UNITIL CORP - Quarter Report: 2011 September (Form 10-Q)

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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 September 30, 2011

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 October 25, 2011
Common Stock, No par value		10,945,747 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2011

Table of Contents


		Page No.
Part I. Financial Information		2

Item 1.	Financial Statements

	Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2011 and 2010	20

	Consolidated Balance Sheets, September 30, 2011, September 30, 2010 and December 31, 2010	21-22

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2011 and 2010	23

	Notes to Consolidated Financial Statements	24-38

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	2-19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	38

Item 4T.	Controls and Procedures	Inapplicable

Part II. Other Information

Item 1.	Legal Proceedings	39

Item 1A.	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 3.	Defaults Upon Senior Securities	Inapplicable

Item 4.	(Removed and Reserved)	Inapplicable

Item 5.	Other Information	39

Item 6.	Exhibits	40

Signatures		41

Exhibit 11	Computation of Earnings per Weighted Average Common Share Outstanding

PART I. FINANCIAL INFORMATION

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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. On December 1, 2008, the Company purchased: (i) all of the outstanding capital stock of Northern Utilities, Inc. (Northern Utilities), a natural gas distribution utility serving customers in New Hampshire and Maine, from Bay State Gas Company and (ii) all of the outstanding capital stock of Granite State Gas Transmission, Inc. (Granite State), an interstate natural gas transmission pipeline company primarily serving the needs of Northern Utilities, from NiSource, Inc. (the Acquisitions).

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

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

ii)

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

iii)

Northern Utilities, 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 100,900 electric customers and 70,800 natural gas customers in their service territory.

In addition, Unitil is the parent company of Granite State, an interstate natural gas transmission pipeline company, operating 87 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 $499.8 million at September 30, 2011. 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., which owns and manages Unitil’s corporate office building and property located in Hampton, New Hampshire and Unitil Power Corp., which formerly functioned as the full requirements wholesale power supply provider for Unitil Energy. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

RATES AND REGULATION

Rate Case Activity:

Fitchburg - On January 14, 2011, Fitchburg filed a petition with the Massachusetts Department of Public Utilities (MDPU) requesting approval of a comprehensive revenue decoupling proposal and for an increase in its electric and gas distribution rates. In its rate filing the Company made a request for an increase of $7.1 million in its electric distribution rates, including the recovery of deferred emergency storm restoration costs incurred as a result of the December 2008 ice storm and subsequent restoration. The MDPU had earlier approved Fitchburg’s petition to defer and record as a regulatory asset costs associated with the repair of its electric distribution system from the ice storm damage for future recovery in rates. The Company’s filing also included a request for an increase of $4.4 million in its gas distribution rates.

On August 1, 2011, the MDPU issued its Order (the “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 the Company. 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. As a result, the Company recognized a non-recurring pre-tax charge of $2.0 million in the third quarter of 2011 to charge-off previously accrued carrying costs of $1.8 million and other previously accrued expenses related to the December 2008 ice storm. 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 - On June 29, 2010, Granite State filed a base transportation rate increase of $2.3 million in annual revenue with the FERC. On November 30, 2010, a settlement was filed on behalf of Granite State and all intervenors in the proceeding, resolving all issues and providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. The settlement was approved by the FERC on January 31, 2011.

On July 26, 2011, an amendment to the rate settlement agreement was filed on behalf of Granite State and the parties to this proceeding. The amendment was approved by the FERC on August 31, 2011. The amended settlement agreement results in 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 would also be permitted to file limited rate adjustment filings to recover the revenue requirements for future capital cost additions to transmission plant for major planned projects as stipulated in the amended settlement. The limited rate adjustment filings would be made annually on or about June 29 of each year to be effective August 1 of each year, and are projected to conclude in 2014 when these major projects will be completed. The estimated annual revenue increases for these limited rate adjustment filings of approximately $0.3 million, $0.3 million and $0.6 million would occur on August 1, 2012, August 1, 2013 and August 1, 2014, respectively.

Unitil Energy - On April 26, 2011 the New Hampshire Public Utilities Commission (NHPUC) issued an order approving new base rates (Order). The Order makes permanent a temporary increase of $5.2 million in annual revenue which went into effect on July 1, 2010. The Order also provides for an additional increase of $5.0 million in annual revenue which went into effect on May 1, 2011. The Order extends through May 1, 2016 and provides for a long-term rate plan and earnings sharing mechanism, with estimated future increases in annual revenue of $1.5 million, $1.9 million and $1.4 million to occur on May 1, 2012, May 1, 2013 and May 1, 2014, respectively, to support Unitil Energy’s continued capital improvements to its distribution system. Additionally, the Order provides for an augmented vegetation management program and reliability enhancement program by Unitil Energy which would be funded in the future rate increases discussed above. Finally, the Order provides for recovery of deferred December 2008 ice storm and February 2010 wind storm costs over eight years in the form of a tariff surcharge and 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.

Northern Utilities - In May 2011, Northern Utilities filed two separate rate cases requesting approval to change its natural gas distribution base rates in New Hampshire and Maine, with the NHPUC and the Maine Public Utilities Commission (MPUC), respectively.

The filings represent the first rate case in approximately 10 years for Northern Utilities’ New Hampshire gas distribution operations and 28 years for its Maine gas distribution operations. In New Hampshire, the Company has requested an increase of $5.2 million in annual gas distribution base revenue, which represents an increase of approximately 8.1 percent. In Maine, the Company has requested an increase of $10.1 million in annual gas distribution base revenue which represents an increase of approximately 16.7 percent. Both filings include an initial step increase to reflect 2011 capital spending and a proposed capital cost recovery tracking mechanism to recover the future costs associated with Northern Utilities’ cast iron and bare steel pipe replacement programs. The rate case filings are subject to regulatory review and approval with final rate orders expected by the end of the first quarter of 2012. Northern Utilities has also requested temporary rates in both states. In New Hampshire, a settlement of temporary rates was reached among the Company, the NHPUC Staff and the Office of Consumer Advocate which provides for a temporary increase of approximately $1.7 million in annual revenue to become effective as of August 1, 2011. On July 22, 2011, the NHPUC approved the temporary revenue increase as filed. In New Hampshire, once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, August 1, 2011. Hearings on permanent rates before the NHPUC are currently scheduled for the end of March 2012.

The request for temporary rates in Maine remains pending before the MPUC. On August 3, 2011, the Maine Office of the Public Advocate filed its testimony in the rate case, recommending an increase of $7.4 million, and a number of adjustments to the initial step increase to reflect 2011 capital spending related to the proposed capital cost tracking mechanism. On September 14, 2011, the MPUC Staff submitted its Bench Analysis, which provided the Staff’s view on a number of issues in the company’s requested increase and proposed several modifications. The MPUC Staff did not provide a recommended revenue requirement, but indicated that its analysis showed that the required increase was less than either the Company’s or Public Advocate’s proposals. The Company filed its rebuttal testimony on October 5, 2011, which supports its initial requested increase with several minor adjustments. On October 25, 2011, the Company and the Maine Office of the Public Advocate along with certain other Intervenor parties to this proceeding, entered into a comprehensive settlement agreement resolving all outstanding issues in this rate case among them. The comprehensive settlement agreement supports the Company’s request for a temporary annual increase in distribution revenue of $3.5 million effective November 1, 2011, a permanent annual increase in distribution revenue of $7.8 million effective January 1, 2012, and a permanent annual increase in distribution revenue of $0.8 million to recover the costs of 2011 cast iron capital spending effective May 1, 2012. Hearings before the MPUC on the comprehensive settlement agreement are scheduled for the last week of October. Deliberations for the temporary annual increase in distribution revenue are also scheduled for the last week of October. The Company expects a final decision from the MPUC by November 1, 2011 regarding the temporary annual increase in distribution revenue, and by December 31, 2011 regarding the permanent annual increases in distribution revenue.

Regulation:

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

Unitil’s distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under cost of service regulation and subject to the rules, policies and procedures in each applicable regulatory jurisdiction. 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 suppliers. A majority of Unitil’s largest commercial and industrial (C&I) customers purchase their electric and natural gas supplies from third-party suppliers. However, most residential and small customers continue to purchase their electric and natural gas supplies through Unitil’s distribution utilities. Unitil’s distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual 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.

The regulatory process in both New Hampshire and Maine, in connection with those states’ approvals of the Acquisitions, included the negotiation and filing of settlement agreements reflecting commitments by Unitil with respect to Northern Utilities’ rates, customer service and operations. The settlement agreements were separately negotiated and filed in each state but reflect a number of common features. For additional discussion, please refer to Unitil’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 3, 2011.

CAUTIONARY STATEMENT

This report and the documents we incorporate 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 impact the rates the Company is able to charge, the Company’s authorized rate of return and the Company’s ability to recover costs in its rates;

•

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

•

customers’ preferences on 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 counterparty’s 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 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 Management’s Discussion & Analysis compares the results of operations for each of the two fiscal periods ended September 30, 2011 and September 30, 2010 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 its 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 expenses usually exceed sales margins in those periods.

Earnings Overview

The Company’s Earnings (Loss) Applicable to Common Shareholders was $6.3 million, or $0.58 per share, for the nine months ended September 30, 2011, compared to $4.3 million, or $0.40 per share, for the same period of 2010. Results for the nine month period reflect increased electric and gas sales margins and volumes across all of Unitil’s distribution utilities.

For the third quarter of 2011, the Company reported a net loss of ($1.6 million), or ($0.15) per share, compared to a net loss of ($0.1) million, or ($0.01) per share, for the third quarter of 2010. During the third quarter of 2011, the Company’s Massachusetts distribution utility completed its electric and natural gas rate cases which provided: a combined annual revenue increase of $7 million, electric and gas revenue decoupling mechanisms, and recovery of December 2008 ice storm costs. In the third quarter of 2011, in connection with those Massachusetts rate cases, the Company recognized a non-recurring pre-tax charge of $2.0 million, or $0.11 per share, related to the December 2008 ice storm. The conclusion of the Massachusetts rate cases provides resolution to the open regulatory matters concerning the ratemaking treatment and cost recovery related to the December 2008 ice storm event.

Natural gas sales margin increased $0.3 million and $4.3 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, reflecting higher sales volumes. Total natural gas therm sales were 6.0% and 13.1% higher in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. The increased sales reflect: increased usage by Commercial and Industrial (C&I) customers, growth in new customers and the effect of colder weather earlier in the year. Heating Degree Days in the first nine months of 2011 were 9.2% greater than in the same period in 2010. On a weather-normalized basis, natural gas sales increased 5.9% and 8.6% in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010.

Electric sales margin increased $0.9 million and $5.6 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, reflecting higher rates. Total electric kilowatt hour (kWh) sales decreased 3.4% in the three months ended September 30, 2011 compared to the same period in 2010 reflecting the effect of cooler summer weather in 2011 compared to the same period in 2010. For the nine months ended September 30, 2011, total kWh sales increased 0.3% compared to the same period in 2010 reflecting higher sales to Residential customers partially offset by lower sales to C&I customers. The increased sales to Residential customers in the nine month period reflect customer growth and the effect of colder winter weather in the first quarter of 2011 compared to 2010, partially offset by the effect of cooler summer weather in 2011 compared to 2010. There were 19.8% fewer Cooling Degree Days in the third quarter of 2011 compared to the same period in 2010 while Heating Degree Days in the first quarter of 2011 were 6% greater than in the same period in 2010. On a weather-normalized basis, total kWh sales increased 0.8% and 1.0% in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010.

Operation and Maintenance (O&M) expenses increased $0.5 million and $1.4 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The changes in O&M expenses for the three month period reflect higher utility operating costs of $0.8 million and higher compensation and employee benefit costs of $0.2 million, partially offset by lower professional fees of $0.3 million and lower all other operating costs of $0.2 million. The changes in O&M expenses for the nine month period reflect higher utility operating costs of $1.8 million and higher compensation and employee benefit costs of $1.0 million, partially offset by a reduction of $1.0 million associated with the proceeds from an insurance settlement, lower professional fees of $0.2 million and lower all other operating costs of $0.2 million. Utility operating costs in the three and nine month periods ended September 30, 2011 include approximately $0.4 million and $0.8 million, respectively, 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 $0.8 million and $2.1 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, reflecting normal utility plant additions and a change in depreciation rates resulting from the Company’s recent base rate case in Massachusetts.

Local Property and Other Taxes increased $0.5 million and $1.2 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. These increases reflect higher local property tax rates and higher levels of utility plant in service.

Federal and State Income Taxes decreased by $0.8 million for the three months ended September 30, 2011 compared to the same period in 2010 due to lower pre-tax earnings in the current period. Federal and State Income Taxes increased by $1.4 million for the nine months ended September 30, 2011 compared to the same period in 2010 due to higher pre-tax earnings in 2011 compared to the same period in 2010.

Other Non-Operating Expenses increased $0.1 million and $0.1 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010.

assets, including a non-recurring pre-tax charge, in the third quarter of 2011, against interest income of $1.8 million related to the final Order issued by the MDPU, discussed above, the issuance of $40 million of long-term notes by Unitil Energy and Northern Utilities in March 2010 and interest expense of $0.1 million recognized in the third quarter of 2011 related to the settlement with a customer regarding a billing error, as discussed below in Note 6 to the Consolidated Financial Statements.

Usource, the Company’s non-regulated energy brokering business, recorded revenues of $1.5 million and $4.2 million in the three and nine month periods ended September 30, 2011, respectively, increases of $0.3 million and $0.8 million, respectively, compared to the same periods of 2010. 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.

In 2010, 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, 2011, March, 2011, June 2011 and September 2011 meetings, the Unitil 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 and nine months ended September 30, 2011 is presented below.

Gas Sales, Revenues and Margin

Therm Sales – Total therm sales of natural gas increased 6.0% and 13.1% in the three and nine months ended September 30, 2011 compared to the same periods in 2010. The increase in gas therm sales in the Company’s utility service territories reflects increased usage by both Residential and C&I customers resulting from the addition of new customers. The increased sales also reflect the effect of colder weather earlier in the year. Heating Degree Days in the first nine months of 2011 were 9.2% greater than in the same period in 2010. On a weather-normalized basis, natural gas sales increased 5.9% and 8.6% in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010.

The following table details total firm therm sales for the three and nine months ended September 30, 2011 and 2010, by major customer class:


Therm Sales (millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2011		2010		Change		% Change			2011		2010		Change		% Change
Residential		2.6		2.5		0.1		4.0	%		30.5		26.9		3.6		13.4	%
Commercial / Industrial		20.5		19.3		1.2		6.2	%		114.1		100.9		13.2		13.1	%

Total		23.1		21.8		1.3		6.0	%		144.6		127.8		16.8		13.1	%

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three and nine months ended September 30, 2011 and 2010:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2011		2010		$ Change			% Change⁽¹⁾			2011		2010		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	8.0	$	6.7	$	1.3			7.5	%	$	46.8	$	42.5	$	4.3			4.2	%
Commercial / Industrial		13.2		10.7		2.5			14.3	%		65.5		59.7		5.8			5.7	%

Total Gas Operating Revenue	$	21.2	$	17.4	$	3.8			21.8	%	$	112.3	$	102.2	$	10.1			9.9	%

Cost of Gas Sales:
Purchased Gas	$	12.5	$	8.9	$	3.6			20.7	%	$	68.0	$	61.5	$	6.5			6.4	%
Conservation & Load Management		0.5		0.6		(0.1	)		(0.6	%)		1.5		2.2		(0.7	)		(0.7	%)

Total Cost of Gas Sales	$	13.0	$	9.5	$	3.5			20.1	%	$	69.5	$	63.7	$	5.8			5.7	%

Gas Sales Margin	$	8.2	$	7.9	$	0.3			1.7	%	$	42.8	$	38.5	$	4.3			4.2	%

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

Total Gas Operating Revenues increased $3.8 million, or 21.8%, and $10.1 million, or 9.9%, in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. Total Gas Operating Revenues include the recovery of the approved costs of gas sales, which are recorded as Purchased Gas and Conservation & Load Management (C&LM) in Operating Expenses. The increase in Total Gas Operating Revenues in the third quarter of 2011 reflects higher Purchased Gas revenues of $3.6 million and higher natural gas sales margins of $0.3 million, partially offset by lower C&LM revenues of $0.1 million. The increase in Total Gas Operating Revenues in the first nine months of 2011 reflects higher Purchased Gas revenues of $6.5 million and higher natural gas sales margins of $4.3 million, partially offset by lower C&LM revenues of $0.7 million.

The Purchased Gas and C&LM components of Gas Operating Revenues increased a combined $3.5 million, or 20.1%, of Total Gas Operating Revenue and $5.8 million, or 5.7%, of Total Gas Operating Revenue in the three and nine month periods ended September 30, 2011 compared to the same periods in 2010. These increases are due to higher sales of natural gas partially offset by an increase in the amount of natural gas purchased by customers directly from third-party suppliers and lower spending on energy efficiency and conservation programs. The Company recovers the costs of Purchased Gas and C&LM in its rates at cost on a pass through basis.

Natural gas sales margin increased $0.3 million and $4.3 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, primarily reflecting higher sales volumes.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Total kWh sales decreased 3.4% in the three months ended September 30, 2011 compared to the same period in 2010 reflecting the effect of cooler summer weather in 2011 compared to the same period in 2010. For the nine months ended September 30, 2011, total kWh sales increased 0.3% compared to the same period in 2010 reflecting higher sales to Residential customers partially offset by lower sales to C&I customers. The increased sales to Residential customers in the nine month period reflect customer growth and the effect of colder winter weather earlier in the year partially offset by the effect of cooler summer weather in 2011 compared to 2010. There were 19.8% fewer Cooling Degree Days in the third quarter of 2011 compared to the same period in 2010 while Heating Degree Days in the

first quarter of 2011 were 6% greater than in the same period in 2010. On a weather-normalized basis, total kWh sales increased 0.8% and 1.0% in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010.

The following table details total kWh sales for the three and nine months ended September 30, 2011 and 2010 by major customer class:


kWh Sales (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2011		2010		Change			% Change			2011		2010		Change			% Change
Residential		190.2		198.7		(8.5	)		(4.3	%)		530.1		524.7		5.4			1.0	%
Commercial / Industrial		276.5		284.6		(8.1	)		(2.8	%)		766.2		767.9		(1.7	)		(0.2	%)

Total		466.7		483.3		(16.6	)		(3.4	%)		1,296.3		1,292.6		3.7			0.3	%

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three and nine month periods ended September 30, 2011 and 2010:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,										Nine Months Ended September 30,
	2011		2010		$ Change			% Change⁽¹⁾			2011		2010		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	27.2	$	31.0	$	(3.8	)		(6.6	%)	$	76.1	$	82.9	$	(6.8	)		(4.4	%)
Commercial / Industrial		23.3		26.5		(3.2	)		(5.6	%)		65.5		72.0		(6.5	)		(4.2	%)

Total Electric Operating Revenue	$	50.5	$	57.5	$	(7.0	)		(12.2	%)	$	141.6	$	154.9	$	(13.3	)		(8.6	%)

Cost of Electric Sales:
Purchased Electricity	$	31.0	$	39.6	$	(8.6	)		(15.0	%)	$	88.0	$	107.1	$	(19.1	)		(12.3	%)
Conservation & Load Management		1.7		1.0		0.7			1.2	%		3.8		3.6		0.2			0.1	%

Total Cost of Electric Sales	$	32.7	$	40.6	$	(7.9	)		(13.8	%)	$	91.8	$	110.7	$	(18.9	)		(12.2	%)

Electric Sales Margin	$	17.8	$	16.9	$	0.9			1.6	%	$	49.8	$	44.2	$	5.6			3.6	%

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

Total Electric Operating Revenue decreased by $7.0 million, or 12.2%, and $13.3 million, or 8.6%, in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. Total Electric Operating Revenues include the recovery of the approved costs of electric sales, which are recorded as Purchased Electricity and C&LM in Operating Expenses. The decrease in Total Electric Operating Revenues in the third quarter of 2011 reflects lower Purchased Electricity revenues of $8.6 million, partially offset by higher electric sales margin of $0.9 million and higher C&LM revenues of $0.7 million. The decrease in Total Electric Operating Revenues in the first nine months of 2011 reflects lower Purchased Electricity revenues of $19.1 million, partially offset by higher electric sales margin of $5.6 million and higher C&LM revenues of $0.2 million.

The Purchased Electricity and C&LM components of Total Electric Operating Revenues decreased a combined $7.9 million, or 13.8%, and $18.9 million, or 12.2%, of Total Electric Operating Revenues in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in

2010. The decrease in the three month period primarily reflects lower electric kWh sales and lower electric commodity prices, partially offset by increased spending on energy efficiency and conservation programs. The decrease in the nine month period primarily reflects lower electric commodity costs and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by increased sales and increased spending on energy efficiency and conservation programs. The Company recovers the costs of Purchased Electricity and C&LM in its rates at cost on a pass through basis.

Electric sales margin increased $0.9 million and $5.6 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, reflecting higher rates. Electric sales margin also reflects the recognition of non-recurring billing adjustments of $0.2 million and $0.3 million in the three and nine month periods ended September 30, 2011, respectively, related to a customer billing error, as discussed below in Note 6 to the Consolidated Financial Statements.

Operating Revenue - Other

The following table details total Other Revenue for the three and nine months ended September 30, 2011 and 2010:


Other Revenue (000’s)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2011		2010		$ Change		% Change			2011		2010		$ Change		% Change
Other	$	1.5	$	1.2	$	0.3		25.0	%	$	4.2	$	3.4	$	0.8		23.5	%

Total Other Revenue	$	1.5	$	1.2	$	0.3		25.0	%	$	4.2	$	3.4	$	0.8		23.5	%

Total Other Revenue increased $0.3 million, or 25.0%, and $0.8 million, or 23.5%, in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. These increases were the result of growth in revenues from the Company’s non-regulated energy brokering business, Usource. 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 expenses include the cost to supply interstate pipeline gas and supplemental gas resources (e.g. liquefied natural gas, propane) to meet customers’ total requirements for gas. Purchased Gas increased $3.6 million and $6.5 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. These increases reflect higher sales of natural gas partially offset by an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The Company recovers the approved costs of Purchased Gas in its rates at cost on a pass through basis and therefore changes in these expenses do not affect earnings.

Purchased Electricity – Purchased Electricity expenses include the cost to supply electricity to meet customers’ total requirements for electricity, as well as other electric supply related restructuring costs, including long-term power supply contract buyout costs. Purchased Electricity decreased $8.6 million and $19.1 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. The decrease in the three month period primarily reflects lower electric kWh sales and lower electric commodity costs. The decrease in the nine month period primarily reflects lower electric commodity costs and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by increased sales. The Company recovers the approved costs

of Purchased Electricity in its rates at cost on a pass through basis and therefore changes in these expenses do not affect earnings.

Operation and Maintenance (O&M) – O&M expense includes electric and gas utility operating costs, and the operating cost of the Company’s unregulated business activities. Total O&M expenses increased $0.5 million and $1.4 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The changes in O&M expenses for the three month period reflect higher utility operating costs of $0.8 million and higher compensation and employee benefit costs of $0.2 million, partially offset by lower professional fees of $0.3 million and lower all other operating costs of $0.2 million. The changes in O&M expenses for the nine month period reflect higher utility operating costs of $1.8 million and higher compensation and employee benefit costs of $1.0 million, partially offset by a reduction of $1.0 million associated with the proceeds from an insurance settlement, lower professional fees of $0.2 million and lower all other operating costs of $0.2 million. Utility operating costs in the three and nine month periods ended September 30, 2011 include approximately $0.4 million and $0.8 million, respectively, 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 – Conservation and Load Management 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 usage. 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. Approximately 70% of these costs are related to electric operations and 30% to gas operations.

Total C&LM expenses increased $0.6 million, or 37.5% and decreased $0.5 million, or 8.6%, in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. These approved costs are collected from customers on a pass through basis and therefore, fluctuations in program costs do not affect earnings.

Depreciation, Amortization and Taxes

Depreciation and Amortization – Depreciation and Amortization expense increased $0.8 million and $2.1 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, reflecting normal utility plant additions and a change in depreciation rates resulting from the Company’s recent base rate case in Massachusetts.

Local Property and Other Taxes – Local Property and Other Taxes increased $0.5 million and $1.2 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. These increases reflect higher local property tax rates and higher levels of utility plant in service.

Federal and State Income Taxes – Federal and State Income Taxes decreased by $0.8 million for the three months ended September 30, 2011 compared to the same period in 2010 due to lower pre-tax earnings in the current period. Federal and State Income Taxes increased by $1.4 million for the nine months ended September 30, 2011 compared to the same period in 2010 due to higher pre-tax earnings in 2011 compared to the same period in 2010.

Other Non-Operating Expenses (Income)

Other Non-Operating Expenses increased $0.1 million and $0.1 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010.

Interest Expense, Net

Interest expense is presented in the consolidated 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 September 30,								Nine Months Ended September 30,
	2011			2010			Change		2011			2010			Change
Interest Expense
Long-term Debt	$	5.1		$	5.1		$	—	$	15.2		$	14.9		$	0.3
Short-term Debt		0.4			0.3			0.1		1.2			1.1			0.1
Regulatory Liabilities		0.1			0.1			—		0.2			0.2			—

Subtotal Interest Expense		5.6			5.5			0.1		16.6			16.2			0.4

Interest (Income)
Regulatory Assets		1.2			(0.6	)		1.8		(0.2	)		(2.3	)		2.1
AFUDC⁽¹⁾ and Other		(0.2	)		(0.2	)		—		(0.4	)		(0.4	)		—

Subtotal Interest (Income)		1.0			(0.8	)		1.8		(0.6	)		(2.7	)		2.1

Total Interest Expense, Net	$	6.6		$	4.7		$	1.9	$	16.0		$	13.5		$	2.5

⁽¹⁾	AFUDC – Allowance for Funds Used During Construction.

Interest Expense, Net increased $1.9 million and $2.5 million in the three and nine month periods ended September 30, 2011, respectively, compared to the same periods in 2010. The increases in the three and nine month periods ended September 30, 2011 are due to lower interest income recorded on regulatory assets, including a non-recurring pre-tax charge, in the third quarter of 2011, against interest income of $1.8 million related to the final Order issued by the MDPU, discussed above, the issuance of $40 million of long-term notes by Unitil Energy and Northern Utilities in March 2010 and interest expense of $0.1 million recognized in the third quarter of 2011 related to the settlement with a customer regarding a billing error, as discussed below in Note 6 to the Consolidated Financial Statements.

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 bank 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. The Company’s utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows.

The continued availability of these methods of financing, as well as the Company’s choice of a specific form of security, 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 the Company’s earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

Unitil has a revolving credit agreement with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit agreement was $80.0 million at September 30, 2011, September 30, 2010 and December 31, 2010. There was $65.4 million, $46.3 and $66.8 million in short-term debt outstanding through bank borrowings under the revolving credit agreement at September 30, 2011, September 30, 2010 and December 31, 2010, respectively. The total amount of credit available under the Company’s revolving credit agreement was $14.6 million, $33.7 million and $13.2 million at September 30, 2011, September 30, 2010 and December 31, 2010, respectively. The revolving credit agreement 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 September 30, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

On October 12, 2011, Unitil entered into the fifth amendment agreement with Bank of America, N.A., as administrative agent, and a syndicate of other lenders party thereto, further amending the revolving credit agreement dated as of November 26, 2008. The revolving credit agreement was previously amended on January 2, 2009, March 16, 2009, October 13, 2009 and October 8, 2010 to, among other things, increase the maximum borrowings under the facility, provide for a base rate interest rate option, reflect letter of credit availability, modify certain financial reporting requirements and extend the scheduled termination date of the facility. The fifth amendment agreement increases the maximum borrowings under the facility to $115 million, changes the additional interest margin applicable to borrowings at a fluctuating rate of interest per annum equal to the daily London Interbank Offered Rate from 2.00% to 1.75%, and changes the annual letter of credit fee from 1.625% of the daily amount available to be drawn under letters of credit issued under the credit facility to 1.50% of such daily amount. Also, see Credit Arrangements in Note 4.

Northern Utilities enters into asset management agreements under which Northern Utilities releases certain natural gas pipeline and storage assets, resells the natural gas storage inventory to an asset manager and subsequently repurchases the inventory over the course of the natural gas heating season at the same price at which it sold the natural gas inventory to the asset manager. There was $13.0 million, $12.3 million and $11.7 million outstanding at September 30, 2011, September 30, 2010 and December 31, 2010, respectively, related to these asset management agreements. There were no amounts of natural gas inventory released in September 2011 and payable in October 2011 that were recorded in Accounts Payable at September 30, 2011. There were no amounts of natural gas inventory released in September 2010 and payable in October 2010 that were recorded in Accounts Payable at September 30, 2010. The amount of natural gas inventory released in December 2010, which was payable in January 2011, is $3.9 million and recorded in Accounts Payable at December 31, 2010.

The Company also provides limited guarantees on certain energy and natural gas storage management contracts entered into by the three distribution utilities. The Company’s policy is to generally limit these guarantees to approximately two years or less. As of September 30, 2011 there are $37.2 million of guarantees outstanding and the longest of these guarantees 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 September 30, 2011, the principal amount outstanding for the 8% Unitil Realty notes was $3.5 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 September 30, 2011, 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 nine months ended September 30, 2011 compared to the same period in 2010.


	Nine Months Ended September 30,
	2011		2010
Cash Provided by Operating Activities	$	49.8	$	21.5

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $49.8 million for the first nine months of 2011 compared to $21.5 million in the same period of 2010. In the first nine months of 2011 as compared to the first nine months of 2010, net sources of cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes increased by $7.5 million, changes in working capital items increased $4.8 million, and changes in all other Operating Activities increased $16.0 million.


	Nine Months Ended September 30,
	2011			2010
Cash (Used in) Investing Activities	$	(42.7	)	$	(33.8	)

Cash (Used in) Investing Activities – Cash (Used in) Investing Activities was ($42.7) million for the nine months ended September 30, 2011 compared to ($33.8) million for the same period in 2010. The capital spending in both periods is representative of normal distribution utility capital expenditures reflecting normal electric and gas utility system additions. Capital expenditures are projected to total approximately ($59.0) million for 2011.


	Nine Months Ended September 30,
	2011			2010
Cash Provided by (Used in) Financing Activities	$	(8.1	)	$	12.6

Cash Provided by (Used in) Financing Activities – Cash (Used in) Financing Activities was ($8.1) million for the nine months ended September 30, 2011 compared to Cash Provided by Financing Activities of $12.6 million for the same period in 2010. Short-term borrowings were reduced by ($1.4) million in the first nine months of 2011. Other sources and (uses) of cash include ($11.4) million for quarterly dividend payments, gas inventory financing of $5.1 million, repayment of long-term debt of ($0.3) million, and other of ($0.8) million. Proceeds from issuances of common stock provided a source of cash of $0.7 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 3, 2011.

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 Financial Accounting Standards Board (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)



	September 30,				December 31,
	2011		2010		2010
Energy Supply Contract Obligations	$	14.9	$	24.3	$	21.7
Deferred Restructuring Costs		22.0		25.8		25.0

Subtotal – Restructuring Related Items		36.9		50.1		46.7
Retirement Benefit Obligations		47.0		43.6		47.1
Income Taxes		12.1		13.2		12.7
Environmental Obligations		17.9		20.6		20.3
Deferred Storm Charges		18.5		21.0		21.0
Other		15.0		10.1		10.9

Total Regulatory Assets	$	147.4	$	158.6	$	158.7
Less: Current Portion of Regulatory Assets⁽¹⁾		16.5		16.6		15.7

Regulatory Assets – noncurrent	$	130.9	$	142.0	$	143.0

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

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.

On August 1, 2011, the Massachusetts Department of Public Utilities (MDPU) issued an Order approving revenue decoupling mechanisms (RDM) for the electric and natural gas divisions of the Company’s Massachusetts combination electric and natural gas distribution utility, Fitchburg Gas and Electric Light Company (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. The purpose of decoupling is to eliminate the disincentive a utility otherwise has to encourage energy efficiency programs. Under the RDM, the Company will recognize, in its Consolidated Statements of Earnings from August 1, 2011 forward, distribution revenues for Fitchburg based on predetermined amounts approved by the MDPU. The difference between distribution revenue amounts billed to customers and the predetermined amounts is recognized as increases or decreases in Accrued Revenue which form the basis for future reconciliation adjustments in periodically resetting rates for future cash recovery.

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 regulatory authorities 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 Retiree Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

The Company records on its 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 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.

The Company’s RBO may also be significantly affected by changes in key actuarial assumptions, including, anticipated rates of return on plan assets and the discount rates used in determining the Company’s RBO. 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 a market average of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For the year ended December 31, 2010, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $300,000 in the Net Periodic Benefit Cost for the Pension Plan. For the year ended December 31, 2010, a 1.0% increase in the assumption of health care cost trend rates would have resulted in an increase in the Net Periodic Benefit Cost for the PBOP Plan of $728,000. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for that time period would have resulted in a decrease in the Net Periodic Benefit Cost for the PBOP Plan of $565,000. 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 and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included on 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.

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 realizability 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 September 30, 2011, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

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

LABOR RELATIONS

As of September 30, 2011, the Company and its subsidiaries had 460 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of September 30, 2011, 152 of the Company’s employees were represented by labor unions. These employees are covered by four separate collective bargaining agreements which expire on March 31, 2012, May 31, 2012, May 31, 2013 and June 5, 2014. The agreements provide discrete salary adjustments, established work practices and uniform benefit packages. The Company expects to negotiate new agreements prior to their expiration dates.

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding was $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rates on the Company’s short-term borrowings for the three months ended September 30, 2011 and September 30, 2010 were 2.24% and 2.32%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2011 and September 30, 2010 were 2.26% and 2.30%, respectively.

MARKET 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 full collection of electric power and natural gas supply 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 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 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011		2010
Operating Revenues
Gas	$	21.2		$	17.4		$	112.3	$	102.2
Electric		50.5			57.5			141.6		154.9
Other		1.5			1.2			4.2		3.4

Total Operating Revenues		73.2			76.1			258.1		260.5

Operating Expenses
Purchased Gas		12.5			8.9			68.0		61.5
Purchased Electricity		31.0			39.6			88.0		107.1
Operation and Maintenance		13.6			13.1			38.3		36.9
Conservation & Load Management		2.2			1.6			5.3		5.8
Depreciation and Amortization		6.9			6.1			22.5		20.4
Provisions (Benefit) for Taxes:
Local Property and Other		3.2			2.7			9.5		8.3
Federal and State Income		(1.4	)		(0.6	)		3.7		2.3

Total Operating Expenses		68.0			71.4			235.3		242.3

Operating Income		5.2			4.7			22.8		18.2
Non-Operating Expenses (Income)		0.2			0.1			0.4		0.3

Income Before Interest Expense		5.0			4.6			22.4		17.9
Interest Expense, Net		6.6			4.7			16.0		13.5

Net Income (Loss)		(1.6	)		(0.1	)		6.4		4.4
Less: Dividends on Preferred Stock		—			—			0.1		0.1

Earnings (Loss) Applicable to Common Shareholders	$	(1.6)		$	(0.1)		$	6.3	$	4.3


Weighted Average Common Shares Outstanding – Basic (000’s)		10,887			10,830			10,875		10,817
Weighted Average Common Shares Outstanding – Diluted (000’s)		10,887			10,830			10,877		10,818
Earnings Per Common Share (Basic and Diluted)	$	(0.15	)	$	(0.01	)	$	0.58	$	0.40
Dividends Declared Per Share of Common Stock	$	0.345		$	0.345		$	1.38	$	1.38

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)

(UNAUDITED)


	September 30,				December 31,
	2011		2010		2010
ASSETS:

Utility Plant:
Electric	$	326.6	$	313.5	$	321.5
Gas		363.9		348.5		360.1
Common		30.4		30.4		30.2
Construction Work in Progress		41.4		18.9		16.6

Total Utility Plant		762.3		711.3		728.4
Less: Accumulated Depreciation		262.5		247.7		251.9

Net Utility Plant		499.8		463.6		476.5

Current Assets:
Cash		7.9		8.0		8.9
Accounts Receivable, net		30.4		27.2		36.9
Accrued Revenue		35.2		35.7		46.7
Refundable Taxes		—		—		7.5
Gas Inventory		15.6		15.9		10.6
Materials and Supplies		3.8		3.3		2.9
Prepayments and Other		4.5		3.0		3.6

Total Current Assets		97.4		93.1		117.1

Noncurrent Assets:
Regulatory Assets		130.9		142.0		143.0
Other Noncurrent Assets		20.6		26.3		23.0

Total Noncurrent Assets		151.5		168.3		166.0

TOTAL ASSETS	$	748.7	$	725.0	$	759.6

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)

(UNAUDITED)


	September 30,				December 31,
	2011		2010		2010
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	181.2	$	183.5	$	189.0
Preferred Stock		2.0		2.0		2.0
Long-Term Debt, Less Current Portion		288.0		288.5		288.3

Total Capitalization		471.2		474.0		479.3

Current Liabilities:
Long-Term Debt, Current Portion		0.5		0.5		0.5
Accounts Payable		16.0		16.0		26.5
Taxes Payable		0.6		0.7		—
Short-Term Debt		65.4		46.3		66.8
Energy Supply Contract Obligations		21.8		23.0		17.0
Other Current Liabilities		22.5		23.5		16.1

Total Current Liabilities		126.8		110.0		126.9

Deferred Income Taxes		46.7		37.2		43.8

Noncurrent Liabilities:
Energy Supply Contract Obligations		6.1		13.6		12.6
Retirement Benefit Obligations		74.1		67.2		74.0
Environmental Obligations		14.4		14.2		14.5
Other Noncurrent Liabilities		9.4		8.8		8.5

Total Noncurrent Liabilities		104.0		103.8		109.6

TOTAL CAPITALIZATION AND LIABILITIES	$	748.7	$	725.0	$	759.6

(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)


	Nine Months Ended September 30,
	2011			2010
Operating Activities:
Net Income	$	6.4		$	4.4
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		22.5			20.4
Deferred Tax Provision (Benefit)		2.5			(0.9	)
Changes in Working Capital Items:
Accounts Receivable		6.5			6.3
Accrued Revenue		11.5			8.3
Taxes Refundable / Payable		8.1			2.4
Gas Inventory		(5.0	)		(1.6	)
Accounts Payable		(10.5	)		(9.1	)
Other Changes in Working Capital Items		4.3			3.8
Deferred Regulatory and Other Charges		8.8			(9.2	)
Other, net		(5.3	)		(3.3	)

Cash Provided by Operating Activities		49.8			21.5


Investing Activities:
Property, Plant and Equipment Additions		(42.7	)		(33.8	)

Cash (Used in) Investing Activities		(42.7	)		(33.8	)


Financing Activities:
Repayment of Short-Term Debt		(1.4	)		(18.2	)
Proceeds From Issuance (Repayment of) Long-Term Debt, net		(0.3	)		39.7
Net Increase in Gas Inventory Financing		5.1			2.3
Dividends Paid		(11.4	)		(11.3	)
Proceeds from Issuance of Common Stock, net		0.7			0.7
Other, net		(0.8	)		(0.6	)

Cash Provided by (Used in) Financing Activities		(8.1	)		12.6

Net Increase (Decrease) in Cash		(1.0	)		0.3
Cash at Beginning of Period		8.9			7.7

Cash at End of Period	$	7.9		$	8.0


Supplemental Cash Flow Information:
Interest Paid	$	13.8		$	12.5
Income Taxes Paid (Refunded)	$	(7.3	)	$	1.0

(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. (collectively, “Usource”) 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 87 miles of underground gas transmission pipeline primarily located in Maine, New Hampshire and Massachusetts. 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. Amounts presented are in millions unless otherwise specified. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three and nine months ended September 30, 2011 are not necessarily indicative of results to be expected for the year ending December 31, 2011. 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, 2010, as filed with the Securities and Exchange Commission (SEC) on February 3, 2011, for a description of the Company’s Basis of Presentation.

Derivatives – The Company has a regulatory commission-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 September 30, 2011, September 30, 2010 and December 31, 2010, the Company had 1.7 billion, 1.3 billion and 1.3 billion cubic feet (BCF), respectively, outstanding in natural gas purchase contracts under its hedging program.

Liability Derivatives ($ millions)

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 Offset in Regulatory Assets⁽¹⁾, as of:
		Fair Value
Description	Balance Sheet Location	September 30, 2011		September 30, 2010		December 31, 2010
Natural Gas Futures Contracts	Other Current Liabilities	$	1.2	$	1.7	$	0.8

Natural Gas Futures Contracts	Other Noncurrent Liabilities		0.3		0.3		0.2

Total		$	1.5	$	2.0	$	1.0

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.9	$	0.7	$	1.5	$	3.6
Amount of Loss Reclassified into unaudited Consolidated Statements of Earnings⁽²⁾:
Purchased Gas	$	—	$	—	$	1.0	$	3.9

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

Reclassifications – Certain amounts previously reported have been reclassified to improve the financial statements’ presentation and to conform to current year presentation.

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

The Allowance for Doubtful Accounts as of September 30, 2011, September 30, 2010 and December 31, 2010, which are included in Accounts Receivable, net on the accompanying unaudited consolidated balance sheets, were as follows:


	September 30,				December 31,
	2011		2010		2010
Allowance for Doubtful Accounts	$	2.5	$	2.6	$	2.6

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 consolidated financial statements.

Recently Issued Pronouncements – In May 2011, the Financial Accounting Standards Board issued Accounting Standards Update No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs”, (ASU 2011-04). This update changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited, and requires prospective application. The Company does not expect that the adoption of ASU 2011-04 will have a significant, if any, impact on the Company’s Consolidated Financial Statements.

NOTE 2 – DIVIDENDS DECLARED PER SHARE

Declaration

Date

Date Paid
(Payable)

Shareholder of
Record Date

Dividend
Amount

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

09/22/10

11/15/10

11/01/10

0.345

06/17/10

08/16/10

08/02/10

0.345

03/25/10

05/14/10

04/30/10

0.345

01/14/10

02/16/10

02/02/10

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 10,944,675, 10,879,741 and 10,890,262 of common shares outstanding at September 30, 2011, September 30, 2010 and December 31, 2010, respectively.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2011, the Company sold 30,083 shares of its common stock, at an average price of $24.35 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans resulting in net proceeds of approximately $732,000. 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 – On February 9, 2011, 24,330 restricted shares were issued in conjunction with the 2003 Restricted Stock Plan (Restricted Stock Plan) with an aggregate market value at the date of issuance of $554,237. There were 38,811 and 33,608 non-vested shares under the Restricted Stock Plan as of September 30, 2011 and 2010, respectively. The weighted average grant date fair value of these shares was $22.03 and $21.92, respectively. The compensation expense associated with the issuance of shares under the Restricted Stock Plan is being recognized over the vesting period and was $0.5 million and $0.4 million for the nine months ended September 30, 2011 and 2010, respectively. At September 30, 2011, there was approximately $1.0 million of total unrecognized compensation cost under the Restricted Stock Plan which is expected to be recognized over approximately 2.5 years. There were no forfeitures or cancellations under the Restricted Stock Plan during the nine months ended September 30, 2011.

On March 24, 2011, the Board of Directors of the Company amended the Company’s 2003 Restricted Stock Plan (the “Amendment”) and restated the 2003 Restricted Stock Plan, as amended, in its entirety as the Company’s Amended and Restated 2003 Stock Plan (the “Stock Plan”). The Amendment adds restricted stock units as a type of award that the Company may grant to the Company’s employees, Directors or consultants pursuant to the Stock Plan. There were no restricted stock units issued under the Stock Plan during the nine months ended September 30, 2011.

Preferred Stock

Details on preferred stock at September 30, 2011, September 30, 2010 and December 31, 2010 are shown below:


	September 30,				December 31,
	2011		2010		2010
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

Shares Outstanding

September 30,

December 31,

2011

2010

Preferred Stock

Unitil Energy Preferred Stock, Non-Redeemable, Non-Cumulative:

6.00% Series, $100 Par Value,

2,250

2,250

Fitchburg Preferred Stock, Redeemable, Cumulative:

5.125% Series, $100 Par Value

7,861

7,901

8.00% Series, $100 Par Value

9,696

9,742

There were $0.1 million and $0.1 million of total dividends declared on Preferred Stock in the both the three and nine months ended September 30, 2011 and September 30, 2010, respectively.

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

Long-Term Debt

Details on long-term debt at September 30, 2011, September 30, 2010 and December 31, 2010 are shown below (millions):


	September 30,				December 31,
	2011		2010		2010
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, Due December 3, 2018		30.0		30.0		30.0
5.29% Senior Notes, Due March 2, 2020		25.0		25.0		25.0
7.72% Senior Notes, Due December 3, 2038		50.0		50.0		50.0

Granite 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		3.5		4.0		3.8

Total Long-Term Debt		288.5		289.0		288.8
Less: Current Portion		0.5		0.5		0.5

Total Long-term Debt, Less Current Portion	$	288.0	$	288.5	$	288.3

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 September 30, 2011 is estimated to be approximately $338 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

At September 30, 2011, September 30, 2010 and December 31, 2010, the Company had $65.4 million, $46.3 million and $66.8 million, respectively, in short-term debt outstanding through bank borrowings under its revolving credit facility which extends through October 8, 2013. The borrowing limit under the revolving credit facility was $80.0 million at September 30, 2011, September 30, 2010 and December 31, 2010. The total amount of credit available under the Company’s revolving credit facility at September 30, 2011, September 30, 2010 and December 31, 2010 was $14.6 million, $33.7 million and $13.2 million, 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 September 30, 2011, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

Guarantees

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2011 and September 30, 2010 (millions):


Three Months Ended September 30, 2011	Electric		Gas			Other			Non- Regulated		Total
Revenues	$	50.5	$	21.2		$	—		$	1.5	$	73.2
Segment Profit (Loss)		2.3		(4.2	)		(0.1	)		0.4		(1.6	)
Capital Expenditures		6.7		9.9			1.0			—		17.6

Three Months Ended September 30, 2010
Revenues	$	57.5	$	17.4		$	—		$	1.2	$	76.1
Segment Profit (Loss)		3.0		(3.4	)		(0.1	)		0.4		(0.1	)
Capital Expenditures		6.0		7.5			1.1			—		14.6

Nine Months Ended September 30, 2011
Revenues	$	141.6	$	112.3		$	—		$	4.2	$	258.1
Segment Profit (Loss)		5.6		(0.4	)		(0.2	)		1.3		6.3
Capital Expenditures		16.5		23.9			2.3			—		42.7
Segment Assets		368.9		367.5			6.4			5.9		748.7

Nine Months Ended September 30, 2010
Revenues	$	154.9	$	102.2		$	—		$	3.4	$	260.5
Segment Profit (Loss)		5.0		(1.9	)		0.1			1.1		4.3
Capital Expenditures		13.9		17.8			2.1			—		33.8
Segment Assets		368.6		344.8			6.9			4.7		725.0

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 6 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2010 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 3, 2011.

Regulatory Matters

Fitchburg – Base Rate Case Filings – On January 14, 2011, Fitchburg filed a petition with the MDPU requesting approval of a comprehensive revenue decoupling proposal and for an increase in its electric and gas distribution rates. In its rate filing the Company made a request for an increase of $7.1 million in its electric distribution rates, including the recovery of deferred emergency storm restoration costs incurred as a result of the December 2008 ice storm and subsequent restoration. The MDPU had earlier approved Fitchburg’s petition to defer and record as a regulatory asset costs associated with the repair of its electric distribution system from the ice storm damage for future recovery in rates. The Company’s filing also included a request for an increase of $4.4 million in its gas distribution rates.

On August 1, 2011, the Massachusetts Department of Public Utilities (“MDPU”) issued its Order (the “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 the Company. 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 Gas Transmission, Inc. – Base Rate Case Filing – On June 29, 2010, Granite State filed a base transportation rate increase of $2.3 million in annual revenue with the FERC. On November 30,

2010, a settlement was filed on behalf of Granite State and all intervenors in the proceeding, resolving all issues and providing for an increase of $1.7 million in annual revenue, based on new gas transportation rates to be effective January 1, 2011. The settlement was approved by the FERC on January 31, 2011.

Unitil Energy Base Rate Case Filing – On April 26, 2011, the NHPUC approved a final rate settlement which makes permanent a temporary increase of $5.2 million in annual revenue which went into effect on July 1, 2010, and provides for an additional increase of $5.0 million in annual revenue which went into effect on 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, $1.9 million and $1.4 million in annual revenue to occur on May 1, 2012, May 1, 2013 and May 1, 2014, respectively, 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 seven percent and a sharing of earnings with customers if its return on equity is greater than ten percent 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’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 current spending level of approximately $1.0 million to $3.1 million 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.

Northern Utilities Base Rate Case Filings – In May 2011, Northern Utilities filed two separate rate cases requesting approval to change its natural gas distribution base rates in New Hampshire and Maine, with the NHPUC and the MPUC, respectively.

states. In New Hampshire, a settlement of temporary rates was reached among the Company, the NHPUC Staff and the Office of Consumer Advocate which provides for a temporary increase of approximately $1.7 million in annual revenue to become effective as of August 1, 2011. On July 22, 2011, the NHPUC approved the temporary revenue increase as filed. In New Hampshire, once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were established, August 1, 2011. Hearings on permanent rates before the NHPUC are currently scheduled for the end of March 2012.

Fitchburg – Management Audit – As a result of its investigation of Fitchburg’s preparation for, and response to, the December 2008 ice storm, the MDPU ordered a comprehensive independent management audit of Fitchburg’s management practices. The management audit, which was performed by Jacobs Consultancy, Inc. (Jacobs), was completed and the audit report was submitted by Jacobs to the MDPU on April 13, 2011. The audit report found Unitil’s management practices to be comprehensive, sound and in-line with industry practice. It also included sixteen recommendations intended to further improve the results of Unitil’s management strategy, and acknowledged that many of these recommendations were already being implemented by the Company. On September 1, 2011 the MDPU issued its Order with respect to the audit, accepting the majority of Jacob’s audit report, and requiring the company to implement the remaining recommendations, as well as provide biannual status updates as to the company’s implementation progress. On September 30, 2011, the company filed its first implementation status report with the MDPU.

Fitchburg – Electric Operations – On November 24, 2010, Fitchburg submitted its annual reconciliation of costs and revenues for Transition and Transmission under its restructuring plan (the Annual Reconciliation Filing). In addition, the Standard Offer Service and Default Service Costs incurred during the seven year Standard Offer Service period that ended February 28, 2005 have been combined and recovery continues through a Transition Charge Surcharge of $0.00400 per kWh. Changes to the Pension/PBOP Adjustment, Residential Assistance Adjustment Factor, and Net Metering Recovery Surcharge were proposed in other proceedings. The rates were approved effective January 1, 2011, subject to reconciliation pending investigation by the MDPU. This matter remains pending. A final order on Fitchburg’s 2009 Annual Reconciliation Filing also remains pending.

Fitchburg – Gas Operations – On November 2, 2009 the MDPU issued an order finding that Fitchburg engaged in certain price stabilization practices for the 2007 / 2008 and 2008 / 2009 heating seasons without the MDPU’s prior approval and that Fitchburg’s gas purchasing practices were imprudent. As a result, the MDPU required Fitchburg to refund $4.6 million of natural gas costs, plus an appropriate carrying charge based on the prime lending rate, to its gas customers. The Company recorded a pre-tax charge of $4.9 million in the fourth quarter of 2009 based on the MDPU’s order. On November 30, 2009, the MDPU approved Fitchburg’s proposal to amortize its refund of natural gas costs to customers over a five-year period. Fitchburg has appealed to the Massachusetts Supreme Judicial Court (SJC) and is seeking to reverse and vacate the MDPU’s order. Fitchburg believes that its gas-procurement practices were consistent with those of other Massachusetts natural gas distribution companies and all relevant MDPU rules and orders and Massachusetts law. The appeal has been fully briefed and oral argument before the SJC was held on September 7, 2011. A decision from the SJC is anticipated by the end of the year.

Fitchburg – Other – On July 2, 2008, the Governor of Massachusetts signed into law “The Green Communities Act” (the GC Act), an energy policy statute designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs. Several regulatory proceedings have been initiated to implement various provisions of the GC Act, including provisions for each distribution company to file enhanced three-year energy efficiency investment plans, plans to establish smart grid pilot programs, proposals to purchase long-term contracts for renewable energy, special tariffs to allow the net metering of customer-owned renewable generation, and terms and conditions for purchasing supplier receivables. Three year energy efficiency investment plans, plans to establish smart grid pilot programs, and net metering tariffs have been approved by the MDPU. On June 16, 2011, the MDPU issued its final order with respect to the terms and conditions for purchasing supplier receivables (POR). Under POR, the electric distribution companies purchase the billing accounts receivable of competitive suppliers operating in their service territories.

On January 26, 2011, the MDPU issued orders with respect to Fitchburg’s 2008 and 2009 Service Quality Reports for its electric division. Fitchburg failed to meet certain of its service quality benchmarks in 2008, and a penalty of $100,478 was ordered to be refunded to its electric customers. The Company refunded this amount to customers in their June and July 2011 billings. For 2009 performance, no net penalty was assessed. As required by the Order, on February 16, 2011 Fitchburg filed a report regarding the actions it has taken to improve its performance in the metrics it had not met.

On March 1, 2011, Fitchburg submitted its 2010 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. The filing remains pending before the MDPU.

Unitil Energy – Other – In July 2008, the State of New Hampshire enacted legislation that allows electric utilities to make investments in distributed energy resources, including energy efficiency and demand reduction technologies, as well as clean cogeneration and renewable generation. On August 5, 2009 Unitil Energy filed a plan for approval of investment in and rate recovery for Distributed Energy Resources (DER). An order approving a settlement agreement for a time-of-use pilot program was issued on February 26, 2010. On June 11, 2010, the NHPUC issued an order on the remaining two proposed projects and cost recovery. The NHPUC denied one of the two projects, citing that the costs outweighed the benefits but found the other project to be in the public interest. On November 1, 2010 Unitil Energy filed adjustments to base distribution rates to collect actual costs associated with authorized DER projects. The first step adjustment was approved and became effective on April 1, 2011.

Unitil Energy – Billing – In August 2011, the Company and one of its larger customers in New Hampshire settled a lawsuit filed by the customer in June 2011 regarding a billing error that resulted from a transformer connected to the customer’s meter, which had been mislabeled by the manufacturer, and caused the Company 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 (Distribution and Other Delivery Charges - $0.5 million; Supply Charges - $1.3 million). As a result of the settlement, the Company reimbursed the customer $1.8 million plus $0.3 million of interest. The Company recognized non-recurring charges of $0.3 million and $0.4 million for distribution charges plus interest in the three and nine months ended September 30, 2011, respectively.

As a result of this metering issue, which was discovered in February 2011, certain other customers in the Company’s service territory were underbilled from October 2004 through January 2011 for supply charges. Accordingly, the Company has requested authorization from the NHPUC to process the billing correction. The Company’s request remains pending before the NHPUC. See additional discussion on this matter below in “Legal Proceedings.”

Northern Utilities – Other – On November 21, 2008, the MPUC issued an order approving a settlement agreement resolving a number of Notices of Probable Violation (NOPVs) of certain safety related procedures and rules by Northern Utilities. Under the Settlement, Northern Utilities will incur total expenditures of approximately $3.8 million for safety related improvements to Northern Utilities’ distribution system to ensure compliance with the relevant state and federal gas safety laws, for which no rate recovery will be allowed. These compliance costs were accrued by Northern Utilities prior to the

acquisition date and the remaining amount on the Company’s unaudited consolidated balance sheet at September 30, 2011 was $0.8 million.

On June 27, 2008 the MPUC opened an investigation of Northern Utilities’ cast iron pipe replacement activities and the benefits of an accelerated replacement program for cast iron distribution pipe remaining in portions of Northern Utilities’ Maine service areas. In an order issued on July 30, 2010, the MPUC approved a Settlement Agreement resolving this matter, filed on behalf of Northern Utilities, the Maine Office of the Public Advocate, and several state legislator intervenors, which was filed with the MPUC on July 6, 2010. Under the Agreement, Northern Utilities is proceeding 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. Under the Agreement, the parties agreed to support a cost recovery mechanism that will provide for the timely recovery of prudently-incurred costs of the Program. The features of this cost recovery mechanism will be finalized during Northern Utilities’ current base rate case proceeding, which is underway, as described above.

Northern Utilities – Maine Sales Tax Under-Collection – As part of a routine internal financial review related to 2010, it was determined that during the conversion of the Northern Utilities customer portfolio from the prior owner to Unitil’s customer information system, a portion of Northern Utilities’ commercial and industrial customers were incorrectly converted as exempt from Maine sales tax. As a result, the Company did not bill and collect sales tax from those customers as of the conversion of the customer portfolio in July 2009. The Company promptly contacted the Maine Revenue Service (MRS) to advise them of the error. A Settlement Agreement between Northern Utilities and MRS was executed on January 31, 2011. Among other things, the Settlement Agreement allowed the Company time to amend all sales tax returns for all relevant periods affected by the sales tax conversion error provided that at the time amended returns were filed that the Company would pay all additional sales tax due plus interest. The Settlement Agreement also provided a waiver from the MRS of any civil penalties for failure to pay such sales taxes at the time when they were due. Accordingly, on May 26, 2011, Northern filed amend sales tax returns and paid sales tax due of $1.0 million to the MRS pursuant to the settlement agreement. Pursuant to state law, the tax shortfall is a debt of the customer to the utility and the Company has a right to recover the sales tax from customers. On June 2, 2011, the Company reached agreement with the MPUC concerning the methodology and procedure by which customers who were incorrectly converted as exempt from Maine sales tax would be billed for their sales tax arrears. The billing and collection of the tax arrears began in June 2011 and the Company has collected substantially all of the arrears as a result of the collection effort.

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 territory 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.

A civil suit was filed against Unitil Energy on June 20, 2011 in Rockingham County Superior Court in Brentwood, New Hampshire, captioned The Riverwoods Company at Exeter v. Unitil Energy Systems, Inc. The suit alleged damage claims for negligence, breach of contract and violation of the New Hampshire Consumer Protection Act, RSA chapter 358-A. Riverwoods sought recovery of $1.2 million, representing its claim for the balance of overpayments incurred as a result of a billing error, as well as interest, fees and costs, and double or treble damages pursuant to RSA chapter 358-A. On August 29, 2011, the Company and the customer settled the pending lawsuit. The Company paid the customer an additional $1.5 million, consisting of the remaining amount of overcharges plus interest. The lawsuit has been withdrawn. The dispute which was the subject matter of this action is also the subject of a petition filed by Unitil Energy with the NHPUC, and which is described more fully above in “Regulatory Matters.”

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 6 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2010 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 3, 2011.

The Company’s past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in compliance with applicable environmental and safety laws and regulations, and the Company believes that as of September 30, 2011, 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 increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Included in Environmental Obligations on the Company’s unaudited Consolidated Balance Sheet at September 30, 2011 are accrued liabilities totaling $12.0 million related to estimated future cleanup costs for permanent remediation of a former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. 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 September 30, 2011 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 $0.1 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at September 30, 2011 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.

NOTE 8: INCOME TAXES

The Company bills its customers 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.

The Company filed its tax returns for the year ended December 31, 2010 with the Internal Revenue Service (IRS) in September 2011. As a result, the Company generated net operating loss (NOL) carryforwards for income tax purposes of $9.5 million. In total for tax periods ended before December 31, 2010, the Company had generated Federal NOL carryforward deductions for income tax purposes of $4.3 million to offset against taxes payable in future periods. If unused, the Company’s NOL carryforward

deductions will expire in 2029 and 2030. In addition, at December 31, 2010, the Company had $1.4 million of Alternative Minimum Tax (AMT) credit carryforwards to offset future AMT indefinitely.

In its Federal income tax return filings for the year ended December 31, 2009, the Company recognized NOL carrybacks against its Federal taxable income for the years ended December 31, 2004, 2005, and 2007 in the amounts of $1.1 million, $12.8 million, and $9.6 million, respectively. The carryback of the 2009 NOL resulted in current tax refunds of $7.5 million, which were received in 2011.

According to Internal Revenue Code (IRC) 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 is under examination by the IRS. The IRS is currently performing fieldwork as part of their audit procedures. Currently, the Company believes that the ultimate resolution of this examination will not result in a material adverse effect to the Company’s financial position or results of operations. 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.

On March 3, 2011 the Company received notice of approval from the Joint Committee regarding the settlement between the Company and the IRS for tax years ending December 31, 2006, December 31, 2007, and December 31, 2008, which were previously under examination. As a result of the settlement, in November 2010, the Company paid $1.7 million and $0.2 million in taxes and interest, respectively, principally for certain timing items deducted in previous years which were subsequently deducted in the 2009 Federal income tax returns.

The Company evaluated its tax positions at December 31, 2010 and for the current interim reporting period ended September 30, 2011 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, 2010; December 31, 2009; December 31, 2008; and December 31, 2007.

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 10 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2010 as filed with the SEC on February 3, 2011 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:


	2011			2010
Used to Determine Plan Costs
Discount Rate		5.35	%		5.75	%
Rate of Compensation Increase		3.50	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%
Health Care Cost Trend Rate Assumed for Next Year		7.00	%		7.50	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2011			2010			2011			2010			2011		2010
Service Cost	$	735		$	653		$	479		$	366		$	71	$	71
Interest Cost		1,171			1,114			570			504			57		56
Expected Return on Plan Assets		(1,210	)		(1,045	)		(204	)		(150	)		—		—
Prior Service Cost Amortization		62			63			432			395			3		—
Transition Obligation Amortization		—			—			5			5			—		—
Actuarial Loss Amortization		783			601			—			—			19		34

Sub-total		1,541			1,386			1,282			1,120			150		161
Amounts Capitalized and Deferred		(128	)		(522	)		(248	)		(231	)		—		—

Net Periodic Benefit Cost Recognized	$	1,413		$	864		$	1,034		$	889		$	150	$	161


	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,	2011			2010			2011			2010			2011		2010
Service Cost	$	2,206		$	1,957		$	1,438		$	1,099		$	214	$	213
Interest Cost		3,513			3,343			1,709			1,512			170		170
Expected Return on Plan Assets		(3,630	)		(3,136	)		(613	)		(449	)		—		—
Prior Service Cost Amortization		187			190			1,296			1,184			8		2
Transition Obligation Amortization		—			—			16			16			—		—
Actuarial Loss Amortization		2,349			1,804			—			—			59		100

Sub-total		4,625			4,158			3,846			3,362			451		485
Amounts Capitalized and Deferred		(1,309	)		(1,625	)		(882	)		(818	)		—		—

Net Periodic Benefit Cost Recognized	$	3,316		$	2,533		$	2,964		$	2,544		$	451	$	485

Employer Contributions

The Company has made $8.8 million of contributions to the Pension Plan in 2011. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan in 2011 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 September 30, 2011, the Company had made $40,000 of contributions to the SERP Plan in 2011. The Company presently anticipates contributing an additional $13,000 to the SERP Plan in 2011.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Market 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 September 30, 2011. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2011 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 Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

Item 1A.

Risk Factors

There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2010 as filed with the SEC on February 3, 2011.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

There were no sales of unregistered equity securities by the Company for the fiscal period ended September 30, 2011.

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on March 24, 2011, the Company will periodically repurchase shares of its Common Stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. There is no pool or maximum number of shares related to these purchases; however, the trading plan will terminate when $224,500 in value of shares have been purchased or, if sooner, on March 24, 2012.

The Company may suspend or terminate this 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.

The Company’s repurchases are shown in the table below for the monthly periods noted:


Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
7/1/11 – 7/31/11		—		—		—
8/1/11 – 8/31/11		—		—		—
9/1/11 – 9/30/11		194	$	26.21		194

Total		194	$	26.21		194

Item 5.

Other Information

On October 27, 2011, the Company issued a press release announcing its results of operations for the three- and nine-month periods ended September 30, 2011. 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
11	Computation in Support of Earnings Per Weighted 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 October 27, 2011 Announcing Earnings For the Quarter Ended September 30, 2011.	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: October 27, 2011		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: October 27, 2011		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer

EXHIBIT INDEX


Exhibit No.	Description of Exhibit	Reference
11	Computation in Support of Earnings Per Weighted 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 October 27, 2011 Announcing Earnings For the Quarter Ended September 30, 2011.	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