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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2012	Jan. 25, 2013	Jun. 30, 2012
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		13,780,921
Entity Public Float			$ 359,089,609

Consolidated Statements of Earnings - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Revenues:
Gas	$ 160.6	$ 159.2	$ 150.1
Electric	187.0	188.1	203.7
Other	5.5	5.5	4.6
Total Operating Revenues	353.1	352.8	358.4
Operating Expenses:
Purchased Gas	81.9	89.1	90.5
Purchased Electricity	108.4	114.2	137.7
Operation and Maintenance	57.0	51.5	48.8
Conservation & Load Management	9.2	8.5	8.8
Depreciation and Amortization	35.1	29.3	28.9
Provisions for Taxes:
Local Property and Other	14.0	13.0	11.2
Federal and State Income	11.0	10.0	4.5
Total Operating Expenses	316.6	315.6	330.4
Operating Income	36.5	37.2	28.0
Other Non-Operating Expenses	0.2	0.4	0.3
Income Before Interest Expense	36.3	36.8	27.7
Interest Expense, net	18.1	20.4	18.1
Net Income	18.2	16.4	9.6
Less Dividends on Preferred Stock	0.1	0.1	0.1
Earnings Applicable to Common Shareholders	$ 18.1	$ 16.3	$ 9.5
Average Common Shares Outstanding (000's)-Basic	12,669	10,880	10,823
Average Common Shares Outstanding (000's)-Diluted	12,672	10,883	10,824
Earnings per Common Share-Basic and Diluted	$ 1.43	$ 1.50	$ 0.88

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Utility Plant:
Electric	$ 356.9	$ 333.3
Gas	424.4	382.3
Common	30.9	29.8
Construction Work in Progress	19.4	28.3
Utility Plant	831.6	773.7
Less: Accumulated Depreciation	230.4	216.5
Net Utility Plant	601.2	557.2
Current Assets:
Cash	9.8	7.5
Accounts Receivable, net	45.9	44.2
Accrued Revenue	58.1	54.2
Gas Inventory	10.5	14.8
Material and Supplies	4.1	3.6
Prepayments and Other	4.2	4.5
Total Current Assets	132.6	128.8
Noncurrent Assets:
Regulatory Assets	136.0	142.2
Other Noncurrent Assets	16.8	18.5
Total Noncurrent Assets	152.8	160.7
TOTAL ASSETS	886.6	846.7
Capitalization:
Common Stock Equity	260.4	191.7
Preferred Stock	0.2	2.0
Long-Term Debt, Less Current Portion	287.3	287.8
Total Capitalization	547.9	481.5
Current Liabilities:
Long-Term Debt, Current Portion	0.5	0.5
Accounts Payable	30.9	26.4
Short-Term Debt	49.4	87.9
Energy Supply Obligations	13.8	24.5
Current Deferred Income Taxes	13.4	9.0
Taxes Payable	0.7	1.0
Other Current Liabilities	16.7	17.5
Total Current Liabilities	125.4	166.8
Noncurrent Liabilities:
Energy Supply Obligations	3.3	4.2
Noncurrent Deferred Income Taxes	38.7	37.3
Cost of Removal Obligations	51.4	46.5
Retirement Benefit Obligations	103.7	91.2
Environmental Obligations	13.8	14.5
Other Noncurrent Liabilities	2.4	4.7
Total Noncurrent Liabilities	213.3	198.4
TOTAL CAPITALIZATION AND LIABILITIES	$ 886.6	$ 846.7

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating Activities:
Net Income	$ 18.2	$ 16.4	$ 9.6
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	35.1	29.3	28.9
Deferred Taxes Provision	10.8	8.7	10.5
Changes in Working Capital Items:
Accounts Receivable	(1.7)	(7.3)	(3.4)
Accrued Revenue	(3.9)	(4.8)	(3.5)
Taxes Refundable / Payable	(0.3)	8.5	(5.8)
Gas Inventory	4.3	(4.2)	3.7
Accounts Payable	4.5	(0.1)	1.4
Other Changes in Working Capital Items	(0.5)	0.5	(4.6)
Deferred Regulatory and Other Charges	3.6	1.1	(4.3)
Other, net	(3.4)	(2.2)	(6.6)
Cash Provided by Operating Activities	66.7	45.9	25.9
Investing Activities:
Property, Plant and Equipment Additions	(68.5)	(57.1)	(49.6)
Cash (Used In) Investing Activities	(68.5)	(57.1)	(49.6)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	(38.5)	21.1	2.3
Proceeds from Issuance of Long-Term Debt			40.0
Repayment of Long-Term Debt	(0.5)	(0.5)	(0.5)
Net Increase (Decrease) in Gas Inventory Financing	(3.8)	4.6	(2.2)
Dividends Paid	(17.2)	(15.2)	(15.0)
Retirement of Preferred Stock	(1.8)
Proceeds from Issuance of Common Stock	66.8	1.0	0.9
Other, net	(0.9)	(1.2)	(0.6)
Cash Provided by Financing Activities	4.1	9.8	24.9
Net Increase (Decrease) in Cash	2.3	(1.4)	1.2
Cash at Beginning of Year	7.5	8.9	7.7
Cash at End of Year	9.8	7.5	8.9
Supplemental Information:
Interest Paid	21.2	21.2	20.5
Income Taxes (Refunded) Paid	0.7	(7.3)	2.3
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 1.9	$ 2.6	$ 1.5

Consolidated Statements Of Changes In Common Stock Equity - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2009	$ 193.1	$ 159.5	$ 33.6
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
Ending Balance at Dec. 31, 2010	189.0	160.8	28.2
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
Ending Balance at Dec. 31, 2011	191.7	162.3	29.4
Net Income	18.2		18.2
Dividends	(17.2)		(17.2)
Shares Issued Under Stock Plans	0.9	0.9
Issuance of Common Shares	1.1	1.1
Issuance of Common Shares	65.7	65.7
Ending Balance at Dec. 31, 2012	$ 260.4	$ 230.0	$ 30.4

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.18)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.22)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=20435746&loc=d3e565-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph d
-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 Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 10, 15
-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 AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A7
-Appendix A

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 87-21
-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 SEC
-Name Regulation S-X (SX)
-Number 210
-Section 03
-Paragraph 19
-Article 5

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-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 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28, 29, 30
-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 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

+ Details

- Definition

Value of stock (or other type of equity) issued during the period as a result of any equity-based compensation plan other than an employee stock ownership plan (ESOP), net of stock value of such awards forfeited. Stock issued could result from the issuance of restricted stock, the exercise of stock options, stock issued under employee stock purchase plans, and/or other employee benefit plans.

+ References + Details

Consolidated Statements Of Changes In Common Stock Equity (Parenthetical) - shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Common Stock, Shares issued	41,752	39,473	41,455
Common Stock, Shares issued	2,760,000

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

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 and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.

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

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly- owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to 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)	2012		2011
Energy Supply Obligations	$	8.5	$	16.2
Deferred Restructuring Costs		20.1		21.8
Retirement Benefit Obligations		62.5		55.3
Income Taxes		10.2		10.9
Environmental Obligations		16.8		17.5
Deferred Storm Charges		27.8		28.6
Regulatory Tracker Mechanisms		24.7		23.5
Other		12.0		12.0

Total Regulatory Assets	$	182.6	$	185.8
Less: Current Portion of Regulatory Assets⁽¹⁾		46.6		43.6

Regulatory Assets—noncurrent	$	136.0	$	142.2

⁽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, 2012 and 2011, the Unitil affiliates had deposited $5.4 million and $4.6 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, 2012 and 2011, there was $1.2 million and $2.6 million, respectively, deposited for this purpose.

Accrued Revenue—Accrued Revenue includes the current portion of Regulatory Assets (see “Regulatory Accounting” above and unbilled revenues (see Utility Revenue Recognition below.) The following table shows the components of Accrued Revenue as of December 31, 2012 and 2011.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2012		2011
Regulatory Assets—Current	$	46.6	$	43.6
Unbilled Revenues		11.5		10.6

Total Accrued Revenue	$	58.1	$	54.2

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.04%, 2.28% and 2.25% in 2012, 2011 and 2010, 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 is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31, 2012 and 2011, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $51.4 million and $46.5 million, respectively. Prior to December 31, 2012, the cost of removal amounts had been recorded in Accumulated Depreciation on the Consolidated Balance Sheets. The prior period amounts have been reclassified to Cost of Removal Obligations on the Consolidated Balance Sheets to conform to current year presentation.

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, 2012, the unamortized balance of the bargain purchase adjustment is $14.7 million, to be amortized over the next six years.

Off-Balance Sheet Arrangements—As of December 31, 2012, 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).

Fair Value—The Financial Accounting Standards Board (FASB) Codification defines fair value, and establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The three levels of the fair value hierarchy under the FASB Codification are described below:


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

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

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

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3.

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

Derivatives—The Company has a regulatory 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 in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of December 31, 2012 and December 31, 2011, the Company had 1.9 billion cubic feet (BCF) and 1.6 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, 2012		December 31, 2011
Natural Gas Futures Contracts	Other Current Liabilities	$	0.7	$	1.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		0.6

Total		$	0.7	$	2.3

⁽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)	2012		2011
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	1.0	$	2.9

Amount of Loss Reclassified into Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	2.6	$	1.6

⁽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, the amount of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are estimated. These unbilled revenues are estimated each month based on estimated customer usage by class and applicable customer rates.

On August 1, 2011, the Massachusetts Department of Public Utilities (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).

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

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

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

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


	December 31,
Energy Supply Obligations consist of the following: (millions)	2012		2011
Current:
Gas Inventory Obligation	$	8.7	$	12.4
Power Supply Contract Divestitures		0.9		8.7
Renewable Energy Portfolio Standards		4.2		3.4

Total Energy Supply Obligations—Current	$	13.8	$	24.5

Long-Term:
Power Supply Contract Divestitures	$	3.3	$	4.2

Total Energy Supply Obligations	$	17.1	$	28.7

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, 2012, 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).

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: 2012 – 3.60%, 2011 – 3.43% and 2010 – 3.99%.

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, 2012, 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. Deferred income taxes are reflected as Current and Noncurrent Deferred Income Taxes on the Consolidated Balance Sheets based on the nature of the underlying timing item. Prior to December 31, 2012, deferred income taxes were reflected as a single amount on the Consolidated Balance Sheets. The prior period amount of current deferred income taxes, $9.0 million, has been reclassified to conform to current year presentation.

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, 2012, 2011 and 2010, the Company paid quarterly dividends of $0.345 per share, resulting in an annual dividend 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 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 adopted ASU 2011-04 and it did not have 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. Most significant has been the reclassification of cost of removal costs associated with asset retirements from Accumulated Depreciation to Cost of Removal Obligations and the segregation of Deferred Income Taxes to current and noncurrent amounts on the Company’s Consolidated Balance Sheets, as discussed above in Utility Plant and Income Taxes, respectively.

Equity

12 Months Ended

Dec. 31, 2012

Equity

Note 2: Equity

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

Common Stock

The Company’s common stock trades on the New York Stock Exchange 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 13,780,601, and 10,954,065 shares of common stock outstanding at December 31, 2012 and December 31, 2011, respectively.

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

Dividend Reinvestment and Stock Purchase Plan—During 2012, the Company sold 41,752 shares of its common stock, at an average price of $26.37 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of $1.1 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 2011 and 2010, the Company raised $1.0 million and $0.9 million, respectively, through the issuance of 39,473 and 41,455 shares, respectively, of its common stock in connection with its DRP and 401(k) plans.

Common 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 22, 2012, 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 2012, 2011 and 2010, the Company repurchased 6,368, 8,765 and 3,225 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, $0.2 million and $0.1 million in 2012, 2011 and 2010, respectively.

During 2012, 2011 and 2010, 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 Unitil Corporation Amended and Restated 2003 Stock Plan (the Stock Plan). Participants in the Stock Plan are selected by the Compensation Committee of the Board of Directors to receive awards under the Stock Plan, including awards of restricted shares (Restricted Shares), or of restricted stock units (Restricted Stock Units). The Compensation Committee has the authority to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Stock Plan; construe and interpret the Stock Plan and any agreement or instrument entered into under the Stock Plan as they apply to participants; establish, amend, or waive rules and regulations for the Stock Plan’s administration as they apply to participants; and, subject to the provisions of the Stock Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Stock Plan. On April 19, 2012, the Company’s shareholders approved an amendment to the Stock Plan to, among other things, increase the maximum number of shares of common stock available for awards to plan participants.

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

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. Awards may be grossed up to offset the participant’s tax obligations in connection with the award. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

Restricted Shares issued for 2010 – 2012 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
2/5/10	12,520	$0.3
2/9/11	24,330	$0.6
2/3/12	25,600	$0.7

The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $1.3 million, $0.7 million and $0.5 million in 2012, 2011 and 2010, respectively. There were 53,932 and 52,362 non-vested shares under the Stock Plan as of December 31, 2012 and 2011, respectively. The weighted average grant date fair value of these shares was $24.67 per share and $22.21 per share, respectively. At December 31, 2012, there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.5 years. There were 816 restricted shares forfeited and there were no cancellations under the Stock Plan during 2012.

There were no Restricted Stock Units issued in conjunction with the Stock Plan during 2010 and 2011. On October 1, 2012, there were 5,470 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. These Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. Restricted Stock Units issued during 2012 in conjunction with the Stock Plan during 2012 are presented in the following table:


Equity RSUs	2012
	Equity RSUs		Weighted Average Stock Price
Beginning Equity Restricted Stock Units		—
Equity Restricted Stock Units Granted		3,829	$	27.43
Dividend Equivalents Earned—Prior Years		—
Dividend Equivalents Earned—Current Year		54	$	24.62
Equity Restricted Stock Units Settled		—

Ending Equity Restricted Stock Units		3,883	$	27.39

Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31, 2012 is less than $0.1 million representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash.

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 2012, 2011 and 2010. 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 or will be made under this plan since it was terminated by the Board of Directors in 2003. As of December 31, 2012, 2011 and 2010, there was no aggregate intrinsic value of the options exercisable. As of December 31, 2011, all options under this plan have expired.


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

Ending Options Outstanding		—		$	—		33,000		$	25.88

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

Preferred Stock

One of Unitil’s distribution utility companies, Unitil Energy, has an aggregate of $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock outstanding at December 31, 2012.

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

Fitchburg was required to offer to redeem annually a given number of shares of each series of its Redeemable, Cumulative Preferred Stock and to purchase such shares that were tendered by holders of the respective stock. In addition, Fitchburg had the option to redeem the Redeemable, Cumulative Preferred Stock at a given redemption price, plus accrued dividends.

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2012, 2011 and 2010 related to the annual redemption offer were $8,000, $8,600 and $25,000, respectively.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.


(Millions except shares and per share data)	2012		2011		2010
Earnings Available to Common Shareholders	$	18.1	$	16.3	$	9.5

Weighted Average Common Shares Outstanding—Basic (000’s)		12,669		10,880		10,823
Plus: Diluted Effect of Incremental Shares (000’s)		3		3		1

Weighted Average Common Shares Outstanding—Diluted (000’s)		12,672		10,883		10,824

Earnings per Share—Basic and Diluted	$	1.43	$	1.50	$	0.88

Weighted average options to purchase 33,000 shares of common stock were outstanding during 2010 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, 24,325, 1,642 and 6,164 weighted average non-vested restricted shares for 2012, 2011 and 2010, 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

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
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-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
-URI http://asc.fasb.org/extlink&oid=6228006&loc=d3e74512-122707

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187143-122770

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

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

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

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Section B
-Paragraph 7, 11A
-Chapter 1
-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 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-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 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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-Paragraph 15
-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 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
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-Paragraph 29, 30, 31
-Article 5

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 20: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 21: http://www.xbrl.org/2003/role/presentationRef
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-Name Staff Accounting Bulletin (SAB)
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
-Paragraph 2, 3, 4, 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 23: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

Long-Term Debt, Credit Arrangements, Leases and Guarantees

12 Months Ended

Dec. 31, 2012

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 long-term debt 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 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 long-term debt 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. None of the Fitchburg, Northern Utilities and Granite State default provisions are 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, 2012, 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 $500,405, $462,055, and $426,643 in 2012, 2011, and 2010, respectively.

The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2012 is: 2013 – $541,938; 2014 – $2,486,919; 2015 – $4,035,633; 2016 – $17,421,724; and 2017 – $17,160,985, respectively.

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


(millions)	December 31,
	2012		2011
Estimated Fair Value of Long- Term Debt	$	349.7	$	338.7

Details on long-term debt at December 31, 2012 and 2011 are shown below:


	December 31,
Long-Term Debt (millions)	2012		2011
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		2.8		3.3

Total Long-Term Debt		287.8		288.3
Less: Current Portion		0.5		0.5

Total Long-Term Debt, Less Current Portion	$	287.3	$	287.8

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)
	2012			2011			2010
Interest Expense
Long-term Debt	$	20.3		$	20.3		$	20.0
Short-term Debt		1.5			1.7			1.7
Regulatory Liabilities		0.5			—			0.3

Subtotal Interest Expense		22.3			22.0			22.0

Interest Income
Regulatory Assets		(3.4	)		(1.1	)		(3.5	)
AFUDC⁽¹⁾ and Other		(0.8	)		(0.5	)		(0.4	)

Subtotal Interest Income		(4.2	)		(1.6	)		(3.9	)

Total Interest Expense, net	$	18.1		$	20.4		$	18.1

⁽¹⁾

AFUDC—Allowance for Funds Used During Construction

Credit Arrangements

Unitil has an unsecured revolving credit facility with a group of banks that extends to October 8, 2013. Effective July 24, 2012, Unitil reduced the borrowing limit under its revolving credit facility from $115 million to $60 million. The new $60 million borrowing limit reflects reduced borrowing needs as a result of the recent repayment of short-term debt with the net proceeds of the Company’s public equity offering in May 2012.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of December 31, 2012 and December 31, 2011:


Revolving Credit Facility (millions)
	December 31,
	2012		2011
Limit	$	60.0	$	115.0
Outstanding	$	49.4	$	87.9
Available	$	10.6	$	27.1

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, 2012 and December 31, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

The weighted average interest rates on all short-term borrowings were 2.0%, 2.2%, and 2.3% during 2012, 2011, and 2010, 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 $10.7 million and $14.9 million of natural gas storage inventory obligations at December 31, 2012 and 2011, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2012, which was payable in January 2013, is $2.1 million and recorded in Accounts Payable at December 31, 2012. 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.

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, 2012, 2011 and 2010 amounted to $1.3 million, $1.4 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. Fitchburg intends to purchase this facility at its fair market value at the end of this lease term.

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2012:


Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2013	$	997	$	628
2014		804		300
2015		668		82
2016		479		—
2017		198		—
2018 – 2022		50		—

Total Payments	$	3,196	$	1,010

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, 2012, there were approximately $12.3 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, 2012, the principal amount outstanding for the 8% Unitil Realty notes was $2.8 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

Dec. 31, 2012

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 commercial and industrial (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.

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 million British Thermal Units (MMbtu) per day of year-round and seasonal 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 billion cubic feet (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 Independent System Operator 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 2012, 75% of Unitil’s largest New Hampshire customers, representing 24% of total New Hampshire electric energy sales, and 90% of Unitil’s largest Massachusetts customers, representing 31% of total Massachusetts electric energy sales, are purchasing their electric power supply in the competitive market. However, most residential and small commercial customers continue to purchase their electric supply through Unitil’s distribution utilities under regulated energy rates and tariffs. We believe that the concentration of the competitive retail market on higher use customers has been a common experience throughout the New England electricity 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. 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. On June 13, 2012, the MDPU approved, for a period of one year, Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market.

Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. On July 31, 2012, the NHPUC approved Unitil Energy’s request to modify its Default Service solicitation to a process where 100% of the Default Service requirements are acquired for six months. Unitil Energy is in the process of transitioning to this procurement strategy which will be completed in late 2013. Currently, Unitil Energy has a group of contracts of varying duration and percentage to meet its Default Service supply requirements.

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 economical manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are 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, reliable power system operation 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, 2012

Commitments and Contingencies

Note 5: Commitments and Contingencies

Regulatory Matters

Overview—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. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms. 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 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 two years, is $24.3 million as of December 31, 2012 including $13.3 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—Base Rates—On August 1, 2011, the MDPU issued an 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.

Granite State—Base Rates—Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file a limited Section 4 rate case that includes incremental annual rate adjustments to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects totaling up to $11.4 million. Of the $11.4 million, $4.0 million of capital spending is being recovered in current rates. On June 29, 2012, Granite State submitted to the FERC an incremental annual rate adjustment filing of $0.3 million due to capital costs additions of $2.4 million, with rates effective August 1, 2012. On July 27, 2012, the FERC accepted the tariffs as proposed.

Unitil Energy—Base Rates—On April 26, 2011, the NHPUC approved a rate settlement with a permanent increase of $5.2 million in annual revenue effective July 1, 2010, and an additional increase of $5.0 million in annual revenue effective May 1, 2011. The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with 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. Unitil Energy filed its first step adjustment filing for $1.5 million for implementation on May 1, 2012, to recover increased spending for its vegetation management program and reliability enhancement program. The adjustment filing was approved by the NHPUC with minor modifications.

Northern Utilities—Base Rates—Maine—On November 29, 2011, the MPUC approved 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 precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

Northern Utilities—Base Rates—New Hampshire—On April 24, 2012, the NHPUC approved a settlement agreement providing for a $3.7 million permanent increase in annual distribution revenues for Northern Utilities’ New Hampshire operations, effective May 1, 2012. The permanent rate increase was reconciled back to August 1, 2011, the effective date of temporary rates.

Major Storms—Fitchburg and Unitil Energy

Superstorm Sandy—On October 29-30, 2012, a severe storm struck the Eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Based on its preliminary assessment, Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.6 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm. The amount and timing of the cost recovery of these storm restoration expenditures will be determined in future regulatory proceedings. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations. This matter remains pending.

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 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, including capitalized amounts, it incurred $1.5 million in costs for Tropical Storm Irene and $3.3 million in costs for the October 2011 snow storm. The Company has requested approval to defer and accrue carrying charges on approximately $4.3 million of the storm costs that were not capitalized into utility plant. On May 1, 2012 the MDPU approved the request to defer the storm costs and ordered that the issue of carrying charges would be addressed in the Company’s next base rate proceeding.

Unitil Energy—2011 Storm Costs—On December 16, 2011, Unitil Energy filed a petition with the NHPUC to increase its storm recovery adjustment factor effective May 1, 2012, to recover the approximately $4.4 million of costs of repairing damage to its electrical system resulting from the August 2011 Tropical Storm Irene and the October 2011 snow storm. On April 24, 2012, the NHPUC issued an order approving recovery of the costs over a five year period with a carrying cost rate of 4.52%, subject to reconciliation.

Fitchburg—Electric Operations—On November 30, 2012, Fitchburg submitted its annual reconciliation of costs and revenues for Transition and Transmission under its restructuring plan. The filing 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 Factor, 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, 2013, subject to reconciliation pending investigation by the MDPU. This matter remains pending.

Fitchburg—Gas Operations—On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an MDPU order issued on November 2, 2009 which had ordered Fitchburg to refund natural gas costs, 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 SJC’s decision, the Regulatory Liability was adjusted and the Company recognized a pre-tax credit to earnings of $4.7 million in the fourth quarter of 2011 as a $4.5 million reduction in Purchased Gas expense and a reduction of $0.2 million in Interest Expense, net.

The Company began the recoupment of the amounts previously refunded, with interest, effective January 1, 2012. In order to minimize the rate impact on customers, the recoupment is scheduled to occur over three consecutive heating seasons, beginning January 1, 2012.

Fitchburg—Service Quality—On March 1, 2012, Fitchburg submitted its 2011 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. The 2010 Service Quality report for Fitchburg’s electric division remains pending.

On December 11, 2012, the MDPU opened an investigation into the service quality provided by the gas and electric distribution companies in Massachusetts and the Service Quality guidelines currently in effect. The MDPU investigation will review existing and potential new reliability, safety, and customer satisfaction metrics; potential penalties for downed wire response; potential clean energy metrics; penalty provisions, including penalty offsets for superior performance in other metrics for poor performance on a different metric; and review of historic data for use in establishing service quality benchmarks. Fitchburg will be an active participant in this docket, which remains pending.

Fitchburg—Other—On February 11, 2009, the SJC issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in the Company’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU has opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. The MDPU has set a procedural schedule providing for the filing of testimony, issuance of discovery and an evidentiary hearing in May 2013. This matter remains pending before the MDPU.

On July 2, 2008, the Governor of Massachusetts signed into law “The Green Communities Act” (the GC Act), an energy policy statute designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs. Several regulatory proceedings have been initiated to implement various provisions of the GC Act, including provisions for each distribution company to file enhanced three-year energy efficiency investment plans, plans to establish smart grid pilot programs, proposals to purchase long-term contracts for renewable energy, special tariffs to allow the net metering of customer-owned renewable generation, and terms and conditions for purchasing supplier receivables. Fitchburg’s initial 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 and Fitchburg’s filing for the next three year energy efficiency investment plans are under review in separately designated dockets.

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth”, which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. This act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisition for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU has also opened a proceeding, as mandated by the act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor.

On August 6, 2012, the Governor of Massachusetts also signed into law “An Act Relative to the Emergency Response of Public Utilities”, which establishes a new storm trust fund and requires that penalties levied by the MDPU for violations of its emergency preparedness rules be credited to customers.

Unitil Energy—Annual Rate Reconciliation Filing—On June 15, 2012, Unitil Energy filed its annual reconciliation and rate filing, for rates effective August 1, 2012, including reconciliation of prior year costs and revenues. This filing was approved by the NHPUC on July 20, 2012 with minor modifications.

Unitil Energy—Billing Adjustment—In August 2011, Unitil Energy and one of its larger customers in New Hampshire entered into an agreement 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. As a result of the agreement, 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 related to this agreement and filed with the NHPUC for recovery of the remaining amount of the reimbursement to this customer for reconciling electric supply related charges.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service areas were under-billed from October 2004 through January 2011 for reconciling supply-related charges. Accordingly, the Company requested authorization from the NHPUC to adjust reconciling account balances and process the billing correction. A settlement agreement between Unitil Energy, the Office of Consumer Advocate and the NHPUC Staff was filed with the NHPUC, providing for recovery by the Company from its under-billed customers of approximately $1.4 million of the amount it had reimbursed the large customer. On January 25, 2013, the NHPUC approved the settlement agreement.

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 is proceeding with a comprehensive upgrade and replacement 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.

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 in the first quarter of 2013.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (“Fitchburg”), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit will now continue with only the twelve named plaintiffs seeking damages. Future proceedings may include an appeal of this decision or a trial on the claims of the twelve named plaintiffs. The Company continues to believe the suit is without merit and will continue to defend itself vigorously.

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, 2012, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Fitchburg’s Manufactured Gas Plant Site—Fitchburg 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 proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allowed Fitchburg to achieve 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, 2012 and 2011 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. Additionally, Northern Utilities has executed a Letter of Intent with New Yard, LLC to redevelop the Portland site as a boat repair facility with lease proceeds being used to offset remediation costs. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs until all remedial activities are completed.

The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.

Included in the Company’s Consolidated Balance Sheets at December 31, 2012 and 2011 are current and non-current accrued liabilities totaling $2.8 million and $2.7 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 2012 and 2011.

ENVIRONMENTAL OBLIGATIONS


(Millions)	December 31,
	2012		2011
Total Environmental Obligations—Balance at Beginning of Period	$	14.7	$	14.6
Changes in Estimates		0.1		0.1
Liabilities Assumed		—		—
Less: Payments / Reductions		—		—

Total Environmental Obligations—Balance at End of Period		14.8		14.7
Less: Current Portion⁽¹⁾		1.0		0.2

Environmental Obligations—noncurrent—Balance at End of Period	$	13.8	$	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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
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-URI http://asc.fasb.org/extlink&oid=6449706&loc=d3e16207-108621

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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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.

+ Details

Bad Debts

12 Months Ended

Dec. 31, 2012

Bad Debts

Note 6: Bad Debts

Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2012, 2011 and 2010, the Company recorded provisions for the energy commodity portion of bad debts of $1.9 million, $1.8 million and $1.4 million, respectively. These provisions were recognized in Purchased Electricity and Purchased Gas expense as the associated electric and gas utility revenues were billed. Purchased Electricity and Purchased Gas costs are recovered from customers through periodic rate reconciling mechanisms.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2010 – 2012 ($ millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2012
Electric	$	1.7	$	1.4	$	0.3	$	2.3	$	1.1
Gas		0.5		2.2		0.3		2.3		0.7
Other		0.1		—		—		—		0.1

	$	2.3	$	3.6	$	0.6	$	4.6	$	1.9

Year Ended December 31, 2011
Electric	$	1.8	$	2.1	$	0.2	$	2.4	$	1.7
Gas		0.7		2.2		0.3		2.7		0.5
Other		0.1		—		—		—		0.1

	$	2.6	$	4.3	$	0.5	$	5.1	$	2.3

Year Ended December 31, 2010
Electric	$	1.7	$	2.0	$	0.2	$	2.1	$	1.8
Gas		0.7		2.5		0.4		2.9		0.7
Other		0.1		—		—		—		0.1

	$	2.5	$	4.5	$	0.6	$	5.0	$	2.6

Income Taxes

12 Months Ended

Dec. 31, 2012

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, 2012, 2011 and 2010 are shown in the table below:


	($000’s)
	2012			2011			2010
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	—		$	(6,026	)

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

Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		6,019			13,002			11,821
Net Operating Loss Carryforwards		2,835			(4,844	)		(5,520	)
Regulatory Assets and Liabilities		472			513			3,338
Other, net		(241	)		(695	)		(480	)

Total Deferred Federal Tax Provision (Benefit)		9,085			7,976			9,159

Total Federal Tax Provision		9,085			7,976			3,133

State
Current		132			1,358			28
Deferred		1,759			691			1,303

Total State Tax Provision		1,891			2,049			1,331

Total Provision for Federal and State Income Taxes	$	10,976		$	10,025		$	4,464

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:


	2012			2011			2010
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			5			6
Utility Plant Differences		(2	)		(1	)		(7	)
Other, Net		1			—			(1	)

Effective Income Tax Rate		38	%		38	%		32	%

Temporary differences which gave rise to current deferred tax assets and liabilities in 2012 and 2011, are shown below:


Current Deferred Income Taxes (000’s)	2012			2011
Accrued Revenue, Current Portion	$	13,568		$	9,358
Other, net		(168	)		(366	)

Total Current Deferred Income Tax Liabilities	$	13,400		$	8,992

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2012 and 2011 are shown below:


Noncurrent Deferred Income Taxes (000’s)	2012			2011
Utility Plant Differences	$	66,907		$	57,809
Net Operating Loss Carryforwards		(8,521	)		(11,656	)
AMT Tax Credit Carryforwards		(1,538	)		(1,366	)
Regulatory Assets and Liabilities		17,872			23,269
Retirement Benefit Obligations		(38,644	)		(33,591	)
Other, net		2,606			2,829

Total Noncurrent Deferred Income Tax Liabilities	$	38,682		$	37,294

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, 2011 with the Internal Revenue Service (IRS) in September 2012. As of December 31, 2012, the Company had recorded cumulative federal and state net operating loss (NOL) carryforward assets of $8.5 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2012, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

According to Internal Revenue Code rules, Federal Income Tax 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 has performed all fieldwork procedures and the Company and the IRS entered into a settlement agreement for certain timing items, originally reported in 2009, to be deducted in future periods. The result of the settlement agreement did not have a material impact on the Company’s consolidated financial position or results of operations. On January 22, 2013 the Company received notice of approval from the Joint Committee regarding the settlement agreement.

The Company evaluated its tax positions at December 31, 2012 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by the FASB Codification is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2009; December 31, 2010; and December 31, 2011.

- 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

+ Details

Segment Information

12 Months Ended

Dec. 31, 2012

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 three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the 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, 2012, 2011 and 2010 (Millions):


Year Ended December 31, 2012	Electric		Gas			Other			Non- Regulated		Total

Revenues	$	187.0	$	160.6		$	—		$	5.5	$	353.1

Interest Income		2.4		0.8			0.4			0.1		3.7

Interest Expense		9.0		11.1			1.7			—		21.8

Depreciation & Amortization Expense		18.0		15.7			1.4			—		35.1

Income Tax Expense (Benefit)		4.8		5.8			(0.5	)		0.9		11.0

Segment Profit (Loss)		7.6		8.9			0.3			1.3		18.1

Segment Assets		403.7		471.6			5.6			5.7		886.6

Capital Expenditures		21.2		43.9			3.4			—		68.5

Year Ended December 31, 2011

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		393.8		440.9			6.5			5.5		846.7

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		3.7		(0.7	)		0.5			1.0		4.5

Segment Profit		8.0		1.4			(1.4	)		1.5		9.5

Segment Assets		388.2		401.1			5.7			5.4		800.4

Capital Expenditures		19.8		27.4			2.4			—		49.6

- Definition

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

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Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8906-108599

Reference 15: 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.

+ Details

Retirement Benefit Plans

12 Months Ended

Dec. 31, 2012

Retirement Benefit Plans

Note 9: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement 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 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.

•

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:


	2012			2011			2010
Used to Determine Plan costs for years ended December 31:
Discount Rate		4.60	%		5.35	%		5.75	%
Rate of Compensation Increase		3.00	%		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		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)	$	981		$	909		$	728
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(756	)	$	(705	)	$	(565	)


Used to Determine Benefit Obligations at December 31:
Discount Rate		4.00	%		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.00	%		3.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%		7.00	%
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)	$	11,808		$	9,109		$	7,530
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(9,291	)	$	(7,217	)	$	(5,997	)

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 2012, 2011 and 2010, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $367,000, $325,000 and $300,000, respectively, in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2012, 2011 and 2010 was 3.00%, 3.50% and 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
	2012			2011			2010			2012			2011			2010			2012		2011		2010

Service Cost	$	3,227		$	2,941		$	2,608		$	2,066		$	1,918		$	1,466		$	289	$	285	$	285

Interest Cost		4,633			4,684			4,457			2,303			2,279			2,016			211		227		227

Expected Return on Plan Assets		(5,390	)		(4,840	)		(4,181	)		(695	)		(818	)		(599	)		—		—		—

Prior Service Cost Amortization		188			249			253			1,729			1,729			1,579			11		11		2

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

Curtailment Loss		—			—			41			—			—			—			—		—		—

Actuarial Loss Amortization		3,617			3,132			2,406			129			—			—			64		78		133


Sub-total		6,275			6,166			5,584			5,553			5,129			4,483			575		601		647

Amounts Capitalized and Deferred		(2,726	)		(2,590	)		(2,240	)		(2,127	)		(1,622	)		(1,183	)		—		—		—

NPBC Recognized	$	3,549		$	3,576		$	3,344		$	3,426		$	3,507		$	3,300		$	575	$	601	$	647

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 $4.4 million, $2.5 million and $0.2 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 2012, 2011 and 2010 before capitalization and deferral was $6.3 million, $6.2 million and $5.6 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2012, 2011 and 2010 would have been $6.7 million, $5.7 million and $6.2 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:	2012			2011			2012			2011			2012			2011

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

Actual Return on Plan Assets		7,780			225			837			108			—			—

Employer Contributions		9,387			8,813			2,190			—			53			53

Participant Contributions		—			—			18			13			—			—

Acquired Plan Assets		—			—			—			—			—			—

Benefits Paid		(4,456	)		(3,438	)		(2,083	)		(1,644	)		(53	)		(53	)

Plan Assets at End of Year	$	72,411		$	59,700		$	8,301		$	7,339		$	—		$	—


Change in PBO:

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

Service Cost		3,227			2,941			2,066			1,918			289			285

Interest Cost		4,633			4,684			2,303			2,279			211			227

Participant Contributions		—			—			18			13			—			—

Plan Amendments		617			—			(318	)		—			—			—

Curtailment Gain		—			—			—			—			—			—

Benefits Paid		(4,456	)		(3,438	)		(2,083	)		(1,644	)		(53	)		(53	)

Actuarial (Gain) or Loss		9,752			9,139			9,176			5,020			1,145			(107	)

PBO at End of Year	$	116,492		$	102,719		$	62,092		$	50,930		$	6,207		$	4,615

Funded Status: Assets vs PBO	$	(44,081	)	$	(43,019	)	$	(53,791	)	$	(43,591	)	$	(6,207	)	$	(4,615	)

The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets of $62.5 million and $55.3 million at December 31, 2012 and 2011, respectively, to account for 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 $103.4 million and $91.3 million as of December 31, 2012 and 2011, respectively. The ABO for the SERP was $4.8 million and $0.5 million as of December 31, 2012 and 2011, 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 was 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 evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period.

On July 6, 2012, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was signed into law. MAP-21 increased the interest rates used to determine pension liability. The Company elected to apply the provisions of MAP-21 for purposes of determining pension liability for minimum funding purposes for the 2012 plan year. As part of this decision, the Company contributed $3.1 million in additional contributions in 2012 for the 2011 plan year to achieve 100% funding on the MAP-21 basis as of January 1, 2012. This eliminated the amortization payments created in prior years, discussed above. In addition, the minimum required contribution for the 2012 plan year decreased from $6.1 million to $1.0 million. Of the $9.4 million contributed during 2012, $8.3 million was attributed to the 2011 plan year and $1.1 million was attributed to the 2012 plan year.

The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2013 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

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


	Pension Plan						PBOP Plan						SERP
	2012		2011		2010		2012		2011		2010		2012		2011		2010
Employer Contributions	$	9,387	$	8,813	$	4,302	$	2,190	$	—	$	3,482	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	18	$	13	$	—	$	—	$	—	$	—
Benefit Payments	$	4,456	$	3,438	$	3,185	$	2,083	$	1,644	$	1,848	$	53	$	53	$	53

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2013	$	4,698	$	1,811	$	357
2014		4,448		1,960		353
2015		4,567		2,083		349
2016		4,908		2,156		344
2017		5,121		2,284		339
2018 - 2022	$	30,278	$	13,535	$	1,767

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 2013			Actual Allocation at December 31,
	Target Allocation 2013			2012			2011			2010
Equity Funds		48	%		48	%		49	%		58	%
Debt Funds		47	%		47	%		46	%		42	%
Asset Allocation Fund⁽¹⁾		5	%		5	%		5	%		0	%

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 2013			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2013			2012			2011			2010
Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		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 2012. 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.

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2012 and 2011 are as follows ($000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2012		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	$	34,742	$	34,742	$	—	$	—
Fixed Income Funds		34,251		34,251		—		—
Asset Allocation Fund		3,418		3,418		—		—

Total Assets	$	72,411	$	72,411	$	—	$	—


	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	$	—	$	—

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2012 and 2011 are as follows ($000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2012		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	$	3,670	$	3,670	$	—	$	—
Index Funds		3,357		3,357
Equity Funds		1,274		1,274

Total Assets	$	8,301	$	8,301	$	—	$	—


	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	$	—	$	—

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.

The Company’s contributions to the 401(k) Plan were $1,387,000, $1,190,000 and $980,000 for the years ended December 31, 2012, 2011, and 2010, respectively.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

Reference 2: 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 3: 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 4: 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 5: 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 6: 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 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 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 9: 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 10: 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 11: 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 12: 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 13: 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 14: 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.

+ Details

Quarterly Financial Information

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information

Note 10: Quarterly Financial Information (unaudited; Millions, except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented.


	Three Months Ended
	March 31,				June 30,						September 30,					December 31,
	2012		2011		2012			2011			2012		2011			2012		2011
Total Operating Revenues	$	114.2	$	115.4	$	68.8		$	69.5		$	71.3	$	73.2		$	98.8	$	94.7
Operating Income	$	14.0	$	13.4	$	4.3		$	4.2		$	5.0	$	5.2		$	13.2	$	14.4
Net Income (Loss) Applicable to Common	$	9.0	$	8.7	$	(0.4	)	$	(0.8	)	$	0.5	$	(1.6	)	$	9.0	$	10.0

	Per Share Data:
Earnings Per Common Share	$	0.83	$	0.81	$	(0.03	)	$	(0.08	)	$	0.03	$	(0.15	)	$	0.66	$	0.92
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345		$	0.345		$	0.345	$	0.345		$	0.345	$	0.345

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Nature of Operations

Principles of Consolidation

Regulatory Accounting


	December 31,
Regulatory Assets consist of the following (millions)	2012		2011
Energy Supply Obligations	$	8.5	$	16.2
Deferred Restructuring Costs		20.1		21.8
Retirement Benefit Obligations		62.5		55.3
Income Taxes		10.2		10.9
Environmental Obligations		16.8		17.5
Deferred Storm Charges		27.8		28.6
Regulatory Tracker Mechanisms		24.7		23.5
Other		12.0		12.0

Total Regulatory Assets	$	182.6	$	185.8
Less: Current Portion of Regulatory Assets⁽¹⁾		46.6		43.6

Regulatory Assets—noncurrent	$	136.0	$	142.2

⁽¹⁾

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

Cash

Accrued Revenue


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2012		2011
Regulatory Assets—Current	$	46.6	$	43.6
Unbilled Revenues		11.5		10.6

Total Accrued Revenue	$	58.1	$	54.2

Utility Plant

Goodwill and Intangible Assets

Off-Balance Sheet Arrangements

Fair Value


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

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

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

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

Derivatives

As of December 31, 2012 and December 31, 2011, the Company had 1.9 billion cubic feet (BCF) and 1.6 BCF, respectively, outstanding in natural gas purchase contracts under its hedging program.

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


		Fair Value
Description	Balance Sheet Location	December 31, 2012		December 31, 2011
Natural Gas Futures Contracts	Other Current Liabilities	$	0.7	$	1.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		0.6

Total		$	0.7	$	2.3

⁽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)	2012		2011
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	1.0	$	2.9

Amount of Loss Reclassified into Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	2.6	$	1.6

⁽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

Revenue Recognition-Non-Regulated Operations

Allowance for Doubtful Accounts

Retirement Benefit Obligations

Energy Supply Obligations

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


	December 31,
Energy Supply Obligations consist of the following: (millions)	2012		2011
Current:
Gas Inventory Obligation	$	8.7	$	12.4
Power Supply Contract Divestitures		0.9		8.7
Renewable Energy Portfolio Standards		4.2		3.4

Total Energy Supply Obligations—Current	$	13.8	$	24.5

Long-Term:
Power Supply Contract Divestitures	$	3.3	$	4.2

Total Energy Supply Obligations	$	17.1	$	28.7

Use of Estimates

Commitments and Contingencies

Depreciation and Amortization

Gas Inventory

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

Environmental Matters

Stock-based Employee Compensation

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

Sales and Consumption Taxes

Income Taxes

Dividends

Other Recently Issued Pronouncements

Subsequent Events

Reclassifications

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Offset in Regulatory Assets

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, 2012		December 31, 2011
Natural Gas Futures Contracts	Other Current Liabilities	$	0.7	$	1.7
Natural Gas Futures Contracts	Other Noncurrent Liabilities		—		0.6

Total		$	0.7	$	2.3

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

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of December 31, 2012 and 2011.


Accrued Revenue (millions)	December 31,
Accrued Revenue (millions)	2012		2011
Regulatory Assets—Current	$	46.6	$	43.6
Unbilled Revenues		11.5		10.6

Total Accrued Revenue	$	58.1	$	54.2

Regulatory Assets and Reclassification From Regulatory Asset into Purchased Gas


	Twelve Months Ended December 31,
(millions)	2012		2011
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	1.0	$	2.9

Amount of Loss Reclassified into Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	2.6	$	1.6

⁽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.

Components of Energy Supply Obligations


	December 31,
Energy Supply Obligations consist of the following: (millions)	2012		2011
Current:
Gas Inventory Obligation	$	8.7	$	12.4
Power Supply Contract Divestitures		0.9		8.7
Renewable Energy Portfolio Standards		4.2		3.4

Total Energy Supply Obligations—Current	$	13.8	$	24.5

Long-Term:
Power Supply Contract Divestitures	$	3.3	$	4.2

Total Energy Supply Obligations	$	17.1	$	28.7

Non Current Regulatory Asset For Utility Derivatives

Fair Value Offset in Regulatory Assets


	December 31,
Regulatory Assets consist of the following (millions)	2012		2011
Energy Supply Obligations	$	8.5	$	16.2
Deferred Restructuring Costs		20.1		21.8
Retirement Benefit Obligations		62.5		55.3
Income Taxes		10.2		10.9
Environmental Obligations		16.8		17.5
Deferred Storm Charges		27.8		28.6
Regulatory Tracker Mechanisms		24.7		23.5
Other		12.0		12.0

Total Regulatory Assets	$	182.6	$	185.8
Less: Current Portion of Regulatory Assets⁽¹⁾		46.6		43.6

Regulatory Assets—noncurrent	$	136.0	$	142.2

⁽¹⁾

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

Equity (Tables)

12 Months Ended

Dec. 31, 2012

Restricted Shares Issued in Conjunction with Stock Plan

Restricted Shares issued for 2010 – 2012 in conjunction with the Stock Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
2/5/10	12,520	$0.3
2/9/11	24,330	$0.6
2/3/12	25,600	$0.7

Restricted Stock Units Issued in Conjunction with Stock Plan

Restricted Stock Units issued during 2012 in conjunction with the Stock Plan during 2012 are presented in the following table:


Equity RSUs	2012
	Equity RSUs		Weighted Average Stock Price
Beginning Equity Restricted Stock Units		—
Equity Restricted Stock Units Granted		3,829	$	27.43
Dividend Equivalents Earned—Prior Years		—
Dividend Equivalents Earned—Current Year		54	$	24.62
Equity Restricted Stock Units Settled		—

Ending Equity Restricted Stock Units		3,883	$	27.39

Stock Options Activity

As of December 31, 2011, all options under this plan have expired.


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

Ending Options Outstanding		—		$	—		33,000		$	25.88

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

Reconciliation of Basic and Diluted Earnings Per Share

The following table reconciles basic and diluted earnings per share.


(Millions except shares and per share data)	2012		2011		2010
Earnings Available to Common Shareholders	$	18.1	$	16.3	$	9.5

Weighted Average Common Shares Outstanding—Basic (000’s)		12,669		10,880		10,823
Plus: Diluted Effect of Incremental Shares (000’s)		3		3		1

Weighted Average Common Shares Outstanding—Diluted (000’s)		12,672		10,883		10,824

Earnings per Share—Basic and Diluted	$	1.43	$	1.50	$	0.88

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

12 Months Ended

Dec. 31, 2012

Estimated Fair Value of Long-Term Debt


(millions)	December 31,
	2012		2011
Estimated Fair Value of Long- Term Debt	$	349.7	$	338.7

Details on Long Term Debt

Details on long-term debt at December 31, 2012 and 2011 are shown below:


	December 31,
Long-Term Debt (millions)	2012		2011
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		2.8		3.3

Total Long-Term Debt		287.8		288.3
Less: Current Portion		0.5		0.5

Total Long-Term Debt, Less Current Portion	$	287.3	$	287.8

Summary of Interest Expense and Interest Income

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


Interest Expense, net (millions)
	2012			2011			2010
Interest Expense
Long-term Debt	$	20.3		$	20.3		$	20.0
Short-term Debt		1.5			1.7			1.7
Regulatory Liabilities		0.5			—			0.3

Subtotal Interest Expense		22.3			22.0			22.0

Interest Income
Regulatory Assets		(3.4	)		(1.1	)		(3.5	)
AFUDC⁽¹⁾ and Other		(0.8	)		(0.5	)		(0.4	)

Subtotal Interest Income		(4.2	)		(1.6	)		(3.9	)

Total Interest Expense, net	$	18.1		$	20.4		$	18.1

⁽¹⁾

AFUDC—Allowance for Funds Used During Construction

Borrowing Limits, Amounts Outstanding and Amounts Available Under Revolving Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of December 31, 2012 and December 31, 2011:


Revolving Credit Facility (millions)
	December 31,
	2012		2011
Limit	$	60.0	$	115.0
Outstanding	$	49.4	$	87.9
Available	$	10.6	$	27.1

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases

The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2012:


Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2013	$	997	$	628
2014		804		300
2015		668		82
2016		479		—
2017		198		—
2018 – 2022		50		—

Total Payments	$	3,196	$	1,010

- Definition

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

+ References

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

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

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

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

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

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

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

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

+ Details

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Environmental Obligations

The following table shows the balances and activity in the Company’s liability for Environmental Obligations for 2012 and 2011.

ENVIRONMENTAL OBLIGATIONS


(Millions)	December 31,
	2012		2011
Total Environmental Obligations—Balance at Beginning of Period	$	14.7	$	14.6
Changes in Estimates		0.1		0.1
Liabilities Assumed		—		—
Less: Payments / Reductions		—		—

Total Environmental Obligations—Balance at End of Period		14.8		14.7
Less: Current Portion⁽¹⁾		1.0		0.2

Environmental Obligations—noncurrent—Balance at End of Period	$	13.8	$	14.5

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

Bad Debts (Tables)

12 Months Ended

Dec. 31, 2012

Allowance for Doubtful Accounts

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2010 – 2012 ($ millions):

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2012
Electric	$	1.7	$	1.4	$	0.3	$	2.3	$	1.1
Gas		0.5		2.2		0.3		2.3		0.7
Other		0.1		—		—		—		0.1

	$	2.3	$	3.6	$	0.6	$	4.6	$	1.9

Year Ended December 31, 2011
Electric	$	1.8	$	2.1	$	0.2	$	2.4	$	1.7
Gas		0.7		2.2		0.3		2.7		0.5
Other		0.1		—		—		—		0.1

	$	2.6	$	4.3	$	0.5	$	5.1	$	2.3

Year Ended December 31, 2010
Electric	$	1.7	$	2.0	$	0.2	$	2.1	$	1.8
Gas		0.7		2.5		0.4		2.9		0.7
Other		0.1		—		—		—		0.1

	$	2.5	$	4.5	$	0.6	$	5.0	$	2.6

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Provisions for Federal and State Income Taxes


	($000’s)
	2012			2011			2010
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks	$	—		$	—		$	(6,026	)

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

Deferred Federal Tax Provision (Benefit)
Utility Plant Differences		6,019			13,002			11,821
Net Operating Loss Carryforwards		2,835			(4,844	)		(5,520	)
Regulatory Assets and Liabilities		472			513			3,338
Other, net		(241	)		(695	)		(480	)

Total Deferred Federal Tax Provision (Benefit)		9,085			7,976			9,159

Total Federal Tax Provision		9,085			7,976			3,133

State
Current		132			1,358			28
Deferred		1,759			691			1,303

Total State Tax Provision		1,891			2,049			1,331

Total Provision for Federal and State Income Taxes	$	10,976		$	10,025		$	4,464

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate

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:


	2012			2011			2010
Statutory Federal Income Tax Rate		34	%		34	%		34	%
Income Tax Effects of:
State Income Taxes, Net		5			5			6
Utility Plant Differences		(2	)		(1	)		(7	)
Other, Net		1			—			(1	)

Effective Income Tax Rate		38	%		38	%		32	%

Deferred Income Taxes Assets Liabilities Current

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to current deferred tax assets and liabilities in 2012 and 2011, are shown below:


Current Deferred Income Taxes (000’s)	2012			2011
Accrued Revenue, Current Portion	$	13,568		$	9,358
Other, net		(168	)		(366	)

Total Current Deferred Income Tax Liabilities	$	13,400		$	8,992

Deferred Income Taxes Assets liabilities Noncurrent

Deferred Tax Assets and Liabilities

Temporary differences which gave rise to noncurrent deferred tax assets and liabilities in 2012 and 2011 are shown below:


Noncurrent Deferred Income Taxes (000’s)	2012			2011
Utility Plant Differences	$	66,907		$	57,809
Net Operating Loss Carryforwards		(8,521	)		(11,656	)
AMT Tax Credit Carryforwards		(1,538	)		(1,366	)
Regulatory Assets and Liabilities		17,872			23,269
Retirement Benefit Obligations		(38,644	)		(33,591	)
Other, net		2,606			2,829

Total Noncurrent Deferred Income Tax Liabilities	$	38,682		$	37,294

Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Significant Segment Financial Data

The following table provides significant segment financial data for the years ended December 31, 2012, 2011 and 2010 (Millions):


Year Ended December 31, 2012	Electric		Gas			Other			Non- Regulated		Total

Revenues	$	187.0	$	160.6		$	—		$	5.5	$	353.1

Interest Income		2.4		0.8			0.4			0.1		3.7

Interest Expense		9.0		11.1			1.7			—		21.8

Depreciation & Amortization Expense		18.0		15.7			1.4			—		35.1

Income Tax Expense (Benefit)		4.8		5.8			(0.5	)		0.9		11.0

Segment Profit (Loss)		7.6		8.9			0.3			1.3		18.1

Segment Assets		403.7		471.6			5.6			5.7		886.6

Capital Expenditures		21.2		43.9			3.4			—		68.5

Year Ended December 31, 2011

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		393.8		440.9			6.5			5.5		846.7

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		3.7		(0.7	)		0.5			1.0		4.5

Segment Profit		8.0		1.4			(1.4	)		1.5		9.5

Segment Assets		388.2		401.1			5.7			5.4		800.4

Capital Expenditures		19.8		27.4			2.4			—		49.6

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References + Details

Retirement Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Key Assumptions used in Determining Benefit Plan Costs and Obligations

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


	2012			2011			2010
Used to Determine Plan costs for years ended December 31:
Discount Rate		4.60	%		5.35	%		5.75	%
Rate of Compensation Increase		3.00	%		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		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)	$	981		$	909		$	728
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(756	)	$	(705	)	$	(565	)


Used to Determine Benefit Obligations at December 31:
Discount Rate		4.00	%		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.00	%		3.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.00	%		6.50	%		7.00	%
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)	$	11,808		$	9,109		$	7,530
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(9,291	)	$	(7,217	)	$	(5,997	)

Components of Retirement Plan Costs

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


	Pension Plan									PBOP Plan									SERP
	2012			2011			2010			2012			2011			2010			2012		2011		2010

Service Cost	$	3,227		$	2,941		$	2,608		$	2,066		$	1,918		$	1,466		$	289	$	285	$	285

Interest Cost		4,633			4,684			4,457			2,303			2,279			2,016			211		227		227

Expected Return on Plan Assets		(5,390	)		(4,840	)		(4,181	)		(695	)		(818	)		(599	)		—		—		—

Prior Service Cost Amortization		188			249			253			1,729			1,729			1,579			11		11		2

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

Curtailment Loss		—			—			41			—			—			—			—		—		—

Actuarial Loss Amortization		3,617			3,132			2,406			129			—			—			64		78		133


Sub-total		6,275			6,166			5,584			5,553			5,129			4,483			575		601		647

Amounts Capitalized and Deferred		(2,726	)		(2,590	)		(2,240	)		(2,127	)		(1,622	)		(1,183	)		—		—		—

NPBC Recognized	$	3,549		$	3,576		$	3,344		$	3,426		$	3,507		$	3,300		$	575	$	601	$	647

Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status

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:	2012			2011			2012			2011			2012			2011

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

Actual Return on Plan Assets		7,780			225			837			108			—			—

Employer Contributions		9,387			8,813			2,190			—			53			53

Participant Contributions		—			—			18			13			—			—

Acquired Plan Assets		—			—			—			—			—			—

Benefits Paid		(4,456	)		(3,438	)		(2,083	)		(1,644	)		(53	)		(53	)

Plan Assets at End of Year	$	72,411		$	59,700		$	8,301		$	7,339		$	—		$	—


Change in PBO:

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

Service Cost		3,227			2,941			2,066			1,918			289			285

Interest Cost		4,633			4,684			2,303			2,279			211			227

Participant Contributions		—			—			18			13			—			—

Plan Amendments		617			—			(318	)		—			—			—

Curtailment Gain		—			—			—			—			—			—

Benefits Paid		(4,456	)		(3,438	)		(2,083	)		(1,644	)		(53	)		(53	)

Actuarial (Gain) or Loss		9,752			9,139			9,176			5,020			1,145			(107	)

PBO at End of Year	$	116,492		$	102,719		$	62,092		$	50,930		$	6,207		$	4,615

Funded Status: Assets vs PBO	$	(44,081	)	$	(43,019	)	$	(53,791	)	$	(43,591	)	$	(6,207	)	$	(4,615	)

Employer Contributions, Participant Contributions and Benefit Payments

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


	Pension Plan						PBOP Plan						SERP
	2012		2011		2010		2012		2011		2010		2012		2011		2010
Employer Contributions	$	9,387	$	8,813	$	4,302	$	2,190	$	—	$	3,482	$	53	$	53	$	53
Participant Contributions	$	—	$	—	$	—	$	18	$	13	$	—	$	—	$	—	$	—
Benefit Payments	$	4,456	$	3,438	$	3,185	$	2,083	$	1,644	$	1,848	$	53	$	53	$	53

Estimated Future Benefit Payments

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


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2013	$	4,698	$	1,811	$	357
2014		4,448		1,960		353
2015		4,567		2,083		349
2016		4,908		2,156		344
2017		5,121		2,284		339
2018 - 2022	$	30,278	$	13,535	$	1,767

Actual Investment Allocations

The actual investment allocations are shown in the tables below.


Pension Plan	Target Allocation 2013			Actual Allocation at December 31,
	Target Allocation 2013			2012			2011			2010
Equity Funds		48	%		48	%		49	%		58	%
Debt Funds		47	%		47	%		46	%		42	%
Asset Allocation Fund⁽¹⁾		5	%		5	%		5	%		0	%

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 2013			Actual Allocation at December 31,
PBOP Plan	Target Allocation 2013			2012			2011			2010
Equity Funds		55	%		56	%		55	%		56	%
Debt Funds		45	%		44	%		45	%		44	%

Total					100	%		100	%		100	%

Pension Plans

Assets Measured at Fair Value on Recurring Basis

Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2012 and 2011 are as follows ($000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2012		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	$	34,742	$	34,742	$	—	$	—
Fixed Income Funds		34,251		34,251		—		—
Asset Allocation Fund		3,418		3,418		—		—

Total Assets	$	72,411	$	72,411	$	—	$	—


	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	$	—	$	—

Other Postretirement Benefit Plans, Defined Benefit

Assets Measured at Fair Value on Recurring Basis

Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2012 and 2011 are as follows ($000’s):


	Fair Value Measurements at Reporting Date Using
Description	Balance as of December 31, 2012		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	$	3,670	$	3,670	$	—	$	—
Index Funds		3,357		3,357
Equity Funds		1,274		1,274

Total Assets	$	8,301	$	8,301	$	—	$	—


	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	$	—	$	—

- Definition

Tabular disclosure of assets, including [financial] instruments measured at fair value that are classified in stockholders' equity, if any, by class that are measured at fair value on a recurring basis. The disclosures contemplated herein include the fair value measurements at the reporting date by the level within the fair value hierarchy in which the fair value measurements in their entirety fall, segregating fair value measurements using quoted prices in active markets for identical assets (Level 1), significant other observable inputs (Level 2), and significant unobservable inputs (Level 3).

+ References + Details

Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information


	Three Months Ended
	March 31,				June 30,						September 30,					December 31,
	2012		2011		2012			2011			2012		2011			2012		2011
Total Operating Revenues	$	114.2	$	115.4	$	68.8		$	69.5		$	71.3	$	73.2		$	98.8	$	94.7
Operating Income	$	14.0	$	13.4	$	4.3		$	4.2		$	5.0	$	5.2		$	13.2	$	14.4
Net Income (Loss) Applicable to Common	$	9.0	$	8.7	$	(0.4	)	$	(0.8	)	$	0.5	$	(1.6	)	$	9.0	$	10.0

	Per Share Data:
Earnings Per Common Share	$	0.83	$	0.81	$	(0.03	)	$	(0.08	)	$	0.03	$	(0.15	)	$	0.66	$	0.92
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345		$	0.345		$	0.345	$	0.345		$	0.345	$	0.345

Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Millions, Bcf in Billions	3 Months Ended								12 Months Ended
	Dec. 31, 2012 USD ($) Bcf $ / shares	Sep. 30, 2012 $ / shares	Jun. 30, 2012 $ / shares	Mar. 31, 2012 $ / shares	Dec. 31, 2011 USD ($) Bcf $ / shares	Sep. 30, 2011 $ / shares	Jun. 30, 2011 $ / shares	Mar. 31, 2011 $ / shares	Dec. 31, 2012 USD ($) Bcf mi Entity Segment $ / shares	Dec. 31, 2011 USD ($) Bcf $ / shares	Dec. 31, 2010 $ / shares
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Entity									3
Length of pipeline \| mi									86
Average interest rates									2.04%	2.28%	2.25%
Cost of removal obligation	$ 51.4				$ 46.5				$ 51.4	$ 46.5
Intangible Asset Amortization Period	6 years								6 years
Intangible Assets, Purchase Adjustments									$ 14.7
Number of Natural Gas Storage Outstanding \| Bcf	1.9				1.6				1.9	1.6
Depreciation rate based on average depreciable property balance									3.60%	3.43%	3.99%
Current Deferred Income Taxes	$ 13.4				$ 9.0				$ 13.4	$ 9.0
Common stock dividend paid per share \| $ / shares	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 1.38	$ 1.38	$ 1.38
Plant
Significant Accounting Policies [Line Items]
Intangible Asset Amortization Period	10 years								10 years
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents investment maturity period									3 months
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share \| $ / shares									$ 0.345	$ 0.345	$ 0.345
Prior to December 31, 2012
Significant Accounting Policies [Line Items]
Current Deferred Income Taxes	$ 9.0								$ 9.0
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	5.4				$ 4.6				5.4	$ 4.6
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits	$ 1.2				$ 2.6				$ 1.2	$ 2.6
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Entity									3
Other Subsidiaries
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Segment									3

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

Dec. 31, 2012

Dec. 31, 2011

Regulatory Assets [Line Items]

Regulatory Assets

$ 182.6

$ 185.8

Less: Current Portion of Regulatory Assets

^[1]

46.6

43.6

Regulatory Assets-noncurrent

136.0

142.2

Restructuring Charges | Energy Supply Obligations

Regulatory Assets [Line Items]

Regulatory Assets

8.5

16.2

Restructuring Charges | Deferred Restructuring Costs

Regulatory Assets [Line Items]

Regulatory Assets

20.1

21.8

Retirement Benefit Obligations

Regulatory Assets [Line Items]

Regulatory Assets

62.5

55.3

Income Taxes

Regulatory Assets [Line Items]

Regulatory Assets

10.2

10.9

Electric Utilities

Regulatory Assets [Line Items]

Regulatory Assets

27.8

28.6

Regulatory Tracker Mechanisms

Regulatory Assets [Line Items]

Regulatory Assets

24.7

23.5

Other Assets

Regulatory Assets [Line Items]

Regulatory Assets

12.0

Environmental Matters

Regulatory Assets [Line Items]

Regulatory Assets

$ 16.8

$ 17.5

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

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 58.1	$ 54.2
Regulatory Asset
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	46.6	43.6
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 11.5	$ 10.6

Fair Value Offset in Regulatory Assets (Detail) - Not Designated as Hedging Instrument - USD ($)
$ in Millions

Dec. 31, 2012

Dec. 31, 2011

Regulatory Assets [Line Items]

Natural Gas Futures Contracts

^[1]

$ 0.7

$ 2.3

Natural Gas Contracts | Other Current Liabilities

Regulatory Assets [Line Items]

Natural Gas Futures Contracts

^[1]

$ 0.7

1.7

Natural Gas Contracts | Other Noncurrent Liabilities

Regulatory Assets [Line Items]

Natural Gas Futures Contracts

^[1]

$ 0.6

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

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

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Natural Gas Future Contract

Regulatory Assets [Line Items]

Gain (loss) recognized in Regulatory Assets

$ 1.0

$ 2.9

Gas Purchase Costs

Regulatory Assets [Line Items]

Loss reclassification into unaudited Consolidated Statement of Earnings

^[1]

$ 2.6

$ 1.6

[1]	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.

Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 13.8	$ 24.5
Energy Supply Obligations	3.3	4.2
Total Energy Supply Obligations	17.1	28.7
Gas Inventory Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations	8.7	12.4
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations	0.9	8.7
Energy Supply Obligations	3.3	4.2
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 4.2	$ 3.4

Equity - Additional Information (Detail) - USD ($)	1 Months Ended		12 Months Ended
Equity - Additional Information (Detail) - USD ($)	Oct. 31, 2012	May 16, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Apr. 21, 2011
Class of Stock [Line Items]
Common stock, authorized shares						25,000,000
Common stock, shares outstanding			13,780,601	10,954,065
Common stock shares repurchase			6,368	8,765	3,225
Repurchase expense			$ 200,000	$ 200,000	$ 100,000
Preferred Stock			200,000	2,000,000
Redeemable, Cumulative Preferred Stock			$ 8,000	$ 8,600	$ 25,000
Stock Option
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share					33,000
Non Vested Restricted Stock
Class of Stock [Line Items]
Antidilutive securities excluded from computation of earnings per share			24,325	1,642	6,164
Unitil Energy Systems Inc \| Series 6 \| Nonredeemable Preferred Stock \| Noncumulative Preferred Stock
Class of Stock [Line Items]
Preferred Stock			$ 200,000
Dividend rate			6.00%
Restricted Stock Unit \| Maximum
Class of Stock [Line Items]
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 100,000
Before Amendment
Class of Stock [Line Items]
Common stock, authorized shares						16,000,000
Common Stock Offering
Class of Stock [Line Items]
Common stock, share issued		2,760,000
Common stock price per share		$ 25.25
Proceed from issuance of common stock		$ 65,700,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock Vesting Period			4 years
Restricted stock Vesting Percentage Annually			25.00%
Share Based compensation Expense			$ 1,300,000	$ 700,000	$ 500,000
Restricted Stock Non-Vested			53,932	52,362
Restricted Stock Weighted Average Grant Date Fair Value			$ 24.67	$ 22.21
Total unrecognized compensation cost			$ 700,000
Share Compensation Recognition period			2 years 6 months
Restricted shares forfeited			816
Restricted shares cancellation			0
Fully-vested restricted stock units issued	5,470
Restricted Stock \| Common Stock
Class of Stock [Line Items]
Percentage underlying restricted stock that directors will receive	70.00%
Restricted Stock \| Cash
Class of Stock [Line Items]
Percentage underlying restricted stock that directors will receive	30.00%
Restricted Stock \| Maximum
Class of Stock [Line Items]
Restricted stock available for Awards			677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000
Restricted Stock Units Issued
Class of Stock [Line Items]
Restricted stock Units Issued				0	0
Series 8 \| Fitchburg Gas and Electric Light Company
Class of Stock [Line Items]
Dividend rate			8.00%
Redeemable, Cumulative Preferred Stock			$ 965,400
Series 5 \| Fitchburg Gas and Electric Light Company
Class of Stock [Line Items]
Dividend rate			5.125%
Redeemable, Cumulative Preferred Stock			$ 792,313
Preferred Stock premium percentage			1.28%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock, share issued			41,752	39,473	41,455
Common stock price per share			$ 26.37
Proceed from issuance of common stock			$ 1,100,000	$ 1,000,000	$ 900,000

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Shares $ / shares in Millions	12 Months Ended
	Dec. 31, 2012 $ / shares shares
Period 1
Class of Stock [Line Items]
Issuance Date	Feb. 05, 2010
Shares \| shares	12,520
Aggregate Market Value \| $ / shares	$ 0.3
Period 2
Class of Stock [Line Items]
Issuance Date	Feb. 09, 2011
Shares \| shares	24,330
Aggregate Market Value \| $ / shares	$ 0.6
Period 3
Class of Stock [Line Items]
Issuance Date	Feb. 03, 2012
Shares \| shares	25,600
Aggregate Market Value \| $ / shares	$ 0.7

Restricted Stock Units Issued (Detail)	12 Months Ended
Restricted Stock Units Issued (Detail)	Dec. 31, 2012 $ / shares shares
Restricted Stock
Equity RSUs
Equity Restricted Stock Units Granted \| shares	3,829
Equity Restricted Stock Units Settled \| shares
Ending Equity Restricted Stock Units \| shares	3,883
Restricted Stock \| Current year
Equity RSUs
Dividend Equivalents Earned \| shares	54
Weighted Average Exercise Price
Weighted-Average Stock Price
Equity Restricted Stock Units Granted \| $ / shares	$ 27.43
Equity Restricted Stock Units Settled \| $ / shares
Ending Equity Restricted Stock Units \| $ / shares	27.39
Weighted Average Exercise Price \| Current year
Weighted-Average Stock Price
Dividend Equivalents Earned \| $ / shares	$ 24.62

Stock Options Activity (Detail) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Number of Shares
Beginning Options Outstanding	33,000	63,500
Options Granted
Options Exercised
Options Forfeited / Expired	(33,000)	(30,500)
Ending Options Outstanding		33,000
Options Vested and Exercisable- end of year		33,000
Weighted-Average Exercise Price per Share
Beginning Options Outstanding	$ 25.88	$ 28.90
Options Granted
Options Exercised
Options Forfeited / Expired	$ 25.88	32.17
Ending Options Outstanding		25.88
Options Vested and Exercisable- end of year		$ 25.88

Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders	$ 9.0	$ 0.5	$ (0.4)	$ 9.0	$ 10.0	$ (1.6)	$ (0.8)	$ 8.7	$ 18.1	$ 16.3	$ 9.5
Weighted Average Common Shares Outstanding-Basic (000's)									12,669	10,880	10,823
Plus: Diluted Effect of Incremental Shares (000's)									3	3	1
Weighted Average Common Shares Outstanding-Diluted (000's)									12,672	10,883	10,824
Earnings per Share-Basic and Diluted	$ 0.66	$ 0.03	$ (0.03)	$ 0.83	$ 0.92	$ (0.15)	$ (0.08)	$ 0.81	$ 1.43	$ 1.50	$ 0.88

- Definition

The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.

+ References + Details

- Definition

Number of [basic] shares or units, after adjustment for contingently issuable shares or units and other shares or units not deemed outstanding, determined by relating the portion of time within a reporting period that common shares or units have been outstanding to the total time in that period.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=7655603&loc=d3e1448-109256

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Weighted-Average Number of Common Shares Outstanding
-URI http://asc.fasb.org/extlink&oid=6528421

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-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 128
-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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-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 128
-Paragraph 40
-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.

+ Details

Long-Term Debt, Credit Arrangements, Leases and Guarantees - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jul. 24, 2012
Line of Credit Facility [Line Items]
Long term debt repayments	$ 500,000	$ 500,000	$ 500,000
Weighted average interest rate on short term borrowings	2.00%	2.20%	2.30%
Accounts Payable	$ 30,900,000	$ 26,400,000
Total rental expense under operating leases	1,300,000	1,400,000	$ 1,000,000
Guarantee outstanding	$ 12,300,000
Guarantee end date	Feb. 28, 2014
Revolving Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date	Oct. 08, 2013
Revolving credit facility	$ 60,000,000	115,000,000		$ 115,000,000
Reduced Borrowing Limit				$ 60,000,000
Percentage of capitalization	The revolving credit agreement also contains a covenant restricting the Company's ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of December 31, 2012 and December 31, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement.
Bonds
Line of Credit Facility [Line Items]
Long term debt repayments	$ 500,405	462,055	$ 426,643
2013	541,938
2014	2,486,919
2015	4,035,633
2016	17,421,724
2017	$ 17,160,985
Northern Utilities Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization	65.00%
Outstanding Inventory	$ 10,700,000	14,900,000
Accounts Payable	$ 2,100,000	$ 2,500,000
Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization	65.00%
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization	65.00%
Maximum \| Unitil Corporation
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization	70.00%
Unitil Realty Corp \| Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen
Line of Credit Facility [Line Items]
Principal amount of notes outstanding	$ 2,800,000
Granite State Gas Transmission Inc \| Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen
Line of Credit Facility [Line Items]
Principal amount of notes outstanding	$ 10,000,000

Estimated Fair Value of Long-Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Estimated Fair Value of Long- Term Debt	$ 349.7	$ 338.7

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-Term Debt	$ 287.8	$ 288.3
Less: Current Portion	0.5	0.5
Total Long-term Debt, Less Current Portion	287.3	287.8
Senior Notes Six Point Three Three Percent Due May One Twenty Twenty Two
Debt Instrument [Line Items]
Senior Notes	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds Five Point Two Four Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Four Nine Percent Due October Fourteen Twenty Twenty Four
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Nine Six Percent Due September One Twenty Twenty Eight
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Zero Zero Percent Due May One Twenty Thirty One
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Three Two Percent Due September Fifteen Twenty Thirty Six
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Five Percent Due November Thirty Twenty Twenty Three
Debt Instrument [Line Items]
Long-Term Debt	19.0	19.0
Fitchburg Gas and Electric Light Company \| Notes Seven Point Three Seven Percent Due January Fifteen Twenty Twenty Nine
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0
Fitchburg Gas and Electric Light Company \| Notes Seven Point Nine Eight Percent Due June One Twenty Thirty One
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Nine Percent Due October Fifteen Twenty Twenty Five
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0
Fitchburg Gas and Electric Light Company \| Notes Five Point Nine Zero Percent Due December Fifteen Twenty Thirty
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0
Northern Utilities Inc \| Senior Notes Six Point Nine Five Percent Due December Three Twenty Eighteen
Debt Instrument [Line Items]
Senior Notes	30.0	30.0
Northern Utilities Inc \| Senior Notes Five Point Two Nine Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Senior Notes	25.0	25.0
Northern Utilities Inc \| Senior Notes Seven Point Seven Two Percent Due December Three Twenty Thirty Eight
Debt Instrument [Line Items]
Senior Notes	50.0	50.0
Granite State Gas Transmission Inc \| Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen
Debt Instrument [Line Items]
Senior Notes	10.0	10.0
Unitil Realty Corp \| Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen
Debt Instrument [Line Items]
Senior Secured Notes	$ 2.8	$ 3.3

Details on Long Term Debt (Parenthetical) (Detail)	Dec. 31, 2012	Dec. 31, 2011
Senior Notes Six Point Three Three Percent Due May One Twenty Twenty Two
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%
Unitil Energy Systems Inc \| First Mortgage Bonds Five Point Two Four Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Four Nine Percent Due October Fourteen Twenty Twenty Four
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Nine Six Percent Due September One Twenty Twenty Eight
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%
Unitil Energy Systems Inc \| First Mortgage Bonds Eight Point Zero Zero Percent Due May One Twenty Thirty One
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%
Unitil Energy Systems Inc \| First Mortgage Bonds Six Point Three Two Percent Due September Fifteen Twenty Thirty Six
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Five Percent Due November Thirty Twenty Twenty Three
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%
Fitchburg Gas and Electric Light Company \| Notes Seven Point Three Seven Percent Due January Fifteen Twenty Twenty Nine
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%
Fitchburg Gas and Electric Light Company \| Notes Seven Point Nine Eight Percent Due June One Twenty Thirty One
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%
Fitchburg Gas and Electric Light Company \| Notes Six Point Seven Nine Percent Due October Fifteen Twenty Twenty Five
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%
Fitchburg Gas and Electric Light Company \| Notes Five Point Nine Zero Percent Due December Fifteen Twenty Thirty
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%
Northern Utilities Inc \| Senior Notes Six Point Nine Five Percent Due December Three Twenty Eighteen
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%
Northern Utilities Inc \| Senior Notes Five Point Two Nine Percent Due March Two Twenty Twenty
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%
Northern Utilities Inc \| Senior Notes Seven Point Seven Two Percent Due December Three Twenty Thirty Eight
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%
Granite State Gas Transmission Inc \| Senior Notes Seven Point One Five Percent Due December Fifteen Twenty Eighteen
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%
Unitil Realty Corp \| Senior Secured Notes Eight Point Zero Zero Percent Due Through August One Twenty Seventeen
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%

Summary of Interest Expense and Interest Income (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Interest Expense

Long-term Debt

$ 20.3

$ 20.0

Short-term Debt

1.5

1.7

Interest Expense

21.8

22.1

Interest Expense

22.3

22.0

Interest Income

Interest Income

(4.2)

(1.6)

(3.9)

Total Interest Expense, net

18.1

20.4

18.1

Other Regulatory Liability

Interest Expense

Interest Expense

0.5

0.3

Regulatory Asset

Interest Income

Interest Income

(3.4)

(1.1)

(3.5)

Allowance for Funds Used During Construction, Capitalized Interest

Interest Income

Interest Income

^[1]

$ (0.8)

$ (0.5)

$ (0.4)

[1]	AFUDC-Allowance for Funds Used During Construction

Borrowing Limits, Amounts Outstanding and Amounts Available Under Revolving Credit Facility (Detail) - Revolving Facility - USD ($) $ in Millions	Dec. 31, 2012	Jul. 24, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Revolving credit facility	$ 60.0	$ 115.0	$ 115.0
Outstanding revolving credit facility	49.4		87.9
Available revolving credit facility	$ 10.6		$ 27.1

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) $ in Thousands	Dec. 31, 2012 USD ($)
Operating leases
2013	$ 997
2014	804
2015	668
2016	479
2017	198
2018 - 2022	50
Total Payments	3,196
Capital lease
2013	628
2014	300
2015	82
2016
2017
2018 - 2022
Total Payments	$ 1,010

Energy Supply - Additional Information (Detail)	1 Months Ended	12 Months Ended
Energy Supply - Additional Information (Detail)	Jul. 31, 2012	Dec. 31, 2012 Bcf MMBTU
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities		14,057
Power supply contract duration		12 months
Percentage of power supply requirement		50.00%
Fitchburg Gas and Electric Light Company \| Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration		1 year
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities		100,000
Natural gas, underground storage \| Bcf		3.4
Northern Utilities Inc \| Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration		1 year
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Power supply contract duration	6 months
Percentage of power supply requirement	100.00%

Regulatory Matters - Additional Information (Detail) $ in Thousands	1 Months Ended								3 Months Ended	12 Months Ended
	Oct. 31, 2012 USD ($)	Jun. 29, 2012 USD ($)	Apr. 24, 2012 USD ($)	Dec. 16, 2011 USD ($)	Nov. 29, 2011 USD ($)	Aug. 31, 2011 USD ($)	Aug. 01, 2011 USD ($) yr	Apr. 26, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Nov. 02, 2011 USD ($)	Feb. 28, 2011 USD ($)	Dec. 31, 2009 USD ($)
Regulatory Assets [Line Items]
Regulatory Assets , Remaining Balance										$ 24,300
Accrued Revenue										58,100	$ 54,200
Environmental Obligations										$ 14,800	14,700
Minimum
Regulatory Assets [Line Items]
Cost recovery period, years										1 year
Maximum
Regulatory Assets [Line Items]
Cost recovery period, years										2 years
New Hampshire Division \| Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs										7 years
Maine Division \| Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs										5 years
Other Restructuring
Regulatory Assets [Line Items]
Accrued Revenue										$ 13,300
Environmental Matters
Regulatory Assets [Line Items]
Income (loss) incurred in excess of recorded amount										$ 0
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Return of Equity							9.20%
Deferred Emergency Storm Restoration Cost							$ 11,400
Amortized and Recovered Cost, Years \| yr							7
Recovery of damage of electrical system	$ 1,100
Portion of storm cost expenditures that the Company has requested deferral of and recovery of through rate adjustments				$ 4,300
Fitchburg Gas and Electric Light Company \| Environmental Restoration Costs
Regulatory Assets [Line Items]
Amortization period for environmental costs										7 years
Settlement insurance									$ 2,000
Fitchburg Gas and Electric Light Company \| Environmental Clean Up Costs
Regulatory Assets [Line Items]
Environmental Obligations										$ 12,000	12,000
Fitchburg Gas and Electric Light Company \| Tropical Storm Irene
Regulatory Assets [Line Items]
Storm expenditures				1,500
Fitchburg Gas and Electric Light Company \| Severe Snow Storm
Regulatory Assets [Line Items]
Storm expenditures				$ 3,300
Fitchburg Gas and Electric Light Company \| Natural Gas \| Court
Regulatory Assets [Line Items]
Refund of Cost												$ 4,500
Regulatory Liabilities												4,700		$ 4,900
Fitchburg Gas and Electric Light Company \| Natural Gas \| Supreme Court
Regulatory Assets [Line Items]
Refund of Cost												$ 200
Fitchburg Gas and Electric Light Company \| Electric Distribution
Regulatory Assets [Line Items]
Increase in annual revenue							$ 3,300
Fitchburg Gas and Electric Light Company \| Gas Distribution
Regulatory Assets [Line Items]
Increase in annual revenue							$ 3,700
Granite State Gas Transmission Inc \| Gas Transportation and Storage
Regulatory Assets [Line Items]
Additional Cost to Transmission Plant		$ 2,400								11,400
Annual revenue increase in rate adjustments		$ 300
Granite State Gas Transmission Inc \| Asset Recoverable Gas Costs
Regulatory Assets [Line Items]
Amount being Recovered										$ 4,000
Unitil Energy Systems Inc
Regulatory Assets [Line Items]
Settlement agreement date										May 01, 2016
Adjustment to recover the increased spending for vegetation management program and reliability enhancement program										$ 1,500
Recovery of damage of electrical system	$ 2,600
Customer's Overpayment Amount						$ 1,800
Amount Reimbursed to Customer						1,800
Interest on Reimbursement						300
Non-Recurring Charge on Distribution						$ 400
Request for recovery of under-billed customers													$ 1,400
Unitil Energy Systems Inc \| Storm Costs
Regulatory Assets [Line Items]
Cost recovery period, years				5 years
Recovery of damage of electrical system				$ 4,400
Interest rate allowed by regulators on the unrecovered amount of storm costs which have been approved for recovery through rate adjustments				4.52%
Unitil Energy Systems Inc \| Minimum
Regulatory Assets [Line Items]
Estimated increases for Capital Improvement										1,500
Unitil Energy Systems Inc \| Maximum
Regulatory Assets [Line Items]
Estimated increases for Capital Improvement										$ 2,000
Unitil Energy Systems Inc \| Range One
Regulatory Assets [Line Items]
Return of Equity										7.00%
Unitil Energy Systems Inc \| Range Two
Regulatory Assets [Line Items]
Return of Equity										10.00%
Unitil Energy Systems Inc \| Year One Policy
Regulatory Assets [Line Items]
Increase in annual revenue								$ 5,200
Amendment effective date								Jul. 01, 2010
Unitil Energy Systems Inc \| Year Two Policy
Regulatory Assets [Line Items]
Increase in annual revenue								$ 5,000
Amendment effective date								May 01, 2011
Northern Utilities Inc
Regulatory Assets [Line Items]
Increase in annual revenue			$ 3,700
Amendment effective date			May 1, 2012
Settlement agreement date			Apr. 24, 2012
Environmental Obligations										$ 2,800	$ 2,700
Northern Utilities Inc \| Maine Operations
Regulatory Assets [Line Items]
Increase in annual revenue					$ 7,800
Amendment effective date					January 1, 2012
Northern Utilities Inc \| Cast Iron Pipe Replacement Capital Spending
Regulatory Assets [Line Items]
Increase in annual revenue					$ 850
Amendment effective date					May 1, 2012

Company's Liability for Environmental Obligations (Detail) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Environmental Exit Cost [Line Items]

Total Environmental Obligations Balance at Beginning of Period

$ 14.7

$ 14.6

Changes in Estimates

0.1

Liabilities Assumed

Less: Payments / Reductions

Total Environmental Obligations at End of Period

14.8

14.7

Less: Current Portion

^[1]

1.0

0.2

Environmental Obligations-noncurrent-Balance at End of Period

$ 13.8

$ 14.5

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

- Definition

Carrying value of the obligation (known or estimated) arising from requirements to perform activities to remediate one or more sites, payable in twelve months or in the next operating cycle if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 450
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6952336&loc=d3e14326-108349

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6393242&loc=d3e13207-110859

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6361293&loc=d3e6911-107765

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 30
-Section 50
-Paragraph 10
-Subparagraph (d)(1)
-URI http://asc.fasb.org/extlink&oid=6393242&loc=d3e13237-110859

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.20)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Section A
-Paragraph 8
-Chapter 3
-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 5
-Paragraph 9
-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 AICPA
-Name Statement of Position (SOP)
-Number 96-1
-Paragraph 161, 163
-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 SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 20
-Article 5

+ Details

Bad Debts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 3.6	$ 4.3	$ 4.5
Unitil Energy Systems Inc
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 1.9	$ 1.8	$ 1.4

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Accounts and Other Receivables [Line Items]
Balance at Beginning of Period	$ 2.3	$ 2.6	$ 2.5
Provision	3.6	4.3	4.5
Recoveries	0.6	0.5	0.6
Accounts Written Off	4.6	5.1	5.0
Balance at End of Period	1.9	2.3	2.6
Electric
Accounts and Other Receivables [Line Items]
Balance at Beginning of Period	1.7	1.8	1.7
Provision	1.4	2.1	2.0
Recoveries	0.3	0.2	0.2
Accounts Written Off	2.3	2.4	2.1
Balance at End of Period	1.1	1.7	1.8
Gas
Accounts and Other Receivables [Line Items]
Balance at Beginning of Period	0.5	0.7	0.7
Provision	2.2	2.2	2.5
Recoveries	0.3	0.3	0.4
Accounts Written Off	2.3	2.7	2.9
Balance at End of Period	0.7	0.5	0.7
Others
Accounts and Other Receivables [Line Items]
Balance at Beginning of Period	0.1	0.1	0.1
Balance at End of Period	$ 0.1	$ 0.1	$ 0.1

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current Federal Tax Provision (Benefit)
Current Benefit of Operating Loss Carrybacks			$ (6,026)
Total Current Federal Tax Provision (Benefit)			(6,026)
Deferred Federal Tax Provision (Benefit)
Utility Plant Differences	$ 6,019	$ 13,002	11,821
Net Operating Loss Carryforwards	2,835	(4,844)	(5,520)
Regulatory Assets and Liabilities	472	513	3,338
Other, net	(241)	(695)	(480)
Total Deferred Federal Tax Provision (Benefit)	9,085	7,976	9,159
Total Federal Tax Provision	9,085	7,976	3,133
State
Current	132	1,358	28
Deferred	1,759	691	1,303
Total State Tax Provision	1,891	2,049	1,331
Total Provision for Federal and State Income Taxes	$ 11,000	$ 10,000	$ 4,500

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	34.00%	34.00%	34.00%
State Income Taxes, Net	5.00%	5.00%	6.00%
Utility Plant Differences	(2.00%)	(1.00%)	(7.00%)
Other, Net	1.00%		(1.00%)
Effective Income Tax Rate	38.00%	38.00%	32.00%

Deferred Tax Assets and Liabilities, Current (Detail) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current Deferred Income Taxes
Accrued Revenue, Current Portion	$ 13,568	$ 9,358
Other, net	(168)	(366)
Total Current Deferred Income Tax Liabilities	$ 13,400	$ 9,000

- Definition

Amount of deferred tax liability attributable to taxable temporary differences, net of deferred tax asset attributable to deductible temporary differences and carryforwards net of valuation allowances expected to be realized or consumed within one year or operating cycle, if longer.

+ References + Details

Deferred Tax Assets and Liabilities, Non Current (Detail) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Schedule of Deferred Tax Assets and Liabilities [Line Items]
Utility Plant Differences	$ 66,907	$ 57,809
Net Operating Loss Carryforwards	(8,521)	(11,656)
AMT Tax Credit Carryforwards	(1,538)	(1,366)
Regulatory Assets and Liabilities	17,872	23,269
Retirement Benefit Obligations	(38,644)	(33,591)
Other, net	2,606	2,829
Total Noncurrent Deferred Income Tax Liabilities	$ 38,700	$ 37,300

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets	$ 8,521	$ 11,656
Alternative Minimum tax credit carryforwards	$ 1,538	$ 1,366
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date	2029
Internal Revenue Service (IRS) \| Federal Net Operating Loss Carryforwards
Operating Loss Carryforwards [Line Items]
Operating Loss Refunds	$ 2,000
Federal and State
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets	$ 8,500
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date	2019
Federal
Operating Loss Carryforwards [Line Items]
Tax examination description	The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2009; December 31, 2010; and December 31, 2011.

Segment Information - Additional Information (Detail)	12 Months Ended
Segment Information - Additional Information (Detail)	Dec. 31, 2012 mi Entity Segment Pipeline
Segment Reporting Information [Line Items]
No of segments \| Segment	4
No of subsidiaries \| Entity	3
Length of pipeline	86
Granite State Gas Transmission Inc
Segment Reporting Information [Line Items]
Length of pipeline	86
No of major pipeline \| Pipeline	3

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 98.8	$ 71.3	$ 68.8	$ 114.2	$ 94.7	$ 73.2	$ 69.5	$ 115.4	$ 353.1	$ 352.8	$ 358.4
Interest Income									3.7	1.4	4.0
Interest Expense									21.8	21.8	22.1
Depreciation & Amortization Expense									35.1	29.3	28.9
Income Tax Expense									11.0	10.0	4.5
Segment Profit	9.0	$ 0.5	$ (0.4)	$ 9.0	10.0	$ (1.6)	$ (0.8)	$ 8.7	18.1	16.3	9.5
Segment Assets	886.6				846.7				886.6	846.7	800.4
Capital Expenditures									68.5	57.1	49.6
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									187.0	188.1	203.7
Interest Income									2.4	0.7	3.2
Interest Expense									9.0	9.4	9.6
Depreciation & Amortization Expense									18.0	14.2	13.9
Income Tax Expense									4.8	5.2	3.7
Segment Profit									7.6	7.8	8.0
Segment Assets	403.7				393.8				403.7	393.8	388.2
Capital Expenditures									21.2	20.3	19.8
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									160.6	159.2	150.1
Interest Income									0.8	0.5	0.5
Interest Expense									11.1	10.7	10.5
Depreciation & Amortization Expense									15.7	13.6	14.2
Income Tax Expense									5.8	4.3	(0.7)
Segment Profit									8.9	6.7	1.4
Segment Assets	471.6				440.9				471.6	440.9	401.1
Capital Expenditures									43.9	33.6	27.4
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									0.4	0.1	0.2
Interest Expense									1.7	1.7	2.0
Depreciation & Amortization Expense									1.4	1.5	0.8
Income Tax Expense									(0.5)	(0.6)	0.5
Segment Profit									0.3	0.1	(1.4)
Segment Assets	5.6				6.5				5.6	6.5	5.7
Capital Expenditures									3.4	3.2	2.4
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									5.5	5.5	4.6
Interest Income									0.1	0.1	0.1
Income Tax Expense									0.9	1.1	1.0
Segment Profit									1.3	1.7	1.5
Segment Assets	$ 5.7				$ 5.5				$ 5.7	$ 5.5	$ 5.4

Key Assumptions used in Determining Benefit Plan Costs and Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Rate of Compensation Increase	3.00%	3.50%	3.50%
Expected Long-term rate of return on plan assets	8.50%
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.60%	5.35%	5.75%
Rate of Compensation Increase	3.00%	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	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	$ 981	$ 909	$ 728
Effect of 1% Decrease in Health Care Cost Trend Rate	$ (756)	$ (705)	$ (565)
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.00%	4.60%	5.35%
Rate of Compensation Increase	3.00%	3.00%	3.50%
Health Care Cost Trend Rate Assumed for Next Year	8.00%	6.50%	7.00%
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	$ 11,808	$ 9,109	$ 7,530
Effect of 1% Decrease in Health Care Cost Trend Rate	$ (9,291)	$ (7,217)	$ (5,997)

Retirement Benefit Plans - Additional Information (Detail) - USD ($)

1 Months Ended

12 Months Ended

Jul. 06, 2012

Jun. 25, 2010

Jan. 31, 2010

Aug. 17, 2006

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Defined Benefit Plan Disclosure [Line Items]

Change in Discount Rate

0.25%

Increase or decrease of Net Periodic Benefit Cost (NPBC) due to change in the discount rate

$ 367,000

$ 325,000

$ 300,000

Increase in Rate of Compensation

3.00%

3.50%

Pension expense

$ 6,300,000

$ 6,200,000

$ 5,600,000

Regulatory Assets

$ 182,600,000

185,800,000

Defined Benefit Plan, Description of Settlements and Curtailments

The Company evaluated the two alternative shortfall amortization periods under the Relief Act and made the decision to continue with the seven year amortization period.

Defined Benefit Plan, Expected Long-term Return on Assets

8.50%

Defined Benefit Plan, Expected Long-term Rate-of-Return on Assets Assumption

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.

Pension Protection Act

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Funded Percentage

100.00%

Amortization Period For Defined Benefit Plan

7 years

Well-Funded Pension Plan

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Funded Percentage

100.00%

Company's contributions

$ 3,100,000

$ 1,100,000

8,300,000

Well-Funded Pension Plan | Minimum

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Funded Percentage

92.00%

Minimum required contribution

1,000,000

Well-Funded Pension Plan | Maximum

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Funded Percentage

100.00%

Minimum required contribution

$ 6,100,000

Employee Retirement Income Security Act Class Action

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Funded Percentage

80.00%

Amortization Period For Defined Benefit Plan

7 years

Defined Benefit Plan, shortfall

$ 10,200,000

Defined Benefit Plan, Annual Employer Contributions

$ 1,700,000

Defined Benefit Obligations

Defined Benefit Plan Disclosure [Line Items]

Regulatory Assets

62,500,000

55,300,000

Fair Value Of Plan Assets

Defined Benefit Plan Disclosure [Line Items]

Pension expense

6,700,000

5,700,000

6,200,000

Total contributions | Well-Funded Pension Plan

Defined Benefit Plan Disclosure [Line Items]

Company's contributions

9,400,000

Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Accumulated Benefit Obligation

103,400,000

91,300,000

Defined Benefit Plan, shortfall

(3,617,000)

(3,132,000)

(2,406,000)

Other Postretirement Benefit Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, shortfall

(129,000)

Company's contributions

$ 2,190,000

3,482,000

Other Postretirement Benefit Plans, Defined Benefit | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

55.00%

Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

45.00%

Supplemental Employee Retirement Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Accumulated Benefit Obligation

$ 4,800,000

500,000

Defined Benefit Plan, shortfall

(64,000)

(78,000)

(133,000)

Company's contributions

53,000

Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Company's contributions

$ 9,387,000

8,813,000

4,302,000

Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

48.00%

Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

47.00%

Pension Plans | Equity And Debt Securities

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

5.00%

Four Zero One K Plan

Defined Benefit Plan Disclosure [Line Items]

Company's contributions

$ 1,387,000

$ 1,190,000

$ 980,000

Scenario, Forecast | Pension Plans

Defined Benefit Plan Disclosure [Line Items]

Amortizations related to Actuarial Loss and Prior Service Cost

4,400,000

Scenario, Forecast | Other Postretirement Benefit Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Amortizations related to Actuarial Loss and Prior Service Cost

2,500,000

Scenario, Forecast | Supplemental Employee Retirement Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Amortizations related to Actuarial Loss and Prior Service Cost

$ 200,000

Scenario, Forecast | Pension Plans | Equity Funds

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

48.00%

Scenario, Forecast | Pension Plans | Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

47.00%

Scenario, Forecast | Pension Plans | Equity And Debt Securities

Defined Benefit Plan Disclosure [Line Items]

Defined Benefit Plan, Target Plan Asset Allocations

^[1]

5.00%

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

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	$ 3,227	$ 2,941	$ 2,608
Interest Cost	4,633	4,684	4,457
Expected Return on Plan Assets	(5,390)	(4,840)	(4,181)
Prior Service Cost Amortization	188	249	253
Curtailment Loss			41
Actuarial Loss Amortization	3,617	3,132	2,406
Sub-total	6,275	6,166	5,584
Amounts Capitalized and Deferred	(2,726)	(2,590)	(2,240)
Net Periodic Benefit Cost Recognized	3,549	3,576	3,344
Other Postretirement Benefit Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	2,066	1,918	1,466
Interest Cost	2,303	2,279	2,016
Expected Return on Plan Assets	(695)	(818)	(599)
Prior Service Cost Amortization	1,729	1,729	1,579
Transition Obligation Amortization	21	21	21
Actuarial Loss Amortization	129
Sub-total	5,553	5,129	4,483
Amounts Capitalized and Deferred	(2,127)	(1,622)	(1,183)
Net Periodic Benefit Cost Recognized	3,426	3,507	3,300
Supplemental Employee Retirement Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	289	285	285
Interest Cost	211	227	227
Prior Service Cost Amortization	11	11	2
Actuarial Loss Amortization	64	78	133
Sub-total	575	601	647
Net Periodic Benefit Cost Recognized	$ 575	$ 601	$ 647

Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Service Cost	$ 3,227	$ 2,941	$ 2,608
Interest Cost	4,633	4,684	4,457
Curtailment Gain			(41)
Funded Status: Assets vs PBO	(44,081)	(43,019)
Pension Plans \| Change in Plan Assets
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Plan Assets at Beginning of Year	59,700	54,100
Actual Return on Plan Assets	7,780	225
Employer Contributions	9,387	8,813
Acquired Plan Assets
Benefits Paid	(4,456)	(3,438)
Plan Assets at End of Year	72,411	59,700	54,100
Pension Plans \| Change In Projected Benefit Obligation
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
PBO at Beginning of Year	102,719	89,393
Service Cost	3,227	2,941
Interest Cost	4,633	4,684
Plan Amendments	617
Curtailment Gain
Benefits Paid	(4,456)	(3,438)
Actuarial (Gain) or Loss	9,752	9,139
PBO at End of Year	116,492	102,719	89,393
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Service Cost	2,066	1,918	1,466
Interest Cost	2,303	2,279	2,016
Employer Contributions	2,190		3,482
Participant Contributions	18	13
Benefits Paid	(2,083)	(1,644)	(1,848)
Funded Status: Assets vs PBO	(53,791)	(43,591)
Other Postretirement Benefit Plans, Defined Benefit \| Change in Plan Assets
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Plan Assets at Beginning of Year	7,339	8,862
Actual Return on Plan Assets	837	108
Employer Contributions	2,190
Participant Contributions	18	13
Acquired Plan Assets
Benefits Paid	(2,083)	(1,644)
Plan Assets at End of Year	8,301	7,339	8,862
Other Postretirement Benefit Plans, Defined Benefit \| Change In Projected Benefit Obligation
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
PBO at Beginning of Year	50,930	43,344
Service Cost	2,066	1,918
Interest Cost	2,303	2,279
Participant Contributions	18	13
Plan Amendments	(318)
Curtailment Gain
Benefits Paid	(2,083)	(1,644)
Actuarial (Gain) or Loss	9,176	5,020
PBO at End of Year	62,092	50,930	43,344
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Service Cost	289	285	285
Interest Cost	211	227	227
Employer Contributions	53	53	53
Benefits Paid	(53)	(53)	(53)
Funded Status: Assets vs PBO	(6,207)	(4,615)
Supplemental Employee Retirement Plans, Defined Benefit \| Change in Plan Assets
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
Employer Contributions	53	53
Acquired Plan Assets
Benefits Paid	(53)	(53)
Supplemental Employee Retirement Plans, Defined Benefit \| Change In Projected Benefit Obligation
Schedule of Defined Benefit Plan Change in Benefit Obligation [Line Items]
PBO at Beginning of Year	4,615	4,263
Service Cost	289	285
Interest Cost	211	227
Curtailment Gain
Benefits Paid	(53)	(53)
Actuarial (Gain) or Loss	1,145	(107)
PBO at End of Year	$ 6,207	$ 4,615	$ 4,263

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Plans
Defined Contribution Benefit Plans [Line Items]
Employer Contributions	$ 9,387	$ 8,813	$ 4,302
Benefit Payments	4,456	3,438	3,185
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Benefit Plans [Line Items]
Employer Contributions	2,190		3,482
Participant Contributions	18	13
Benefit Payments	2,083	1,644	1,848
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Benefit Plans [Line Items]
Employer Contributions	53	53	53
Benefit Payments	$ 53	$ 53	$ 53

- Definition

The amount of payments made for which participants are entitled under a pension plan, including pension benefits, death benefits, and benefits due on termination of employment. Also includes payments made under a postretirement benefit plan, including prescription drug benefits, health care benefits, life insurance benefits, and legal, educational and advisory services. This item represents a periodic decrease to the plan obligations and a decrease to plan assets.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 60
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6414203&loc=d3e39716-114964

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 30
-Glossary Benefits
-URI http://asc.fasb.org/extlink&oid=6506267

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 60
-Glossary Benefits
-URI http://asc.fasb.org/extlink&oid=6506309

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (a)(6)
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Postretirement Benefits
-URI http://asc.fasb.org/extlink&oid=6521376

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (b)(5)
-URI http://asc.fasb.org/extlink&oid=21915506&loc=d3e1928-114920

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS106-2
-Paragraph 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 8: 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 9: 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 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a, 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.

+ Details

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2012 USD ($)
Pension Plans
Schedule of Pension Expected Future Benefit Payments [Line Items]
2013	$ 4,698
2014	4,448
2015	4,567
2016	4,908
2017	5,121
2018 - 2022	30,278
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2013	1,811
2014	1,960
2015	2,083
2016	2,156
2017	2,284
2018 - 2022	13,535
Supplemental Employee Retirement Plans, Defined Benefit
Schedule of Pension Expected Future Benefit Payments [Line Items]
2013	357
2014	353
2015	349
2016	344
2017	339
2018 - 2022	$ 1,767

Actual Investment Allocations (Detail)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Pension Plans

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Actual Allocation

100.00%

Pension Plans | Equity Funds

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

48.00%

Actual Allocation

48.00%

49.00%

58.00%

Pension Plans | Fixed Income Securities

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

47.00%

Actual Allocation

47.00%

46.00%

42.00%

Pension Plans | Equity And Debt Securities

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

5.00%

Actual Allocation

^[1]

5.00%

0.00%

Pension Plans | Scenario, Forecast | Equity Funds

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

48.00%

Pension Plans | Scenario, Forecast | Fixed Income Securities

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

47.00%

Pension Plans | Scenario, Forecast | Equity And Debt Securities

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

^[1]

5.00%

Other Postretirement Benefit Plans, Defined Benefit

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Actual Allocation

100.00%

Other Postretirement Benefit Plans, Defined Benefit | Equity Funds

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

55.00%

Actual Allocation

56.00%

55.00%

56.00%

Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Target Allocation

45.00%

Actual Allocation

44.00%

45.00%

44.00%

Other Postretirement Benefit Plans, Defined Benefit | Scenario, Forecast | Equity Funds

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Actual Allocation

55.00%

Other Postretirement Benefit Plans, Defined Benefit | Scenario, Forecast | Fixed Income Securities

Schedule of Defined Benefit Plan Asset Allocation Targets [Line Items]

Actual Allocation

45.00%

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

Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	$ 72,411	$ 59,700
Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	34,742	29,094
Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	34,251	27,697
Equity And Debt Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	3,418	2,909
Fair Value, Inputs, Level 1
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	72,411	59,700
Fair Value, Inputs, Level 1 \| Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	34,742	29,094
Fair Value, Inputs, Level 1 \| Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	34,251	27,697
Fair Value, Inputs, Level 1 \| Equity And Debt Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	3,418	2,909
Fair Value, Inputs, Level 2
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 2 \| Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 2 \| Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 2 \| Equity And Debt Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3 \| Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3 \| Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3 \| Equity And Debt Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	$ 8,301	$ 7,339
Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	3,670	3,311
Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	3,357	2,977
Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	1,274	1,051
Fair Value, Inputs, Level 1
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	8,301	7,339
Fair Value, Inputs, Level 1 \| Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	3,670	3,311
Fair Value, Inputs, Level 1 \| Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	3,357	2,977
Fair Value, Inputs, Level 1 \| Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis	1,274	1,051
Fair Value, Inputs, Level 2
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 2 \| Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 2 \| Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 2 \| Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3 \| Fixed Income Securities
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3 \| Index Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis
Fair Value, Inputs, Level 3 \| Equity Funds
Schedule of Pension and Other Postretirment Plan Assets by Fair Value [Line Items]
Assets measured at fair value on recurring basis

Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 98.8	$ 71.3	$ 68.8	$ 114.2	$ 94.7	$ 73.2	$ 69.5	$ 115.4	$ 353.1	$ 352.8	$ 358.4
Operating Income	13.2	5.0	4.3	14.0	14.4	5.2	4.2	13.4	36.5	37.2	28.0
Net Income (Loss) Applicable to Common	$ 9.0	$ 0.5	$ (0.4)	$ 9.0	$ 10.0	$ (1.6)	$ (0.8)	$ 8.7	$ 18.1	$ 16.3	$ 9.5
Per Share Data:
Earnings Per Common Share	$ 0.66	$ 0.03	$ (0.03)	$ 0.83	$ 0.92	$ (0.15)	$ (0.08)	$ 0.81	$ 1.43	$ 1.50	$ 0.88
Dividends Paid Per Common Share	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 0.345	$ 1.38	$ 1.38	$ 1.38