase of $3.5 million in annual distribution revenue effective November 1, 2011. The settlement also precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

In New Hampshire, Northern Utilities requested an increase of $5.2 million in annual gas distribution base revenue, which represents an increase of approximately 8.1%. On July 22, 2011, the NHPUC approved a settlement for a temporary rate increase of approximately $1.7 million in annual revenue effective August 1, 2011. Once permanent rates are approved by the NHPUC, they will be reconciled back to August 1, 2011. The Company is currently in settlement discussions with the NHPUC and a final rate order is expected in the first quarter of 2012.

Fitchburg—Management Audit—As a result of its investigation of Fitchburg's preparation for, and response to, the December 2008 ice storm, the MDPU ordered a comprehensive independent management audit of Fitchburg's management practices. The management audit, which was performed by Jacobs Consultancy, Inc. (Jacobs), was completed and the audit report was submitted by Jacobs to the MDPU on April 13, 2011. The audit report found Unitil's management practices to be comprehensive, sound and in-line with industry practice. It also included sixteen recommendations intended to further improve the results of Unitil's management strategy, and acknowledged that many of these recommendations were already being implemented by the Company. On September 1, 2011, the MDPU issued its order with respect to the audit, accepting the majority of Jacob's audit report, and requiring the company to implement the remaining recommendations, as well as provide semi-annual status updates as to the company's implementation progress. On September 30, 2011, the Company filed its first implementation status report with the MDPU.

Fitchburg—Electric Operations—On November 30, 2011, Fitchburg submitted its annual reconciliation of costs and revenues for Transition and Transmission under its restructuring plan. The filing includes the reconciliation of costs and revenues for a number of surcharges and cost factors which are under individual review in separate proceedings before the MDPU, including the Pension/PBOP Adjustment, Residential Assistance Adjustment Factor, Net Metering Recovery Surcharge, Attorney General Consultant Expense Factor and Revenue Decoupling Adjustment Factor. The rates were approved effective January 1, 2012, subject to reconciliation pending investigation by the MDPU. This matter remains pending. Final orders on Fitchburg's 2009 and 2010 annual reconciliation filings also remain pending.

Fitchburg—Gas Operations—On November 2, 2011, the SJC issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU's original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU's prior approval and that the Company's natural gas purchasing practices were imprudent. The Company appealed the MDPU's decision to the SJC. The SJC's decision vacates the MDPU's order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU's original order. As a result of the decision, the Regulatory Liability was adjusted and the Company recognized a credit of $4.7 million in the fourth quarter of 2011.

On December 28, 2011, the MDPU approved Fitchburg's proposal to discontinue the previously ordered refund of the $4.6 million of natural gas costs, and to begin the recoupment of the amounts previously refunded, with interest, effective January 1, 2012. In order to minimize the rate impact on customers, the recoupment will occur over the next three winter heating seasons.

Fitchburg—Storm Cost Deferral Petition—On December 16, 2011, Fitchburg filed a request with the MDPU for authorization to defer, for future recovery in rates, the costs incurred to perform storm-related emergency repairs on its electric distribution system as a result of two recent storms, Tropical Storm Irene, which occurred on August 28, 2011, and a severe snow storm, which occurred on October 29-30, 2011. Fitchburg estimates that it incurred $1.5 million in costs for Tropical Storm Irene and $3.2 million in costs for the October snow storm. Fitchburg also requested that it be allowed to accrue carrying charges on the deferred amount. This matter remains pending.

Fitchburg—Other—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 matter of how 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, 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 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 are under review in a separately designated docket.

On March 1, 2011, Fitchburg submitted its 2010 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 January 13, 2012, the MDPU issued its order approving the 2010 Service Quality Report for Fitchburg's gas division. On January 26, 2011, the MDPU issued orders with respect to Fitchburg's 2008 and 2009 Service Quality Reports for its electric division. Fitchburg failed to meet certain of its service quality benchmarks in 2008, and a penalty of $100,478 was ordered to be refunded to its electric customers. The Company refunded this amount to customers in their June and July 2011 billings. For 2009 performance, no net penalty was assessed. As required by the order, on February 16, 2011 Fitchburg filed a report regarding the actions it has taken to improve its performance in the metrics it had not met.

Unitil Energy—Annual Rate Reconciliation Filing—On July 29, 2011, the NHPUC approved Unitil Energy's annual reconciliation and rate filing under its restructuring plan, for rates effective August 1, 2011, including reconciliation of prior year costs and revenues.

Unitil Energy—Billing—In August 2011, Unitil Energy and one of its larger customers in New Hampshire settled a lawsuit filed by the customer in June 2011 regarding a billing error that resulted from a transformer connected to the customer's meter, which had been mislabeled by the manufacturer, and caused Unitil Energy to overcharge the customer for bills issued from October 2004 through January 2011. The amount of the customer's overpayment was calculated to be $1.8 million (Distribution and Other Delivery Charges—$0.5 million; Supply Charges—$1.3 million). As a result of the settlement, Unitil Energy reimbursed the customer $1.8 million plus $0.3 million of interest. The Company recognized a non-recurring charge of $0.4 million for distribution charges plus interest in 2011.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company's service territory were under-billed from October 2004 through January 2011 for supply charges. Accordingly, the Company has requested authorization from the NHPUC to process the billing correction. The Company's request remains pending before the NHPUC.

Northern Utilities—NOPV—On November 21, 2008, the MPUC issued an order approving a settlement agreement resolving a number of Notices of Probable Violation (NOPVs) of certain safety related procedures and rules by Northern Utilities. Under the Settlement, Northern Utilities will incur total expenditures of approximately $3.8 million for safety related improvements to Northern Utilities' distribution system to ensure compliance with the relevant state and federal gas safety laws, for which no rate recovery will be allowed. These compliance costs were accrued by Northern Utilities prior to the acquisition date and the remaining amount on the Company's consolidated balance sheet at December 31, 2011 was $0.8 million.

Northern Utilities—Cast Iron Pipe Replacement Program—On July 30, 2010, the MPUC approved a Settlement Agreement providing for an accelerated replacement program for cast iron distribution pipe remaining in portions of Northern Utilities' Maine service areas. Under the Agreement, Northern Utilities will proceed with a comprehensive upgrade and replacement program (the Program), which will provide for the systematic replacement of cast iron, wrought iron and bare steel pipe in Northern Utilities' natural gas distribution system in Portland and Westbrook, Maine and the conversion of the system to intermediate pressure. The Agreement establishes the objective of completing the Program by the end of the 2024 construction season.

Northern Utilities—Maine Sales Tax Under-Collection—As previously reported, during 2011 the Company determined that during the conversion of the Northern Utilities customer portfolio from the prior owner to Unitil's customer information system, a portion of Northern Utilities' commercial and industrial customers were incorrectly converted as exempt from Maine sales tax. This issue has been resolved with Maine Revenue Services and the MPUC and the Company has collected substantially all of the arrears.

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 will evaluate 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 Company expects the final audit report will be issued by December 31, 2012.

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.

A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. On April 1, 2009, an Amended Complaint was filed in Worcester Superior Court and served on Fitchburg. The Amended 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 Amended Complaint 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 Superior Court issued its order on the Company's Motion to Dismiss the Complaint, granting it in part and denying it in part. The Company anticipates that the court will decide whether the lawsuit is appropriate for class action treatment in late 2012. The Company continues to believe the suit is without merit and will defend itself vigorously.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU's original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU's prior approval and that the Company's natural gas purchasing practices were imprudent. The Company appealed the MDPU's decision to the SJC. The SJC's decision vacates the MDPU's order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. See additional discussion above in Regulatory Matters.

Environmental Matters

The Company's past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2011, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance 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 continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allows Fitchburg to work towards temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed and completed.

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. Fitchburg had filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. In January 2011, Fitchburg settled with the remaining insurance carriers for approximately $2.0 million and received these payments in the first quarter of 2011. Any recovery that Fitchburg receives from insurance or third-parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are shared equally between Fitchburg and its gas customers.

Fitchburg is in the process of developing long-range plans for a feasible permanent remediation solution for the Sawyer Passway site, including alternatives for re-use of the site. Included on the Company's Consolidated Balance Sheets at December 31, 2011 and 2010 in Environmental Obligations are accrued liabilities totaling $12.0 million and $12.0 million, respectively, related to estimated future clean-up 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.

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, and Scarborough sites. The sites in Lewiston and Portland have been investigated and remedial activities are currently underway. 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 the Company's Consolidated Balance Sheets at December 31, 2011 and 2010 are current and non-current accrued liabilities totaling $2.7 million and $2.6 million, respectively, associated with Northern Utilities environmental remediation obligations for these former MGP sites. A corresponding Regulatory Asset was recorded to reflect that the recovery of these environmental remediation cost is probable through the regulatory process.

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

The following table shows the balances and activity in the Company's liability for Environmental Obligations for 2011 and 2010.

ENVIRONMENTAL OBLIGATIONS


(Millions)	December 31,
	2011		2010
Total Environmental Obligations—Balance at Beginning of Period	$	14.6	$	14.5
Changes in Estimates		0.1		0.2
Liabilities Assumed		—		—
Less: Payments / Reductions		—		0.1

Total Environmental Obligations—Balance at End of Period		14.7		14.6
Less: Current Portion ⁽¹⁾		0.2		0.1

Environmental Obligations – noncurrent – Balance at End of Period	$	14.5	$	14.5

⁽¹⁾	Reflects amounts included in Other Current Liabilities on the Company's Consolidated Balance Sheets.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name FASB Interpretation (FIN)
-Number 14
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

+ Details

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

Note 7: Income Taxes

Provisions for Federal and State Income Taxes reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2011, 2010 and 2009 are shown in the table below:


	($000's)
	2011			2010			2009
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	(6,026	)	$	(3,226	)

Total Current Federal Tax Provision (Benefit)		—			(6,026	)		(3,226	)

Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		13,002			11,821			8,716
Net Operating Loss Carryforwards		(4,844	)		(5,520	)		—
Regulatory Assets and Liabilities		513			3,338			(1,308	)
Other, net		(695	)		(480	)		(120	)

Total Deferred Federal Tax Provision (Benefit)		7,976			9,159			7,288

Total Federal Tax Provision		7,976			3,133			4,062

State
Current		1,358			28			1,578
Deferred		691			1,303			(218	)

Total State Tax Provision		2,049			1,331			1,360

Total Provision for Federal and State Income Taxes	$	10,025		$	4,464		$	5,422

The differences between the Company's provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:


	2011			2010			2009
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			6			6
Utility Plant Differences		(1	)		(7	)		(3	)
Other, Net		—			(1	)		(1	)

Effective Income Tax Rate		38	%		32	%		36	%

Temporary differences which gave rise to deferred tax assets and liabilities in 2011 and 2010 are shown below:


Deferred Income Taxes (000's)	2011			2010
Depreciation and Utility Plant	$	57,809		$	44,608
Net Operating Loss Carryforwards		(11,656	)		(8,567	)
AMT Tax Credit Carryforwards		(1,366	)		(1,366	)
Regulatory Assets / Liabilities & Mechanisms		32,627			33,421
Retirement Benefit Obligations		(33,591	)		(25,155	)
Other, net		2,463			883

Total Deferred Income Tax Liabilities	$	46,286		$	43,824

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

The Company filed its tax returns for the year ended December 31, 2010 with the Internal Revenue Service (IRS) in September 2011. As a result, the Company generated net operating loss (NOL) carryforwards for income tax purposes of $9.5 million.

As of December 31, 2011, the Company had recorded cumulative federal and state NOL carryforward assets of $11.7 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, 2011, the Company had $1.4 million of Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

In its federal income tax return filings for the year ended December 31, 2009, the Company recognized NOL carrybacks against its federal taxable income for the years ended December 31, 2004, 2005, and 2007 in the amounts of $1.1 million, $12.8 million, and $9.6 million, respectively. The carryback of the 2009 NOL resulted in tax refunds of $7.5 million, which were received in 2011.

According to Internal Revenue Code (IRC) rules, NOL refunds in excess of $2.0 million fall under the jurisdiction of the Joint Committee of Congress (Joint Committee) and are subject to review by the IRS and attorneys of the Joint Committee. As a result, the Company, on April 1, 2011, received notice that its federal income tax return filing for the year ended December 31, 2009 would be under examination by the IRS. The IRS is currently performing field work as part of their audit procedures. In addition, because of the application of the 2009 NOL, tax periods ended December 31, 2004, 2005 and 2007 are subject to examination to the extent of the application of the NOL to those periods. The Company believes that the ultimate resolution of this examination will not have a material impact on the Company's consolidated financial position or results of operations.

On March 3, 2011 the Company received notice of approval from the Joint Committee regarding the settlement between the Company and the IRS for tax years ending December 31, 2006, December 31, 2007, and December 31, 2008, which were previously under examination. As a result of the settlement, in November 2010, the Company paid $1.7 million and $0.2 million in taxes and interest, respectively, principally for certain timing items deducted in 2008 related to emergency storm restoration costs; which, upon IRS review, were allowed to be deducted in the 2009 federal income tax returns. 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.

The Company evaluated its tax positions at December 31, 2011 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, 2008; December 31, 2009; and December 31, 2010.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Number 109
-Paragraph 136, 172
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Segment Information

12 Months Ended

Dec. 31, 2011

Segment Information [Abstract]

Segment Information

Note 8: Segment Information

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

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

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

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

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

The following table provides significant segment financial data for the years ended December 31, 2011, 2010 and 2009 (Millions):


Year Ended December 31, 2011	Electric		Gas			Other			Non- Regulated		Total

Revenues	$	188.1	$	159.2		$	—		$	5.5	$	352.8

Interest Income		0.7		0.5			0.1			0.1		1.4

Interest Expense		9.4		10.7			1.7			—		21.8

Depreciation & Amortization Expense		14.2		13.6			1.5			—		29.3

Income Tax Expense (Benefit)		5.2		4.3			(0.6	)		1.1		10.0

Segment Profit (Loss)		7.8		6.7			0.1			1.7		16.3

Segment Assets		380.7		407.5			6.5			5.5		800.2

Capital Expenditures		20.3		33.6			3.2			—		57.1

Year Ended December 31, 2010

Revenues	$	203.7	$	150.1		$	—		$	4.6	$	358.4

Interest Income		3.2		0.5			0.2			0.1		4.0

Interest Expense		9.6		10.5			2.0			—		22.1

Depreciation & Amortization Expense		13.9		14.2			0.8			—		28.9

Income Tax Expense (Benefit)		3.7		(0.7	)		0.5			1.0		4.5

Segment Profit (Loss)		8.0		1.4			(1.4	)		1.5		9.5

Segment Assets		377.7		370.8			5.7			5.4		759.6

Capital Expenditures		19.8		27.4			2.4			—		49.6

Year Ended December 31, 2009

Revenues	$	209.9	$	152.8		$	—		$	4.3	$	367.0

Interest Income		3.6		0.5			0.7			—		4.8

Interest Expense		9.1		9.7			1.8			—		20.6

Depreciation & Amortization Expense		14.0		12.8			0.6			—		27.4

Income Tax Expense		2.4		1.9			0.1			1.0		5.4

Segment Profit		4.9		3.3			0.1			1.6		9.9

Segment Assets		365.6		349.7			7.3			2.6		725.2

Capital Expenditures		27.7		30.0			1.0			—		58.7

- 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.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Retirement Benefit Plans

12 Months Ended

Dec. 31, 2011

Retirement Benefit Plans [Abstract]

Retirement Benefit Plans

Note 9: Retirement Benefit Plans

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

•

The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee's level of compensation and length of service. In September 2009, the Company amended the Pension Plan as follows:

•

The Pension Plan was closed to non-union employees hired on or after January 1, 2010.

•

All non-union employees hired before January 1, 2010 had a choice of either:

•

Remaining in the Pension Plan with the existing set of benefits, or

•

Electing to move to Unitil Corporation's enhanced Tax Deferred Savings and Investment Plan. Non-union employees who elected this option received a frozen benefit from the existing Pension Plan for all of the benefits that they had accrued to December 31, 2009. This frozen benefit will not grow with future salary increases or future service. Non-union employees who elected this option will receive an enhanced employer matching contribution as well as a Company contribution in the Unitil Corporation Tax Deferred Savings and Investment Plan.

•

Union employees were not affected by this amendment.

In September 2010, the Company amended the Pension Plan as follows:

•

The Pension Plan was closed to United Steelworker Local 12012-6 employees hired on or after January 1, 2011.

•

All United Steelworker Local 12012-6 employees hired before January 1, 2011 had a choice of either:

•

Remaining in the Pension Plan with the existing set of benefits, or

•

Electing to move to Unitil Corporation's enhanced Tax Deferred Savings and Investment Plan. The United Steelworker Local 12012-6 employees who elected this option received a frozen benefit from the existing Pension Plan for all of the benefits that they had accrued to December 31, 2010. This frozen benefit will not grow with future salary increases or future service. The employees who elected this option will receive an enhanced employer matching contribution as well as a Company contribution in the Unitil Corporation Tax Deferred Savings and Investment Plan.

•

All other union employees were not affected by this amendment.

•

The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan. In 2009, the Company made the following changes to the PBOP Plan.

Changes to Utility Workers Union of America Local 341 Benefits

A new Collective Bargaining Agreement (Agreement) was entered into between Northern Utilities, Granite State and the Utility Workers Union of America Local 341 (UWUA) for the period April 1, 2009 through March 31, 2012. Included in the Agreement were changes to retiree medical benefits under the Plan. These changes are as follows:

•

Retirees under sixty-five (65) years and their dependents will be covered by the medical benefits provided by the PBOP Plan. Early retirees will be responsible for contributing 20% of the premium for medical insurance for themselves and their dependents until age sixty-five (65).

•

Retirees over sixty-five (65) years will be covered by a Supplement to Medicare Plan and will be responsible for a 20% premium cost sharing.

•

For all employees hired on or after April 1, 2009, no post-65 retiree medical coverage will be provided.

•

The Company is to determine post-65 drug coverage to be offered to all future retirees eligible for retiree medical.

These above-referenced retiree medical provisions were effective January 1, 2010.

Changes to United Steelworker Local 12012-6 Benefits

A new Collective Bargaining Agreement (Agreement) was entered into between Northern Utilities and United Steelworker Local 12012-6 (USW) for the period June 6, 2010 through June 5, 2014. Included in the Agreement were changes to retiree medical benefits under the Plan. These changes are as follows:

•

Retirees over sixty-five (65) years will be covered by a Supplement to Medicare Plan and will be responsible for a 20% premium cost sharing.

•

For all employees hired on or after June 6, 2010, no post-65 retiree medical coverage will be provided.

These above-referenced retiree medical provisions were effective June 6, 2010.

Changes to Non-Union Employee Benefits

In September 2009, the Company announced the following PBOP Plan changes, effective January 1, 2010, for non-union employees:

•

Employees who retire on or after January 1, 2010 will pay 20% of the cost of their retiree medical benefits.

•

Employees who retire on or after January 1, 2010 will not receive any cash payments towards their Medicare premiums.

•

Employees who are hired on or after January 1, 2010 will only be provided with company subsidized medical insurance until they reach age 65 and will not receive a Medicare supplement plan after age 65.

•

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

Effective with the acquisitions of Northern Utilities and Granite State, the Company assumed the assets and obligations of the Northern Utilities and Granite State pension plans with respect to active union employees. All other active employees of Northern Utilities and Granite State effectively became members of the Company's Pension Plan as of the acquisitions closing date.

Certain employees of Northern Utilities qualified for participation in the Company's PBOP Plan effective with the acquisition closing date.

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


	2011			2010			2009
Used to Determine Plan costs for years ended December 31:
Discount Rate ⁽¹⁾		5.35	%		5.75	%		6.25	%
Rate of Compensation Increase		3.50	%		3.50	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.50	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000's)	$	909		$	728		$	735
Effect of 1% Decrease in Health Care Cost Trend Rate (000's)	$	(705	)	$	(565	)	$	(576	)

⁽¹⁾

As a result of the changes to the PBOP Plan in September 2009 discussed above, the Company was required to update the discount rate used in determining the PBOP Plan costs for the remainder of 2009. Based on the market rates for long-term bonds at that time, the Company assumed a discount rate of 5.50% for the PBOP Plan from September through December of 2009.


Used to Determine Benefit Obligations at December 31:
Discount Rate		4.60	%		5.35	%		5.75	%
Rate of Compensation Increase		3.00	%		3.50	%		3.50	%
Health Care Cost Trend Rate Assumed for Next Year		6.50	%		7.00	%		7.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2017			2017			2017
Effect of 1% Increase in Health Care Cost Trend Rate (000's)	$	9,109		$	7,530		$	5,887
Effect of 1% Decrease in Health Care Cost Trend Rate (000's)	$	(7,217	)	$	(5,997	)	$	(4,704	)

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2011, 2010 and 2009, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $325,000, $300,000 and $300,000, respectively, in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2011, 2010 and 2009 was 3.50%, based on the expected long-term increase in compensation costs for personnel covered by the plans.

The following table provides the components of the Company's Retirement plan costs ($000's):


	Pension Plan									PBOP Plan									SERP
	2011			2010			2009			2011			2010			2009			2011		2010		2009

Service Cost	$	2,941		$	2,608		$	2,282		$	1,918		$	1,466		$	1,417		$	285	$	285	$	217

Interest Cost		4,684			4,457			4,294			2,279			2,016			2,269			227		227		181

Expected Return on Plan Assets		(4,840	)		(4,181	)		(4,432	)		(818	)		(599	)		(440	)		—		—		—

Prior Service Cost Amortization		249			253			264			1,729			1,579			1,634			11		2		(2	)

Transition Obligation Amortization		—			—			—			21			21			21			—		—		—

Curtailment Loss		—			41			32			—			—			—			—		—		—

Actuarial Loss Amortization		3,132			2,406			1,598			—			—			—			78		133		70


Sub-total		6,166			5,584			4,038			5,129			4,483			4,901			601		647		466

Amounts Capitalized and Deferred		(2,590)			(2,240	)		(1,409	)		(1,622	)		(1,183	)		(1,642	)		—		—		—

NPBC Recognized	$	3,576		$	3,344		$	2,629		$	3,507		$	3,300		$	3,259		$	601	$	647	$	466

The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company's Retirement plan costs over the next fiscal year is $3.8 million, $1.9 million and $0.1 million for the Pension, PBOP and SERP plans, respectively.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company's pension expense for the years 2011, 2010 and 2009 before capitalization and deferral was $6.2 million, $5.6 million and $4.0 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2011, 2010 and 2009 would have been $5.7 million, $6.2 million and $6.3 million respectively.

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


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2011			2010			2011			2010			2011			2010

Plan Assets at Beginning of Year	$	54,100		$	47,082		$	8,862		$	6,306		$	—		$	—

Actual Return on Plan Assets		225			5,901			108			922			—			—

Employer Contributions		8,813			4,302			—			3,482			53			53

Participant Contributions		—			—			13			—			—			—

Acquired Plan Assets		—			—			—			—			—			—

Benefits Paid		(3,438	)		(3,185	)		(1,644	)		(1,848	)		(53	)		(53	)

Plan Assets at End of Year	$	59,700		$	54,100		$	7,339		$	8,862		$	—		$	—


Change in PBO:

PBO at Beginning of Year	$	89,393		$	79,288		$	43,344		$	35,694		$	4,263		$	3,979

Service Cost		2,941			2,608			1,918			1,466			285			285

Interest Cost		4,684			4,457			2,279			2,016			227			227

Participant Contributions		—			—			13			—			—			—

Plan Amendments		—			—			—			1,683			—			138

Curtailment Gain		—			(1	)		—			—			—			—

Benefits Paid		(3,438	)		(3,185	)		(1,644	)		(1,848	)		(53	)		(53	)

Actuarial (Gain) or Loss		9,139			6,226			5,020			4,333			(107	)		(313	)

PBO at End of Year	$	102,719		$	89,393		$	50,930		$	43,344		$	4,615		$	4,263

Funded Status: Assets vs PBO	$	(43,019	)	$	(35,293	)	$	(43,591	)	$	(34,482	)	$	(4,615	)	$	(4,263	)

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of their retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets of $55.3 million and $47.1 million at December 31, 2011 and 2010, respectively, to recognize the future collection of these plan obligations in electric and gas rates.

The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $91.3 million and $78.4 million as of December 31, 2011 and 2010, respectively. The ABO for the SERP was $0.5 million and $0.5 million as of December 31, 2011 and 2010, respectively. For the PBOP Plan, the ABO and PBO are the same.

On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA were new minimum funding rules which went into effect for plan years beginning in 2008. The funding target was 100% of a plan's liability (as determined under the PPA) with any shortfall amortized over seven years, with lower (92% – 100%) funding targets available to well-funded plans during the transition period. Due to the significant declines in the valuation of capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum funding rules set forth in the PPA such that all plans, except those that were subject to deficit reduction contribution requirements in 2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the 2008 – 2010 plan years. The Company's Pension Plan was 80% funded under the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) as of January 1, 2010 which resulted in a shortfall of $10.2 million. This shortfall is being amortized over seven years with annual payments of $1.7 million, beginning in 2010. The $1.7 million payments for 2010 and 2011 are included in the Employer Contributions amounts shown in the table below. On June 25, 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act of 2010 (Relief Act) was signed into law. The pension relief portion of the Relief Act provides two alternative shortfall amortization periods to the seven year amortization period required under the PPA. The Company has evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2012 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities' rates for these Pension Plan costs.

The following table represents employer contributions, participant contributions and benefit payments ($000's).


	Pension Plan						PBOP Plan						SERP
	2011		2010		2009		2011		2010		2009		2011		2010		2009
Employer Contributions	$	8,813	$	4,302	$	4,227	$	—	$	3,482	$	2,800	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	13	$	—	$	—	$	—	$	—	$	—
Benefit Payments	$	3,438	$	3,185	$	3,742	$	1,644	$	1,848	$	1,731	$	53	$	53	$	53

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2012	$	4,040	$	1,762	$	52
2013		4,197		1,835		302
2014		4,466		1,941		301
2015		4,570		2,035		299
2016		4,738		2,088		298
2017 - 2021	$	28,659	$	12,214	$	1,497

The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company's Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 48% in common stock equities, 47% in fixed income securities and 5% in a combined equity and debt fund. The Company's Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55% in common stock equities and 45% in fixed income securities. The actual investment allocations are shown in the tables below.


Pension Plan	Target Allocation 2012			Actual Allocation at December 31,
	Target Allocation 2012			2011			2010			2009
Equity Funds		48	%		49	%		58	%		59	%
Debt Funds		47	%		46	%		42	%		40	%
Asset Allocation Fund⁽¹⁾		5	%		5	%		0	%		1	%

Total					100	%		100	%		100	%

⁽¹⁾

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


PBOP Plan	Target Allocation 2012			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2012			2011			2010			2009
Equity Funds		55	%		55	%		56	%		56	%
Debt Funds		45	%		45	%		44	%		44	%

Total					100	%		100	%		100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2011. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

The 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.

Valuation Techniques

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

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2011 and 2010 are as follows ($000's):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	29,094	$	29,094	$	—	$	—
Fixed Income Funds		27,697		27,697		—		—
Asset Allocation Fund		2,909		2,909		—		—

Total Assets	$	59,700	$	59,700	$	—	$	—


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Pension Plan Assets:
Mutual Funds:
Equity Funds	$	31,625	$	31,625	$	—	$	—
Fixed Income Funds		22,475		22,475		—		—

Total Assets	$	54,100	$	54,100	$	—	$	—

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2011 and 2010 are as follows ($000's):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	3,311	$	3,311	$	—	$	—
Index Funds		2,977		2,977
Equity Funds		1,051		1,051

Total Assets	$	7,339	$	7,339	$	—	$	—


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2010		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
PBOP Plan Assets:
Mutual Funds:
Fixed Income Funds	$	3,936	$	3,936	$	—	$	—
Index Funds		3,580		3,580
Equity Funds		1,346		1,346

Total Assets	$	8,862	$	8,862	$	—	$	—

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

In September 2009, the Company amended the Plan as follows:

For current non-union employees who elect to stay with the Company's existing Pension Plan, there will be no changes in the 401(k) Plan. For those employees, the Company will continue to match contributions, with a maximum matching contribution of 3% of current compensation and those participants will be 100% vested in these company matching contributions once they have completed three years of service.

For non-union employees who are hired on or after January 1, 2010, and for non-union employees who elect to move from the Company's existing Pension Plan and accept a frozen pension benefit, the Company will provide the following enhancements to the 401(k) Plan:

•

The Company will contribute 4% of base pay each year, regardless of whether or not the non-union employee elects to contribute to the 401(k) Plan.

•

The Company will increase the matching contributions from 3% of base pay to 6% of base pay. This will be a 100% match of the first 6% of the non-union employee's contributions.

•

All Company contributions will be 100% vested at all times.

•

New non-union employees will be automatically enrolled in the 401(k) Plan following the completion of 1,000 hours of service, with the automatic contribution rate of 3%. This contribution rate will automatically increase by 1% on January 1 of each year until the non-union employee's contribution is 10% of pay. Non-union employees may elect to opt-out of the automatic enrollment and/or automatic increase features of the enhanced 401(k) Plan.

The Company's contributions to the 401(k) Plan were $1,190,000, $980,000 and $671,000 for the years ended December 31, 2011, 2010, and 2009, respectively.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS106-2
-Paragraph 20, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

+ Details