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Document and Entity Information - shares	3 Months Ended
Document and Entity Information - shares	Mar. 31, 2018	Apr. 23, 2018
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		14,861,228

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues
Gas	$ 87.0	$ 74.8
Electric	57.5	49.5
Other	1.3	1.7
Total Operating Revenues	145.8	126.0
Operating Expenses
Cost of Gas Sales	47.1	36.8
Cost of Electric Sales	35.2	27.5
Operation and Maintenance	17.3	16.0
Depreciation and Amortization	12.3	12.5
Taxes Other than Income Taxes	5.8	5.5
Total Operating Expenses	117.7	98.3
Operating Income	28.1	27.7
Interest Expense, net	6.0	6.0
Other Expense (Income), net	1.7	1.6
Income Before Income Taxes	20.4	20.1
Income Taxes	4.8	7.7
Net Income	$ 15.6	$ 12.4
Net Income Per Common Share (Basic and Diluted)	$ 1.06	$ 0.88
Weighted Average Common Shares Outstanding - (Basic and Diluted)	14.8	14.0
Dividends Declared Per Share of Common Stock	$ 0.365	$ 0.360

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Current Assets:
Cash and Cash Equivalents	$ 9.5	$ 8.9	$ 8.8
Accounts Receivable, net	74.4	67.4	57.6
Accrued Revenue	45.1	53.3	41.3
Exchange Gas Receivable	0.2	5.8	2.1
Gas Inventory	0.4	0.6	0.3
Materials and Supplies	7.8	6.9	7.1
Prepayments and Other	7.1	8.4	8.9
Total Current Assets	144.5	151.3	126.1
Utility Plant:
Gas	706.7	699.6	642.0
Electric	478.8	476.7	440.9
Common	69.1	67.4	35.9
Construction Work in Progress	32.1	35.5	68.6
Total Utility Plant	1,286.7	1,279.2	1,187.4
Less: Accumulated Depreciation	314.3	307.7	296.5
Net Utility Plant	972.4	971.5	890.9
Other Noncurrent Assets:
Regulatory Assets	111.2	109.6	103.5
Other Assets	16.2	9.5	13.9
Total Other Noncurrent Assets	127.4	119.1	117.4
TOTAL ASSETS	1,244.3	1,241.9	1,134.4
Current Liabilities:
Accounts Payable	30.1	41.5	28.1
Short-Term Debt	45.3	38.3	76.6
Long-Term Debt, Current Portion	29.8	29.8	30.0
Regulatory Liabilities	10.9	9.2	12.8
Energy Supply Obligations	7.8	9.7	9.0
Environmental Obligations	0.6	0.5	0.5
Capital Lease Obligations	3.1	3.1	3.0
Interest Payable	6.9	4.4	6.0
Other Current Liabilities	11.8	14.5	11.0
Total Current Liabilities	146.3	151.0	177.0
Noncurrent Liabilities:
Retirement Benefit Obligations	151.6	150.1	151.5
Deferred Income Taxes, net	87.0	82.9	106.0
Cost of Removal Obligations	86.6	84.3	79.7
Regulatory Liabilities	49.1	48.9	0.7
Capital Lease Obligations	4.9	5.7	7.5
Environmental Obligations	1.5	1.6	1.8
Other Noncurrent Liabilities	5.7	4.3	4.9
Total Noncurrent Liabilities	386.4	377.8	352.1
Capitalization:
Long-Term Debt, Less Current Portion	363.0	376.3	303.5
Stockholders' Equity:
Common Equity (Authorized: 25,000,000 and Outstanding:14,860,123, 14,107,741 and 14,815,585 Shares)	277.4	275.8	242.1
Retained Earnings	71.0	60.8	59.5
Total Common Stock Equity	348.4	336.6	301.6
Preferred Stock	0.2	0.2	0.2
Total Stockholders' Equity	348.6	336.8	301.8
Total Capitalization	711.6	713.1	605.3
Commitments and Contingencies (Notes 6 & 7)
TOTAL LIABILITIES AND CAPITALIZATION	$ 1,244.3	$ 1,241.9	$ 1,134.4

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Common Stock Authorized	25,000,000	25,000,000	25,000,000
Common Equity Outstanding	14,860,123	14,815,585	14,107,741

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Activities:
Net Income	$ 15.6	$ 12.4
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	12.3	12.5
Deferred Tax Provision	4.7	7.9
Changes in Working Capital Items:
Accounts Receivable	(7.0)	(4.7)
Accrued Revenue	8.2	8.2
Exchange Gas Receivable	5.6	6.2
Regulatory Liabilities	1.7	2.4
Accounts Payable	(11.4)	(4.3)
Other Changes in Working Capital Items	3.6	(1.2)
Deferred Regulatory and Other Charges	(7.9)	(7.7)
Other, net	3.0	5.8
Cash Provided by Operating Activities	28.4	37.5
Investing Activities:
Property, Plant and Equipment Additions	(10.1)	(17.5)
Cash (Used in) Investing Activities	(10.1)	(17.5)
Financing Activities:
Proceeds from (Repayment of) Short-Term Debt, net	7.0	(5.3)
Repayment of Long-Term Debt	(13.4)	(0.2)
Decrease in Capital Lease Obligations	(0.8)	(0.8)
Net Decrease in Exchange Gas Financing	(5.4)	(5.9)
Dividends Paid	(5.4)	(5.1)
Proceeds from Issuance of Common Stock	0.3	0.3
Cash (Used in) Financing Activities	(17.7)	(17.0)
Net Increase in Cash and Cash Equivalents	0.6	3.0
Cash and Cash Equivalents at Beginning of Period	8.9	5.8
Cash and Cash Equivalents at End of Period	9.5	8.8
Supplemental Cash Flow Information:
Interest Paid	3.6	4.0
Income Taxes Paid	0.2
Payments on Capital Leases	0.8	0.9
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 0.5	$ 0.6

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2016	$ 292.9	$ 240.7	$ 52.2
Net Income	12.4		12.4
Dividends on Common Shares	(5.1)		(5.1)
Stock Compensation Plans	1.1	1.1
Issuance of Common Shares	0.3	0.3
Ending Balance at Mar. 31, 2017	301.6	242.1	59.5
Beginning Balance at Dec. 31, 2017	336.6	275.8	60.8
Net Income	15.6		15.6
Dividends on Common Shares	(5.4)	0.0	(5.4)
Stock Compensation Plans	1.3	1.3
Issuance of Common Shares	0.3	0.3
Ending Balance at Mar. 31, 2018	$ 348.4	$ 277.4	$ 71.0

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Common stock, shares issued	7,812	7,581

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2018

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The Company’s 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 – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three months ended March 31, 2018 are not necessarily indicative of results to be expected for the year ending December 31, 2018. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission (SEC) on February 1, 2018, for a description of the Company’s Basis of Presentation.

Utility Revenue Recognition – Gas Operating Revenues and Electric Operating Revenues consist of billed and unbilled revenue and revenue from rate adjustment mechanisms. Billed and unbilled revenue includes delivery revenue and pass-through revenue, recognized according to tariffs approved by federal and state regulatory commissions which determine the amount of revenue the Company will record for these items. Revenue from rate adjustment mechanisms is accrued revenue, recognized in connection with rate adjustment mechanisms, and authorized by regulators for recognition in the current period for future cash recoveries from, or credits to, customers.

Billed and unbilled revenue is recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenues are calculated. These unbilled revenues are calculated each month based on estimated customer usage by class and applicable customer rates and are then reversed in the following month when billed to customers.

In the first quarter of 2018, the Company adopted Accounting Standards Update (ASU) 2014-09, and its subsequent clarifications and amendments outlined in ASU 2015-14, ASU 2016-08, ASU 2016-10 and ASU 2017-13, on a modified retrospective basis, which requires application to contracts with customers effective January 1, 2018, with the cumulative impact on contracts not yet completed as of December 31, 2017 recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the three months ended March 31, 2018. A majority of the Company’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customer monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer.

As discussed below, the Company plans to disclose billed and unbilled revenue separately from rate adjustment mechanism revenue in the Notes to the Consolidated Financial Statements for periods in 2018 going forward, and will also provide this disclosure for prior periods for informational purposes.

The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in ASU 2014-09. Revenue recognized in connection with rate adjustment mechanisms is consistent with the definition of alternative revenue programs in Accounting Standards Codification (ASC) 980-605-25-3, as the Company has the ability to adjust rates in the future as a result of past activities or completed events. ASU 2014-09 requires the Company to disclose separately the amount of revenues from contracts with customers and alternative revenue program revenues.

In the following tables, revenue is classified by the types of goods/services rendered and market/customer type. The lower revenues reported in the first quarter of 2018 to account for the reduction in the corporate income tax rate under the Tax Cuts and Jobs Act of 2017 (TCJA) are shown separately in the table below for informational purposes.


	Three Months Ended March 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	35.8		$	34.4		$	70.2
C&I		50.6			24.1			74.7
Other		6.5			3.9			10.4
Revenue Reductions – TCJA		(1.5	)		(0.8	)		(2.3	)

Total Billed and Unbilled Revenue		91.4			61.6			153.0
Rate Adjustment Mechanism Revenue		(4.4	)		(4.1	)		(8.5	)

Total Gas and Electric Operating Revenues	$	87.0		$	57.5		$	144.5


	Three Months Ended March 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	30.9		$	27.3		$	58.2
C&I		42.3			19.5			61.8
Other		5.6			2.2			7.8

Total Billed and Unbilled Revenue		78.8			49.0			127.8
Rate Adjustment Mechanism Revenue		(4.0	)		0.5			(3.5	)

Total Gas and Electric Operating Revenues	$	74.8		$	49.5		$	124.3

Fitchburg is subject to revenue decoupling. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. The difference between distribution revenue amounts billed to customers and the targeted revenue decoupling amounts is recorded as an increase or a decrease in Accrued Revenue, which forms the basis for resetting rates for future cash recoveries from, or credits to, customers. These revenue decoupling targets may be adjusted as a result of rate cases that the Company files with the MDPU. The Company estimates that revenue decoupling applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively.

Other Operating Revenue – Non-regulated – Usource, Unitil’s non-regulated subsidiary, conducts its business activities as a broker of competitive energy services. Usource does not take title to the electric and gas commodities which are the subject of the brokerage contracts. The Company records energy brokering revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource partners with certain entities to facilitate these brokerage services and pays these entities a fee under revenue sharing agreements.

As discussed above, the Company adopted ASU 2014-09 in the first quarter of 2018. There was no cumulative effect of adoption to be recognized as an adjustment to the opening balance of Retained Earnings on the Company’s Consolidated Balance Sheets. ASU 2014-09 requires that payments made by Usource to third parties (“Channel Partners”) for revenue sharing agreements are recognized net, as a reduction from revenue, where those payments were previously recognized gross as an operating expense. Therefore, beginning with the three months ended March 31, 2018 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements are reported as “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings, along with Usource’s revenues. Prior to the adoption of ASU 2014-09, payments by Usource to third parties for revenue sharing agreements are included as “Operation and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. Those Channel Partner payments were $0.3 million each of the first quarters of 2018 and 2017.

If ASU 2014-09 had been adopted retroactively for the three months ended March 31, 2017, the result would have been corresponding reductions of $0.3 million in both “Other” in in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below.


	Three Months Ended March 31,
	As Reported		If ASU 2014-09 Had Been in Effect
Other Operating Revenues ($ millions):	2018		2017
Usource Contract Revenue	$	1.6	$	1.7
Less: Revenue Sharing Payments		0.3		0.3

Total Other Operating Revenues	$	1.3	$	1.4


	Three Months Ended March 31,
	As Reported		If ASU 2014-09 Had Been in Effect
Operation and Maintenance Expense ($ millions):	2018		2017
Operation and Maintenance Expense	$	17.3	$	15.7

Retirement Benefit Costs – The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan) and the Unitil Corporation Supplemental Executive Retirement Plan (SERP).The net periodic benefit costs associated with these benefit plans consist of service cost and other components (See Note 9 to the Consolidated Financial Statements). In the first quarter of 2018, the Company adopted ASU No. 2017-07, “Compensation – Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.

Accordingly, for all periods presented in the Consolidated Financial Statements in this Form 10-Q for the quarter ended March 31, 2018, the service cost component of the Company’s net periodic benefit costs is reported in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings while the other components of net periodic benefit costs are reported in the “Other Expense (Income), net” section of the Consolidated Statements of Earnings. Prior to adoption, the Company reported all components of its net periodic benefit costs in “Operations and Maintenance” in the “Operating Expenses” section of the Consolidated Statements of Earnings. The change in presentation for the quarter ended March 31, 2018 resulted in a reduction of “Operations and Maintenance” and an increase in “Other Expense (Income), net” on the Consolidated Statements of Earnings for the prior period. There are $1.5 million and $1.6 million of non-service cost net periodic benefit costs reported in “Other Expense (Income), net for the three months ended March 31, 2018 and March 31, 2017, respectively, net of amounts deferred as regulatory assets for future recovery.

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

Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s current and deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations, less credit amounts that are based on the Company’s credit rating. As of March 31, 2018, March 31, 2017 and December 31, 2017, the Unitil subsidiaries had deposited $3.3 million, $2.6 million and $2.9 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. There were no cash margin deposits at Northern Utilities as of March 31, 2018, March 31, 2017 and December 31, 2017.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Also, the electric and gas divisions of Fitchburg are authorized to recover through rates past due amounts associated with hardship accounts that are protected from shut-off. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

The Allowance for Doubtful Accounts as of March 31, 2018, March 31, 2017 and December 31, 2017, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, was as follows:

($ millions)

March 31,

December 31,

2018

2017

Allowance for Doubtful Accounts

1.6

1.0

1.6

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of March 31, 2018, March 31, 2017 and December 31, 2017.


	March 31,				December 31,
Accrued Revenue ($ millions)	2018		2017		2017
Regulatory Assets – Current	$	34.6	$	32.0	$	39.5
Unbilled Revenues		10.5		9.3		13.8

Total Accrued Revenue	$	45.1	$	41.3	$	53.3

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of March 31, 2018, March 31, 2017 and December 31, 2017.


	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2018		2017		2017
Northern Utilities	$	—	$	1.9	$	5.4
Fitchburg		0.2		0.2		0.4

Total Exchange Gas Receivable	$	0.2	$	2.1	$	5.8

Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of March 31, 2018, March 31, 2017 and December 31, 2017.


	March 31,				December 31,
Gas Inventory ($ millions)	2018		2017		2017
Natural Gas	$	—	$	—	$	0.4
Propane		0.3		0.2		0.1
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.4	$	0.3	$	0.6

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At March 31, 2018, March 31, 2017 and December 31, 2017, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $86.6 million, $79.7 million, and $84.3 million, respectively.

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the Massachusetts Department of Public Utilities (MDPU), Unitil Energy is regulated by the New Hampshire Public Utilities Commission (NHPUC) and Northern Utilities is regulated by the Maine Public Utilities Commission (MPUC) and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2018		2017		2017
Retirement Benefits	$	85.4	$	75.7	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		31.9		27.7		36.0
Deferred Storm Charges		8.0		8.6		7.2
Environmental		9.0		10.7		9.5
Income Taxes		6.3		7.3		6.5
Other		5.2		5.5		5.4

Total Regulatory Assets		145.8		135.5		149.1
Less: Current Portion of Regulatory Assets⁽¹⁾		34.6		32.0		39.5

Regulatory Assets – noncurrent	$	111.2	$	103.5	$	109.6

⁽¹⁾

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


	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2018		2017		2017
Rate Adjustment Mechanisms	$	10.3	$	9.2	$	6.9
Gas Pipeline Refund (Note 6)		0.6		4.3		2.3
Income Taxes (Note 8)		49.1		—		48.9

Total Regulatory Liabilities		60.0		13.5		58.1
Less: Current Portion of Regulatory Liabilities		10.9		12.8		9.2

Regulatory Liabilities – noncurrent	$	49.1	$	0.7	$	48.9

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Included in Regulatory Assets as of March 31, 2018 are $0.5 million of deferred storm charges to be recovered over the year and $6.5 million of environmental costs, rate case costs and other expenditures to be recovered over varying periods in the next seven years. Regulators have authorized recovery of these expenditures, but without a return. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Derivatives – The Company’s regulated energy subsidiaries enter into energy supply contracts to serve their electric and gas customers. The Company follows a procedure for determining whether each contract qualifies as a derivative instrument under the guidance provided by the FASB Codification on Derivatives and Hedging. For each contract, the Company reviews and documents the key terms of the contract. Based on those terms and any additional relevant components of the contract, the Company determines and documents whether the contract qualifies as a derivative instrument as defined in the FASB Codification. The Company has determined that none of its energy supply contracts, other than the regulatory approved hedging program, described below, qualifies as a derivative instrument under the guidance set forth in the FASB Codification.

The Company has managed a regulatory approved hedging program for Northern Utilities, which is designed to fix or cap a portion of its gas supply costs for the coming years of service through the purchase of European call option contracts. Any gains or losses resulting from these option contracts are passed through to customers 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. Currently, there are no active transactions and the Company has proposed to regulators to discontinue the program. This matter remains pending.

As of March 31, 2018, March 31, 2017 and December 31, 2017 the Company had zero, 1.2 billion and 0.6 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

As of March 31, 2018 and March 31, 2017 and December 31, 2017, the Company’s derivatives that are not designated as hedging instruments under FASB ASC 815-20 have a fair value of $0, $0.3 million and less than $0.1 million, respectively.

Investments in Marketable Securities – The Company has a trust through which it invests in a variety of equity and fixed income mutual funds. These funds are intended to satisfy obligations under the Company’s Supplemental Executive Retirement Plan (“SERP”) (See further discussion of the SERP in Note 9.

At March 31, 2018, March 31, 2017 and December 31, 2017, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.1 million, $3.3 and $3.6 million, respectively, as shown in the table below. These investments are valued based on quoted prices from active markets and are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Changes in the fair value of these investments are recorded in Other Expense, net.


	March 31,				December 31,
Fair Value of Marketable Securities ($ millions)	2018		2017		2017
Equity Funds	$	1.9	$	1.1	$	2.1
Fixed Income Funds		1.6		0.9		1.5
Cash and Equivalents		1.6		1.3		—

Total Marketable Securities	$	5.1	$	3.3	$	3.6

Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.


	March 31,				December 31,
Energy Supply Obligations ($ millions)	2018		2017		2017
Current:
Exchange Gas Obligation	$	—	$	1.9	$	5.4
Renewable Energy Portfolio Standards		7.5		6.8		4.0
Power Supply Contract Divestitures		0.3		0.3		0.3

Total Energy Supply Obligations – Current		7.8		9.0		9.7
Long-Term:
Power Supply Contract Divestitures		0.8		1.2		0.9

Total Energy Supply Obligations	$	8.6	$	10.2	$	10.6

Exchange Gas Obligation – As discussed above, 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 entered into long-term renewable contracts for electric energy and/or renewable energy credits pursuant to Massachusetts legislation, specifically, the Act Relative to Green Communities of 2008 and the Act Relative to Competitively Priced Electricity (2012) in the Commonwealth, and the MDPU’s regulations implementing the legislation. The generating facilities associated with three of these contracts have been constructed and are operating. A recent round of long-term renewable energy procurements was conducted during 2016 and several contracts were finalized and submitted to MDPU for approval in 2017. These approvals remain pending. Additional procurements are expected in compliance with the Act to Promote Energy Diversity (2016). Fitchburg recovers the costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

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

Recently Issued Pronouncements – In March 2017, the FASB issued ASU No. 2017-07, “Compensation – Retirement Benefits (Topic 715) which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU became effective for the Company on January 1, 2018. The change in capitalization of retirement benefits did not have a material impact on the Company’s Consolidated Financial Statements.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606)”, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.

The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales.

The Company used the modified retrospective method when adopting the new standard on January 1, 2018. The new guidance did not have a material impact to the Consolidated Financial Statements. (See “Utility Revenue Recognition” and “Other Operating Revenue – Non-regulated” above.)

In February 2016, the FASB issued ASU 2016-02, Leases, Topic 842, which amends the existing guidance relating to the definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. In November 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for the Company on January 1, 2019, with early adoption permitted. The Company plans to adopt this guidance in the first quarter of 2019. The Company expects this ASU to increase lease assets and lease liabilities on the Consolidated Balance Sheets and does not expect the guidance will have a material impact on the Consolidated Statements of Income, Statements of Cash Flows and lease disclosures.

In January 2016, the FASB issued Accounting Standards Update (ASU) 2016-01 which addresses certain aspects of recognition, measurement, presentation and disclosure of financial instruments. A financial instrument is defined as cash, evidence of ownership interest in a company or other entity, or a contract that both: (i) imposes on one entity a contractual obligation either to deliver cash or another financial instrument to a second entity or to exchange other financial instruments on potentially unfavorable terms with the second entity and (ii) conveys to that second entity a contractual right either to receive cash or another financial instruments from the first entity or to exchange other financial instruments on potentially favorable terms with the first entity. The ASU became effective for the Company on January 1, 2018 and it did not have a material impact 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 – The Company evaluates all events or transactions through the date of the related filing. During the period through the date of this filing, the Company did not have any material subsequent events that would result in adjustment to or disclosure in its Consolidated Financial Statements.

DIVIDENDS DECLARED PER SHARE

3 Months Ended

Mar. 31, 2018

DIVIDENDS DECLARED PER SHARE

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
04/25/18	05/29/18	05/15/18	$0.365
01/30/18	02/28/18	02/14/18	$0.365

10/25/17	11/29/17	11/15/17	$0.360
07/26/17	08/29/17	08/15/17	$0.360
04/26/17	05/30/17	05/16/17	$0.360
01/25/17	02/28/17	02/14/17	$0.360

SEGMENT INFORMATION

3 Months Ended

Mar. 31, 2018

SEGMENT INFORMATION

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three months ended March 31, 2018 and March 31, 2017:


	Gas			Electric			Non- Regulated		Other			Total

Three Months Ended March 31, 2018 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	91.4		$	61.6		$	—	$	—		$	153.0
Rate Adjustment Mechanism Revenue		(4.4	)		(4.1	)		—		—			(8.5	)
Other Operating Revenue – Non-Regulated		—			—			1.3		—			1.3

Total Operating Revenues	$	87.0		$	57.5		$	1.3	$	—		$	145.8

Segment Profit (Loss)		12.6			3.0			0.4		(0.4	)		15.6
Identifiable Segment Assets		712.6			481.8			7.1		42.8			1,244.3
Capital Expenditures		3.6			6.0			—		0.5			10.1

Three Months Ended March 31, 2017 ($ millions)
Revenues	$	74.8		$	49.5		$	1.7	$	—		$	126.0
Segment Profit		9.9			2.1			0.4		—			12.4
Identifiable Segment Assets		641.8			442.8			7.0		42.8			1,134.4
Capital Expenditures		5.7			8.3			—		3.5			17.5

As of December 31, 2017 ($ millions)
Identifiable Segment Assets	$	714.3		$	476.9		$	6.7	$	44.0		$	1,241.9

DEBT AND FINANCING ARRANGEMENTS

3 Months Ended

Mar. 31, 2018

DEBT AND FINANCING ARRANGEMENTS

NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Details on long-term debt at March 31, 2018, March 31, 2017 and December 31, 2017 are shown below:


($ millions)	March 31,				December 31,
	2018		2017		2017
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		10.0		15.0		15.0
8.49% Senior Secured Notes, Due October 14, 2024		7.5		9.0		7.5
6.96% Senior Secured Notes, Due September 1, 2028		20.0		20.0		20.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		7.6		9.5		7.6
6.79% Senior Notes, Due October 15, 2025		10.0		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		—		10.0
7.37% Senior Notes, Due January 15, 2029		12.0		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		—		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		10.0		20.0		10.0
5.29% Senior Notes, Due March 2, 2020		16.6		25.0		25.0
3.52% Senior Notes, Due November 1, 2027		20.0		—		20.0
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		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		—		30.0
Granite State:
7.15% Senior Notes, Due December 15, 2018		3.3		6.7		3.3
3.72% Senior Notes, Due November 1, 2027		15.0		—		15.0
Unitil Realty Corp.:
8.00% Senior Secured Notes, Due Through August 1, 2017		—		0.2		—

Total Long-Term Debt		396.0		336.4		409.4
Less: Unamortized Debt Issuance Costs		3.2		2.9		3.3

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		392.8		333.5		406.1
Less: Current Portion		29.8		30.0		29.8

Total Long-term Debt, Less Current Portion	$	363.0	$	303.5	$	376.3

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

($ millions)

March 31,

December 31,

2018

2017

Estimated Fair Value of Long-Term Debt

428.0

374.3

457.1

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (as further amended, restated, amended and restated, modified or supplemented from time to time, the “Credit Facility”). The Credit Facility terminates October 4, 2020 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 1.25%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $88.9 million for the three months ended March 31, 2018. Total gross repayments were $81.9 million for the three months ended March 31, 2017. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of March 31, 2018, March 31, 2017 and December 31, 2017:


	Revolving Credit Facility ($ millions)
	March 31,				December 31,
	2018		2017		2017
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	45.3	$	76.6	$	38.3
Letters of Credit Outstanding	$	0.0	$	1.1	$	0.0

Available	$	74.7	$	42.3	$	81.7

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 Corporation’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 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 Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At March 31, 2018, March 31, 2017 and December 31, 2017, 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.)

The weighted average interest rates on all short-term borrowings and intercompany money pool transactions were 2.9% and 2.1% for the three months ended March 31, 2018 and March 31, 2017, respectively. The weighted average interest rate on all short-term borrowings for the twelve months ended December 31, 2017 was 2.4%.

On November 1, 2017, Northern Utilities issued $20 million of Notes due 2027 at 3.52% and $30 million of Notes due 2047 at 4.32%. Fitchburg issued $10 million of Notes due 2027 at 3.52% and $15 million of Notes due 2047 at 4.32%. Granite State issued $15 million of Notes due 2027 at 3.72%. Northern Utilities, Fitchburg and Granite State used the net proceeds from these offerings to refinance higher cost long-term debt that matured in 2017, to repay short-term debt and for general corporate purposes. Approximately $0.7 million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets.

In April 2014, Unitil Service Corp. entered into a financing arrangement, structured as a capital lease obligation, for various information systems and technology equipment. Final funding under this capital lease occurred on October 30, 2015, resulting in total funding of $13.4 million. The capital lease matures on September 30, 2020. As of March 31, 2018, there are $2.7 million of current and $4.4 million of noncurrent obligations under this capital lease on the Company’s Consolidated Balance Sheets.

Unitil Corporation and its utility subsidiaries, Fitchburg, Unitil Energy, Northern Utilities, and Granite State are currently rated “BBB+” by Standard & Poor’s Ratings Services. Unitil Corporation and Granite State are currently rated “Baa2”, and Fitchburg, Unitil Energy and Northern Utilities are currently rated “Baa1” by Moody’s Investors Services.

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 $1.0 million, $3.8 million and $8.5 million of natural gas storage inventory at March 31, 2018, March 31, 2017 and December 31, 2017, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2018 and payable in April 2018 is $1.0 million and is recorded in Accounts Payable at March 31, 2018. The amount of natural gas inventory released in March 2017 and payable in April 2017 was $2.0 million and was recorded in Accounts Payable at March 31, 2017. The amount of natural gas inventory released in December 2017 and payable in January 2018 was $3.1 million and was recorded in Accounts Payable at December 31, 2017.

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 March 31, 2018, there were approximately $17.9 million of guarantees outstanding and the longest term guarantee extends through August 2018.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Granite State. As of March 31, 2018, the principal amount outstanding for the 7.15% Granite State notes was $3.3 million.

COMMON STOCK AND PREFERRED STOCK

3 Months Ended

Mar. 31, 2018

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 14,107,741, 14,815,585 and 14,860,123 shares of common stock outstanding at March 31, 2017, December 31, 2017 and March 31, 2018, respectively.

Unitil Corporation Common Stock Offering - On December 14, 2017, the Company issued and sold 690,000 shares of its common stock at a price of $48.30 per share in a registered public offering (Offering). The Company’s net increase to Common Equity and Cash proceeds from the Offering was approximately $31.7 million and was used to make equity capital contributions to the Company’s regulated utility subsidiaries, repay short-term debt and for general corporate purposes.

Dividend Reinvestment and Stock Purchase Plan - During the first quarter of 2018, the Company sold 7,812 shares of its common stock, at an average price of $43.71 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $341,500. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

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

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

of shares of common stock that may be delivered under the Stock Plan and, in addition, may authorize and make an equitable adjustment to the Stock Plan’s annual individual award limit.

Restricted Shares

Outstanding awards of Restricted Shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on Restricted Shares underlying the award may be credited to a participant’s account. 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 29, 2018, 37,510 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.6 million. There were 90,882 and 94,880 non-vested shares under the Stock Plan as of March 31, 2018 and 2017, respectively. The weighted average grant date fair value of these shares was $41.93 and $39.55, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.8 million and $1.7 million for the three months ended March 31, 2018 and 2017, respectively. At March 31, 2018, there was approximately $1.3 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.8 years. During the three months ended March 31, 2018 there were 784 shares of Restricted Shares forfeited. There were no cancellations under the Stock Plan during the three months ended March 31, 2018.

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 three months ended March 31, 2018 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, 2017		52,224	$	36.22
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		453	$	42.04
Restricted Stock Units Settled		—		—

Restricted Stock Units as of March 31, 2018		52,677	$	36.27

There were 43,696 Restricted Stock Units outstanding as of March 31, 2017 with a weighted average stock price of $33.49. Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of March 31, 2018, March 31, 2017 and December 31, 2017 is $1.0 million, $0.8 million and $1.0 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 1,893 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of March 31, 2018, March 31, 2017 and December 31, 2017. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three month periods ended March 31, 2018 and March 31, 2017, respectively.

REGULATORY MATTERS

3 Months Ended

Mar. 31, 2018

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, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.

Tax Cuts and Jobs Act of 2017

At the end of December 2017, the United States Congress voted and the President signed into law major federal tax law changes Tax Cuts and Jobs Act of 2017 (TCJA) effective for tax year 2018. Among other things, the TCJA substantially reduces the corporate income tax rate to 21 percent, effective January 1, 2018. Each state public utility commission, with jurisdiction over the areas that are served by Unitil’s electric and gas subsidiary companies, has or is in the process of issuing procedural orders directing how the tax law changes are to be reflected in rates, including requiring that the companies provide certain filings and calculations. Unitil is fully complying with these orders and will make any necessary changes to its rates as directed by the commissions. The FERC has opened a rulemaking proceeding on this matter (described below). The Company believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows.

In Maine, Northern Utilities’ Maine division has recently completed a base rate case (described more fully below). The MPUC had issued a procedural order indicating that the tax law changes were to be reflected in its calculation of final rates for the Company, and the final order in that docket incorporated the lower tax rates.

In New Hampshire, Northern Utilities’ New Hampshire division has a base rate case proceeding pending (described below), and the NHPUC issued an order directing the Company to show how the tax changes can be effected within the schedule for the rate case. On April 6, 2018, Northern Utilities filed a proposed comprehensive settlement agreement among the Company, the Staff of the Public Utilities Commission and the Office of Consumer Advocate which includes the effect of the tax changes in the calculation of the agreed upon revenue requirement. With respect to Unitil Energy, the NHPUC directed the Company to make a filing by April 1, 2018, showing the effect of the tax law changes on rates. On March 16, 2018, the Company filed for its annual step increase pursuant to the provisions of its last base rate case, and included in that filing proposed adjustments to account for the tax changes. This proposal remains pending.

In Massachusetts, the Attorney General filed a petition with the MDPU requesting that it open an investigation to require the flow-through of the tax law changes in rates for all utilities subject to the MDPU’s jurisdiction. On February 2, 2018 the MDPU issued an order opening an investigation into the effect on rates of the decrease in the federal corporate income tax rate on the MDPU’s regulated utilities. The MDPU consolidated the Attorney General’s petition into its investigation. In its order, the MDPU required each utility company subject to its jurisdiction to file, by May 1, 2018, a proposal to address the effects of the TCJA and to reduce its rates through the establishment of a revised cost of service incorporating the lower federal corporate income tax rate as of January 1, 2018. Such proposals must address the adjustment of rates going forward and also incorporate the timely refund of revenues associated with the lower tax expense on current income and excess accumulated deferred income taxes (ADIT). Fitchburg plans to submit filings for both its gas and electric divisions with estimated revenue reductions of $0.8 million at each respective division. This matter remains pending.

On March 15, 2018, the FERC issued a Notice of Proposed Rulemaking (NOPR) that would allow it to determine which pipelines under the Natural Gas Act may be collecting unjust and unreasonable rates in light of the corporate tax rate reduction and changes to the FERC’s income tax allowance policies. The proposed rule, if adopted, would require an interstate pipeline to file a one-time report on the regulated rate effect of the new tax law and changes to the FERC’s income tax allowance policies. In addition to filing the one-time report, each pipeline would have four options: 1) make a limited rate filing to reduce its rates by the percentage reduction in its cost of service shown in its report; 2) commit to file either a prepackaged uncontested rate settlement or a general rate case by December 31, 2018; 3) file a statement explaining why it believes its current rates are reasonable and no reduction is necessary; or 4) file the required report without taking any other action, at which point FERC would consider whether to initiate an investigation. Granite State is reviewing the NOPR and will comply with all FERC requirements. Granite State believes that the ultimate resolution of these matters will not have a material impact on its financial position, operating results or cash flows.

Rate Case Activity

Unitil Energy – Base Rates – On April 20, 2017 the NHPUC issued its final order approving a settlement between Unitil Energy, NHPUC Staff and the Office of Consumer Advocate providing for a permanent increase of $4.1 million in electric base rates, and a three year rate plan with an additional rate step adjustment, effective May 1, 2017, of $0.9 million, followed by two rate step adjustments in May of 2018 and 2019 to recover the revenue requirements associated with annual capital expenditures as defined under the rate plan. On March 16, 2018, Unitil Energy filed its second step adjustment. The filing also incorporated the revenue requirement effect of the federal tax decrease pursuant to the TCJA, along with the termination of the one-year reconciliation adjustment which had recouped the difference between temporary rates and final rates. The net effect of the three adjustments results in a proposed revenue decrease of $0.4 million. The proposal remains pending.

Fitchburg – Base Rates – Electric – On April 29, 2016 the MDPU issued an order approving a $2.1 million increase in Fitchburg’s electric base revenue decoupling target, effective May 1, 2016. As part of its order, the MDPU approved, with modifications, Fitchburg’s request for an annual capital cost recovery mechanism, which allows for increases to target revenues to recover the revenue requirement associated with capital additions as defined under the mechanism. In 2016, Fitchburg filed its first compliance report on capital investments for calendar year 2015. The MDPU approved the recovery of approximately $0.5 million, effective January 1, 2017, subject to further investigation and reconciliation. On December 18, 2017, the MDPU approved Fitchburg’s calendar year 2015 capital investments and associated revenue requirements for recovery. On June 29, 2017, Fitchburg filed its compliance report on capital investments for calendar year 2016. On December 20, 2017, the MDPU approved the recovery of approximately $0.4 million, effective January 1, 2018, subject to further investigation and reconciliation.

Fitchburg – Base Rates – Gas – On April 29, 2016, the MDPU issued an order approving a $1.6 million increase in Fitchburg’s gas base revenue decoupling target, effective May 1, 2016.

Fitchburg – Gas Operations – On October 31, 2016, Fitchburg submitted its annual filing under its gas system enhancement program to recover the revenue requirements associated with its projected capital additions in 2017 as defined under the program. The filing sought approval to collect an additional $0.9 million of annual revenue requirements. On April 28, 2017, the MDPU approved recovery of the projected 2017 revenue requirements, subject to reconciliation and a cap of 1.5% on the change in revenue requirement to be billed in any given year. The cap resulted in approval of an additional $0.5 million of annual revenue requirements to be billed effective May 1, 2017 with the remaining $0.4 million of annual revenue requirements deferred for billing in future periods. In its April 28, 2017 annual reconciliation filing for 2016 revenue requirements, the Company requested that the MDPU waive the 1.5% revenue requirement cap. On October 31, 2017, the MDPU approved a one-year waiver of the cap and allowed the Company to bill the total 2016 actual reconciliation balance. On October 31, 2017, Fitchburg submitted its annual filing under the program to recover the revenue requirements associated with its projected capital additions in 2018. In this filing, the Company has requested to change the revenue requirements cap to 3%. This matter remains pending.

Northern Utilities – Base Rates – Maine – In May 2017, Northern Utilities filed a base rate case with the MPUC seeking to increase annual revenues by $6.0 million. The requested increase was subsequently supplemented by an additional $0.7 million associated with the Company’s Targeted Area Build-out (TAB) Program (see below). In addition to the distribution base rate increase, Northern Utilities requested to extend its Targeted Infrastructure Replacement Adjustment mechanism (TIRA) (see below).

On February 28, 2018 the MPUC issued its Final Order (Order) in the base rate case. The Order provides for a revenue increase of $2.1 million offset by a revenue decrease of $2.2 million to incorporate the effect of the lower federal income tax rate under the TCJA, resulting in an overall annual revenue decrease of $0.1 million. The MPUC approved a return on equity of 9.5 percent and a capital structure reflecting 50 percent equity and 50 percent long-term debt. The Order also provides for a reduction in annual depreciation expense reducing the Company’s annual operating costs by approximately $0.5 million. The Order addresses a number of other issues including a change to therm billing, increases in other delivery charges, and cost recovery under the Company’s TAB Program and TIRA mechanism. The new rates and other changes became effective as of March 1, 2018. On March 16, 2018, the Company filed a Motion for Clarification requesting the MPUC clarify its Order in light of what the Company believes to be an inadvertent inconsistency with the Order regarding 2016 TIRA Eligible Facilities, rate base and related annual revenue adjustments.

Northern Utilities – Targeted Infrastructure Replacement Adjustment – Maine – The settlement in Northern Utilities’ Maine division’s 2013 rate case allowed the Company to implement a TIRA rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects, including the Company’s Cast Iron Replacement Program (CIRP). The TIRA had an initial term of four years and covered targeted capital expenditures in 2013 through 2016. In its Order in the current base rate case (see above), the MPUC approved an extension of the Company’s TIRA mechanism, with revision, for an additional eight-year period, which will allow for annual rate adjustments through the end of the CIRP program. On March 30, 2018, the Company filed its request to increase its annual base rates to recover the revenue requirements for 2017 Eligible Facilities. This matter remains pending.

Northern Utilities – Targeted Area Build-out Program – Maine – In December 2015, the MPUC approved a TAB program and associated rate surcharge mechanism. This program is designed to allow the economic extension of natural gas mains to new, targeted service areas in Maine. It allows customers in the targeted area the ability to pay a rate surcharge, instead of a large upfront payment or capital contribution to connect to the natural gas delivery system. The initial pilot of the TAB program was approved for the City of Saco, and is being built out over a period of three years, with the potential to add 1,000 new customers and approximately $1 million in annual distribution revenue in the Saco area. A second TAB program was approved for the Town of Sanford, and has the potential to add 2,000 new customers and approximately $2 million in annual distribution revenue in the Sanford area. In its base rate case Order (above), the MPUC approved the inclusion of Saco TAB investments in rate base along with a cost recovery incentive mechanism for future TAB investments.

Northern Utilities – Base Rates – New Hampshire – On June 5, 2017, Northern Utilities filed for a base rate increase with the NHPUC seeking to increase annual revenues by $4.7 million. On June 15, 2017, the NHPUC suspended the Company’s proposed permanent rates tariffs while the filing is under regulatory review

Northern Utilities reached a settlement agreement on temporary rates to produce an increase in annual revenues of approximately $1.6 million, effective with service rendered on and after August 1, 2017, and until a final, non-appealable order on permanent rates is issued. The settlement agreement was approved by the NHPUC on July 31, 2017. As of March 31, 2018, Northern Utilities has deferred approximately $1.1 million of costs associated with this base rate case. Once a final decision on permanent rates is issued, it will be reconciled back to the date that temporary rates were implemented.

On April 6, 2018, Northern Utilities filed a proposed comprehensive settlement agreement among the Company, the NHPUC Staff and the Office of the Consumer Advocate. The settling parties agreed to an annual revenue increase of $2.6 million and an offsetting decrease of $1.7 million to reflect the effect of the TCJA, for a net annual revenue increase of $0.9 million, effective May 1, 2018. The parties also agreed to a step increase of $2.3 million to recover post-test year capital investments, also effective May 1, 2018. Under the agreement, the company may file for a second step increase for effect May 1, 2019 to recover eligible capital investments in 2018, up to a revenue requirement cap of $2.2 million. If the company chooses the option to implement the second step increase, the next distribution base rate case shall be based on an historic test year of no earlier than twelve months ending December 31, 2020. A hearing before the NHPUC to consider the settlement agreement was held on April 12, 2018. This matter remains pending.

Northern Utilities – Pipeline Refund – On February 19, 2015, the FERC issued Opinion No. 524-A, the final order in Portland Natural Gas Transmission’s (PNGTS) Section 4 rate case, requiring PNGTS to issue refunds to shippers. Northern Utilities received a pipeline refund of $22.0 million on April 15, 2015. As a gas supply-related refund, the entire amount refunded will be credited to Northern Utilities’ customers and marketers over three years as directed by the NHPUC and MPUC. As of March 31, 2018, $21.4 million has been refunded to Northern Utilities’ customers and marketers. The Company has recorded current Regulatory Liabilities related to these refunds of $0.6 million on its Consolidated Balance Sheets as of March 31, 2018.

Granite State – Base Rates – Granite State has in place a FERC-approved second amended settlement agreement under which it is permitted to file annually, each June, for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects up to a specific cap on expenditures. On June 21, 2017 Granite State filed for an annual revenue increase under this provision of $0.2 million, effective August 1, 2017. The FERC issued an order approving the filing on July 28, 2017. This is the last annual rate adjustment allowed under the second amended settlement because Granite must file a general rate case pursuant to Section 4 of the Natural Gas Act by April 30, 2018 with rates effective no later than November 1, 2018.

Other Matters

NHPUC Energy Efficiency Resource Standard Proceeding – In May 2015, the NHPUC opened a proceeding to establish an Energy Efficiency Resource Standard (“EERS”), an energy efficiency policy with specific targets or goals for energy savings that New Hampshire electric and gas utilities must meet. On April 27, 2016, a comprehensive settlement agreement was filed by the parties, including Unitil Energy and Northern Utilities, which was approved by the NHPUC on August 2, 2016. The settlement provides for: extending the 2014-2016 Core program an additional year (through 2017); establishing an EERS; establishing a recovery mechanism to compensate the utilities for lost-revenue related to the EERS programs; and approving the performance incentives and processes for stakeholder involvement, evaluation, measurement and verification, and oversight of the EERS programs. In accordance with the Settlement, on September 1, 2017, the New Hampshire electric and gas utilities jointly filed a Statewide Energy Efficiency Plan for the period 2018-2020. The Settlement and the Statewide Energy Efficiency Plan for the period 2018-2020 were approved on January 2, 2018.

Unitil Energy – Electric Grid Modernization – In July 2015, the NHPUC opened an investigation into Grid Modernization to address a variety of issues related to Distribution System Planning, Customer Engagement with Distributed Energy Resources, and Utility Cost Recovery and Financial Incentives. The NHPUC engaged a consultant to direct a Working Group to investigate these issues and to prepare a final report with recommendations for the Commission. The final report was filed on March 20, 2017. This matter remains pending.

Unitil Energy – Net Metering – Pursuant to legislation that became effective in May 2016, the NHPUC opened a proceeding to consider alternatives to the net metering tariffs currently in place. The NHPUC issued an Order on June 23, 2017. The Order removes the cap on the total amount of generation capacity which may be owned or operated by customer-generators eligible for net metering. The order also adopts an alternative net metering tariff for small customer-generators (those with renewable energy systems of 100 kW or less) which will remain in effect for a period of years while further data is collected and analyzed, time-of-use and other pilot programs are implemented, and a distributed energy resource valuation study is conducted. Systems that are installed or queued during this period will have their net metering rate structure “grandfathered” until December 31, 2040. The Company does not believe that this proceeding will have a material adverse impact on the Company’s financial position, operating results or cash flows.

Fitchburg – Electric Operations – On November 1, 2017, Fitchburg submitted its 2017 annual reconciliation of costs and revenues for transition and transmission under its restructuring plan, including the reconciliation of costs and revenues for a number of other surcharges and cost factors, for review and approval by the MDPU. All of the rates were given final approval by the MDPU on December 28, 2017, effective January 1, 2018.

Fitchburg – Service Quality – On March 1, 2018, Fitchburg submitted its 2017 Service Quality Reports for both its gas and electric divisions in accordance with new Service Quality Guidelines issued by the MDPU in December 2015. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. These filings are pending approval.

Fitchburg – Solar Generation – On August 19, 2016, Fitchburg filed a petition with the MDPU seeking approval to develop a 1.3 MW solar generation facility located on Company property in Fitchburg, Massachusetts, including a cost recovery mechanism to share the costs and benefits of the project among all Fitchburg customers. On November 9, 2016, the MDPU approved a Settlement Agreement supporting the proposal, which was reached among the Company, the Attorney General of Massachusetts, and the Low-Income Weatherization and Fuel Assistance Program Network. Construction of the solar generating facility was completed and the facility began generating power on November 22, 2017. On April 2, 2018, Fitchburg submitted its first filing pursuant to its Solar Cost Adjustment tariff, by which the company recovers its annual revenue requirement related to its investment in the solar generation facility. The filing seeks a net amount of approximately $300,000 for recovery effective June 1, 2018.

Fitchburg – Energy Diversity – Governor Baker signed into law H4568 “An Act to Promote Energy Diversity” on August 8, 2016. Among many sections in the bill, the primary provision adds new sections 83c and 83d to the 2008 Green Communities Act. Section 83c requires every electric distribution company (EDC), including Fitchburg, to jointly and competitively solicit proposals for at least 400 MW’s of offshore wind energy generation by June 30, 2017, as part of a total of 1,600 MW of offshore wind the EDCs are directed to procure by June 30, 2027. The procurement requirement is subject to a determination by the MDPU that the proposed long-term contracts are cost-effective. Section 83d further requires the EDCs to jointly seek proposals for cost effective clean energy (hydro and other) long-term contracts via one or more staggered solicitations, the first of which shall be issued not later than April 1, 2017, for a total of 9,450,000 megawatt-hours by December 31, 2022. Emergency regulations implementing these new provisions, 220 C.M.R. § 23.00 et seq. and 220 C.M.R. § 24.00 et seq. were adopted by the MDPU on December 29, 2016, and adopted as final regulations on March 8, 2017. The EDCs issued the RFP for Long-Term Contracts for Clean Energy Projects, pursuant to Section 83d on March 31, 2017 and project proposals were received on July 27, 2017. Final selection of projects concluded in the first quarter of 2018 and contract negotiation is underway. The EDCs issued the RFP for Long-Term Contracts for Offshore Wind Energy Projects pursuant to Section 83c on June 29, 2017 and project proposals were received on December 20, 2017.

Fitchburg – Clean Energy RFP – Pursuant to Section 83a of the Green Communities Act in Massachusetts and similar clean energy directives established in Connecticut and Rhode Island, state agencies and the electric distribution companies in the three states, including Fitchburg, issued an RFP for clean energy resources (including Class I renewable generation and large hydroelectric generation) in November 2015. The RFP sought proposals for clean energy and transmission projects that can deliver new renewable energy to the three states. Project proposals were received in January 2016. Selection of contracts concluded during the fourth quarter of 2016 and contract negotiations concluded during the second quarter of 2017. On September 20, 2017, Fitchburg, along with the other three EDCs, filed for approval of the purchase power agreements which were negotiated as a result of the joint solicitation. A hearing on the merits was held in February 2018. This matter remains pending.

Fitchburg – Other – On August 25, 2017, the Massachusetts Department of Energy Resources (“DOER”) issued its final Solar Massachusetts Renewable Target (SMART) Program regulations. These regulations were promulgated pursuant to Chapter 75 of the Acts of 2016, which required the DOER to establish a new solar incentive program. The regulation is designed to support the continued development of an additional 1,600 MW of solar renewable energy generating sources via a declining block compensation mechanism. On September 12, 2017, the Massachusetts electric utilities jointly filed a model SMART tariff with the MDPU to implement the program and propose a cost recovery mechanism. Hearings on the merits were held in late March and early April 2018. This filing remains pending. In the interim, the current program for solar renewable energy credits, known as SREC-II, remains in effect for all eligible solar facilities.

On May 11, 2016, the MDPU issued an Order commencing a rulemaking proceeding to adopt emergency regulations amending 220 C.M.R. § 18.00 et seq. (“Net Metering Regulations”). Specifically, the MDPU amended its Net Metering Regulations to implement the net metering provisions of An Act Relative to Solar Energy, St. 2016, c. 75, §§ 3-9, and to make additional clerical changes to the Net Metering Regulations. On July 15, 2016, the MDPU issued an order approving Final Net Metering Regulations. Fitchburg’s tariff, filed in compliance with the new regulations, was approved on February 7, 2017.

In December 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.” In June 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 is 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. Fitchburg and the Commonwealth’s three other electric distribution companies filed their initial GMPs on August 19, 2015. These filings are currently under MDPU review and remain pending.

On January 28, 2016 the MDPU approved Fitchburg’s Three-Year Energy Efficiency Plan for 2016-2018, subject to limited modifications and directives in the Order. The Department found that the savings goals included in each Three-Year Plan are reasonable and are consistent with the achievement of all available cost-effective energy efficiency; approved each Program Administrator’s program implementation cost budget for the Three-Year Plans; approved the performance incentive pool, mechanism, and payout rates; found that all proposed energy efficiency programs are cost-effective; found that funding sources are reasonable and that each Program Administrator may recover the funds to implement its energy efficiency plan through its Energy Efficiency Surcharge; and found that each Program Administrator’s Three-Year Plan is consistent with the Green Communities Act, the Guidelines, and Department precedent.

FERC Transmission Formula Rate Proceedings – Pursuant to Section 206 of the Federal Power Act, there are several pending proceedings before the FERC concerning the justness and reasonableness of the Return on Equity (“ROE”) component of the ISO-New England, Inc. Participating Transmission Owners’ Regional Network Service and Local Network Service formula rates. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating a decision of the FERC with respect to these formula rates, and remanded it for further proceedings. The FERC had found that the Transmission Owners existing ROE was unlawful, and had set a new ROE. The Court found that the FERC had failed to articulate a satisfactory explanation for its orders. At this time, the ROE set in the vacated order will remain in place until further FERC action is taken. Separately, on March 15, 2018, the Transmission Owners filed a petition for review with the Court of certain orders of the FERC setting for hearing other complaints challenging the allowed return on equity component of the formula rates. Fitchburg and Unitil Energy are Participating Transmission Owners, although Unitil Energy does not own transmission plant. To the extent that these proceedings result in any changes to the rates being charged, a retroactive reconciliation may be required. The Company does not believe that these proceedings will have a material adverse impact on the Company’s financial condition or results of operations.

Legal Proceedings

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

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 Massachusetts Supreme Judicial Court issued an order denying class certification status in July 2016, though the plaintiffs’ individual claims remain pending. The Company continues to believe these claims are without merit and will continue to defend itself vigorously.

ENVIRONMENTAL MATTERS

3 Months Ended

Mar. 31, 2018

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, 2017 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2018.

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 is in material compliance with applicable environmental and safety laws and regulations and, as of March 31, 2018, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure 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. 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.

Northern Utilities Manufactured Gas Plant Sites – Northern Utilities has an extensive program to identify, investigate and remediate former manufactured gas plant (MGP) sites, which were operated from the mid-1800s through the mid-1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. In Maine, Northern Utilities has documented the presence of MGP sites in Lewiston and Portland, and a former MGP disposal site in Scarborough.

Northern Utilities has worked with the Maine Department of Environmental Protection (ME DEP) and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have substantially completed remediation of all sites, though on site monitoring continues and it is possible that future activities may be required. Supplemental remediation at the Exeter and Somersworth MGP sites commenced in the second quarter of 2018 with anticipated completions by the third quarter of 2018.

The NHPUC and MPUC have approved regulatory mechanisms for the recovery of MGP environmental costs. For Northern Utilities’ New Hampshire division, the NHPUC has approved the recovery of MGP environmental costs over succeeding seven-year periods. For Northern Utilities’ Maine division, the MPUC has authorized the recovery of environmental remediation costs over succeeding five- year periods.

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 – Fitchburg has worked with the Massachusetts Department of Environmental Protection to address environmental concerns with the former MGP site at Sawyer Passway, and has substantially completed remediation activities, though on site monitoring will continue and it is possible that future activities may be required.

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.

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the three months ended March 31, 2018 and 2017.


Environmental Obligations
	($ millions)
	Fitchburg				Northern Utilities				Total
	Three months ended March 31,
	2018		2017		2018		2017		2018		2017
Total Balance at Beginning of Period	$	0.1	$	0.1	$	2.0	$	1.9	$	2.1	$	2.0
Additions		0.1		—		0.1		0.4		0.2		0.4
Less: Payments / Reductions		0.1		—		0.1		0.1		0.2		0.1

Total Balance at End of Period		0.1		0.1		2.0		2.2		2.1		2.3

Less: Current Portion		0.1		0.1		0.5		0.4		0.6		0.5

Noncurrent Balance at End of Period	$	—	$	—	$	1.5	$	1.8	$	1.5	$	1.8

INCOME TAXES

3 Months Ended

Mar. 31, 2018

INCOME TAXES

NOTE 8: INCOME TAXES

In December 2017, the Tax Cuts and Jobs Act (TCJA), which included a reduction to the corporate federal income tax rate to 21% effective January 1, 2018, was signed into law. In accordance with GAAP Accounting Standard 740, the Company revalued its Accumulated Deferred Income Taxes (ADIT) at the new 21% tax rate at which the ADIT will be reversed in future periods. The Company recorded reasonable estimates to reflect the impacts of the Tax Act and recorded a net Regulatory Liability in the amount of $48.9 million at December 31, 2017 as a result of the ADIT revaluation.

On March 15, 2018; FERC issued its Notice of Proposed Rulemaking in Docket No. RM18-11-000 in which FERC provided specific guidance on the flow back of excess ADIT: The amount of the reduction to ADIT that was collected from customers but is no longer payable to the IRS is excess ADIT and should be flowed back to ratepayers under general ratemaking principles. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of the excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA.

Based on communications received by the Company from its state regulators in rate cases and other regulatory proceedings in the first quarter of 2018 and as prescribed in the TCJA, the recent FERC guidance noted above and IRS normalization rules; the benefit of these excess ADIT amounts will be subject to flow back to customers in future utility rates according to the Average Rate Assumption Method (ARAM). ARAM reconciles excess ADIT at the reversal rate of the underlying book/tax temporary timing differences. The Company estimates the ARAM flow back period to be between fifteen and twenty years. The Company’s regulators and the IRS are each expected to issue guidance in future periods that will determine the final disposition of the re-measurement of regulatory deferred tax balances. At this time, the Company has applied a reasonable interpretation of the TCJA and a reasonable estimate of the regulatory resolution. Future clarification of the TCJA and regulatory decisions may change the amounts estimated.

In addition to the excess $47.1 million ADIT amounts the Company expects to flow back to customers in future utility rates, as noted above, there was $1.8 million of excess ADIT at December 31, 2017, which had not been previously included in customers’ utility rates. During 2018, the Company determined that since this excess ADIT had not been previously collected from utility customers; it would, therefore, not be subject to flow back to customers in future rates. The Company will recognize a nonrecurring benefit in its tax provision as the underlying book/tax temporary differences reverse in the current and future periods.

The Company filed its tax returns for the year ended December 31, 2016 with the Internal Revenue Service in September 2017 and generated additional federal net operating loss carryforward (NOLC) assets principally due to current tax repair deductions, tax depreciation and research and development deductions. In 2016, the Company recorded a benefit of approximately $0.7 million for New Hampshire business enterprise tax credits utilized in filing the Company’s 2015 tax returns. For the year ended December 31, 2017, the Company decreased its federal NOLC $1.1 million in the calculation of its provisions for income taxes for the period and revalued the NOLC by $10.1 million for federal rate of 21% enacted in the TCJA.

As of December 31, 2017, the Company had recorded cumulative federal and state NOLC assets of $12.7 million to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029. In addition, at December 31, 2017, the Company had $3.5 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable.

In March 2018, Unitil Corporation received notice that its Federal Income Tax return filings for the years ended December 31, 2015 and December 31, 2016 are under examination by the IRS. Currently, the Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s financial statements. The Company remains subject to examination by New Hampshire tax authorities for the tax periods ended December 31, 2014; December 31, 2015; and December 31, 2016. Income tax filings for the year ended December 31, 2016 have been filed with the New Hampshire Department of Revenue Administration. The State of Maine has concluded its review of the Company’s tax returns for December 31, 2014, December 31, 2015, and December 31, 2016 which resulted in a small additional refund to the Company.

The Company evaluated its tax positions at March 31, 2018 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, de-recognition, 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, 2014; December 31, 2015; and December 31, 2016.

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

3 Months Ended

Mar. 31, 2018

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, 2017 as filed with the SEC on February 1, 2018 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:


	2018			2017
Used to Determine Plan Costs
Discount Rate		3.60	%		4.10	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%
Health Care Cost Trend Rate Assumed for Next Year		7.50	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2025

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended March 31,	2018			2017			2018			2017			2018			2017
Service Cost	$	848		$	824		$	733		$	744		$	122		$	115
Interest Cost		1,469			1,514			851			978			101			98
Expected Return on Plan Assets		(1,946	)		(1,819	)		(409	)		(337	)		—			—
Prior Service Cost Amortization		81			66			327			350			47			47
Actuarial Loss Amortization		1,447			1,176			346			524			122			74

Sub-total		1,899			1,761			1,848			2,259			392			334
Amounts Capitalized and Deferred		(720	)		(662	)		(742	)		(1,037	)		(113	)		(99	)

Net Periodic Benefit Cost Recognized	$	1,179		$	1,099		$	1,106		$	1,222		$	279		$	235

Employer Contributions

As of March 31, 2018, the Company had made $1.2 million and $1.0 million of contributions to its Pension Plan and PBOP Plan, respectively, in 2018. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2018 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 March 31, 2018, the Company had made $43,900 of benefit payments under the SERP Plan in 2018. The Company presently anticipates making an additional $356,300 of benefit payments under the SERP Plan in 2018.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2018

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.

Basis of Presentation

Utility Revenue Recognition


	Three Months Ended March 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	35.8		$	34.4		$	70.2
C&I		50.6			24.1			74.7
Other		6.5			3.9			10.4
Revenue Reductions – TCJA		(1.5	)		(0.8	)		(2.3	)

Total Billed and Unbilled Revenue		91.4			61.6			153.0
Rate Adjustment Mechanism Revenue		(4.4	)		(4.1	)		(8.5	)

Total Gas and Electric Operating Revenues	$	87.0		$	57.5		$	144.5


	Three Months Ended March 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	30.9		$	27.3		$	58.2
C&I		42.3			19.5			61.8
Other		5.6			2.2			7.8

Total Billed and Unbilled Revenue		78.8			49.0			127.8
Rate Adjustment Mechanism Revenue		(4.0	)		0.5			(3.5	)

Total Gas and Electric Operating Revenues	$	74.8		$	49.5		$	124.3

Other Operating Revenue - Non-regulated


	Three Months Ended March 31,
	As Reported		If ASU 2014-09 Had Been in Effect
Other Operating Revenues ($ millions):	2018		2017
Usource Contract Revenue	$	1.6	$	1.7
Less: Revenue Sharing Payments		0.3		0.3

Total Other Operating Revenues	$	1.3	$	1.4


	Three Months Ended March 31,
	As Reported		If ASU 2014-09 Had Been in Effect
Operation and Maintenance Expense ($ millions):	2018		2017
Operation and Maintenance Expense	$	17.3	$	15.7

Retirement Benefit Costs

Income Taxes

Cash and Cash Equivalents

Allowance for Doubtful Accounts

($ millions)

March 31,

December 31,

2018

2017

Allowance for Doubtful Accounts

1.6

1.0

1.6

Accrued Revenue


	March 31,				December 31,
Accrued Revenue ($ millions)	2018		2017		2017
Regulatory Assets – Current	$	34.6	$	32.0	$	39.5
Unbilled Revenues		10.5		9.3		13.8

Total Accrued Revenue	$	45.1	$	41.3	$	53.3

Exchange Gas Receivable


	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2018		2017		2017
Northern Utilities	$	—	$	1.9	$	5.4
Fitchburg		0.2		0.2		0.4

Total Exchange Gas Receivable	$	0.2	$	2.1	$	5.8

Gas Inventory


	March 31,				December 31,
Gas Inventory ($ millions)	2018		2017		2017
Natural Gas	$	—	$	—	$	0.4
Propane		0.3		0.2		0.1
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.4	$	0.3	$	0.6

Utility Plant

Regulatory Accounting


	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2018		2017		2017
Retirement Benefits	$	85.4	$	75.7	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		31.9		27.7		36.0
Deferred Storm Charges		8.0		8.6		7.2
Environmental		9.0		10.7		9.5
Income Taxes		6.3		7.3		6.5
Other		5.2		5.5		5.4

Total Regulatory Assets		145.8		135.5		149.1
Less: Current Portion of Regulatory Assets⁽¹⁾		34.6		32.0		39.5

Regulatory Assets – noncurrent	$	111.2	$	103.5	$	109.6

⁽¹⁾

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


	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2018		2017		2017
Rate Adjustment Mechanisms	$	10.3	$	9.2	$	6.9
Gas Pipeline Refund (Note 6)		0.6		4.3		2.3
Income Taxes (Note 8)		49.1		—		48.9

Total Regulatory Liabilities		60.0		13.5		58.1
Less: Current Portion of Regulatory Liabilities		10.9		12.8		9.2

Regulatory Liabilities – noncurrent	$	49.1	$	0.7	$	48.9

Derivatives

Investments in Marketable Securities


	March 31,				December 31,
Fair Value of Marketable Securities ($ millions)	2018		2017		2017
Equity Funds	$	1.9	$	1.1	$	2.1
Fixed Income Funds		1.6		0.9		1.5
Cash and Equivalents		1.6		1.3		—

Total Marketable Securities	$	5.1	$	3.3	$	3.6

Energy Supply Obligations


	March 31,				December 31,
Energy Supply Obligations ($ millions)	2018		2017		2017
Current:
Exchange Gas Obligation	$	—	$	1.9	$	5.4
Renewable Energy Portfolio Standards		7.5		6.8		4.0
Power Supply Contract Divestitures		0.3		0.3		0.3

Total Energy Supply Obligations – Current		7.8		9.0		9.7
Long-Term:
Power Supply Contract Divestitures		0.8		1.2		0.9

Total Energy Supply Obligations	$	8.6	$	10.2	$	10.6

Recently Issued Pronouncements

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

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

3 Months Ended

Mar. 31, 2018

Components of Gas and Electric Operating Revenue


	Three Months Ended March 31, 2018
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	35.8		$	34.4		$	70.2
C&I		50.6			24.1			74.7
Other		6.5			3.9			10.4
Revenue Reductions – TCJA		(1.5	)		(0.8	)		(2.3	)

Total Billed and Unbilled Revenue		91.4			61.6			153.0
Rate Adjustment Mechanism Revenue		(4.4	)		(4.1	)		(8.5	)

Total Gas and Electric Operating Revenues	$	87.0		$	57.5		$	144.5


	Three Months Ended March 31, 2017
Gas and Electric Operating Revenues ($ millions):	Gas			Electric			Total
Billed and Unbilled Revenue:
Residential	$	30.9		$	27.3		$	58.2
C&I		42.3			19.5			61.8
Other		5.6			2.2			7.8

Total Billed and Unbilled Revenue		78.8			49.0			127.8
Rate Adjustment Mechanism Revenue		(4.0	)		0.5			(3.5	)

Total Gas and Electric Operating Revenues	$	74.8		$	49.5		$	124.3

Schedule of Other Operating Revenues and Operating Expenses


	Three Months Ended March 31,
	As Reported		If ASU 2014-09 Had Been in Effect
Other Operating Revenues ($ millions):	2018		2017
Usource Contract Revenue	$	1.6	$	1.7
Less: Revenue Sharing Payments		0.3		0.3

Total Other Operating Revenues	$	1.3	$	1.4


	Three Months Ended March 31,
	As Reported		If ASU 2014-09 Had Been in Effect
Operation and Maintenance Expense ($ millions):	2018		2017
Operation and Maintenance Expense	$	17.3	$	15.7

Allowance for Doubtful Accounts Included in Accounts Receivable Net

($ millions)

March 31,

December 31,

2018

2017

Allowance for Doubtful Accounts

1.6

1.0

1.6

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of March 31, 2018, March 31, 2017 and December 31, 2017.


	March 31,				December 31,
Accrued Revenue ($ millions)	2018		2017		2017
Regulatory Assets – Current	$	34.6	$	32.0	$	39.5
Unbilled Revenues		10.5		9.3		13.8

Total Accrued Revenue	$	45.1	$	41.3	$	53.3

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of March 31, 2018, March 31, 2017 and December 31, 2017.


	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2018		2017		2017
Northern Utilities	$	—	$	1.9	$	5.4
Fitchburg		0.2		0.2		0.4

Total Exchange Gas Receivable	$	0.2	$	2.1	$	5.8

Components of Gas Inventory

The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of March 31, 2018, March 31, 2017 and December 31, 2017.


	March 31,				December 31,
Gas Inventory ($ millions)	2018		2017		2017
Natural Gas	$	—	$	—	$	0.4
Propane		0.3		0.2		0.1
Liquefied Natural Gas & Other		0.1		0.1		0.1

Total Gas Inventory	$	0.4	$	0.3	$	0.6

Regulatory Assets


	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2018		2017		2017
Retirement Benefits	$	85.4	$	75.7	$	84.5
Energy Supply & Other Rate Adjustment Mechanisms		31.9		27.7		36.0
Deferred Storm Charges		8.0		8.6		7.2
Environmental		9.0		10.7		9.5
Income Taxes		6.3		7.3		6.5
Other		5.2		5.5		5.4

Total Regulatory Assets		145.8		135.5		149.1
Less: Current Portion of Regulatory Assets⁽¹⁾		34.6		32.0		39.5

Regulatory Assets – noncurrent	$	111.2	$	103.5	$	109.6

⁽¹⁾

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

Regulatory Liabilities


	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2018		2017		2017
Rate Adjustment Mechanisms	$	10.3	$	9.2	$	6.9
Gas Pipeline Refund (Note 6)		0.6		4.3		2.3
Income Taxes (Note 8)		49.1		—		48.9

Total Regulatory Liabilities		60.0		13.5		58.1
Less: Current Portion of Regulatory Liabilities		10.9		12.8		9.2

Regulatory Liabilities – noncurrent	$	49.1	$	0.7	$	48.9

Fair Value of Marketable Securities

Changes in the fair value of these investments are recorded in Other Expense, net.


	March 31,				December 31,
Fair Value of Marketable Securities ($ millions)	2018		2017		2017
Equity Funds	$	1.9	$	1.1	$	2.1
Fixed Income Funds		1.6		0.9		1.5
Cash and Equivalents		1.6		1.3		—

Total Marketable Securities	$	5.1	$	3.3	$	3.6

Components of Energy Supply Obligations

The following discussion and table summarize the nature and amounts of the items recorded as Energy Supply Obligations (current portion) and Other Noncurrent Liabilities (noncurrent portion) on the Company’s Consolidated Balance Sheets.


	March 31,				December 31,
Energy Supply Obligations ($ millions)	2018		2017		2017
Current:
Exchange Gas Obligation	$	—	$	1.9	$	5.4
Renewable Energy Portfolio Standards		7.5		6.8		4.0
Power Supply Contract Divestitures		0.3		0.3		0.3

Total Energy Supply Obligations – Current		7.8		9.0		9.7
Long-Term:
Power Supply Contract Divestitures		0.8		1.2		0.9

Total Energy Supply Obligations	$	8.6	$	10.2	$	10.6

DIVIDENDS DECLARED PER SHARE (Tables)

3 Months Ended

Mar. 31, 2018

Schedule of Dividends Declared


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
04/25/18	05/29/18	05/15/18	$0.365
01/30/18	02/28/18	02/14/18	$0.365

10/25/17	11/29/17	11/15/17	$0.360
07/26/17	08/29/17	08/15/17	$0.360
04/26/17	05/30/17	05/16/17	$0.360
01/25/17	02/28/17	02/14/17	$0.360

SEGMENT INFORMATION (Tables)

3 Months Ended

Mar. 31, 2018

Significant Segment Financial Data

The following table provides significant segment financial data for the three months ended March 31, 2018 and March 31, 2017:


	Gas			Electric			Non- Regulated		Other			Total

Three Months Ended March 31, 2018 ($ millions)
Revenues:
Billed and Unbilled Revenue	$	91.4		$	61.6		$	—	$	—		$	153.0
Rate Adjustment Mechanism Revenue		(4.4	)		(4.1	)		—		—			(8.5	)
Other Operating Revenue – Non-Regulated		—			—			1.3		—			1.3

Total Operating Revenues	$	87.0		$	57.5		$	1.3	$	—		$	145.8

Segment Profit (Loss)		12.6			3.0			0.4		(0.4	)		15.6
Identifiable Segment Assets		712.6			481.8			7.1		42.8			1,244.3
Capital Expenditures		3.6			6.0			—		0.5			10.1

Three Months Ended March 31, 2017 ($ millions)
Revenues	$	74.8		$	49.5		$	1.7	$	—		$	126.0
Segment Profit		9.9			2.1			0.4		—			12.4
Identifiable Segment Assets		641.8			442.8			7.0		42.8			1,134.4
Capital Expenditures		5.7			8.3			—		3.5			17.5

As of December 31, 2017 ($ millions)
Identifiable Segment Assets	$	714.3		$	476.9		$	6.7	$	44.0		$	1,241.9

DEBT AND FINANCING ARRANGEMENTS (Tables)

3 Months Ended

Mar. 31, 2018

Details on Long Term Debt

Details on long-term debt at March 31, 2018, March 31, 2017 and December 31, 2017 are shown below:


($ millions)	March 31,				December 31,
	2018		2017		2017
Unitil Corporation:
6.33% Senior Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
3.70% Senior Notes, Due August 1, 2026		30.0		30.0		30.0
Unitil Energy First Mortgage Bonds:
5.24% Senior Secured Notes, Due March 2, 2020		10.0		15.0		15.0
8.49% Senior Secured Notes, Due October 14, 2024		7.5		9.0		7.5
6.96% Senior Secured Notes, Due September 1, 2028		20.0		20.0		20.0
8.00% Senior Secured Notes, Due May 1, 2031		15.0		15.0		15.0
6.32% Senior Secured Notes, Due September 15, 2036		15.0		15.0		15.0
Fitchburg:
6.75% Senior Notes, Due November 30, 2023		7.6		9.5		7.6
6.79% Senior Notes, Due October 15, 2025		10.0		10.0		10.0
3.52% Senior Notes, Due November 1, 2027		10.0		—		10.0
7.37% Senior Notes, Due January 15, 2029		12.0		12.0		12.0
5.90% Senior Notes, Due December 15, 2030		15.0		15.0		15.0
7.98% Senior Notes, Due June 1, 2031		14.0		14.0		14.0
4.32% Senior Notes, Due November 1, 2047		15.0		—		15.0
Northern Utilities:
6.95% Senior Notes, Due December 3, 2018		10.0		20.0		10.0
5.29% Senior Notes, Due March 2, 2020		16.6		25.0		25.0
3.52% Senior Notes, Due November 1, 2027		20.0		—		20.0
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		50.0
4.32% Senior Notes, Due November 1, 2047		30.0		—		30.0
Granite State:
7.15% Senior Notes, Due December 15, 2018		3.3		6.7		3.3
3.72% Senior Notes, Due November 1, 2027		15.0		—		15.0
Unitil Realty Corp.:
8.00% Senior Secured Notes, Due Through August 1, 2017		—		0.2		—

Total Long-Term Debt		396.0		336.4		409.4
Less: Unamortized Debt Issuance Costs		3.2		2.9		3.3

Total Long-Term Debt, net of Unamortized Debt Issuance Costs		392.8		333.5		406.1
Less: Current Portion		29.8		30.0		29.8

Total Long-term Debt, Less Current Portion	$	363.0	$	303.5	$	376.3

Fair Value of Long Term Debt

($ millions)

March 31,

December 31,

2018

2017

Estimated Fair Value of Long-Term Debt

428.0

374.3

457.1

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 March 31, 2018, March 31, 2017 and December 31, 2017:


	Revolving Credit Facility ($ millions)
	March 31,				December 31,
	2018		2017		2017
Limit	$	120.0	$	120.0	$	120.0
Short-Term Borrowings Outstanding	$	45.3	$	76.6	$	38.3
Letters of Credit Outstanding	$	0.0	$	1.1	$	0.0

Available	$	74.7	$	42.3	$	81.7

- Definition

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

+ References

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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

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

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=64930739&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=64930785&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21521-112644

+ Details

COMMON STOCK AND PREFERRED STOCK (Tables)

3 Months Ended

Mar. 31, 2018

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during the three months ended March 31, 2018 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, 2017		52,224	$	36.22
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		453	$	42.04
Restricted Stock Units Settled		—		—

Restricted Stock Units as of March 31, 2018		52,677	$	36.27

ENVIRONMENTAL MATTERS (Tables)

3 Months Ended

Mar. 31, 2018

Environmental Obligations Recognized by Company

The following table sets forth a summary of changes in the Company’s liability for Environmental Obligations for the three months ended March 31, 2018 and 2017.


Environmental Obligations
	($ millions)
	Fitchburg				Northern Utilities				Total
	Three months ended March 31,
	2018		2017		2018		2017		2018		2017
Total Balance at Beginning of Period	$	0.1	$	0.1	$	2.0	$	1.9	$	2.1	$	2.0
Additions		0.1		—		0.1		0.4		0.2		0.4
Less: Payments / Reductions		0.1		—		0.1		0.1		0.2		0.1

Total Balance at End of Period		0.1		0.1		2.0		2.2		2.1		2.3

Less: Current Portion		0.1		0.1		0.5		0.4		0.6		0.5

Noncurrent Balance at End of Period	$	—	$	—	$	1.5	$	1.8	$	1.5	$	1.8

RETIREMENT BENEFIT OBLIGATIONS (Tables)

3 Months Ended

Mar. 31, 2018

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:


	2018			2017
Used to Determine Plan Costs
Discount Rate		3.60	%		4.10	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		7.75	%		7.75	%
Health Care Cost Trend Rate Assumed for Next Year		7.50	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.50	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2024			2025

Components of Retirement Plan Costs

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended March 31,	2018			2017			2018			2017			2018			2017
Service Cost	$	848		$	824		$	733		$	744		$	122		$	115
Interest Cost		1,469			1,514			851			978			101			98
Expected Return on Plan Assets		(1,946	)		(1,819	)		(409	)		(337	)		—			—
Prior Service Cost Amortization		81			66			327			350			47			47
Actuarial Loss Amortization		1,447			1,176			346			524			122			74

Sub-total		1,899			1,761			1,848			2,259			392			334
Amounts Capitalized and Deferred		(720	)		(662	)		(742	)		(1,037	)		(113	)		(99	)

Net Periodic Benefit Cost Recognized	$	1,179		$	1,099		$	1,106		$	1,222		$	279		$	235

Summary of Significant Accounting Policies - Additional Information (Detail) Bcf in Billions	3 Months Ended
	Mar. 31, 2018 USD ($) Subsidiary mi Bcf	Mar. 31, 2017 USD ($) Bcf	Dec. 31, 2017 USD ($) Bcf
Significant Accounting Policies [Line Items]
Length Of Pipeline \| mi	86
Revenue sharing payments	$ 300,000	$ 300,000
Other	1,300,000	1,700,000
Operation and Maintenance Expense	17,300,000	16,000,000
Cost of removal obligation	86,600,000	79,700,000	$ 84,300,000
Regulatory Assets	$ 145,800,000	$ 135,500,000	$ 149,100,000
Number of Natural Gas Storage Outstanding \| Bcf	0.0	1.2	0.6
Investments in trading securities	$ 5,100,000	$ 3,300,000	$ 3,600,000
ASU 2014-09
Significant Accounting Policies [Line Items]
Revenue sharing payments		300,000
Operation and Maintenance Expense		15,700,000
Non Service
Significant Accounting Policies [Line Items]
Non-service cost net periodic benefit costs	1,500,000	1,600,000
Not Designated as Hedging Instruments
Significant Accounting Policies [Line Items]
Derivative Assets, not designated as hedging instruments	$ 0	300,000	100,000
Annual Electric Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM	27.00%
Annual Natural Gas Sales Volume
Significant Accounting Policies [Line Items]
Percentage of total sales volumes revenue subject to RDM	11.00%
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period	3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	$ 3,300,000	2,600,000	2,900,000
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits	0	0	0
Restatement Adjustment [Member] \| ASU 2014-09
Significant Accounting Policies [Line Items]
Other		(300,000)
Operation and Maintenance Expense		(300,000)
Deferred Storm Charges
Significant Accounting Policies [Line Items]
Regulatory Assets	8,000,000	$ 8,600,000	$ 7,200,000
Deferred Storm Charges \| Recovered over Next Year
Significant Accounting Policies [Line Items]
Regulatory Assets	500,000
Environmental and Rate Case Costs and Other Expenditures \| Recovered over the next seven years
Significant Accounting Policies [Line Items]
Regulatory Assets	$ 6,500,000
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary	3
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries \| Subsidiary	3

Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 144.5	$ 124.3
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	153.0	127.8
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(8.5)	(3.5)
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	87.0	74.8
Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	91.4	78.8
Gas Segment \| Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(4.4)	(4.0)
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	57.5	49.5
Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	61.6	49.0
Electric \| Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(4.1)	0.5
Residential \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	70.2	58.2
Residential \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	35.8	30.9
Residential \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	34.4	27.3
C&I \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	74.7	61.8
C&I \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	50.6	42.3
C&I \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	24.1	19.5
Other \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	10.4	7.8
Other \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	6.5	5.6
Other \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	3.9	$ 2.2
Revenue Reduction - TCJA \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(2.3)
Revenue Reduction - TCJA \| Gas Segment \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(1.5)
Revenue Reduction - TCJA \| Electric \| Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ (0.8)

Schedule of Other Operating Revenues and Operating Expenses (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Component of Operating Other Cost and Expense [Abstract]
Usource Contract Revenue	$ 1.6
Less: Revenue Sharing Payments	0.3	$ 0.3
Total Other Operating Revenues	1.3
Operation and Maintenance Expense	$ 17.3	16.0
ASU 2014-09
Component of Operating Other Cost and Expense [Abstract]
Usource Contract Revenue		1.7
Less: Revenue Sharing Payments		0.3
Total Other Operating Revenues		1.4
Operation and Maintenance Expense		$ 15.7

Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 1.6	$ 1.6	$ 1.0

Components of Accrued Revenue (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 45.1	$ 53.3	$ 41.3
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	10.5	13.8	9.3
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 34.6	$ 39.5	$ 32.0

Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.2	$ 5.8	$ 2.1
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable		5.4	1.9
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.2	$ 0.4	$ 0.2

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.4	$ 0.6	$ 0.3
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		0.4
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.3	$ 0.1	$ 0.2

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

Mar. 31, 2018

Dec. 31, 2017

Mar. 31, 2017

Regulatory Assets [Line Items]

Regulatory Assets

$ 145.8

$ 149.1

$ 135.5

Less: Current Portion of Regulatory Assets

^[1]

34.6

39.5

32.0

Regulatory Assets - noncurrent

111.2

109.6

103.5

Environmental Matters

Regulatory Assets [Line Items]

Regulatory Assets

9.0

9.5

10.7

Other Assets

Regulatory Assets [Line Items]

Regulatory Assets

5.2

5.4

5.5

Retirement Benefits

Regulatory Assets [Line Items]

Regulatory Assets

85.4

84.5

75.7

Deferred Storm Charges

Regulatory Assets [Line Items]

Regulatory Assets

8.0

7.2

8.6

Income Taxes

Regulatory Assets [Line Items]

Regulatory Assets

6.3

6.5

7.3

Energy Supply & Other Rate Adjustment Mechanisms

Regulatory Assets [Line Items]

Regulatory Assets

$ 31.9

$ 36.0

$ 27.7

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

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 60.0	$ 58.1	$ 13.5
Less: Current Portion of Regulatory Liabilities	10.9	9.2	12.8
Regulatory Liabilities-noncurrent	49.1	48.9	0.7
Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	10.3	6.9	9.2
Gas Pipeline Refund
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0.6	2.3	$ 4.3
Income Tax Related Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 49.1	$ 48.9

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 5.1	$ 3.6	$ 3.3
Fair Value, Inputs, Level 1
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	5.1	3.6	3.3
Fair Value, Inputs, Level 1 \| Equity Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	1.9	2.1	1.1
Fair Value, Inputs, Level 1 \| Fixed Income Funds
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	1.6	$ 1.5	0.9
Fair Value, Inputs, Level 1 \| Cash Equivalents
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Trading Securities	$ 1.6		$ 1.3

Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 7.8	$ 9.7	$ 9.0
Power Supply Contract Divestitures, Noncurrent	0.8	0.9	1.2
Total Energy Supply Obligations	8.6	10.6	10.2
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current		5.4	1.9
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	7.5	4.0	6.8
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 0.3	$ 0.3	$ 0.3

Dividends Declared Per Share (Detail) - $ / shares	3 Months Ended
Dividends Declared Per Share (Detail) - $ / shares	Mar. 31, 2018	Mar. 31, 2017
Dividends Payable [Line Items]
Dividend Amount	$ 0.365	$ 0.360
Group One
Dividends Payable [Line Items]
Declaration Date	Apr. 25, 2018
Date Paid (Payable)	May 29, 2018
Shareholder of Record Date	May 15, 2018
Dividend Amount	$ 0.365
Group Two
Dividends Payable [Line Items]
Declaration Date	Jan. 30, 2018
Date Paid (Payable)	Feb. 28, 2018
Shareholder of Record Date	Feb. 14, 2018
Dividend Amount	$ 0.365
Group Three
Dividends Payable [Line Items]
Declaration Date	Oct. 25, 2017
Date Paid (Payable)	Nov. 29, 2017
Shareholder of Record Date	Nov. 15, 2017
Dividend Amount	$ 0.360
Group Four
Dividends Payable [Line Items]
Declaration Date	Jul. 26, 2017
Date Paid (Payable)	Aug. 29, 2017
Shareholder of Record Date	Aug. 15, 2017
Dividend Amount	$ 0.360
Group Five
Dividends Payable [Line Items]
Declaration Date	Apr. 26, 2017
Date Paid (Payable)	May 30, 2017
Shareholder of Record Date	May 16, 2017
Dividend Amount	$ 0.360
Group Six
Dividends Payable [Line Items]
Declaration Date	Jan. 25, 2017
Date Paid (Payable)	Feb. 28, 2017
Shareholder of Record Date	Feb. 14, 2017
Dividend Amount	$ 0.360

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue - Non-Regulated	$ 1.3
Revenues	145.8	$ 126.0
Segment Profit	15.6	12.4
Identifiable Segment Assets	1,244.3	1,134.4	$ 1,241.9
Capital Expenditures	10.1	17.5
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	153.0
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	(8.5)
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	87.0	74.8
Segment Profit	12.6	9.9
Identifiable Segment Assets	712.6	641.8	714.3
Capital Expenditures	3.6	5.7
Gas Segment \| Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	91.4
Gas Segment \| Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	(4.4)
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	57.5	49.5
Segment Profit	3.0	2.1
Identifiable Segment Assets	481.8	442.8	476.9
Capital Expenditures	6.0	8.3
Electric \| Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	61.6
Electric \| Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	(4.1)
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit	(0.4)
Identifiable Segment Assets	42.8	42.8	44.0
Capital Expenditures	0.5	3.5
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue - Non-Regulated	1.3
Revenues	1.3	1.7
Segment Profit	0.4	0.4
Identifiable Segment Assets	$ 7.1	$ 7.0	$ 6.7

Details on Long Term Debt (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Total Long-Term Debt	$ 396.0	$ 409.4	$ 336.4
Less: Unamortized Debt Issuance Costs	3.2	3.3	2.9
Long-Term Debt	392.8	406.1	333.5
Less: Current Portion	29.8	29.8	30.0
Total Long-term Debt, Less Current Portion	363.0	376.3	303.5
Long-Term Debt	392.8	406.1	333.5
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Total Long-Term Debt	20.0	20.0	20.0
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0	30.0
Unitil Energy Systems Inc \| First Mortgage Bonds 5.24% Senior Secured Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt	10.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Total Long-Term Debt	7.5	7.5	9.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Total Long-Term Debt	20.0	20.0	20.0
Unitil Energy Systems Inc \| First Mortgage Bonds 8.00% Senior Secured Notes, Due May 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc \| First Mortgage Bonds 6.32% Senior Secured Notes, Due September 15, 2036
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company \| 6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Total Long-Term Debt	7.6	7.6	9.5
Fitchburg Gas and Electric Light Company \| 6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Total Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company \| 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	10.0	10.0
Fitchburg Gas and Electric Light Company \| 7.37% Senior Notes, Due January 15, 2029
Debt Instrument [Line Items]
Total Long-Term Debt	12.0	12.0	12.0
Fitchburg Gas and Electric Light Company \| 5.90% Senior Notes, Due December 15, 2030
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company \| 7.98% Senior Notes, Due June 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt	14.0	14.0	14.0
Fitchburg Gas and Electric Light Company \| 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt	15.0	15.0
Northern Utilities Inc \| 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	20.0	20.0
Northern Utilities Inc \| 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt	30.0	30.0
Northern Utilities Inc \| 6.95% Senior Notes, Due December 3, 2018
Debt Instrument [Line Items]
Total Long-Term Debt	10.0	10.0	20.0
Northern Utilities Inc \| 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt	16.6	25.0	25.0
Northern Utilities Inc \| 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0	50.0
Northern Utilities Inc \| 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt	50.0	50.0	50.0
Granite State Gas Transmission Inc \| 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Total Long-Term Debt	3.3	3.3	6.7
Granite State Gas Transmission Inc \| 3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt	$ 15.0	$ 15.0
Unitil Realty Corp \| 8.00% Senior Secured Notes, Due August 1, 2017
Debt Instrument [Line Items]
Total Long-Term Debt			$ 0.2

Details on Long Term Debt (Parenthetical) (Detail)		3 Months Ended		12 Months Ended
Details on Long Term Debt (Parenthetical) (Detail)	Nov. 01, 2017	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate		6.33%	6.33%	6.33%
Debt instrument due date		May 01, 2022	May 01, 2022	May 01, 2022
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate		3.70%	3.70%	3.70%
Debt instrument due date		Aug. 01, 2026	Aug. 01, 2026	Aug. 01, 2026
First Mortgage Bonds 5.24% Senior Secured Notes, 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. 02, 2020	Mar. 02, 2020	Mar. 02, 2020
First Mortgage Bonds 8.49% Senior Secured Notes, 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% Senior Secured Notes, 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. 01, 2028	Sep. 01, 2028	Sep. 01, 2028
First Mortgage Bonds 8.00% Senior Secured Notes, 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 01, 2031	May 01, 2031	May 01, 2031
First Mortgage Bonds 6.32% Senior Secured Notes, 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% Senior 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
6.79% Senior 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
3.52% Senior Notes, Due November 1, 2027 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	3.52%	3.52%	3.52%	3.52%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
3.52% Senior Notes, Due November 1, 2027 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	3.52%	3.52%	3.52%	3.52%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
7.37% Senior 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
5.90% Senior 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
7.98% Senior 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. 01, 2031	Jun. 01, 2031	Jun. 01, 2031
4.32% Senior Notes, Due November 1, 2047 \| Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate	4.32%	4.32%	4.32%	4.32%
Debt instrument due date	Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
4.32% Senior Notes, Due November 1, 2047 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.32%	4.32%	4.32%	4.32%
Debt instrument due date	Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
6.95% Senior Notes, 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. 03, 2018	Dec. 03, 2018	Dec. 03, 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. 02, 2020	Mar. 02, 2020	Mar. 02, 2020
7.72% Senior Notes, 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. 03, 2038	Dec. 03, 2038	Dec. 03, 2038
4.42% Senior Notes, Due October 15, 2044 \| Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		4.42%	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
3.72% Senior Notes, Due November 1, 2027 \| Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate	3.72%	3.72%	3.72%	3.72%
Debt instrument due date	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
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. 01, 2017	Aug. 01, 2017	Aug. 01, 2017

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 428.0	$ 457.1	$ 374.3

Debt and Financing Arrangements - Additional Information (Detail) - USD ($)			3 Months Ended		12 Months Ended
	Nov. 01, 2017	Oct. 04, 2013	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Oct. 30, 2015
Line of Credit Facility [Line Items]
Weighted average interest rate on short term borrowings			2.90%	2.10%	2.40%
Issuance of long-term debt	$ 700,000
Capital lease obligation, current			$ 3,100,000	$ 3,000,000	$ 3,100,000
Capital lease obligation, noncurrent			4,900,000	7,500,000	5,700,000
Accounts Payable			30,100,000	28,100,000	41,500,000
Guarantee outstanding			$ 17,900,000
Unitil Service Corp.
Line of Credit Facility [Line Items]
Capital lease obligation, total capitalized cost						$ 13,400,000
Capital lease obligation, maturity period			Sep. 30, 2020
Capital lease obligation, current			$ 2,700,000
Capital lease obligation, noncurrent			4,400,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Natural gas storage inventory			1,000,000	3,800,000	8,500,000
Accounts Payable			1,000,000	2,000,000	3,100,000
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			$ 88,900,000
Repayments of lines of credit				$ 81,900,000
Credit Facility \| Revolving Credit Facility
Line of Credit Facility [Line Items]
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
Revolving credit facility termination date		Oct. 04, 2020
Percentage of capitalization			The affirmative and negative covenants under the Credit Facility shall apply 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 Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At March 31, 2018, March 31, 2017 and December 31, 2017, 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 (LIBOR)
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest		1.25%
7.15% Senior Notes, Due December 15, 2018 \| Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, maturity date			Dec. 15, 2018	Dec. 15, 2018	Dec. 15, 2018
Long-term debt, stated interest rate			7.15%	7.15%	7.15%
Senior Notes			$ 3,300,000
3.52% Senior Notes, Due November 1, 2027 \| Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 20,000,000
Long-term debt, maturity date	Nov. 01, 2027		Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
Long-term debt, stated interest rate	3.52%		3.52%	3.52%	3.52%
3.52% Senior Notes, Due November 1, 2027 \| Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 10,000,000
Long-term debt, maturity date	Nov. 01, 2027		Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
Long-term debt, stated interest rate	3.52%		3.52%	3.52%	3.52%
4.32% Senior Notes, Due November 1, 2047 \| Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 30,000,000
Long-term debt, maturity date	Nov. 01, 2047		Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
Long-term debt, stated interest rate	4.32%		4.32%	4.32%	4.32%
4.32% Senior Notes, Due November 1, 2047 \| Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 15,000,000
Long-term debt, maturity date	Nov. 01, 2047		Nov. 01, 2047	Nov. 01, 2047	Nov. 01, 2047
Long-term debt, stated interest rate	4.32%		4.32%	4.32%	4.32%
3.72% Senior Notes, Due November 1, 2027 \| Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 15,000,000
Long-term debt, maturity date	Nov. 01, 2027		Nov. 01, 2027	Nov. 01, 2027	Nov. 01, 2027
Long-term debt, stated interest rate	3.72%		3.72%	3.72%	3.72%

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 45,300,000	$ 38,300,000	$ 76,600,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120,000,000	120,000,000	120,000,000
Short-Term Borrowings Outstanding	45,300,000	38,300,000	76,600,000
Letters of Credit Outstanding	0	0	1,100,000
Available revolving credit facility	$ 74,700,000	$ 81,700,000	$ 42,300,000

Common Stock And Preferred Stock - Additional Information (Detail) - USD ($)			3 Months Ended		12 Months Ended
	Jan. 29, 2018	Dec. 14, 2017	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Class of Stock [Line Items]
Common stock, shares outstanding			14,860,123	14,107,741	14,815,585
Common stock, shares issued			7,812	7,581
Proceeds from Issuance of Common Stock			$ 300,000	$ 300,000
Share based compensation expense			$ 1,800,000	1,700,000
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			$ 1,000,000	800,000	$ 1,000,000
Preferred Stock			200,000	200,000	$ 200,000
Maximum
Class of Stock [Line Items]
Dividend declared			100,000	$ 100,000
Registered Public Offering
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock		$ 31,700,000
Registered Public Offering \| Common Stock
Class of Stock [Line Items]
Common stock, shares issued		690,000
Common stock price per share		$ 48.30
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Proceeds from Issuance of Common Stock			$ 341,500
Dividend and Distribution Reinvestment and Share Purchase Plan \| Average
Class of Stock [Line Items]
Common stock price per share			$ 43.71
Dividend and Distribution Reinvestment and Share Purchase Plan \| Common Stock
Class of Stock [Line Items]
Common stock, shares issued			7,812
Unitil Energy Systems Inc \| Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			1,893	1,893	1,893
Preferred Stock			$ 200,000	$ 200,000	$ 200,000
Dividend rate			6.00%	6.00%	6.00%
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period			4 years
Restricted stock non-vested			90,882	94,880
Restricted stock weighted average grant date fair value			$ 41.93	$ 39.55
Unrecognized share based compensation			$ 1,300,000
Share compensation recognition period			2 years 9 months 18 days
Restricted Stock Units Granted	37,510
Aggregate Market Value	$ 1,600,000
Forfeitures under the stock plan			784
Cancellations under the stock plan			0
Restricted Stock \| Maximum
Class of Stock [Line Items]
Restricted stock available for awards			677,500
Restricted stock that may be awarded in any one calendar year to any one participant			20,000
Restricted Stock \| Vesting Annually
Class of Stock [Line Items]
Restricted stock vesting percentage annually			25.00%
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Restricted Stock Units Granted			0
Restricted stock units outstanding				43,696
Weighted-Average Stock Price				$ 33.49

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs)	3 Months Ended
	Mar. 31, 2018 $ / shares shares
Restricted Stock Units
Beginning Restricted Stock Units \| shares	52,224
Restricted Stock Units Granted \| shares	0
Dividend Equivalents Earned \| shares	453
Restricted Stock Units Settled \| shares	0
Ending Restricted Stock Units \| shares	52,677
Weighted-Average Stock Price
Beginning Restricted Stock Units \| $ / shares	$ 36.22
Restricted Stock Units Granted \| $ / shares	0
Dividend Equivalents Earned \| $ / shares	42.04
Restricted Stock Units Settled \| $ / shares	0
Ending Restricted Stock Units \| $ / shares	$ 36.27

Regulatory Matters - Additional Information (Detail)																	1 Months Ended	3 Months Ended
Regulatory Matters - Additional Information (Detail)	May 01, 2019 USD ($)	May 01, 2018 USD ($)	Apr. 06, 2018 USD ($)	Mar. 16, 2018 USD ($)	Feb. 28, 2018 USD ($)	Dec. 20, 2017 USD ($)	Oct. 31, 2017	Aug. 25, 2017 MW	Jul. 31, 2017 USD ($)	Jun. 21, 2017 USD ($)	Jun. 05, 2017 USD ($)	Apr. 28, 2017	Apr. 20, 2017 USD ($)	Oct. 31, 2016 USD ($)	Apr. 29, 2016 USD ($)	Apr. 15, 2015 USD ($)	May 31, 2017 USD ($)	Mar. 31, 2018 USD ($) State Customer	Jun. 30, 2027 MW	Dec. 31, 2022 MWh	Jun. 01, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jun. 30, 2017 MW	Jun. 23, 2017 kW	Mar. 31, 2017 USD ($)	Aug. 19, 2016 MW
Regulatory Assets [Line Items]
Corporate income tax rate																		21.00%
Current Portion of Regulatory Liabilities																		$ 10,900,000				$ 9,200,000			$ 12,800,000
Power capacity facility for small customers \| kW																								100
Northern Utilities Inc
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue									$ 1,600,000								$ 6,000,000	$ 700,000
Amendment effective date									Aug. 01, 2017
TIRA initial term																		Four years
Deferred cost																		$ 1,100,000
Pipeline refund received																$ 22,000,000		21,400,000
Current Portion of Regulatory Liabilities																		600,000
Northern Utilities Inc \| Subsequent Event
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue			$ 2,600,000
Northern Utilities Inc \| Revenue Offset [Member] \| Subsequent Event
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue			$ (1,700,000)
Northern Utilities Inc \| Scenario Forecast
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue		$ 0.9
Annual revenue adjustment	$ 2,200,000	$ 2,300,000
Northern Utilities Inc \| Maine
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue					$ 2,100,000													$ (100,000)
Percentage of approved return on equity					9.50%
Percentage of approved return on equity, reflecting on equity					50.00%
Percentage of approved return on equity, reflecting on debt					50.00%
Reduction of annual operating costs					$ (500,000)
TIRA extended term																		8 years
Construction completion period																		3 years
Number of new customers \| Customer																		1,000
Potential regulated operating revenue																		$ 1,000,000
Grace period to receive refund																		3 years
Northern Utilities Inc \| Maine \| Second TAB program
Regulatory Assets [Line Items]
Number of new customers \| Customer																		2,000
Potential regulated operating revenue																		$ 2,000,000
Northern Utilities Inc \| Maine \| Revenue Offset [Member]
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue					$ (2,200,000)
Northern Utilities Inc \| New Hampshire
Regulatory Assets [Line Items]
Grace period to receive refund																		3 years
Northern Utilities Inc \| New Hampshire \| Natural Gas Distribution
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue											$ 4,700,000
Granite State Gas Transmission Inc \| Gas Transportation and Storage
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue										$ 200,000
Amendment effective date										Aug. 01, 2017								Jul. 28, 2017
Unitil Energy Systems Inc \| New Hampshire
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue				$ 400,000
Permanent rate increase													$ 4,100,000
Unitil Energy Systems Inc \| New Hampshire \| First Rate Step Adjustments
Regulatory Assets [Line Items]
Permanent rate increase													$ 900,000
Fitchburg Gas and Electric Light Company
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue														$ 500,000				$ (800,000)
Recovery amount														$ 900,000
Percentage of waiver approved on annual changes in the revenue requirement eligible for recovery												1.50%
Amendment effective date														May 01, 2017
Revenues sought approval to collect, deferred for recovery in future periods														$ 400,000
Percentage of waiver sought on annual changes in the revenue requirement eligible for recovery							3.00%					1.50%
Number of states with electric distribution companies \| State																		3
Fitchburg Gas and Electric Light Company \| Solar Generation
Regulatory Assets [Line Items]
Power generation facility \| MW																										1.3
Fitchburg Gas and Electric Light Company \| Minimum \| Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility \| MW																							400
Fitchburg Gas and Electric Light Company \| Solar Massachusetts Renewable Target Program \| Solar Generation
Regulatory Assets [Line Items]
Power generation capacity \| MW								1,600
Fitchburg Gas and Electric Light Company \| Scenario Forecast
Regulatory Assets [Line Items]
Power generation capacity \| MWh																				9,450,000
Fitchburg Gas and Electric Light Company \| Scenario Forecast \| Solar Generation
Regulatory Assets [Line Items]
Recovery amount																					$ 300,000
Fitchburg Gas and Electric Light Company \| Scenario Forecast \| Offshore Wind Energy
Regulatory Assets [Line Items]
Power generation facility \| MW																			1,600
Fitchburg Gas and Electric Light Company \| Electric base
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue															$ 2,100,000
Amendment effective date						Jan. 01, 2018									May 01, 2016			Jan. 01, 2017
Annual revenue adjustment						$ 400,000												$ 500,000
Fitchburg Gas and Electric Light Company \| Gas base
Regulatory Assets [Line Items]
Increase (decrease) in annual revenue															$ 1,600,000
Amendment effective date															May 01, 2016

Environmental Matters - Additional Information (Detail) - Environmental Restoration Costs	3 Months Ended
	Mar. 31, 2018
Maine
Site Contingency [Line Items]
Amortization period for environmental costs	5 years
New Hampshire
Site Contingency [Line Items]
Amortization period for environmental costs	7 years

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2.1	$ 2.0
Additions	0.2	0.4
Less: Payments / Reductions	0.2	0.1
Total Balance at End of Period	2.1	2.3
Less: Current Portion			$ 0.6	$ 0.5	$ 0.5
Noncurrent Balance			1.5	1.6	1.8
Total Balance at End of period	2.1	2.3	2.1	2.1	2.3
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	0.1	0.1
Additions	0.1
Less: Payments / Reductions	0.1
Total Balance at End of Period	0.1	0.1
Less: Current Portion			0.1		0.1
Total Balance at End of period	0.1	0.1	0.1	0.1	0.1
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	2.0	1.9
Additions	0.1	0.4
Less: Payments / Reductions	0.1	0.1
Total Balance at End of Period	2.0	2.2
Less: Current Portion			0.5		0.4
Noncurrent Balance			1.5		1.8
Total Balance at End of period	$ 2.0	$ 2.2	$ 2.0	$ 2.0	$ 2.2

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 31, 2017
Income Taxes [Line Items]
Corporate federal income tax		21.00%
Regulatory Liability	$ 58.1	$ 60.0	$ 58.1		$ 13.5
Regulatory liability, expected flow back to customers		$ 47.1
Regulatory liability, expected pass back to ratepayers			1.8
Tax benefit for New Hampshire business enterprise tax credits				$ 0.7
Deferred tax assets, operating loss carryforwards, federal	1.1		1.1
Net Operating Loss Carryforwards	12.7		$ 12.7
NOL carryforward assets expiration date			2029
Alternative minimum tax credit carryforwards	3.5		$ 3.5
Minimum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period		15 years
Maximum
Income Taxes [Line Items]
Average Rate Assumption Method estimated flow back period		20 years
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 48.9	$ 49.1	48.9
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax	21.00%
Deferred tax assets, operating loss carryforwards, federal	$ 10.1		$ 10.1
Federal, Maine, Massachusetts, and New Hampshire Tax Authorities
Income Taxes [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, 2014; December 31, 2015; and December 31, 2016

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) - Benefit Plan Costs	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.60%	4.10%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.75%	7.75%
Health Care Cost Trend Rate Assumed for Next Year	7.50%	8.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2024	2025

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 848	$ 824
Interest Cost	1,469	1,514
Expected Return on Plan Assets	(1,946)	(1,819)
Prior Service Cost Amortization	81	66
Actuarial Loss Amortization	1,447	1,176
Sub-total	1,899	1,761
Amounts Capitalized and Deferred	(720)	(662)
Net Periodic Benefit Cost Recognized	1,179	1,099
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	733	744
Interest Cost	851	978
Expected Return on Plan Assets	(409)	(337)
Prior Service Cost Amortization	327	350
Actuarial Loss Amortization	346	524
Sub-total	1,848	2,259
Amounts Capitalized and Deferred	(742)	(1,037)
Net Periodic Benefit Cost Recognized	1,106	1,222
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	122	115
Interest Cost	101	98
Prior Service Cost Amortization	47	47
Actuarial Loss Amortization	122	74
Sub-total	392	334
Amounts Capitalized and Deferred	(113)	(99)
Net Periodic Benefit Cost Recognized	$ 279	$ 235

Retirement Benefit Obligations - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018 USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	$ 1,200,000
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	1,000,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Benefit payments under SERP Plan	356,300
Expected additional benefit payments under SERP Plan in 2016	$ 43,900