Unitil (UTL) 10-K 30 Jan 20 2019 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2019	Jan. 27, 2020	Jun. 30, 2019
Document Information [Line Items]
Entity Interactive Data Current	Yes
Document Type	10-K
Document Transition Report	false
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Entity File Number	1-8858
Entity Tax Identification Number	02-0381573
Entity Incorporation, State or Country Code	NH
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Address, Address Line One	6 Liberty Lane West
Entity Address, City or Town	Hampton
Entity Address, Postal Zip Code	03842-1720
Entity Address, State or Province	NH
City Area Code	603
Local Phone Number	772-0775
Trading Symbol	UTL
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		14,930,967
Title of 12(b) Security	Common Stock
Document Annual Report	true
Entity Public Float			$ 880,678,701
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenues
Total Operating Revenues	$ 438.2	$ 444.1	$ 406.2
Operating Expenses
Operation and Maintenance	67.2	69.5	64.5
Depreciation and Amortization	52	50.4	46.9
Taxes Other Than Income Taxes	22.7	22.4	21.1
Total Operating Expenses	365.1	372.9	330.8
Operating Income	73.1	71.2	75.4
Interest Expense, Net	23.7	24	23.1
Other (Income) Expense, Net	(8.6)	5.8	5.8
Income Before Income Taxes	58	41.4	46.5
Provision for Income Taxes	13.8	8.4	17.5
Net Income Applicable to Common Shares	$ 44.2	$ 33	$ 29
Earnings per Common Share—Basic and Diluted	$ 2.97	$ 2.23	$ 2.06
Weighted Average Common Shares Outstanding—(Basic and Diluted)	14.9	14.8	14.1
Gas
Operating Revenues
Total Operating Revenues	$ 203.4	$ 216.1	$ 194
Operating Expenses
Total Operating Expenses	81.2	99.2	84.3
Electric
Operating Revenues
Total Operating Revenues	233.9	223.3	206.2
Operating Expenses
Total Operating Expenses	142	131.4	114
Other
Operating Revenues
Total Operating Revenues	$ 0.9	$ 4.7	$ 6

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and Cash Equivalents		$ 5.2	$ 7.8
Accounts Receivable, Net		55.1	66.8
Accrued Revenue		50	54.7
Exchange Gas Receivable		6.1	8.1
Gas Inventory		0.8	0.8
Materials and Supplies		7.9	7
Prepayments and Other		5.8	7
Total Current Assets		130.9	152.2
Utility Plant:
Gas		837.7	760.6
Electric		529.7	500.1
Common		62.7	83.1
Construction Work in Progress		37.4	25.5
Utility Plant		1,467.5	1,369.3
Less: Accumulated Depreciation		356	332.5
Net Utility Plant		1,111.5	1,036.8
Other Noncurrent Assets:
Regulatory Assets		112	99
Operating Lease Right of Use Assets		4
Other Assets		12.4	10.3
Total Other Noncurrent Assets		128.4	109.3
TOTAL ASSETS		1,370.8	1,298.3
Current Liabilities:
Accounts Payable		37.6	42.6
Short-Term Debt		58.6	82.8
Long-Term Debt, Current Portion	[1]	19.5	18.4
Regulatory Liabilities		7.4	11.5
Energy Supply Obligations		10.5	13.4
Environmental Obligations		0.6	0.6
Other Current Liabilities		25.6	23.2
Total Current Liabilities		159.8	192.5
Noncurrent Liabilities:
Retirement Benefit Obligations		141.9	121.5
Deferred Income Taxes, Net		103.6	97.8
Cost of Removal Obligations		96	90.7
Regulatory Liabilities		46.6	47
Environmental Obligations		2.1	1.4
Other Noncurrent Liabilities		6.5	8.7
Total Noncurrent Liabilities		396.7	367.1
Capitalization:
Long-Term Debt, Less Current Portion		437.5	387.4
Stockholders' Equity:
Common Equity (Outstanding 14,930,170 and 14,876,955 Shares)		282.5	279.1
Retained Earnings		94.1	72
Total Common Stock Equity		376.6	351.1
Preferred Stock		0.2	0.2
Total Stockholders' Equity		376.8	351.3
Total Capitalization		814.3	738.7
Commitments and Contingencies (Note 8)
TOTAL LIABILITIES AND CAPITALIZATION		$ 1,370.8	$ 1,298.3
[1]	The Current Portion of Long-Term Debt includes sinking fund payments.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Common Equity Outstanding	14,930,170	14,876,955

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Activities:
Net Income	$ 44.2	$ 33	$ 29
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	52	50.4	46.9
Deferred Tax Provision	13.5	8	17.5
Gain on Divestiture, net (See Note 1)	(13.4)
Changes in Working Capital Items:
Accounts Receivable	11.7	0.6	(14.5)
Accrued Revenue	4.7	(1.4)	(3.8)
Regulatory Liabilities	(4.1)	2.3	(1.2)
Exchange Gas Receivable	2	(2.3)	2.5
Accounts Payable	(5)	1.1	9.1
Other Changes in Working Capital Items	4.6	3.6	(1.8)
Deferred Regulatory and Other Charges	(5.3)	(11.3)	(6.1)
Other, net		(5.5)	8.6
Cash Provided by Operating Activities	104.9	78.5	86.2
Investing Activities:
Property, Plant and Equipment Additions	(119.2)	(102.4)	(119.3)
Proceeds from Divestiture, Net (See Note 1)	13.4
Cash Used In Investing Activities	(105.8)	(102.4)	(119.3)
Financing Activities:
(Repayment of) Proceeds from Short-Term Debt, net	(24.2)	44.5	(43.6)
Issuance of Long-Term Debt	69.6	29.9	89.3
Repayment of Long-Term Debt	(18.8)	(30.1)	(17.2)
Decrease in Capital Lease Obligations	(5.3)	(3)	(2.5)
Net (Decrease) Increase in Exchange Gas Financing	(2)	2.1	(2.4)
Dividends Paid	(22.1)	(21.8)	(20.4)
Proceeds from Issuance of Common Stock	1.1	1.2	33
Cash (Used In) Provided by Financing Activities	(1.7)	22.8	36.2
Net (Decrease) Increase in Cash and Cash Equivalents	(2.6)	(1.1)	3.1
Cash and Cash Equivalents at Beginning of Year	7.8	8.9	5.8
Cash and Cash Equivalents at End of Year	5.2	7.8	8.9
Supplemental Information:
Interest Paid	24.1	24.6	23
Income Taxes Paid	0.8	0.4
Payments on Capital Leases	5.5	3.3	3.3
Capital Expenditures Included in Accounts Payable	0.6	0.5	1.1
Non-Cash Additions to Property, Plant and Equipment
Right-of-Use Assets Obtained in Exchange for Lease Obligations	$ 4

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY - USD ($) $ in Millions	Total	Dividend and Distribution Reinvestment and Share Purchase Plan	Registered Public Offering	Common Equity	Common EquityDividend and Distribution Reinvestment and Share Purchase Plan	Common EquityRegistered Public Offering	Retained Earnings
Beginning Balance at Dec. 31, 2016	$ 292.9			$ 240.7			$ 52.2
Net Income	29						29
Dividends on Common Shares	(20.4)						(20.4)
Shares Issued Under Stock Plans	2.1			2.1
Issuance of Common Shares		$ 1.3	$ 31.7		$ 1.3	$ 31.7
Ending Balance at Dec. 31, 2017	336.6			275.8			60.8
Net Income	33						33
Dividends on Common Shares	(21.8)						(21.8)
Shares Issued Under Stock Plans	2.1			2.1
Issuance of Common Shares	1.2			1.2
Ending Balance at Dec. 31, 2018	351.1			279.1			72
Net Income	44.2						44.2
Dividends on Common Shares	(22.1)						(22.1)
Shares Issued Under Stock Plans	2.3			2.3
Issuance of Common Shares	1.1			1.1
Ending Balance at Dec. 31, 2019	$ 376.6			$ 282.5			$ 94.1

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Dividends per Common Share	$ 1.48	$ 1.46	$ 1.44
Common stock, shares issued	20,065	25,932
Dividend and Distribution Reinvestment and Share Purchase Plan
Common stock, shares issued			26,256
Registered Public Offering [Member]
Common stock, shares issued			690,000

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 1 : Summary of Significant Accounting Policies Nature of Operations non-regulated 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 capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”). Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1 , 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated energy Divestiture of Non-Regulated Business Subsidiary — non-regulated after-tax 9.8 pre-tax 13.4 3.6 Basis of Presentation Principles of Consolidation Use of Estimates ( GAAP Fair Value L L Level 1— Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2— Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly. Level 3— Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3 . There have been no changes in the valuation techniques used during the current period. Utility Revenue Recognition— 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, 2015-14, 2016-08, 2016-10 2017-13, 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 twelve months ended December 31, 2019. 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. The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in ASU 2014-09. 980-605-25-3, 2014-09 In the following tables, revenue is classified by the types of goods/services rendered and market/customer type. Twelve Months Ended Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 81.4 $ 121.5 $ 202.9 Commercial & Industrial 120.1 93.8 213.9 Other 10.6 7.8 18.4 Total Billed and Unbilled Revenue 212.1 223.1 435.2 Rate Adjustment Mechanism Revenue (8.7 ) 10.8 2.1 Total Gas and Electric Operating Revenues $ 203.4 $ 233.9 $ 437.3 Twelve Months Ended December 31, 2018 Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 81.4 $ 123.6 $ 205.0 Commercial & Industrial 119.7 96.4 216.1 Other 9.6 8.7 18.3 Total Billed and Unbilled Revenue 210.7 228.7 439.4 Rate Adjustment Mechanism Revenue 5.4 (5.4 ) — Total Gas and Electric Operating Revenues $ 216.1 $ 223.3 $ 439.4 Twelve Months Ended December 31, 2017 Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 71.2 $ 107.9 $ 179.1 Commercial & Industrial 102.8 87.7 190.5 Other 13.5 6.0 19.5 Total Billed and Unbilled Revenue 187.5 201.6 389.1 Rate Adjustment Mechanism Revenue 6.5 4.6 11.1 Total Gas and Electric Operating Revenues $ 194.0 $ 206.2 $ 400.2 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 the current portion of 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 Massachusetts Department of Public Utilities (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— non-regulated As discussed above, the Company adopted ASU 2014-09 2014-09 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements were 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, , 2018 and 2017 , respectively. If ASU 2014-09 , the result would have been corresponding reductions of $1.1 million in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below. Other Operating Revenues ($ millions): Twelve Months Ended December 31 As Reported If ASU 2014-09 Had Been in Effect 2019 2018 2017 Usource Contract Revenue $ 1.1 $ 5.7 $ 6.0 Less: Revenue Sharing Payments (0.2 ) (1.0 ) (1.1 ) Total Other Operating Revenues $ 0.9 $ 4.7 $ 4.9 Operation and Maintenance Expense ($ millions): Twelve Months Ended December 31 As Reported If ASU 2014-09 Had Been in Effect 2019 2018 2017 Operation and Maintenance Expense $ 67.2 $ 69.5 $ 63.4 Retirement Benefit Costs— to the Consolidated Financial Statements). In the first quarter of 2018 , the Company adopted ASU No. 2017-07, 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-K , 2019 , 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 ( Income , N , 2019 resulted in a reduction of “Operations and Maintenance” and an increase in “Other (Income) , N . There are $4.6 million, $5.5 million and $5.7 million of non-service (Income) Expense, N , 2019 , 2018 and 2017 , respectively, net of amounts deferred as regulatory assets for future recovery. Depreciation and Amortization depreciable property balances at the beginning and end of each year: 2019 – 3.41%, 2018 – 3.38% and 2017 – 3.45%. Stock-based Employee Compensation . Sales and Consumption Taxes , 2019 . Income Taxes— Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known. Dividends ended December 31 , 2019 the Company paid quarterly dividends of $0.37 per share, resulting in an annualized dividend rate of $1.48 per common share. For the years ended December 31 , 2018 and 2017 , the Company paid quarterly dividends of $0.365 and $0.36 per common share, respectively, resulting in annualized dividend rates of $1.46 and $1.44 per common share, respectively. At its January 2020 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.375 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.50 per share from $1.48 per share. Cash and Cash Equivalents (ISO-NE) ISO-NE. 2-1/2 , 2019 and 2018 , the Unitil subsidiaries had deposited $1.9 million and $3.5 million, respectively to satisfy their ISO-NE Allowance for Doubtful Accounts written-off shut-off. In June 2016, the FASB issued ASU 2016-13, Accrued Revenue— . Accrued Revenue (millions) December 31, 2019 2018 Regulatory Assets—Current $ 35.8 $ 41.3 Unbilled Revenues 14.2 13.4 Total Accrued Revenue $ 50.0 $ 54.7 Exchange Gas Receivable average cost . The following table shows the components of Exchange Gas Receivable as of December 31 , 201 9 and 2018 . Exchange Gas Receivable (millions) December 31, 201 9 201 8 Northern Utilities $ 5.5 $ 7.5 Fitchburg 0.6 0.6 Total Exchange Gas Receivable $ 6.1 $ 8.1 Gas Inventory Gas Inventory (millions) December 31, 201 9 201 8 Natural Gas $ 0.4 $ 0.3 Propane 0.3 0.4 Liquefied Natural Gas & Other 0.1 0.1 Total Gas Inventory $ 0.8 $ 0.8 The Company also has an inventory of Materials and Supplies in the amounts of $7.9 million and $7.0 million as of December 31, 2019 and December 31, 2018, respectively. These amounts are recorded at weighted average cost. Utility Plant 2019 , 2018 and 2017 , respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31 , 2019 and 2018 , the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $96.0 million and $90.7 million, respectively. Regulatory Accounting Regulatory Assets consist of the following (millions) December 31 , 2019 2018 Retirement Benefits $ 88.9 $ 72.0 Energy Supply & Other Rate Adjustment Mechanisms 31.0 38.4 Deferred Storm Charges 5.6 6.3 Environmental 7.2 7.9 Income Taxes 4.2 5.7 Other Deferred Charges 10.9 10.0 Total Regulatory Assets 147.8 140.3 Less: Current Portion of Regulatory Assets (1) 35.8 41.3 Regulatory Assets—noncurrent $ 112.0 $ 99.0 (1) Reflects amounts included in the Accrued Revenue on the Company’s Consolidated Balance Sheets. Regulatory Liabilities consist of the following (millions) December 31, 2019 2018 Rate Adjustment Mechanisms $ 6.0 $ 11.5 Income Taxes (Note 9) 47.6 47.0 Other 0.4 — Total Regulatory Liabilities 54.0 58.5 Less: Current Portion of Regulatory Liabilities 7.4 11.5 Regulatory Liabilities—noncurrent $ 46.6 $ 47.0 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 December 31, 2019 are $ 7.6 Leases— longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows the Company to carryforward the historical lease classification. The Company also elected the practical expedient related to land easements, allowing the Company to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The adoption of the standard resulted in recognition of approximately $ 4.2 Derivatives The Company previously operated a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service, which included use of derivative instruments. The hedging program was terminated in 2018 . Under the hedging program previously operated by Northern Utilities, any gains or losses resulting from the change in the fair value of these derivatives were passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause. The fair value of these derivatives was 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 recorded gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassified these gains or losses into Cost of Gas Sales when the gains and losses were passed through to customers through the Cost of Gas Clause. The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31 , 2019 and December 31 , 2018 . There were no , 2019 and 2018 . There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31 , 2019 and 2018 . As discussed below in the “Fitchburg Investments in Marketable Securities . At December 31, 2019 and 2018, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.6 million and $4.8 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 (Income) Expense, Net. Fair Value of Marketable Securities (millions) December 31, 2019 2018 Money Market Funds $ 5.6 $ 4.8 Total Marketable Securities $ 5.6 $ 4.8 The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the “DC Plan”). The DC Plan is a non-qualified tax-deferred , 2019 , is open to senior management or other highly compensated employees as determined by the Company’s Board of Directors, and may also be used for recruitment and retention purposes for newly hired senior executives. The DC Plan design mirrors the Company’s Tax Deferred Savings and Investment Plan formula, but provides for contributions on compensation above the IRS limit, which will allow participants to defer up to 85 % of base salary, and up to 85 % of any cash incentive for retirement. The Company may also elect to make discretionary contributions on behalf of any participant in an amount determined by the Company’s Board of Directors. A trust has been established to invest the funds associated with the DC Plan. At December 31 , 2019 and 2018 , the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $0.2 million and $0 , 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 (Income) Expense, Net. Fair Value of Marketable Securities (millions) December 31 , 2019 2018 Equity Funds $ 0.1 $ — Money Market Funds 0.1 — Total Marketable Securities $ 0.2 $ — Energy Supply Obligations December 31, Energy Supply Obligations consist of the following: (millions) 2019 2018 Current: Exchange Gas Obligation $ 5.5 $ 7.5 Renewable Energy Portfolio Standards 4.7 5.6 Power Supply Contract Divestitures 0.3 0.3 Total Energy Supply Obligations—Current 10.5 13.4 Noncurrent: Power Supply Contract Divestitures 0.3 0.6 Total Energy Supply Obligations $ 10.8 $ 14.0 Exchange Gas Obligation— Renewable Energy Portfolio Standards— 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 defer costs for RPS compliance which are recorded in the 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 the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were approved by the MDPU in the second quarter of 2019. Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018) . 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— stranded costs. As of December 31, 2019, Fitchburg has fully-recovered its power supply-related stranded costs and Unitil Energy $0.6 million remaining to recover. 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). Retirement Benefit Obligations —The Company sponsors the Pension Plan, which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union non-qualified The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10). Off-Balance Sheet Arrangements , 2019 , the Company does not have any significant arrangements that would be classified as Off-Balance Commitments and Contingencies , 2019 , the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8) . Environmental Matters , 2019 , there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8 , Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms. Recently Issued Pronouncements – 2019-12, In February 2016, the FASB issued ASU No. 2016-02, 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

Quarterly Financial Information

Quarterly Financial Information	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information	Note 2: Quarterly Financial Information (unaudited; millions, except per share data) Quarterly earnings per share may not agree with the annual amounts due to rounding and the impact of additional common share issuances. Basic and Diluted Earnings per Share are the same for the periods presented. As discussed above in “Divestiture of Non-Regulated Three Months Ended March 31, June 30, September 30, December 31, 2019 2018 2019 2018 2019 2018 2019 2018 Total Operating Revenues $ 152.1 $ 145.8 $ 84.4 $ 84.5 $ 85.3 $ 88.2 $ 116.4 $ 125.6 Operating Income $ 28.8 $ 28.1 $ 12.3 $ 10.6 $ 10.0 $ 10.3 $ 22.0 $ 22.2 Net Income Applicable to Common $ 26.5 $ 15.6 $ 4.0 $ 3.6 $ 2.3 $ 2.8 $ 11.4 $ 11.0 Per Share Data: Earnings Per Common Share $ 1.78 $ 1.06 $ 0.27 $ 0.24 $ 0.15 $ 0.19 $ 0.77 $ 0.74 Dividends Paid Per Common Share $ 0.37 $ 0.365 $ 0.37 $ 0.365 $ 0.37 $ 0.365 $ 0.37 $ 0.365

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2019
Segment Information	Note 3: Segment Information Unitil reports three non-regulated. regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine. Granite State is an interstate natural gas transmission pip eline comp a ny, 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 n atura l gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transmission services provided to Northern Utilities and, to a lesser ext ent, third-party marketers. Granite State is included in the Gas column below. Unitil Resources is the Company’s wholly-owned non-regulated , were wholly-owned subsidiaries of Unitil Resources. Usource provided brokering and advisory services to large commercial and industrial customers in the northeastern United States. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Resources and Usource are included in the Non-Regulated Unitil Realty, Unitil Service and the holding company are included in the Other column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use. The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes and preferred stock dividends. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the FERC, NHPUC, MDPU, and MPUC. Assets allocated to each segment are based upon specific identification of such assets provided by Company records. The following table provides significant segment financial data for the years ended December 31, 2019, 2018 and 2017 (millions): Year Ended December 31, 2019 Gas Electric Non- Regulated Other Total Revenues: Billed and Unbilled Revenue $ 212.1 $ 223.1 $ $ $ 435.2 Rate Adjustment Mechanism Revenue (8.7 ) 10.8 — — 2.1 Other Operating Revenue— Non-Regulated — — 0.9 — 0.9 Total Operating Revenues 203.4 233.9 0.9 — 438.2 Interest Income 1.2 0.9 0.2 0.6 2.9 Interest Expense 14.4 9.4 — 2.8 26.6 Depreciation & Amortization Expense 28.5 22.6 — 0.9 52.0 Income Tax Expense (Benefit) 7.2 4.2 3.8 (1.4 ) 13.8 Segment Profit 19.1 11.5 10.2 3.4 44.2 Segment Assets 823.3 529.3 0.3 17.9 1,370.8 Capital Expenditures 74.0 39.6 — 5.6 119.2 Year Ended December 31, 2018 Revenues: Billed and Unbilled Revenue $ 210.7 $ 228.7 $ — $ — $ 439.4 Rate Adjustment Mechanism Revenue 5.4 (5.4 ) — — — Other Operating Revenue— Non-Regulated — — 4.7 — 4.7 Total Operating Revenues 216.1 223.3 4.7 — 444.1 Interest Income 0.8 0.8 0.2 0.6 2.4 Interest Expense 14.2 9.0 — 3.2 26.4 Depreciation & Amortization Expense 24.9 23.1 0.1 2.3 50.4 Income Tax Expense (Benefit) 7.1 4.2 0.5 (3.4 ) 8.4 Segment Profit 18.8 11.4 1.3 1.5 33.0 Segment Assets 764.1 484.2 6.9 43.1 1,298.3 Capital Expenditures 70.8 28.4 — 3.2 102.4 Year Ended December 31, 2017 Revenues $ 194.0 $ 206.2 $ 6.0 $ — $ 406.2 Interest Income 0.7 1.0 0.1 0.6 2.4 Interest Expense 13.7 8.8 — 3.0 25.5 Depreciation & Amortization Expense 22.4 23.4 0.1 1.0 46.9 Income Tax Expense (Benefit) 10.7 7.5 0.7 (1.4 ) 17.5 Segment Profit 16.4 11.9 1.2 (0.5 ) 29.0 Segment Assets 714.3 476.9 6.7 44.0 1,241.9 Capital Expenditures 72.1 33.7 — 13.5 119.3

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts	12 Months Ended
	Dec. 31, 2019
Allowance for Doubtful Accounts [Abstract]
Allowance for Doubtful Accounts	Note 4: Allowance for Doubtful Accounts Unitil’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. In 2019 , 2018 and 2017, the Company recorded provisions for the energy commodity portion of bad debts of $2.3 million, $2.6 million and $1.3 million, respectively. These provisions were recognized in Cost of Gas Sales and Cost of Electric Sales expense as the associated electric and gas utility revenues were billed. Cost of Gas Sales and Cost of Electric Sales costs are recovered from customers through periodic rate reconciling 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. As of December 31, 2019 and 2018, the Company has recorded 5.6 million and 5.2 million, respectively, of hardship accounts in Regulatory Assets. The Company is currently receiving recovery in rates or expects to receive recovery of these hardship accounts in future rate cases. The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2017 —2019 (millions): ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at Beginning of Period Provision Recoveries Accounts Written Off Balance at End of Period Year Ended December 31, 2019 Electric $ 0.5 $ 3.0 $ 0.3 $ 3.2 $ 0.6 Gas 0.8 1.9 0.5 2.8 0.4 Other — — — — — $ 1.3 $ 4.9 $ 0.8 $ 6.0 $ 1.0 Year Ended December 31, 2018 Electric $ 0.9 $ 3.2 $ 0.3 $ 3.9 $ 0.5 Gas 0.6 2.9 0.3 3.0 0.8 Other 0.1 (0.1 ) — — — $ 1.6 $ 6.0 $ 0.6 $ 6.9 $ 1.3 Year Ended December 31, 2017 Electric $ 0.8 $ 1.8 $ 0.3 $ 2.0 $ 0.9 Gas 0.2 1.9 0.3 1.8 0.6 Other 0.1 — — — 0.1 $ 1.1 $ 3.7 $ 0.6 $ 3.8 $ 1.6

Debt and Financing Arrangements

Debt and Financing Arrangements	12 Months Ended
	Dec. 31, 2019
Debt And Financing Arrangements	Note 5: Debt and Financing Arrangements The Company funds a portion of its operations through the issuance of long-term debt and through short-term borrowings under its revolving Credit Facility. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow: Long-Term Debt and Interest Expense Long-Term Debt Structure and Covenants The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s) must be satisfied, including that Unitil have total funded indebtedness less than 70 % of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil long-term debt agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of certain Unitil subsidiaries or certain other actions against Unitil subsidiaries. Substantially all of the property of Unitil Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met; including that Unitil Energy have sufficient available net bondable plant to issue the securities and earnings available for interest charges equal to at least two times the annual interest requirement. The Unitil Energy agreements further require that if Unitil Energy defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries. All of the long-term debt of Fitchburg, Northern Utilities and Granite State are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term agreements of that subsidiary must be satisfied, including that the subsidiary have total funded indebtedness less than 65% of total capitalization. Additionally, to issue new long-term debt, Fitchburg must maintain earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State long-term debt agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of that subsidiary’s long-term debt agreements. None of the Fitchburg, Northern Utilities and Granite State default provisions are triggered by the actions or defaults of Unitil or any of its other subsidiaries. The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State long-term debt instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets. Unitil Energy, Fitchburg, Northern Utilities and Granite State pay common dividends to their sole common shareholder, Unitil Corporation and these common dividends are the primary source of cash for the payment of dividends to Unitil’s common shareholders. The long-term debt issued by the Company and its subsidiaries contains certain covenants that determine the amount that the Company and each of these subsidiary companies has available to pay for dividends. As of December 31, 2019, in accordance with the covenants, these subsidiary companies had a combined amount of $308.4 million available for the payment of dividends and Unitil Corporation had $123.1 million available for the payment of dividends . As of December 31 , 2019 , the Company’s balance in Retained Earnings was $94.1 million. , 2019 for the payment of dividends. Issuance of Long-Term Debt —On December 18, 2019, Unitil Corporation issued $ million of Notes due 2029 at %. Unitil Corporation used the net proceeds from this offering to repay short-term debt and for general corporate purposes. Approximately $ million of costs associated with these issuances have been netted against Long-Term Debt for presentation purposes on the Consolidated Balance Sheets. On September 12, 2019, Northern Utilities issued $40 million of Notes due 2049 On November 30, 2018 Unitil Energy issued $30 million of FMB Debt Repayment $18.8 million, and , 2018 , and 2017 , respectively. The aggregate amount of bond repayment requirements and normal scheduled long-term debt repayments for each of the five years following 2019 is: 2020 — $19.8 million; 2021 — $8.6 million; 2022 — $28.2 million; 2023 — $6.7 million ; 2024 — $6.7 million million. Fair Value of Long-Term Debt 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. Estimated Fair Value of Long-Term Debt (millions) December 31, 2019 2018 Estimated Fair Value of Long-Term Debt $ 518.7 $ 422.0 Details on long-term debt at December 31 , 2019 and 2018 are shown below: Long-Term Debt (millions) December 31, 2019 2018 Unitil Corporation: 6.33 % Senior Notes, Due May 1, 2022 $ 20.0 $ 20.0 3.70 % Senior Notes, Due August 1, 2026 30.0 30.0 3.43% Senior Notes, Due December 18, 2029 30.0 — Unitil Energy First Mortgage Bonds: 5.24 % Senior Secured Notes, Due March 2, 2020 5.0 10.0 8.49 % Senior Secured Notes, Due October 14, 2024 4.5 6.0 6.96 % Senior Secured Notes, Due September 1, 2028 18.0 20.0 8.00 % Senior Secured Notes, Due May 1, 2031 15.0 15.0 6.32 % Senior Secured Notes, Due September 15, 2036 15.0 15.0 4.18 % Senior Secured Notes, Due November 30, 2048 30.0 30.0 Fitchburg: 6.75 % Senior Notes, Due November 30, 2023 3.8 5.7 6.79 % Senior Notes, Due October 15, 2025 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 5.90 % Senior Notes, Due December 15, 2030 15.0 15.0 7.98 % Senior Notes, Due June 1, 2031 14.0 14.0 4.32 % Senior Notes, Due November 1, 2047 15.0 15.0 Northern Utilities: 5.29 % Senior Notes, Due March 2, 2020 8.2 16.6 3.52 % Senior Notes, Due November 1, 2027 20.0 20.0 7.72 % Senior Notes, Due December 3, 2038 50.0 50.0 4.42 % Senior Notes , Due October 15, 2044 50.0 50.0 4.32 % Senior Notes, Due November 1, 2047 30.0 30.0 4.04% Senior Notes, Due September 12, 2049 40.0 — Granite State: 3.72 % Senior Notes , Due November 1, 2027 15.0 15.0 Total Long-Term Debt 460.5 409.3 Less: Unamortized Debt Issuance Costs 3.5 3.5 Total Long-Term Debt, net of Unamortized Debt Issuance Costs 457.0 405.8 Less: Current Portion (1) 19.5 18.4 Total Long-Term Debt, Less Current Portion $ 437.5 $ 387.4 (1) The Current Portion of Long-Term Debt includes sinking fund payments. Interest Expense, N e Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset. A summary of interest expense and interest income is provided in the following table: Interest Expense, N 2019 2018 2017 Interest Expense Long-Term Debt $ 22.9 $ 23.1 $ 21.8 Short-Term Debt 3.0 2.6 2.5 Regulatory Liabilities 0.7 0.7 1.2 Subtotal Interest Expense 26.6 26.4 25.5 Interest Income Regulatory Assets (0.8 ) (0.8 ) (0.7 ) AFUDC (1) (2.1 ) (1.6 ) (1.7 ) Subtotal Interest Income (2.9 ) (2.4 ) (2.4 ) Total Interest Expense, N $ 23.7 $ 24.0 $ 23.1 (1) AFUDC—Allowance for Funds Used During Construction Credit Arrangements On July 25, 2018, the Company entered into a Second Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders, which amended and restated in its entirety the Company’s prior credit agreement, dated as of October 4, 2013, as amended. The Credit Facility extends to one-year one-month The Company utilizes the Credit Facility for cash management purposes related to its short-term operating activities. Total gross borrowings were $252.7 million and $265.6 million for the years ended December 31, 2019 and December 31, 2018, respectively. Total gross repayments were $276.9 million and $221.1 million for the years ended December 31, 2019 and December 31, 2018, respectively. The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2019 and December 31, 2018: Revolving Credit Facility (millions) December 31, 201 9 201 8 Limit $ 120.0 $ 120.0 Short-Term Borrowings Outstanding $ 58.6 $ 82.8 Letters of Credit Outstanding $ 0.1 $ — Available $ 61.3 $ 37.2 The Credit Facility contains customary terms and conditions for credit facilities of this type, including affirmative and negative covenants. There are restrictions on, among other things, Unitil’s and its subsidiaries’ ability to permit liens or incur indebtedness, and restrictions on Unitil’s ability to merge or consolidate with another entity or change its line of business. The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2019 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. The Company believes it has sufficient sources of working capital to fund its operations. The weighted average interest rates on all short-term borrowings were 3.4 %, 3.3 %, and 2.4 % during 2019 2018 2017 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. 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 million . This capital lease was paid in full in the second quarter of 2019. 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 $6.5 million and $8.4 million of natural gas storage inventory at December 31, 2019 and 2018, respectively, related to these asset management agreements. The amount of natural gas inventory released in December 2019, which was payable in January 2020, was $1.0 million and recorded in Accounts Payable at December 31, 2019. The amount of natural gas inventory released in December 2018, which was payable in January 2019, was $0.9 million and recorded in Accounts Payable at December 31, 2018. Leases Unitil’s subsidiaries lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. Total rental expense under operating leases charged to operations for the years ended December 31, 2019, 2018 and 2017 amounted to $1.4 million, $2.2 million and $2.0 million respectively. The balance sheet classification of the Company’s lease obligations was as follows: December 31, Lease Obligations (millions) 2019 2018 Operating Lease Obligations: Other Current Liabilities (current portion) $ 1.2 $ — Other Noncurrent Liabilities (long-term portion) 2.8 — Total Operating Lease Obligations 4.0 — Capital Lease Obligations: Other Current Liabilities (current portion) 0.2 3.1 Other Noncurrent Liabilities (long-term portion) 0.3 2.7 Total Capital Lease Obligations 0.5 5.8 Total Lease Obligations $ 4.5 $ 5.8 Cash paid for amounts included in the measurement of operating lease obligations for the twelve months ended December 31, 2019 was $1.4 million and was included in Cash Provided by Operating Activities on the Consolidated Statements of Cash Flows. Assets under capital leases amounted to approximately $1.2 million and $15.0 million as of December 31, 2019 and 2018, respectively, less accumulated amortization of $0.6 million and $1.7 million, respectively and are included in Net Utility Plant on the Company’s Consolidated Balance Sheets. The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2019. The payments for capital leases consist of $0.2 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $0.3 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2019. The payments for operating leases consist of $1.2 million of current operating lease obligations , which are included in Other Current Liabilities and $2.8 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2019. Lease Payments ($000’s) Year Ending December 31, Operating Capital 2020 $ 1,355 $ 262 2021 1,185 161 2022 904 97 2023 604 55 2024 274 — 2025 139 — Total Payments 4,461 575 Less: Interest 435 29 Amount of Lease Obligations Recorded on Consolidated Balance Sheets $ 4,026 $ 546 Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of December 31, 2019, the weighted average remaining lease term is 3.9 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.2 %. Disclosures Related to Periods Prior to the Adoption of ASU NO. 2016-02—Leases (See Note 1). The payment amounts in the following table are as of December 31, 2018. Lease Payments ($000’s) Year Ending December 31, Operating Capital 2019 $ 1,372 $ 3,069 2020 1,138 2,535 2021 969 93 2022 689 32 2023 390 14 2024 120 — Total Payments $ 4,678 $ 5,743 Guarantees The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of December 31, 2019 million of guarantees outstanding.

Equity

Equity	12 Months Ended
	Dec. 31, 2019
Equity	Note 6: Equity The Company has common stock outstanding and one of our subsidiaries has preferred stock outstanding. Details regarding these forms of capitalization follow: Common Stock The Company’s common stock trades on the New York Stock Exchange under the symbol “UTL”. The Company had 14,876,955 and 14,930,170 shares of common stock outstanding at December 31 , 2018 and December 31 , 2019 , respectively. The Company has 25,000,000 shares of common stock authorized as of December 31 , 2018 and December 31 , 2019 . Unitil Corporation Common Stock Offering , 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 , the Company sold 20,065 shares of its common stock, at an average price of $57.37 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401 (k) plans resulting in net proceeds of $1.1 million. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock. During 2018 and 2017 , the Company raised $1.2 million and $1.3 million, respectively, through the issuance of 25,932 and 26,256 shares, respectively, of its common stock in connection with its DRP and 401 (k) plans. Common Shares Repurchased, Cancelled and Retired 10b5-1 , as amended (the Exchange Act), adopted by the Company on May 1 , 2014 , the Company may periodically repurchase shares of its common stock on the open market related to the stock portion of the Directors’ annual retainer. Until December 1 , 2018 , the Company also periodically repurchased shares of its common stock on the open market related to Employee Length of Service Awards. (See Part II, Item 5 , for additional information). During 2019 , 2018 and 2017 , the Company repurchased 2,911, 791 and 1,686 shares of its common stock, respectively, pursuant to the Rule 10b5-1 , 2018 and 2017 , respectively. During 2019 , 2018 and 2017 , the Company did no t cancel or retire any of its common stock. Stock-Based Compensation Plans Stock Plan 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 a 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 or retirement Restricted Shares issued for 2017 – 2019 in conjunction with the Stock Plan are presented in the following table: Issuance Date Shares Aggregate 1/30/17 34,930 $1.6 1/29/18 37,510 $1.6 1/29/19 33,150 $1.6 There were 32,950 and 29,252 non-vested , 2019 and 2018 , respectively. The weighted average grant date fair value of these shares was $47.35 per share and $42.86 per share, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recorded over the vesting period and was $2.3 million, $2.2 million and $2.7 million in 2019 , 2018 and 2017 , respectively. At December 31 , 2019 , there was approximately $0.7 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.5 years. There were no no 2019 . On January 28 , there were 28,630 Restricted Shares issued under the Stock Plan with an aggregate market value of $1.8 million. Restricted Stock Units Restricted Stock Units, which are issued to members of the Company’s Board of Directors, 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 2019 and 2018 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) 2019 2018 Units Weighted Average Stock Price Units Weighted Average Stock Price Beginning Restricted Stock Units 61,789 $ 38.25 52,224 $ 36.22 Restricted Stock Units Granted 6,943 $ 63.50 7,892 $ 49.63 Dividend Equivalents Earned 1,632 $ 58.15 1,673 $ 47.85 Restricted Stock Units Settled — — — — Ending Restricted Stock Units 70,364 $ 41.20 61,789 $ 38.25 Included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets as of December 31 , 2019 and 2018 are million and $1.3 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 w er e million, or 1,887 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31 , 2019 . There w er e million, or 1,893 shares, of Unitil Energy’s 6.00 % Series Preferred Stock outstanding as of December 31 , 2018 . There were less than $0.1 million of total dividends declared on Preferred Stock in each of the twelve month periods ended December 31 , 2019 and December 31 , 2018 , respectively. Earnings Per Share The following table reconciles basic and diluted earnings per share (EPS). (Millions except shares and per share data) 2019 2018 2017 Earnings Available to Common Shareholders $ 44.2 $ 33.0 $ 29.0 Weighted Average Common Shares Outstanding—Basic (000’s) 14,894 14,824 14,095 Plus: Diluted Effect of Incremental Shares (000’s) 6 5 7 Weighted Average Common Shares Outstanding—Diluted (000’s) 14,900 14,829 14,102 Earnings per Share—Basic and Diluted $ 2.97 $ 2.23 $ 2.06 The following table shows the number of weighted average non-vested 2019 2018 2017 Weighted Average Non-Vested — 6,102 8,733

Energy Supply

Energy Supply	12 Months Ended
	Dec. 31, 2019
Energy Supply	Note 7: Energy Supply NATURAL GAS SUPPLY Unitil purchases and manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts. Northern Utilities’ C&I customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many of Northern Utilities’ largest and some medium C&I customers purchase their gas supply from third-party suppliers, while most small C&I customers, as well as all residential customers, purchase their gas supply from Northern Utilities under regulated rates and tariffs. As of December 2019, 78% of Unitil’s largest New Hampshire gas customers, representing 37% of Unitil’s New Hampshire gas therm sales and 64% of Unitil’s largest Maine customers, representing 28% of Unitil’s Maine gas therm sales, are purchasing gas supply from a third-party supplier. Fitchburg’s residential and C&I business customers are entitled to purchase their natural gas supply from third-party gas suppliers. Many large and some medium C&I customers purchase their gas supply from third-party suppliers while most of Fitchburg’s residential and small C&I customers continue to purchase their supplies at regulated rates from Fitchburg. As of December 2019, 76% of Unitil’s largest Massachusetts gas customers, representing 29% of Unitil’s Massachusetts gas therm sales, are purchasing gas supply from third-party suppliers. The approved costs associated with natural gas supplied to customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically adjusted rates and are included in Cost of Gas Sales in the Consolidated Statements of Earnings. Regulated Natural Gas Supply Northern Utilities purchases a majority of its natural gas from U.S. domestic and Canadian suppliers largely under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas transportation and delivery to its system its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply contracts delivered to its system, or in the case of liquefied natural gas (LNG), via over the road trucking of supplies to storage facilities within Northern Utilities’ service territory. Northern Utilities has available under firm contract 115,000 million British Thermal Units (MMbtu) per day of year-round and seasonal transportation capacity to its distribution facilities, and 4.3 billion cubic feet (BCF) of underground storage. As a supplement to pipeline natural gas, Northern Utilities owns an LNG storage and vaporization facility. This plant is used principally during peak load periods to augment the supply of pipeline natural gas. Fitchburg purchases natural gas under contracts from producers and marketers largely under contracts of one year or less, and occasionally on the spot market. Fitchburg arranges for gas transportation and delivery to its system through its own long-term contracts with Tennessee Gas Pipeline, through peaking supply contracts delivered to its system, or in the case of LNG or liquefied propane gas (LPG), via trucking of supplies to storage facilities within Fitchburg’s service territory. Fitchburg has available under firm contract 14,439 MMbtu per day of year-round transportation and 0.43 BCF of underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, Fitchburg owns a propane air gas plant and an LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas. ELECTRIC POWER SUPPLY Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the ISO-NE Unitil’s customers in both New Hampshire and Massachusetts are entitled to purchase their electric supply from competitive third-party suppliers. As of December 2019, 75% of Unitil’s largest New Hampshire customers, representing 23% of Unitil’s New Hampshire electric kilowatt-hour (kWh) sales and 87% of Unitil’s largest Massachusetts customers, representing 37% of Unitil’s Massachusetts electric kWh sales, are purchasing their electric power supply in the competitive market. Additionally, cities and towns in Massachusetts may, with approval from the MDPU, implement municipal aggregations whereby the municipality purchases electric power on behalf of all citizens and businesses that do not opt out of the aggregation. The Towns of Lunenburg and Ashby have active municipal aggregations. Customers in Lunenburg comprise about 16 r base and customers in Ashby comprise another 4%. Buoyed by the municipal aggregations, 28% of Unitil’s residential customers in Massachusetts purchase their electricity from a third-party supplier as of December 2019. In New Hampshire, the percentage of residential customers purchasing electricity from a third-party supplier as of December 2019 is at 9%, down slightly from 10% in 2018 and reflecting a downward trend from a high of 13% in 2015. Most residential and small commercial customers continue to purchase their electric supply through Unitil’s electric distribution utilities under regulated energy rates and tariffs. Regulated Electric Power Supply In order to provide regulated electric supply service to their customers, Unitil’s electric distribution utilities enter into load-following wholesale electric power supply contracts to purchase electric supply from various wholesale suppliers. Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Currently, with approval of the NHPUC, Unitil Energy purchases Default Service power supply contracts for small, medium and large customers every six months for % of the supply requirements. Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service electric supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Basic Service power supply contracts for residential and for small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements. On June 13, 2012, the MDPU approved Fitchburg’s request to discontinue the procurement process for Fitchburg’s large customers and become the load-serving entity for these customers. Currently, all Basic Service power supply requirements for large accounts are assigned to Fitchburg’s ISO-NE settlement account where Fitchburg procures electric supply through ISO-NE’s real-time market. The NHPUC and MDPU regularly review alternatives to their procurement policy, which may lead to future changes in this regulated power supply procurement structure. Regional Electric Transmission and Power Markets Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE ISO-NE ISO-NE ISO-NE ISO-NE Electric Power Supply Divestiture In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The companies have a continuing obligation to submit regulatory filings that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans. Long-Term Renewable Contracts Fitchburg has entered into long-term renewable contracts for the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with six of these contracts have been constructed and are now operating. In 2018, the Company filed two long-term contracts with the MDPU, one for offshore wind generation and another for imported hydroelectric power and associated transmission. Those contracts were approved in 2019. In 2019, the Company participated in an additional statewide procurement for offshore wind generation and the resulting contract will be filed for approval with the MDPU during the first quarter of

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies	Note 8: Commitments and Contingencies Regulatory Matters Overview —Unitil’s distribution utilities deliver electricity and/or natural gas to customers in the Company’s service territories at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. Fitchburg’s electric and gas divisions also operate under revenue decoupling mechanisms. Most of Unitil’s customers are entitled to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business customers are entitled to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized In connection with the implementation of retail choice, Unitil Power and Fitchburg divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. These assets have been principally recovered as of December 31 , 2019 . The remaining balance of these assets is $0.6 million as of December 31 , 2019 , including $0.3 million recorded in Current Assets as Accrued Revenue on the Company’s Consolidated Balance Sheet projected to be recovered in the next $0.3 million recorded in Regulatory Assets on the Company’s Consolidated Balance Sheet projected to be recovered over the two years distribution companies have a continuing obligation to submit filings in Massachusetts and New Hampshire that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans. Tax Cuts and Jobs Act of 2017 On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (TCJA) was signed into law. Among other things, the TCJA substantially reduced the corporate income tax rate to 21%, 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, issued orders directing how the tax law changes were to be reflected in rates. Unitil has complied with these orders and has made the required changes to its rates as directed by the commissions. The FERC issued a Notice of Proposed Rulemaking 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 reduction. This matter has been resolved for Granite State in its May 2, 2018 uncontested rate settlement filing, which accounted for the effect of the TCJA. On November 21, 2019, the FERC issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the impacts of the TCJA and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT). FERC also required transmission providers with stated rates to account for the ADIT impacts of the TCJA in their next rate case. The Company believes that compliance with the new rule will not have a material impact on its financial position, operating results, or cash flows. Rate Case Activity Northern Utilities—Base Rates—Maine— and facilities and other operational and safety-related system improvements. The first annual adjustment is proposed for November 1, 2020, to recover the Company’s 2019 investment cost of eligible facilities and improvements. This matter remains pending. Northern Utilities—Targeted Infrastructure Replacement Adjustment (TIRA)—Maine— Northern Utilities—Base Rates—New Hampshire— Unitil Energy—Base Rates— Fitchburg—Base Rates—Electric— MDPU - On October 29, 2019, Fitchburg filed its cumulative revenue requirement of $1.1 million associated with the Company’s 2015-2018 capital expenditures. On December 16, 2019, the filing was approved, effective January 1, 2020, subject to further investigation and reconciliation. Final approval of the 2019 filing remains pending. On December 17, 2019, Fitchburg filed for a $2.7 million increase in its electric base revenue decoupling target, which represents a 4.1% increase over 2018 test year operating electric revenues. The filing included a request for an inflation-based Performance Base Ratemaking plan. By statute, the MDPU is afforded ten months to act on a request for a rate increase. A decision is expected by the end of October, 2020. Fitchburg—Base Rates—Gas— Fitchburg—Gas System Enhancement Program— infrastructure replacement and safety related investment costs, subject to an annual cap. Under the plan, the Company is required to make two annual filings with the MDPU: a forward-looking filing for the subsequent construction year, to be filed on or before October (the “GSEP Filing”); and a filing, submitted on or before May , of final project documentation for projects completed during the prior year, demonstrating substantial compliance with its plan in effect for that year and showing that project costs were reasonably and prudently incurred (the “GREC Filing”). The Company considers these to be routine regulatory proceedings and there are no material issues outstanding. In an Order issued on April 30, 2019, the MDPU approved Fitchburg’s 2018 GSEP Filing and increased the annual cap on recovery. Because the increase in the amount for recovery, $1.6 million, still exceeded the annual cap, the Order resulted in a revenue increase of $1.0 million that went into effect on May 1, 2019, subject to reconciliation. The amount that exceeded the cap, $0.6 million, has been deferred to be recovered in a later proceeding. On May 1, 2019, the Company made its 2019 GREC Filing, seeking a waiver of the annual ​​​​​​​cap and a revenue increase of $1.0 million. The MDPU approved the Company’s request in its Order issued October 31, 2019. Granite State—Base Rates— the the Other Matters Fitchburg—Independent Statewide Examination of the Safety of the Commonwealth’s Gas Distribution System on-going Northern Utilities / Granite State—Firm Capacity Contract one-year 12-month Reconciliation Filings— recovery of the ongoing costs of storm repairs incurred by Unitil Energy; and the actual wholesale energy costs for electric power and natural gas incurred by each of the three companies. Fitchburg, Unitil Energy and Northern Utilities have been, and remain in full compliance with all directives and orders regarding these filings. The Company considers these to be routine regulatory proceedings and there are no material issues outstanding. Fitchburg—Massachusetts RFPs— term contracts via one or more staggered solicitations ​​​​​​​for a total of 9,450,000 megawatt-hours by December 31, 2022. Unitil’s pro rata share of each of these contracts is approximately one percent. The EDCs issued the RFP for Section 83D Long-Term Contracts for Qualified Clean Energy Projects in March 2017, and after selection of final projects and negotiation, final contracts for 9,554,940 MWh of Qualified Clean Energy and associated Environmental Attributes from hydroelectric generation were filed in July 2018 for approval by the MDPU. On June 25, 2019, the MDPU approved the power purchase agreements, including the EDCs’ proposal to sell the energy procured under the contract into the ISO-NE ISO-NE The EDCs issued the RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation in June 2017. Final selection of projects was made in May 2018, contracts were signed in July 2018 and on July 23, 2018, the EDCs, including Fitchburg, filed two long-term contracts, each for 400MW of offshore wind energy generation with the ISO-NE ISO-NE , once certain conditions and contingencies are met . The EDCs issued an RFP pursuant to Section 83C for Long-Term Contracts for Offshore Wind Energy Generation on May 23, 2019. This is the second solicitation pursuant to Section 83C and with the MDPU MDPU 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 the ROE, 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. On November 21 , 2019 the FERC issued an order in EL14 -12 , Midcontinent Independent System Operator ROE, in which FERC outlined a new methodology for calculating the ROE. On December 26 , 2019 in response to the FERC order in EL 14 -12 , the New England Transmission Owners (NETOs) filed a motion to reopen the record and submitted a supplemental brief. Responses to that filing are due January 21 , 2020 . Also pending at FERC is a Section 206 proceeding concerning the justness and reasonableness of ISO-New hearing procedures. On May 24, 2019 the judge appointed a Dispute Resolution Facilitator to aid parties in settlement negotiations. The procedural schedule was suspended September 24, 2019 in order to allow participants to focus on settlement negotiations. On October 24, 2019, the NETO’s filed an unopposed motion to suspend the procedural schedule and waiver of answer period indicating that the NETO’s, Municipal PTF Owners and the Commission Trial Staff have reached agreement in principle on the terms of a settlement to resolve all open issues in the proceeding. 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. Contractual Obligations The table below lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2019. Payments Due by Period Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2019 Total 2020 2021 2022 2023 2024 2025 & Gas Supply Contracts $ 584.8 $ 45.6 $ 48.7 $ 48.0 $ 45.5 $ 36.5 $ 360.5 Electric Supply Contracts 14.2 2.0 1.2 1.2 1.2 1.2 7.4 Total $ 599.0 $ 47.6 $ 49.9 $ 49.2 $ 46.7 $ 37.7 $ 367.9 The Company and its subsidiaries have material energy supply commitments that are discussed in Note 7 to the accompanying Consolidated Financial Statements. Cash outlays for the purchase of electricity and natural gas to serve customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over-collected cash over subsequent periods of less than a year. Legal Proceedings The Company is involved in legal and administrative proceedings and claims of various types, including those 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. Environmental Matters The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company is in material compliance with applicable environmental and safety laws and regulations and, as of December 31, 2019, has not identified any material losses reasonably likely to be incurred in excess of recorded amounts. However, the Company 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— mid-1800s mid-1900s. Northern Utilities has worked with the Maine Department of Environmental ​​​​​​​Protection and New Hampshire Department of Environmental Services (NH DES) to address environmental concerns with these sites. Northern Utilities or others have completed remediation activities at all sites; however, on site monitoring continues at several sites which may result in future remedial actions as directed by the applicable regulatory agency. In July 2019, the NH DES requested that Northern Utilities review modeled expectations for groundwater contaminants against observed data at the Rochester site. The results of the review, along with recommendations regarding remedial action, will be submitted to the NH DES in January 2020. While any recommendation is subject to approval by the NH DES, the Company has accrued $0.7 million for estimated costs to complete the remediation at the Rochester site, which is included in the Environmental Obligations table below. 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 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 the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets as of December 31, 2019 and 2018. Environmental Obligations (millions) Fitchburg Northern Utilities Total 2019 2018 2019 2018 2019 2018 Total Balance at Beginning of Period $ — $ 0.1 $ 2.0 $ 2.0 $ 2.0 $ 2.1 Additions — — 0.9 0.3 0.9 0.3 Less: Payments / Reductions — 0.1 0.2 0.3 0.2 0.4 Total Balance at End of Period $ — $ — $ 2.7 $ 2.0 $ 2.7 $ 2.0 Less: Current Portion — — 0.6 0.6 0.6 0.6 Noncurrent Balance at December 31, $ — $ — $ 2.1 $ 1.4 $ 2.1 $ 1.4

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Taxes	Note 9: Income Taxes Provisions for Federal a nd ($000’s) 2019 2018 2017 Current Income Tax Provision Federal $ — $ — $ — State 351 355 — Total Current Income Taxes $ 351 $ 355 $ — Deferred Income Provision Federal $ 9,340 $ 5,032 $ 13,675 State 4,117 3,006 3,862 Total Deferred Income Taxes 13,457 8,038 17,537 Total Income Tax Expense $ 13,808 $ 8,393 $ 17,537 The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below: 2019 2018 2017 Statutory Federal Income Tax Rate 21 % 21 % 34 % Income Tax Effects of: State Income Taxes, net 6 6 6 Utility Plant Differences (3 ) (7 ) (1 ) Tax Credits — — (1 ) Other, net — — — Effective Income Tax Rate 24 % 20 % 38 % Temporary differences which gave rise to deferred tax assets and liabilities in 2019 and 2018 are shown below: Temporary Differences (000’s) 2019 2018 Deferred Tax Assets Retirement Benefit Obligations $ 36,551 $ 32,249 Net Operating Loss Carryforwards 1,609 10,773 Tax Credit Carryforwards 1,489 2,704 Other, net 1,589 1,571 Total Deferred Tax Assets $ 41,238 $ 47,297 Deferred Tax Liabilities Utility Plant Differences $ 134,011 $ 132,682 Regulatory Assets & Liabilities 5,239 6,429 Other, net 5,539 5,964 Total Deferred Tax Liabilities 144,789 145,075 Net Deferred Tax Liabilities $ 103,551 $ 97,778 In June 2019 the Company received notice that the Internal Revenue Service (IRS) completed all fieldwork for the tax years December 31, 2015 and December 31, 2016 income tax audit and closed the audit with no adjustment. Income tax filings for the year ended December 31, 2018 have been filed with the IRS, Massachusetts Department of Revenue, the Maine Revenue Service, and the New Hampshire Department of Revenue Administration. The Company evaluated its tax positions 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 Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31 , 2016 ; December 31 , 2017 ; and December 31 , 2018 . In December 2017 , the 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 ADIT at the new 21 % tax rate at which the ADIT will be reversed in future periods. The Company recorded a net Regulatory Liability in the amount of $48.9 million at December 31 , 2017 as a result of the ADIT revaluation. The MDPU issued a multi-utility Order D.P.U. 18 -15 -E (the “Order”) on December 21 , 2018 . The Order clarified the categories of Excess ADIT for Massachusetts ratemaking: 1) Excess protected ADIT directly related to utility plant fixed assets (rate base), 2) other non-plant excess ADIT amounts (unprotected), and 3) excess ADIT created through reconciling mechanisms. In the Order, all Massachusetts utilities were ordered to begin flow back of protected and unprotected excess ADIT on February 1 , 2019 and to reconcile excess ADIT amounts previously collected from ratepayers through reconciliation mechanisms in the next filing of each of those individual reconciling mechanisms. Fitchburg was ordered to begin flowing back to customers excess ADIT of $10.1 million and $10.4 million to electric and gas ratepayers, respectively , over approximately fifteen years . Fitchburg filed its compliance filing under D.P.U. -15 -E on January 4 , 2019 for rates effective February 1 , 2019 . The MDPU approved this filing on January 16 , 2019 . The filing will be updated and the balances of excess ADIT will be reconciled annually until the next rate case . On November 15 , 2018 the FERC issued two pronouncements regarding the accounting for income taxes due to the TCJA; 1) Notice of Proposed Rulemaking Docket No. RM 19 -5 -000 and 2) Policy Statement PL 19 -2 -000 providing specific guidance on the flow back of excess ADIT created by the implementation of the TCJA. According to the FERC guidance; the amount of the reduction to ADIT that was previously 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. On November 21 , 2019 the FERC issued a final order Docket No. RM19 -5 -000 regarding the 2018 Notice of Proposed Rulemaking and Policy Statement (“Notice”) and affirmed the regulatory treatment outlined in the 2018 Notice. 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 protected 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 for protected and unprotected excess ADIT to be between fifteen and twenty years, over the remaining life of the related utility plant. Subject to regulatory approval, the Company expects to flow back to customers a net $47.1 million of protected excess ADIT created as a result of the lowering of the statutory tax rate by the TCJA over periods estimated to be fifteen to twenty years. In addition to the protected excess $47.1 million ADIT amounts the Company expects to flow through to customers in utility rates, as noted above, there were approximately $1.8 million of excess ADIT created through reconciling mechanisms at December 31 , 2017 , related to the implementation of the new federal tax rate of the TCJA, which had not been previously collected from customers through utility rates. The Company reconciles these excess ADIT amounts through the specific reconciliation mechanisms in the filing of each of those individual reconciling mechanisms which will be subject to the review of state regulators. In 2018 and 2019 , the Company recognized $ 0.7 million and $ 0 , respectively, of this excess ADIT amount due to the completed filings in the associated jurisdictions. The Company expects to recognize the remaining $ 1.1 million of this excess ADIT in future periods, which is currently expected to be in 2020 , after the Company has filed all of its reconciling mechanisms related to the excess ADIT. In addition to the $48.9 million of net excess ADIT noted above , as of December 31, 2018, there was $2.0 million of remaining excess ADIT created by the recognition of Net Operating Loss Carryforward assets (NOLC), discussed below, and related to the implementation of the new federal tax rate of the TCJA, which had not been previously included in utility rates. The Company is recognizing the benefit of this excess ADIT in accordance with the regulatory treatment of excess ADIT for each of jurisdiction. The Company recognized $1.7 million of this tax benefit in the current year due to the turning of book/tax temporary differences associated with this excess ADIT. The Company expects to recognize the remaining $ 0.3 million of this excess ADIT in future periods, which is currently expected to be in 2020, in accordance with regulatory guidance as discussed above. The Company has not yet received regulatory orders in all of its jurisdictions regarding the flow-back of excess deferred taxes. The Company’s regulators are expected to issue additional ratemaking 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 TCJA matters with the Company’s regulators may change the amounts estimated. Under the Company’s Tax Sharing Agreement (the “Agreement ”) which was approved upon the formation of Unitil as a public utility holding company ; the Company files consolidated Federal and State tax returns and Unitil Corporation and each of its utility operating subsidiaries recognize the results of their operations in its tax returns as if it were a stand-alone taxpayer. The Agreement provides that the Company will account for income taxes in compliance with U.S. GAAP and regulatory accounting principles. The Company filed its tax returns for the year ended December 31 , 2018 with the IRS in September 2019 and utilized federal NOLC assets of $5.7 million principally due to pension cost deductions, tax repair deductions, tax depreciation and research and development deductions. For the tax year ended December 31 , 2019 , the Company used $3.5 million of the NOLC in calculating the 2019 federal tax provision. As of December 31 , 2019 , the Company had recorded cumulative federal NOLC assets of $ 1.6 million to offset against taxes payable in future periods. If unused, the Company’s NOLC carryforward assets will begin to expire in 2029 . The Company received $ 0.9 million of the Alternative Minimum Tax (AMT) credits in 2019 and will receive $ 0.3 million of the AMT credits in 2020 . In addition, at December 31 , 2019 , the Company had $ 2.3 million of cumulative alternative minimum tax credits, general business tax credit and other state tax credit carryforwards to offset future income taxes payable. In assessing the near-term use of NOLCs and tax credits, the Company evaluates the expected level of future taxable income, available tax planning strategies, reversals of existing taxable temporary differences and taxable income available in carryback years. Based on all available evidence, both positive and negative, and the weight of that evidence to the extent such evidence can be objectively verified, the Company expects to utilize all of its NOLCs by December 31 , 2020 prior to their expiration in 2029 . The Company bills its customers for sales tax in Massachusetts and Maine. 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 Plans

Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2019
Retirement Benefit Plans	Note 10: Retirement Benefit Plans The Company sponsors the following retirement benefit plans to provide certain pension and post-retirement benefits for its retirees and current employees as follows: • The Unitil Corporation Retirement Plan (Pension Plan)—The Pension Plan is a defined benefit pension plan. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service. • The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts, into which it funds contributions to the PBOP Plan. • The Unitil Corporation Supplemental Executive Retirement Plan (SERP)—The SERP is a non-qualified The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations: 2019 2018 2017 Used to Determine Plan costs for years ended December 31: Discount Rate 4.25 % 3.60 % 4.10 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Expected Long-term rate of return on plan assets 7.50 % 7.75 % 7.75 % Health Care Cost Trend Rate Assumed for Next Year 7.00 % 7.50 % 8.00 % Ultimate Health Care Cost Trend Rate 4.50 % 4.50 % 4.00 % Year that Ultimate Health Care Cost Trend Rate is reached 2024 2024 2025 Used to Determine Benefit Obligations at December 31: Discount Rate 3.25 % 4.25 % 3.60 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Health Care Cost Trend Rate Assumed for Next Year 7.00 % 7.00 % 7.50 % Ultimate Health Care Cost Trend Rate 4.50 % 4.50 % 4.50 % Year that Ultimate Health Care Cost Trend Rate is reached 2029 2024 2024 The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on an assessment of current market conditions using high quality corporate bond interest rate indices and pension yield curves. For 2019, a change in the discount rate of 0.25 % would have resulted in an increase or decrease of approximately $534 ,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2019 was based on the expected long-term increase in compensation costs for personnel covered by the plans. The following table provides the components of the Company’s Retirement plan costs (000’s): Pension Plan PBOP Plan SERP 2019 2018 2017 2019 2018 2017 2019 2018 2017 Service Cost $ 3,104 $ 3,393 $ 3,295 $ 2,304 $ 2,933 $ 2,974 $ 247 $ 487 $ 460 Interest Cost 6,484 5,878 6,057 3,426 3,404 3,913 567 404 392 Expected Return on Plan Assets (8,475 ) (7,785 ) (7,306 ) (1,645 ) (1,635 ) (1,347 ) — — — Prior Service Cost Amortization 320 324 263 1,213 1,309 1,399 56 189 189 Actuarial Loss Amortization 4,324 5,786 4,662 227 1,383 2,098 628 486 295 Sub-total 5,757 7,596 6,971 5,525 7,394 9,037 1,498 1,566 1,336 Amounts Capitalized or Deferred (2,227 ) (3,465 ) (3,122 ) (2,317 ) (3,416 ) (4,515 ) (430 ) (451 ) (397 ) NPBC Recognized $ 3,530 $ 4,131 $ 3,849 $ 3,208 $ 3,978 $ 4,522 $ 1,068 $ 1,115 $ 939 The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year 2018 and 2017 before capitalization and deferral was $ million, $ million and $ million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2019, 2018 and 2017 would have been $ million, $ million and $ million respectively, prior to amounts capitalized or deferred. The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s) : Pension Plan PBOP Plan SERP Change in Plan Assets: 2019 2018 2019 2018 2019 2018 Plan Assets at Beginning of Year $ 107,808 $ 102,315 $ 21,109 $ 20,234 $ — $ — Actual Return on Plan Assets 17,908 (6,149 ) 3,808 (1,085 ) — — Employer Contributions 6,916 16,628 4,000 4,000 610 401 Participant Contributions — — 121 153 — — Benefits Paid (6,877 ) (4,986 ) (1,758 ) (2,193 ) (610 ) (401 ) Plan Assets at End of Year $ 125,755 $ 107,808 $ 27,280 $ 21,109 $ — $ — Change in PBO: PBO at Beginning of Year $ 156,197 $ 166,921 $ 81,005 $ 94,122 $ 13,754 $ 11,723 Service Cost 3,104 3,393 2,304 2,933 247 487 Interest Cost 6,484 5,878 3,426 3,404 567 404 Participant Contributions — — 121 153 — — Plan Amendments — — — — 225 — Benefits Paid (6,877 ) (4,986 ) (1,758 ) (2,193 ) (610 ) (401 ) Actuarial (Gain) or Loss 23,227 (15,009 ) 10,559 (17,414 ) 3,576 1,541 PBO at End of Year $ 182,135 $ 156,197 $ 95,657 $ 81,005 $ 17,759 $ 13,754 Funded Status: Assets vs PBO $ (56,380 ) $ (48,389 ) $ (68,377 ) $ (59,896 ) $ (17,759 ) $ (13,754 ) The increase in the PBO for the Pension plan as of December 31, 2019 compared to December 31, 2018 reflects a decrease in the assumed discount rate as of December 31, 2019. The increase in the PBO for the PBOP plan as of December 31, 2019 compared to December 31, 2018 reflects a decrease in the assumed discount rate as of December 31, 2019. The funded status of the Pension, PBOP and SERP Plans is calculated based on the difference between the benefit obligation and the fair value of plan assets and is recorded on the balance sheets as an asset or a liability. Because the Company recovers the retiree benefit costs from customers through rates, regulatory assets are recorded in lieu of an adjustment to Accumulated Other Comprehensive Income/(Loss). The Company has recorded on its consolidated balance sheets as a liability the underfunded status of its and its subsidiaries’ retirement benefit obligations based on the projected benefit obligation. The Company has recognized Regulatory Assets, net of deferred tax benefits, of $88.9 million and $72.0 million at December 31, 2019 and 2018, respectively, to account for the future collection of these plan obligations in electric and gas rates. The Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $166.5 million and $142.8 million as of December 31, 2019 and 2018, respectively. The ABO for the SERP was $ 13.6 million and $10.8 million as of December 31, 2019 and 2018, respectively. For the PBOP Plan, the ABO and PBO are the same. (See Note 1 for further discussion of SERP funding.) The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2020 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs. The following table represents employer contributions, participant contributions and benefit payments (000’s). Pension Plan PBOP Plan SERP 2019 2018 2017 2019 2018 2017 2019 2018 2017 Employer Contributions $ 6,916 $ 16,628 $ 4,100 $ 4,000 $ 4,000 $ 4,000 $ 610 $ 401 $ 34 Participant Contributions $ — $ — $ — $ 121 $ 153 $ 126 $ — $ — $ — Benefit Payments $ 6,877 $ 4,986 $ 5,574 $ 1,758 $ 2,193 $ 2,405 $ 610 $ 401 $ 34 The following table represents estimated future benefit payments (000’s). Estimated Future Benefit Payments Pension PBOP SERP 2020 $ 6,706 $ 2,774 $ 653 2021 7,192 3,035 653 2022 6,903 3,167 651 2023 7,687 3,341 650 2024 8,622 3,622 648 2025 - 2029 49,511 21,761 6,037 The Expected Long-Term Rate of Return on Pension Plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on Pension Plan assets is based on target investment allocation of 53 % in common stock equities, 37 % in fixed income securities and 10 % in real estate securities. The Company’s Expected Long-Term Rate of Return on PBOP Plan assets is based on target investment allocation of 55 % in common stock equities and 45 Pension Plan Target Allocation 2020 Actual Allocation at December 31, 2019 2018 2017 Equity Funds 53 % 54 % 49 % 49 % Debt Funds 37 % 36 % 40 % 34 % Real Estate Fund 10 % 9 % 10 % 10 % Asset Allocation Fund (1) — — — 6 % Other (2) — 1 % 1 % 1 % Total 100 % 100 % 100 % (1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities. (2) Represents investments being held in cash equivalents as of December 31, 2019, December 31, 2018 and December 31, 2017 pending payment of benefits. PBOP Plan Target Allocation 2020 Actual Allocation at December 31, 2019 2018 2017 Equity Funds 55 % 56 % 53 % 56 % Debt Funds 45 % 44 % 47 % 42 % Other (1) — — — 2 % Total 100 % 100 % 100 % (1) Represents investments being held in cash equivalents as of December 31, 2017 pending transfer into debt and equity funds. The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 7.50 % for 2019. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class. Following is a description of the valuation methodologies used for assets measured at fair value. There have been no changes in the methodologies used at December 31, 2019 and 2018. Please also see Note 1 for a discussion of the Company’s fair value accounting policy. Equity, Fixed Income, Index and Asset Allocation Funds These investments are valued based on quoted prices from active markets. These securities are categorized in Level 1 as they are actively traded and no valuation adjustments have been applied. Cash Equivalents These investments are valued at cost, which approximates fair value, and are categorized in Level 1. Real Estate Fund These investments are valued at net asset value per unit based on a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity. In accordance with FASB Codification Topic 820, “Fair Value Measurement”, these investments have not been classified in the fair value hierarchy. The fair value amounts presented in the tables below for the Real Estate Fund are intended to permit reconciliation of the fair value hierarchy to the “Plan Assets at End of Year” line item shown in the “Change in Plan Assets” table above. Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2019 and 2018 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of December 31, Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 2019 Pension Plan Assets: Mutual Funds: Equity Funds $ 68,848 $ 68,848 $ — $ — Fixed Income Funds 44,980 44,980 — — Total Mutual Funds 113,828 113,828 — — Cash Equivalents 750 750 Total Assets in the Fair Value Hierarchy $ 114,578 $ 114,578 $ — $ — Real Estate Fund–Measured at Net Asset Value 11,177 Total Assets $ 125,755 2018 Pension Plan Assets: Mutual Funds: Equity Funds $ 52,884 $ 52,884 $ — $ — Fixed Income Funds 43,281 43,281 — — Total Mutual Funds 96,165 96,165 — — Cash Equivalents 1,202 1,202 Total Assets in the Fair Value Hierarchy $ 97,367 $ 97,367 $ — $ — Real Estate Fund–Measured at Net Asset Value 10,441 Total Assets $ 107,808 Redemptions of the Real Estate Fund are subject to a sixty-five day notice period and the fund is valued quarterly. There are no unfunded commitments. Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2019 and 2018 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of December 31, Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 2019 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 11,888 $ 11,888 $ — $ — Equity Funds 15,392 15,392 — — Total Assets $ 27,280 $ 27,280 $ — $ — 2018 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 9,905 $ 9,905 $ — $ — Equity Funds 11,204 11,204 — — Total Assets $ 21,109 $ 21,109 $ — $ — Employee 401(k) Tax Deferred Savings Plan— The Company’s contributions to the 401(k) Plan were $2.8 million, $2.7 million and $2.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Nature of Operations	Nature of Operations non-regulated 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 capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in New Hampshire; Fitchburg, which operates in Massachusetts; and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the “distribution utilities”). Granite State is an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1 , 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energy’s customers. Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated energy
Divestiture of Non-Regulated Business Subsidiary	Divestiture of Non-Regulated Business Subsidiary — non-regulated after-tax 9.8 pre-tax 13.4 3.6
Principles of Consolidation	Principles of Consolidation
Use of Estimates	Use of Estimates ( GAAP
Fair Value	Fair Value L L Level 1— Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2— Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly. Level 3— Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. Accordingly, the degree of judgment exercised by the Company in determining fair value is greatest for instruments categorized in Level 3. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Fair value is a market-based measure considered from the perspective of a market participant rather than an entity-specific measure. Therefore, even when market assumptions are not readily available, the Company’s own assumptions are set to reflect those that market participants would use in pricing the asset or liability at the measurement date. The Company uses prices and inputs that are current as of the measurement date, including during periods of market dislocation. In periods of market dislocation, the observability of prices and inputs may be reduced for many instruments. This condition could cause an instrument to be reclassified from Level 1 to Level 2 or from Level 2 to Level 3 . There have been no changes in the valuation techniques used during the current period.
Utility Revenue Recognition	Utility Revenue Recognition— 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, 2015-14, 2016-08, 2016-10 2017-13, 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 twelve months ended December 31, 2019. 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. The Company’s billed and unbilled revenue meets the definition of “revenues from contracts with customers” as defined in ASU 2014-09. 980-605-25-3, 2014-09 In the following tables, revenue is classified by the types of goods/services rendered and market/customer type. Twelve Months Ended Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 81.4 $ 121.5 $ 202.9 Commercial & Industrial 120.1 93.8 213.9 Other 10.6 7.8 18.4 Total Billed and Unbilled Revenue 212.1 223.1 435.2 Rate Adjustment Mechanism Revenue (8.7 ) 10.8 2.1 Total Gas and Electric Operating Revenues $ 203.4 $ 233.9 $ 437.3 Twelve Months Ended December 31, 2018 Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 81.4 $ 123.6 $ 205.0 Commercial & Industrial 119.7 96.4 216.1 Other 9.6 8.7 18.3 Total Billed and Unbilled Revenue 210.7 228.7 439.4 Rate Adjustment Mechanism Revenue 5.4 (5.4 ) — Total Gas and Electric Operating Revenues $ 216.1 $ 223.3 $ 439.4 Twelve Months Ended December 31, 2017 Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 71.2 $ 107.9 $ 179.1 Commercial & Industrial 102.8 87.7 190.5 Other 13.5 6.0 19.5 Total Billed and Unbilled Revenue 187.5 201.6 389.1 Rate Adjustment Mechanism Revenue 6.5 4.6 11.1 Total Gas and Electric Operating Revenues $ 194.0 $ 206.2 $ 400.2 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 the current portion of 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 Massachusetts Department of Public Utilities (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	Other Operating Revenue—Non-regulated— non-regulated As discussed above, the Company adopted ASU 2014-09 2014-09 and going forward, payments made by Usource to Channel Partners for revenue sharing agreements were 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, , 2018 and 2017 , respectively. If ASU 2014-09 , the result would have been corresponding reductions of $1.1 million in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below. Other Operating Revenues ($ millions): Twelve Months Ended December 31 As Reported If ASU 2014-09 Had Been in Effect 2019 2018 2017 Usource Contract Revenue $ 1.1 $ 5.7 $ 6.0 Less: Revenue Sharing Payments (0.2 ) (1.0 ) (1.1 ) Total Other Operating Revenues $ 0.9 $ 4.7 $ 4.9 Operation and Maintenance Expense ($ millions): Twelve Months Ended December 31 As Reported If ASU 2014-09 Had Been in Effect 2019 2018 2017 Operation and Maintenance Expense $ 67.2 $ 69.5 $ 63.4
Retirement Benefit Costs	Retirement Benefit Costs— to the Consolidated Financial Statements). In the first quarter of 2018 , the Company adopted ASU No. 2017-07, 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-K , 2019 , 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 ( Income , N , 2019 resulted in a reduction of “Operations and Maintenance” and an increase in “Other (Income) , N . There are $4.6 million, $5.5 million and $5.7 million of non-service (Income) Expense, N , 2019 , 2018 and 2017 , respectively, net of amounts deferred as regulatory assets for future recovery.
Depreciation and Amortization	Depreciation and Amortization depreciable property balances at the beginning and end of each year: 2019 – 3.41%, 2018 – 3.38% and 2017 – 3.45%.
Stock-based Employee Compensation	Stock-based Employee Compensation .
Sales and Consumption Taxes	Sales and Consumption Taxes , 2019 .
Income Taxes	Income Taxes— Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. The Company accounts for income taxes in accordance with the FASB Codification guidance on Income Taxes, which requires an asset and liability approach for the financial accounting and reporting of income taxes. Significant judgments and estimates are required in determining the current and deferred tax assets and liabilities. The Company’s deferred tax assets and liabilities reflect its best assessment of estimated future taxes to be paid. In accordance with the FASB Codification, the Company periodically assesses the realization of its deferred tax assets and liabilities and adjusts the income tax provision, the current tax liability and deferred taxes in the period in which the facts and circumstances which gave rise to the revision become known.
Dividends	Dividends ended December 31 , 2019 the Company paid quarterly dividends of $0.37 per share, resulting in an annualized dividend rate of $1.48 per common share. For the years ended December 31 , 2018 and 2017 , the Company paid quarterly dividends of $0.365 and $0.36 per common share, respectively, resulting in annualized dividend rates of $1.46 and $1.44 per common share, respectively. At its January 2020 meeting, the Unitil Corporation Board of Directors declared a quarterly dividend on the Company’s common stock of $0.375 per share, an increase of $0.005 per share on a quarterly basis, resulting in an increase in the effective annualized dividend rate to $1.50 per share from $1.48 per share.
Cash and Cash Equivalents	Cash and Cash Equivalents (ISO-NE) ISO-NE. 2-1/2 , 2019 and 2018 , the Unitil subsidiaries had deposited $1.9 million and $3.5 million, respectively to satisfy their ISO-NE
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts written-off shut-off. In June 2016, the FASB issued ASU 2016-13,
Accrued Revenue	Accrued Revenue— . Accrued Revenue (millions) December 31, 2019 2018 Regulatory Assets—Current $ 35.8 $ 41.3 Unbilled Revenues 14.2 13.4 Total Accrued Revenue $ 50.0 $ 54.7
Exchange Gas Receivable	Exchange Gas Receivable average cost . The following table shows the components of Exchange Gas Receivable as of December 31 , 201 9 and 2018 . Exchange Gas Receivable (millions) December 31, 201 9 201 8 Northern Utilities $ 5.5 $ 7.5 Fitchburg 0.6 0.6 Total Exchange Gas Receivable $ 6.1 $ 8.1
Gas Inventory	Gas Inventory Gas Inventory (millions) December 31, 201 9 201 8 Natural Gas $ 0.4 $ 0.3 Propane 0.3 0.4 Liquefied Natural Gas & Other 0.1 0.1 Total Gas Inventory $ 0.8 $ 0.8 The Company also has an inventory of Materials and Supplies in the amounts of $7.9 million and $7.0 million as of December 31, 2019 and December 31, 2018, respectively. These amounts are recorded at weighted average cost.
Utility Plant	Utility Plant 2019 , 2018 and 2017 , respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At December 31 , 2019 and 2018 , the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $96.0 million and $90.7 million, respectively.
Regulatory Accounting	Regulatory Accounting Regulatory Assets consist of the following (millions) December 31 , 2019 2018 Retirement Benefits $ 88.9 $ 72.0 Energy Supply & Other Rate Adjustment Mechanisms 31.0 38.4 Deferred Storm Charges 5.6 6.3 Environmental 7.2 7.9 Income Taxes 4.2 5.7 Other Deferred Charges 10.9 10.0 Total Regulatory Assets 147.8 140.3 Less: Current Portion of Regulatory Assets (1) 35.8 41.3 Regulatory Assets—noncurrent $ 112.0 $ 99.0 (1) Reflects amounts included in the Accrued Revenue on the Company’s Consolidated Balance Sheets. Regulatory Liabilities consist of the following (millions) December 31, 2019 2018 Rate Adjustment Mechanisms $ 6.0 $ 11.5 Income Taxes (Note 9) 47.6 47.0 Other 0.4 — Total Regulatory Liabilities 54.0 58.5 Less: Current Portion of Regulatory Liabilities 7.4 11.5 Regulatory Liabilities—noncurrent $ 46.6 $ 47.0 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 December 31, 2019 are $ 7.6
Leases	Leases— longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows the Company to carryforward the historical lease classification. The Company also elected the practical expedient related to land easements, allowing the Company to carry forward its current accounting treatment for land easements on existing agreements. The Company made an accounting policy election to keep leases with an initial term of 12 months or less off of the balance sheet. The Company recognizes those lease payments in the Consolidated Statements of Earnings on a straight-line basis over the lease term. The adoption of the standard resulted in recognition of approximately $ 4.2
Derivatives	Derivatives The Company previously operated a regulatory approved hedging program for Northern Utilities designed to fix or cap a portion of its gas supply costs for the coming years of service, which included use of derivative instruments. The hedging program was terminated in 2018 . Under the hedging program previously operated by Northern Utilities, any gains or losses resulting from the change in the fair value of these derivatives were passed through to ratepayers directly through Northern Utilities’ Cost of Gas Clause. The fair value of these derivatives was 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 recorded gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassified these gains or losses into Cost of Gas Sales when the gains and losses were passed through to customers through the Cost of Gas Clause. The Company had no derivative assets or liabilities recorded on its Consolidated Balance Sheets as of December 31 , 2019 and December 31 , 2018 . There were no , 2019 and 2018 . There were no losses / (gains) reclassified into the Consolidated Statements of Earnings for the years ended December 31 , 2019 and 2018 . As discussed below in the “Fitchburg
Investments in Marketable Securities	Investments in Marketable Securities . At December 31, 2019 and 2018, the fair value of the Company’s investments in these trading securities, which are recorded on the Consolidated Balance Sheets in Other Assets, were $5.6 million and $4.8 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 (Income) Expense, Net. Fair Value of Marketable Securities (millions) December 31, 2019 2018 Money Market Funds $ 5.6 $ 4.8 Total Marketable Securities $ 5.6 $ 4.8 The Company also sponsors the Unitil Corporation Deferred Compensation Plan (the “DC Plan”). The DC Plan is a non-qualified tax-deferred , 2019 , is open to senior management or other highly compensated employees as determined by the Company’s Board of Directors, and may also be used for recruitment and retention purposes for newly hired senior executives. The DC Plan design mirrors the Company’s Tax Deferred Savings and Investment Plan formula, but provides for contributions on compensation above the IRS limit, which will allow participants to defer up to 85 % of base salary, and up to 85 % of any cash incentive for retirement. The Company may also elect to make discretionary contributions on behalf of any participant in an amount determined by the Company’s Board of Directors. A trust has been established to invest the funds associated with the DC Plan. At December 31 , 2019 and 2018 , the fair value of the Company’s investments in these trading securities related to the DC Plan, which are recorded on the Consolidated Balance Sheets in Other Assets, were $0.2 million and $0 , 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 (Income) Expense, Net. Fair Value of Marketable Securities (millions) December 31 , 2019 2018 Equity Funds $ 0.1 $ — Money Market Funds 0.1 — Total Marketable Securities $ 0.2 $ —
Energy Supply Obligations	Energy Supply Obligations December 31, Energy Supply Obligations consist of the following: (millions) 2019 2018 Current: Exchange Gas Obligation $ 5.5 $ 7.5 Renewable Energy Portfolio Standards 4.7 5.6 Power Supply Contract Divestitures 0.3 0.3 Total Energy Supply Obligations—Current 10.5 13.4 Noncurrent: Power Supply Contract Divestitures 0.3 0.6 Total Energy Supply Obligations $ 10.8 $ 14.0 Exchange Gas Obligation— Renewable Energy Portfolio Standards— 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 defer costs for RPS compliance which are recorded in the 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 the purchase of clean energy and/or RECs pursuant to Massachusetts legislation, specifically, An Act Relative to Green Communities (“Green Communities Act”, 2008), An Act Relative to Competitively Priced Electricity in the Commonwealth (2012) and An Act to Promote Energy Diversity (“Energy Diversity Act”, 2016). The generating facilities associated with four of these contracts have been constructed and are now operating. Since 2017, the Company has participated in two major statewide procurements which resulted in contracts for imported hydroelectric power and associated transmission and for offshore wind generation. The contracts were approved by the MDPU in the second quarter of 2019. Additional long-term clean energy contracts are expected in compliance with the Energy Diversity Act and An Act to Promote a Clean Energy Future (2018) . 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— stranded costs. As of December 31, 2019, Fitchburg has fully-recovered its power supply-related stranded costs and Unitil Energy $0.6 million remaining to recover. 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).
Retirement Benefit Obligations	Retirement Benefit Obligations —The Company sponsors the Pension Plan, which is a defined benefit pension plan. Effective January 1, 2010, the Pension Plan was closed to new non-union non-qualified The Company records on its balance sheets as an asset or liability the overfunded or underfunded status of its retirement benefit obligations (RBO) based on the projected benefit obligations. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates (See Note 10).
Off-Balance Sheet Arrangements	Off-Balance Sheet Arrangements , 2019 , the Company does not have any significant arrangements that would be classified as Off-Balance
Commitments and Contingencies	Commitments and Contingencies , 2019 , the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (See Note 8) .
Environmental Matters	Environmental Matters , 2019 , there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 8 , Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.
Recently Issued Pronouncements	Recently Issued Pronouncements – 2019-12, In February 2016, the FASB issued ASU No. 2016-02, Other than the pronouncements discussed above, there are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.
Subsequent Events	Subsequent Events

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Components of Gas and Electric Operating Revenue	In the following tables, revenue is classified by the types of goods/services rendered and market/customer type. Twelve Months Ended Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 81.4 $ 121.5 $ 202.9 Commercial & Industrial 120.1 93.8 213.9 Other 10.6 7.8 18.4 Total Billed and Unbilled Revenue 212.1 223.1 435.2 Rate Adjustment Mechanism Revenue (8.7 ) 10.8 2.1 Total Gas and Electric Operating Revenues $ 203.4 $ 233.9 $ 437.3 Twelve Months Ended December 31, 2018 Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 81.4 $ 123.6 $ 205.0 Commercial & Industrial 119.7 96.4 216.1 Other 9.6 8.7 18.3 Total Billed and Unbilled Revenue 210.7 228.7 439.4 Rate Adjustment Mechanism Revenue 5.4 (5.4 ) — Total Gas and Electric Operating Revenues $ 216.1 $ 223.3 $ 439.4 Twelve Months Ended December 31, 2017 Gas and Electric Operating Revenues (millions): Gas Electric Total Billed and Unbilled Revenue: Residential $ 71.2 $ 107.9 $ 179.1 Commercial & Industrial 102.8 87.7 190.5 Other 13.5 6.0 19.5 Total Billed and Unbilled Revenue 187.5 201.6 389.1 Rate Adjustment Mechanism Revenue 6.5 4.6 11.1 Total Gas and Electric Operating Revenues $ 194.0 $ 206.2 $ 400.2
Schedule of Other Operating Revenues and Operating Expenses	If ASU 2014-09 , the result would have been corresponding reductions of $1.1 million in both “Other” in the “Operating Revenues” section of the Consolidated Statements of Earnings and “Operation and Maintenance” in the “Operating Expenses” section of the Company’s Consolidated Statements of Earnings as shown in the tables below. Other Operating Revenues ($ millions): Twelve Months Ended December 31 As Reported If ASU 2014-09 Had Been in Effect 2019 2018 2017 Usource Contract Revenue $ 1.1 $ 5.7 $ 6.0 Less: Revenue Sharing Payments (0.2 ) (1.0 ) (1.1 ) Total Other Operating Revenues $ 0.9 $ 4.7 $ 4.9 Operation and Maintenance Expense ($ millions): Twelve Months Ended December 31 As Reported If ASU 2014-09 Had Been in Effect 2019 2018 2017 Operation and Maintenance Expense $ 67.2 $ 69.5 $ 63.4
Components of Accrued Revenue	The following table shows the components of Accrued Revenue as of December 31, 2019 and 2018 . Accrued Revenue (millions) December 31, 2019 2018 Regulatory Assets—Current $ 35.8 $ 41.3 Unbilled Revenues 14.2 13.4 Total Accrued Revenue $ 50.0 $ 54.7
Components of Exchange Gas Receivable	The following table shows the components of Exchange Gas Receivable as of December 31 , 201 9 and 2018 . Exchange Gas Receivable (millions) December 31, 201 9 201 8 Northern Utilities $ 5.5 $ 7.5 Fitchburg 0.6 0.6 Total Exchange Gas Receivable $ 6.1 $ 8.1
Components of Gas Inventory	The following table shows the components of Gas Inventory as of December 31, 2019 and 2018. Gas Inventory (millions) December 31, 201 9 201 8 Natural Gas $ 0.4 $ 0.3 Propane 0.3 0.4 Liquefied Natural Gas & Other 0.1 0.1 Total Gas Inventory $ 0.8 $ 0.8
Regulatory Assets	Regulatory Assets consist of the following (millions) December 31 , 2019 2018 Retirement Benefits $ 88.9 $ 72.0 Energy Supply & Other Rate Adjustment Mechanisms 31.0 38.4 Deferred Storm Charges 5.6 6.3 Environmental 7.2 7.9 Income Taxes 4.2 5.7 Other Deferred Charges 10.9 10.0 Total Regulatory Assets 147.8 140.3 Less: Current Portion of Regulatory Assets (1) 35.8 41.3 Regulatory Assets—noncurrent $ 112.0 $ 99.0 (1) Reflects amounts included in the Accrued Revenue on the Company’s Consolidated Balance Sheets.
Regulatory Liabilities	Regulatory Liabilities consist of the following (millions) December 31, 2019 2018 Rate Adjustment Mechanisms $ 6.0 $ 11.5 Income Taxes (Note 9) 47.6 47.0 Other 0.4 — Total Regulatory Liabilities 54.0 58.5 Less: Current Portion of Regulatory Liabilities 7.4 11.5 Regulatory Liabilities—noncurrent $ 46.6 $ 47.0
Fair Value of Marketable Securities	Changes in the fair value of these investments are recorded in Other (Income) Expense, Net. Fair Value of Marketable Securities (millions) December 31 , 2019 2018 Equity Funds $ 0.1 $ — Money Market Funds 0.1 — Total Marketable Securities $ 0.2 $ —
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. December 31, Energy Supply Obligations consist of the following: (millions) 2019 2018 Current: Exchange Gas Obligation $ 5.5 $ 7.5 Renewable Energy Portfolio Standards 4.7 5.6 Power Supply Contract Divestitures 0.3 0.3 Total Energy Supply Obligations—Current 10.5 13.4 Noncurrent: Power Supply Contract Divestitures 0.3 0.6 Total Energy Supply Obligations $ 10.8 $ 14.0
Deferred Compensation Plan [Member]
Fair Value of Marketable Securities	Changes in the fair value of these investments are recorded in Other (Income) Expense, Net. Fair Value of Marketable Securities (millions) December 31, 2019 2018 Money Market Funds $ 5.6 $ 4.8 Total Marketable Securities $ 5.6 $ 4.8

Quarterly Financial Informati_2

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information	Three Months Ended March 31, June 30, September 30, December 31, 2019 2018 2019 2018 2019 2018 2019 2018 Total Operating Revenues $ 152.1 $ 145.8 $ 84.4 $ 84.5 $ 85.3 $ 88.2 $ 116.4 $ 125.6 Operating Income $ 28.8 $ 28.1 $ 12.3 $ 10.6 $ 10.0 $ 10.3 $ 22.0 $ 22.2 Net Income Applicable to Common $ 26.5 $ 15.6 $ 4.0 $ 3.6 $ 2.3 $ 2.8 $ 11.4 $ 11.0 Per Share Data: Earnings Per Common Share $ 1.78 $ 1.06 $ 0.27 $ 0.24 $ 0.15 $ 0.19 $ 0.77 $ 0.74 Dividends Paid Per Common Share $ 0.37 $ 0.365 $ 0.37 $ 0.365 $ 0.37 $ 0.365 $ 0.37 $ 0.365

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Significant Segment Financial Data	The following table provides significant segment financial data for the years ended December 31, 2019, 2018 and 2017 (millions): Year Ended December 31, 2019 Gas Electric Non- Regulated Other Total Revenues: Billed and Unbilled Revenue $ 212.1 $ 223.1 $ $ $ 435.2 Rate Adjustment Mechanism Revenue (8.7 ) 10.8 — — 2.1 Other Operating Revenue— Non-Regulated — — 0.9 — 0.9 Total Operating Revenues 203.4 233.9 0.9 — 438.2 Interest Income 1.2 0.9 0.2 0.6 2.9 Interest Expense 14.4 9.4 — 2.8 26.6 Depreciation & Amortization Expense 28.5 22.6 — 0.9 52.0 Income Tax Expense (Benefit) 7.2 4.2 3.8 (1.4 ) 13.8 Segment Profit 19.1 11.5 10.2 3.4 44.2 Segment Assets 823.3 529.3 0.3 17.9 1,370.8 Capital Expenditures 74.0 39.6 — 5.6 119.2 Year Ended December 31, 2018 Revenues: Billed and Unbilled Revenue $ 210.7 $ 228.7 $ — $ — $ 439.4 Rate Adjustment Mechanism Revenue 5.4 (5.4 ) — — — Other Operating Revenue— Non-Regulated — — 4.7 — 4.7 Total Operating Revenues 216.1 223.3 4.7 — 444.1 Interest Income 0.8 0.8 0.2 0.6 2.4 Interest Expense 14.2 9.0 — 3.2 26.4 Depreciation & Amortization Expense 24.9 23.1 0.1 2.3 50.4 Income Tax Expense (Benefit) 7.1 4.2 0.5 (3.4 ) 8.4 Segment Profit 18.8 11.4 1.3 1.5 33.0 Segment Assets 764.1 484.2 6.9 43.1 1,298.3 Capital Expenditures 70.8 28.4 — 3.2 102.4 Year Ended December 31, 2017 Revenues $ 194.0 $ 206.2 $ 6.0 $ — $ 406.2 Interest Income 0.7 1.0 0.1 0.6 2.4 Interest Expense 13.7 8.8 — 3.0 25.5 Depreciation & Amortization Expense 22.4 23.4 0.1 1.0 46.9 Income Tax Expense (Benefit) 10.7 7.5 0.7 (1.4 ) 17.5 Segment Profit 16.4 11.9 1.2 (0.5 ) 29.0 Segment Assets 714.3 476.9 6.7 44.0 1,241.9 Capital Expenditures 72.1 33.7 — 13.5 119.3

Allowance for Doubtful Accoun_2

Allowance for Doubtful Accounts (Tables)	12 Months Ended
	Dec. 31, 2019
Allowance for Doubtful Accounts	The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2017 —2019 (millions): ALLOWANCE FOR DOUBTFUL ACCOUNTS Balance at Beginning of Period Provision Recoveries Accounts Written Off Balance at End of Period Year Ended December 31, 2019 Electric $ 0.5 $ 3.0 $ 0.3 $ 3.2 $ 0.6 Gas 0.8 1.9 0.5 2.8 0.4 Other — — — — — $ 1.3 $ 4.9 $ 0.8 $ 6.0 $ 1.0 Year Ended December 31, 2018 Electric $ 0.9 $ 3.2 $ 0.3 $ 3.9 $ 0.5 Gas 0.6 2.9 0.3 3.0 0.8 Other 0.1 (0.1 ) — — — $ 1.6 $ 6.0 $ 0.6 $ 6.9 $ 1.3 Year Ended December 31, 2017 Electric $ 0.8 $ 1.8 $ 0.3 $ 2.0 $ 0.9 Gas 0.2 1.9 0.3 1.8 0.6 Other 0.1 — — — 0.1 $ 1.1 $ 3.7 $ 0.6 $ 3.8 $ 1.6

Debt and Financing Arrangemen_2

Debt and Financing Arrangements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value of Long Term Debt	Estimated Fair Value of Long-Term Debt (millions) December 31, 2019 2018 Estimated Fair Value of Long-Term Debt $ 518.7 $ 422.0
Details on Long Term Debt	Details on long-term debt at December 31 , 2019 and 2018 are shown below: Long-Term Debt (millions) December 31, 2019 2018 Unitil Corporation: 6.33 % Senior Notes, Due May 1, 2022 $ 20.0 $ 20.0 3.70 % Senior Notes, Due August 1, 2026 30.0 30.0 3.43% Senior Notes, Due December 18, 2029 30.0 — Unitil Energy First Mortgage Bonds: 5.24 % Senior Secured Notes, Due March 2, 2020 5.0 10.0 8.49 % Senior Secured Notes, Due October 14, 2024 4.5 6.0 6.96 % Senior Secured Notes, Due September 1, 2028 18.0 20.0 8.00 % Senior Secured Notes, Due May 1, 2031 15.0 15.0 6.32 % Senior Secured Notes, Due September 15, 2036 15.0 15.0 4.18 % Senior Secured Notes, Due November 30, 2048 30.0 30.0 Fitchburg: 6.75 % Senior Notes, Due November 30, 2023 3.8 5.7 6.79 % Senior Notes, Due October 15, 2025 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 5.90 % Senior Notes, Due December 15, 2030 15.0 15.0 7.98 % Senior Notes, Due June 1, 2031 14.0 14.0 4.32 % Senior Notes, Due November 1, 2047 15.0 15.0 Northern Utilities: 5.29 % Senior Notes, Due March 2, 2020 8.2 16.6 3.52 % Senior Notes, Due November 1, 2027 20.0 20.0 7.72 % Senior Notes, Due December 3, 2038 50.0 50.0 4.42 % Senior Notes , Due October 15, 2044 50.0 50.0 4.32 % Senior Notes, Due November 1, 2047 30.0 30.0 4.04% Senior Notes, Due September 12, 2049 40.0 — Granite State: 3.72 % Senior Notes , Due November 1, 2027 15.0 15.0 Total Long-Term Debt 460.5 409.3 Less: Unamortized Debt Issuance Costs 3.5 3.5 Total Long-Term Debt, net of Unamortized Debt Issuance Costs 457.0 405.8 Less: Current Portion (1) 19.5 18.4 Total Long-Term Debt, Less Current Portion $ 437.5 $ 387.4 (1) The Current Portion of Long-Term Debt includes sinking fund payments.
Summary of Interest Expense and Interest Income	A summary of interest expense and interest income is provided in the following table: Interest Expense, N 2019 2018 2017 Interest Expense Long-Term Debt $ 22.9 $ 23.1 $ 21.8 Short-Term Debt 3.0 2.6 2.5 Regulatory Liabilities 0.7 0.7 1.2 Subtotal Interest Expense 26.6 26.4 25.5 Interest Income Regulatory Assets (0.8 ) (0.8 ) (0.7 ) AFUDC (1) (2.1 ) (1.6 ) (1.7 ) Subtotal Interest Income (2.9 ) (2.4 ) (2.4 ) Total Interest Expense, N $ 23.7 $ 24.0 $ 23.1 (1) AFUDC—Allowance for Funds Used During Construction
Borrowing Limits Amounts Outstanding and Amounts Available under Credit Facility	The following table details the borrowing limits, amounts outstanding and amounts available under the revolving Credit Facility as of December 31, 2019 and December 31, 2018: Revolving Credit Facility (millions) December 31, 201 9 201 8 Limit $ 120.0 $ 120.0 Short-Term Borrowings Outstanding $ 58.6 $ 82.8 Letters of Credit Outstanding $ 0.1 $ — Available $ 61.3 $ 37.2
Classification of the Company Lease Obligations	The balance sheet classification of the Company’s lease obligations was as follows: December 31, Lease Obligations (millions) 2019 2018 Operating Lease Obligations: Other Current Liabilities (current portion) $ 1.2 $ — Other Noncurrent Liabilities (long-term portion) 2.8 — Total Operating Lease Obligations 4.0 — Capital Lease Obligations: Other Current Liabilities (current portion) 0.2 3.1 Other Noncurrent Liabilities (long-term portion) 0.3 2.7 Total Capital Lease Obligations 0.5 5.8 Total Lease Obligations $ 4.5 $ 5.8
Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases	The following table is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31, 2019. The payments for capital leases consist of $0.2 million of current Capital Lease Obligations, which are included in Other Current Liabilities, and $0.3 million of noncurrent Capital Lease Obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2019. The payments for operating leases consist of $1.2 million of current operating lease obligations , which are included in Other Current Liabilities and $2.8 million of noncurrent operating lease obligations, which are included in Other Noncurrent Liabilities, on the Company’s Consolidated Balance Sheets as of December 31, 2019. Lease Payments ($000’s) Year Ending December 31, Operating Capital 2020 $ 1,355 $ 262 2021 1,185 161 2022 904 97 2023 604 55 2024 274 — 2025 139 — Total Payments 4,461 575 Less: Interest 435 29 Amount of Lease Obligations Recorded on Consolidated Balance Sheets $ 4,026 $ 546 Operating lease obligations are based on the net present value of the remaining lease payments over the remaining lease term. In determining the present value of lease payments, the Company used the interest rate stated in each lease agreement. As of December 31, 2019, the weighted average remaining lease term is 3.9 years and the weighted average operating discount rate used to determine the operating lease obligations was 5.2 %. Disclosures Related to Periods Prior to the Adoption of ASU NO. 2016-02—Leases (See Note 1). The payment amounts in the following table are as of December 31, 2018. Lease Payments ($000’s) Year Ending December 31, Operating Capital 2019 $ 1,372 $ 3,069 2020 1,138 2,535 2021 969 93 2022 689 32 2023 390 14 2024 120 — Total Payments $ 4,678 $ 5,743

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Restricted Shares Issued in Conjunction with Stock Plan	Restricted Shares issued for 2017 – 2019 in conjunction with the Stock Plan are presented in the following table: Issuance Date Shares Aggregate 1/30/17 34,930 $1.6 1/29/18 37,510 $1.6 1/29/19 33,150 $1.6
Restricted Stock Units Issued	The equity portion of Restricted Stock Units activity during 2019 and 2018 in conjunction with the Stock Plan are presented in the following table: Restricted Stock Units (Equity Portion) 2019 2018 Units Weighted Average Stock Price Units Weighted Average Stock Price Beginning Restricted Stock Units 61,789 $ 38.25 52,224 $ 36.22 Restricted Stock Units Granted 6,943 $ 63.50 7,892 $ 49.63 Dividend Equivalents Earned 1,632 $ 58.15 1,673 $ 47.85 Restricted Stock Units Settled — — — — Ending Restricted Stock Units 70,364 $ 41.20 61,789 $ 38.25
Reconciliation of Basic and Diluted Earnings Per Share	The following table reconciles basic and diluted earnings per share (EPS). (Millions except shares and per share data) 2019 2018 2017 Earnings Available to Common Shareholders $ 44.2 $ 33.0 $ 29.0 Weighted Average Common Shares Outstanding—Basic (000’s) 14,894 14,824 14,095 Plus: Diluted Effect of Incremental Shares (000’s) 6 5 7 Weighted Average Common Shares Outstanding—Diluted (000’s) 14,900 14,829 14,102 Earnings per Share—Basic and Diluted $ 2.97 $ 2.23 $ 2.06
Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share	The following table shows the number of weighted average non-vested 2019 2018 2017 Weighted Average Non-Vested — 6,102 8,733

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
Gas And Electric Supply Contractual Obligations	The table below lists the Company’s known specified gas and electric supply contractual obligations as of December 31, 2019. Payments Due by Period Gas and Electric Supply Contractual Obligations (millions) as of December 31, 2019 Total 2020 2021 2022 2023 2024 2025 & Gas Supply Contracts $ 584.8 $ 45.6 $ 48.7 $ 48.0 $ 45.5 $ 36.5 $ 360.5 Electric Supply Contracts 14.2 2.0 1.2 1.2 1.2 1.2 7.4 Total $ 599.0 $ 47.6 $ 49.9 $ 49.2 $ 46.7 $ 37.7 $ 367.9
Environmental Obligations Recognized by Company	The following table sets forth a summary of changes in the Company’s liability for the current and long-term portions of the Company’s environmental obligations, which are included in Other Current Liabilities and Other Noncurrent Liabilities, respectively, on the Company’s Consolidated Balance Sheets as of December 31, 2019 and 2018. Environmental Obligations (millions) Fitchburg Northern Utilities Total 2019 2018 2019 2018 2019 2018 Total Balance at Beginning of Period $ — $ 0.1 $ 2.0 $ 2.0 $ 2.0 $ 2.1 Additions — — 0.9 0.3 0.9 0.3 Less: Payments / Reductions — 0.1 0.2 0.3 0.2 0.4 Total Balance at End of Period $ — $ — $ 2.7 $ 2.0 $ 2.7 $ 2.0 Less: Current Portion — — 0.6 0.6 0.6 0.6 Noncurrent Balance at December 31, $ — $ — $ 2.1 $ 1.4 $ 2.1 $ 1.4

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Provisions for Federal and State Income Taxes	Provisions for Federal a nd ($000’s) 2019 2018 2017 Current Income Tax Provision Federal $ — $ — $ — State 351 355 — Total Current Income Taxes $ 351 $ 355 $ — Deferred Income Provision Federal $ 9,340 $ 5,032 $ 13,675 State 4,117 3,006 3,862 Total Deferred Income Taxes 13,457 8,038 17,537 Total Income Tax Expense $ 13,808 $ 8,393 $ 17,537
Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate	The differences between the Company’s provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below: 2019 2018 2017 Statutory Federal Income Tax Rate 21 % 21 % 34 % Income Tax Effects of: State Income Taxes, net 6 6 6 Utility Plant Differences (3 ) (7 ) (1 ) Tax Credits — — (1 ) Other, net — — — Effective Income Tax Rate 24 % 20 % 38 %
Deferred Tax Assets and Liabilities	Temporary differences which gave rise to deferred tax assets and liabilities in 2019 and 2018 are shown below: Temporary Differences (000’s) 2019 2018 Deferred Tax Assets Retirement Benefit Obligations $ 36,551 $ 32,249 Net Operating Loss Carryforwards 1,609 10,773 Tax Credit Carryforwards 1,489 2,704 Other, net 1,589 1,571 Total Deferred Tax Assets $ 41,238 $ 47,297 Deferred Tax Liabilities Utility Plant Differences $ 134,011 $ 132,682 Regulatory Assets & Liabilities 5,239 6,429 Other, net 5,539 5,964 Total Deferred Tax Liabilities 144,789 145,075 Net Deferred Tax Liabilities $ 103,551 $ 97,778

Retirement Benefit Plans (Table

Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations	The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations: 2019 2018 2017 Used to Determine Plan costs for years ended December 31: Discount Rate 4.25 % 3.60 % 4.10 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Expected Long-term rate of return on plan assets 7.50 % 7.75 % 7.75 % Health Care Cost Trend Rate Assumed for Next Year 7.00 % 7.50 % 8.00 % Ultimate Health Care Cost Trend Rate 4.50 % 4.50 % 4.00 % Year that Ultimate Health Care Cost Trend Rate is reached 2024 2024 2025 Used to Determine Benefit Obligations at December 31: Discount Rate 3.25 % 4.25 % 3.60 % Rate of Compensation Increase 3.00 % 3.00 % 3.00 % Health Care Cost Trend Rate Assumed for Next Year 7.00 % 7.00 % 7.50 % Ultimate Health Care Cost Trend Rate 4.50 % 4.50 % 4.50 % Year that Ultimate Health Care Cost Trend Rate is reached 2029 2024 2024
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 2019 2018 2017 2019 2018 2017 2019 2018 2017 Service Cost $ 3,104 $ 3,393 $ 3,295 $ 2,304 $ 2,933 $ 2,974 $ 247 $ 487 $ 460 Interest Cost 6,484 5,878 6,057 3,426 3,404 3,913 567 404 392 Expected Return on Plan Assets (8,475 ) (7,785 ) (7,306 ) (1,645 ) (1,635 ) (1,347 ) — — — Prior Service Cost Amortization 320 324 263 1,213 1,309 1,399 56 189 189 Actuarial Loss Amortization 4,324 5,786 4,662 227 1,383 2,098 628 486 295 Sub-total 5,757 7,596 6,971 5,525 7,394 9,037 1,498 1,566 1,336 Amounts Capitalized or Deferred (2,227 ) (3,465 ) (3,122 ) (2,317 ) (3,416 ) (4,515 ) (430 ) (451 ) (397 ) NPBC Recognized $ 3,530 $ 4,131 $ 3,849 $ 3,208 $ 3,978 $ 4,522 $ 1,068 $ 1,115 $ 939
Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status	The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status (000’s) : Pension Plan PBOP Plan SERP Change in Plan Assets: 2019 2018 2019 2018 2019 2018 Plan Assets at Beginning of Year $ 107,808 $ 102,315 $ 21,109 $ 20,234 $ — $ — Actual Return on Plan Assets 17,908 (6,149 ) 3,808 (1,085 ) — — Employer Contributions 6,916 16,628 4,000 4,000 610 401 Participant Contributions — — 121 153 — — Benefits Paid (6,877 ) (4,986 ) (1,758 ) (2,193 ) (610 ) (401 ) Plan Assets at End of Year $ 125,755 $ 107,808 $ 27,280 $ 21,109 $ — $ — Change in PBO: PBO at Beginning of Year $ 156,197 $ 166,921 $ 81,005 $ 94,122 $ 13,754 $ 11,723 Service Cost 3,104 3,393 2,304 2,933 247 487 Interest Cost 6,484 5,878 3,426 3,404 567 404 Participant Contributions — — 121 153 — — Plan Amendments — — — — 225 — Benefits Paid (6,877 ) (4,986 ) (1,758 ) (2,193 ) (610 ) (401 ) Actuarial (Gain) or Loss 23,227 (15,009 ) 10,559 (17,414 ) 3,576 1,541 PBO at End of Year $ 182,135 $ 156,197 $ 95,657 $ 81,005 $ 17,759 $ 13,754 Funded Status: Assets vs PBO $ (56,380 ) $ (48,389 ) $ (68,377 ) $ (59,896 ) $ (17,759 ) $ (13,754 )
Employer Contributions, Participant Contributions and Benefit Payments	The following table represents employer contributions, participant contributions and benefit payments (000’s). Pension Plan PBOP Plan SERP 2019 2018 2017 2019 2018 2017 2019 2018 2017 Employer Contributions $ 6,916 $ 16,628 $ 4,100 $ 4,000 $ 4,000 $ 4,000 $ 610 $ 401 $ 34 Participant Contributions $ — $ — $ — $ 121 $ 153 $ 126 $ — $ — $ — Benefit Payments $ 6,877 $ 4,986 $ 5,574 $ 1,758 $ 2,193 $ 2,405 $ 610 $ 401 $ 34
Estimated Future Benefit Payments	The following table represents estimated future benefit payments (000’s). Estimated Future Benefit Payments Pension PBOP SERP 2020 $ 6,706 $ 2,774 $ 653 2021 7,192 3,035 653 2022 6,903 3,167 651 2023 7,687 3,341 650 2024 8,622 3,622 648 2025 - 2029 49,511 21,761 6,037
Pension Plans
Schedule of Allocation of Plan Assets	The actual investment allocations are shown in the tables below. Pension Plan Target Allocation 2020 Actual Allocation at December 31, 2019 2018 2017 Equity Funds 53 % 54 % 49 % 49 % Debt Funds 37 % 36 % 40 % 34 % Real Estate Fund 10 % 9 % 10 % 10 % Asset Allocation Fund (1) — — — 6 % Other (2) — 1 % 1 % 1 % Total 100 % 100 % 100 % (1) Represents investments in an asset allocation fund. This fund invests in both equity and debt securities. (2) Represents investments being held in cash equivalents as of December 31, 2019, December 31, 2018 and December 31, 2017 pending payment of benefits. Assets measured at fair value on a recurring basis for the Pension Plan as of December 31, 2019 and 2018 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of December 31, Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 2019 Pension Plan Assets: Mutual Funds: Equity Funds $ 68,848 $ 68,848 $ — $ — Fixed Income Funds 44,980 44,980 — — Total Mutual Funds 113,828 113,828 — — Cash Equivalents 750 750 Total Assets in the Fair Value Hierarchy $ 114,578 $ 114,578 $ — $ — Real Estate Fund–Measured at Net Asset Value 11,177 Total Assets $ 125,755 2018 Pension Plan Assets: Mutual Funds: Equity Funds $ 52,884 $ 52,884 $ — $ — Fixed Income Funds 43,281 43,281 — — Total Mutual Funds 96,165 96,165 — — Cash Equivalents 1,202 1,202 Total Assets in the Fair Value Hierarchy $ 97,367 $ 97,367 $ — $ — Real Estate Fund–Measured at Net Asset Value 10,441 Total Assets $ 107,808
Other Postretirement Benefit Plans, Defined Benefit
Schedule of Allocation of Plan Assets	The actual investment allocations are shown in the tables below. PBOP Plan Target Allocation 2020 Actual Allocation at December 31, 2019 2018 2017 Equity Funds 55 % 56 % 53 % 56 % Debt Funds 45 % 44 % 47 % 42 % Other (1) — — — 2 % Total 100 % 100 % 100 % (1) Represents investments being held in cash equivalents as of December 31, 2017 pending transfer into debt and equity funds. Assets measured at fair value on a recurring basis for the PBOP Plan as of December 31, 2019 and 2018 are as follows (000’s): Fair Value Measurements at Reporting Date Using Description Balance as of December 31, Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 2019 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 11,888 $ 11,888 $ — $ — Equity Funds 15,392 15,392 — — Total Assets $ 27,280 $ 27,280 $ — $ — 2018 PBOP Plan Assets: Mutual Funds: Fixed Income Funds $ 9,905 $ 9,905 $ — $ — Equity Funds 11,204 11,204 — — Total Assets $ 21,109 $ 21,109 $ — $ —

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended								12 Months Ended
	Jan. 31, 2020$ / shares	Dec. 31, 2019USD ($)$ / shares	Sep. 30, 2019$ / shares	Jun. 30, 2019$ / shares	Mar. 31, 2019$ / shares	Dec. 31, 2018USD ($)$ / shares	Sep. 30, 2018$ / shares	Jun. 30, 2018$ / shares	Mar. 31, 2018$ / shares	Dec. 31, 2019USD ($)EntitySubsidiarymi$ / shares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares	Jan. 01, 2019USD ($)
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Entity										3
Length Of Pipeline | mi										86
Revenue sharing payments										$ 0.2	$ 1	$ 1.1
Depreciation rate based on average depreciable property balance										3.41%	3.38%	3.45%
Common stock dividend paid per share | $ / shares		$ 0.37	$ 0.37	$ 0.37	$ 0.37	$ 0.365	$ 0.365	$ 0.365	$ 0.365	$ 1.48	$ 1.46	$ 1.44
Common stock dividend per share, declared | $ / shares										$ 1.48	$ 1.46	$ 1.44
Inventory of materials and supplies		$ 0.8				$ 0.8				$ 0.8	$ 0.8
Average interest rates										3.90%	2.70%	2.90%
Gain on divestiture of business, pretax										$ 13.4
Gain on divestiture of business, net										9.8
Provision for income taxes										3.6
Cost of removal obligation		96				90.7				96	$ 90.7
Recognition of lease assets													$ 4.2
Recognition of lease liabilities													$ 4.2
Power Supply Contract Divestitures		0.3				0.6				0.3	0.6
Investments in trading securities		5.6				4.8				$ 5.6	$ 4.8
Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend paid per share | $ / shares										$ 0.37	$ 0.365	$ 0.36
Materials And Supplies
Significant Accounting Policies [Line Items]
Inventory of materials and supplies		7.9				7				$ 7.9	$ 7
ASU 2014-09
Significant Accounting Policies [Line Items]
Revenue sharing payments												$ 1.1
Non Service
Significant Accounting Policies [Line Items]
Non-service cost net periodic benefit costs										$ 4.6	5.5	$ 5.7
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary										3
Unitil Service; Unitil Realty; and Unitil Resources
Significant Accounting Policies [Line Items]
Number of Subsidiaries | Subsidiary										3
Power Supply Contract Divestitures		0.6								$ 0.6
Subsequent Event
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	$ 1.50
Subsequent Event | Quarterly Dividends
Significant Accounting Policies [Line Items]
Common stock dividend per share, declared | $ / shares	0.375
Increase in dividend declared amount per share | $ / shares	$ 0.005
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%
Environmental and Rate Case Costs and Other Expenditures | Recovered over the next seven years
Significant Accounting Policies [Line Items]
Power Supply Contract Divestitures		7.6								$ 7.6
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits		$ 1.9				3.5				$ 1.9	3.5
Maximum
Significant Accounting Policies [Line Items]
Lease term		12 months								12 months
Deferred Compensation Plan [Member]
Significant Accounting Policies [Line Items]
Investments in trading securities		$ 0.2				$ 0				$ 0.2	$ 0

Components of Gas and Electric

Components of Gas and Electric Operating Revenue (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 437.3	$ 439.4	$ 400.2
Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	435.2	439.4	389.1
Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	2.1		11.1
Gas Segment
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	203.4	216.1	194
Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	212.1	210.7	187.5
Gas Segment | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	(8.7)	5.4	6.5
Electric
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	233.9	223.3	206.2
Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	223.1	228.7	201.6
Electric | Rate Adjustment Mechanism Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	10.8	(5.4)	4.6
Residential | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	202.9	205	179.1
Residential | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	81.4	81.4	71.2
Residential | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	121.5	123.6	107.9
Commercial & Industrial | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	213.9	216.1	190.5
Commercial & Industrial | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	120.1	119.7	102.8
Commercial & Industrial | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	93.8	96.4	87.7
Other | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	18.4	18.3	19.5
Other | Gas Segment | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	10.6	9.6	13.5
Other | Electric | Billed and Unbilled Revenue
Operating Revenues [Line Items]
Total Gas and Electric Operating Revenues	$ 7.8	$ 8.7	$ 6

Schedule of Other Operating Rev

Schedule of Other Operating Revenues and Operating Expenses (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Component of Operating Other Cost and Expense [Line Items]
Total Operating Revenues	$ 437.3	$ 439.4	$ 400.2
Less: Revenue Sharing Payments	(0.2)	(1)	(1.1)
Operation and Maintenance Expense	67.2	69.5	64.5
Usource Contract Revenues [Member]
Component of Operating Other Cost and Expense [Line Items]
Total Operating Revenues	1.1	5.7
Other
Component of Operating Other Cost and Expense [Line Items]
Total Operating Revenues	$ 0.9	$ 4.7	4.9
ASU 2014-09
Component of Operating Other Cost and Expense [Line Items]
Less: Revenue Sharing Payments			(1.1)
Operation and Maintenance Expense			63.4
ASU 2014-09 | Usource Contract Revenues [Member]
Component of Operating Other Cost and Expense [Line Items]
Total Operating Revenues			$ 6

Components of Accrued Revenue (

Components of Accrued Revenue (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Deferred Revenue Arrangement [Line Items]
Regulatory assets-cuurrent	[1]	$ 35.8	$ 41.3
Total Accrued Revenue		50	54.7
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Regulatory assets-cuurrent		14.2	13.4
Regulatory Assets
Deferred Revenue Arrangement [Line Items]
Regulatory assets-cuurrent		$ 35.8	$ 41.3
[1]	Reflects amounts included in the Accrued Revenue on the Company’s Consolidated Balance Sheets.

Components of Exchange Gas Rece

Components of Exchange Gas Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Receivables [Line Items]
Total Exchange Gas Receivable	$ 6.1	$ 8.1
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	5.5	7.5
Fitchburg
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.6	$ 0.6

Components of Gas Inventory (De

Components of Gas Inventory (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.8	$ 0.8
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.1
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.4	0.3
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.3	$ 0.4

Regulatory Assets (Detail)

Regulatory Assets (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Regulatory Assets		$ 147.8	$ 140.3
Less: Current Portion of Regulatory Assets	[1]	35.8	41.3
Regulatory Assets—noncurrent		112	99
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets		7.2	7.9
Other Deferred Charges
Regulatory Assets [Line Items]
Regulatory Assets		10.9	10
Retirement Benefits
Regulatory Assets [Line Items]
Regulatory Assets		88.9	72
Deferred Storm Charges
Regulatory Assets [Line Items]
Regulatory Assets		5.6	6.3
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets		4.2	5.7
Energy Supply & Other Rate Adjustment Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets		$ 31	$ 38.4
[1]	Reflects amounts included in the Accrued Revenue on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities (Detail)

Regulatory Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 54	$ 58.5
Less: Current Portion of Regulatory Liabilities	7.4	11.5
Regulatory Liabilities-noncurrent	46.6	47
Rate Adjustment Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	6	11.5
Income Tax Related Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liabilities	47.6	$ 47	$ 48.9
Other Regulatory Assets (Liabilities) [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 0.4

Fair Value of Marketable Securi

Fair Value of Marketable Securities (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 5.6	$ 4.8
Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.2	0
Fair Value, Inputs, Level 1
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.6	4.8
Fair Value, Inputs, Level 1 | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.2
Fair Value, Inputs, Level 1 | Equity Funds | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	0.1
Fair Value, Inputs, Level 1 | Money Market Funds
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	5.6	$ 4.8
Fair Value, Inputs, Level 1 | Money Market Funds | Deferred Compensation Plan [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Trading Securities	$ 0.1

Components of Energy Supply Obl

Components of Energy Supply Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 10.5	$ 13.4
Power Supply Contract Divestitures, Noncurrent	0.3	0.6
Total Energy Supply Obligations	10.8	14
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	5.5	7.5
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	4.7	5.6
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations-Current	$ 0.3	$ 0.3

Quarterly Financial Informati_3

Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information [Line Items]
Total Operating Revenues	$ 116.4	$ 85.3	$ 84.4	$ 152.1	$ 125.6	$ 88.2	$ 84.5	$ 145.8	$ 438.2	$ 444.1	$ 406.2
Operating Income	22	10	12.3	28.8	22.2	10.3	10.6	28.1	73.1	71.2	75.4
Net Income Applicable to Common	$ 11.4	$ 2.3	$ 4	$ 26.5	$ 11	$ 2.8	$ 3.6	$ 15.6	$ 44.2	$ 33	$ 29
Per Share Data:
Earnings Per Common Share	$ 0.77	$ 0.15	$ 0.27	$ 1.78	$ 0.74	$ 0.19	$ 0.24	$ 1.06	$ 2.97	$ 2.23	$ 2.06
Dividends Paid Per Common Share	$ 0.37	$ 0.37	$ 0.37	$ 0.37	$ 0.365	$ 0.365	$ 0.365	$ 0.365	$ 1.48	$ 1.46	$ 1.44

Segment Information - Additiona

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019PipelineSegmentEntitymi
Segment Reporting Information [Line Items]
No of segments | Segment	3
Number of Subsidiaries | Entity	3
Length Of Pipeline	86
Granite State Gas Transmission Inc
Segment Reporting Information [Line Items]
Length Of Pipeline	86
No of major pipeline | Pipeline	3

Significant Segment Financial D

Significant Segment Financial Data (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue—Non-Regulated									$ 0.9	$ 4.7
Revenues	$ 116.4	$ 85.3	$ 84.4	$ 152.1	$ 125.6	$ 88.2	$ 84.5	$ 145.8	438.2	444.1	$ 406.2
Interest Income									2.9	2.4	2.4
Interest Expense									26.6	26.4	25.5
Depreciation & Amortization Expense									52	50.4	46.9
Income Tax Expense (Benefit)									13.8	8.4	17.5
Segment Profit	11.4	$ 2.3	$ 4	$ 26.5	11	$ 2.8	$ 3.6	$ 15.6	44.2	33	29
Segment Assets	1,370.8				1,298.3				1,370.8	1,298.3	1,241.9
Capital Expenditures									119.2	102.4	119.3
Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									435.2	439.4
Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									2.1
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									203.4	216.1	194
Interest Income									1.2	0.8	0.7
Interest Expense									14.4	14.2	13.7
Depreciation & Amortization Expense									28.5	24.9	22.4
Income Tax Expense (Benefit)									7.2	7.1	10.7
Segment Profit									19.1	18.8	16.4
Segment Assets	823.3				764.1				823.3	764.1	714.3
Capital Expenditures									74	70.8	72.1
Gas Segment | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									212.1	210.7
Gas Segment | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									(8.7)	5.4
Electric
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									233.9	223.3	206.2
Interest Income									0.9	0.8	1
Interest Expense									9.4	9	8.8
Depreciation & Amortization Expense									22.6	23.1	23.4
Income Tax Expense (Benefit)									4.2	4.2	7.5
Segment Profit									11.5	11.4	11.9
Segment Assets	529.3				484.2				529.3	484.2	476.9
Capital Expenditures									39.6	28.4	33.7
Electric | Billed and Unbilled Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									223.1	228.7
Electric | Rate Adjustment Mechanism Revenue
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues									10.8	(5.4)
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income									0.6	0.6	0.6
Interest Expense									2.8	3.2	3
Depreciation & Amortization Expense									0.9	2.3	1
Income Tax Expense (Benefit)									(1.4)	(3.4)	(1.4)
Segment Profit									3.4	1.5	(0.5)
Segment Assets	17.9				43.1				17.9	43.1	44
Capital Expenditures									5.6	3.2	13.5
Non- Regulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Other Operating Revenue—Non-Regulated									0.9	4.7
Revenues									0.9	4.7	6
Interest Income									0.2	0.2	0.1
Depreciation & Amortization Expense										0.1	0.1
Income Tax Expense (Benefit)									3.8	0.5	0.7
Segment Profit									10.2	1.3	1.2
Segment Assets	$ 0.3				$ 6.9				$ 0.3	$ 6.9	$ 6.7

Activity in Company's Allowance

Activity in Company's Allowance for Doubtful Accounts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	$ 1.3	$ 1.6	$ 1.1
Provision	4.9	6	3.7
Recoveries	0.8	0.6	0.6
Accounts Written Off	6	6.9	3.8
Balance at End of Period	1	1.3	1.6
Electric
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.5	0.9	0.8
Provision	3	3.2	1.8
Recoveries	0.3	0.3	0.3
Accounts Written Off	3.2	3.9	2
Balance at End of Period	0.6	0.5	0.9
Gas
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period	0.8	0.6	0.2
Provision	1.9	2.9	1.9
Recoveries	0.5	0.3	0.3
Accounts Written Off	2.8	3	1.8
Balance at End of Period	$ 0.4	0.8	0.6
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance at Beginning of Period		0.1	0.1
Provision		$ (0.1)
Balance at End of Period			$ 0.1

Allowance for Doubtful Accoun_3

Allowance for Doubtful Accounts - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 4.9	$ 6	$ 3.7
Recoveries	0.8	0.6	0.6
Regulatory Assets Harship Accounts
Financing Receivable, Impaired [Line Items]
Recoveries	5.6	5.2
Energy Commodity
Financing Receivable, Impaired [Line Items]
Provision for Bad Debt	$ 2.3	$ 2.6	$ 1.3

Estimated Fair Value of Long Te

Estimated Fair Value of Long Term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Inputs, Level 2
Debt Instrument [Line Items]
Estimated Fair Value of Long-Term Debt	$ 518.7	$ 422

Details on Long Term Debt (Deta

Details on Long Term Debt (Detail) - USD ($) $ in Millions		Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Total Long-Term Debt		$ 460.5	$ 409.3
Less: Unamortized Debt Issuance Costs		3.5	3.5
Long-Term Debt		457	405.8
Less: Current Portion	[1]	19.5	18.4
Total Long-Term Debt, Less Current Portion		437.5	387.4
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Total Long-Term Debt		20	20
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Total Long-Term Debt		30
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Senior Secured Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt		5	10
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Senior Secured Notes, Due October 14, 2024
Debt Instrument [Line Items]
Total Long-Term Debt		4.5	6
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Senior Secured Notes, Due September 1, 2028
Debt Instrument [Line Items]
Total Long-Term Debt		18	20
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	15
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	15
Unitil Energy Systems Inc | First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
Fitchburg Gas and Electric Light Company | 6.75% Senior Notes, Due November 30, 2023
Debt Instrument [Line Items]
Total Long-Term Debt		3.8	5.7
Fitchburg Gas and Electric Light Company | 6.79% Senior Notes, Due October 15, 2025
Debt Instrument [Line Items]
Total Long-Term Debt		10	10
Fitchburg Gas and Electric Light Company | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		10	10
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Total Long-Term Debt		12	12
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Total Long-Term Debt		15	15
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Total Long-Term Debt		14	14
Fitchburg Gas and Electric Light Company | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		15	15
Northern Utilities Inc | 3.52% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		20	20
Northern Utilities Inc | 4.32% Senior Notes, Due November 1, 2047
Debt Instrument [Line Items]
Total Long-Term Debt		30	30
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Total Long-Term Debt		8.2	16.6
Northern Utilities Inc | 7.72% Senior Notes, Due December 3, 2038
Debt Instrument [Line Items]
Total Long-Term Debt		50	50
Northern Utilities Inc | 4.42% Senior Notes, Due October 15, 2044
Debt Instrument [Line Items]
Total Long-Term Debt		50	50
Northern Utilities Inc | 4.04% Senior Notes, Due September 12, 2049
Debt Instrument [Line Items]
Total Long-Term Debt		40
Granite State Gas Transmission Inc | 3.72% Senior Notes, Due November 1, 2027
Debt Instrument [Line Items]
Total Long-Term Debt		$ 15	$ 15
[1]	The Current Portion of Long-Term Debt includes sinking fund payments.

Details on Long Term Debt (Pare

Details on Long Term Debt (Parenthetical) (Detail)	Sep. 12, 2019	Dec. 31, 2019	Dec. 31, 2018
6.33% Senior Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate		6.33%	6.33%
Debt instrument due date		May 1, 2022	May 1, 2022
3.70% Senior Notes, Due August 1, 2026
Debt Instrument [Line Items]
Stated interest rate		3.70%	3.70%
Debt instrument due date		Aug. 1, 2026	Aug. 1, 2026
3.43% Senior Notes, Due December 18, 2029
Debt Instrument [Line Items]
Stated interest rate		3.43%	3.43%
Debt instrument due date		Dec. 18, 2029	Dec. 18, 2029
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%
Debt instrument due date		Mar. 2, 2020	Mar. 2, 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%
Debt instrument due date		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%
Debt instrument due date		Sep. 1, 2028	Sep. 1, 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%
Debt instrument due date		May 1, 2031	May 1, 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%
Debt instrument due date		Sep. 15, 2036	Sep. 15, 2036
First Mortgage Bonds 4.18% Senior Secured Notes Due November 30, 2048 | Unitil Energy Systems Inc
Debt Instrument [Line Items]
Stated interest rate		4.18%	4.18%
Debt instrument due date		Nov. 30, 2048	Nov. 30, 2048
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%
Debt instrument due date		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%
Debt instrument due date		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%
Debt instrument due date		Nov. 1, 2027	Nov. 1, 2027
3.52% Senior Notes, Due November 1, 2027 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		3.52%	3.52%
Debt instrument due date		Nov. 1, 2027	Nov. 1, 2027
7.37% Notes, Due January 15, 2029 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		7.37%	7.37%
Debt instrument due date		Jan. 15, 2029	Jan. 15, 2029
5.90% Notes, Due December 15, 2030 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		5.90%	5.90%
Debt instrument due date		Dec. 15, 2030	Dec. 15, 2030
7.98% Notes, Due June 1, 2031 | Fitchburg Gas and Electric Light Company
Debt Instrument [Line Items]
Stated interest rate		7.98%	7.98%
Debt instrument due date		Jun. 1, 2031	Jun. 1, 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%
Debt instrument due date		Nov. 1, 2047	Nov. 1, 2047
4.32% Senior Notes, Due November 1, 2047 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		4.32%	4.32%
Debt instrument due date		Nov. 1, 2047	Nov. 1, 2047
5.29% Senior Notes, Due March 2, 2020 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		5.29%	5.29%
Debt instrument due date		Mar. 2, 2020	Mar. 2, 2020
7.72% Senior Notes, Due December 3, 2038 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		7.72%	7.72%
Debt instrument due date		Dec. 3, 2038	Dec. 3, 2038
4.42% Senior Notes, Due October 15, 2044 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate		4.42%	4.42%
Debt instrument due date		Oct. 15, 2044	Oct. 15, 2044
4.04% Senior Notes, Due September 12, 2049 | Northern Utilities Inc
Debt Instrument [Line Items]
Stated interest rate	4.04%	4.04%	4.04%
Debt instrument due date	Sep. 12, 2049	Sep. 12, 2049	Sep. 12, 2049
3.72% Senior Notes, Due November 1, 2027 | Granite State Gas Transmission Inc
Debt Instrument [Line Items]
Stated interest rate		3.72%	3.72%
Debt instrument due date		Nov. 1, 2027	Nov. 1, 2027

Summary of Interest Expense and

Summary of Interest Expense and Interest Income (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Interest Expense
Long-Term Debt		$ 22.9	$ 23.1	$ 21.8
Short-Term Debt		3	2.6	2.5
Regulatory Liabilities		0.7	0.7	1.2
Interest Expense		26.6	26.4	25.5
Interest Income
Interest Income		(2.9)	(2.4)	(2.4)
Total Interest Expense, Net		23.7	24	23.1
Regulatory Assets
Interest Income
Interest Income		(0.8)	(0.8)	(0.7)
AFUDC and Other
Interest Income
Interest Income	[1]	$ (2.1)	$ (1.6)	$ (1.7)
[1]	AFUDC—Allowance for Funds Used During Construction

Debt and Financing Arrangemen_3

Debt and Financing Arrangements - Additional Information (Detail) - USD ($)	Dec. 18, 2019	Sep. 12, 2019	Nov. 30, 2018	Jul. 25, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 30, 2015
Line of Credit Facility [Line Items]
Amount available for the payment of dividends					$ 123,100,000
Retained Earnings					$ 94,100,000	$ 72,000,000
Restriction on retained earnings for dividend payments					Therefore, there were no restrictions on the Company’s Retained Earnings at December 31, 2019 for the payment of dividends.
Issuance of long-term debt	$ 200,000	$ 200,000
Long term debt repayments					$ 18,800,000	$ 30,100,000	$ 17,200,000
Weighted average interest rate on short term borrowings					3.40%	3.30%	2.40%
Capital lease obligation, total capitalized cost					$ 546,000	$ 5,800,000
Capital lease obligation, current					200,000	3,100,000
Capital lease obligation, noncurrent	300,000				300,000	2,700,000
Accounts Payable					37,600,000	42,600,000
Total rental expense under operating leases					1,400,000	2,200,000	$ 2,000,000
Net Utility Plant					1,111,500,000	1,036,800,000
Guarantee outstanding					6,200,000
Operating lease obligations					1,400,000
Other current operating lease obligation					1,200,000	1,200,000
Other noncurrent operating lease obligation					$ 2,800,000
Operating lease, weighted average remaining lease term					3 years 10 months 24 days
Operating lease, weighted average discount rate percentage					5.20%
Assets under Capital Leases [Member]
Line of Credit Facility [Line Items]
Net Utility Plant					$ 1,200,000	15,000,000
Net Utility Plant, accumulated amortization					$ 600,000	1,700,000
Unitil Service Corp
Line of Credit Facility [Line Items]
Capital lease obligation, total capitalized cost								$ 13,400,000
Northern Utilities Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization					65.00%
Natural gas storage inventory					$ 6,500,000	8,400,000
Accounts Payable						900,000
Granite State Gas Transmission Inc
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization					65.00%
Fitchburg Gas and Electric Light Company
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization					65.00%
Unitil Corporation | Maximum [Member]
Line of Credit Facility [Line Items]
Total funded indebtedness as percentage of capitalization					70.00%
Unitil Energy, Fitchburg, Northern Utilities and Granite State
Line of Credit Facility [Line Items]
Amount available for the payment of dividends					$ 308,400,000
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility					120,000,000	120,000,000
Proceeds from lines of credit					252,700,000	265,600,000
Repayments of lines of credit					$ 276,900,000	$ 221,100,000
Credit Facility | Second Amended 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
Revolving credit facility termination date				Jul. 25, 2023
Increase in borrowing limit				$ 50,000,000
Credit Facility | Second Amended Credit Facility | London Interbank Offered Rate
Line of Credit Facility [Line Items]
Credit facility, daily fluctuating rate of interest				1.125%
Credit Facility | Revolving Credit Facility
Line of Credit Facility [Line Items]
Percentage of capitalization					The affirmative and negative covenants under the Credit Facility shall apply to Unitil until the Credit Facility terminates and all amounts borrowed under the Credit Facility are paid in full (or with respect to letters of credit, they are cash collateralized). The only financial covenant in the Credit Facility provides that Unitil’s Funded Debt to Capitalization (as each term is defined in the Credit Facility) cannot exceed 65%, tested on a quarterly basis. At December 31, 2019 and December 31, 2018, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
4.18% First Mortgage Bonds, Due November 30, 2048
Line of Credit Facility [Line Items]
Issuance of long-term debt			$ 500,000
4.18% First Mortgage Bonds, Due November 30, 2048 | Unitil Energy
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount			$ 30,000,000
Long-term debt, stated interest rate			4.18%
Long-term debt, maturity date			Nov. 30, 2048
3.43% Senior Notes, Due December 18, 2029
Line of Credit Facility [Line Items]
Long-term debt, stated interest rate					3.43%	3.43%
Long-term debt, maturity date					Dec. 18, 2029	Dec. 18, 2029
3.43% Senior Notes, Due December 18, 2029 | Unitil Corporation
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount	$ 30,000,000
Long-term debt, stated interest rate	3.43%
Long-term debt, maturity date	Dec. 18, 2029
4.04% Senior Notes, Due September 12, 2049 | Northern Utilities Inc
Line of Credit Facility [Line Items]
Long-term debt, aggregate principal amount		$ 40,000,000
Long-term debt, stated interest rate		4.04%			4.04%	4.04%
Long-term debt, maturity date		Sep. 12, 2049			Sep. 12, 2049	Sep. 12, 2049
Bonds [Member]
Line of Credit Facility [Line Items]
Long term debt repayments						$ 30,100,000	$ 17,200,000
Debt repayment, 2020					$ 19,800,000
Debt repayment, 2021					8,600,000
Debt repayment, 2022					28,200,000
Debt repayment, 2023					6,700,000
Debt repayment, 2024					6,700,000
Debt repayment, Thereafter					$ 390,500,000

Borrowing Limits Amounts Outsta

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Short-Term Borrowings Outstanding	$ 58,600,000	$ 82,800,000
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility, limit	120,000,000	120,000,000
Short-Term Borrowings Outstanding	58,600,000	82,800,000
Letters of Credit Outstanding	100,000
Available revolving credit facility	$ 61,300,000	$ 37,200,000

Debt and Financing Arrangemen_4

Debt and Financing Arrangements - Classification of the Company Lease Obligations (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 18, 2019	Dec. 31, 2018
Operating Lease Obligations:
Other Current Liabilities (current portion)	$ 1,200		$ 1,200
Other Noncurrent Liabilities (long-term portion)	2,800
Total Operating Lease Obligations	4,026
Capital Lease Obligations:
Other Current Liabilities (current portion)	200		3,100
Other Noncurrent Liabilities (long-term portion)	300	$ 300	2,700
Total Capital Lease Obligations	546		5,800
Total Lease Obligations	$ 4,500		$ 5,800

Future Operating Lease Payment

Future Operating Lease Payment Obligations and Future Minimum Lease Payments under Capital Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Operating leases
Rest of 2019	$ 1,355
2019		$ 1,372
2020	1,185	1,138
2021	904	969
2022	604	689
2023	274	390
2024-2028	139	120
Total Payments	4,461	4,678
Less: Interest	435
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	4,026
Capital lease
Rest of 2019	262
2019		3,069
2020	161	2,535
2021	97	93
2022	55	32
2023		14
Total Payments	575	5,743
Less: Interest	29
Amount of Lease Obligations Recorded on Consolidated Balance Sheets	$ 546	$ 5,800

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($)	Jan. 28, 2020	Dec. 14, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common stock, shares outstanding			14,930,170	14,876,955
Common stock, shares authorized			25,000,000	25,000,000
Common stock, shares issued			20,065	25,932
Proceeds from Issuance of Common Stock			$ 1,100,000	$ 1,200,000	$ 33,000,000
Common stock shares repurchase			2,911	791	1,686
Share based compensation expense			$ 2,300,000	$ 2,200,000	$ 2,700,000
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			$ 1,900,000	1,300,000
Preferred Stock			$ 200,000	200,000
Percentage of fully-vested restricted stock units that directors will receive in common shares when settled			70.00%
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock, shares issued					26,256
Proceeds from Issuance of Common Stock			$ 1,100,000	$ 1,200,000	$ 1,300,000
Dividend and Distribution Reinvestment and Share Purchase Plan | Common Stock
Class of Stock [Line Items]
Common stock, shares issued			20,065	25,932	26,256
Registered Public Offering
Class of Stock [Line Items]
Common stock, shares issued					690,000
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
Maximum
Class of Stock [Line Items]
Repurchase expense			$ 200,000	$ 100,000	$ 100,000
Dividend declared			$ 100,000	$ 100,000
Average | Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock price per share			$ 57.37
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding			1,887	1,893
Preferred Stock			$ 200,000	$ 200,000
Dividend rate			6.00%	6.00%
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period			4 years
Restricted stock non-vested			32,950	29,252
Restricted stock weighted average grant date fair value			$ 47.35	$ 42.86
Unrecognized share based compensation			$ 700,000
Share compensation recognition period			2 years 6 months
Forfeitures under the stock plan			0
Cancellations under the stock plan			0
Restricted Stock | Subsequent Event
Class of Stock [Line Items]
Aggregate Market Value	$ 1,800,000
Restricted Stock Units Granted	28,630
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 Shares Issued in Con

Restricted Shares Issued in Conjunction with Stock Plan (Detail) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)shares
Period 1
Class of Stock [Line Items]
Issuance Date	Jan. 30, 2017
Shares | shares	34,930
Aggregate Market Value | $	$ 1.6
Period 2
Class of Stock [Line Items]
Issuance Date	Jan. 29, 2018
Shares | shares	37,510
Aggregate Market Value | $	$ 1.6
Period 3
Class of Stock [Line Items]
Issuance Date	Jan. 29, 2019
Shares | shares	33,150
Aggregate Market Value | $	$ 1.6

Restricted Stock Units Issued (

Restricted Stock Units Issued (Detail) - Restricted Stock Units (RSUs) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Restricted Stock Units
Beginning Restricted Stock Units	61,789	52,224
Restricted Stock Units Granted	6,943	7,892
Dividend Equivalents Earned	1,632	1,673
Restricted Stock Units Settled	0	0
Ending Restricted Stock Units	70,364	61,789
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 38.25	$ 36.22
Restricted Stock Units Granted	63.50	49.63
Dividend Equivalents Earned	58.15	47.85
Restricted Stock Units Settled
Ending Restricted Stock Units	$ 41.20	$ 38.25

Reconciliation of Basic and Dil

Reconciliation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule Of Computation Of Basic And Diluted Earnings Per Common Share [Line Items]
Earnings Available to Common Shareholders									$ 44.2	$ 33	$ 29
Weighted Average Common Shares Outstanding-Basic									14,894	14,824	14,095
Plus: Diluted Effect of Incremental Shares									6	5	7
Weighted Average Common Shares Outstanding-Diluted									14,900	14,829	14,102
Earnings per Share-Basic and Diluted	$ 0.77	$ 0.15	$ 0.27	$ 1.78	$ 0.74	$ 0.19	$ 0.24	$ 1.06	$ 2.97	$ 2.23	$ 2.06

Weighted Average Non Vested Res

Weighted Average Non Vested Restricted Shares Excluded from Computation of Earnings Per Share (Detail) - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Non Vested Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Non-Vested Restricted Shares Not Included in EPS Computation		6,102	8,733

Energy Supply - Additional Info

Energy Supply - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019BcfMMBTU
Northern Utilities Inc
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities | MMBTU	115,000,000,000
Natural gas, underground storage | Bcf	4,300,000,000
Northern Utilities Inc | Maximum
Gas and Oil Acreage [Line Items]
Purchases of natural gas, contract duration	1 year
Fitchburg Gas and Electric Light Company
Gas and Oil Acreage [Line Items]
Natural gas available under firm contract per day of year-round and seasonal transportation and underground storage capacity to distribution facilities | MMBTU	14,439
Natural gas, underground storage | Bcf	0.43
Percentage of power supply requirement	50.00%
Power supply contract duration	12 months
Unitil Energy Systems Inc
Gas and Oil Acreage [Line Items]
Percentage of power supply requirement	100.00%
Power supply contract duration	6 months

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)

Dec. 17, 2019USD ($)

Oct. 29, 2019USD ($)

Jun. 28, 2019USD ($)

Jun. 25, 2019

May 01, 2019USD ($)

Apr. 17, 2019USD ($)

Nov. 01, 2018USD ($)

May 07, 2018USD ($)

May 02, 2018USD ($)

Apr. 20, 2017USD ($)

Dec. 31, 2017

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017

May 23, 2019MWh

Apr. 30, 2019USD ($)

Jul. 31, 2018MWMWh

Jun. 30, 2017MWMWh

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Regulatory Assets [Line Items]

Regulatory Assets, Remaining Balance

$ 600,000

Accrued Revenue

50,000,000

$ 54,700,000

Regulatory Assets

$ 112,000,000

$ 99,000,000

Corporate income tax rate

21.00%

21.00%

34.00%

Spending cap

$ 599,000,000

Accrued Estimated Costs For Remediation

$ 700,000

Tax Year 2018

Regulatory Assets [Line Items]

Corporate income tax rate

21.00%

21.00%

21.00%

21.00%

Other Restructuring

Regulatory Assets [Line Items]

Accrued Revenue

$ 300,000

Regulatory Assets

$ 300,000

Cost recovery period, years

2 years

New Hampshire

Regulatory Assets [Line Items]

Increase (decrease) in annual revenue

$ 3,200,000

Northern Utilities Inc

Regulatory Assets [Line Items]

Increase (decrease) in annual revenue

$ 7,000,000

$ 1,400,000

Increase in annual base rate

2.10%

2.40%

Annual TIRA adjustment

$ 1,000,000

$ 1,100,000

Percentage of increase in test year operating revenue

7.00%

Fitchburg Gas and Electric Light Company

Regulatory Assets [Line Items]

Increase (decrease) in annual revenue

$ 2,700,000

$ 1,100,000

$ 1,000,000

$ 900,000

Spending cap

$ 400,000

$ 400,000

Recovery amount

600,000

$ 1,600,000

Percentage of change in revenue over previous year

4.10%

Power generation capacity | MWh

9,450,000

Fitchburg Gas and Electric Light Company | Offshore Wind Energy

Regulatory Assets [Line Items]

Power generation facility | MW

400

1,600

Remuneration Percentage

2.75%

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | First Solicitation [Member]

Regulatory Assets [Line Items]

Power generation facility | MWh

800

Fitchburg Gas and Electric Light Company | Offshore Wind Energy | Second Solicitation [Member]

Regulatory Assets [Line Items]

Power generation facility | MWh

800

Fitchburg Gas and Electric Light Company | Qualified Clean Energy

Regulatory Assets [Line Items]

Power generation capacity | MWh

9,554,940

Remuneration Percentage

2.75%

Unitil Energy Systems Inc | New Hampshire

Regulatory Assets [Line Items]

Permanent rate increase

$ 4,100,000

Unitil Energy Systems Inc | New Hampshire | Second Rate Step Adjustments

Regulatory Assets [Line Items]

Increase (decrease) in annual revenue

$ 340,000

Fitchburg Gas Company

Regulatory Assets [Line Items]

Increase (decrease) in annual revenue

$ 7,300,000

Percentage of change in revenue over previous year

20.80%

Gas And Electric Supply Contrac

Gas And Electric Supply Contractual Obligations (Detail) $ in Millions	Dec. 31, 2019USD ($)
Total	$ 599
2020	47.6
2021	49.9
2022	49.2
2023	46.7
2024	37.7
2025 & Beyond	367.9
Gas Supply Contracts
Total	584.8
2020	45.6
2021	48.7
2022	48
2023	45.5
2024	36.5
2025 & Beyond	360.5
Electric Supply Contracts
Total	14.2
2020	2
2021	1.2
2022	1.2
2023	1.2
2024	1.2
2025 & Beyond	$ 7.4

Company's Liability for Environ

Company's Liability for Environmental Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	$ 2	$ 2.1
Additions	0.9	0.3
Less: Payments / Reductions	0.2	0.4
Total Balance at End of Period	2.7	2
Less: Current Portion	0.6	0.6
Noncurrent Balance at End of Period	2.1	1.4
Fitchburg Gas and Electric Light Company
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	0	0.1
Less: Payments / Reductions	0	0.1
Total Balance at End of Period		0
Less: Current Portion	0
Noncurrent Balance at End of Period	0
Northern Utilities Inc
Environmental Exit Cost [Line Items]
Total Balance at Beginning of Period	2	2
Additions	0.9	0.3
Less: Payments / Reductions	0.2	0.3
Total Balance at End of Period	2.7	2
Less: Current Portion	0.6	0.6
Noncurrent Balance at End of Period	$ 2.1	$ 1.4

Provisions for Federal and Stat

Provisions for Federal and State Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Income Tax Provision
Federal	$ 0
State	351	$ 355
Total Current Income Taxes	351	355
Deferred Income Provision
Federal	9,340	5,032	$ 13,675
State	4,117	3,006	3,862
Total Deferred Income Taxes	13,457	8,038	17,537
Total Income Tax Expense	$ 13,800	$ 8,400	$ 17,500

Differences Between Provisions

Differences Between Provisions for Income Taxes and Provisions Calculated at Statutory Federal Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Examination [Line Items]
Statutory Federal Income Tax Rate	21.00%	21.00%	34.00%
State Income Taxes, net	6.00%	6.00%	6.00%
Utility Plant Differences	(3.00%)	(7.00%)	(1.00%)
Tax Credits	0.00%		(1.00%)
Other, net	0.00%	0.00%	0.00%
Effective Income Tax Rate	24.00%	20.00%	38.00%

Deferred Tax Assets and Liabili

Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred Tax Assets
Retirement Benefit Obligations	$ 36,551	$ 32,249
Net Operating Loss Carryforwards	1,609	10,773
Tax Credit Carryforwards	1,489	2,704
Other, net	1,589	1,571
Total Deferred Tax Assets	41,238	47,297
Deferred Tax Liabilities
Utility Plant Differences	134,011	132,682
Regulatory Assets & Liabilities	5,239	6,429
Other, net	5,539	5,964
Total Deferred Tax Liabilities	144,789	145,075
Net Deferred Tax Liabilities	$ 103,551	$ 97,778

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2020
Income Taxes [Line Items]
Corporate federal income tax			21.00%	21.00%	34.00%
Regulatory Liability			$ 54	$ 58.5
Regulatory liability, expected flow back to customers			$ 47.1	48.9
Average Rate Assumption Method estimated flow back period		15 years	15 years
Tax provision			$ 1.7
Deferred tax assets, operating loss carryforwards, federal			1.6
Alternative minimum tax credit carryforwards			0.9
Additional Alternative minimum tax credit carryforwards			2.3
Scenario Forecast
Income Taxes [Line Items]
Alternative minimum tax credit carryforwards						$ 0.3
Income Tax Related Liabilities
Income Taxes [Line Items]
Regulatory Liability	$ 48.9		47.6	47	$ 48.9
Reconciling Mechanisms
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers			1.1		$ 1.8
Tax provision			0	0.7
Net Operating Loss Carryforward Assets
Income Taxes [Line Items]
Regulatory liability, expected pass back to ratepayers			0.3	$ 2
Fitchburg Gas and Electric Light Company | Electric Ratepayers
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers			10.1
Fitchburg Gas and Electric Light Company | Gas Ratepayers
Income Taxes [Line Items]
Regulatory liability, expected flow back to customers			$ 10.4
Tax Year 2018
Income Taxes [Line Items]
Corporate federal income tax	21.00%		21.00%	21.00%	21.00%
Tax Year 2018 | Internal Revenue Service [Member]
Income Taxes [Line Items]
Net Operating Loss Carryforwards Utilized For Income Taxes			$ 5.7
Tax Year 2019
Income Taxes [Line Items]
Net operating loss carryforwards in federal tax provisions			$ 3.5

Key Weighted Average Assumption

Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.25%	3.60%	4.10%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Expected Long-term rate of return on plan assets	7.50%	7.75%	7.75%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	7.50%	8.00%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2024	2024	2025
Benefit Obligation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.25%	4.25%	3.60%
Rate of Compensation Increase	3.00%	3.00%	3.00%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	7.00%	7.50%
Ultimate Health Care Cost Trend Rate	4.50%	4.50%	4.50%
Year that Ultimate Health Care Cost Trend Rate is reached	2029	2024	2024

Retirement Benefit Obligations

Retirement Benefit Obligations - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Change in Discount Rate	0.25%
Increase or decrease of Net Periodic Benefit Cost (NPBC) due to change in the discount rate	$ 534
Pension expense	5,800	$ 7,600	$ 7,000
Regulatory assets	$ 147,800	140,300
Defined Benefit Plan, Expected Long-term Rate-of-Return on Assets Assumption	The desired investment objective is a long-term rate of return on assets that is approximately 5 – 6% greater than the assumed rate of inflation as measured by the Consumer Price Index.
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	$ 166,500	142,800
Company's contributions	6,916	16,628	4,100
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	4,000	4,000	4,000
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation	13,600	10,800
Company's contributions	610	401	34
Fair Value Of Plan Assets
Defined Benefit Plan Disclosure [Line Items]
Pension expense	7,300	7,200	7,600
Defined Benefit Obligations
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	88,900	72,000
Four Zero One K Plan
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	$ 2,800	$ 2,700	$ 2,400
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Long-term Return on Assets	7.50%	7.75%	7.75%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				53.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				37.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				45.00%
Real Estate Funds | Scenario Forecast | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations				10.00%

Components of Retirement Plan C

Components of Retirement Plan Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 3,104	$ 3,393	$ 3,295
Interest Cost	6,484	5,878	6,057
Expected Return on Plan Assets	(8,475)	(7,785)	(7,306)
Prior Service Cost Amortization	320	324	263
Actuarial Loss Amortization	4,324	5,786	4,662
Sub-total	5,757	7,596	6,971
Amounts Capitalized or Deferred	(2,227)	(3,465)	(3,122)
NPBC Recognized	3,530	4,131	3,849
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,304	2,933	2,974
Interest Cost	3,426	3,404	3,913
Expected Return on Plan Assets	(1,645)	(1,635)	(1,347)
Prior Service Cost Amortization	1,213	1,309	1,399
Actuarial Loss Amortization	227	1,383	2,098
Sub-total	5,525	7,394	9,037
Amounts Capitalized or Deferred	(2,317)	(3,416)	(4,515)
NPBC Recognized	3,208	3,978	4,522
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service Cost	247	487	460
Interest Cost	567	404	392
Prior Service Cost Amortization	56	189	189
Actuarial Loss Amortization	628	486	295
Sub-total	1,498	1,566	1,336
Amounts Capitalized or Deferred	(430)	(451)	(397)
NPBC Recognized	$ 1,068	$ 1,115	$ 939

Summary of Information on Plans

Summary of Information on Plans' Assets, Projected Benefit Obligations (PBO), and Funded Status (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	$ 107,808	$ 102,315
Actual Return on Plan Assets	17,908	(6,149)
Employer Contributions	6,916	16,628	$ 4,100
Participant Contributions	0
Benefits Paid	(6,877)	(4,986)
Plan Assets at End of Year	125,755	107,808	102,315
PBO at Beginning of Year	156,197	166,921
Service Cost	3,104	3,393	3,295
Interest Cost	6,484	5,878	6,057
Plan Amendments	0
Benefits Paid	(6,877)	(4,986)	(5,574)
Actuarial (Gain) or Loss	23,227	(15,009)
PBO at End of Year	182,135	156,197	166,921
Funded Status: Assets vs PBO	(56,380)	(48,389)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	21,109	20,234
Actual Return on Plan Assets	3,808	(1,085)
Employer Contributions	4,000	4,000	4,000
Participant Contributions	121	153
Benefits Paid	(1,758)	(2,193)
Plan Assets at End of Year	27,280	21,109	20,234
PBO at Beginning of Year	81,005	94,122
Service Cost	2,304	2,933	2,974
Interest Cost	3,426	3,404	3,913
Plan Amendments	0
Benefits Paid	(1,758)	(2,193)	(2,405)
Actuarial (Gain) or Loss	10,559	(17,414)
PBO at End of Year	95,657	81,005	94,122
Funded Status: Assets vs PBO	(68,377)	(59,896)
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Plan Assets at Beginning of Year	0
Actual Return on Plan Assets	0
Employer Contributions	610	401	34
Participant Contributions	0
Benefits Paid	(610)	(401)
Plan Assets at End of Year	0	0
PBO at Beginning of Year	13,754	11,723
Service Cost	247	487	460
Interest Cost	567	404	392
Plan Amendments	225
Benefits Paid	(610)	(401)	(34)
Actuarial (Gain) or Loss	3,576	1,541
PBO at End of Year	17,759	13,754	$ 11,723
Funded Status: Assets vs PBO	$ (17,759)	$ (13,754)

Employer Contributions, Partici

Employer Contributions, Participant Contributions and Benefit Payments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	$ 6,916	$ 16,628	$ 4,100
Benefit Payments	6,877	4,986	5,574
Other Postretirement Benefit Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	4,000	4,000	4,000
Participant Contributions	121	153	126
Benefit Payments	1,758	2,193	2,405
Supplemental Employee Retirement Plans, Defined Benefit
Defined Contribution Plan Disclosure [Line Items]
Employer Contributions	610	401	34
Benefit Payments	$ 610	$ 401	$ 34

Estimated Future Benefit Paymen

Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2019USD ($)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
2020	$ 6,706
2021	7,192
2022	6,903
2023	7,687
2024	8,622
2025 - 2029	49,511
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2020	2,774
2021	3,035
2022	3,167
2023	3,341
2024	3,622
2025 - 2029	21,761
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
2020	653
2021	653
2022	651
2023	650
2024	648
2025 - 2029	$ 6,037

Actual Investment Allocations (

Actual Investment Allocations (Detail)		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			54.00%	49.00%	49.00%
Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			36.00%	40.00%	34.00%
Pension Plans | Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[1]		0.00%		6.00%
Pension Plans | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[2]		1.00%	1.00%	1.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			100.00%	100.00%	100.00%
Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			56.00%	53.00%	56.00%
Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			44.00%	47.00%	42.00%
Other Postretirement Benefit Plans, Defined Benefit | Other
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation	[3]		0.00%		2.00%
Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Actual Allocation			9.00%	10.00%	10.00%
Scenario Forecast | Pension Plans | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		53.00%
Scenario Forecast | Pension Plans | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		37.00%
Scenario Forecast | Pension Plans | Asset Allocation Fund
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	[1]	0.00%
Scenario Forecast | Pension Plans | Other
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	[2]	0.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		55.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		45.00%
Scenario Forecast | Other Postretirement Benefit Plans, Defined Benefit | Other
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	[3]	0.00%
Scenario Forecast | Real Estate Funds | Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Target Allocation		10.00%
[1]	Represents investments in an asset allocation fund. This fund invests in both equity and debt securities.
[2]	Represents investments being held in cash equivalents as of December 31, 2019, December 31, 2018 and December 31, 2017 pending payment of benefits.
[3]	Represents investments being held in cash equivalents as of December 31, 2017 pending transfer into debt and equity funds.

Assets Measured at Fair Value o

Assets Measured at Fair Value on Recurring Basis for Pension Plan (Detail) - Pension Plans - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 125,755	$ 107,808	$ 102,315
Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	113,828	96,165
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	68,848	52,884
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	44,980	43,281
Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	750	1,202
Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	114,578	97,367
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	11,177	10,441
Fair Value, Inputs, Level 1 | Mutual Fund
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	113,828	96,165
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	68,848	52,884
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	44,980	43,281
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	750	1,202
Fair Value, Inputs, Level 1 | Mutual Fund Including Cash And Cash Equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 114,578	$ 97,367

Assets Measured at Fair Value_2

Assets Measured at Fair Value on Recurring Basis for PBOP Plan (Detail) - Other Postretirement Benefit Plans, Defined Benefit - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 27,280	$ 21,109	$ 20,234
Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	11,888	9,905
Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	15,392	11,204
Fair Value, Inputs, Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	27,280	21,109
Fair Value, Inputs, Level 1 | Mutual Fund | Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	11,888	9,905
Fair Value, Inputs, Level 1 | Mutual Fund | Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets measured at fair value	$ 15,392	$ 11,204