Unitil (UTL) 10-Q 22 Oct 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 19, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	755,001
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		13,983,403

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating Revenues
Gas	$ 21.7	$ 20.9	$ 149.6	$ 139.3
Electric	51.4	54.2	170.1	162.2
Other	1.6	1.5	4.7	4.5
Total Operating Revenues	74.7	76.6	324.4	306
Operating Expenses
Cost of Gas Sales	5.5	5.7	76.5	71.3
Cost of Electric Sales	29.2	31.6	106.2	101.5
Operation and Maintenance	16.8	16.9	50	49.3
Depreciation and Amortization	11.4	10.8	34.1	31.2
Taxes Other Than Income Taxes	4.5	4.2	13	12.8
Total Operating Expenses	67.4	69.2	279.8	266.1
Operating Income	7.3	7.4	44.6	39.9
Interest Expense, net	5.5	5	17.3	15.5
Other Expense, net		0.1	0.2	0.3
Income Before Income Taxes	1.8	2.3	27.1	24.1
Income Tax Expense	0.1	0.7	10.1	8.8
Net Income	$ 1.7	$ 1.6	$ 17	$ 15.3
Net Income Per Common Share (Basic and Diluted)	$ 0.12	$ 0.11	$ 1.22	$ 1.10
Weighted Average Common Shares Outstanding - (Basic and Diluted)	13.9	13.8	13.9	13.8
Dividends Declared Per Share of Common Stock	$ 0.350	$ 0.345	$ 1.050	$ 1.035

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Current Assets:
Cash and Cash Equivalents	$ 8.9	$ 8.4	$ 10.1
Accounts Receivable, net	45.4	60.7	41.6
Accrued Revenue	28.8	48.5	31.4
Exchange Gas Receivable	10.6	15	14.5
Deferred Income Taxes	12.5		2.1
Gas Inventory	0.6	1.1	1
Materials and Supplies	6.8	6.3	6.6
Prepayments and Other	5.4	5.2	5.1
Total Current Assets	119	145.2	112.4
Utility Plant:
Gas	540.2	522.9	488.9
Electric	398.4	390.6	382.9
Common	35.4	32.7	32.4
Construction Work in Progress	77.6	42.6	54.2
Total Utility Plant	1,051.6	988.8	958.4
Less: Accumulated Depreciation	269.2	255.1	252.4
Net Utility Plant	782.4	733.7	706
Other Noncurrent Assets:
Regulatory Assets	102.8	107.6	85.3
Other Assets	13.8	13.7	12.8
Total Other Noncurrent Assets	116.6	121.3	98.1
TOTAL ASSETS	1,018	1,000.2	916.5
Current Liabilities:
Accounts Payable	21.2	44.2	19.3
Short-Term Debt	4.1	29.3	1.4
Long-Term Debt, Current Portion	4.1	4	2.5
Energy Supply Obligations	15.8	22.1	18.1
Deferred Income Taxes		3.1
Environmental Obligations	5	3.5	5.3
Interest Payable	6.3	3.5	5.4
Regulatory Liabilities	28.1	8.7	13
Taxes Payable	4.9	0.1	0.1
Other Current Liabilities	11.7	10.9	10.9
Total Current Liabilities	101.2	129.4	76
Noncurrent Liabilities:
Deferred Income Taxes	91.7	72.9	88.3
Cost of Removal Obligations	69.9	63.8	63.2
Retirement Benefit Obligations	122	118.6	81.8
Regulatory Liabilities	11	0.1
Capital Lease Obligations	12.1	7.5	6.5
Environmental Obligations	0.5	2	2
Other Noncurrent Liabilities	3.5	3.7	4.1
Total Noncurrent Liabilities	310.7	268.6	245.9
Capitalization:
Long-Term Debt, Less Current Portion	328.4	328.9	326.7
Stockholders' Equity:
Common Equity (Authorized: 25,000,000 and Outstanding: 13,982,941, 13,906,964 and 13,916,026 Shares)	236.8	234.7	233.9
Retained Earnings	40.7	38.4	33.8
Total Common Stock Equity	277.5	273.1	267.7
Preferred Stock	0.2	0.2	0.2
Total Stockholders' Equity	277.7	273.3	267.9
Total Capitalization	$ 606.1	$ 602.2	$ 594.6
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,018	$ 1,000.2	$ 916.5

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Common Stock Authorized	25,000,000	25,000,000	25,000,000
Common Equity Outstanding	13,982,941	13,916,026	13,906,964

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating Activities:
Net Income	$ 17	$ 15.3
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	34.1	31.2
Deferred Tax Provision	3.6	8.2
Changes in Working Capital Items:
Accounts Receivable	15.3	10.6
Accrued Revenue	19.7	25.2
Regulatory Liabilities	19.4	3.3
Taxes Payable	4.8	(0.1)
Exchange Gas Receivable	4.4	(3.7)
Accounts Payable	(23)	(18.8)
Other Changes in Working Capital Items	2.9	7.1
Deferred Regulatory and Other Charges	13.9	5.1
Other, net	(1.2)	(0.8)
Cash Provided by Operating Activities	110.9	82.6
Investing Activities:
Property, Plant and Equipment Additions	(70.9)	(60.7)
Cash (Used in) Investing Activities	(70.9)	(60.7)
Financing Activities:
Repayment of Short-Term Debt, net	(25.2)	(16.5)
Repayment of Long-Term Debt	(0.4)	(0.4)
Increase in Capital Lease Obligations	4.1	5.6
Net Increase (Decrease) in Exchange Gas Financing	(4.3)	3.6
Dividends Paid	(14.7)	(14.4)
Proceeds from Issuance of Common Stock, net	1	0.9
Cash (Used in) Financing Activities	(39.5)	(21.2)
Net Increase in Cash and Cash Equivalents	0.5	0.7
Cash and Cash Equivalents at Beginning of Period	8.4	9.4
Cash and Cash Equivalents at End of Period	8.9	10.1
Supplemental Cash Flow Information:
Interest Paid	14.9	13.5
Income Taxes Paid	1.8	1.2
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 1.2	$ 1.7

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Balance at Dec. 31, 2013	$ 265	$ 232.1	$ 32.9
Net Income	15.3		15.3
Dividends on Common Shares	(14.4)		(14.4)
Stock Compensation Plans	0.9	0.9
Issuance of Common Shares	0.9	0.9
Balance at Sep. 30, 2014	267.7	233.9	33.8
Balance at Dec. 31, 2014	273.1	234.7	38.4
Net Income	17		17
Dividends on Common Shares	(14.7)		(14.7)
Stock Compensation Plans	1.1	1.1
Issuance of Common Shares	1	1
Balance at Sep. 30, 2015	$ 277.5	$ 236.8	$ 40.7

CONSOLIDATED STATEMENTS OF CHA7

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Common stock, shares issued	27,776	28,958

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use natural gas for heating purposes. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the distribution utilities). Granite State is a natural gas transportation pipeline, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. Unitil also has three other wholly-owned subsidiaries: Unitil Service; Unitil Realty; and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States. Basis of Presentation – 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. To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3. There have been no changes in the valuation techniques used during the current period. Income Taxes – Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. Deferred income taxes are reflected as Deferred Income Taxes in Current Assets and Noncurrent Liabilities on the Consolidated Balance Sheets based on the nature of the underlying timing item. Cash and Cash Equivalents – Allowance for Doubtful Accounts – The Allowance for Doubtful Accounts as of September 30, 2015, September 30, 2014 and December 31, 2014, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows: ($ millions) September 30, December 31, 2015 2014 2014 Allowance for Doubtful Accounts $ 2.0 $ 2.1 $ 1.8 Accrued Revenue – September 30, December 31, Accrued Revenue ($ millions) 2015 2014 2014 Regulatory Assets – Current $ 22.6 $ 24.6 $ 37.8 Unbilled Revenues 6.2 6.8 10.7 Total Accrued Revenue $ 28.8 $ 31.4 $ 48.5 Exchange Gas Receivable – September 30, December 31, Exchange Gas Receivable ($ millions) 2015 2014 2014 Northern Utilities $ 9.9 $ 13.4 $ 14.2 Fitchburg 0.7 1.1 0.8 Total Exchange Gas Receivable $ 10.6 $ 14.5 $ 15.0 Gas Inventory September 30, December 31, Gas Inventory ($ millions) 2015 2014 2014 Natural Gas $ 0.3 $ 0.8 $ 0.8 Propane 0.2 0.1 0.2 Liquefied Natural Gas & Other 0.1 0.1 0.1 Total Gas Inventory $ 0.6 $ 1.0 $ 1.1 Utility Plant – Regulatory Accounting – September 30, December 31, Regulatory Assets consist of the following ($ millions) 2015 2014 2014 Retirement Benefits $ 65.3 $ 42.2 $ 65.1 Energy Supply & Other Regulatory Tracker Mechanisms 17.4 17.6 31.0 Deferred Storm Charges 16.9 20.7 21.2 Environmental 11.1 10.6 11.0 Income Taxes 8.9 10.1 9.7 Deferred Restructuring Costs — 2.1 1.6 Other 5.8 6.6 5.8 Total Regulatory Assets $ 125.4 $ 109.9 $ 145.4 Less: Current Portion of Regulatory Assets (1) 22.6 24.6 37.8 Regulatory Assets – noncurrent $ 102.8 $ 85.3 $ 107.6 (1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets. September 30, December 31, Regulatory Liabilities consist of the following ($ millions) 2015 2014 2014 Regulatory Tracker Mechanisms $ 17.1 $ 13.0 $ 8.8 Gas Pipeline Refund (Note 6) 22.0 — — Total Regulatory Liabilities 39.1 13.0 $ 8.8 Less: Current Portion of Regulatory Liabilities 28.1 13.0 8.7 Regulatory Liabilities – noncurrent $ 11.0 $ — $ 0.1 Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future. Derivatives – The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Northern Utilities purchases call option contracts on NYMEX natural gas futures contracts for future winter period months. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause. As of September 30, 2015, September 30, 2014 and December 31, 2014 the Company had 3.7 billion, 3.0 billion and 2.4 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program. The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s unaudited Consolidated Balance Sheets. Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of: Fair Value Description Balance Sheet Sept. 30, 2015 Sept. 30, December 31, Derivative Assets Natural Gas Options Contracts Prepayments $ — $ — $ — Natural Gas Options Contracts Other Assets 0.1 — 0.1 Total Derivative Assets $ 0.1 $ — $ 0.1 Derivative Liabilities Natural Gas Options Contracts Other Current $ — $ 0.1 $ — Natural Gas Options Contracts Other — 0.1 — Total Derivative Liabilities $ — $ 0.2 $ — Three Months Ended Nine Months Ended ($ millions) 2015 2014 2015 2014 Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: Natural Gas Futures / Options Contracts $ 0.2 $ 0.1 $ 0.2 $ (0.4 ) Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings (1) Cost of Gas Sales $ 0.2 $ 0.1 $ 0.2 $ (0.8 ) (1) These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings. Energy Supply Obligations – September 30, December 31, Energy Supply Obligations ($ millions) 2015 2014 2014 Current: Exchange Gas Obligation $ 9.9 $ 13.4 $ 14.2 Renewable Energy Portfolio Standards 5.5 4.1 7.4 Power Supply Contract Divestitures 0.4 0.6 0.5 Total Energy Supply Obligations – Current 15.8 18.1 22.1 Long-Term: Power Supply Contract Divestitures 1.7 2.1 1.9 Total Energy Supply Obligations $ 17.5 $ 20.2 $ 24.0 Exchange Gas Obligation – Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations. Renewable Energy Portfolio Standards – Renewable Energy Portfolio Standards (RPS) require retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets. Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling rate mechanism. Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The current and noncurrent obligations related to these divestitures are recorded in Energy Supply Obligations and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion). Massachusetts Green Communities Act – In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism. Recently Issued Pronouncements – In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements. In July 2015, the FASB issued ASU 2015-11 which provides authoritative guidance requiring inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. This pronouncement is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Company is evaluating this new guidance and does not expect it to have any impact on the Company’s Consolidated Financial Statements. In May 2015, the FASB issued ASU 2015-07 which provides authoritative guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all periods presented. The Company is evaluating the impact this new guidance may have on its disclosures and does not expect it to have a material impact on the Company’s Consolidated Financial Statements. In April 2015, the FASB issued ASU 2015-03 which requires entities to present debt issuance costs related to a debt liability as a direct deduction from the carrying amount of that debt liability on the balance sheet as opposed to being presented as a deferred charge. ASU 2015-03 does not contain guidance for debt issuance costs related to line-of-credit arrangements. Consequently, in August 2015, the FASB issued ASU 2015-15 to add paragraphs indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The effective date of these pronouncements is for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements. Other than the pronouncements discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company. Subsequent Events –

DIVIDENDS DECLARED PER SHARE

DIVIDENDS DECLARED PER SHARE	9 Months Ended
	Sep. 30, 2015
DIVIDENDS DECLARED PER SHARE	NOTE 2 – DIVIDENDS DECLARED PER SHARE Declaration Date Date Paid (Payable) Shareholder of Record Date Dividend Amount 10/21/15 11/27/15 11/13/15 $ 0.350 07/22/15 08/28/15 08/14/15 $ 0.350 04/22/15 05/28/15 05/14/15 $ 0.350 01/26/15 02/27/15 02/13/15 $ 0.350 10/21/14 11/28/14 11/14/14 $0.345 07/22/14 08/29/14 08/15/14 $0.345 04/22/14 05/29/14 05/15/14 $ 0.345 01/16/14 02/28/14 02/14/14 $ 0.345

SEGMENT INFORMATION

SEGMENT INFORMATION	9 Months Ended
	Sep. 30, 2015
SEGMENT INFORMATION	NOTE 3 – SEGMENT INFORMATION The following table provides significant segment financial data for the three and nine months ended September 30, 2015 and September 30, 2014 and as of December 31, 2014 (millions): Three Months Ended September 30, 2015 Gas Electric Non- Regulated Other Total Revenues $ 21.7 $ 51.4 $ 1.6 $ — $ 74.7 Segment Profit (Loss) (1.4 ) 2.5 0.3 0.3 1.7 Capital Expenditures 22.5 7.8 — 2.1 32.4 Three Months Ended September 30, 2014 Revenues $ 20.9 $ 54.2 $ 1.5 $ — $ 76.6 Segment Profit (Loss) (1.5 ) 2.9 0.2 — 1.6 Capital Expenditures 23.1 7.1 0.1 1.3 31.6 Nine Months Ended September 30, 2015 Revenues $ 149.6 $ 170.1 $ 4.7 $ — $ 324.4 Segment Profit 9.5 6.2 0.9 0.4 17.0 Capital Expenditures 45.4 19.5 0.1 5.9 70.9 Segment Assets 584.3 413.8 6.4 13.5 1,018.0 Nine Months Ended September 30, 2014 Revenues $ 139.3 $ 162.2 $ 4.5 $ — $ 306.0 Segment Profit 9.3 5.2 0.6 0.2 15.3 Capital Expenditures 39.4 17.2 0.4 3.7 60.7 Segment Assets 505.6 392.1 6.4 12.4 916.5 As of December 31, 2014 Segment Assets $ 566.3 $ 414.1 $ 6.3 $ 13.5 $ 1,000.2

DEBT AND FINANCING ARRANGEMENTS

DEBT AND FINANCING ARRANGEMENTS	9 Months Ended
	Sep. 30, 2015
DEBT AND FINANCING ARRANGEMENTS	NOTE 4 – DEBT AND FINANCING ARRANGEMENTS Long-Term Debt – Details on long-term debt at September 30, 2015, September 30, 2014 and December 31, 2014 are shown below: ($ millions) September 30, December 31, 2015 2014 2014 Unitil Corporation Senior Notes: 6.33% Notes, Due May 1, 2022 $ 20.0 $ 20.0 $ 20.0 Unitil Energy Systems, Inc.: First Mortgage Bonds: 5.24% Series, Due March 2, 2020 15.0 15.0 15.0 8.49% Series, Due October 14, 2024 15.0 15.0 15.0 6.96% Series, Due September 1, 2028 20.0 20.0 20.0 8.00% Series, Due May 1, 2031 15.0 15.0 15.0 6.32% Series, Due September 15, 2036 15.0 15.0 15.0 Fitchburg Gas and Electric Light Company: Long-Term Notes: 6.75% Notes, Due November 30, 2023 15.2 19.0 15.2 7.37% Notes, Due January 15, 2029 12.0 12.0 12.0 7.98% Notes, Due June 1, 2031 14.0 14.0 14.0 6.79% Notes, Due October 15, 2025 10.0 10.0 10.0 5.90% Notes, Due December 15, 2030 15.0 15.0 15.0 Northern Utilities, Inc.: Senior Notes: 6.95% Senior Notes, Due December 3, 2018 30.0 30.0 30.0 5.29% Senior Notes, Due March 2, 2020 25.0 25.0 25.0 7.72% Senior Notes, Due December 3, 2038 50.0 50.0 50.0 4.42% Senior Notes, Due October 15, 2044 50.0 — 50.0 Granite State Gas Transmission, Inc.: Senior Notes: 7.15% Senior Notes, Due December 15, 2018 10.0 10.0 10.0 Unitil Realty Corp.: Senior Secured Notes: 8.00% Notes, Due Through August 1, 2017 1.3 1.9 1.7 Total Long-Term Debt 332.5 286.9 332.9 Short-Term Debt Reclassified to Long-Term Debt — 42.3 — Total Long-Term Debt After Reclassification 332.5 329.2 332.9 Less: Current Portion 4.1 2.5 4.0 Total Long-term Debt, Less Current Portion $ 328.4 $ 326.7 $ 328.9 Fair Value of Long-Term Debt (millions) September 30, December 31, 2015 2014 2014 Estimated Fair Value of Long-Term Debt $ 356.7 $ 378.2 $ 380.6 Credit Arrangements On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate (“LIBOR”) plus 1.375%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million. On July 24, 2015, the Company entered into the First Amendment to the Credit Facility. The First Amendment provides for an extension of the scheduled termination date to October 4, 2020, reduces the daily fluctuating rate of interest per annum equal to one-month LIBOR plus 1.25%, and reduces other customary credit facility fees. All other terms and conditions of the Credit Facility, including affirmative and negative covenants, remain substantially unchanged. The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $77.1 million and $139.9 million for the nine month periods ended September 30, 2015 and September 30, 2014, respectively. Total gross repayments were $102.3 million and $156.4 million for the nine months periods ended September 30, 2015 and September 30, 2014, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of September 30, 2015, September 30, 2014 and December 31, 2014: Revolving Credit Facility (millions) September 30, December 31, 2015 2014 2014 Limit $ 120.0 $ 120.0 $ 120.0 Outstanding $ 4.1 $ 43.7 $ 29.3 Available $ 115.9 $ 76.3 $ 90.7 The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At September 30, 2015, September 30, 2014 and December 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 4.) On December 23, 2014, Standard & Poor’s Ratings Services assigned its “BBB+” issuer credit rating to Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy and Northern Utilities. In April 2014, Unitil Service Corp. entered into a financing arrangement for various information systems and technology equipment. The financing arrangement is structured as a capital lease obligation with maximum availability of $15 million. As of September 30, 2015, Unitil Service Corp. has received funding under this financing arrangement in the amount of $11.4 million, which was used to fund project costs. Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $9.9 million, $13.6 million and $15.1 million of natural gas storage inventory at September 30, 2015, September 30, 2014 and December 31, 2014, respectively, related to these asset management agreements. The amount of natural gas inventory released in September 2015 and payable in October 2015 is $0.1 million and is recorded in Accounts Payable at September 30, 2015. The amount of natural gas inventory released in September 2014 and payable in October 2014 was $0.2 million and was recorded in Accounts Payable at September 30, 2014. The amount of natural gas inventory released in December 2014 and payable in January 2015 was $1.0 million and was recorded in Accounts Payable at December 31, 2014. 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 September 30, 2015, there were approximately $13.6 million of guarantees outstanding and the longest term guarantee extends through August 2016. 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 September 30, 2015, the principal amount outstanding for the 8% Unitil Realty notes was $1.3 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of September 30, 2015, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

COMMON STOCK AND PREFERRED STOC

COMMON STOCK AND PREFERRED STOCK	9 Months Ended
	Sep. 30, 2015
COMMON STOCK AND PREFERRED STOCK	NOTE 5 – COMMON STOCK AND PREFERRED STOCK Common Stock The Company’s common stock trades on the New York Stock Exchange under the symbol, “UTL.” The Company had 13,906,964, 13,916,026 and 13,982,941 shares of common stock outstanding at September 30, 2014, December 31, 2014 and September 30, 2015, respectively. Dividend Reinvestment and Stock Purchase Plan – Stock Plan – The maximum number of shares available for awards to participants under the Stock Plan is 677,500. The maximum number of shares that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make an equitable adjustment to the number and kind of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit. Restricted Shares Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. The Company may deduct or withhold, or require a participant to remit to the Company, an amount sufficient to satisfy any taxes required by federal, state, or local law or regulation to be withheld with respect to any taxable event arising in connection with an Award. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death. On January 26, 2015, 40,010 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.5 million. There were 80,588 and 67,334 non-vested shares under the Stock Plan as of September 30, 2015 and 2014, respectively. The weighted average grant date fair value of these shares was $33.14 and $28.51, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.6 million and $1.3 million for the nine months ended September 30, 2015 and 2014, respectively. At September 30, 2015, there was approximately $1.2 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.6 years. There were 871 restricted shares forfeited and there were no cancellations under the Stock Plan during the nine months ended September 30, 2015. Restricted Stock Units Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2015 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) Units Weighted Average Stock Price Restricted Stock Units as of December 31, 2014 23,576 $ 29.90 Restricted Stock Units Granted — — Dividend Equivalents Earned 718 $ 34.83 Restricted Stock Units Settled — — Restricted Stock Units as of September 30, 2015 24,294 $ 30.04 There were 14,270 Restricted Stock Units (equity portion) outstanding as of September 30, 2014 with a weighted average stock price of $28.96. On October 1, 2015, there were 12,807 fully-vested Restricted Stock Units issued to members of the Company’s Board of Directors. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of September 30, 2015, September 30, 2014 and December 31, 2014 is $0.4 million, $0.2 million and $0.4 million, respectively, representing the fair value of liabilities associated with the portion of fully vested RSUs that will be settled in cash. Preferred Stock There was $0.2 million, or 2,009 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2015. There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of September 30, 2014 and December 31, 2014. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three and nine month periods ended September 30, 2015 and September 30, 2014, respectively.

REGULATORY MATTERS

REGULATORY MATTERS	9 Months Ended
	Sep. 30, 2015
REGULATORY MATTERS	NOTE 6 – REGULATORY MATTERS UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2014 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2015. Regulatory Matters Northern Utilities Base Rates Maine – Northern Utilities Base Rates New Hampshire – Northern Utilities Pipeline Refund – Unitil Energy – Granite State Base Rates – Fitchburg Base Rates Electric – Fitchburg Base Rates Gas – Major Storms – Fitchburg and Unitil Energy Thanksgiving 2014 Snow Storm – Both Fitchburg and Unitil Energy experienced a significant snow storm that began the afternoon of November 26, 2014 and ended the morning of November 27, 2014, Thanksgiving Day. Unitil Energy spent approximately $2.1 million for the repair and replacement of electric distribution systems damaged during the storm, including $0.4 million related to capital construction and $1.7 million for which Unitil Energy will seek recovery through its approved storm reserve fund, subject to review by the NHPUC in a future regulatory proceeding. Fitchburg spent approximately $0.3 million for the repair and replacement of electric distribution systems damaged during the storm, including $0.1 million related to capital construction and $0.2 million in storm expense. As Fitchburg does not have an approved storm reserve fund, these expenses resulted in a pre-tax charge against 2014 earnings of $0.2 million. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations. Fitchburg Electric Operations – Fitchburg Gas Operations – Fitchburg Service Quality – Amendments to MDPU Service Quality Guidelines – Fitchburg Other – On December 23, 2013, the MDPU opened an investigation into Modernization of the Electric Grid. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices.” On June 12, 2014, the MDPU issued its first Grid Modernization order, setting forth a requirement that each electric distribution company submit a ten-year strategic Grid Modernization Plan (GMP). As part of the GMP, each company must include a five-year Short-Term Investment Plan (STIP), which must include an approach to achieving advanced metering functionality within five years of the Department’s approval of the GMP. The filing of a GMP will be a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. Capital investments contained in the STIP are eligible for pre-authorization, meaning that the MDPU will not revisit in later filings whether the Company should have proceeded with these investments. On November 5, 2014, the MDPU issued two inter-related orders regarding Grid Modernization. The first order provided guidance and filing requirements for the business case justification that the electric companies must file as part of their GMPs. The second order required the electric companies to implement sufficient advanced metering functionality to enable the sale of electricity to Basic Service customers via time varying rates (rates which vary depending upon the period or time of day that the electricity is consumed). The MDPU determined that time varying rates will establish pricing signals that will enable customers to save money by altering usage patterns and reducing peak load, among other enumerated benefits. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015 and are awaiting commencement of the MDPU’s review. The MDPU is addressing in separate proceedings (1) cybersecurity, privacy, and access to meter data, and (2) electric vehicles. These matters remain pending. Legal Proceedings The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. The Company believes, based upon information furnished by counsel and others, that the ultimate resolution of these claims will not have a material impact on the Company’s financial position. In early 2009, a putative class action complaint was filed against Unitil’s Massachusetts based utility, Fitchburg, in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellermann 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. 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. The plaintiffs appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”), and the SJC upheld the lower Court’s order. Subsequently, Plaintiffs filed a renewed motion to certify a class under a different theory than previously argued. The Company filed its opposition to this motion and also filed a motion for summary judgment. On July 27, 2015, the Court issued its decision allowing class certification and denying the Company’s motion for summary judgment. The Company appealed this decision to the SJC, and on October 15, 2015, the SJC granted the Company’s motion for direct review of the case. The Town of Lunenburg has filed a separate action in the Court arising out of the December 2008 ice storm. The Court accepted the parties’ joint schedule with discovery continuing into 2016 and trial likely in late 2016. The Company continues to believe that both of these suits are without merit and will continue to defend itself vigorously.

ENVIRONMENTAL MATTERS

ENVIRONMENTAL MATTERS	9 Months Ended
	Sep. 30, 2015
ENVIRONMENTAL MATTERS	NOTE 7 – ENVIRONMENTAL MATTERS UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2014 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 28, 2015. The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of September 30, 2015, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs. Northern Utilities Manufactured Gas Plant Sites – Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Dover, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in the fourth quarter of 2013. Final remediation activities in Portland are scheduled to commence in the fourth quarter of 2015 with an anticipated completion in the first quarter of 2016. In the second quarter of 2014, the State of Maine completed its taking of the site via eminent domain for the expansion of the adjacent marine terminal. As a result of the outcome of negotiations with the State of Maine, future operation, maintenance and remedial costs have been accrued, to ensure that applicable remedial activities are completed. Although remediation at the site in Exeter has been substantially completed, sediment contamination attributed to the former MGP was identified off-site. This off-site location has been investigated and remediation activities in Exeter are scheduled to commence in the fourth quarter of 2015 with an anticipated completion in the first quarter of 2016. Remediation costs of $1.6 million have been accrued on the Company’s Consolidated Balance Sheets as of September 30, 2015, to ensure completion of the work. 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 succeeding seven-year periods, without carrying costs. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over succeeding five-year periods, without carrying costs. The Environmental Obligations table below shows the amounts accrued for Northern Utilities related to estimated future cleanup costs associated with Northern Utilities’ environmental remediation obligations for former MGP sites. Corresponding Regulatory Assets were recorded to reflect that the future recovery of these environmental remediation costs is expected based on regulatory precedent and established practices. Fitchburg’s Manufactured Gas Plant Site – The Environmental Obligations table below shows the amounts accrued for Fitchburg related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site with a corresponding Regulatory Asset recorded to reflect that the recovery of these environmental remediation costs are probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs. The Company’s ultimate liability for future environmental remediation costs, including MGP site costs, may vary from estimates, which may be adjusted as new information or future developments become available. Based on the Company’s current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, the Company does not believe that these environmental costs will have a material adverse effect on the Company’s consolidated financial position or results of operations. The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the nine months ended September 30, 2015 and 2014. Environmental Obligations ($ millions) Fitchburg Northern Total Nine months ended September 30, 2015 2014 2015 2014 2015 2014 Total Balance at Beginning of Period $ 1.9 $ 12.0 $ 3.6 $ 2.8 $ 5.5 $ 14.8 Additions — 5.5 1.9 1.1 1.9 6.6 Less: Payments / Reductions 0.3 13.4 1.6 0.7 1.9 14.1 Total Balance at End of Period 1.6 4.1 3.9 3.2 5.5 7.3 Less: Current Portion 1.6 4.1 3.4 1.2 5.0 5.3 Noncurrent Balance at End of Period $ — $ — $ 0.5 $ 2.0 $ 0.5 $ 2.0

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2015
INCOME TAXES	NOTE 8: INCOME TAXES The Company filed its tax returns for the year ended December 31, 2014 with the Internal Revenue Service (IRS) in September 2015. As of September 30, 2015, the Company had recorded cumulative federal net operating loss (NOL) carryforward assets and Research and Development (R&D) credit carryforwards of $15.1 million to offset against taxes payable in future periods. If unused, the Company’s federal NOL carryforward assets will begin to expire in 2029, and the federal R&D credits will begin to expire in 2035. In addition, at December 31, 2014, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) to offset future AMT taxes payable indefinitely. In the third quarter, the Company recognized research and development tax credits under the rules of Section 41 of the Internal Revenue Code. The Company will continue to recognize a tax benefit on its incremental qualified research expenses. The Company evaluated its tax positions at September 30, 2015 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2012; December 31, 2013 and December 31, 2014. The Company bills its customers for sales tax in Massachusetts and Maine and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s unaudited Consolidated Statements of Earnings.

RETIREMENT BENEFIT OBLIGATIONS

RETIREMENT BENEFIT OBLIGATIONS	9 Months Ended
	Sep. 30, 2015
RETIREMENT BENEFIT OBLIGATIONS	NOTE 9: RETIREMENT BENEFIT OBLIGATIONS The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2014 as filed with the SEC on January 28, 2015 for additional information regarding these plans. The following table includes the key weighted average assumptions used in determining the Company’s benefit plan costs and obligations: 2015 2014 Used to Determine Plan Costs Discount Rate 4.00 % 4.80 % Rate of Compensation Increase 3.00 % 3.00 % Expected Long-term rate of return on plan assets 8.00 % 8.00 % Health Care Cost Trend Rate Assumed for Next Year 6.00 % 7.00 % Ultimate Health Care Cost Trend Rate 4.00 % 4.00 % Year that Ultimate Health Care Cost Trend Rate is reached 2018 2018 The following tables provide the components of the Company’s Retirement plan costs ($000’s): Pension Plan PBOP Plan SERP Three Months Ended September 30, 2015 2014 2015 2014 2015 2014 Service Cost $ 916 $ 753 $ 656 $ 497 $ 28 $ 15 Interest Cost 1,343 1,273 729 671 78 68 Expected Return on Plan Assets (1,694 ) (1,562 ) (273 ) (230 ) — — Prior Service Cost Amortization 54 52 420 421 2 2 Actuarial Loss Amortization 1,180 711 288 14 84 25 Sub-total 1,799 1,227 1,820 1,373 192 110 Amounts Capitalized and Deferred (927 ) (556 ) (921 ) (632 ) — — Net Periodic Benefit Cost Recognized $ 872 $ 671 $ 899 $ 741 $ 192 $ 110 Pension Plan PBOP Plan SERP Nine Months Ended September 30, 2015 2014 2015 2014 2015 2014 Service Cost $ 2,748 $ 2,255 $ 1,968 $ 1,491 $ 84 $ 43 Interest Cost 4,029 3,819 2,187 2,015 234 204 Expected Return on Plan Assets (5,082 ) (4,684 ) (819 ) (690 ) — — Prior Service Cost Amortization 162 158 1,260 1,261 8 8 Actuarial Loss Amortization 3,540 2,135 864 42 252 75 Sub-total 5,397 3,683 5,460 4,119 578 330 Amounts Capitalized and Deferred (2,510 ) (1,400 ) (2,563 ) (1,697 ) — — Net Periodic Benefit Cost Recognized $ 2,887 $ 2,283 $ 2,897 $ 2,422 $ 578 $ 330 Employer Contributions As of September 30, 2015, the Company had made $4.2 million of contributions to its Pension Plan in 2015 and had made $3.0 million of contributions to its PBOP Plan in 2015. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2015 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs. As of September 30, 2015, the Company had made $31,800 of contributions to the SERP Plan in 2015. The Company presently anticipates contributing an additional $8,500 to the SERP Plan in 2015.

SUMMARY OF SIGNIFICANT ACCOUN17

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2015
Nature of Operations	Nature of Operations The Company’s earnings are seasonal and are typically higher in the first and fourth quarters when customers use natural gas for heating purposes. Unitil’s principal business is the local distribution of electricity in the southeastern seacoast and state capital regions of New Hampshire and the greater Fitchburg area of north central Massachusetts, and the local distribution of natural gas in southeastern New Hampshire, portions of southern and central Maine and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the distribution utilities). Granite State is a natural gas transportation pipeline, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. Unitil also has three other wholly-owned subsidiaries: Unitil Service; Unitil Realty; and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.
Basis of Presentation	Basis of Presentation –
Fair Value	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. To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3. There have been no changes in the valuation techniques used during the current period.
Income Taxes	Income Taxes – Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. Deferred income taxes are reflected as Deferred Income Taxes in Current Assets and Noncurrent Liabilities on the Consolidated Balance Sheets based on the nature of the underlying timing item.
Cash and Cash Equivalents	Cash and Cash Equivalents –
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts – The Allowance for Doubtful Accounts as of September 30, 2015, September 30, 2014 and December 31, 2014, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows: ($ millions) September 30, December 31, 2015 2014 2014 Allowance for Doubtful Accounts $ 2.0 $ 2.1 $ 1.8
Accrued Revenue	Accrued Revenue – September 30, December 31, Accrued Revenue ($ millions) 2015 2014 2014 Regulatory Assets – Current $ 22.6 $ 24.6 $ 37.8 Unbilled Revenues 6.2 6.8 10.7 Total Accrued Revenue $ 28.8 $ 31.4 $ 48.5
Exchange Gas Receivable	Exchange Gas Receivable – September 30, December 31, Exchange Gas Receivable ($ millions) 2015 2014 2014 Northern Utilities $ 9.9 $ 13.4 $ 14.2 Fitchburg 0.7 1.1 0.8 Total Exchange Gas Receivable $ 10.6 $ 14.5 $ 15.0
Gas Inventory	Gas Inventory September 30, December 31, Gas Inventory ($ millions) 2015 2014 2014 Natural Gas $ 0.3 $ 0.8 $ 0.8 Propane 0.2 0.1 0.2 Liquefied Natural Gas & Other 0.1 0.1 0.1 Total Gas Inventory $ 0.6 $ 1.0 $ 1.1
Utility Plant	Utility Plant –
Regulatory Accounting	Regulatory Accounting – September 30, December 31, Regulatory Assets consist of the following ($ millions) 2015 2014 2014 Retirement Benefits $ 65.3 $ 42.2 $ 65.1 Energy Supply & Other Regulatory Tracker Mechanisms 17.4 17.6 31.0 Deferred Storm Charges 16.9 20.7 21.2 Environmental 11.1 10.6 11.0 Income Taxes 8.9 10.1 9.7 Deferred Restructuring Costs — 2.1 1.6 Other 5.8 6.6 5.8 Total Regulatory Assets $ 125.4 $ 109.9 $ 145.4 Less: Current Portion of Regulatory Assets (1) 22.6 24.6 37.8 Regulatory Assets – noncurrent $ 102.8 $ 85.3 $ 107.6 (1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets. September 30, December 31, Regulatory Liabilities consist of the following ($ millions) 2015 2014 2014 Regulatory Tracker Mechanisms $ 17.1 $ 13.0 $ 8.8 Gas Pipeline Refund (Note 6) 22.0 — — Total Regulatory Liabilities 39.1 13.0 $ 8.8 Less: Current Portion of Regulatory Liabilities 28.1 13.0 8.7 Regulatory Liabilities – noncurrent $ 11.0 $ — $ 0.1 Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.
Derivatives	Derivatives – The Company has a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service. Northern Utilities purchases call option contracts on NYMEX natural gas futures contracts for future winter period months. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause. As of September 30, 2015, September 30, 2014 and December 31, 2014 the Company had 3.7 billion, 3.0 billion and 2.4 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program. The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s unaudited Consolidated Balance Sheets. Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of: Fair Value Description Balance Sheet Sept. 30, 2015 Sept. 30, December 31, Derivative Assets Natural Gas Options Contracts Prepayments $ — $ — $ — Natural Gas Options Contracts Other Assets 0.1 — 0.1 Total Derivative Assets $ 0.1 $ — $ 0.1 Derivative Liabilities Natural Gas Options Contracts Other Current $ — $ 0.1 $ — Natural Gas Options Contracts Other — 0.1 — Total Derivative Liabilities $ — $ 0.2 $ — Three Months Ended Nine Months Ended ($ millions) 2015 2014 2015 2014 Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: Natural Gas Futures / Options Contracts $ 0.2 $ 0.1 $ 0.2 $ (0.4 ) Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings (1) Cost of Gas Sales $ 0.2 $ 0.1 $ 0.2 $ (0.8 ) (1) These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.
Energy Supply Obligations	Energy Supply Obligations – September 30, December 31, Energy Supply Obligations ($ millions) 2015 2014 2014 Current: Exchange Gas Obligation $ 9.9 $ 13.4 $ 14.2 Renewable Energy Portfolio Standards 5.5 4.1 7.4 Power Supply Contract Divestitures 0.4 0.6 0.5 Total Energy Supply Obligations – Current 15.8 18.1 22.1 Long-Term: Power Supply Contract Divestitures 1.7 2.1 1.9 Total Energy Supply Obligations $ 17.5 $ 20.2 $ 24.0 Exchange Gas Obligation – Northern Utilities enters into gas exchange agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. The gas inventory related to these agreements is recorded in Exchange Gas Receivable on the Company’s Consolidated Balance Sheets while the corresponding obligations are recorded in Energy Supply Obligations. Renewable Energy Portfolio Standards – Renewable Energy Portfolio Standards (RPS) require retail electricity suppliers, including public utilities, to demonstrate that required percentages of their sales are met with power generated from certain types of resources or technologies. Compliance is demonstrated by purchasing and retiring Renewable Energy Certificates (REC) generated by facilities approved by the state as qualifying for REC treatment. Unitil Energy and Fitchburg purchase RECs in compliance with RPS legislation in New Hampshire and Massachusetts for supply provided to default service customers. RPS compliance costs are a supply cost that is recovered in customer default service rates. Unitil Energy and Fitchburg collect RPS compliance costs from customers throughout the year and demonstrate compliance for each calendar year on the following July 1. Due to timing differences between collection of revenue from customers and payment of REC costs to suppliers, Unitil Energy and Fitchburg typically maintain accrued revenue for RPS compliance which is recorded in Accrued Revenue with a corresponding liability in Energy Supply Obligations on the Company’s Consolidated Balance Sheets. Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling rate mechanism. Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The current and noncurrent obligations related to these divestitures are recorded in Energy Supply Obligations and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion). Massachusetts Green Communities Act – In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts are pending approval by the MDPU as well as subsequent facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg will recover its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.
Recently Issued Pronouncements	Recently Issued Pronouncements – In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The effective date of this pronouncement is for fiscal years beginning after December 15, 2017 with early adoption permitted as of the original effective date. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements. In July 2015, the FASB issued ASU 2015-11 which provides authoritative guidance requiring inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. This pronouncement is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Company is evaluating this new guidance and does not expect it to have any impact on the Company’s Consolidated Financial Statements. In May 2015, the FASB issued ASU 2015-07 which provides authoritative guidance removing the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all periods presented. The Company is evaluating the impact this new guidance may have on its disclosures and does not expect it to have a material impact on the Company’s Consolidated Financial Statements. In April 2015, the FASB issued ASU 2015-03 which requires entities to present debt issuance costs related to a debt liability as a direct deduction from the carrying amount of that debt liability on the balance sheet as opposed to being presented as a deferred charge. ASU 2015-03 does not contain guidance for debt issuance costs related to line-of-credit arrangements. Consequently, in August 2015, the FASB issued ASU 2015-15 to add paragraphs indicating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The effective date of these pronouncements is for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impact that this new guidance will have on the Company’s Consolidated Financial Statements. Other than the pronouncements discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.
Subsequent Events	Subsequent Events –

SUMMARY OF SIGNIFICANT ACCOUN18

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2015
Allowance for Doubtful Accounts Included in Accounts Receivable Net	The Allowance for Doubtful Accounts as of September 30, 2015, September 30, 2014 and December 31, 2014, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows: ($ millions) September 30, December 31, 2015 2014 2014 Allowance for Doubtful Accounts $ 2.0 $ 2.1 $ 1.8
Components of Accrued Revenue	The following table shows the components of Accrued Revenue as of September 30, 2015, September 30, 2014 and December 31, 2014. September 30, December 31, Accrued Revenue ($ millions) 2015 2014 2014 Regulatory Assets – Current $ 22.6 $ 24.6 $ 37.8 Unbilled Revenues 6.2 6.8 10.7 Total Accrued Revenue $ 28.8 $ 31.4 $ 48.5
Components of Exchange Gas Receivable	The following table shows the components of Exchange Gas Receivable as of September 30, 2015, September 30, 2014 and December 31, 2014. September 30, December 31, Exchange Gas Receivable ($ millions) 2015 2014 2014 Northern Utilities $ 9.9 $ 13.4 $ 14.2 Fitchburg 0.7 1.1 0.8 Total Exchange Gas Receivable $ 10.6 $ 14.5 $ 15.0
Components of Gas Inventory	The following table shows the components of Gas Inventory as of September 30, 2015, September 30, 2014 and December 31, 2014. September 30, December 31, Gas Inventory ($ millions) 2015 2014 2014 Natural Gas $ 0.3 $ 0.8 $ 0.8 Propane 0.2 0.1 0.2 Liquefied Natural Gas & Other 0.1 0.1 0.1 Total Gas Inventory $ 0.6 $ 1.0 $ 1.1
Regulatory Assets	September 30, December 31, Regulatory Assets consist of the following ($ millions) 2015 2014 2014 Retirement Benefits $ 65.3 $ 42.2 $ 65.1 Energy Supply & Other Regulatory Tracker Mechanisms 17.4 17.6 31.0 Deferred Storm Charges 16.9 20.7 21.2 Environmental 11.1 10.6 11.0 Income Taxes 8.9 10.1 9.7 Deferred Restructuring Costs — 2.1 1.6 Other 5.8 6.6 5.8 Total Regulatory Assets $ 125.4 $ 109.9 $ 145.4 Less: Current Portion of Regulatory Assets (1) 22.6 24.6 37.8 Regulatory Assets – noncurrent $ 102.8 $ 85.3 $ 107.6 (1) Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.
Regulatory Liabilities	September 30, December 31, Regulatory Liabilities consist of the following ($ millions) 2015 2014 2014 Regulatory Tracker Mechanisms $ 17.1 $ 13.0 $ 8.8 Gas Pipeline Refund (Note 6) 22.0 — — Total Regulatory Liabilities 39.1 13.0 $ 8.8 Less: Current Portion of Regulatory Liabilities 28.1 13.0 8.7 Regulatory Liabilities – noncurrent $ 11.0 $ — $ 0.1
Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets	Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of: Fair Value Description Balance Sheet Sept. 30, 2015 Sept. 30, December 31, Derivative Assets Natural Gas Options Contracts Prepayments $ — $ — $ — Natural Gas Options Contracts Other Assets 0.1 — 0.1 Total Derivative Assets $ 0.1 $ — $ 0.1 Derivative Liabilities Natural Gas Options Contracts Other Current $ — $ 0.1 $ — Natural Gas Options Contracts Other — 0.1 — Total Derivative Liabilities $ — $ 0.2 $ —
Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Purchased Gas	Three Months Ended Nine Months Ended ($ millions) 2015 2014 2015 2014 Amount of Loss / (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives: Natural Gas Futures / Options Contracts $ 0.2 $ 0.1 $ 0.2 $ (0.4 ) Amount of Loss / (Gain) Reclassified into unaudited Consolidated Statements of Earnings (1) Cost of Gas Sales $ 0.2 $ 0.1 $ 0.2 $ (0.8 ) (1) These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.
Components of Energy Supply Obligations	September 30, December 31, Energy Supply Obligations ($ millions) 2015 2014 2014 Current: Exchange Gas Obligation $ 9.9 $ 13.4 $ 14.2 Renewable Energy Portfolio Standards 5.5 4.1 7.4 Power Supply Contract Divestitures 0.4 0.6 0.5 Total Energy Supply Obligations – Current 15.8 18.1 22.1 Long-Term: Power Supply Contract Divestitures 1.7 2.1 1.9 Total Energy Supply Obligations $ 17.5 $ 20.2 $ 24.0

DIVIDENDS DECLARED PER SHARE (T

DIVIDENDS DECLARED PER SHARE (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Dividends Declared	Declaration Date Date Paid (Payable) Shareholder of Record Date Dividend Amount 10/21/15 11/27/15 11/13/15 $ 0.350 07/22/15 08/28/15 08/14/15 $ 0.350 04/22/15 05/28/15 05/14/15 $ 0.350 01/26/15 02/27/15 02/13/15 $ 0.350 10/21/14 11/28/14 11/14/14 $0.345 07/22/14 08/29/14 08/15/14 $0.345 04/22/14 05/29/14 05/15/14 $ 0.345 01/16/14 02/28/14 02/14/14 $ 0.345

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2015
Significant Segment Financial Data	The following table provides significant segment financial data for the three and nine months ended September 30, 2015 and September 30, 2014 and as of December 31, 2014 (millions): Three Months Ended September 30, 2015 Gas Electric Non- Regulated Other Total Revenues $ 21.7 $ 51.4 $ 1.6 $ — $ 74.7 Segment Profit (Loss) (1.4 ) 2.5 0.3 0.3 1.7 Capital Expenditures 22.5 7.8 — 2.1 32.4 Three Months Ended September 30, 2014 Revenues $ 20.9 $ 54.2 $ 1.5 $ — $ 76.6 Segment Profit (Loss) (1.5 ) 2.9 0.2 — 1.6 Capital Expenditures 23.1 7.1 0.1 1.3 31.6 Nine Months Ended September 30, 2015 Revenues $ 149.6 $ 170.1 $ 4.7 $ — $ 324.4 Segment Profit 9.5 6.2 0.9 0.4 17.0 Capital Expenditures 45.4 19.5 0.1 5.9 70.9 Segment Assets 584.3 413.8 6.4 13.5 1,018.0 Nine Months Ended September 30, 2014 Revenues $ 139.3 $ 162.2 $ 4.5 $ — $ 306.0 Segment Profit 9.3 5.2 0.6 0.2 15.3 Capital Expenditures 39.4 17.2 0.4 3.7 60.7 Segment Assets 505.6 392.1 6.4 12.4 916.5 As of December 31, 2014 Segment Assets $ 566.3 $ 414.1 $ 6.3 $ 13.5 $ 1,000.2

DEBT AND FINANCING ARRANGEMEN21

DEBT AND FINANCING ARRANGEMENTS (Tables)	9 Months Ended
	Sep. 30, 2015
Details on Long Term Debt	Details on long-term debt at September 30, 2015, September 30, 2014 and December 31, 2014 are shown below: ($ millions) September 30, December 31, 2015 2014 2014 Unitil Corporation Senior Notes: 6.33% Notes, Due May 1, 2022 $ 20.0 $ 20.0 $ 20.0 Unitil Energy Systems, Inc.: First Mortgage Bonds: 5.24% Series, Due March 2, 2020 15.0 15.0 15.0 8.49% Series, Due October 14, 2024 15.0 15.0 15.0 6.96% Series, Due September 1, 2028 20.0 20.0 20.0 8.00% Series, Due May 1, 2031 15.0 15.0 15.0 6.32% Series, Due September 15, 2036 15.0 15.0 15.0 Fitchburg Gas and Electric Light Company: Long-Term Notes: 6.75% Notes, Due November 30, 2023 15.2 19.0 15.2 7.37% Notes, Due January 15, 2029 12.0 12.0 12.0 7.98% Notes, Due June 1, 2031 14.0 14.0 14.0 6.79% Notes, Due October 15, 2025 10.0 10.0 10.0 5.90% Notes, Due December 15, 2030 15.0 15.0 15.0 Northern Utilities, Inc.: Senior Notes: 6.95% Senior Notes, Due December 3, 2018 30.0 30.0 30.0 5.29% Senior Notes, Due March 2, 2020 25.0 25.0 25.0 7.72% Senior Notes, Due December 3, 2038 50.0 50.0 50.0 4.42% Senior Notes, Due October 15, 2044 50.0 — 50.0 Granite State Gas Transmission, Inc.: Senior Notes: 7.15% Senior Notes, Due December 15, 2018 10.0 10.0 10.0 Unitil Realty Corp.: Senior Secured Notes: 8.00% Notes, Due Through August 1, 2017 1.3 1.9 1.7 Total Long-Term Debt 332.5 286.9 332.9 Short-Term Debt Reclassified to Long-Term Debt — 42.3 — Total Long-Term Debt After Reclassification 332.5 329.2 332.9 Less: Current Portion 4.1 2.5 4.0 Total Long-term Debt, Less Current Portion $ 328.4 $ 326.7 $ 328.9
Fair Value of Long Term Debt	(millions) September 30, December 31, 2015 2014 2014 Estimated Fair Value of Long-Term Debt $ 356.7 $ 378.2 $ 380.6
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 September 30, 2015, September 30, 2014 and December 31, 2014: Revolving Credit Facility (millions) September 30, December 31, 2015 2014 2014 Limit $ 120.0 $ 120.0 $ 120.0 Outstanding $ 4.1 $ 43.7 $ 29.3 Available $ 115.9 $ 76.3 $ 90.7

COMMON STOCK AND PREFERRED ST22

COMMON STOCK AND PREFERRED STOCK (Tables)	9 Months Ended
	Sep. 30, 2015
Restricted Stock Units Issued	The equity portion of Restricted Stock Units activity during the nine months ended September 30, 2015 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) Units Weighted Average Stock Price Restricted Stock Units as of December 31, 2014 23,576 $ 29.90 Restricted Stock Units Granted — — Dividend Equivalents Earned 718 $ 34.83 Restricted Stock Units Settled — — Restricted Stock Units as of September 30, 2015 24,294 $ 30.04

ENVIRONMENTAL MATTERS (Tables)

ENVIRONMENTAL MATTERS (Tables)	9 Months Ended
	Sep. 30, 2015
Environmental Obligations Recognized by Company	The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the nine months ended September 30, 2015 and 2014. Environmental Obligations ($ millions) Fitchburg Northern Total Nine months ended September 30, 2015 2014 2015 2014 2015 2014 Total Balance at Beginning of Period $ 1.9 $ 12.0 $ 3.6 $ 2.8 $ 5.5 $ 14.8 Additions — 5.5 1.9 1.1 1.9 6.6 Less: Payments / Reductions 0.3 13.4 1.6 0.7 1.9 14.1 Total Balance at End of Period 1.6 4.1 3.9 3.2 5.5 7.3 Less: Current Portion 1.6 4.1 3.4 1.2 5.0 5.3 Noncurrent Balance at End of Period $ — $ — $ 0.5 $ 2.0 $ 0.5 $ 2.0

RETIREMENT BENEFIT OBLIGATIONS

RETIREMENT BENEFIT OBLIGATIONS (Tables)	9 Months Ended
	Sep. 30, 2015
Key Weighted Average Assumptions used in Determining Benefit Plan Costs and Obligations	The following table includes the key weighted average assumptions used in determining the Company’s benefit plan costs and obligations: 2015 2014 Used to Determine Plan Costs Discount Rate 4.00 % 4.80 % Rate of Compensation Increase 3.00 % 3.00 % Expected Long-term rate of return on plan assets 8.00 % 8.00 % Health Care Cost Trend Rate Assumed for Next Year 6.00 % 7.00 % Ultimate Health Care Cost Trend Rate 4.00 % 4.00 % Year that Ultimate Health Care Cost Trend Rate is reached 2018 2018
Components of Retirement Plan Costs	The following tables provide the components of the Company’s Retirement plan costs ($000’s): Pension Plan PBOP Plan SERP Three Months Ended September 30, 2015 2014 2015 2014 2015 2014 Service Cost $ 916 $ 753 $ 656 $ 497 $ 28 $ 15 Interest Cost 1,343 1,273 729 671 78 68 Expected Return on Plan Assets (1,694 ) (1,562 ) (273 ) (230 ) — — Prior Service Cost Amortization 54 52 420 421 2 2 Actuarial Loss Amortization 1,180 711 288 14 84 25 Sub-total 1,799 1,227 1,820 1,373 192 110 Amounts Capitalized and Deferred (927 ) (556 ) (921 ) (632 ) — — Net Periodic Benefit Cost Recognized $ 872 $ 671 $ 899 $ 741 $ 192 $ 110 Pension Plan PBOP Plan SERP Nine Months Ended September 30, 2015 2014 2015 2014 2015 2014 Service Cost $ 2,748 $ 2,255 $ 1,968 $ 1,491 $ 84 $ 43 Interest Cost 4,029 3,819 2,187 2,015 234 204 Expected Return on Plan Assets (5,082 ) (4,684 ) (819 ) (690 ) — — Prior Service Cost Amortization 162 158 1,260 1,261 8 8 Actuarial Loss Amortization 3,540 2,135 864 42 252 75 Sub-total 5,397 3,683 5,460 4,119 578 330 Amounts Capitalized and Deferred (2,510 ) (1,400 ) (2,563 ) (1,697 ) — — Net Periodic Benefit Cost Recognized $ 2,887 $ 2,283 $ 2,897 $ 2,422 $ 578 $ 330

Summary of Significant Accoun25

Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)SubsidiarymiBcf	Dec. 31, 2014USD ($)Bcf	Sep. 30, 2014USD ($)Bcf
Significant Accounting Policies [Line Items]
Length Of Pipeline | mi	86
Cost of Removal Obligations	$ 69.9	$ 63.8	$ 63.2
Number of Natural Gas Storage Outstanding | Bcf	3.7	2.4	3
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period	3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	$ 2.9	$ 6.3	$ 8
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits	$ 0	$ 0	$ 0
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary	3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary	3

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 2	$ 1.8	$ 2.1

Components of Accrued Revenue (

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 28.8	$ 48.5	$ 31.4
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	22.6	37.8	24.6
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 6.2	$ 10.7	$ 6.8

Exchange Gas Receivable (Detail

Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Receivables [Line Items]
Total Exchange Gas Receivable	$ 10.6	$ 15	$ 14.5
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	9.9	14.2	13.4
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.7	$ 0.8	$ 1.1

Components of Gas Inventory (De

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.6	$ 1.1	$ 1
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.3	0.8	0.8
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.2	$ 0.2	$ 0.1

Regulatory Assets (Detail)

Regulatory Assets (Detail) - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Regulatory Assets [Line Items]
Regulatory Assets		$ 125.4	$ 145.4	$ 109.9
Less: Current Portion of Regulatory Assets	[1]	22.6	37.8	24.6
Regulatory Assets - noncurrent		102.8	107.6	85.3
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets		11.1	11	10.6
Other Assets
Regulatory Assets [Line Items]
Regulatory Assets		5.8	5.8	6.6
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets		65.3	65.1	42.2
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory Assets		16.9	21.2	20.7
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets		8.9	9.7	10.1
Energy Supply & Other Regulatory Tracker Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets		$ 17.4	31	17.6
Deferred Restructuring Costs
Regulatory Assets [Line Items]
Regulatory Assets			$ 1.6	$ 2.1
[1]	Reflects amounts included in Accrued Revenue, discussed above, on the Company's Consolidated Balance Sheets.

Regulatory Liabilities (Detail)

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 39.1	$ 8.8	$ 13
Less: Current Portion of Regulatory Liabilities	28.1	8.7	13
Regulatory Liabilities - noncurrent	11	0.1
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	17.1	$ 8.8	$ 13
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 22

Fair Value Amount of Derivative

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Derivative Assets
Derivative Assets	$ 0.1	$ 0.1
Derivative Liabilities
Derivative Liabilities			$ 0.2
Natural Gas Options Contract | Other Assets
Derivative Assets
Derivative Assets	$ 0.1	$ 0.1
Natural Gas Options Contract | Other Current Liabilities
Derivative Liabilities
Derivative Liabilities			0.1
Natural Gas Options Contract | Other Noncurrent Liabilities
Derivative Liabilities
Derivative Liabilities			$ 0.1

Regulatory Assets Liabilities a

Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Cost of Gas Sales (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Natural Gas Options Contract
Regulatory Assets [Line Items]
Loss/(Gain) recognized in Regulatory Assets(Liabilities)		$ 0.2	$ 0.1	$ 0.2	$ (0.4)
Gas Purchase Costs
Regulatory Assets [Line Items]
Loss/(Gain) Reclassified into unaudited Consolidated Statement of Earnings	[1]	$ 0.2	$ 0.1	$ 0.2	$ (0.8)
[1]	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Energy Supply Obligations (Deta

Energy Supply Obligations (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 15.8	$ 22.1	$ 18.1
Power Supply Contract Divestitures, Long-Term	1.7	1.9	2.1
Total Energy Supply Obligations	17.5	24	20.2
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	9.9	14.2	13.4
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	5.5	7.4	4.1
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations - Current	$ 0.4	$ 0.5	$ 0.6

Dividends Declared Per Share (D

Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Dividends Payable [Line Items]
Dividend Amount	$ 0.350	$ 0.345	$ 1.050	$ 1.035
Group One
Dividends Payable [Line Items]
Declaration Date			Oct. 21, 2015
Date Paid (Payable)			Nov. 27, 2015
Shareholder of Record Date			Nov. 13, 2015
Dividend Amount			$ 0.350
Group Two
Dividends Payable [Line Items]
Declaration Date			Jul. 22, 2015
Date Paid (Payable)			Aug. 28, 2015
Shareholder of Record Date			Aug. 14, 2015
Dividend Amount			$ 0.350
Group Three
Dividends Payable [Line Items]
Declaration Date			Apr. 22, 2015
Date Paid (Payable)			May 28, 2015
Shareholder of Record Date			May 14, 2015
Dividend Amount			$ 0.350
Group Four
Dividends Payable [Line Items]
Declaration Date			Jan. 26, 2015
Date Paid (Payable)			Feb. 27, 2015
Shareholder of Record Date			Feb. 13, 2015
Dividend Amount			$ 0.350
Group Five
Dividends Payable [Line Items]
Declaration Date			Oct. 21, 2014
Date Paid (Payable)			Nov. 28, 2014
Shareholder of Record Date			Nov. 14, 2014
Dividend Amount			$ 0.345
Group Six
Dividends Payable [Line Items]
Declaration Date			Jul. 22, 2014
Date Paid (Payable)			Aug. 29, 2014
Shareholder of Record Date			Aug. 15, 2014
Dividend Amount			$ 0.345
Group Seven
Dividends Payable [Line Items]
Declaration Date			Apr. 22, 2014
Date Paid (Payable)			May 29, 2014
Shareholder of Record Date			May 15, 2014
Dividend Amount			$ 0.345
Group Eight
Dividends Payable [Line Items]
Declaration Date			Jan. 16, 2014
Date Paid (Payable)			Feb. 28, 2014
Shareholder of Record Date			Feb. 14, 2014
Dividend Amount			$ 0.345

Significant Segment Financial D

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 74.7	$ 76.6	$ 324.4	$ 306
Segment Profit (Loss)	1.7	1.6	17	15.3
Capital Expenditures	32.4	31.6	70.9	60.7
Segment Assets	1,018	916.5	1,018	916.5	$ 1,000.2
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	21.7	20.9	149.6	139.3
Segment Profit (Loss)	(1.4)	(1.5)	9.5	9.3
Capital Expenditures	22.5	23.1	45.4	39.4
Segment Assets	584.3	505.6	584.3	505.6	566.3
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	51.4	54.2	170.1	162.2
Segment Profit (Loss)	2.5	2.9	6.2	5.2
Capital Expenditures	7.8	7.1	19.5	17.2
Segment Assets	413.8	392.1	413.8	392.1	414.1
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit (Loss)	0.3		0.4	0.2
Capital Expenditures	2.1	1.3	5.9	3.7
Segment Assets	13.5	12.4	13.5	12.4	13.5
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	1.6	1.5	4.7	4.5
Segment Profit (Loss)	0.3	0.2	0.9	0.6
Capital Expenditures		0.1	0.1	0.4
Segment Assets	$ 6.4	$ 6.4	$ 6.4	$ 6.4	$ 6.3

Debt and Financing Arrangemen37

Debt and Financing Arrangements - Additional Information (Detail) - USD ($)	Jul. 24, 2015	Oct. 04, 2013	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Oct. 15, 2014	Apr. 30, 2014
Line of Credit Facility [Line Items]
Reclassification of short-term debt to long-term debt				$ 42,300,000
Proceeds from capital lease obligation			$ 11,400,000
Accounts Payable			21,200,000	19,300,000	$ 44,200,000
Guarantee outstanding			13,600,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Natural gas storage inventory			9,900,000	13,600,000	15,100,000
Accounts Payable			100,000	200,000	1,000,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility			120,000,000	120,000,000	$ 120,000,000
Proceeds from lines of credit			77,100,000	139,900,000
Repayments of lines of credit			$ 102,300,000	$ 156,400,000
4.42% Senior Unsecured Notes due October 15, 2044 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount						$ 50,000,000
Long-term debt, stated interest rate						4.42%
Long-term debt, maturity date			Oct. 15, 2044
Credit Facility | Capital Lease Obligations
Line of Credit Facility [Line Items]
Revolving credit facility							$ 15,000,000
Credit Facility | Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date		Oct. 4, 2018
Revolving credit facility		$ 120,000,000
Sublimit for the issuance of standby letters of credit		25,000,000
Credit Facility by an aggregate additional amount		$ 30,000,000
Percentage of capitalization			The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil's Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65% tested on a quarterly basis. At June 30, 2015, June 30, 2014 and December 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
Credit Facility | Revolving Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest		1.375%
Credit Facility | Amended Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility expiration date	Oct. 4, 2020
Credit Facility | Amended Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest	1.25%
8.00% Senior Secured Notes, Due August 1, 2017 | Unitil Realty Corp
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate			8.00%	8.00%	8.00%
Long-term debt, maturity date			Aug. 1, 2017	Aug. 1, 2017	Aug. 1, 2017
Senior Secured Notes			$ 1,300,000	$ 1,900,000	$ 1,700,000
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate			7.15%	7.15%	7.15%
Long-term debt, maturity date			Dec. 15, 2018	Dec. 15, 2018	Dec. 15, 2018
Senior Notes			$ 10,000,000	$ 10,000,000	$ 10,000,000

Details on Long Term Debt (Deta

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Debt Instrument [Line Items]
Short-Term Debt Reclassified to Long-Term Debt			$ 42.3
Long-Term Debt	$ 332.5	$ 332.9	329.2
Less: Current Portion	4.1	4	2.5
Total Long-term Debt, Less Current Portion	328.4	328.9	326.7
Before Reclassification of Short-Term Debt to Long-Term Debt
Debt Instrument [Line Items]
Long-Term Debt	332.5	332.9	286.9
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20	20	20
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	15	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20	20	20
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15	15	15
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15	15	15
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	15.2	15.2	19
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12	12	12
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14	14	14
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10	10	10
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15	15	15
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30	30	30
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25	25	25
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50	50	50
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Senior Notes	50	50
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10	10	10
Unitil Realty Corp | 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 1.3	$ 1.7	$ 1.9

Details on Long Term Debt (Pare

Details on Long Term Debt (Parenthetical) (Detail)	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%	6.33%
Debt instrument due date	May 1, 2022	May 1, 2022	May 1, 2022
First Mortgage Bonds 5.24% Series, Due March 2, 2020 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%	5.24%
Debt instrument due date	Mar. 2, 2020	Mar. 2, 2020	Mar. 2, 2020
First Mortgage Bonds 8.49% Series, Due October 14, 2024 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%	8.49%
Debt instrument due date	Oct. 14, 2024	Oct. 14, 2024	Oct. 14, 2024
First Mortgage Bonds 6.96% Series, Due September 1, 2028 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%	6.96%
Debt instrument due date	Sep. 1, 2028	Sep. 1, 2028	Sep. 1, 2028
First Mortgage Bonds 8.00% Series, Due May 1, 2031 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%	8.00%
Debt instrument due date	May 1, 2031	May 1, 2031	May 1, 2031
First Mortgage Bonds 6.32% Series, Due September 15, 2036 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%	6.32%
Debt instrument due date	Sep. 15, 2036	Sep. 15, 2036	Sep. 15, 2036
6.75% Notes, Due November 30, 2023 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%	6.75%
Debt instrument due date	Nov. 30, 2023	Nov. 30, 2023	Nov. 30, 2023
7.37% Notes, Due January 15, 2029 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%	7.37%
Debt instrument due date	Jan. 15, 2029	Jan. 15, 2029	Jan. 15, 2029
7.98% Notes, Due June 1, 2031 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%	7.98%
Debt instrument due date	Jun. 1, 2031	Jun. 1, 2031	Jun. 1, 2031
6.79% Notes, Due October 15, 2025 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%	6.79%
Debt instrument due date	Oct. 15, 2025	Oct. 15, 2025	Oct. 15, 2025
5.90% Notes, Due December 15, 2030 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%	5.90%
Debt instrument due date	Dec. 15, 2030	Dec. 15, 2030	Dec. 15, 2030
6.95% Senior Notes, Series A, Due December 3, 2018 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%	6.95%
Debt instrument due date	Dec. 3, 2018	Dec. 3, 2018	Dec. 3, 2018
5.29% Senior Notes, Due March 2, 2020 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%	5.29%
Debt instrument due date	Mar. 2, 2020	Mar. 2, 2020	Mar. 2, 2020
7.72% Senior Notes, Series B, Due December 3, 2038 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%	7.72%
Debt instrument due date	Dec. 3, 2038	Dec. 3, 2038	Dec. 3, 2028
4.42% Senior Notes, Due October 15, 2044 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.42%		4.42%
Debt instrument due date	Oct. 15, 2044	Oct. 15, 2044	Oct. 15, 2044
7.15% Senior Notes, Due December 15, 2018 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%	7.15%
Debt instrument due date	Dec. 15, 2018	Dec. 15, 2018	Dec. 15, 2018
8.00% Senior Secured Notes, Due August 1, 2017 | Unitil Realty Corp
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%	8.00%
Debt instrument due date	Aug. 1, 2017	Aug. 1, 2017	Aug. 1, 2017

Estimated Fair Value of Long Te

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 356.7	$ 380.6	$ 378.2

Borrowing Limits Amounts Outsta

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - Revolving Credit Facility - USD ($)	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Debt Instrument [Line Items]
Revolving credit facility	$ 120,000,000	$ 120,000,000	$ 120,000,000
Outstanding revolving credit facility	4,100,000	29,300,000	43,700,000
Available revolving credit facility	$ 115,900,000	$ 90,700,000	$ 76,300,000

Common Stock and Preferred St42

Common Stock and Preferred Stock - Additional Information (Detail) - USD ($)	Oct. 01, 2015	Jan. 26, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Common stock, shares outstanding			13,982,941	13,906,964	13,982,941	13,906,964	13,916,026
Common stock, shares issued					27,776	28,958
Proceeds from Issuance of Common Stock					$ 1,000,000	$ 900,000
Aggregate Market Value		$ 1,500,000
Share based compensation expense					$ 1,600,000	1,300,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled					70.00%
Percentage of fully-vested restricted stock units that directors will receive in cash when settled					30.00%
Fair value of liabilities associated with fully vested RSUs that will be settled in cash			$ 400,000	$ 200,000	$ 400,000	200,000	$ 400,000
Preferred Stock			200,000	200,000	200,000	200,000	$ 200,000
Maximum
Class of Stock [Line Items]
Dividend declared			$ 100,000	$ 100,000	100,000	$ 100,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock					$ 960,000
Dividend and Distribution Reinvestment and Share Purchase Plan | Average
Class of Stock [Line Items]
Common stock price per share			$ 34.56		$ 34.56
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued					27,776
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period					4 years
Fully-vested restricted stock units issued		40,010
Restricted stock non-vested			80,588	67,334	80,588	67,334
Restricted stock weighted average grant date fair value			$ 33.14	$ 28.51	$ 33.14	$ 28.51
Unrecognized share based compensation			$ 1,200,000		$ 1,200,000
Share compensation recognition period					2 years 7 months 6 days
Forfeitures under the stock plan					871
Cancellations under the stock plan					0
Restricted Stock | Maximum
Class of Stock [Line Items]
Restricted stock available for awards			677,500		677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000		20,000
Restricted Stock | Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually					25.00%
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Fully-vested restricted stock units issued					0
Restricted stock units outstanding				14,270		14,270
Weighted-Average Stock Price				$ 28.96		$ 28.96
Restricted Stock Units (RSUs) | Subsequent Event
Class of Stock [Line Items]
Fully-vested restricted stock units issued	12,807
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			2,009	2,250	2,009	2,250	2,250
Preferred Stock			$ 200,000	$ 200,000	$ 200,000	$ 200,000	$ 200,000
Dividend rate					6.00%	6.00%	6.00%

Restricted Stock Units Issued (

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs)	9 Months Ended
	Sep. 30, 2015$ / sharesshares
Restricted Stock Units
Beginning Restricted Stock Units | shares	23,576
Restricted Stock Units Granted | shares	0
Dividend Equivalents Earned | shares	718
Restricted Stock Units Settled | shares	0
Ending Restricted Stock Units | shares	24,294
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 29.90
Restricted Stock Units Granted	0
Dividend Equivalents Earned	34.83
Restricted Stock Units Settled	0
Ending Restricted Stock Units	$ 30.04

Regulatory Matters - Additional

Regulatory Matters - Additional Information (Detail) - USD ($) $ in Millions	Jun. 16, 2015	Apr. 15, 2015	Nov. 26, 2014	Apr. 30, 2014	Apr. 21, 2014	Dec. 27, 2013	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Regulatory Matters [Line Items]
Current Portion of Regulatory Liabilities								$ 28.1	$ 8.7	$ 13
Regulatory Liabilities - noncurrent								$ 11	0.1
Northern Utilities Inc
Regulatory Matters [Line Items]
TIRA initial term								Four years
Pipeline refund received		$ 22
Current Portion of Regulatory Liabilities								$ 11.1
Regulatory Liabilities - noncurrent								$ 10.9
Northern Utilities Inc | First Annual Adjustment
Regulatory Matters [Line Items]
Annual TIRA Adjustment									1.3
Annual TIRA Adjustment, effective date								May 1, 2014
Northern Utilities Inc | Second Annual Adjustment
Regulatory Matters [Line Items]
Annual TIRA Adjustment								$ 1.2
Annual TIRA Adjustment, effective date								May 1, 2015
Northern Utilities Inc | 2014 Step Adjustments
Regulatory Matters [Line Items]
Increase in annual revenue									$ 1.4
Amendment effective date								May 1, 2014
Northern Utilities Inc | Northern Utilities' customers
Regulatory Matters [Line Items]
Settlement agreement date								Oct. 5, 2015
Northern Utilities Inc | Maine
Regulatory Matters [Line Items]
Increase in annual revenue						$ 3.8
Amendment effective date								Jan. 1, 2014
Northern Utilities Inc | Maine | Northern Utilities' customers
Regulatory Matters [Line Items]
Grace period to issue refund								3 years
Northern Utilities Inc | New Hampshire
Regulatory Matters [Line Items]
Increase in annual revenue								$ 1.8
Amendment effective date								May 1, 2015
Northern Utilities Inc | New Hampshire | Natural Gas Distribution
Regulatory Matters [Line Items]
Increase in annual revenue					$ 4.6
Amendment effective date								May 1, 2014
Northern Utilities Inc | New Hampshire | Northern Utilities' customers
Regulatory Matters [Line Items]
Grace period to issue refund								3 years
Unitil Energy Systems Inc
Regulatory Matters [Line Items]
Amendment effective date								May 1, 2014
Settlement agreement date								May 1, 2016
Adjustment to recover the increased spending for vegetation management program and reliability enhancement program and a proposed storm resiliency program				$ 1.5
Construction expenditures			$ 0.4
Recovery of damage of electrical system			1.7
Unitil Energy Systems Inc | Storm Costs
Regulatory Matters [Line Items]
Storm expenditures			2.1
Fitchburg Gas and Electric Light Company
Regulatory Matters [Line Items]
Amendment effective date								May 1, 2016
Storm expenditures			0.2
Construction expenditures			0.1
Recovery amount								$ 0.3
Fitchburg Gas and Electric Light Company | Storm Costs
Regulatory Matters [Line Items]
Storm expenditures			$ 0.3
Fitchburg Gas and Electric Light Company | Electric base
Regulatory Matters [Line Items]
Increase in annual revenue	$ 3.8
Percentage of approved return on equity	5.60%
Fitchburg Gas and Electric Light Company | Gas base
Regulatory Matters [Line Items]
Increase in annual revenue	$ 3
Percentage of approved return on equity	8.30%
Granite State Gas Transmission Inc | Gas Transportation and Storage
Regulatory Matters [Line Items]
Increase in annual revenue							$ 0.4
Amendment effective date							Aug. 1, 2015

Environmental Matters - Additio

Environmental Matters - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Site Contingency [Line Items]
Environmental obligations	$ 5,500,000	$ 7,300,000	$ 5,500,000	$ 14,800,000
Environmental obligations, spent during the year	$ 1,900,000	14,100,000
Maine | Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	5 years
New Hampshire | Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	7 years
Environmental Matters
Site Contingency [Line Items]
Income (loss) incurred in excess of recorded amount	$ 0
Fitchburg Gas and Electric Light Company
Site Contingency [Line Items]
Environmental obligations	1,600,000	4,100,000	1,900,000	12,000,000
Environmental obligations, spent during the year	$ 300,000	13,400,000
Fitchburg Gas and Electric Light Company | Environmental Restoration Costs
Site Contingency [Line Items]
Amortization period for environmental costs	7 years
Fitchburg Gas and Electric Light Company | Environmental Clean Up Costs
Site Contingency [Line Items]
Environmental obligations	$ 5,500,000
Environmental obligations, spent during the year	3,900,000
Northern Utilities Inc
Site Contingency [Line Items]
Accrued remedial costs	1,600,000
Environmental obligations	3,900,000	3,200,000	$ 3,600,000	$ 2,800,000
Environmental obligations, spent during the year	$ 1,600,000	$ 700,000

Environmental Obligations Recog

Environmental Obligations Recognized by Company (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Site Contingency [Line Items]
Beginning Balance	$ 5.5	$ 14.8
Additions	1.9	6.6
Less: Payments / Reductions	1.9	14.1
Ending Balance	5.5	7.3
Less: Current Portion	5	5.3	$ 3.5
Ending Balance	0.5	2	$ 2
Fitchburg Gas and Electric Light Company
Site Contingency [Line Items]
Beginning Balance	1.9	12
Additions		5.5
Less: Payments / Reductions	0.3	13.4
Ending Balance	1.6	4.1
Less: Current Portion	1.6	4.1
Northern Utilities Inc
Site Contingency [Line Items]
Beginning Balance	3.6	2.8
Additions	1.9	1.1
Less: Payments / Reductions	1.6	0.7
Ending Balance	3.9	3.2
Less: Current Portion	3.4	1.2
Ending Balance	$ 0.5	$ 2

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015USD ($)
Operating Loss Carryforwards [Line Items]
Alternative Minimum tax credit carryforwards	$ 1,500,000
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date	2,035
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, 2012; December 31, 2013 and December 31, 2014.
Federal and State
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets	$ 15,100,000
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
NOL carryforward assets expiration date	2,029

Key Weighted Average Assumption

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - Benefit Plan Costs	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.00%	4.80%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	8.00%	8.00%
Health Care Cost Trend Rate Assumed for Next Year	6.00%	7.00%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2,018	2,018

Components of Retirement Plan C

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension Plans
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	$ 916	$ 753	$ 2,748	$ 2,255
Interest Cost	1,343	1,273	4,029	3,819
Expected Return on Plan Assets	(1,694)	(1,562)	(5,082)	(4,684)
Prior Service Cost Amortization	54	52	162	158
Actuarial Loss Amortization	1,180	711	3,540	2,135
Sub-total	1,799	1,227	5,397	3,683
Amounts Capitalized and Deferred	(927)	(556)	(2,510)	(1,400)
Net Periodic Benefit Cost Recognized	872	671	2,887	2,283
Other Postretirement Benefit Plans, Defined Benefit
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	656	497	1,968	1,491
Interest Cost	729	671	2,187	2,015
Expected Return on Plan Assets	(273)	(230)	(819)	(690)
Prior Service Cost Amortization	420	421	1,260	1,261
Actuarial Loss Amortization	288	14	864	42
Sub-total	1,820	1,373	5,460	4,119
Amounts Capitalized and Deferred	(921)	(632)	(2,563)	(1,697)
Net Periodic Benefit Cost Recognized	899	741	2,897	2,422
Supplemental Employee Retirement Plans, Defined Benefit
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Service Cost	28	15	84	43
Interest Cost	78	68	234	204
Prior Service Cost Amortization	2	2	8	8
Actuarial Loss Amortization	84	25	252	75
Sub-total	192	110	578	330
Net Periodic Benefit Cost Recognized	$ 192	$ 110	$ 578	$ 330

Retirement Benefit Obligation50

Retirement Benefit Obligations - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	$ 4,200,000
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	3,000,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	8,500
Expected additional contribution to SERP plan in 2015	$ 31,800