Form 10-Q

Large Accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q 1 d315448d10q.htm FORM 10-Q Form 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, 2012

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. (Check one):

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 23, 2012
Common Stock, no par value		10,990,496 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended March 31, 2012

Table of Contents


		Page No.
Part I. Financial Information		3

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Earnings - Three Months Ended March 31, 2012 and 2011	19

	Consolidated Balance Sheets, March 31, 2012, March 31, 2011 and December 31, 2011	20-21

	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2012 and 2011	22

	Notes to Consolidated Financial Statements	23-36

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3-18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	36

Part II. Other Information

Item 1.	Legal Proceedings	36

Item 1A.	Risk Factors	36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	Mine Safety Disclosures	Inapplicable

Item 5.	Other Information	37

Item 6.	Exhibits	38

Signatures		39

Exhibits		40

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 areas in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:

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, New Hampshire;

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 101,400 electric customers and 71,900 natural gas customers in their service areas.

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 $512.2 million at March 31, 2012. 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 REGULATIONS

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 Massachusetts Department of Public Utilities (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 areas, 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, Massachusetts and Maine, Unitil’s 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 13% 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.

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, the Company’s cost of service 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;

•

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 and energy used 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.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended March 31, 2012 and March 31, 2011 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.

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.

Earnings Overview

The Company’s Earnings Applicable to Common Shareholders (Earnings) were $9.0 million for the first quarter of 2012, an increase of $0.3 million over the first quarter of 2011. Earnings per common share (EPS) were $0.83 for the first quarter of 2012, an improvement of $0.02 per share over the first quarter of 2011.

The Company estimates that the mild winter weather negatively impacted earnings by $1.6 million, or $0.15 per share, in the first quarter of 2012. According to the National Oceanic and Atmospheric Administration, the northeast region of the United States, in which Unitil’s service areas are located, experienced its warmest first quarter period in 2012 as compared to normal temperatures in the 118 years of record keeping. Based on weather data collected in the Company’s service areas, there were 18% fewer Heating Degree Days in the first quarter of 2012 compared to the same period in 2011.

Natural gas sales margin was $27.3 million in the three months ended March 31, 2012, an increase of $2.5 million compared to the same period in 2011. In the first quarter of 2012, natural gas sales margin was positively affected by increased base rates and decoupling revenues from recently completed rate cases and the growth in new natural gas customers. Sales margin was negatively affected by lower therm unit sales which decreased 11.3% in the three months ended March 31, 2012 compared to the same period in 2011, reflecting the effect of milder winter weather in the first quarter of 2012 compared to 2011. Approximately 13% of the Company’s total therm sales of natural gas are decoupled and changes in these sales do not affect sales margin. Weather-normalized therm unit sales of natural gas are estimated to be about the same in the first quarter of 2012 compared to the same period in 2011.

Electric sales margin was $16.1 million in the three months ended March 31, 2012, reflecting higher base rates and decoupling revenues from recently completed rate cases, offset by lower electric kilowatt-hour (kWh) sales. Total electric kWh sales decreased 4.8% compared to the first quarter of 2011, primarily reflecting the effect of milder winter weather in the first quarter of 2012 compared to 2011. Approximately 27% of total electric kWh sales are decoupled and changes in these sales do not affect sales margins. Weather-normalized kWh sales are estimated to be about the same in the first quarter of 2012 compared to the same period in 2011.

Operation and Maintenance (O&M) expenses increased $1.2 million in the three months ended March 31, 2012 compared to the same period in 2011. The increase in O&M expenses in the first quarter of 2012

compared to the same period in 2011 reflects lower O&M expenses recorded in the first quarter of 2011 due to the receipt of a $1.0 million insurance payment. The other changes in O&M expenses reflect higher employee compensation and benefit costs of $0.7 million, lower professional fees of $0.3 million and lower utility operating expenses of $0.2 million. Utility operating costs in the first quarter of 2012 include approximately $0.3 million of spending on vegetation management and reliability enhancement programs. These costs are recovered through cost tracker rate mechanisms that result in corresponding increases in revenue.

Depreciation and Amortization expense increased $0.4 million in the three months ended March 31, 2012 compared to the same period in 2011, reflecting normal utility plant additions and amortization of previously deferred storm charges, partially offset by changes in depreciation rates resulting from the Company’s recently completed rate cases.

Local Property and Other Taxes increased by $0.4 million in the three months ended March 31, 2012 compared to the same period in 2011. The increase reflects higher local property tax rates on higher levels of utility plant in service.

Interest Expense, net increased $0.3 million in the three months ended March 31, 2012 compared to the same period in 2011, reflecting higher short-term borrowings.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $1.3 million in the first quarter of 2012, on par with revenues of $1.3 million in the first quarter of 2011.

In 2011, Unitil’s annual common dividend was $1.38, representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January, 2012 and March, 2012 meetings, Unitil’s Board of Directors declared quarterly dividends on the Company’s common stock of $0.345 per share.

A more detailed discussion of the Company’s results of operations for the three months ended March 31, 2012 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas decreased 11.3% in the three months ended March 31, 2012 compared to the same period in 2011, reflecting decreases of 14.6% and 10.2% in sales to Residential and Commercial and Industrial (C&I) customers, respectively. The decrease in gas therm sales in the Company’s utility service areas reflects the effect of milder winter weather in the first quarter of 2012 compared to 2011. Based on weather data collected in the Company’s service areas, there were 18% fewer Heating Degree Days in the first quarter of 2012 compared to the same period in 2011. Approximately 13% of the Company’s total therm sales of natural gas are decoupled and changes in these sales do not affect sales margin. As discussed above, under revenue decoupling for Fitchburg, distribution revenues, which are included in sales margin, will be recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and will no longer be dependent on sales volumes. Weather-normalized therm unit sales of natural gas are estimated to be about the same in the first quarter of 2012 compared to the same period in 2011.

The following table details total firm therm sales for the three months ended March 31, 2012 and 2011, by major customer class:


Therm Sales (millions)
	Three Months Ended March 31,
	2012		2011		Change			% Change
Residential		17.0		19.9		(2.9	)		(14.6	%)
Commercial/Industrial		55.4		61.7		(6.3	)		(10.2	%)

Total		72.4		81.6		(9.2	)		(11.3	%)

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three months ended March 31, 2012 and 2011:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended March 31,
	2012		2011		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	27.3	$	28.0	$	(0.7	)		(1.1	%)
Commercial / Industrial		36.9		37.9		(1.0	)		(1.5	%)

Total Gas Operating Revenue	$	64.2	$	65.9	$	(1.7	)		(2.6	%)

Cost of Gas Sales:
Purchased Gas	$	36.5	$	40.5	$	(4.0	)		(6.1	%)
Conservation & Load Management		0.4		0.6		(0.2	)		(0.3	%)

Total Cost of Gas Sales	$	36.9	$	41.1	$	(4.2	)		(6.4	%)

Gas Sales Margin	$	27.3	$	24.8	$	2.5			3.8	%

⁽¹⁾	Represents change as a percent of Total Gas Operating Revenue.

Unitil analyzes operating results using Gas Sales Margin. Gas Sales Margin is calculated as Total Gas Operating Revenues less the associated cost of sales, which are recorded as Purchased Gas and Conservation & Load Management (C&LM) in Operating Expenses. Unitil believes Gas Sales Margin is a better measure to analyze profitability than Total Gas Operating Revenues since the approved cost of sales are tracked costs that are passed through directly to the customer resulting in an equal and offsetting amount reflected in Total Gas Operating Revenues.

The decrease in Total Gas Operating Revenues of $1.7 million in the first quarter of 2012 reflects lower cost of sales of $4.2 million, including lower Purchased Gas costs of $4.0 million and C&LM revenues of $0.2 million, which are tracked costs that are passed through directly to customers. These lower costs of sales were partially offset by higher gas base revenues of $2.5 million.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – In the first quarter of 2012, Unitil’s total electric kWh sales decreased 4.8% compared to the first quarter of 2011. Sales to Residential and C&I customers decreased 5.2% and 4.5%, respectively, in the first quarter of 2012 compared to the same period in 2011, primarily reflecting the effect of milder winter weather in the first quarter of 2012 compared to 2011. As discussed above, based on weather data collected in the Company’s service areas, there were 18% fewer Heating Degree Days in the first quarter of 2012 compared to the same period in 2011. Approximately 27% of total electric kWh sales are decoupled and changes in these sales do not affect sales margins. As discussed above, under revenue decoupling for Fitchburg, distribution revenues, which are included in sales margin, will be recognized in the Company’s Consolidated Statements of Earnings from August 1, 2011 forward, on established revenue targets and will no longer be dependent on sales volumes. Weather-normalized kWh sales are estimated to be about the same in the first quarter of 2012 compared to the same period in 2011.

The following table details total kWh sales for the three months ended March 31, 2012 and 2011 by major customer class:


kWh Sales (millions)
	Three Months Ended March 31,
	2012		2011		Change			% Change
Residential		179.4		189.2		(9.8	)		(5.2	%)
Commercial/Industrial		235.3		246.3		(11.0	)		(4.5	%)

Total		414.7		435.5		(20.8	)		(4.8	%)

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three months ended March 31, 2012 and 2011:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended March 31,
	2012		2011		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	27.7	$	27.0	$	0.7			1.5	%
Commercial / Industrial		21.0		21.2		(0.2	)		(0.4	%)

Total Electric Operating Revenue	$	48.7	$	48.2	$	0.5			1.0	%

Cost of Electric Sales:
Purchased Electricity	$	31.1	$	31.2	$	(0.1	)		(0.2	%)
Conservation & Load Management		1.5		0.9		0.6			1.2	%

Total Cost of Electric Sales	$	32.6	$	32.1	$	0.5			1.0	%

Electric Sales Margin	$	16.1	$	16.1	$	—			—

⁽¹⁾	Represents change as a percent of Total Electric Operating Revenue.

Unitil analyzes operating results using Electric Sales Margin. Electric Sales Margin is calculated as Total Electric Operating Revenues less the associated cost of sales, which are recorded as Purchased Electricity and Conservation & Load Management (C&LM) in Operating Expenses. Unitil believes Electric Sales Margin is a better measure to analyze profitability than Total Electric Operating Revenues since the approved cost of sales are tracked 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 $16.1 million in the three months ended March 31, 2012, reflecting higher base rates and decoupling revenues from recently completed rate cases, offset by lower kWh sales.

The increase in Total Electric Operating Revenues of $0.5 million in the first quarter of 2012 reflects higher cost of sales of $0.5 million, including lower Purchased Electricity costs of $0.1 million and higher C&LM revenues of $0.6 million, which are tracked 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, 2012 and 2011:


Other Operating Revenue (Millions)
	Three Months Ended March 31,
	2012		2011		$ Change		% Change
Other	$	1.3	$	1.3	$	—		—

Total Other Operating Revenue	$	1.3	$	1.3	$	—		—

Total Other Operating Revenue, which is comprised of revenues from the Company’s non-regulated energy brokering business, Usource, was about the same in the three month period ended March 31, 2012 compared to the same period in 2011. 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.

Operating Expenses

Purchased Gas – Purchased Gas includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements. Purchased Gas decreased $4.0 million, or 9.9%, in the three month period ended March 31, 2012 compared to the same period in 2011. The decrease in Purchased Gas reflects lower sales of natural gas. The Company recovers the approved costs of Purchased Gas through reconciling rate mechanisms which track costs and revenues for recovery on a pass-through basis and therefore changes in approved expenses do not affect earnings.

Purchased Electricity – Purchased Electricity includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity decreased $0.1 million, or 0.3%, in the three month period ended March 31, 2012 compared to the same period in 2011, reflecting lower kWh sales. The Company recovers the approved costs of Purchased Electricity through reconciling rate mechanisms which track costs and revenues for recovery on a pass-through basis 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 non-regulated business activities. O&M expenses increased $1.2 million in the three months ended March 31, 2012 compared to the same period in 2011. The increase in O&M expenses in the first quarter of 2012 compared to the same period in 2011 reflects lower O&M expenses recorded in the first quarter of 2011 due to the receipt of a $1.0 million insurance payment. The other changes in O&M expenses reflect higher employee compensation and benefit costs of $0.7 million, lower professional fees of $0.3 million and lower utility operating expenses of $0.2 million. Utility operating costs in the first quarter of 2012 include approximately $0.3 million of spending on vegetation management and reliability enhancement programs. These costs are recovered through cost tracker rate mechanisms that result in corresponding increases in revenue.

Conservation & Load Management – C&LM expenses are expenses associated with the development, management, and delivery of the Company’s energy efficiency programs. Energy efficiency programs are designed, in conformity to state regulatory requirements, to help consumers use natural gas and electricity more efficiently and thereby decrease their energy costs. Programs are tailored to residential, small business and large business customer groups and provide educational materials, technical assistance, and rebates that contribute toward the cost of purchasing and installing approved measures. In the first quarter of 2012, approximately 80% of these costs were related to electric operations and 20% to gas operations.

Total C&LM expenses increased by $0.4 million in the three months ended March 31, 2012 compared to the same period in 2011. These costs are collected from customers on a fully reconciling basis and therefore, fluctuations in program costs do not affect earnings.

Depreciation, Amortization and Taxes

Depreciation and Amortization – Depreciation and Amortization expense increased by $0.4 million, or 5.1%, in the three months ended March 31, 2012 compared to the same period in 2011, reflecting normal utility plant additions and amortization of previously deferred storm charges, partially offset by changes in depreciation rates resulting from the Company’s recently completed rate cases.

Local Property and Other Taxes – Local Property and Other Taxes increased by $0.4 million, or 12.1%, in the three months ended March 31, 2012 compared to the same period in 2011. The increase reflects higher local property tax rates on higher levels of utility plant in service.

Federal and State Income Taxes – Federal and State Income Taxes decreased by $0.1 million for the three months ended March 31, 2012 compared to the same period in 2011.

Other Non-Operating Expenses

Other Non-operating Expenses in the three month period ended March 31, 2012 were flat compared to the same period in 2011.

Interest Expense, Net

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

Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.


Interest Expense, Net (millions)	Three Months Ended March 31,
	2012			2011			Change
Interest Expense
Long-term Debt	$	5.1		$	5.1		$	—
Short-term Debt		0.5			0.4			0.1
Regulatory Liabilities		—			0.1			(0.1	)

Subtotal Interest Expense		5.6			5.6			—

Interest (Income)
Regulatory Assets		(0.6	)		(0.9	)		0.3
AFUDC and Other		(0.1	)		(0.1	)		—

Subtotal Interest (Income)		(0.7	)		(1.0	)		0.3

Total Interest Expense, Net	$	4.9		$	4.6		$	0.3

Interest Expense, Net increased $0.3 million in the three months ended March 31, 2012 compared to the same period in 2011, reflecting higher short-term borrowings.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future 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 (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, 2012, March 31, 2011 and December 31, 2011, all of the Company’s subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

Unitil has a revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit facility was $115.0 million at March, 31, 2012. There were $77.6 million, $50.6 million and $87.9 million in short-term debt outstanding through bank borrowings under the revolving credit facility at March 31, 2012, March 31, 2011 and December 31, 2011, respectively. The revolving credit facility contains customary terms and conditions for credit facilities of this type, including, without limitation, covenants restricting the Company’s ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a covenant restricting the Company’s ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of March 31, 2012, March 31, 2011 and December 31, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement. (See also “Credit Arrangements” in Note 4.)

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.

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, 2012, there were approximately $31.6 million of guarantees outstanding and the longest term guarantee extends through February 2014.

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 were $6.3 million, $1.8 million and $14.9 million outstanding at March 31, 2012, March 31, 2011 and December 31, 2011, respectively, related to these asset management agreements. The amount of natural gas inventory released in March 2012, which is payable in April 2012, is $0.3 million and recorded in Accounts Payable at March 31, 2012. The amount of natural gas inventory released in March 2011, which was payable in April 2011, is $1.7 million and recorded in Accounts Payable at March 31, 2011. The amount of natural gas inventory released in December 2011, which was payable in January 2012, is $2.5 million and recorded in Accounts Payable at December 31, 2011.

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, 2012, the principal amount outstanding for the 8% Unitil Realty notes was $3.2 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, 2012 compared to the same period in 2011.


	Three Months Ended March 31,
	2012		2011
Cash Provided by Operating Activities	$	30.4	$	36.4

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $30.4 million in 2012, a decrease of $6.0 million compared to 2011. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes, was $22.6 million in 2012 compared to $21.1 million in 2011, representing an increase of $1.5 million. Working capital changes in Current Assets and Liabilities resulted in a $13.5 million net source of cash in 2012 compared to a $17.3 million net source of cash in 2011, representing a decrease of $3.8 million. Deferred Regulatory and Other Charges resulted in a ($4.2) million use of cash in 2012 compared to a ($2.5) million use of cash in 2011. All Other, net operating activities resulted in a use of cash of ($1.5) million in 2012 compared to a source of cash of $0.5 million in 2011.


	Three Months Ended March 31,
	2012			2011
Cash (Used in) Investing Activities	$	(9.1	)	$	(10.8	)

Cash (Used in) Investing Activities – Cash Used in Investing Activities was ($9.1) million for 2012 compared to ($10.8) million in 2011. 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,
	2012			2011
Cash (Used in) Financing Activities	$	(20.6	)	$	(27.9	)

Cash (Used in) Financing Activities – Cash Used in Financing Activities was ($20.6) million in 2012 compared to ($27.9) million in 2011. In 2012, uses of cash in financing activities included repayment of short-term debt of ($10.3) million, a decrease in gas inventory financing of ($6.5) million, regular quarterly dividend payments on common and preferred stock of ($3.8) million and repayment of long-term debt of ($0.1) million. Sources of cash in 2012 are from the issuance of common stock of $0.3 million. All other financing activities resulted in a net use of cash of ($0.2) million.

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 February 1, 2012.

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 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 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.


Regulatory Assets consist of the following (millions)

	March 31,				December 31,
	2012		2011		2011
Energy Supply Contracts	$	10.7	$	19.5	$	12.9
Deferred Restructuring Costs		21.1		24.0		21.8

Subtotal – Restructuring Related Items		31.8		43.5		34.7
Retirement Benefits		55.1		46.9		55.3
Income Taxes		11.2		12.9		10.9
Environmental		17.1		18.9		17.5
Deferred Storm Charges		26.8		21.1		22.4
Other		16.2		10.6		17.8

Total Regulatory Assets	$	158.2	$	153.9	$	158.6
Less: Current Portion of Regulatory Assets⁽¹⁾		16.8		14.3		18.8

Regulatory Assets – noncurrent	$	141.4	$	139.6	$	139.8

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

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

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 revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recoveries from, or credits to, customers. The Company’s other electric and natural gas distribution utilities are not subject to RDM.

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, 2011 and 2010, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $325,000 and $300,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2011 and 2010, 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 $909,000 and $728,000, 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 $705,000 and $565,000, respectively. (See Note 9 to the accompanying unaudited 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 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, 2012, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s unaudited consolidated financial statements below.

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

LABOR RELATIONS

As of March 31, 2012, the Company and its subsidiaries had 458 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of March 31, 2012, 150 of the Company’s employees were represented by labor unions. There are 115 union employees covered by three separate collective bargaining agreements, which expire on May 31, 2012, May 31, 2013 and June 5, 2014. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

In addition, 35 union employees were covered by a separate collective bargaining agreement, which expired on March 31, 2012. The Company and the relevant labor union have prepared a Memorandum of Understanding outlining the terms of a new collective bargaining agreement, which will expire on March 31, 2017, and the labor union has approved such terms. Such terms include discreet salary adjustments, established work practices and uniform benefit packages. The Company expects to execute the final document in the second quarter of 2012.

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, 2012 and March 31, 2011 were 2.05% and 2.29%, respectively. The average interest rate on the Company’s short-term borrowings for the twelve months ended December 31, 2011 was 2.2%.

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.

Item 1.

Financial Statements

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except common shares and per share data)

(UNAUDITED)


	Three Months Ended March 31,
	2012		2011
Operating Revenues
Gas	$	64.2	$	65.9
Electric		48.7		48.2
Other		1.3		1.3

Total Operating Revenues		114.2		115.4

Operating Expenses
Purchased Gas		36.5		40.5
Purchased Electricity		31.1		31.2
Operation and Maintenance		13.4		12.2
Conservation & Load Management		1.9		1.5
Depreciation and Amortization		8.3		7.9
Provisions for Taxes:
Local Property and Other		3.7		3.3
Federal and State Income		5.3		5.4

Total Operating Expenses		100.2		102.0

Operating Income		14.0		13.4
Other Non-Operating Expense		0.1		0.1

Income Before Interest Expense		13.9		13.3
Interest Expense, Net		4.9		4.6

Net Income		9.0		8.7
Less: Dividends on Preferred Stock		—		—

Earnings Applicable to Common Shareholders	$	9.0	$	8.7


Weighted Average Common Shares Outstanding – Basic (000’s)		10,917		10,860
Weighted Average Common Shares Outstanding – Diluted (000’s)		10,921		10,861
Earnings Per Common Share (Basic and Diluted)	$	0.83	$	0.81

Dividends Declared Per Share of Common Stock	$	0.69	$	0.69

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	March 31,				December 31,
	2012		2011		2011
ASSETS:

Utility Plant:
Electric	$	339.6	$	325.1	$	333.3
Gas		390.0		362.3		382.3
Common		29.9		30.7		29.8
Construction Work in Progress		21.0		13.9		28.3

Total Utility Plant		780.5		732.0		773.7
Less: Accumulated Depreciation		268.3		256.0		263.0

Net Utility Plant		512.2		476.0		510.7

Current Assets:
Cash		8.2		6.6		7.5
Accounts Receivable, Net		47.9		45.7		44.2
Accrued Revenue		37.4		33.9		56.6
Gas Inventory		6.8		0.7		14.8
Materials and Supplies		3.9		3.4		3.6
Prepayments and Other		5.0		4.4		4.5

Total Current Assets		109.2		94.7		131.2

Noncurrent Assets:
Regulatory Assets		141.4		139.6		139.8
Other Noncurrent Assets		20.4		26.4		18.5

Total Noncurrent Assets		161.8		166.0		158.3

TOTAL	$	783.2	$	736.7	$	800.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)

(UNAUDITED)


	March 31,				December 31,
	2012		2011		2011
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	193.6	$	190.5	$	191.7
Preferred Stock		2.0		2.0		2.0
Long-Term Debt, Less Current Portion		287.7		288.2		287.8

Total Capitalization		483.3		480.7		481.5

Current Liabilities:
Long-Term Debt, Current Portion		0.5		0.5		0.5
Accounts Payable		18.7		22.5		26.4
Short-Term Debt		77.6		50.6		87.9
Energy Supply Contract Obligations		12.6		9.1		21.1
Taxes Payable		0.4		0.1		1.0
Other Current Liabilities		22.4		21.1		17.5

Total Current Liabilities		132.2		103.9		154.4

Deferred Income Taxes		52.1		48.7		46.3

Noncurrent Liabilities:
Energy Supply Contract Obligations		4.0		10.4		4.2
Retirement Benefit Obligations		89.5		70.3		91.2
Environmental Obligations		14.5		14.5		14.5
Other Noncurrent Liabilities		7.6		8.2		8.1

Total Noncurrent Liabilities		115.6		103.4		118.0

TOTAL	$	783.2	$	736.7	$	800.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Three Months Ended March 31,
	2012			2011
Operating Activities:
Net Income	$	9.0		$	8.7
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		8.3			7.9
Deferred Tax Provision		5.3			4.5
Changes in Working Capital Items:
Accounts Receivable		(3.7	)		(8.8	)
Accrued Revenue		19.2			12.8
Taxes Refundable / Payable		(0.6	)		7.6
Gas Inventory		8.0			9.9
Accounts Payable		(7.7	)		(4.0	)
Other Changes in Working Capital Items		(1.7	)		(0.2	)
Deferred Regulatory and Other Charges		(4.2	)		(2.5	)
Other, net		(1.5	)		0.5

Cash Provided by Operating Activities		30.4			36.4


Investing Activities:
Property, Plant and Equipment Additions		(9.1	)		(10.8	)

Cash (Used in) Investing Activities		(9.1	)		(10.8	)


Financing Activities:
Repayment of Short-Term Debt		(10.3	)		(16.2	)
Repayment of Long-Term Debt		(0.1	)		(0.1	)
Net Decrease in Gas Inventory Financing		(6.5	)		(7.8	)
Dividends Paid		(3.8	)		(3.8	)
Proceeds from Issuance of Common Stock		0.3			0.3
Other, net		(0.2	)		(0.3	)

Cash (Used in) Financing Activities		(20.6	)		(27.9	)

Net Increase (Decrease) in Cash		0.7			(2.3	)
Cash at Beginning of Period		7.5			8.9

Cash at End of Period	$	8.2		$	6.6


Supplemental Cash Flow Information:
Interest Paid	$	3.1		$	3.1
Income Taxes Paid (Refunded)	$	0.6		$	(6.9	)

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

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.

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, 2012 are not necessarily indicative of results to be expected for the year ending December 31, 2012. 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, 2011, as filed with the Securities and Exchange Commission (SEC) on February 1, 2012, for a description of the Company’s Basis of Presentation.

Derivatives – The Company has a regulatory approved hedging program for Northern Utilities designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases natural gas futures contracts on the New York Mercantile Exchange (NYMEX) that correspond to the associated delivery month. Any gains or losses resulting from the change in the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. The fair value of these derivatives is determined using Level 2 inputs (valuations based on quoted prices available in active markets for similar assets or liabilities, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are directly observable, and inputs derived principally from market data), specifically based on the NYMEX closing prices for outstanding contracts as of the balance sheet date. As a result of the ratemaking process, the Company records gains and losses resulting from the change in fair value of the derivatives as regulatory liabilities or assets, then reclassifies these gains or losses into Purchased Gas when the gains and losses are passed through to customers in accordance with rate reconciling mechanisms.

As of March 31, 2012, March 31, 2011 and December 31, 2011, the Company had 1.5 billion, 1.3 billion and 1.6 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

The tables below show derivatives, which are part of the regulatory approved hedging program, that are not designated as hedging instruments under FASB ASC 815-20. As discussed above, the change in fair value related to these derivatives is recorded initially as a Regulatory Asset then reclassified to Purchased Gas in accordance with the recovery mechanism. The tables below include disclosure of the Regulatory Asset and reclassifications from the Regulatory Asset into Purchased Gas.


Fair Value Amount (millions) Offset in Regulatory Assets⁽¹⁾, as of:
		Fair Value
Description	Balance Sheet Location	March 31, 2012		March 31, 2011		December 31, 2011
Natural Gas Futures Contracts	Other Current Liabilities	$	1.8	$	0.4	$	1.7

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.2		—		0.6

Total		$	2.0	$	0.4	$	2.3

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


	Three Months Ended March 31,
(millions)	2012		2011
Amount of Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	1.3	$	0.1
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽ ²⁾:
Purchased Gas	$	1.6	$	0.7

⁽²⁾	These amounts are offset in the unaudited Consolidated Statements of Earnings with Accrued Revenue and therefore there is no effect on earnings.

The Allowance for Doubtful Accounts as of March 31, 2012, March 31, 2011 and December 31, 2011, which are included in Accounts Receivable, Net on the accompanying unaudited consolidated balance sheets, were as follows:

(Millions)

March 31,

December 31,

2012

2011

Allowance for Doubtful Accounts

2.6

3.0

2.3

Subsequent Events – The Company has evaluated all events or transactions through the date of this filing. During this period, the Company did not have any material subsequent events that impacted its unaudited consolidated financial statements.

Reclassifications – Based on the Company’s analysis certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation.

Recently Issued Pronouncements – There are no recently issued pronouncements applicable to the Company that have not already been adopted.

NOTE 2 – DIVIDENDS DECLARED PER SHARE

As shown in the table below, the Company declared two quarterly dividends on its common stock in the first quarter of 2012; one which was paid in the first quarter of 2012 and the other which is payable in the second quarter of 2012. The Company typically declares quarterly dividends twice in the first quarter, once in the second quarter and once in the third quarter.

Declaration

Date

Date Paid (Payable)

Shareholder of
Record Date

Dividend Amount

03/22/12

05/15/12

05/01/12

0.345

01/17/12

02/15/12

02/01/12

0.345

09/21/11

11/15/11

11/01/11

0.345

06/16/11

08/15/11

08/01/11

0.345

03/24/11

05/16/11

05/02/11

0.345

01/18/11

02/15/11

02/01/11

0.345

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

Common Stock

The Company’s common stock trades under the symbol, “UTL.”

On April 21, 2011, the Company’s shareholders approved an increase in the authorized shares of the Company’s common stock. Shareholders approved an amendment to the Company’s Articles of

Incorporation to increase the authorized number of shares of the Company’s common stock, from 16,000,000 shares to 25,000,000 shares in the aggregate. The Company had 10,989,389, 10,925,136 and 10,954,065 of common shares outstanding at March 31, 2012, March 31, 2011 and December 31, 2011, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first quarter of 2012, the Company sold 9,724 shares of its common stock, at an average price of $27.19 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $264,000. 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 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 from the Company’s, its subsidiaries’ and its affiliates’ employees, directors and consultants to receive an award of shares of Company common stock (including restricted shares) or of restricted stock units. The Compensation Committee has the power 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.

Outstanding awards of restricted shares fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on restricted shares underlying the award may be credited to a participant’s account. Awards may be grossed up to offset the participant’s tax obligations in connection with the award. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death. The maximum number of shares of restricted stock available for awards to participants under the Stock Plan was 177,500 as of March 31, 2012, and was increased on April 19, 2012 to 677,500. The maximum aggregate number of shares or restricted stock units 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.

On February 3, 2012, 25,600 restricted shares were issued in conjunction with the Stock Plan with an aggregate market value at the date of issuance of $720,896. There were 53,780 and 49,089 non-vested shares under the Stock Plan as of March 31, 2012 and 2011, respectively. The weighted average grant date fair value of these shares was $24.78 and $22.17, respectively. The compensation expense associated with the issuance of shares under the Stock Plan is being recognized over the vesting period and was $0.3 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively. At March 31, 2012, there was approximately $1.5 million of total unrecognized compensation cost under the Stock Plan which is expected to be recognized over approximately 2.9 years. There were no forfeitures or cancellations under the Stock Plan during the three months ended March 31, 2012.

There were no restricted stock units issued under the Stock Plan during the three months ended March 31, 2012.

Preferred Stock

Details on preferred stock at March 31, 2012, March 31, 2011 and December 31, 2011 are shown below:

(Amounts in Millions)


	March 31,				December 31,
	2012		2011		2011
Preferred Stock
Unitil Energy Preferred Stock, Non-Redeemable, Non-Cumulative:
6.00% Series, $100 Par Value,	$	0.2	$	0.2	$	0.2
Fitchburg Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value		0.8		0.8		0.8
8.00% Series, $100 Par Value		1.0		1.0		1.0

Total Preferred Stock	$	2.0	$	2.0	$	2.0

There were 2,250, 2,250 and 2,250 shares of Unitil Energy’s 6.00% Series Preferred Stock outstanding at March 31, 2012, March 31, 2011 and December 31, 2011, respectively. There were 7,861, 7,901 and 7,861 shares of Fitchburg’s 5.125% Series Preferred Stock outstanding at March 31, 2012, March 31, 2011 and December 31, 2011, respectively. There were 9,696, 9,742 and 9,696 shares of Fitchburg’s 8.00% Series Preferred Stock outstanding at March 31, 2012, March 31, 2011 and December 31, 2011, respectively.

There was less than $0.1 million of total dividends declared on Preferred Stock in each of the three month periods ended March 31, 2012 and March 31, 2011, respectively.

NOTE 4 – LONG-TERM DEBT, CREDIT ARRANGEMENTS AND GUARANTEES

Long-Term Debt

Details on long-term debt at March 31, 2012, March 31, 2011 and December 31, 2011 are shown below ($ Millions):


	March 31,				December 31,
	2012		2011		2011
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		3.2		3.7		3.3

Total Long-Term Debt		288.2		288.7		288.3
Less: Current Portion		0.5		0.5		0.5

Total Long-term Debt, Less Current Portion	$	287.7	$	288.2	$	287.8

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, 2012 is estimated to be

approximately $336 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

Unitil has a revolving credit facility with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit facility was $115.0 million at March, 31, 2012, $80.0 million at March 31, 2011 and $115.0 million at December 31, 2011. There were $77.6 million, $50.6 million and $87.9 million in short-term debt outstanding through bank borrowings under the revolving credit facility at March 31, 2012, March 31, 2011 and December 31, 2011, respectively. The total amount of credit available under the Company’s revolving credit facility was $37.4 million, $29.4 million and $27.1 million at March 31, 2012, March 31, 2011 and December 31, 2011, respectively. The revolving credit facility contains customary terms and conditions for credit facilities of this type, including, without limitation, covenants restricting the Company’s ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a covenant restricting the Company’s ability to permit funded debt to exceed 65% of capitalization at the end of each fiscal quarter. As of March 31, 2012, March 31, 2011 and December 31, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

Guarantees

The Company also 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, 2012, there were approximately $31.6 million of guarantees outstanding and the longest term guarantee extends through February 2014.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of March 31, 2012, the principal amount outstanding for the 8% Unitil Realty notes was $3.2 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the $10 million Granite State notes due 2018. As of March 31, 2012, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million.

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three months ended March 31, 2012 and March 31, 2011:


Three Months Ended March 31, 2012 (Millions)	Electric		Gas		Other			Non- Regulated		Total
Revenues	$	48.7	$	64.2	$	—		$	1.3	$	114.2
Segment Profit (Loss)		1.2		7.6		(0.1	)		0.3		9.0
Identifiable Segment Assets		378.5		392.0		6.2			6.5		783.2
Capital Expenditures		5.3		3.1		0.7			—		9.1

Three Months Ended March 31, 2011 (Millions)
Revenues	$	48.2	$	65.9	$	—		$	1.3	$	115.4
Segment Profit		1.7		6.8		(0.2	)		0.4		8.7
Identifiable Segment Assets		369.0		355.4		6.4			5.9		736.7
Capital Expenditures		5.3		5.2		0.3			—		10.8

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2011 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2012.

Regulatory Matters

Fitchburg – Increase in Base Rates Approved – On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an order approving increases of $3.3 million and $3.7 million in annual distribution revenues for Fitchburg’s electric and gas divisions, respectively. The MDPU also approved revenue decoupling mechanisms and a return on equity of 9.2% for both the electric and gas divisions of Fitchburg. The rate increase for Fitchburg’s electric division included the recovery of $11.4 million of previously deferred emergency storm restoration costs associated with the December 2008 ice storm, which costs are to be amortized and recovered over seven (7) years without carrying costs. The order provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Granite State – Increase in Base Rates Approved – On January 31, 2011, the FERC approved a settlement agreement providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. Subsequently, on August 31, 2011, the FERC approved an amendment to the settlement agreement which provides for an additional increase of approximately $0.5 million in Granite State’s annual revenues effective August 1, 2011. Under the amended settlement agreement, beginning in 2012, Granite State is permitted to file incremental annual rate adjustment filings to recover the revenue requirements for certain specified future capital cost additions to transmission plant projects totaling up to $11.4 million. Of the $11.4 million, $1.6 million has been expended and is being recovered in the 2011 approved rates. The annual rate adjustments would be effective August 1 of each year, and are projected to conclude in 2014 when the major projects will be completed. The annual revenue increases for these rate adjustments are estimated to be approximately $0.5 million each year during 2012 through 2014.

Unitil Energy – Increase in Base Rates Approved – On April 26, 2011, the New Hampshire Public Utilities Commission (NHPUC) approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue effective July 1, 2010, and provides for an additional increase of $5.0 million in annual revenue effective May 1, 2011.

The settlement extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with estimated future increases of $1.5 million to $2.0 million in annual revenue to occur on May 1, 2012, May 1, 2013 and May 1, 2014, to support Unitil Energy’s continued capital improvements to its distribution system. The rate plan allows Unitil to file for additional rate relief if its return on equity is less than 7% and a sharing of earnings with customers if its return on equity is greater than 10% in a calendar year. The settlement provides for a return on equity of 9.67%, a common equity ratio of 45.45% and an overall weighted cost of capital of 8.39% to determine changes to distribution rate levels.

The settlement approved Unitil Energy’s proposal for an augmented vegetation management program and reliability enhancement program. Under the augmented vegetation management program, Unitil Energy will be increasing its vegetation management spending from a test-year spending level of approximately $0.7 million to $3.1 million per year by 2013. Under the new reliability enhancement program, Unitil Energy will spend $1.8 million annually towards targeted projects designed to enhance system reliability. The funding for both of these programs is included in the future rate increases discussed above.

The settlement provides for recovery of deferred December 2008 ice storm and February 2010 wind storm costs of approximately $7.6 million, including carrying charges. These costs will be recovered over eight years in the form of a tariff surcharge. Finally, the settlement establishes a major storm reserve of $400,000 annually, which will be used to recover costs associated with responding to and recovering from future qualifying major storm events.

Unitil Energy filed its first step adjustment filing on February 29, 2012 for implementation on May 1, 2012, which includes rate increases to recover the increased spending for its vegetation management program and reliability enhancement program discussed above. The adjustment filing remains pending.

Northern Utilities – Increase in Base Rates Approved, Settlement Reached – In May 2011, Northern Utilities filed two separate rate cases with the NHPUC and Maine Public Utilities Commission (MPUC) requesting approval to increase its natural gas distribution base rates in New Hampshire and Maine, respectively.

On November 29, 2011, the MPUC approved a comprehensive settlement agreement providing for a $7.8 million permanent increase in annual distribution revenue for Northern Utilities’ Maine operations, effective January 1, 2012, and an additional permanent increase in annual distribution revenue of $0.85 million to recover the costs of 2011 cast iron pipe replacement capital spending effective May 1, 2012. The settlement is inclusive of an earlier settlement for a temporary rate increase of $3.5 million in annual distribution revenue effective November 1, 2011. The settlement also precludes Northern Utilities from filing for a new base rate increase with an effective date prior to January 1, 2014.

On March 22, 2012, Northern Utilities, the Staff of the NHPUC and the Office of Consumer Advocate agreed to a settlement agreement providing for a $3.7 million permanent increase in annual revenues, effective May 1, 2012. Previously, on July 22, 2011, the NHPUC approved a settlement for a temporary rate increase of approximately $1.7 million in annual revenue effective August 1, 2011. A hearing was held on March 29, 2012, and the NHPUC issued an order approving the settlement agreement on April 24, 2012. Permanent rates will be reconciled back to August 1, 2011.

Fitchburg – Management Audit – On September 1, 2011, the MDPU issued its order with respect to a comprehensive independent management audit of Fitchburg’s management practices, undertaken as a result of the MDPU’s investigation of Fitchburg’s response to the December 2008 ice storm. The audit report found Fitchburg’s management practices to be comprehensive, sound and in-line with industry

practice. The MDPU accepted the majority of the audit report, and required the Company to implement several of the report’s recommendations, as well as provide semi-annual status updates as to the Company’s implementation progress. The Company filed status reports with the MDPU on September 30, 2011 and March 30, 2012.

Fitchburg – Electric Operations – On November 30, 2011, Fitchburg submitted its annual reconciliation of costs and revenues for transition and transmission under its restructuring plan. The filing includes the reconciliation of costs and revenues for a number of surcharges and cost factors which are under individual review in separate proceedings before the MDPU, including the Pension/PBOP Adjustment, Residential Assistance Adjustment Factor, Net Metering Recovery Surcharge, Attorney General Consultant Expense Factor and Revenue Decoupling Adjustment Factor. The rates were approved effective January 1, 2012, subject to reconciliation pending investigation by the MDPU. This matter remains pending. Final orders on Fitchburg’s 2009 and 2010 annual reconciliation filings also remain pending.

Fitchburg – Gas Operations – On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an MDPU order issued on November 2, 2009 which had ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The SJC ordered instead, a $0.2 million refund, plus interest. The Company had previously recorded a pre-tax charge to earnings and recognized a Regulatory Liability of $4.9 million in the fourth quarter of 2009 based on the MDPU’s original order. As a result of the decision, the Regulatory Liability was adjusted and the Company recognized a credit of $4.7 million in the fourth quarter of 2011.

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

Fitchburg – Storm Cost Deferral Petition – On December 16, 2011, Fitchburg filed a request with the MDPU for authorization to defer, for future recovery in rates, the costs incurred to perform storm-related emergency repairs on its electric distribution system as a result of two recent storms, Tropical Storm Irene, which occurred on August 28, 2011, and a severe snow storm, which occurred on October 29-30, 2011. Fitchburg estimates that, including capitalized amounts, it incurred $1.5 million in costs for Tropical Storm Irene and $3.3 million in costs for the October 2011 snow storm. The Company has requested approval to defer and accrue carrying charges on approximately $4.3 million of the storm costs that were not capitalized into utility plant. This matter remains pending before the MDPU.

Fitchburg – Service Quality – On March 1, 2012, Fitchburg submitted its 2011 Service Quality Reports for both its gas and electric divisions. Fitchburg reported that it met or exceeded its benchmarks for service quality performance in all metrics for both its gas and electric divisions. On January 13, 2012, the MDPU issued its order approving the 2010 Service Quality Report for Fitchburg’s gas division. The 2010 Service Quality report for Fitchburg’s electric division remains pending.

Unitil Energy – 2011 Storm Costs – On December 16, 2011, Unitil Energy filed a petition with the NHPUC to increase its storm recovery adjustment factor effective May 1, 2012. The increase would allow the Company to recover the approximately $4.4 million of costs of repairing damage to its electrical system resulting from the August 2011 Tropical Storm Irene and the October 2011 snow storm. The NHPUC Staff audited the costs and filed a memorandum with the NHPUC recommending that the costs be recovered by the Company over a five year period with carrying costs of 4.52%, subject to a full reconciliation of all costs recovered. Unitil Energy accepts and supports the Staff recommendation. On April 24, 2012, the NHPUC issued an order approving the recommendation of the Staff.

Unitil Energy – Billing Adjustment – In August 2011, Unitil Energy and one of its larger customers in New Hampshire entered into an agreement regarding a billing error that resulted from a transformer connected to the customer’s meter, which had been mislabeled by the manufacturer, and caused Unitil Energy to overcharge the customer for bills issued from October 2004 through January 2011. The amount of the customer’s overpayment was calculated to be $1.8 million. As a result of the settlement, Unitil Energy reimbursed the customer $1.8 million plus $0.3 million of interest. The Company recognized a non-recurring charge of $0.4 million for distribution charges plus interest in 2011.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service areas were under-billed from October 2004 through January 2011 for supply-related charges. Accordingly, the Company has requested authorization from the NHPUC to adjust reconciling account balances and process the billing correction. The Company’s request remains pending before the NHPUC.

Unitil Energy – Annual Rate Reconciliation Filing – On July 29, 2011, the NHPUC approved Unitil Energy’s annual reconciliation and rate filing under its restructuring plan, for rates effective August 1, 2011, including reconciliation of prior year costs and revenues.

Northern Utilities – Cast Iron Pipe Replacement Program – On July 30, 2010, the MPUC approved a settlement agreement providing for an accelerated replacement program for cast iron distribution pipe remaining in portions of Northern Utilities’ Maine service areas. Under the agreement, Northern Utilities will proceed with a comprehensive upgrade and replacement program (the Program), which will provide for the systematic replacement of cast iron, wrought iron and bare steel pipe in Northern Utilities’ natural gas distribution system in Portland and Westbrook, Maine and the conversion of the system to intermediate pressure. The agreement establishes the objective of completing the Program by the end of the 2024 construction season.

Unitil Corporation – FERC Audit – On November 3, 2011, the FERC commenced an audit of Unitil Corporation, including its associated service company and its electric and natural gas distribution companies. Among other requirements, the audit will evaluate the Company’s compliance with: i) cross-subsidization restrictions on affiliate transactions; ii) regulations under the Energy Policy Act of 2005; and the iii) uniform system of accounts for centralized service companies. The Company expects the final audit report will be issued in August, 2012.

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.

A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. On April 1, 2009, an Amended Complaint was filed in Worcester Superior Court and served on Fitchburg. The Amended 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 areas in December, 2008. The Amended Complaint includes M.G.L. ch. 93A claims for purported unfair and deceptive trade practices related to the December 2008 ice storm. On September 4, 2009, the Superior Court issued its order on the Company’s Motion to Dismiss the Complaint, granting it in part and denying it in part. The Company anticipates that the court will decide whether the lawsuit is appropriate for class action treatment in late 2012. The Company continues to believe the suit is without merit and will defend itself vigorously.

On November 2, 2011, the Massachusetts Supreme Judicial Court (SJC) issued its decision vacating an order issued on November 2, 2009 by the MDPU in which the MDPU ordered Fitchburg to refund $4.6 million of natural gas costs, plus interest. The MDPU’s original order issued in 2009 found that the Company had engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that the Company’s natural gas purchasing practices were imprudent. The Company appealed the MDPU’s decision to the SJC. The SJC’s decision vacates the MDPU’s order to refund $4.6 million, plus interest, in favor of a $0.2 million refund, plus interest. See additional discussion above in Regulatory Matters.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2011 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 1, 2012.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations including laws and regulations related to pipeline safety. The Company believes it is in substantial compliance with applicable environmental, health and safety laws and regulations, and the Company believes that as of March 31, 2012, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increased stringent federal, state or local environmental health and safety laws and regulations, could result in increased compliance costs that we cannot currently quantify and that affect our operations.

Fitchburg is in the process of developing long-range plans for a feasible permanent remediation solution of a former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts, including alternatives for re-use of the site. Included in Environmental Obligations on the Company’s unaudited Consolidated Balance Sheet at March 31, 2012 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of the Sawyer Passway site. 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. Fitchburg had filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. In January 2011, Fitchburg settled with the remaining insurance carriers for approximately $2.0 million and received these payments in the first quarter of 2011. Any recovery that Fitchburg receives from insurance or third-parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are shared equally between Fitchburg and its gas customers.

Also included in Environmental Obligations on the Company’s Consolidated Balance Sheet at March 31, 2012 are accrued liabilities totaling $2.5 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $0.2 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at March 31, 2012 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.

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. It is possible that other developments, such as increased stringent federal, state or local environmental health and safety laws and regulations, could result in increased compliance costs that we cannot currently quantify.

NOTE 8: INCOME TAXES

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.

As of December 31, 2011, the Company had recorded cumulative federal and state net operating loss (NOL) carryforward assets of $11.7 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, 2011, the Company had $1.4 million of Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT taxes payable indefinitely.

According to Internal Revenue Code rules, NOL refunds in excess of $2.0 million fall under the jurisdiction of the Joint Committee of Congress (Joint Committee) and are subject to review by the IRS and attorneys of the Joint Committee. As a result, the Company, on April 1, 2011, received notice that its federal income

tax return filing for the year ended December 31, 2009 would be under examination by the IRS. The IRS is currently performing field work as part of their audit procedures. In addition, because of the application of the 2009 NOL, tax periods ended December 31, 2004, 2005 and 2007 are subject to examination to the extent of the application of the NOL to those periods. The Company believes that the ultimate resolution of this examination will not have a material impact on the Company’s consolidated financial position or results of operations.

The Company evaluated its tax positions at December 31, 2011 and for the current interim reporting period ended March 31, 2012 in accordance with the FASB Codification, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by the FASB Codification is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Maine, Massachusetts, and New Hampshire tax authorities for the tax periods ended December 31, 2008; December 31, 2009; and December 31, 2010.

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 9 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2011 as filed with the SEC on February 1, 2012 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:


	2012			2011
Used to Determine Plan Costs
Discount Rate		4.60	%		5.35	%
Rate of Compensation Increase		3.00	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		6.50	%		7.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			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,	2012			2011			2012			2011			2012		2011
Service Cost	$	807		$	735		$	517		$	479		$	72	$	71
Interest Cost		1,158			1,171			576			570			53		57
Expected Return on Plan Assets		(1,347	)		(1,210	)		(174	)		(204	)		—		—
Prior Service Cost Amortization		47			62			432			432			3		3
Transition Obligation Amortization		—			—			5			5			—		—
Actuarial Loss Amortization		904			783			32			—			16		19

Sub-total		1,569			1,541			1,388			1,282			144		150
Amounts Capitalized and Deferred		(557	)		(503	)		(420	)		(234	)		—		—

Net Periodic Benefit Cost Recognized	$	1,012		$	1,038		$	968		$	1,048		$	144	$	150

Employer Contributions

As of March 31, 2012, the Company had made $4.8 million of contributions to its Pension Plan in 2012. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2012 and future years at minimum required and discretionary funding levels consistent with the amounts recovered in the distribution utilities’ rates for these Pension Plan costs.

As of March 31, 2012, the Company had made $13,000 of contributions to the SERP Plan in 2012. The Company presently anticipates contributing an additional $40,000 to the SERP Plan in 2012.

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, 2012. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of March 31, 2012 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 affected, or are reasonably likely to affect, the Company’s internal controls over financial reporting.

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. The Company believes, 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, 2011 as filed with the SEC on February 1, 2012.

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, 2012.

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, 2012.


	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⁾
1/1/12 – 1/31/12		—		—		—	$	7,155
2/1/12 – 2/29/12		—		—		—	$	7,155
3/1/12 – 3/31/12		229	$	27.06		229	$	200,800

Total		229				229

⁽¹⁾	All purchases were made pursuant to the Company’s 2011 Trading Plan (as defined below).

⁽²⁾

On March 24, 2011, the Company adopted a written trading plan under Rule 10b5-1 (the 2011 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, 2011, the Company filed a Current Report on Form 8-K announcing, among other things, that it had adopted the 2011 Trading Plan. The 2011 Trading Plan provided for the repurchase of up to $224,500 worth of shares of the Company’s common stock during its term. The 2011 Trading Plan became effective on March 24, 2011 and terminated on March 24, 2012 (that is, the 2011 Trading Plan terminated during the period covered by the table above).

⁽³⁾

On March 22, 2012, the Company adopted a new written trading plan under Rule 10b5-1 (the 2012 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 26, 2012, the Company filed a Current Report on Form 8-K announcing that it had adopted the 2012 Trading Plan. The 2012 Trading Plan provides for the repurchase of up to $200,800 worth of shares of the Company’s common stock during its term. The 2012 Trading Plan became effective on March 22, 2012 and will terminate on March 22, 2013. The Company may suspend or terminate the 2012 Trading Plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the prohibitions of Rule 10b-5 under the Exchange Act or other applicable securities laws.

Item 5.

Other Information

On April 25, 2012, the Company issued a press release announcing its results of operations for the three-month period ended March 31, 2012. The press release is furnished with this Quarterly Report on Form 10-Q as Exhibit 99.1.

Item 6.

Exhibits

(a) Exhibits


Exhibit No.	Description of Exhibit	Reference
10.1	Unitil Corporation Second Amended and Restated 2003 Stock Plan	Incorporated by reference to Appendix 1 to the Registrant’s Proxy Statement filed on Schedule 14A dated March 13, 2012

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 25, 2012 Announcing Earnings For the Quarter Ended March 31, 2012.	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.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith

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 25, 2012		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: April 25, 2012		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer

EXHIBIT INDEX


Exhibit No.	Description of Exhibit	Reference
10.1	Unitil Corporation Second Amended and Restated 2003 Stock Plan	Incorporated by reference to Appendix 1 to the Registrant’s Proxy Statement filed on Schedule 14A dated March 13, 2012

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 25, 2012 Announcing Earnings For the Quarter Ended March 31, 2012.	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.LAB	XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith