10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended March 31, 2014

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

New Hampshire	02-0381573
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

6 Liberty Lane West, Hampton, New Hampshire	03842-1720
(Address of principal executive office)	(Zip Code)

Registrant’s telephone number, including area code: (603) 772-0775

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at April 18, 2014
Common Stock, no par value	13,887,087 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended March 31, 2014

Table of Contents

		Page No.
Part I. Financial Information
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Earnings - Three Months Ended March 31, 2014 and 2013	20
	Consolidated Balance Sheets, March 31, 2014, March 31, 2013 and December 31, 2013	21-22
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2014 and 2013	23
	Consolidated Statements of Changes in Common Stock Equity - Three Months Ended March 31, 2014 and 2013	24
	Notes to Consolidated Financial Statements	25-46
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3-19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	46
Part II. Other Information
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	48
Item 6.	Exhibits	49
Signatures		50
Exhibits		51

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CAUTIONARY STATEMENT

This report and the documents incorporated by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.

These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue,” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Item 1A (Risk Factors) and the following:

• the Company’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters), which could affect the rates the Company is able to charge, the Company’s authorized rate of return and the Company’s ability to recover costs in its rates;

• fluctuations in the supply of, demand for, and the prices of energy commodities and transmission capacity and the Company’s ability to recover energy commodity costs in its rates;

• customers’ preferred energy sources;

• severe storms and the Company’s ability to recover storm costs in its rates;

• the Company’s stranded electric generation and generation-related supply costs and the Company’s ability to recover stranded costs in its rates;

• declines in the valuation of capital markets, which could require the Company to make substantial cash contributions to cover its pension obligations, and the Company’s ability to recover pension obligation costs in its rates;

• general economic conditions, which could adversely affect (i) the Company’s customers and, consequently, the demand for the Company’s distribution services, (ii) the availability of credit and liquidity resources and (iii) certain of the Company’s counterparties’ obligations (including those of its insurers and lenders);

• the Company’s ability to obtain debt or equity financing on acceptable terms;

• increases in interest rates, which could increase the Company’s interest expense;

• restrictive covenants contained in the terms of the Company’s and its subsidiaries’ indebtedness, which restrict certain aspects of the Company’s business operations;

• variations in weather, which could decrease demand for the Company’s distribution services;

• long-term global climate change, which could adversely affect customer demand or cause extreme weather events that could disrupt the Company’s electric and natural gas distribution services;

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• numerous hazards and operating risks relating to the Company’s electric and natural gas distribution activities, which could result in accidents and other operating risks and costs;

• catastrophic events;

• the Company’s ability to retain its existing customers and attract new customers;

• the Company’s energy brokering customers’ performance under multi-year energy brokering contracts; and

• increased competition.

Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.

PART I. FINANCIAL INFORMATION

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A)

OVERVIEW

Unitil Corporation (Unitil or the Company) is a public utility holding company headquartered in Hampton, New Hampshire. Unitil is subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005.

Unitil’s principal business is the local distribution of electricity and natural gas throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

i) Unitil Energy Systems, Inc. (Unitil Energy), which provides electric service in the southeastern seacoast and state capital regions of New Hampshire, including the capital city of Concord;

ii) Fitchburg Gas and Electric Light Company (Fitchburg), which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and

iii) Northern Utilities, Inc. (Northern Utilities), which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland, which is the largest city in northern New England.

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 102,400 electric customers and 75,900 natural gas customers in their service territory.

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In addition, Unitil is the parent company of Granite State Gas Transmission, Inc. (Granite State) an interstate natural gas transmission pipeline company, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north.

Unitil had an investment in Net Utility Plant of $666.8 million at March 31, 2014. Unitil’s total operating revenue includes revenue to recover the approved cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Company’s earnings are not directly affected by changes in the cost of purchased electricity and natural gas. Earnings from Unitil’s utility operations are primarily derived from the return on investment in the utility assets of the three distribution utilities and Granite State.

Unitil also conducts non-regulated operations principally through Usource Inc. and Usource L.L.C. (collectively, Usource), which is wholly-owned by Unitil Resources Inc., a wholly-owned subsidiary of Unitil. Usource provides energy brokering and advisory services to large commercial and industrial customers primarily in the northeastern United States. The Company’s other subsidiaries include Unitil Service Corp., which provides, at cost, a variety of administrative and professional services to Unitil’s affiliated companies, Unitil Realty Corp. (Unitil Realty), which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

RATES AND REGULATION

Rate Case Activity

Northern Utilities – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years, and covers targeted capital expenditures in 2013 through 2016. On February 28, 2014 Northern Utilities filed its first annual TIRA for rates effective May 1, 2014, seeking an annual increase in base distribution revenue of $1.3 million. This filing is pending final approval of the MPUC. TIRA filings in future periods are projected to result in annual increases in revenue of approximately $1.0 million each year.

Northern Utilities – New Hampshire – On April 21, 2014, the New Hampshire Public Utilities Commission (NHPUC) approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. In addition, the settlement agreement provides for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provides for an annual increase in revenue of $1.4 million, effective May 1, 2014. The 2015 step adjustment is for a projected annual increase in revenue of approximately $1.4 million, effective May 1, 2015. The newly-approved rates will be reconciled to the effective date temporary rates were established, July 1, 2013.

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Unitil Energy – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On March 3, 2014 Unitil Energy filed its third step increase of $1.5 million in annual revenue for effect on May 1, 2014, subject to final approval of the NHPUC.

Granite State – Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects. Granite State received approval from the FERC for its latest annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The next rate adjustment is scheduled to be filed in the second quarter of this year for a projected $0.6 million for rates effective August 1, 2014.

Fitchburg – Electric – In July 2013, Fitchburg filed a rate case with the Massachusetts Department of Public Utilities (MDPU) requesting approval to increase its electric base distribution rates. The Company requested an increase of $6.7 million in electric base revenue or 11.5% over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms; Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism to adjust base electric distribution revenue annually by means of either i) a capital cost tracker mechanism, or ii) a multi-year rate plan featuring a revenue cap inflation-based index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms through a reconciling storm recovery adjustment factor beginning January 1, 2015. Hearings were held over a three week period during January 2014, and the matter has been fully briefed. A final rate order is expected in the second quarter of 2014.

Regulation

Unitil is subject to comprehensive regulation by federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by the FERC. Unitil’s distribution utilities are subject to regulation by the applicable state public utility commissions, with regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the NHPUC; Fitchburg is subject to regulation by the MDPU; and Northern Utilities is regulated by the NHPUC and the MPUC. Granite State, Unitil’s interstate natural gas transmission pipeline, is subject to regulation by the FERC with regard to its rates and operations. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in New Hampshire,

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Massachusetts and Maine, Unitil’s customers, with the exception of Northern Utilities’ residential customers, have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

On August 1, 2011, the MDPU issued an order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of Fitchburg. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, to which RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as an increase or a decrease in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company estimates that RDM applies to approximately 27% and 11% of Unitil’s total annual electric and natural gas sales volumes, respectively. As a result, the sales margins resulting from those sales are no longer sensitive to weather and economic factors. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended March 31, 2014 and March 31, 2013 and should be read in conjunction with the accompanying unaudited Consolidated Financial Statements and the accompanying Notes to unaudited Consolidated Financial Statements included in Part I, Item 1 of this report, which are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).

The Company’s results of operations reflect the seasonal nature of the natural gas business. Annual gas revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, the results of operations are historically most favorable in the first and fourth quarters. Fluctuations in seasonal weather conditions may have a significant effect on the result of operations. Sales of electricity are generally less sensitive to weather than natural gas sales, but may also be affected by the weather conditions in both the winter and summer seasons. Also, as a result of recent rate cases, the Company’s natural gas sales margins are derived from a higher percentage of fixed billing components, including customer charges. Therefore, natural gas revenues and margin will be less affected by the seasonal nature of the natural gas business. In addition, as discussed above, approximately 27% and 11% of the Company’s total annual electric and natural gas sales volumes, respectively, are decoupled and changes in sales to existing customers do not affect sales margin.

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Earnings Overview

The Company’s Earnings Applicable to Common Shareholders (Net Income) was $12.6 million, an increase of $1.8 million, or 17%, compared to the Company’s results for the first quarter of 2013. Earnings Per Share was $0.91 for the first quarter of 2014, up $0.12 per share compared to 2013. The Company’s earnings for the first three months of 2014 were driven by increases in natural gas and electric sales and margins.

Natural gas sales margins were $36.5 million in the first quarter of 2014, an increase of $6.0 million compared to the same period in 2013. Natural gas sales margins in the first quarter of 2014 were positively affected by higher therm unit sales, a growing customer base and recently approved distribution rates. Therm sales of natural gas increased 14.9% in the first quarter of 2014 compared to 2013, driven by the colder winter weather in the first quarter of 2014 compared to 2013. Based on weather data collected in the Company’s service areas, there were 12% more Heating Degree Days in the first quarter of 2014 compared to 2013. Weather-normalized gas therm sales, excluding decoupled sales, in the first quarter of 2014 are estimated to be up 6.4% compared to 2013. As of March 31, 2014, the number of total natural gas customers served has increased by 3.1% in the last twelve months.

Electric sales margins were $19.2 million in the first quarter of 2014, an increase of $0.8 million compared to 2013, reflecting higher electric kilowatt-hour (kWh) sales and recently approved electric distribution rates. Electric kWh sales increased 5.0% in the first quarter of 2014 compared to 2013, driven by the colder winter weather in the first quarter of 2014 compared to 2013.

Operation and Maintenance (O&M) expenses increased $1.9 million in the three months ended March 31, 2014 compared to the same period in 2013. The change in O&M expenses reflects higher compensation costs of $0.9 million, higher employee and retiree benefit costs of $0.6 million and higher utility operating costs of $0.5 million; partially offset by lower all other operating costs, net of $0.1 million.

Depreciation and Amortization expense increased $0.7 million in the three months ended March 31, 2014 compared to the same period in 2013, reflecting higher depreciation of $0.5 million on normal utility plant additions and higher amortization of major storm restoration costs of $0.2 million.

Taxes Other Than Income Taxes increased $0.8 million in the three months ended March 31, 2014 compared to the same period in 2013, reflecting higher local property taxes on higher levels of utility plant in service.

Interest Expense, net increased $0.6 million in the three months ended March 31, 2014 compared to the same period in 2013, reflecting lower interest income on regulatory assets.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $1.6 million in the first quarter of 2014, an increase of $0.1 million compared to the first quarter of 2013.

In 2013, Unitil’s annual common dividend was $1.38, continuing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January, 2014 and April, 2014 meetings, Unitil’s Board of Directors declared quarterly dividends on the Company’s common stock of $0.345 per share.

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A more detailed discussion of the Company’s results of operations for the three months ended March 31, 2014 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 14.9% in the three months ended March 31, 2014 compared to the same period in 2013, reflecting increases of 18.0% and 13.9% in sales to Residential and Commercial and Industrial (C&I) customers, respectively. The increase in gas therm sales in the Company’s utility service territories was driven by the colder winter weather in the first quarter of 2014 compared to 2013 coupled with strong growth in the number of new residential and C&I customers. Based on weather data collected in the Company’s service areas, there were 12% more Heating Degree Days in the first quarter of 2014 compared to the same period in 2013. Weather-normalized gas therm sales, excluding decoupled sales, are estimated to be up 6.4% in the first quarter of 2014 compared to the same period in 2013. As of March 31, 2014, the number of total natural gas customers served has increased by 3.1% in the last twelve months.

The following table details total firm therm sales for the three months ended March 31, 2014 and 2013, by major customer class:

Therm Sales (millions)
	Three Months Ended March 31,
	2014		2013		Change		% Change
Residential		22.9		19.4		3.5		18.0	%
Commercial/Industrial		70.5		61.9		8.6		13.9	%
Total		93.4		81.3		12.1		14.9	%

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three months ended March 31, 2014 and 2013:

Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended March 31,
	2014		2013		$ Change		% Change
Gas Operating Revenues:
Residential	$	37.7	$	29.4	$	8.3		28.2	%
Commercial / Industrial		54.9		41.4		13.5		32.6	%
Total Gas Operating Revenues	$	92.6	$	70.8	$	21.8		30.8	%
Cost of Gas Sales	$	56.1	$	40.3	$	15.8		39.2	%
Gas Sales Margin	$	36.5	$	30.5	$	6.0		19.7	%

The Company analyzes operating results using Gas Sales Margin, a non-GAAP measure. Gas Sales Margin is calculated as Total Gas Operating Revenue less Cost of Gas Sales. The Company believes Gas Sales Margin is a better measure to analyze profitability than Total Gas

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Operating Revenue because the approved cost of sales are tracked and reconciled costs that are passed through directly to the customer, resulting in an equal and offsetting amount reflected in Total Gas Operating Revenue.

Natural gas sales margin was $36.5 million in the three months ended March 31, 2014, an increase of $6.0 million compared to the same period in 2013. Approximately $2.3 million of this increase reflects higher natural gas distribution rates, and $3.7 million of the increase reflects higher sales volumes related to the effect of the colder winter weather and customer growth.

The increase in Total Gas Operating Revenues of $21.8 million in the first quarter of 2014 reflects higher gas sales margin of $6.0 million and higher Cost of Gas Sales of $15.8 million, which are tracked and reconciled costs that are passed through directly to customers.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – In the first quarter of 2014, Unitil’s total electric kWh sales increased 5.0% compared to the first quarter of 2013. Sales to Residential and C&I customers increased 7.2% and 3.3%, respectively, in the first quarter of 2014 compared to the same period in 2013, driven by the effect of colder winter weather in the first quarter of 2014 compared to 2013 coupled with the addition of new residential and C&I customers. As discussed above, sales margin derived from decoupled sales is not sensitive to changes in electric kWh sales. As of March 31, 2014, the number of total electric customers served has increased by 0.6% in the last twelve months.

The following table details total kWh sales for the three months ended March 31, 2014 and 2013 by major customer class:

kWh Sales (millions)
	Three Months Ended March 31,
	2014		2013		Change		% Change
Residential		201.9		188.4		13.5		7.2	%
Commercial/Industrial		245.1		237.3		7.8		3.3	%
Total		447.0		425.7		21.3		5.0	%

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Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three months ended March 31, 2014 and 2013:

Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended March 31,
	2014		2013		$ Change		% Change
Electric Operating Revenues:
Residential	$	34.8	$	26.2	$	8.6		32.8	%
Commercial / Industrial		27.1		19.7		7.4		37.6	%
Total Electric Operating Revenues	$	61.9	$	45.9	$	16.0		34.9	%
Total Cost of Electric Sales	$	42.7	$	27.5	$	15.2		55.3	%
Electric Sales Margin	$	19.2	$	18.4	$	0.8		4.3	%

The Company analyzes operating results using Electric Sales Margin, a non-GAAP measure. Electric Sales Margin is calculated as Total Electric Operating Revenues less Cost of Electric Sales. The Company believes Electric Sales Margin is a better measure to analyze profitability than Total Electric Operating Revenues because the approved cost of sales are tracked and reconciled costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in Total Electric Operating Revenues.

Electric sales margin was $19.2 million in the three months ended March 31, 2014, an increase of $0.8 million compared to the same period in 2013. Approximately $0.5 million of this increase reflects higher electric distribution rates and, $0.3 million of this increase reflects higher sales volumes related to the effect of the colder winter weather and customer growth.

The increase in Total Electric Operating Revenues of $16.0 million in the first quarter of 2014 reflects higher electric sales margin of $0.8 million and higher Costs of Electric Sales of $15.2 million, which are tracked and reconciled costs that are passed through directly to customers.

Operating Revenue – Other

The following table details total Other Operating Revenue for the three months ended March 31, 2014 and 2013:

Other Operating Revenue (Millions)
	Three Months Ended March 31,
	2014		2013		$ Change		% Change
Other	$	1.6	$	1.5	$	0.1		6.7	%
Total Other Operating Revenue	$	1.6	$	1.5	$	0.1		6.7	%

Total Other Operating Revenue, which is comprised of revenues from the Company’s non-regulated energy brokering business, Usource, increased $0.1 million in the three month period ended March 31, 2014 compared to the same period in 2013. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

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Operating Expenses

Cost of Gas Sales – Cost of Gas Sales includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements and spending on energy efficiency programs. Cost of Gas Sales increased $15.8 million, or 39.2%, in the three months ended March 31, 2014 compared to the same period in 2013. This increase reflects higher sales of natural gas and higher wholesale natural gas prices, partially offset by an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Gas Sales in its rates at cost on a pass through basis and therefore changes in approved expenses do not affect earnings.

Cost of Electric Sales – Cost of Electric Sales includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs, and spending on energy efficiency programs. Cost of Electric Sales increased $15.2 million, or 55.3%, in the three months ended March 31, 2014 compared to the same period in 2013. This increase reflects higher electric kWh sales, higher wholesale electricity prices and increased spending on energy efficiency programs, partially offset by an increase in the amount of electricity purchased by customers directly from third-party suppliers. The Company reconciles and recovers the approved Cost of Electric Sales in its rates at cost and therefore changes in approved expenses do not affect earnings.

Operation and Maintenance – O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s other business activities. O&M expenses increased $1.9 million, or 12.5%, in the three months ended March 31, 2014 compared to the same period in 2013. The change in O&M expenses reflects higher compensation costs of $0.9 million, higher employee and retiree benefit costs of $0.6 million and higher utility operating costs of $0.5 million; partially offset by lower all other operating costs, net of $0.1 million.

Depreciation and Amortization – Depreciation and Amortization expense increased $0.7 million, or 7.4%, in the three months ended March 31, 2014 compared to the same period in 2013, reflecting higher depreciation of $0.5 million on normal utility plant additions and higher amortization of major storm restoration costs of $0.2 million.

Taxes Other Than Income Taxes – Taxes Other Than Income Taxes increased $0.8 million, or 21.1%, in the three months ended March 31, 2014 compared to the same period in 2013, reflecting higher local property taxes on higher levels of utility plant in service.

Other Expense, net – Other Expense, net in the three month period ended March 31, 2014 were flat compared to the same period in 2013.

Income Taxes – Federal and State Income Taxes increased by $1.1 million for the three months ended March 31, 2014 compared to the same period in 2013, reflecting higher pre-tax earnings in the current period.

Interest Expense, net

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

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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.

Interest Expense, net (millions)	Three Months Ended March 31,
	2014			2013			Change
Interest Expense
Long-term Debt	$	5.1		$	5.1		$	—
Short-term Debt		0.3			0.3			—
Regulatory Liabilities		0.1			—			0.1
Subtotal Interest Expense		5.5			5.4			0.1
Interest (Income)
Regulatory Assets		(0.2	)		(0.7	)		0.5
AFUDC and Other		(0.1	)		(0.1	)		—
Subtotal Interest (Income)		(0.3	)		(0.8	)		0.5
Total Interest Expense, net	$	5.2		$	4.6		$	0.6

Interest Expense, net increased $0.6 million in the three months ended March 31, 2014 compared to the same period in 2013, reflecting lower interest income on regulatory assets.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities. The Company initially supplements internally generated funds through bank borrowings, as needed, under its unsecured short-term revolving credit facility. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets. Additionally, from time to time, the Company has accessed the public capital markets through public offerings of equity securities. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The amount, type and timing of any future financing will vary from year to year based on capital needs and maturity or redemptions of securities.

The Company and its subsidiaries are individually and collectively members of the Unitil Cash Pool (the “Cash Pool”). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on actual interest costs from lenders under the Company’s revolving Credit Facility. At March 31, 2014, March 31, 2013 and December 31, 2013, the Company and all of its subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

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On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.375%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as March 31, 2014, March 31, 2013 and December 31, 2013:

	Revolving Credit Facility (millions)
	March 31,				December 31,
	2014		2013		2013
Limit	$	120.0	$	60.0	$	120.0
Outstanding	$	59.2	$	32.6	$	60.2
Available	$	60.8	$	27.4	$	59.8

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 March 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date. (See also “Credit Arrangements” in Note 5.)

In April 2014, Unitil Service Corp. entered into an arrangement for the financing of the construction and installation of a customer information system, including software and equipment. The financing arrangement is structured as a construction line of credit in the maximum amount of $15 million, available until August 31, 2015, which will convert into a lease when the project is complete. The lease has an initial term of five years. The Company received its first funding under this financing arrangement in April 2014 in the amount of $4.4 million. These funds were used to pay down short-term borrowings.

The continued availability of various methods of financing, as well as the choice of a specific form of security for such financing, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

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The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of March 31, 2014, there were approximately $31.0 million of guarantees outstanding and the longest term guarantee extends through April 2015.

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 $3.3 million, $3.3 million and $12.5 million of natural gas storage inventory at March 31, 2014, March 31, 2013 and December 31, 2013, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2014 and payable in April 2014 is $2.2 million and is recorded in Accounts Payable at March 31, 2014. The amount of natural gas inventory released in March 2013 and payable in April 2013 was $1.7 million and was recorded in Accounts Payable at March 31, 2013. The amount of natural gas inventory released in December 2013 and payable in January 2014 was $2.7 million and was recorded in Accounts Payable at December 31, 2013.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of March 31, 2014, the principal amount outstanding for the 8% Unitil Realty notes was $2.2 million, and the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

Off-Balance Sheet Arrangements

The Company and its subsidiaries do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.

Cash Flows

Unitil’s utility operations, taken as a whole, are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows. The tables below summarize the major sources and uses of cash (in millions) for the three months ended March 31, 2014 compared to the same period in 2013.

	Three Months Ended March 31,
	2014		2013
Cash Provided by Operating Activities	$	28.7	$	40.8

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $28.7 million in the first quarter of 2014, a decrease of $12.1 million compared to 2013. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $29.8 million in 2014 compared to $25.7 million in 2013, representing an increase of $4.1 million principally driven by higher net income and deferred taxes in 2014. Working capital changes in Current Assets and Liabilities resulted in a ($0.6) million net use of cash in 2014 compared to a $8.9 million net source of cash in 2013, representing a decrease of $9.5 million. The decrease in cash flow from working capital was principally driven by a reduction in cash flow from accrued revenue of $9.0 million reflecting lower collections of flowthrough costs in 2014. Deferred

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Regulatory and Other Charges resulted in a ($1.9) million use of cash in 2014 compared to a $2.9 million source of cash in 2013. All Other, net operating activities resulted in a source of cash of $1.4 million in 2014 compared to a source of cash of $3.3 million in 2013.

	Three Months Ended March 31,
	2014			2013
Cash (Used in) Investing Activities	$	(9.2	)	$	(14.4	)

Cash (Used in) Investing Activities – Cash Used in Investing Activities was ($9.2) million for the first quarter of 2014 compared to ($14.4) million in 2013. The lower cash used in investing activities in the 2014 period is reflective of the timing of cash disbursements which is expected to increase during the year. The Company’s capital spending budget for 2014 is $91 million. The capital spending in both periods is representative of normal distribution utility capital expenditures reflecting normal electric and gas utility system additions.

	Three Months Ended March 31,
	2014			2013
Cash (Used in) Financing Activities	$	(14.6	)	$	(28.7	)

Cash (Used in) Financing Activities – Cash Used in Financing Activities was ($14.6) million in the first quarter of 2014 compared to ($28.7) million in 2013. The lower cash used in financing activities in 2014 primarily reflects lower repayments of short-term debt in 2014 of ($1.0) million compared to ($16.8) million in 2013 as a result of lower cash provided by operating activities in 2014.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on January 29, 2014.

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation by the FERC. Fitchburg is also regulated by the

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MDPU, Unitil Energy is regulated by the NHPUC and Northern Utilities is regulated by the MPUC and NHPUC. Granite State, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the Financial Accounting Standards Board Accounting Standards Codification (FASB Codification). In accordance with the FASB Codification, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

The FASB Codification specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets.” If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities.”

The Company’s principal regulatory assets and liabilities are included on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets and Regulatory Liabilities is provided in Note 1 thereto. The Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s consolidated financial statements.

The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

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

On August 1, 2011, the MDPU issued an order approving a RDM for the electric and natural gas divisions of Fitchburg. Revenue decoupling is the term given to the elimination of the dependency of a utility’s distribution revenue on the volume of electricity or natural gas sales. One of the primary purposes of decoupling is to eliminate the disincentive a utility otherwise has to encourage and promote energy conservation programs designed to reduce energy usage. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011

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forward, distribution revenues for Fitchburg based on established revenue targets. The established revenue targets for the gas division may be subject to periodic adjustments to account for customer growth and special contracts, for which the RDM does not apply. The difference between distribution revenue amounts billed to customers and the targeted amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company’s other electric and natural gas distribution utilities are not subject to the RDM.

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

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

The FASB Codification requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset to recognize the future collection of these obligations in electric and gas rates.

The Company’s RBO and reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s financial statements. 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 the years ended December 31, 2013 and 2012, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $431,000 and $367,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2013 and 2012, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of

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$1,169,000 and $981,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $895,000 and $756,000, respectively. (See Note 9 to the accompanying Consolidated Financial Statements).

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

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

Depreciation – Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s unaudited consolidated financial statements.

Commitments and Contingencies – The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with the FASB Codification as it applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of March 31, 2014, 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 unaudited consolidated financial statements below.

Refer to “Recently Issued Pronouncements” in Note 1 of the Notes to the unaudited Consolidated Financial Statements for information regarding recently issued accounting standards.

LABOR RELATIONS

As of March 31, 2014, the Company and its subsidiaries had 483 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

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As of March 31, 2014, a total of 159 employees of certain of the Company’s subsidiaries were represented by labor unions. There are 44 union employees of Fitchburg covered by a collective bargaining agreement (CBA) which expires on May 31, 2019; 34 union employees of Northern Utilities’ New Hampshire division covered by a separate CBA which expires on June 5, 2014; 37 union employees of Northern Utilities’ Maine division and Granite State covered by a separate CBA which expires on March 31, 2017; 39 union employees of Unitil Energy Systems covered by a separate CBA which expires on May 31, 2018 and 5 union employees of Unitil Service Corp. covered by a separate CBA which expires on May 31, 2016. The agreements provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings for the three months ended March 31, 2014 and March 31, 2013 were 1.55% and 1.98%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2013 was 1.8%.

COMMODITY PRICE RISK

Although Unitil’s three distribution utilities are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for the reconciliation and collection of approved Purchased Electric and Purchased Gas costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

REGULATORY MATTERS

Please refer to Note 6 to the unaudited Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Regulatory Matters.

ENVIRONMENTAL MATTERS

Please refer to Note 7 to the unaudited Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Environmental Matters.

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Item 1. Financial Statements

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except per share data)

(UNAUDITED)

	Three Months Ended March 31,
	2014		2013
Operating Revenues
Gas	$	92.6	$	70.8
Electric		61.9		45.9
Other		1.6		1.5
Total Operating Revenues		156.1		118.2
Operating Expenses
Cost of Gas Sales		56.1		40.3
Cost of Electric Sales		42.7		27.5
Operation and Maintenance		17.1		15.2
Depreciation and Amortization		10.2		9.5
Taxes Other Than Income Taxes		4.6		3.8
Total Operating Expenses		130.7		96.3
Operating Income		25.4		21.9
Interest Expense, net		5.2		4.6
Other Expense, net		0.1		0.1
Income Before Income Taxes		20.1		17.2
Income Taxes		7.5		6.4
Earnings Applicable to Common Shareholders	$	12.6	$	10.8
Earnings Per Common Share (Basic and Diluted)	$	0.91	$	0.79
Weighted Average Common Shares Outstanding – (Basic and Diluted)		13.8		13.7
Dividends Declared Per Share of Common Stock	$	0.345	$	0.69

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)

	March 31,				December 31,
	2014		2013		2013
ASSETS:
Current Assets:
Cash and Cash Equivalents	$	14.3	$	7.5	$	9.4
Accounts Receivable, net		69.5		62.0		52.2
Accrued Revenue		49.6		47.4		56.6
Exchange Gas Receivable		1.3		1.7		10.8
Gas Inventory		0.6		0.5		1.2
Materials and Supplies		5.1		4.6		5.0
Prepayments and Other		5.2		5.3		4.8
Total Current Assets		145.6		129.0		140.0
Utility Plant:
Gas		483.0		429.7		477.3
Electric		377.3		359.6		375.6
Common		31.6		32.7		31.6
Construction Work in Progress		21.3		21.2		24.6
Total Utility Plant		913.2		843.2		909.1
Less: Accumulated Depreciation		246.4		234.9		243.5
Net Utility Plant		666.8		608.3		665.6
Other Noncurrent Assets:
Regulatory Assets		96.5		130.0		100.1
Other Assets		19.1		18.2		14.9
Total Other Noncurrent Assets		115.6		148.2		115.0
TOTAL ASSETS	$	928.0	$	885.5	$	920.6

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions, except number of shares)

(UNAUDITED)

	March 31,				December 31,
	2014		2013		2013
LIABILITIES AND CAPITALIZATION:
Current Liabilities:
Accounts Payable	$	31.8	$	27.1	$	38.1
Short-Term Debt		59.2		32.6		60.2
Long-Term Debt, Current Portion		2.5		0.5		2.5
Energy Supply Obligations		6.1		7.1		14.4
Deferred Income Taxes		3.4		4.9		6.7
Dividends Declared and Payable		—		4.8		—
Environmental Obligations		1.4		1.0		1.0
Interest Payable		5.4		5.4		3.1
Regulatory Liabilities		13.1		11.6		9.7
Other Current Liabilities		8.8		8.9		9.0
Total Current Liabilities		131.7		103.9		144.7
Noncurrent Liabilities:
Deferred Income Taxes		82.5		52.5		73.2
Cost of Removal Obligations		59.2		53.0		57.3
Retirement Benefit Obligations		79.1		107.2		77.3
Environmental Obligations		12.8		13.8		13.8
Other Noncurrent Liabilities		4.0		5.4		4.3
Total Noncurrent Liabilities		237.6		231.9		225.9
Capitalization:
Long-Term Debt, Less Current Portion		284.7		287.2		284.8
Common Stock Equity:
Common Equity (Outstanding: 13,886,768, 13,812,763 and 13,841,400 Shares)		233.1		230.7		232.1
Retained Earnings		40.7		31.6		32.9
Total Common Stock Equity		273.8		262.3		265.0
Preferred Stock		0.2		0.2		0.2
Total Capitalization	$	558.7	$	549.7	$	550.0
TOTAL LIABILITIES AND CAPITALIZATION	$	928.0	$	885.5	$	920.6

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)

	Three Months Ended March 31,
	2014			2013
Operating Activities:
Net Income	$	12.6		$	10.8
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		10.2			9.5
Deferred Tax Provision		7.0			5.4
Changes in Working Capital Items:
Accounts Receivable		(17.3	)		(14.3	)
Accrued Revenue		7.0			16.0
Exchange Gas Receivable		9.5			7.7
Regulatory Liabilities		3.4			4.8
Accounts Payable		(6.3	)		(5.6	)
Other Changes in Working Capital Items		3.1			0.3
Deferred Regulatory and Other Charges		(1.9	)		2.9
Other, net		1.4			3.3
Cash Provided by Operating Activities		28.7			40.8
Investing Activities:
Property, Plant and Equipment Additions		(9.2	)		(14.4	)
Cash (Used in) Investing Activities		(9.2	)		(14.4	)
Financing Activities:
Repayment of Short-Term Debt, net		(1.0	)		(16.8	)
Repayment of Long-Term Debt		(0.1	)		(0.1	)
Net Decrease in Exchange Gas Financing		(8.8	)		(7.2	)
Dividends Paid		(4.8	)		(4.8	)
Proceeds from Issuance of Common Stock		0.3			0.3
Other, net		(0.2	)		(0.1	)
Cash (Used in) Financing Activities		(14.6	)		(28.7	)
Net Increase (Decrease) in Cash		4.9			(2.3	)
Cash at Beginning of Period		9.4			9.8
Cash at End of Period	$	14.3		$	7.5
Supplemental Cash Flow Information:
Interest Paid	$	3.0		$	2.9
Income Taxes Paid	$	0.3		$	0.8
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$	0.4		$	1.0

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)

(UNAUDITED)

	Common Equity		Retained Earnings			Total
Balance at January 1, 2014	$	232.1	$	32.9		$	265.0
Net Income				12.6			12.6
Dividends on Common Shares				(4.8	)		(4.8	)
Stock Compensation Plans		0.7					0.7
Issuance of 9,868 Common Shares		0.3					0.3
Balance at March 31, 2014	$	233.1	$	40.7		$	273.8
Balance at January 1, 2013	$	230.0	$	30.4		$	260.4
Net Income				10.8			10.8
Dividends on Common Shares				(9.6	)		(9.6	)
Stock Compensation Plans		0.4					0.4
Issuance of 10,922 Common Shares		0.3					0.3
Balance at March 31, 2013	$	230.7	$	31.6		$	262.3

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The Company’s results are expected to reflect the seasonal nature of the natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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

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

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

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

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Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2013, as filed with the Securities and Exchange Commission (SEC) on January 29, 2014, for a description of the Company’s Basis of Presentation.

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

Level 1 –	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 –	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3 –	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

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

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

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

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

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liabilities and expenses in accordance with the FASB Codification guidance on Income Taxes. The Company classifies penalty and interest expense related to income tax liabilities as income tax expense and interest expense, respectively, in the Consolidated Statements of Earnings.

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

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator – New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations. As of March 31, 2014, March 31, 2013 and December 31, 2013, the Unitil subsidiaries had deposited $9.8 million, $5.6 million and $7.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. As of March 31, 2014, March 31, 2013 and December 31, 2013, there was $0.1 million, $0 and $0, respectively, deposited for this purpose.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

The Allowance for Doubtful Accounts as of March 31, 2014, March 31, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:

($ millions)
	March 31,				December 31,
	2014		2013		2013
Allowance for Doubtful Accounts	$	2.1	$	2.0	$	1.6

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Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Accrued Revenue ($ millions)	2014		2013		2013
Regulatory Assets – Current	$	39.7	$	37.0	$	43.6
Unbilled Revenues		9.9		10.4		13.0
Total Accrued Revenue	$	49.6	$	47.4	$	56.6

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2014		2013		2013
Northern Utilities	$	1.0	$	1.5	$	9.8
Fitchburg		0.3		0.2		1.0
Total Exchange Gas Receivable	$	1.3	$	1.7	$	10.8

Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Gas Inventory ($ millions)	2014		2013		2013
Natural Gas	$	0.2	$	—	$	0.8
Propane		0.1		0.3		0.3
Liquefied Natural Gas & Other		0.3		0.2		0.1
Total Gas Inventory	$	0.6	$	0.5	$	1.2

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At March 31, 2014, March 31, 2013 and December 31, 2013, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $59.2 million, $53.0 million, and $57.3 million, respectively.

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

	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2014		2013		2013
Energy Supply & Other Regulatory Tracker Mechanisms	$	30.3	$	26.2	$	32.5
Deferred Restructuring Costs		6.9		17.0		9.3
Retirement Benefit		42.3		62.4		42.6
Income Taxes		10.7		10.0		11.9
Environmental		16.0		16.7		16.1
Deferred Storm Charges		24.2		27.7		25.6
Other		5.8		7.0		5.7
Total Regulatory Assets	$	136.2	$	167.0	$	143.7
Less: Current Portion of Regulatory Assets(1)		39.7		37.0		43.6
Regulatory Assets – noncurrent	$	96.5	$	130.0	$	100.1

⁽¹⁾  Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2014		2013		2013
Regulatory Tracker Mechanisms	$	13.1	$	11.6	$	9.7
Total Regulatory Liabilities	$	13.1	$	11.6	$	9.7

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of

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deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation.

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

The Company has 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. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of March 31, 2014, all futures contracts purchased under the prior program design were sold and the hedging portfolio now consists entirely of call option contracts.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of March 31, 2014, March 31, 2013 and December 31, 2013 the Company had 1.1 billion, 1.7 billion and 1.8 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and

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Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
		Fair Value
Description	Balance Sheet Location	March 31, 2014		March 31, 2013		December 31, 2013
Derivative Assets
Natural Gas Futures/Options Contracts	Prepayments and Other	$	0.2	$	0.5	$	0.1
Natural Gas Futures/Options Contracts	Other Assets		—		—		0.1
Total Derivative Assets		$	0.2	$	0.5	$	0.2
Derivative Liabilities
Natural Gas Futures/Options Contracts	Other Current Liabilities	$	—	$	—	$	—
Natural Gas Futures/Options Contracts	Other Noncurrent Liabilities		—		—		—
Total Derivative Liabilities		$	—	$	—	$	—

	Three Months Ended March 31,
($ millions)	2014		2013
Amount of Loss (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures/Options Contracts	$	0.9	$	(0.3	)
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.9	$	0.9

⁽¹⁾  These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

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Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current Energy Supply Obligations and the noncurrent amount of Energy Supply Obligations which is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	March 31,				December 31,
Energy Supply Obligations ($ millions)	2014		2013		2013
Current:
Exchange Gas Obligation	$	1.0	$	1.5	$	9.8
Renewable Energy Portfolio Standards		4.3		4.7		3.7
Power Supply Contract Divestitures		0.8		0.9		0.9
Total Energy Supply Obligations – Current	$	6.1	$	7.1	$	14.4
Long-Term:
Power Supply Contract Divestitures	$	2.3	$	3.1	$	2.5
Total Energy Supply Obligations	$	8.4	$	10.2	$	16.9

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

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

Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling rate mechanism.

Power Supply Contract Divestitures – As a result of the restructuring of the utility industry in New Hampshire and Massachusetts, Unitil Energy’s and Fitchburg’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. In connection with the implementation of retail choice, Unitil Power, which formerly functioned as the wholesale power supply provider for Unitil Energy, and Fitchburg divested their long-term power supply contracts

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through the sale of the entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs. The obligations related to these divestitures are recorded in Energy Supply Obligations on the Company’s Consolidated Balance Sheets with corresponding regulatory assets recorded in Accrued Revenue (current portion) and Regulatory Assets (long-term portion).

Massachusetts Green Communities Act – In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts have been approved by the MDPU and are pending facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg recovers its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Recently Issued Pronouncements – There are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period, other than the financing arrangement entered into by Unitil Service Corp. in April 2014 (see Note 4), the Company did not have any material subsequent events that impacted its unaudited consolidated financial statements.

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. The Company has reclassified certain regulatory tracker and rate reconciliation mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting and reclassified the funding of regulatory-approved major storm cost reserves from Operation and Maintenance expense to Depreciation and Amortization expense on the Company’s Consolidated Statements of Earnings. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration Date	Date Paid (Payable)	Shareholder of Record Date		Dividend Amount
04/22/14	05/29/14		05/15/14	$ 0.345
01/16/14	02/28/14		02/14/14	$ 0.345
09/18/13	11/15/13		11/01/13	$ 0.345
06/05/13	08/15/13		08/01/13	$ 0.345
03/28/13	05/15/13		05/01/13	$ 0.345
01/17/13	02/15/13		02/01/13	$ 0.345

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NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three months ended March 31, 2014 and March 31, 2013:

	Electric		Gas		Other		Non-Regulated		Total
Three Months Ended March 31, 2014 ($ millions)
Revenues	$	61.9	$	92.6	$	—	$	1.6	$	156.1
Segment Profit		0.9		11.5		—		0.2		12.6
Identifiable Segment Assets		405.1		506.1		11.0		5.8		928.0
Capital Expenditures		5.1		3.0		1.0		0.1		9.2
Three Months Ended March 31, 2013 ($ millions)
Revenues	$	45.9	$	70.8	$	—	$	1.5	$	118.2
Segment Profit		2.0		8.3		0.1		0.4		10.8
Identifiable Segment Assets		411.5		462.2		5.5		6.3		885.5
Capital Expenditures		7.0		6.9		0.5		—		14.4
As of December 31, 2013 ($ millions)
Identifiable Segment Assets	$	502.3	$	402.8	$	6.2	$	9.3	$	920.6

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NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt

Details on long-term debt at March 31, 2014, March 31, 2013 and December 31, 2013 are shown below:

($ millions)	March 31,				December 31,
	2014		2013		2013
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
Unitil Energy Systems, Inc.:
First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0		15.0
Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0		50.0
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0		10.0
Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		2.2		2.7		2.3
Total Long-Term Debt		287.2		287.7		287.3
Less: Current Portion		2.5		0.5		2.5
Total Long-term Debt, Less Current Portion	$	284.7	$	287.2	$	284.8

The fair value of the Company’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt at March 31, 2014 is

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estimated to be approximately $332.8 million, before considering any costs, including prepayment costs, to market the Company’s debt. Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.375%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of March 31, 2014, March 31, 2013 and December 31, 2013:

	Revolving Credit Facility (millions)
	March 31,				December 31,
	2014		2013		2013
Limit	$	120.0	$	60.0	$	120.0
Outstanding	$	59.2	$	32.6	$	60.2
Available	$	60.8	$	27.4	$	59.8

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 March 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

In April 2014, Unitil Service Corp. entered into an arrangement for the financing of the construction and installation of a customer information system, including software and equipment. The financing arrangement is structured as a construction line of credit in the maximum amount of $15 million, available until August 31, 2015, which will convert into a lease when the project is complete. The lease has an initial term of five years. The Company received its first funding under this financing arrangement in April 2014 in the amount of $4.4 million. These funds were used to pay down short-term borrowings.

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

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gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $3.2 million, $3.3 million and $12.5 million of natural gas storage inventory at March 31, 2014, March 31, 2013 and December 31, 2013, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2014 and payable in April 2014 is $2.2 million and is recorded in Accounts Payable at March 31, 2014. The amount of natural gas inventory released in March 2013 and payable in April 2013 was $1.7 million and was recorded in Accounts Payable at March 31, 2013. The amount of natural gas inventory released in December 2013 and payable in January 2014 was $2.7 million and was recorded in Accounts Payable at December 31, 2013.

Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of March 31, 2014, there were approximately $31.0 million of guarantees outstanding and the longest term guarantee extends through April 2015.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of March 31, 2014, the principal amount outstanding for the 8% Unitil Realty notes was $2.2 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of March 31, 2014, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol, “UTL.”

The Company had 13,886,768, 13,812,763 and 13,841,400 shares of common stock outstanding at March 31, 2014, March 31, 2013 and December 31, 2013, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first quarter of 2014, the Company sold 9,868 shares of its common stock, at an average price of $31.39 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $310,000. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

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

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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. Awards may be grossed up to offset the participant’s tax obligations in connection with the award. For purposes of compensation expense, Restricted Shares vest immediately upon a participant becoming eligible for retirement, as defined in the Stock Plan. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death.

On January 31, 2014, 35,500 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.1 million. There were 69,073 and 53,480 non-vested shares under the Stock Plan as of March 31, 2014 and 2013, respectively. The weighted average grant date fair value of these shares was $28.52 and $25.99, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.1 million and $0.4 million for the three months ended March 31, 2014 and 2013, respectively. At March 31, 2014, there was approximately $1.1 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 3.0 years. There were no forfeitures or cancellations under the Stock Plan during the three months ended March 31, 2014.

Restricted Stock Units

Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the three months ended March 31, 2014 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2013		14,903	$	28.90
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		163	$	31.48
Restricted Stock Units Settled		—		—
Restricted Stock Units as of March 31, 2014		15,066	$	28.93

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There were 3,932 Restricted Stock Units outstanding as of March 31, 2013 with a weighted average stock price of $27.39. The fair value of liabilities associated with the cash portion of fully-vested Restricted Stock Units is approximately $0.2 million, less than $0.1 million and approximately $0.2 million as of March 31, 2014, March 31, 2013 and December 31, 2013, respectively, and is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

Preferred Stock

There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of March 31, 2014, March 31, 2013 and December 31, 2013. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three month periods ended March 31, 2014 and March 31, 2013, respectively.

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.

Regulatory Matters

Northern Utilities – Base Rates – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years, and covers targeted capital expenditures in 2013 through 2016. The settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan (SQP) that Northern Utilities has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern Utilities will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP. On February 28, 2014 Northern Utilities filed its first annual TIRA for rates effective May 1, 2014, seeking an annual increase in base distribution revenue of $1.3 million. This filing is pending final approval of the MPUC. TIRA filings in future periods are projected to result in annual increases in revenue of approximately $1.0 million each year.

Northern Utilities – Base Rates – New Hampshire – On April 21, 2014, the NHPUC approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. In addition, the settlement agreement provides for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provides for an annual increase in revenue of $1.4 million, effective May 1, 2014. The 2015 step adjustment is for a projected annual increase in revenue of approximately $1.4 million, effective May 1, 2015. The settlement agreement also provides for Earning Sharing where Northern Utilities would be allowed to retain all earnings up to a return of

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10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement provides that the Company’s next filing of a distribution base rate case is to be based on an historic test year of no earlier than twelve months ending December 31, 2016. The newly-approved rates will be reconciled to the effective date temporary rates were established, July 1, 2013.

Unitil Energy – Base Rates – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On March 3, 2014 Unitil Energy filed its third step increase of $1.5 million in annual revenue for effect on May 1, 2014, subject to final approval of the NHPUC.

Granite State – Base Rates – Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects. Granite State received approval from the FERC for its latest annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The next rate adjustment is scheduled to be filed in the second quarter of this year for a projected $0.6 million for rates effective August 1, 2014.

Fitchburg – Electric Base Rates Filed – In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or 11.5% over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism to adjust base electric distribution revenue annually by means of either i) a capital cost tracker mechanism, or ii) a multi-year rate plan featuring a revenue cap inflation-based index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms through a reconciling storm recovery adjustment factor beginning January 1, 2015. Hearings were held over a three week period during January 2014, and the matter has been fully briefed. A final rate order is expected in the second quarter of 2014.

Major Storms – Fitchburg and Unitil Energy

Superstorm Sandy – On October 29-30, 2012, a severe storm struck the eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.7 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm, including $0.3 million and $0.4 million related to capital construction for Fitchburg and Unitil Energy, respectively. The amount and timing of the cost recovery of these storm restoration expenditures for Fitchburg will be determined in its rate case. The cost recovery for Unitil Energy has been approved as discussed below. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

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Fitchburg – Storm Cost Deferral – On May 1, 2012 the MDPU approved Fitchburg’s request to defer $4.3 million of 2011 storm costs associated with Tropical Storm Irene and the October 2011 snowstorm, and Fitchburg is seeking recovery of these costs in the electric rate case it filed in July 2013.

Unitil Energy – 2012 Storm Costs – On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Fitchburg – Electric Operations – On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation, pending investigation by the MDPU.

Fitchburg – Service Quality – On March 1, 2014, Fitchburg submitted its 2013 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for its gas division. The electric division met or exceeded all metric benchmarks except for two measures relating to the performance of certain individual distribution circuits as compared to the performance of the system as a whole. As a result of penalty offsets earned in six metrics where company performance exceeded the benchmark measure, however, no penalties are due.

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

Fitchburg – Other – On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, has commenced an investigation of the incident, with which Fitchburg is cooperating. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition or results of operations.

On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The SJC, however, declined to rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. In the Company’s August 1, 2011 rate decision, the MDPU held that the approval of dollar for dollar collection of supply-related bad debt in the

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Company’s rate cases in 2006 (gas) and 2007 (electric) satisfied the requirement for a hearing ordered by the SJC. The MDPU opened a docket to address the amounts collected by Fitchburg between the time the MDPU first approved dollar for dollar collection of the Company’s bad debt, and the rate decisions in 2006 and 2007. Briefs were filed in June 2013. This matter remains pending before the MDPU.

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

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth,” which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. The Act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisitions for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU also opened a proceeding, as mandated by the Act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor. On December 17, 2013, the MDPU issued an order establishing the new rate design allocation methodologies. The Act also requires electric distribution companies to participate in joint solicitations and enter into additional long-term renewable contracts for 4% of distribution company load. A Request For Proposal for a long-term renewable energy contract, jointly prepared by Fitchburg and the other utility companies in consultation with the Massachusetts Attorney General and the Massachusetts Department of Energy Resources and approved by the MDPU, was issued in the Spring of 2013. After analysis and contract negotiations, contracts for six projects were awarded and submitted for MDPU approval. Three of the contracts were terminated during the approval process, and the MDPU approved the remaining three contracts. Fitchburg’s costs associated with these contracts will be recovered through a MDPU approved tariff.

On December 23, 2013 the MDPU issued two orders related to Grid Modernization. The MDPU opened an investigation on its own motion into Modernization of the Electric Grid and, in a separate but related order, opened an investigation into Electric Vehicles and Electric Vehicle Charging. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. It sets forth a straw proposal which would require each electric distribution company to submit a ten-year strategic grid modernization plan (GMP) within six months of a final Order. As part of the GMP each company must also include a comprehensive advanced metering plan (CAMP), and each company is required to achieve advanced metering functionality. The filing of a GMP will be a recurring obligation and must be updated as part of subsequent base distribution

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rate cases, which by statute must occur no less often than every five years. A cost recovery mechanism is proposed only for investments in advanced metering. The MDPU also proposes to address in separate, upcoming proceedings (1) time varying rates, (2) cybersecurity, privacy, and access to meter data, and (3) electric vehicles (EVs). In the Electric Vehicle Order, the MDPU seeks to establish policies and regulations that will help facilitate and accommodate the widespread adoption of EVs. Among other objectives, the proceeding looks to evaluate (1) EV charging and its impact on the electric distribution system, (2) electric distribution company involvement in EV charging, (3) residential metering practices and rates for EVs, and (4) consumer protection issues. These matters remain pending.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC accepted the matter for review, briefs have been submitted and oral arguments have been held. The decision of the SJC is pending. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the SJC in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of March 31, 2014, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

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

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. In April 2014, the State of Maine announced its intention to acquire the site via an eminent domain taking for the expansion of the adjacent marine terminal. Northern Utilities continues to negotiate with the State of Maine on the details of the taking. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs pending either the outcome of negotiations with the State of Maine or until all remedial activities are completed.

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

Included in Environmental Obligations on the Company’s Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 are $0.4 million and $1.0 million, respectively of current accrued liabilities, and $1.8 million and $1.8 million, respectively, of non-current accrued liabilities 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 anticipates beginning the implementation of a permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the second quarter of 2014. Included in Environmental Obligations on the Company’s Consolidated Balance Sheet at March 31, 2014 and December 31, 2013 are $1.0 million and $0, respectively of current accrued liabilities, and $11.0 million and $12.0 million, respectively, of non-current accrued liabilities related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of this environmental remediation cost is probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs.

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

NOTE 8: INCOME TAXES

The Company filed its tax returns for the year ended December 31, 2012 with the Internal Revenue Service (IRS) in September 2013 and generated federal net operating loss (NOL) carryforward assets of $6.6 million principally due to bonus depreciation and targeted asset repair deductions. As of December 31, 2013, the Company had recorded cumulative federal and state NOL carryforward assets of $17.4 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2013, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

The Company evaluated its tax positions at March 31, 2014 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2010; December 31, 2011; and December 31, 2012.

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

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2013 as filed with the SEC on January 29, 2014 for additional information regarding these plans.

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

	2014			2013
Used to Determine Plan Costs
Discount Rate		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2017

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

	Pension Plan						PBOP Plan						SERP
Three Months Ended March 31,	2014			2013			2014			2013			2014		2013
Service Cost	$	751		$	893		$	497		$	631		$	14	$	18
Interest Cost		1,273			1,142			672			612			68		60
Expected Return on Plan Assets		(1,561	)		(1,489	)		(230	)		(180	)		—		—
Prior Service Cost Amortization		53			52			420			425			3		3
Actuarial Loss Amortization		712			1,059			14			196			25		46
Sub-total		1,228			1,657			1,373			1,684			110		127
Amounts Capitalized and Deferred		(344	)		(616	)		(473	)		(769	)		—		—
Net Periodic Benefit Cost Recognized	$	884		$	1,041		$	900		$	915		$	110	$	127

Employer Contributions

As of March 31, 2014, the Company had made $0.9 million of contributions to its Pension Plan in 2014 and had not made any contributions to its PBOP Plan in 2014. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2014 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of March 31, 2014, the Company had made $13,000 of contributions to the SERP Plan in 2014. The Company presently anticipates contributing an additional $40,000 to the SERP Plan in 2014.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Commodity Price Risk” sections of Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (above).

Item 4. Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of March 31, 2014. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of March 31, 2014 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

There have been no changes in the Company’s internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) during the fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

46

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of March 31, 2014, the Registrant continues to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 6 and 7 to the unaudited Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2013 as filed with the SEC on January 29, 2014.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Recent Sales of Unregistered Securities

There were no sales of unregistered equity securities by the Company during the fiscal quarter ended March 31, 2014.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table shows purchases made by or on behalf of the Company or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act)) of shares of the Company’s common stock during the fiscal quarter ended March 31, 2014.

	Total Number of Shares Purchased (1)		Average Price Paid per Share (1)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)(3)
1/1/14 – 1/31/14		—		—		—	$	8,303
2/1/14 – 2/28/14		—		—		—	$	8,303
3/1/14 – 3/31/14		157	$	31.16		157	$	—
Total		157				157

⁽¹⁾  All purchases were made pursuant to the Company’s 2013 Trading Plan (as defined below).

47

⁽²⁾  On March 28, 2013, the Company adopted a written trading plan under Rule 10b5-1 (the 2013 Trading Plan) under the Exchange Act to facilitate the repurchase of shares of its common stock on the open market in connection with its Employee Length of Service Awards and the stock portion of its Directors’ annual retainer. On March 29, 2013, the Company filed a Current Report on Form 8-K announcing that it had adopted the 2013 Trading Plan. The 2013 Trading Plan provides for the repurchase of up to $91,800 worth of shares of the Company’s common stock during its term. The 2013 Trading Plan became effective on March 28, 2013 and terminated on March 28, 2014 (that is, the 2013 Trading Plan terminated during the period covered by the table above).

⁽³⁾  The Company anticipates the adoption of a new written trading plan under Rule 10b5-1 (the 2014 Trading Plan) under the Exchange Act in May 2014 to facilitate the repurchase of shares of its common stock on the open market in connection with its Employee Length of Service Awards and the common stock portion of its Directors’ annual retainer during the remainder of 2014 and the first quarter of 2015.

Item 5. Other Information

On April 23, 2014, the Company issued a press release announcing its results of operations for the three-month period ended March 31, 2014. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

48

Item 6. Exhibits

(a) Exhibits

Exhibit No.	Description of Exhibit	Reference
11	Computation in Support of Earnings Per Average Common Share	Filed herewith
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Unitil Corporation Press Release Dated April 23, 2014 Announcing Earnings For the Quarter Ended March 31, 2014.	Filed herewith
101.INS	XBRL Instance Document.	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema Document.	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith

49

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	UNITIL CORPORATION
	(Registrant)
Date: April 23, 2014	/s/ Mark H. Collin
	Mark H. Collin
	Chief Financial Officer
Date: April 23, 2014	/s/ Laurence M. Brock
	Laurence M. Brock
	Chief Accounting Officer

50

EXHIBIT INDEX

Exhibit No.	Description of Exhibit	Reference
11	Computation in Support of Earnings Per Average Common Share	Filed herewith
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith
32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith
99.1	Unitil Corporation Press Release Dated April 23, 2014 Announcing Earnings For the Quarter Ended March 31, 2014.	Filed herewith
101.INS	XBRL Instance Document.	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema Document.	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	Filed herewith
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith

51

EX-11

EXHIBIT 11

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

COMPUTATION OF EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING

($ Millions, except for per share data)

(UNAUDITED)

	Three Months Ended March 31,
	2014		2013
Net Income	$	12.6	$	10.8
Less: Dividend Requirements on Preferred Stock		—		—
Net Income Applicable to Common Stock	$	12.6	$	10.8
Weighted Average Number of Common Shares Outstanding – Basic (000’s)		13,819		13,748
Dilutive Effect of Stock Options and Restricted Stock (000’s)		3		2
Weighted Average Number of Common Shares Outstanding – Diluted (000’s)		13,822		13,750
Earnings Per Share – Basic	$	0.91	$	0.79
Earnings Per Share – Diluted	$	0.91	$	0.79

EX-31.1

Exhibit 31.1

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Robert G. Schoenberger, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 23, 2014

/s/ Robert G. Schoenberger

Robert G. Schoenberger

Chief Executive Officer and President

EX-31.2

Exhibit 31.2

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark H. Collin, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 23, 2014

/s/ Mark H. Collin

Mark H. Collin

Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Laurence M. Brock, certify that:

1) I have reviewed this quarterly report on Form 10-Q of Unitil Corporation;

2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonable likely to materially affect, the registrant’s internal controls over financial reporting; and

5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 23, 2014

/s/ Laurence M. Brock

Laurence M. Brock

Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Unitil Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned Robert G. Schoenberger, Chief Executive Officer and President, Mark H. Collin, Chief Financial Officer and Laurence M. Brock, Chief Accounting Officer, certifies, to the best knowledge and belief of the signatory, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Signature	Capacity	Date
/s/ Robert G. Schoenberger
Robert G. Schoenberger	Chief Executive Officer and President	April 23, 2014
/s/ Mark H. Collin
Mark H. Collin	Chief Financial Officer	April 23, 2014
/s/ Laurence M. Brock
Laurence M. Brock	Chief Accounting Officer	April 23, 2014

EX-99.1

Exhibit 99.1

PAGE 1 OF 4

For Release

UNITIL REPORTS FIRST QUARTER EARNINGS

HAMPTON, N.H., APRIL 23, 2014 — Unitil Corporation (NYSE: UTL) (www.unitil.com) today announced Net Income of $12.6 million for the first quarter of 2014, an increase of $1.8 million, or 17%, compared to the Company’s results for the first quarter of 2013. Earnings Per Share was $0.91 for the first quarter of 2014, up $0.12 per share compared to 2013. The Company’s earnings for the first three months of 2014 were driven by increases in natural gas and electric sales and margins.

“Unitil had an excellent first quarter, and our financial results reflect the combination of the colder winter weather in 2014 and the positive impact of steady customer growth,” said Robert G. Schoenberger, Unitil’s Chairman and Chief Executive Officer. “We believe we have all the elements in place for sustained long-term growth.”

Natural gas sales margins were $36.5 million in the first quarter of 2014, an increase of $6.0 million compared to the same period in 2013. Natural gas sales margins in the first quarter of 2014 were positively affected by higher therm unit sales, a growing customer base and recently approved distribution rates. Therm sales of natural gas increased 14.9% in the first quarter of 2014 compared to 2013, driven by the colder winter weather in the first quarter of 2014 compared to 2013. Based on weather data collected in the Company’s service areas, there were 12% more Heating Degree Days in the first quarter of 2014 compared to 2013. Weather-normalized gas therm sales, excluding decoupled sales, in the first quarter of 2014 are estimated to be up 6.4% compared to 2013. As of March 31, 2014, the number of total natural gas customers served has increased by 3.1% in the last twelve months.

Electric sales margins were $19.2 million in the first quarter of 2014, an increase of $0.8 million compared to 2013, reflecting higher electric kilowatt-hour (kWh) sales and recently approved electric distribution rates. Electric kWh sales increased 5.0% in the first quarter of 2014 compared to 2013, driven by the colder winter weather in the first quarter of 2014 compared to 2013.

6 Liberty Lane West

Hampton, New Hampshire 03842

www.unitil.com

Ph: 603-772-0775 Fax: 603-773-6605

(Continued on Next Page)

PAGE 2 OF 4

Usource, the Company’s non-regulated energy brokering business, recorded sales margin of $1.6 million in the first quarter of 2014, an increase of $0.1 million compared to the first quarter of 2013.

Operation and Maintenance (O&M) expenses increased $1.9 million in the three months ended March 31, 2014 compared to the same period in 2013. The change in O&M expenses reflects higher compensation costs of $0.9 million, higher employee and retiree benefit costs of $0.6 million and higher utility operating costs of $0.5 million; partially offset by lower all other operating costs, net of $0.1 million.

Depreciation, Amortization, Taxes and other expenses increased $2.6 million in the three months ended March 31, 2014 compared to the same period in 2013. Depreciation expense increased $0.5 million and property taxes increased $0.8 million in the three months ended March 31, 2014 compared to the same period in 2013, due to higher levels of utility plant in service. Amortization expense increased $0.2 million in 2014 due to higher amortization of storm restoration costs. Federal and State Income Taxes increased $1.1 million for the three months ended March 31, 2014, reflecting higher pre-tax earnings in the current period.

Interest Expense, net increased $0.6 million in the three months ended March 31, 2014 compared to the same period in 2013, reflecting lower interest income on regulatory assets.

At its January 2014 and April 2014 meetings, Unitil’s Board of Directors declared quarterly dividends on the Company’s common stock of $0.345 per share. These quarterly dividends result in a current effective annual dividend rate of $1.38 per share continuing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

The Company’s results are expected to reflect the seasonal nature of the natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

The Company will hold a quarterly conference call to discuss first quarter 2014 results on Wednesday, April 23, 2014, at 2:00 p.m. Eastern Time. This call is being webcast and can be accessed in the Investor Relations section of Unitil’s website, www.unitil.com.

(Continued on Next Page)

PAGE 3 OF 4

Selected financial data for 2014 and 2013 is presented in the following table:

Unitil Corporation – Condensed Financial Data

(Millions, except Per Share and Shares Data) (Unaudited)

	Three Months Ended March 31,
	2014		2013		Change
Gas Therm Sales:
Residential		22.9		19.4		18.0	%
Commercial/Industrial		70.5		61.9		13.9	%
Total Gas Therm Sales		93.4		81.3		14.9	%
Electric kWh Sales:
Residential		201.9		188.4		7.2	%
Commercial/Industrial		245.1		237.3		3.3	%
Total Electric kWh Sales		447.0		425.7		5.0	%
Gas Revenues	$	92.6	$	70.8	$	21.8
Cost of Gas Sales		56.1		40.3		15.8
Gas Sales Margin		36.5		30.5		6.0
Electric Revenues		61.9		45.9		16.0
Cost of Electric Sales		42.7		27.5		15.2
Electric Sales Margin		19.2		18.4		0.8
Usource Sales Margin		1.6		1.5		0.1
Total Sales Margin		57.3		50.4		6.9
Operation & Maintenance Expenses		17.1		15.2		1.9
Depreciation, Amortization, Taxes & Other		22.4		19.8		2.6
Interest Expense, Net		5.2		4.6		0.6
Net Income	$	12.6	$	10.8	$	1.8
Earnings Per Share	$	0.91	$	0.79	$	0.12
Weighted Average Common Shares Outstanding (000’s)		13,822		13,750		72

(Continued on Next Page)

PAGE 4 OF 4

About Unitil Corporation

Unitil Corporation provides energy for life by safely and reliably delivering natural gas and electricity in New England. We are committed to the communities we serve and to developing people, business practices, and technologies that lead to dependable, more efficient energy. Unitil Corporation is a public utility holding company with operations in Maine, New Hampshire and Massachusetts. Together, Unitil’s operating utilities serve approximately 102,400 electric customers and 75,900 natural gas customers. Other subsidiaries include Usource, Unitil’s non-regulated business segment. For more information about our people, technologies, and community involvement please visit www.unitil.com.

Forward-Looking Statements

This press release contains forward-looking statements. All statements, other than statements of historical fact, included in this press release are forward-looking statements. Forward-looking statements include declarations regarding Unitil’s beliefs and current expectations. These forward-looking statements are subject to the inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include the following: Unitil’s regulatory environment (including regulations relating to climate change, greenhouse gas emissions and other environmental matters); fluctuations in the supply of, the demand for, and the prices of energy commodities and transmission capacity and Unitil’s ability to recover energy commodity costs in its rates; customers’ preferred energy sources; severe storms and Unitil’s ability to recover storm costs in its rates; general economic conditions; variations in weather; long-term global climate change; Unitil’s ability to retain its existing customers and attract new customers; Unitil’s energy brokering customers’ performance under multi-year energy brokering contracts; increased competition; and other risks detailed in Unitil’s filings with the Securities and Exchange Commission, including those appearing under the caption “Risk Factors” in Unitil’s Annual Report on Form 10-K for the year ended December 31, 2013. These forward looking statements speak only as of the date they are made. Unitil undertakes no obligation, and does not intend, to update these forward-looking statements.

For more information please contact:

David Chong – Investor Relations	Alec O’Meara – Media Relations
Phone: 603-773-6499	Phone: 603-773-6404
Email: chong@unitil.com	Email: omeara@unitil.com

XML

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility (Detail) (Revolving Credit Facility, USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Oct. 04, 2013	Mar. 31, 2013
Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility	$ 120.0	$ 120.0	$ 120.0	$ 60.0
Outstanding revolving credit facility	59.2	60.2		32.6
Available revolving credit facility	$ 60.8	$ 59.8		$ 27.4

XML

Components of Retirement Plan Costs (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Plans
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	$ 751	$ 893
Interest Cost	1,273	1,142
Expected Return on Plan Assets	(1,561)	(1,489)
Prior Service Cost Amortization	53	52
Actuarial Loss Amortization	712	1,059
Sub-total	1,228	1,657
Amounts Capitalized and Deferred	(344)	(616)
Net Periodic Benefit Cost Recognized	884	1,041
Other Postretirement Benefit Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	497	631
Interest Cost	672	612
Expected Return on Plan Assets	(230)	(180)
Prior Service Cost Amortization	420	425
Actuarial Loss Amortization	14	196
Sub-total	1,373	1,684
Amounts Capitalized and Deferred	(473)	(769)
Net Periodic Benefit Cost Recognized	900	915
Supplemental Employee Retirement Plans, Defined Benefit
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Service Cost	14	18
Interest Cost	68	60
Prior Service Cost Amortization	3	3
Actuarial Loss Amortization	25	46
Sub-total	110	127
Net Periodic Benefit Cost Recognized	$ 110	$ 127

XML

Energy Supply Obligations (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Contractual Obligation [Line Items]
Energy Supply Obligations	$ 6.1	$ 14.4	$ 7.1
Total Energy Supply Obligations	8.4	16.9	10.2
Exchange Gas Obligation
Contractual Obligation [Line Items]
Energy Supply Obligations	1.0	9.8	1.5
Renewable Energy Portfolio Standards
Contractual Obligation [Line Items]
Energy Supply Obligations	4.3	3.7	4.7
Power Supply Contract Divestitures
Contractual Obligation [Line Items]
Energy Supply Obligations	0.8	0.9	0.9
Energy Supply Obligations	$ 2.3	$ 2.5	$ 3.1

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Allowance for Doubtful Accounts Included in Accounts Receivable Net (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Valuation Allowance [Line Items]
Allowance for Doubtful Accounts	$ 2.1	$ 1.6	$ 2.0

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Regulatory Matters - Additional Information (Detail) (USD $)	1 Months Ended		3 Months Ended		1 Months Ended								3 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended	1 Months Ended		3 Months Ended
	Mar. 03, 2014 Unitil Energy Systems Inc	Oct. 31, 2012 Unitil Energy Systems Inc	Mar. 31, 2014 Unitil Energy Systems Inc	Apr. 25, 2013 Unitil Energy Systems Inc	Apr. 25, 2013 Unitil Energy Systems Inc Storm Costs	Jul. 31, 2013 Fitchburg Gas and Electric Light Company	Oct. 31, 2012 Fitchburg Gas and Electric Light Company	May 01, 2012 Fitchburg Gas and Electric Light Company	Jul. 31, 2013 Fitchburg Gas and Electric Light Company Storm Costs	Feb. 28, 2014 Northern Utilities Inc	Dec. 27, 2013 Northern Utilities Inc	Apr. 21, 2013 Northern Utilities Inc	Mar. 31, 2014 Northern Utilities Inc	Dec. 27, 2013 Northern Utilities Inc Maine	Mar. 31, 2014 Northern Utilities Inc Maine	Apr. 21, 2013 Northern Utilities Inc New Hampshire	Mar. 31, 2014 Northern Utilities Inc New Hampshire	Apr. 21, 2013 Northern Utilities Inc New Hampshire Natural Gas Distribution	Jun. 30, 2013 Granite State Gas Transmission Inc Gas Transportation and Storage	Jun. 30, 2014 Granite State Gas Transmission Inc Gas Transportation and Storage Scenario Forecast
Regulatory Matters [Line Items]
Increase in annual revenue						$ 6,700,000			$ 2,100,000			$ 1,400,000	$ 1,000,000	$ 3,800,000		$ 1,400,000		$ 4,600,000
Amendment effective date			May 1, 2014										May 1, 2014		January 1, 2014		May 1, 2015
TIRA initial term													Four years
Percentage of eligibility for earnings											10.00%	10.00%
Percentage of earnings shared equally											11.00%	11.00%
Service quality plan penalties impossed											500,000
First annual TIRA Adjustment										1,300,000
First annual TIRA Adjustment, effective date													May 1, 2014
Percent of increase in annual revenue						11.50%										9.50%
Adjustment to recover the increased spending for vegetation management program and reliability enhancement program and a proposed storm resiliency program	1,500,000
Settlement agreement date	May 01, 2016
Annual revenue increase in rate adjustments																			400,000	600,000
Recovery of damage of electrical system		2,700,000					1,100,000
Construction expenditures		400,000					300,000
Storm expenditures								4,300,000
Recovery of damage of electrical system					$ 2,300,000
Cost recovery period, years					5 years
Interest rate allowed by regulators on the unrecovered amount of storm costs which have been approved for recovery through rate adjustments				4.52%

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Details on Long Term Debt (Parenthetical) (Detail)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Stated interest rate	6.33%	6.33%	6.33%
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Stated interest rate	5.24%	5.24%	5.24%
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Stated interest rate	8.49%	8.49%	8.49%
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Stated interest rate	6.96%	6.96%	6.96%
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%	8.00%
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Stated interest rate	6.32%	6.32%	6.32%
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Stated interest rate	6.75%	6.75%	6.75%
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Stated interest rate	7.37%	7.37%	7.37%
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Stated interest rate	7.98%	7.98%	7.98%
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Stated interest rate	6.79%	6.79%	6.79%
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Stated interest rate	5.90%	5.90%	5.90%
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Stated interest rate	6.95%	6.95%	6.95%
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Stated interest rate	5.29%	5.29%	5.29%
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Stated interest rate	7.72%	7.72%	7.72%
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Stated interest rate	7.15%	7.15%	7.15%
Unitil Realty Corp | 8.00% Senior Secured Notes, Due Through August 1, 2017
Debt Instrument [Line Items]
Stated interest rate	8.00%	8.00%	8.00%

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Retirement Benefit Obligations - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	$ 900,000
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	0
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Contributions to benefit plan	13,000
Expected additional contribution to SERP plan	$ 40,000

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Dividends Declared Per Share

3 Months Ended

Mar. 31, 2014

Dividends Declared Per Share

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration Date	Date Paid (Payable)	Shareholder of Record Date		Dividend Amount
04/22/14	05/29/14		05/15/14	$ 0.345
01/16/14	02/28/14		02/14/14	$ 0.345
09/18/13	11/15/13		11/01/13	$ 0.345
06/05/13	08/15/13		08/01/13	$ 0.345
03/28/13	05/15/13		05/01/13	$ 0.345
01/17/13	02/15/13		02/01/13	$ 0.345

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Environmental Matters - Additional Information (Detail) (USD $) In Millions, unless otherwise specified											3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Mar. 31, 2014 Northern Utilities Inc	Dec. 31, 2013 Northern Utilities Inc	Mar. 31, 2014 Fitchburg Gas and Electric Light Company Environmental Clean Up Costs	Dec. 31, 2013 Fitchburg Gas and Electric Light Company Environmental Clean Up Costs	Mar. 31, 2014 Fitchburg Gas and Electric Light Company Environmental Restoration Costs	Mar. 31, 2014 New Hampshire Environmental Restoration Costs	Mar. 31, 2014 Maine Environmental Restoration Costs	Mar. 31, 2014 Environmental Matters
Site Contingency [Line Items]
Income (loss) incurred in excess of recorded amount											$ 0
Amortization period for environmental costs								7 years	7 years	5 years
Environmental obligations, Current	1.4	1.0	1.0	0.4	1.0	1.0	0
Environmental obligations, Non-current	$ 12.8	$ 13.8	$ 13.8	$ 1.8	$ 1.8	$ 11.0	$ 12.0

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Regulatory Assets (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013		Mar. 31, 2013
Regulatory Assets [Line Items]
Regulatory Assets	$ 136.2		$ 143.7		$ 167.0
Less: Current Portion of Regulatory Assets	39.7	[1]	43.6	[1]	37.0	[1]
Regulatory Assets - noncurrent	96.5		100.1		130.0
Environmental Matters
Regulatory Assets [Line Items]
Regulatory Assets	16.0		16.1		16.7
Retirement Benefit
Regulatory Assets [Line Items]
Regulatory Assets	42.3		42.6		62.4
Income Taxes
Regulatory Assets [Line Items]
Regulatory Assets	10.7		11.9		10.0
Electric Utilities
Regulatory Assets [Line Items]
Regulatory Assets	24.2		25.6		27.7
Other Assets
Regulatory Assets [Line Items]
Regulatory Assets	5.8		5.7		7.0
Energy Supply & Other Regulatory Tracker Mechanisms
Regulatory Assets [Line Items]
Regulatory Assets	30.3		32.5		26.2
Deferred Restructuring Costs
Regulatory Assets [Line Items]
Regulatory Assets	$ 6.9		$ 9.3		$ 17.0

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

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Components of Gas Inventory (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.6	$ 1.2	$ 0.5
Natural Gas
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.2	0.8
Propane
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	0.1	0.3	0.3
Liquefied Natural Gas & Other
Public Utilities, Inventory [Line Items]
Weighted average cost inventory amount	$ 0.3	$ 0.1	$ 0.2

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Income Taxes - Additional Information (Detail) (USD $) In Millions, unless otherwise specified		3 Months Ended		12 Months Ended
	Dec. 31, 2013	Mar. 31, 2014 Federal	Dec. 31, 2013 Federal and State	Dec. 31, 2013 State and Local Jurisdiction	Dec. 31, 2013 Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Net Operating Loss carryforward assets			$ 17.4		$ 6.6
NOL carryforward assets expiration date				2019	2029
Alternative Minimum tax credit carryforwards	$ 1.5
Tax examination description		The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2010; December 31, 2011; and December 31, 2012.

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Regulatory Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.1	$ 9.7	$ 11.6
Regulatory Tracker Mechanisms
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 13.1	$ 9.7	$ 11.6

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Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets (Detail) (Not Designated as Hedging Instrument, USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Derivative Assets
Derivative Assets	$ 0.2	$ 0.2	$ 0.5
Derivative Liabilities
Derivative Liabilities
Natural Gas Future/Options Contract | Prepayments and Other
Derivative Assets
Derivative Assets	0.2	0.1	0.5
Natural Gas Future/Options Contract | Other Assets
Derivative Assets
Derivative Assets		0.1
Natural Gas Future/Options Contract | Other Current Liabilities
Derivative Liabilities
Derivative Liabilities
Natural Gas Future/Options Contract | Other Noncurrent Liabilities
Derivative Liabilities
Derivative Liabilities

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2014

Summary of Significant Accounting Policies

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

The Company’s results are expected to reflect the seasonal nature of the natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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

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

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

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

Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2013, as filed with the Securities and Exchange Commission (SEC) on January 29, 2014, for a description of the Company’s Basis of Presentation.

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

Level 1 –	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 –	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3 –	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

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

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

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

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

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

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator – New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations. As of March 31, 2014, March 31, 2013 and December 31, 2013, the Unitil subsidiaries had deposited $9.8 million, $5.6 million and $7.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. As of March 31, 2014, March 31, 2013 and December 31, 2013, there was $0.1 million, $0 and $0, respectively, deposited for this purpose.

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

The Allowance for Doubtful Accounts as of March 31, 2014, March 31, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:

($ millions)
	March 31,				December 31,
	2014		2013		2013
Allowance for Doubtful Accounts	$	2.1	$	2.0	$	1.6

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Accrued Revenue ($ millions)	2014		2013		2013
Regulatory Assets – Current	$	39.7	$	37.0	$	43.6
Unbilled Revenues		9.9		10.4		13.0
Total Accrued Revenue	$	49.6	$	47.4	$	56.6

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2014		2013		2013
Northern Utilities	$	1.0	$	1.5	$	9.8
Fitchburg		0.3		0.2		1.0
Total Exchange Gas Receivable	$	1.3	$	1.7	$	10.8

Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Gas Inventory ($ millions)	2014		2013		2013
Natural Gas	$	0.2	$	—	$	0.8
Propane		0.1		0.3		0.3
Liquefied Natural Gas & Other		0.3		0.2		0.1
Total Gas Inventory	$	0.6	$	0.5	$	1.2

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At March 31, 2014, March 31, 2013 and December 31, 2013, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $59.2 million, $53.0 million, and $57.3 million, respectively.

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

	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2014		2013		2013
Energy Supply & Other Regulatory Tracker Mechanisms	$	30.3	$	26.2	$	32.5
Deferred Restructuring Costs		6.9		17.0		9.3
Retirement Benefit		42.3		62.4		42.6
Income Taxes		10.7		10.0		11.9
Environmental		16.0		16.7		16.1
Deferred Storm Charges		24.2		27.7		25.6
Other		5.8		7.0		5.7
Total Regulatory Assets	$	136.2	$	167.0	$	143.7
Less: Current Portion of Regulatory Assets(1)		39.7		37.0		43.6
Regulatory Assets – noncurrent	$	96.5	$	130.0	$	100.1

⁽¹⁾  Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2014		2013		2013
Regulatory Tracker Mechanisms	$	13.1	$	11.6	$	9.7
Total Regulatory Liabilities	$	13.1	$	11.6	$	9.7

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation.

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

The Company has 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. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of March 31, 2014, all futures contracts purchased under the prior program design were sold and the hedging portfolio now consists entirely of call option contracts.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of March 31, 2014, March 31, 2013 and December 31, 2013 the Company had 1.1 billion, 1.7 billion and 1.8 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
		Fair Value
Description	Balance Sheet Location	March 31, 2014		March 31, 2013		December 31, 2013
Derivative Assets
Natural Gas Futures/Options Contracts	Prepayments and Other	$	0.2	$	0.5	$	0.1
Natural Gas Futures/Options Contracts	Other Assets		—		—		0.1
Total Derivative Assets		$	0.2	$	0.5	$	0.2
Derivative Liabilities
Natural Gas Futures/Options Contracts	Other Current Liabilities	$	—	$	—	$	—
Natural Gas Futures/Options Contracts	Other Noncurrent Liabilities		—		—		—
Total Derivative Liabilities		$	—	$	—	$	—

	Three Months Ended March 31,
($ millions)	2014		2013
Amount of Loss (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures/Options Contracts	$	0.9	$	(0.3	)
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.9	$	0.9

⁽¹⁾  These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current Energy Supply Obligations and the noncurrent amount of Energy Supply Obligations which is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	March 31,				December 31,
Energy Supply Obligations ($ millions)	2014		2013		2013
Current:
Exchange Gas Obligation	$	1.0	$	1.5	$	9.8
Renewable Energy Portfolio Standards		4.3		4.7		3.7
Power Supply Contract Divestitures		0.8		0.9		0.9
Total Energy Supply Obligations – Current	$	6.1	$	7.1	$	14.4
Long-Term:
Power Supply Contract Divestitures	$	2.3	$	3.1	$	2.5
Total Energy Supply Obligations	$	8.4	$	10.2	$	16.9

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

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

Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling rate mechanism.

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

Massachusetts Green Communities Act – In compliance with the Massachusetts Green Communities Act, discussed below in Note 6, Regulatory Matters, Fitchburg has entered into long-term renewable contracts for electric energy and/or renewable energy credits. The facility associated with one of these contracts has been constructed and is operating. The other contracts have been approved by the MDPU and are pending facility construction and operation. These facilities are anticipated to begin operation by the end of 2016. Fitchburg recovers its costs associated with long-term renewable contracts on a fully reconciling basis through a MDPU-approved cost recovery mechanism.

Recently Issued Pronouncements – There are no recently issued pronouncements that the Company has not already adopted or that have a material impact on the Company.

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period, other than the financing arrangement entered into by Unitil Service Corp. in April 2014 (see Note 4), the Company did not have any material subsequent events that impacted its unaudited consolidated financial statements.

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. The Company has reclassified certain regulatory tracker and rate reconciliation mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting and reclassified the funding of regulatory-approved major storm cost reserves from Operation and Maintenance expense to Depreciation and Amortization expense on the Company’s Consolidated Statements of Earnings. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

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Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Cost of Gas Sales (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Natural Gas Future/Options Contract
Regulatory Assets [Line Items]
Loss recognized in Regulatory Assets	$ 0.9		$ (0.3)
Gas Purchase Costs
Regulatory Assets [Line Items]
Loss Reclassified into unaudited Consolidated Statement of Earnings	$ 0.9	[1]	$ 0.9	[1]

[1] These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

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Common Stock and Preferred Stock - Additional Information (Detail) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Class of Stock [Line Items]
Common stock, shares outstanding	13,886,768	13,812,763	13,841,400
Proceed from issuance of common stock	$ 300,000	$ 300,000
Restricted stock issued	35,500
Restricted stock grant date market value	1,100,000
Share based compensation expense	1,100,000	400,000
Percentage of fully-vested restricted stock units that Directors will receive in common shares when settled	70.00%
Percentage of fully-vested restricted stock units that Directors will receive in cash when settled	30.00%
Fair value of liabilities associated with cash portion of fully vested RSUs	200,000		200,000
Preferred Stock	200,000	200,000	200,000
Maximum
Class of Stock [Line Items]
Fair value of liabilities associated with cash portion of fully vested RSUs		100,000
Dividend declared	100,000	100,000
Dividend and Distribution Reinvestment and Share Purchase Plan
Class of Stock [Line Items]
Common stock, share issued	9,868
Common stock price per share	$ 31.39
Proceed from issuance of common stock	310,000
Restricted Stock
Class of Stock [Line Items]
Restricted stock vesting period	4 years
Restricted stock vesting percentage annually	25.00%
Restricted stock issue date	Jan. 31, 2014
Restricted stock non-vested	69,073	53,480
Restricted stock weighted average grant date fair value	$ 28.52	$ 25.99
Unrecognized share based compensation	1,100,000
Share compensation recognition period	3 years
Forfeitures or cancellations under the stock plan	0
Restricted Stock | Maximum
Class of Stock [Line Items]
Restricted stock available for awards	677,500
Restricted stock that may be awarded in any one calendar year to any one participant	20,000
Restricted Stock Units (RSUs)
Class of Stock [Line Items]
Weighted-Average Stock Price		$ 27.39
Restricted stock units outstanding		3,932
Unitil Energy Systems Inc | Series 6
Class of Stock [Line Items]
Preferred stock, outstanding	2,250	2,250	2,250
Preferred Stock	$ 200,000	$ 200,000	$ 200,000
Dividend rate	6.00%	6.00%	6.00%

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Consolidated Statements of Earnings (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Revenues
Gas	$ 92.6	$ 70.8
Electric	61.9	45.9
Other	1.6	1.5
Total Operating Revenues	156.1	118.2
Operating Expenses
Cost of Gas Sales	56.1	40.3
Cost of Electric Sales	42.7	27.5
Operation and Maintenance	17.1	15.2
Depreciation and Amortization	10.2	9.5
Taxes Other Than Income Taxes	4.6	3.8
Total Operating Expenses	130.7	96.3
Operating Income	25.4	21.9
Interest Expense, net	5.2	4.6
Other Expense, net	0.1	0.1
Income Before Income Taxes	20.1	17.2
Income Taxes	7.5	6.4
Earnings Applicable to Common Shareholders	$ 12.6	$ 10.8
Earnings Per Common Share (Basic and Diluted)	$ 0.91	$ 0.79
Weighted Average Common Shares Outstanding - (Basic and Diluted)	13.8	13.7
Dividends Declared Per Share of Common Stock	$ 0.345	$ 0.690

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Key Weighted Average Assumptions Used in Determining Benefit Plan Costs and Obligations (Detail) (Benefit Plan Costs)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Benefit Plan Costs
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	4.80%	4.00%
Rate of Compensation Increase	3.00%	3.00%
Expected Long-term rate of return on plan assets	8.00%	8.50%
Health Care Cost Trend Rate Assumed for Next Year	7.00%	8.00%
Ultimate Health Care Cost Trend Rate	4.00%	4.00%
Year that Ultimate Health Care Cost Trend Rate is reached	2018	2017

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Consolidated Statements of Changes in Common Stock Equity (USD $) In Millions	Total	Common Equity	Retained Earnings
Beginning Balance at Dec. 31, 2012	$ 260.4	$ 230.0	$ 30.4
Net Income	10.8		10.8
Dividends on Common Shares	(9.6)		(9.6)
Stock Compensation Plans	0.4	0.4
Issuance of Common Shares	0.3	0.3
Ending Balance at Mar. 31, 2013	262.3	230.7	31.6
Beginning Balance at Dec. 31, 2013	265.0	232.1	32.9
Net Income	12.6		12.6
Dividends on Common Shares	(4.8)		(4.8)
Stock Compensation Plans	0.7	0.7
Issuance of Common Shares	0.3	0.3
Ending Balance at Mar. 31, 2014	$ 273.8	$ 233.1	$ 40.7

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Significant Segment Financial Data (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	$ 156.1	$ 118.2
Segment Profit	12.6	10.8
Identifiable Segment Assets	928.0	885.5	920.6
Capital Expenditures	9.2	14.4
Electricity
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	61.9	45.9
Segment Profit	0.9	2.0
Identifiable Segment Assets	405.1	411.5	502.3
Capital Expenditures	5.1	7.0
Gas Segment
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	92.6	70.8
Segment Profit	11.5	8.3
Identifiable Segment Assets	506.1	462.2	402.8
Capital Expenditures	3.0	6.9
All Other Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Segment Profit		0.1
Identifiable Segment Assets	11.0	5.5	6.2
Capital Expenditures	1.0	0.5
Unregulated Operation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Revenues	1.6	1.5
Segment Profit	0.2	0.4
Identifiable Segment Assets	5.8	6.3	9.3
Capital Expenditures	$ 0.1

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Common Stock and Preferred Stock (Tables)

3 Months Ended

Mar. 31, 2014

Restricted Stock Units Issued

The equity portion of Restricted Stock Units activity during the three months ended March 31, 2014 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2013		14,903	$	28.90
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		163	$	31.48
Restricted Stock Units Settled		—		—
Restricted Stock Units as of March 31, 2014		15,066	$	28.93

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Details on Long Term Debt (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Debt Instrument [Line Items]
Long-Term Debt	$ 287.2	$ 287.3	$ 287.7
Less: Current Portion	2.5	2.5	0.5
Total Long-term Debt, Less Current Portion	284.7	284.8	287.2
6.33% Notes, Due May 1, 2022
Debt Instrument [Line Items]
Senior Notes	20.0	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 5.24% Series, Due March 2, 2020
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.49% Series, Due October 14, 2024
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.96% Series, Due September 1, 2028
Debt Instrument [Line Items]
Long-Term Debt	20.0	20.0	20.0
Unitil Energy Systems Inc | First Mortgage Bonds 8.00% Series, Due May 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Unitil Energy Systems Inc | First Mortgage Bonds 6.32% Series, Due September 15, 2036
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Fitchburg Gas and Electric Light Company | 6.75% Notes, Due November 30, 2023
Debt Instrument [Line Items]
Long-Term Debt	19.0	19.0	19.0
Fitchburg Gas and Electric Light Company | 7.37% Notes, Due January 15, 2029
Debt Instrument [Line Items]
Long-Term Debt	12.0	12.0	12.0
Fitchburg Gas and Electric Light Company | 7.98% Notes, Due June 1, 2031
Debt Instrument [Line Items]
Long-Term Debt	14.0	14.0	14.0
Fitchburg Gas and Electric Light Company | 6.79% Notes, Due October 15, 2025
Debt Instrument [Line Items]
Long-Term Debt	10.0	10.0	10.0
Fitchburg Gas and Electric Light Company | 5.90% Notes, Due December 15, 2030
Debt Instrument [Line Items]
Long-Term Debt	15.0	15.0	15.0
Northern Utilities Inc | 6.95% Senior Notes, Series A, Due December 3, 2018
Debt Instrument [Line Items]
Senior Notes	30.0	30.0	30.0
Northern Utilities Inc | 5.29% Senior Notes, Due March 2, 2020
Debt Instrument [Line Items]
Senior Notes	25.0	25.0	25.0
Northern Utilities Inc | 7.72% Senior Notes, Series B, Due December 3, 2038
Debt Instrument [Line Items]
Senior Notes	50.0	50.0	50.0
Granite State Gas Transmission Inc | 7.15% Senior Notes, Due December 15, 2018
Debt Instrument [Line Items]
Senior Notes	10.0	10.0	10.0
Unitil Realty Corp | 8.00% Senior Secured Notes, Due Through August 1, 2017
Debt Instrument [Line Items]
Senior Secured Notes	$ 2.2	$ 2.3	$ 2.7

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 mi Bcf	Dec. 31, 2013 Bcf	Mar. 31, 2013 Bcf
Significant Accounting Policies [Line Items]
Length Of Pipeline	86
Cost of removal obligation	$ 59.2	$ 57.3	$ 53.0
Number of Natural Gas Storage Outstanding	1.1	1.8	1.7
Maximum
Significant Accounting Policies [Line Items]
Cash equivalents maturity period	3 months
ISO-NE Obligations
Significant Accounting Policies [Line Items]
Cash Deposits	9.8	7.3	5.6
Natural Gas Hedging Program
Significant Accounting Policies [Line Items]
Cash Deposits	$ 0.1	$ 0	$ 0
Utilities
Significant Accounting Policies [Line Items]
Number of Subsidiaries	3
Other Subsidiaries
Significant Accounting Policies [Line Items]
Number of Subsidiaries	3

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Consolidated Statements of Changes in Common Stock Equity (Parenthetical)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Common Stock, Shares issued	9,868	10,922

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Current Assets:
Cash and Cash Equivalents	$ 14.3	$ 9.4	$ 7.5
Accounts Receivable, net	69.5	52.2	62.0
Accrued Revenue	49.6	56.6	47.4
Exchange Gas Receivable	1.3	10.8	1.7
Gas Inventory	0.6	1.2	0.5
Materials and Supplies	5.1	5.0	4.6
Prepayments and Other	5.2	4.8	5.3
Total Current Assets	145.6	140.0	129.0
Utility Plant:
Gas	483.0	477.3	429.7
Electric	377.3	375.6	359.6
Common	31.6	31.6	32.7
Construction Work in Progress	21.3	24.6	21.2
Total Utility Plant	913.2	909.1	843.2
Less: Accumulated Depreciation	246.4	243.5	234.9
Net Utility Plant	666.8	665.6	608.3
Other Noncurrent Assets:
Regulatory Assets	96.5	100.1	130.0
Other Assets	19.1	14.9	18.2
Total Other Noncurrent Assets	115.6	115.0	148.2
TOTAL ASSETS	928.0	920.6	885.5
Current Liabilities:
Accounts Payable	31.8	38.1	27.1
Short-Term Debt	59.2	60.2	32.6
Long-Term Debt, Current Portion	2.5	2.5	0.5
Energy Supply Obligations	6.1	14.4	7.1
Deferred Income Taxes	3.4	6.7	4.9
Dividends Declared and Payable			4.8
Environmental Obligations	1.4	1.0	1.0
Interest Payable	5.4	3.1	5.4
Regulatory Liabilities	13.1	9.7	11.6
Other Current Liabilities	8.8	9.0	8.9
Total Current Liabilities	131.7	144.7	103.9
Noncurrent Liabilities:
Deferred Income Taxes	82.5	73.2	52.5
Cost of Removal Obligations	59.2	57.3	53.0
Retirement Benefit Obligations	79.1	77.3	107.2
Environmental Obligations	12.8	13.8	13.8
Other Noncurrent Liabilities	4.0	4.3	5.4
Total Noncurrent Liabilities	237.6	225.9	231.9
Capitalization:
Long-Term Debt, Less Current Portion	284.7	284.8	287.2
Common Stock Equity:
Common Equity (Outstanding: 13,886,768, 13,812,763 and 13,841,400 Shares)	233.1	232.1	230.7
Retained Earnings	40.7	32.9	31.6
Total Common Stock Equity	273.8	265.0	262.3
Preferred Stock	0.2	0.2	0.2
Total Capitalization	558.7	550.0	549.7
TOTAL LIABILITIES AND CAPITALIZATION	$ 928.0	$ 920.6	$ 885.5

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

Nature of Operations

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

The Company’s results are expected to reflect the seasonal nature of the natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

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

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

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

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

Basis of Presentation

Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of results to be expected for the year ending December 31, 2014. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2013, as filed with the Securities and Exchange Commission (SEC) on January 29, 2014, for a description of the Company’s Basis of Presentation.

Fair Value

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

Level 1 –	Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 –	Valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly.
Level 3 –	Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable.

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

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

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

Income Taxes

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

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

Cash and Cash Equivalents

Cash and Cash Equivalents – Cash and Cash Equivalents includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. Under the Independent System Operator – New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s subsidiaries Unitil Energy, Fitchburg and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s subsidiaries provide cash deposits covering approximately 2-1/2 months of outstanding obligations. As of March 31, 2014, March 31, 2013 and December 31, 2013, the Unitil subsidiaries had deposited $9.8 million, $5.6 million and $7.3 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. As of March 31, 2014, March 31, 2013 and December 31, 2013, there was $0.1 million, $0 and $0, respectively, deposited for this purpose.

Allowance for Doubtful Accounts

Allowance for Doubtful Accounts – The Company recognizes a provision for doubtful accounts each month based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company’s distribution utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company.

The Allowance for Doubtful Accounts as of March 31, 2014, March 31, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:

($ millions)
	March 31,				December 31,
	2014		2013		2013
Allowance for Doubtful Accounts	$	2.1	$	2.0	$	1.6

Accrued Revenue

Accrued Revenue – Accrued Revenue includes the current portion of Regulatory Assets and unbilled revenues. The following table shows the components of Accrued Revenue as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Accrued Revenue ($ millions)	2014		2013		2013
Regulatory Assets – Current	$	39.7	$	37.0	$	43.6
Unbilled Revenues		9.9		10.4		13.0
Total Accrued Revenue	$	49.6	$	47.4	$	56.6

Exchange Gas Receivable

Exchange Gas Receivable – Northern Utilities and Fitchburg have gas exchange and storage agreements whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers natural gas back to the Company during the months of November through March. The exchange and storage gas volumes are recorded at weighted average cost. The following table shows the components of Exchange Gas Receivable as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2014		2013		2013
Northern Utilities	$	1.0	$	1.5	$	9.8
Fitchburg		0.3		0.2		1.0
Total Exchange Gas Receivable	$	1.3	$	1.7	$	10.8

Gas Inventory

Gas Inventory – The Company uses the weighted average cost methodology to value natural gas inventory. The following table shows the components of Gas Inventory as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Gas Inventory ($ millions)	2014		2013		2013
Natural Gas	$	0.2	$	—	$	0.8
Propane		0.1		0.3		0.3
Liquefied Natural Gas & Other		0.3		0.2		0.1
Total Gas Inventory	$	0.6	$	0.5	$	1.2

Utility Plant

Utility Plant – The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of is charged to the accumulated provision for depreciation. The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, cost of removal amounts to provide for future negative salvage value. At March 31, 2014, March 31, 2013 and December 31, 2013, the Company estimates that the cost of removal amounts, which are recorded on the Consolidated Balance Sheets in Cost of Removal Obligations are $59.2 million, $53.0 million, and $57.3 million, respectively.

Regulatory Accounting

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

	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2014		2013		2013
Energy Supply & Other Regulatory Tracker Mechanisms	$	30.3	$	26.2	$	32.5
Deferred Restructuring Costs		6.9		17.0		9.3
Retirement Benefit		42.3		62.4		42.6
Income Taxes		10.7		10.0		11.9
Environmental		16.0		16.7		16.1
Deferred Storm Charges		24.2		27.7		25.6
Other		5.8		7.0		5.7
Total Regulatory Assets	$	136.2	$	167.0	$	143.7
Less: Current Portion of Regulatory Assets(1)		39.7		37.0		43.6
Regulatory Assets – noncurrent	$	96.5	$	130.0	$	100.1

⁽¹⁾  Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2014		2013		2013
Regulatory Tracker Mechanisms	$	13.1	$	11.6	$	9.7
Total Regulatory Liabilities	$	13.1	$	11.6	$	9.7

Generally, the Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s Consolidated Financial Statements. The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of the FASB Codification topic on Regulated Operations. If unable to continue to apply the FASB Codification provisions for Regulated Operations, the Company would be required to apply the provisions for the Discontinuation of Rate-Regulated Accounting included in the FASB Codification. In the Company’s opinion, its regulated operations will be subject to the FASB Codification provisions for Regulated Operations for the foreseeable future.

Prior to June 30, 2013, certain regulatory tracker mechanisms which are currently recorded in Regulatory Liabilities had been recorded in Accrued Revenue and Other Current Liabilities on the Consolidated Balance Sheets. Amounts previously reported have been reclassified to conform to current year presentation.

Derivatives

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

The Company has 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. Prior to April 2013 Northern Utilities purchased natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to associated delivery months. Beginning in April 2013, the hedging program was redesigned and the Company began purchasing call option contracts on NYMEX natural gas futures contracts for future winter period months. As of March 31, 2014, all futures contracts purchased under the prior program design were sold and the hedging portfolio now consists entirely of call option contracts.

Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through Northern Utilities’ Cost of Gas Adjustment Clause. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Cost of Gas Sales when the gains and losses are passed through to customers through the Cost of Gas Adjustment Clause.

As of March 31, 2014, March 31, 2013 and December 31, 2013 the Company had 1.1 billion, 1.7 billion and 1.8 billion cubic feet (BCF), respectively, outstanding in natural gas futures and options contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. The tables below include disclosure of the derivative assets and liabilities and the recognition of the charges from their corresponding regulatory liabilities and assets, respectively into Cost of Gas Sales. The current and noncurrent portions of these regulatory assets are recorded as Accrued Revenue and Regulatory Assets, respectively, on the Company’s unaudited Consolidated Balance Sheets. The current and noncurrent portions of these regulatory liabilities are recorded as Regulatory Liabilities and Other Noncurrent Liabilities, respectively on the Company’s unaudited Consolidated Balance Sheets.

Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
		Fair Value
Description	Balance Sheet Location	March 31, 2014		March 31, 2013		December 31, 2013
Derivative Assets
Natural Gas Futures/Options Contracts	Prepayments and Other	$	0.2	$	0.5	$	0.1
Natural Gas Futures/Options Contracts	Other Assets		—		—		0.1
Total Derivative Assets		$	0.2	$	0.5	$	0.2
Derivative Liabilities
Natural Gas Futures/Options Contracts	Other Current Liabilities	$	—	$	—	$	—
Natural Gas Futures/Options Contracts	Other Noncurrent Liabilities		—		—		—
Total Derivative Liabilities		$	—	$	—	$	—

	Three Months Ended March 31,
($ millions)	2014		2013
Amount of Loss (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures/Options Contracts	$	0.9	$	(0.3	)
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.9	$	0.9

⁽¹⁾  These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Energy Supply Obligations

Energy Supply Obligations – The following discussion and table summarize the nature and amounts of the items recorded as current Energy Supply Obligations and the noncurrent amount of Energy Supply Obligations which is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

	March 31,				December 31,
Energy Supply Obligations ($ millions)	2014		2013		2013
Current:
Exchange Gas Obligation	$	1.0	$	1.5	$	9.8
Renewable Energy Portfolio Standards		4.3		4.7		3.7
Power Supply Contract Divestitures		0.8		0.9		0.9
Total Energy Supply Obligations – Current	$	6.1	$	7.1	$	14.4
Long-Term:
Power Supply Contract Divestitures	$	2.3	$	3.1	$	2.5
Total Energy Supply Obligations	$	8.4	$	10.2	$	16.9

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

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

Fitchburg has a contract for energy procurement with a renewable energy developer which began commercial production in September 2013. Fitchburg will recover its costs under this contract through a regulatory approved cost tracker reconciling rate mechanism.

Recently Issued Pronouncements

Recently Issued Pronouncements – 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 – The Company has evaluated all events or transactions through the date of this filing. During this period, other than the financing arrangement entered into by Unitil Service Corp. in April 2014 (see Note 4), the Company did not have any material subsequent events that impacted its unaudited consolidated financial statements.

Reclassifications

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation. The Company has reclassified certain regulatory tracker and rate reconciliation mechanisms from Accrued Revenue and Other Current Liabilities to Regulatory Liabilities on the Company’s Consolidated Balance Sheets, as discussed above in Regulatory Accounting and reclassified the funding of regulatory-approved major storm cost reserves from Operation and Maintenance expense to Depreciation and Amortization expense on the Company’s Consolidated Statements of Earnings. Also, energy efficiency program expenses, which were previously presented as Conservation & Load Management on the Company’s Consolidated Statements of Earnings are now included in Cost of Gas Sales and Cost of Electric Sales.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 18, 2014
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Trading Symbol	UTL
Entity Registrant Name	UNITIL CORP
Entity Central Index Key	0000755001
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		13,887,087

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Summary of Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2014

Allowance for Doubtful Accounts Included in Accounts Receivable Net

The Allowance for Doubtful Accounts as of March 31, 2014, March 31, 2013 and December 31, 2013, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:

($ millions)
	March 31,				December 31,
	2014		2013		2013
Allowance for Doubtful Accounts	$	2.1	$	2.0	$	1.6

Components of Accrued Revenue

The following table shows the components of Accrued Revenue as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Accrued Revenue ($ millions)	2014		2013		2013
Regulatory Assets – Current	$	39.7	$	37.0	$	43.6
Unbilled Revenues		9.9		10.4		13.0
Total Accrued Revenue	$	49.6	$	47.4	$	56.6

Components of Exchange Gas Receivable

The following table shows the components of Exchange Gas Receivable as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Exchange Gas Receivable ($ millions)	2014		2013		2013
Northern Utilities	$	1.0	$	1.5	$	9.8
Fitchburg		0.3		0.2		1.0
Total Exchange Gas Receivable	$	1.3	$	1.7	$	10.8

Components of Gas Inventory

The following table shows the components of Gas Inventory as of March 31, 2014, March 31, 2013 and December 31, 2013.

	March 31,				December 31,
Gas Inventory ($ millions)	2014		2013		2013
Natural Gas	$	0.2	$	—	$	0.8
Propane		0.1		0.3		0.3
Liquefied Natural Gas & Other		0.3		0.2		0.1
Total Gas Inventory	$	0.6	$	0.5	$	1.2

Regulatory Assets

	March 31,				December 31,
Regulatory Assets consist of the following ($ millions)	2014		2013		2013
Energy Supply & Other Regulatory Tracker Mechanisms	$	30.3	$	26.2	$	32.5
Deferred Restructuring Costs		6.9		17.0		9.3
Retirement Benefit		42.3		62.4		42.6
Income Taxes		10.7		10.0		11.9
Environmental		16.0		16.7		16.1
Deferred Storm Charges		24.2		27.7		25.6
Other		5.8		7.0		5.7
Total Regulatory Assets	$	136.2	$	167.0	$	143.7
Less: Current Portion of Regulatory Assets(1)		39.7		37.0		43.6
Regulatory Assets – noncurrent	$	96.5	$	130.0	$	100.1

⁽¹⁾  Reflects amounts included in Accrued Revenue, discussed above, on the Company’s Consolidated Balance Sheets.

Regulatory Liabilities

	March 31,				December 31,
Regulatory Liabilities consist of the following ($ millions)	2014		2013		2013
Regulatory Tracker Mechanisms	$	13.1	$	11.6	$	9.7
Total Regulatory Liabilities	$	13.1	$	11.6	$	9.7

Fair Value Amount of Derivative Assets Liabilities Offset in Regulatory Liabilities Assets

Fair Value Amount of Derivative Assets / Liabilities ($ millions) Offset in Regulatory Liabilities / Assets, as of:
		Fair Value
Description	Balance Sheet Location	March 31, 2014		March 31, 2013		December 31, 2013
Derivative Assets
Natural Gas Futures/Options Contracts	Prepayments and Other	$	0.2	$	0.5	$	0.1
Natural Gas Futures/Options Contracts	Other Assets		—		—		0.1
Total Derivative Assets		$	0.2	$	0.5	$	0.2
Derivative Liabilities
Natural Gas Futures/Options Contracts	Other Current Liabilities	$	—	$	—	$	—
Natural Gas Futures/Options Contracts	Other Noncurrent Liabilities		—		—		—
Total Derivative Liabilities		$	—	$	—	$	—

Regulatory Assets Liabilities and Reclassification from Regulatory Assets Liabilities into Purchased Gas

	Three Months Ended March 31,
($ millions)	2014		2013
Amount of Loss (Gain) Recognized in Regulatory Assets (Liabilities) for Derivatives:
Natural Gas Futures/Options Contracts	$	0.9	$	(0.3	)
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings(1):
Cost of Gas Sales	$	0.9	$	0.9

⁽¹⁾  These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

Components of Energy Supply Obligations

	March 31,				December 31,
Energy Supply Obligations ($ millions)	2014		2013		2013
Current:
Exchange Gas Obligation	$	1.0	$	1.5	$	9.8
Renewable Energy Portfolio Standards		4.3		4.7		3.7
Power Supply Contract Divestitures		0.8		0.9		0.9
Total Energy Supply Obligations – Current	$	6.1	$	7.1	$	14.4
Long-Term:
Power Supply Contract Divestitures	$	2.3	$	3.1	$	2.5
Total Energy Supply Obligations	$	8.4	$	10.2	$	16.9

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Consolidated Balance Sheets (Parenthetical)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Common Equity Outstanding	13,886,768	13,841,400	13,812,763

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Common Stock and Preferred Stock

3 Months Ended

Mar. 31, 2014

Common Stock and Preferred Stock

NOTE 5 – COMMON STOCK AND PREFERRED STOCK

Common Stock

The Company’s common stock trades on the New York Stock Exchange under the symbol, “UTL.”

The Company had 13,886,768, 13,812,763 and 13,841,400 shares of common stock outstanding at March 31, 2014, March 31, 2013 and December 31, 2013, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first quarter of 2014, the Company sold 9,868 shares of its common stock, at an average price of $31.39 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $310,000. The DRP provides participants in the plan a method for investing cash dividends on the Company’s common stock and cash payments in additional shares of the Company’s common stock.

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

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

Restricted Shares

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

On January 31, 2014, 35,500 Restricted Shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of approximately $1.1 million. There were 69,073 and 53,480 non-vested shares under the Stock Plan as of March 31, 2014 and 2013, respectively. The weighted average grant date fair value of these shares was $28.52 and $25.99, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $1.1 million and $0.4 million for the three months ended March 31, 2014 and 2013, respectively. At March 31, 2014, there was approximately $1.1 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 3.0 years. There were no forfeitures or cancellations under the Stock Plan during the three months ended March 31, 2014.

Restricted Stock Units

Restricted Stock Units earn dividend equivalents and will generally be settled by payment to each Director as soon as practicable following the Director’s separation from service to the Company. The Restricted Stock Units will be paid such that the Director will receive (i) 70% of the shares of the Company’s common stock underlying the restricted stock units and (ii) cash in an amount equal to the fair market value of 30% of the shares of the Company’s common stock underlying the Restricted Stock Units. The equity portion of Restricted Stock Units activity during the three months ended March 31, 2014 in conjunction with the Stock Plan are presented in the following table:

Restricted Stock Units (Equity Portion)
	Units		Weighted Average Stock Price
Restricted Stock Units as of December 31, 2013		14,903	$	28.90
Restricted Stock Units Granted		—		—
Dividend Equivalents Earned		163	$	31.48
Restricted Stock Units Settled		—		—
Restricted Stock Units as of March 31, 2014		15,066	$	28.93

There were 3,932 Restricted Stock Units outstanding as of March 31, 2013 with a weighted average stock price of $27.39. The fair value of liabilities associated with the cash portion of fully-vested Restricted Stock Units is approximately $0.2 million, less than $0.1 million and approximately $0.2 million as of March 31, 2014, March 31, 2013 and December 31, 2013, respectively, and is included in Other Noncurrent Liabilities on the Company’s Consolidated Balance Sheets.

Preferred Stock

There was $0.2 million, or 2,250 shares, of Unitil Energy’s 6.00% Series Preferred Stock outstanding as of March 31, 2014, March 31, 2013 and December 31, 2013. There were less than $0.1 million of total dividends declared on Preferred Stock in each of the three month periods ended March 31, 2014 and March 31, 2013, respectively.

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Debt and Financing Arrangements

3 Months Ended

Mar. 31, 2014

Debt and Financing Arrangements

NOTE 4 – DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt

Details on long-term debt at March 31, 2014, March 31, 2013 and December 31, 2013 are shown below:

($ millions)	March 31,				December 31,
	2014		2013		2013
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
Unitil Energy Systems, Inc.:
First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0		15.0
Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0		50.0
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0		10.0
Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		2.2		2.7		2.3
Total Long-Term Debt		287.2		287.7		287.3
Less: Current Portion		2.5		0.5		2.5
Total Long-term Debt, Less Current Portion	$	284.7	$	287.2	$	284.8

The fair value of the Company’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt at March 31, 2014 is estimated to be approximately $332.8 million, before considering any costs, including prepayment costs, to market the Company’s debt. Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

Credit Arrangements

On October 4, 2013, the Company entered into an Amended and Restated Credit Agreement with a syndicate of lenders which amended and restated in its entirety the Company’s prior credit agreement, dated as of November 26, 2008, as amended. The Credit Facility extends to October 4, 2018 and provides for a new borrowing limit of $120 million which includes a $25 million sublimit for the issuance of standby letters of credit. The Credit Facility provides Unitil with the ability to elect that borrowings under the Credit Facility bear interest under several options, including at a daily fluctuating rate of interest per annum equal to one-month London Interbank Offered Rate plus 1.375%. Provided there is no event of default under the Credit Facility, the Company may on a one-time basis request an increase in the aggregate commitments under the Credit Facility by an aggregate additional amount of up to $30 million.

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of March 31, 2014, March 31, 2013 and December 31, 2013:

	Revolving Credit Facility (millions)
	March 31,				December 31,
	2014		2013		2013
Limit	$	120.0	$	60.0	$	120.0
Outstanding	$	59.2	$	32.6	$	60.2
Available	$	60.8	$	27.4	$	59.8

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 March 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.

In April 2014, Unitil Service Corp. entered into an arrangement for the financing of the construction and installation of a customer information system, including software and equipment. The financing arrangement is structured as a construction line of credit in the maximum amount of $15 million, available until August 31, 2015, which will convert into a lease when the project is complete. The lease has an initial term of five years. The Company received its first funding under this financing arrangement in April 2014 in the amount of $4.4 million. These funds were used to pay down short-term borrowings.

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 $3.2 million, $3.3 million and $12.5 million of natural gas storage inventory at March 31, 2014, March 31, 2013 and December 31, 2013, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2014 and payable in April 2014 is $2.2 million and is recorded in Accounts Payable at March 31, 2014. The amount of natural gas inventory released in March 2013 and payable in April 2013 was $1.7 million and was recorded in Accounts Payable at March 31, 2013. The amount of natural gas inventory released in December 2013 and payable in January 2014 was $2.7 million and was recorded in Accounts Payable at December 31, 2013.

Guarantees

The Company provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities. The Company’s policy is to limit the duration of these guarantees. As of March 31, 2014, there were approximately $31.0 million of guarantees outstanding and the longest term guarantee extends through April 2015.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of March 31, 2014, the principal amount outstanding for the 8% Unitil Realty notes was $2.2 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10.0 million Granite State notes due 2018. As of March 31, 2014, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

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Retirement Benefit Obligations (Tables)

3 Months Ended

Mar. 31, 2014

Key Weighted Average Assumptions used in Determining Benefit Plan Costs and Obligations

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

	2014			2013
Used to Determine Plan Costs
Discount Rate		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2017

Components of Retirement Plan Costs

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

	Pension Plan						PBOP Plan						SERP
Three Months Ended March 31,	2014			2013			2014			2013			2014		2013
Service Cost	$	751		$	893		$	497		$	631		$	14	$	18
Interest Cost		1,273			1,142			672			612			68		60
Expected Return on Plan Assets		(1,561	)		(1,489	)		(230	)		(180	)		—		—
Prior Service Cost Amortization		53			52			420			425			3		3
Actuarial Loss Amortization		712			1,059			14			196			25		46
Sub-total		1,228			1,657			1,373			1,684			110		127
Amounts Capitalized and Deferred		(344	)		(616	)		(473	)		(769	)		—		—
Net Periodic Benefit Cost Recognized	$	884		$	1,041		$	900		$	915		$	110	$	127

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Dividends Declared Per Share (Tables)

3 Months Ended

Mar. 31, 2014

Schedule of Dividends Declared

Declaration Date	Date Paid (Payable)	Shareholder of Record Date		Dividend Amount
04/22/14	05/29/14		05/15/14	$ 0.345
01/16/14	02/28/14		02/14/14	$ 0.345
09/18/13	11/15/13		11/01/13	$ 0.345
06/05/13	08/15/13		08/01/13	$ 0.345
03/28/13	05/15/13		05/01/13	$ 0.345
01/17/13	02/15/13		02/01/13	$ 0.345

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Income Taxes

3 Months Ended

Mar. 31, 2014

Income Taxes

NOTE 8: INCOME TAXES

The Company filed its tax returns for the year ended December 31, 2012 with the Internal Revenue Service (IRS) in September 2013 and generated federal net operating loss (NOL) carryforward assets of $6.6 million principally due to bonus depreciation and targeted asset repair deductions. As of December 31, 2013, the Company had recorded cumulative federal and state NOL carryforward assets of $17.4 million to offset against taxes payable in future periods. If unused, the Company’s state NOL carryforward assets will begin to expire in 2019 and the federal NOL carryforward assets will begin to expire in 2029. In addition, at December 31, 2013, the Company had $1.5 million of cumulative Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

The Company evaluated its tax positions at March 31, 2014 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any tax liabilities or assets as defined by the FASB Codification is required. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2010; December 31, 2011; and December 31, 2012.

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

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Regulatory Matters

3 Months Ended

Mar. 31, 2014

Regulatory Matters

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.

Regulatory Matters

Northern Utilities – Base Rates – Maine – On December 27, 2013, the Maine Public Utilities Commission (MPUC) approved a settlement agreement providing for a $3.8 million permanent increase in annual revenue for Northern Utilities’ Maine division, effective January 1, 2014. The settlement agreement also provided that the Company shall be allowed to implement a Targeted Infrastructure Replacement Adjustment (TIRA) rate mechanism to adjust base distribution rates annually to recover the revenue requirements associated with targeted investments in gas distribution system infrastructure replacement and upgrade projects. The TIRA has an initial term of four years, and covers targeted capital expenditures in 2013 through 2016. The settlement agreement also provides for Earning Sharing where Northern would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement continues and revises the service quality plan (SQP) that Northern Utilities has been operating under since 2004 and established in Docket No. 2002-140. The revised SQP consists of seven metrics with an appurtenant administrative penalty for failure to meet any of the seven metrics. The settlement agreement further provides that Northern Utilities will be subject to a maximum annual penalty of $500,000 if it fails to meet any of the baseline performance targets under the revised SQP. On February 28, 2014 Northern Utilities filed its first annual TIRA for rates effective May 1, 2014, seeking an annual increase in base distribution revenue of $1.3 million. This filing is pending final approval of the MPUC. TIRA filings in future periods are projected to result in annual increases in revenue of approximately $1.0 million each year.

Northern Utilities – Base Rates – New Hampshire – On April 21, 2014, the NHPUC approved a settlement agreement providing for an increase of $4.6 million in distribution base revenue and a return on equity of 9.5% for Northern Utilities’ New Hampshire division. In addition, the settlement agreement provides for additional step adjustments in 2014 and 2015 to recover the revenue requirements associated with investments in gas mains extensions and infrastructure replacement projects. The 2014 step adjustment provides for an annual increase in revenue of $1.4 million, effective May 1, 2014. The 2015 step adjustment is for a projected annual increase in revenue of approximately $1.4 million, effective May 1, 2015. The settlement agreement also provides for Earning Sharing where Northern Utilities would be allowed to retain all earnings up to a return of 10%. Earnings in excess of 10% and up to and including 11% will be shared equally, between ratepayers and the Company. Earnings in excess of 11% shall be returned to ratepayers. The settlement agreement provides that the Company’s next filing of a distribution base rate case is to be based on an historic test year of no earlier than twelve months ending December 31, 2016. The newly-approved rates will be reconciled to the effective date temporary rates were established, July 1, 2013.

Unitil Energy – Base Rates – On April 26, 2011, the NHPUC approved a rate settlement that extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with a series of step adjustments to increase revenue in future years to support Unitil Energy’s continued capital improvements to its distribution system. On March 3, 2014 Unitil Energy filed its third step increase of $1.5 million in annual revenue for effect on May 1, 2014, subject to final approval of the NHPUC.

Granite State – Base Rates – Granite State has in place a FERC approved rate settlement agreement under which it is permitted each June to file for a rate adjustment to recover the revenue requirements associated with specified capital investments in gas transmission projects. Granite State received approval from the FERC for its latest annual rate adjustment, in the amount of $0.4 million, with rates effective August 1, 2013. The next rate adjustment is scheduled to be filed in the second quarter of this year for a projected $0.6 million for rates effective August 1, 2014.

Fitchburg – Electric Base Rates Filed – In July 2013, Fitchburg filed a rate case with the MDPU requesting approval to increase its electric distribution rates. The Company requested an increase of $6.7 million in electric base revenue or 11.5% over test year operating revenue. Included in the amount of this annual increase is approximately $2.1 million for the recovery over a three year period of extraordinary storm costs incurred by the Company related to three severe storms, Tropical Storm Irene, the October 2011 snowstorm and Superstorm Sandy. The filing includes a proposed modified revenue decoupling mechanism to adjust base electric distribution revenue annually by means of either i) a capital cost tracker mechanism, or ii) a multi-year rate plan featuring a revenue cap inflation-based index. The filing also includes a proposal to establish a major storm reserve fund to address the costs of future major storms through a reconciling storm recovery adjustment factor beginning January 1, 2015. Hearings were held over a three week period during January 2014, and the matter has been fully briefed. A final rate order is expected in the second quarter of 2014.

Major Storms – Fitchburg and Unitil Energy

Superstorm Sandy – On October 29-30, 2012, a severe storm struck the eastern seaboard of the United States, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. Fitchburg and Unitil Energy incurred approximately $1.1 million and $2.7 million, respectively, in costs for the repair and replacement of electric distribution systems damaged during the storm, including $0.3 million and $0.4 million related to capital construction for Fitchburg and Unitil Energy, respectively. The amount and timing of the cost recovery of these storm restoration expenditures for Fitchburg will be determined in its rate case. The cost recovery for Unitil Energy has been approved as discussed below. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations.

Fitchburg – Storm Cost Deferral – On May 1, 2012 the MDPU approved Fitchburg’s request to defer $4.3 million of 2011 storm costs associated with Tropical Storm Irene and the October 2011 snowstorm, and Fitchburg is seeking recovery of these costs in the electric rate case it filed in July 2013.

Unitil Energy – 2012 Storm Costs – On April 25, 2013, the NHPUC approved the recovery of $2.3 million of costs to repair damage to Unitil Energy’s electrical system resulting from Superstorm Sandy over a five-year period, with carrying charges at the Company’s long-term cost of debt, net of deferred taxes, or 4.52%, applied to the uncollected balance through the recovery period.

Fitchburg – Electric Operations – On November 15, 2013, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing also includes the reconciliation of costs and revenues for a number of other surcharges and cost factors which are subject to review and approval by the MDPU. Many of the surcharges and cost factors were redesigned based on cost-based rate design in compliance with a MDPU order in its Investigation into Cost-Based Rate Design for Reconciliation Factors, which resulted from the “Act Relative to Competitively Priced Electricity in the Commonwealth”, signed into law by the Governor of Massachusetts on August 3, 2012. All of the rates were approved effective January 1, 2014 for billing purposes, subject to reconciliation, pending investigation by the MDPU.

Fitchburg – Service Quality – On March 1, 2014, Fitchburg submitted its 2013 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for its gas division. The electric division met or exceeded all metric benchmarks except for two measures relating to the performance of certain individual distribution circuits as compared to the performance of the system as a whole. As a result of penalty offsets earned in six metrics where company performance exceeded the benchmark measure, however, no penalties are due.

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

Fitchburg – Other – On February 5, 2013, there was a natural gas explosion in the city of Fitchburg, Massachusetts in an area served by Fitchburg’s gas division resulting in property damage to a number of commercial and residential properties. The MDPU, pursuant to its authority under state and federal law, has commenced an investigation of the incident, with which Fitchburg is cooperating. The Company does not believe this incident or investigation will have a material adverse impact on the Company’s financial condition or results of operations.

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

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

On August 3, 2012, the Governor of Massachusetts signed into law “An Act Relative to Competitively Priced Electricity in the Commonwealth,” which both increases electric distribution companies’ obligations to purchase renewable energy resources and the availability of net metering. The Act also includes changes to the MDPU’s ratemaking procedures and authority for reviewing mergers and acquisitions for electric and gas distribution companies. With these changes, electric distribution companies are required to file rate schedules every five years, and gas distribution companies every ten years. The MDPU also opened a proceeding, as mandated by the Act, to establish a cost-based rate design for costs that are currently recovered from distribution customers through a reconciling factor. On December 17, 2013, the MDPU issued an order establishing the new rate design allocation methodologies. The Act also requires electric distribution companies to participate in joint solicitations and enter into additional long-term renewable contracts for 4% of distribution company load. A Request For Proposal for a long-term renewable energy contract, jointly prepared by Fitchburg and the other utility companies in consultation with the Massachusetts Attorney General and the Massachusetts Department of Energy Resources and approved by the MDPU, was issued in the Spring of 2013. After analysis and contract negotiations, contracts for six projects were awarded and submitted for MDPU approval. Three of the contracts were terminated during the approval process, and the MDPU approved the remaining three contracts. Fitchburg’s costs associated with these contracts will be recovered through a MDPU approved tariff.

On December 23, 2013 the MDPU issued two orders related to Grid Modernization. The MDPU opened an investigation on its own motion into Modernization of the Electric Grid and, in a separate but related order, opened an investigation into Electric Vehicles and Electric Vehicle Charging. The stated objective of the Grid Modernization proceeding is to ensure that the electric distribution companies “adopt grid modernization policies and practices” and all related objectives. It sets forth a straw proposal which would require each electric distribution company to submit a ten-year strategic grid modernization plan (GMP) within six months of a final Order. As part of the GMP each company must also include a comprehensive advanced metering plan (CAMP), and each company is required to achieve advanced metering functionality. The filing of a GMP will be a recurring obligation and must be updated as part of subsequent base distribution rate cases, which by statute must occur no less often than every five years. A cost recovery mechanism is proposed only for investments in advanced metering. The MDPU also proposes to address in separate, upcoming proceedings (1) time varying rates, (2) cybersecurity, privacy, and access to meter data, and (3) electric vehicles (EVs). In the Electric Vehicle Order, the MDPU seeks to establish policies and regulations that will help facilitate and accommodate the widespread adoption of EVs. Among other objectives, the proceeding looks to evaluate (1) EV charging and its impact on the electric distribution system, (2) electric distribution company involvement in EV charging, (3) residential metering practices and rates for EVs, and (4) consumer protection issues. These matters remain pending.

Legal Proceedings

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

In early 2009, a putative class action complaint was filed against Unitil Corporation’s (the “Company”) Massachusetts based utility, Fitchburg Gas and Electric Light Company (Fitchburg), in Massachusetts’ Worcester Superior Court (the “Court”), (captioned Bellerman et al v. Fitchburg Gas and Electric Light Company). The Complaint seeks an unspecified amount of damages, including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburg’s service territory in December, 2008. The Complaint, as amended, includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. Following several years of discovery, the plaintiffs in the complaint filed a motion with the Court to certify the case as a class action. On January 7, 2013, the Court issued its decision denying plaintiffs’ motion to certify the case as a class action. As a result of this decision, the lawsuit would now proceed with only the twelve named plaintiffs seeking damages; however, the plaintiffs have appealed this decision to the Massachusetts Supreme Judicial Court (the “SJC”). The SJC accepted the matter for review, briefs have been submitted and oral arguments have been held. The decision of the SJC is pending. The Town of Lunenburg has also filed a separate action in Massachusetts Worcester County Superior Court arising out of the December 2008 ice storm. The parties to this action have agreed to put this matter on hold pending the decision of the SJC in Bellermann. The Company continues to believe these suits are without merit and will continue to defend itself vigorously.

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Environmental Matters

3 Months Ended

Mar. 31, 2014

Environmental Matters

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 8 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2013 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 29, 2014.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in material compliance with applicable environmental and safety laws and regulations, and the Company believes that as of March 31, 2014, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, we cannot assure you that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

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

Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, Lewiston and Scarborough sites. The site in Portland has been investigated and remedial activities are ongoing with the most recent phase completed in December 2013. In April 2014, the State of Maine announced its intention to acquire the site via an eminent domain taking for the expansion of the adjacent marine terminal. Northern Utilities continues to negotiate with the State of Maine on the details of the taking. Future operation, maintenance and remedial costs have been accrued, although there will be uncertainty regarding future costs pending either the outcome of negotiations with the State of Maine or until all remedial activities are completed.

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

Included in Environmental Obligations on the Company’s Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 are $0.4 million and $1.0 million, respectively of current accrued liabilities, and $1.8 million and $1.8 million, respectively, of non-current accrued liabilities 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 anticipates beginning the implementation of a permanent remediation solution at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts in the second quarter of 2014. Included in Environmental Obligations on the Company’s Consolidated Balance Sheet at March 31, 2014 and December 31, 2013 are $1.0 million and $0, respectively of current accrued liabilities, and $11.0 million and $12.0 million, respectively, of non-current accrued liabilities related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of this environmental remediation cost is probable through the regulatory process. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties. Fitchburg recovers the environmental response costs incurred at this former MGP site in gas rates pursuant to the terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs.

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

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Retirement Benefit Obligations

3 Months Ended

Mar. 31, 2014

Retirement Benefit Obligations

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2013 as filed with the SEC on January 29, 2014 for additional information regarding these plans.

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

	2014			2013
Used to Determine Plan Costs
Discount Rate		4.80	%		4.00	%
Rate of Compensation Increase		3.00	%		3.00	%
Expected Long-term rate of return on plan assets		8.00	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2018			2017

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

	Pension Plan						PBOP Plan						SERP
Three Months Ended March 31,	2014			2013			2014			2013			2014		2013
Service Cost	$	751		$	893		$	497		$	631		$	14	$	18
Interest Cost		1,273			1,142			672			612			68		60
Expected Return on Plan Assets		(1,561	)		(1,489	)		(230	)		(180	)		—		—
Prior Service Cost Amortization		53			52			420			425			3		3
Actuarial Loss Amortization		712			1,059			14			196			25		46
Sub-total		1,228			1,657			1,373			1,684			110		127
Amounts Capitalized and Deferred		(344	)		(616	)		(473	)		(769	)		—		—
Net Periodic Benefit Cost Recognized	$	884		$	1,041		$	900		$	915		$	110	$	127

Employer Contributions

As of March 31, 2014, the Company had made $0.9 million of contributions to its Pension Plan in 2014 and had not made any contributions to its PBOP Plan in 2014. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension and PBOP Plans in 2014 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension and PBOP Plan costs.

As of March 31, 2014, the Company had made $13,000 of contributions to the SERP Plan in 2014. The Company presently anticipates contributing an additional $40,000 to the SERP Plan in 2014.

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Dividends Declared Per Share (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Dividends Payable [Line Items]
Dividend Amount	$ 0.345	$ 0.690
Group One
Dividends Payable [Line Items]
Declaration Date	Apr. 22, 2014
Date Paid (Payable)	May 29, 2014
Shareholder of Record Date	May 15, 2014
Dividend Amount	$ 0.345
Group Two
Dividends Payable [Line Items]
Declaration Date	Jan. 16, 2014
Date Paid (Payable)	Feb. 28, 2014
Shareholder of Record Date	Feb. 14, 2014
Dividend Amount	$ 0.345
Group Three
Dividends Payable [Line Items]
Declaration Date	Sep. 18, 2013
Date Paid (Payable)	Nov. 15, 2013
Shareholder of Record Date	Nov. 01, 2013
Dividend Amount	$ 0.345
Group Four
Dividends Payable [Line Items]
Declaration Date	Jun. 05, 2013
Date Paid (Payable)	Aug. 15, 2013
Shareholder of Record Date	Aug. 01, 2013
Dividend Amount	$ 0.345
Group Five
Dividends Payable [Line Items]
Declaration Date	Mar. 28, 2013
Date Paid (Payable)	May 15, 2013
Shareholder of Record Date	May 01, 2013
Dividend Amount	$ 0.345
Group Six
Dividends Payable [Line Items]
Declaration Date	Jan. 17, 2013
Date Paid (Payable)	Feb. 15, 2013
Shareholder of Record Date	Feb. 01, 2013
Dividend Amount	$ 0.345

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Debt and Financing Arrangements (Tables)

3 Months Ended

Mar. 31, 2014

Details on Long Term Debt

Details on long-term debt at March 31, 2014, March 31, 2013 and December 31, 2013 are shown below:

($ millions)	March 31,				December 31,
	2014		2013		2013
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0
Unitil Energy Systems, Inc.:
First Mortgage Bonds:
5.24% Series, Due March 2, 2020		15.0		15.0		15.0
8.49% Series, Due October 14, 2024		15.0		15.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0		15.0
Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0
Northern Utilities Senior Notes:
6.95% Senior Notes, Series A, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Series B, Due December 3, 2038		50.0		50.0		50.0
Granite State Senior Notes:
7.15% Senior Notes, Due December 15, 2018		10.0		10.0		10.0
Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due Through August 1, 2017		2.2		2.7		2.3
Total Long-Term Debt		287.2		287.7		287.3
Less: Current Portion		2.5		0.5		2.5
Total Long-term Debt, Less Current Portion	$	284.7	$	287.2	$	284.8

Borrowing Limits Amounts Outstanding and Amounts Available under Revolving Credit Facility

The following table details the borrowing limits, amounts outstanding and amounts available under the revolving credit facility as of March 31, 2014, March 31, 2013 and December 31, 2013:

	Revolving Credit Facility (millions)
	March 31,				December 31,
	2014		2013		2013
Limit	$	120.0	$	60.0	$	120.0
Outstanding	$	59.2	$	32.6	$	60.2
Available	$	60.8	$	27.4	$	59.8

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Components of Accrued Revenue (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 49.6	$ 56.6	$ 47.4
Unbilled Revenues
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	9.9	13.0	10.4
Regulatory Asset
Deferred Revenue Arrangement [Line Items]
Accrued Revenue	$ 39.7	$ 43.6	$ 37.0

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Restricted Stock Units Issued (Detail) (Restricted Stock, USD $)	3 Months Ended
	Mar. 31, 2014
Restricted Stock
Restricted Stock Units
Beginning Restricted Stock Units	14,903
Restricted Stock Units Granted
Dividend Equivalents Earned	163
Restricted Stock Units Settled
Ending Restricted Stock Units	15,066
Weighted-Average Stock Price
Beginning Restricted Stock Units	$ 28.90
Restricted Stock Units Granted
Dividend Equivalents Earned	$ 31.48
Restricted Stock Units Settled
Ending Restricted Stock Units	$ 28.93

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Activities:
Net Income	$ 12.6	$ 10.8
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization	10.2	9.5
Deferred Tax Provision	7.0	5.4
Changes in Working Capital Items:
Accounts Receivable	(17.3)	(14.3)
Accrued Revenue	7.0	16.0
Exchange Gas Receivable	9.5	7.7
Regulatory Liabilities	3.4	4.8
Accounts Payable	(6.3)	(5.6)
Other Changes in Working Capital Items	3.1	0.3
Deferred Regulatory and Other Charges	(1.9)	2.9
Other, net	1.4	3.3
Cash Provided by Operating Activities	28.7	40.8
Investing Activities:
Property, Plant and Equipment Additions	(9.2)	(14.4)
Cash (Used in) Investing Activities	(9.2)	(14.4)
Financing Activities:
Repayment of Short-Term Debt, net	(1.0)	(16.8)
Repayment of Long-Term Debt	(0.1)	(0.1)
Net Decrease in Exchange Gas Financing	(8.8)	(7.2)
Dividends Paid	(4.8)	(4.8)
Proceeds from Issuance of Common Stock	0.3	0.3
Other, net	(0.2)	(0.1)
Cash (Used in) Financing Activities	(14.6)	(28.7)
Net Increase (Decrease) in Cash	4.9	(2.3)
Cash at Beginning of Period	9.4	9.8
Cash at End of Period	14.3	7.5
Supplemental Cash Flow Information:
Interest Paid	3.0	2.9
Income Taxes Paid	0.3	0.8
Non-cash Investing Activity:
Capital Expenditures Included in Accounts Payable	$ 0.4	$ 1.0

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Segment Information

3 Months Ended

Mar. 31, 2014

Segment Information

NOTE 3 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three months ended March 31, 2014 and March 31, 2013:

	Electric		Gas		Other		Non-Regulated		Total
Three Months Ended March 31, 2014 ($ millions)
Revenues	$	61.9	$	92.6	$	—	$	1.6	$	156.1
Segment Profit		0.9		11.5		—		0.2		12.6
Identifiable Segment Assets		405.1		506.1		11.0		5.8		928.0
Capital Expenditures		5.1		3.0		1.0		0.1		9.2
Three Months Ended March 31, 2013 ($ millions)
Revenues	$	45.9	$	70.8	$	—	$	1.5	$	118.2
Segment Profit		2.0		8.3		0.1		0.4		10.8
Identifiable Segment Assets		411.5		462.2		5.5		6.3		885.5
Capital Expenditures		7.0		6.9		0.5		—		14.4
As of December 31, 2013 ($ millions)
Identifiable Segment Assets	$	502.3	$	402.8	$	6.2	$	9.3	$	920.6

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Exchange Gas Receivable (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013
Receivables [Line Items]
Total Exchange Gas Receivable	$ 1.3	$ 10.8	$ 1.7
Northern Utilities Inc
Receivables [Line Items]
Total Exchange Gas Receivable	1.0	9.8	1.5
Fitchburg Gas and Electric Light Company
Receivables [Line Items]
Total Exchange Gas Receivable	$ 0.3	$ 1.0	$ 0.2

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Debt and Financing Arrangements - Additional Information (Detail) (USD $) In Millions, unless otherwise specified							1 Months Ended	3 Months Ended			1 Months Ended									1 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Mar. 31, 2014 Northern Utilities Inc	Dec. 31, 2013 Northern Utilities Inc	Mar. 31, 2013 Northern Utilities Inc	Oct. 04, 2013 Revolving Credit Facility	Mar. 31, 2014 Revolving Credit Facility	Dec. 31, 2013 Revolving Credit Facility	Mar. 31, 2013 Revolving Credit Facility	Oct. 04, 2013 Revolving Credit Facility London Interbank Offered Rate	Mar. 31, 2014 8.00% Senior Secured Notes, Due Through August 1, 2017 Unitil Realty Corp	Dec. 31, 2013 8.00% Senior Secured Notes, Due Through August 1, 2017 Unitil Realty Corp	Mar. 31, 2013 8.00% Senior Secured Notes, Due Through August 1, 2017 Unitil Realty Corp	Mar. 31, 2014 8.00% Senior Secured Notes, Due Through August 1, 2017 Unitil Realty Corp Debt Outstanding, Principal Amount	Mar. 31, 2014 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc	Dec. 31, 2013 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc	Mar. 31, 2013 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc	Mar. 31, 2014 7.15% Senior Notes, Due December 15, 2018 Granite State Gas Transmission Inc Debt Outstanding, Principal Amount	Apr. 30, 2014 Construction line of credit Subsequent Event
Line of Credit Facility [Line Items]
Estimated Fair Value of Long-Term Debt	$ 332.8
Revolving credit facility expiration date							Oct. 04, 2018													Aug. 31, 2015
Line of credit facility, maximum borowing capacity							120.0	120.0	120.0	60.0										15.0
Sublimit for the issuance of standby letters of credit							25
Credit facility, daily fluctuating rate of interest											1.375%
Credit Facility by an aggregate additional amount							30
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 March 31, 2014, the Company was in compliance with the covenants contained in the Credit Facility in effect on that date.
Capital lease term in years																				5 years
Line of credit facility, funding received																				4.4
Outstanding inventory				3.2	12.5	3.3
Accounts Payable	31.8	38.1	27.1	2.2	2.7	1.7
Guarantee outstanding	31.0
Guarantee end date	Apr. 30, 2015
Senior Secured Notes												2.2	2.3	2.7	2.2
Senior Notes																$ 10.0	$ 10.0	$ 10.0	$ 10.0

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Significant Segment Financial Data

The following table provides significant segment financial data for the three months ended March 31, 2014 and March 31, 2013:

	Electric		Gas		Other		Non-Regulated		Total
Three Months Ended March 31, 2014 ($ millions)
Revenues	$	61.9	$	92.6	$	—	$	1.6	$	156.1
Segment Profit		0.9		11.5		—		0.2		12.6
Identifiable Segment Assets		405.1		506.1		11.0		5.8		928.0
Capital Expenditures		5.1		3.0		1.0		0.1		9.2
Three Months Ended March 31, 2013 ($ millions)
Revenues	$	45.9	$	70.8	$	—	$	1.5	$	118.2
Segment Profit		2.0		8.3		0.1		0.4		10.8
Identifiable Segment Assets		411.5		462.2		5.5		6.3		885.5
Capital Expenditures		7.0		6.9		0.5		—		14.4
As of December 31, 2013 ($ millions)
Identifiable Segment Assets	$	502.3	$	402.8	$	6.2	$	9.3	$	920.6