UNITIL CORP - FORM 10-Q - October 26, 2010

UNITIL CORP - FORM 10-Q - October 26, 2010

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UNITIL CORP Reports

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EX-11 - COMPUTATION IN SUPPORT OF EARNINGS PER WEIGHTED AVERAGE COMMON SHARE - UNITIL CORP	dex11.htm
EX-99.1 - UNITIL CORPORATION PRESS RELEASE DATED OCTOBER 25, 2010 - UNITIL CORP	dex991.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 302 - UNITIL CORP	dex312.htm
EX-31.3 - CERTIFICATION OF CAO PURSUANT TO SECTION 302 - UNITIL CORP	dex313.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 302 - UNITIL CORP	dex311.htm
EX-32.1 - CERTIFICATION OF CEO, CFO AND CAO PURSUANT TO SECTION 906 - UNITIL CORP	dex321.htm

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, 2010

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 ¨ 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 22, 2010
Common Stock, No par value		10,881,062 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2010

Table of Contents


		Page No.
Part I. Financial Information

Item 1.	Financial Statements		18

	Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2010 and 2009		18

	Consolidated Balance Sheets, September 30, 2010, September 30, 2009 and December 31, 2009		19-20

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2010 and 2009		21

	Notes to Consolidated Financial Statements		22-36

Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations		2-17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36

Item 4.	Controls and Procedures		36

Item 4T.	Controls and Procedures		Inapplicable

Part II. Other Information

Item 1.	Legal Proceedings		36

Item 1A.	Risk Factors		36

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

Item 3.	Defaults Upon Senior Securities		Inapplicable

Item 4.	Submission of Matters to a Vote of Security Holders		Inapplicable

Item 5.	Other Information		37

Item 6.	Exhibits		37

Signatures			38

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), an interstate 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 southeastern seacoast and state capital regions of New Hampshire;

ii)

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

iii)

Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area.

Unitil Energy, Fitchburg and Northern Utilities are collectively referred to as the “distribution utilities.” Together, the distribution utilities serve approximately 100,500 electric customers and 70,000 natural gas customers in their service territory.

In addition, Unitil is the parent company of Granite, a natural gas inter-state transmission pipeline, regulated by the FERC, operating 87 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite provides Northern Utilities with interconnection to three major natural gas pipelines and access to pipeline supplies.

The distribution utilities are local “pipes and wires” operating companies and Unitil had an investment in Net Utility Plant of $463.6 million at September 30, 2010. 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.

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 consulting services to large commercial and industrial customers 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

Base Rate Cases:

On April 15, 2010, Unitil Energy filed a proposed annual base rate increase of $10.1 million with the New Hampshire Public Utilities Commission (NHPUC), which represents an increase of 6.5 percent above present rates. Unitil Energy’s filing also included a long-term rate plan establishing base rate step adjustments associated with future planned capital additions and targeted reliability enhancement and vegetation management programs. In its rate filing, Unitil Energy requested that rates initially be set at a lower level on a temporary basis.

On June 29, 2010, the NHPUC issued an order approving a temporary rate increase for Unitil Energy. The order provides for a temporary rate increase of $5.2 million (annual) effective July 1, 2010 which will be collected by applying a uniform per kilowatt-hour (kWh) surcharge of $0.00438 to each of Unitil Energy’s current rate schedules. Of the $5.2 million rate increase, $500,000 of the increase is intended to permit Unitil Energy to annually recover expenses incurred during the December 2008 ice storm and another $500,000 of the increase is intended to fund higher planned vegetation management program expenditures. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were ordered, July 1, 2010. Final review and approval by the NHPUC of Unitil Energy’s permanent base rate increase request is currently scheduled to be completed by February 2011.

On June 29, 2010, Granite filed for an initial proposed base transportation rate increase with the FERC, which is Granite’s first filing for a rate change since its last general rate case in 1997. If approved as filed, the initial rate increase would provide for an increase of approximately $2.3 million in revenue on an annual basis. In addition to its request for new base transportation rates, Granite, in its rate case filing, is seeking approval to implement a capital cost surcharge that would allow Granite to implement a rate surcharge annually to recover certain projected capital expenditures in future periods. Granite expects the FERC regulatory process to result in an effective date of January 1, 2011 for the requested rate increase.

Additionally, Fitchburg and Northern Utilities are currently preparing base rate cases and anticipate completing them with their respective state regulatory commissions within the next twelve months.

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 Massachusetts Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and the Maine Public Utilities Commission (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 traditional cost of service regulation. Under this regulatory structure, Unitil’s distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in New Hampshire, Massachusetts and Maine, Unitil’s customers have the opportunity to purchase their electricity or natural gas supplies from third party 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 10, 2010.

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 ability to achieve the estimated potential synergy savings attributable to the Acquisitions;

•

The Company’s ability to retain existing customers and gain new customers;

•

Variations in weather;

•

Major storms;

•

Recovery of deferred major storm costs;

•

Recovery of energy commodity costs;

•

Changes in the regulatory environment;

•

Customers’ preferences on energy sources;

•

Interest rate fluctuation and credit market concerns;

•

General economic conditions that could have an adverse impact on the availability of credit and liquidity resources generally and could jeopardize certain of our counterparty obligations, including those of our insurers and financial institutions;

•

Fluctuations in supply, demand, transmission capacity and prices for energy commodities;

•

Increased competition; and

•

Customers’ performance under multi-year energy brokering contracts.

Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not

possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2010 and September 30, 2009 and should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Part I, Item 1 of this report.

Between December 2008 and June 2009 the Company issued 5.0 million common shares to complete the Acquisitions. As a result of the Acquisitions and the issuance of new common shares, consolidated results for the Company in the current period may not be directly comparable to prior period results until such time as the Acquisitions and stock issuance is fully reflected in both reporting periods. Also, the Company’s results are expected to reflect the seasonal nature of the acquired natural gas businesses. Accordingly, the Company expects that results of operations will be positively affected during the first and fourth quarters, when sales of natural gas are typically higher, and negatively affected during the second and third quarters, when gas operating and maintenance expenses usually exceed sales margins in the period.

Earnings Overview

The Company’s Earnings (Loss) Applicable to Common Shareholders was a net loss of ($0.1) million for the third quarter of 2010, an improvement of $0.5 million compared to the third quarter of 2009. For the nine months ended September 30, 2010, the Company reported net income of $4.3 million compared to $8.7 million for the same period of 2009. Results for the third quarter were driven primarily by higher electric sales margins reflecting favorable summer weather and higher rates, partially offset by increases in operating and interest costs.

Earnings (loss) per common share (EPS) were ($0.01) and $0.40 for the three and nine month periods ended September 30, 2010 compared with ($0.06) and $0.94 for the same periods of 2009. The Company’s results of operations for 2010 are not directly comparable with 2009 due to the issuance of 5.0 million common shares between December 2008 and June 2009 to complete the financing of the Company’s acquisitions of Northern Utilities and Granite.

Natural gas sales margin was unchanged in the third quarter of 2010 compared to the same period in 2009. For the nine month period ended September 30, 2010, gas sales margin was $3.8 million lower compared to the same period in 2009. Total natural gas therm sales were 2.7% and 5.5% lower in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. Lower gas therm sales in the Company’s utility service territories reflect the effect of warmer winter temperatures earlier in 2010, where there were approximately 13% fewer Heating Degree Days in the nine month period, compared to the prior year.

Electric sales margin increased $2.4 million and $2.5 million in the three and nine months ended September 30, 2010 compared to the same periods in 2009, reflecting higher electric kilowatt-hour (kWh) sales and an electric rate increase implemented in July 2010 for the Company’s New Hampshire electric distribution utility. Total kWh sales increased 11.1% and 4.9% in the three and nine months ended September 30, 2010, respectively, compared to the same periods in 2009 reflecting increased sales to all customer groups. The increased sales reflect above average summer temperatures in the Company’s utility service territories in 2010. According to ISO-New England, the grid operator for the New England region, July was the second-hottest July in New England since 1960 and New England’s all-time electricity consumption for one month was recorded in that month.

Operation and Maintenance (O&M) expenses increased $1.1 million and $2.5 million for the three and nine months ended September 30, 2010, respectively, compared to 2009. The changes in O&M expenses reflect higher utility operating costs and professional fees. Utility operating expenses reflect the full integration of Northern Utilities and Granite into the Company’s consolidated operating results.

Depreciation and Amortization expense decreased $0.4 million and increased $1.1 million in the three and nine months ended September 30, 2010, respectively, compared to the same periods in 2009, reflecting higher depreciation on normal utility plant additions partially offset by lower amortization expense in the current year.

Interest Expense, Net increased $0.7 million and $1.0 million in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. In March 2010, Unitil Energy and Northern Utilities collectively issued $40 million of long-term debt which is contributing to the higher interest expense in the three and nine month periods.

Federal and State Income Taxes decreased by $2.1 million for the nine month period due to lower pre-tax income in 2010 compared to 2009.

All other expenses increased $0.3 million and $0.8 million in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009, primarily reflecting higher property and payroll taxes.

Usource, our non-regulated energy brokering business, recorded revenues of $1.2 million and $3.4 million in the three and nine month periods ended September 30, 2010, respectively, increases of $0.2 million and $0.2 million, respectively compared to the same periods of 2009. 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.

Additionally, EPS for the nine months ended September 30, 2010 reflects a higher number of average shares outstanding year over year, as discussed above.

In 2009, 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, 2010, March, 2010, June 2010 and September 2010 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, 2010 and a period-to-period comparison of changes in financial position are presented below.

Gas Sales, Revenues and Margin

Therm Sales – Total natural gas therm sales were 2.7% and 5.5% lower in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. Lower gas therm sales in the Company’s utility service territories reflect the effect of milder winter temperatures earlier in 2010, where there were approximately 13% fewer Heating Degree Days in the nine month period, compared to the prior year.

The following table details total firm therm sales for the three and nine months ended September 30, 2010 and 2009, by major customer class:


Therm Sales (millions)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2010	2009	Change		% Change		2010	2009	Change		% Change
Residential	2.5	2.9	(0.4	)	(13.8	%)	26.9	29.1	(2.2	)	(7.6	%)
Commercial / Industrial	19.3	19.5	(0.2	)	(1.0	%)	100.9	106.1	(5.2	)	(4.9	%)

Total	21.8	22.4	(0.6	)	(2.7	%)	127.8	135.2	(7.4	)	(5.5	%)

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, 2010 and 2009:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010		2009		$ Change		% Change⁽¹⁾			2010		2009		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	6.7	$	5.7	$	1.0		6.6	%	$	42.5	$	45.9	$	(3.4	)		(3.1	%)
Commercial / Industrial		10.7		9.5		1.2		7.9	%		59.7		65.1		(5.4	)		(4.8	%)

Total Gas Operating Revenue	$	17.4	$	15.2	$	2.2		14.5	%	$	102.2	$	111.0	$	(8.8	)		(7.9	%)

Cost of Gas Sales:
Purchased Gas	$	8.9	$	6.9	$	2.0		13.2	%	$	61.5	$	67.1	$	(5.6	)		(5.0	%)
Conservation & Load Management		0.6		0.4		0.2		1.3	%		2.2		1.6		0.6			0.5	%

Total Cost of Gas Sales	$	9.5	$	7.3	$	2.2		14.5	%	$	63.7	$	68.7	$	(5.0	)		(4.5	%)

Gas Sales Margin	$	7.9	$	7.9	$	—		—		$	38.5	$	42.3	$	(3.8	)		(3.4	%)

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

Total Gas Operating Revenues increased $2.2 million, or 14.5%, and decreased $8.8 million, or 7.9%, in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. Total Gas Operating Revenues include the recovery of the approved cost 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 2010 reflects higher Purchased Gas revenues of $2.0 million and higher C&LM revenues of $0.2 million. The decrease in Total Gas Operating Revenues in the first nine months of 2010 reflects lower Purchased Gas revenues of $5.6 million and lower gas sales margin of $3.8 million, partially offset by higher C&LM revenues of $0.6 million.

The Purchased Gas and C&LM components of Gas Operating Revenues increased a combined $2.2 million, or 14.5%, of Total Gas Operating Revenue and decreased a combined $5.0 million, or 4.5%, of Total Gas Operating Revenue in the three and nine month periods ended September 30, 2010 compared to the same periods in 2009. The increase in the third quarter of 2010 is due to higher natural gas commodity costs and increased spending on energy efficiency and conservation programs, partially offset by lower natural gas sales. The decrease in the nine month period of 2010 primarily reflects lower sales of natural gas, partially offset by increased spending on energy efficiency and conservation programs. The Company recovers the cost of Purchased Gas and C&LM in its rates at cost on a pass through basis.

Natural gas sales margin was unchanged in the third quarter of 2010 compared to the same period in 2009. For the nine month period ended September 30, 2010, gas sales margin was $3.8 million lower compared to the same period in 2009. The decrease in the nine month period principally reflects lower sales of natural gas, which reflect the effect of the milder winter heating season.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Total electric kWh sales increased 11.1% and 4.9% in the three and nine months ended September 30, 2010, respectively, compared to the same periods in 2009 reflecting increased sales to all customer groups. The increased sales reflect higher than average summer temperatures in the Company’s utility service territories in 2010 where there were approximately 61% more Cooling

Degree Days in the three month period ended September 30, 2010, compared to the prior year. According to ISO-New England, the grid operator for the New England region, July was the second-hottest July in New England since 1960 and New England’s all-time electricity consumption for one month was recorded in that month.

The following table details total kWh sales for the three and nine months ended September 30, 2010 and 2009 by major customer class:


kWh Sales (millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010		2009		Change		% Change			2010		2009		Change		% Change
Residential		198.7		172.1		26.6		15.5	%		524.7		493.8		30.9		6.3	%
Commercial / Industrial		284.6		263.0		21.6		8.2	%		767.9		738.2		29.6		4.0	%

Total		483.3		435.1		48.2		11.1	%		1,292.6		1,232.1		60.5		4.9	%

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, 2010 and 2009:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010		2009		$ Change		% Change⁽¹⁾			2010		2009		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	31.0	$	27.9	$	3.1		5.7	%	$	82.9	$	84.3	$	(1.4	)		(0.9	%)
Commercial / Industrial		26.5		26.3		0.2		0.4	%		72.0		79.0		(7.0	)		(4.3	%)

Total Electric Operating Revenue	$	57.5	$	54.2	$	3.3		6.1	%	$	154.9	$	163.3	$	(8.4	)		(5.2	%)

Cost of Electric Sales:
Purchased Electricity	$	39.6	$	38.9	$	0.7		1.3	%	$	107.1	$	119.5	$	(12.4	)		(7.6	%)
Conservation & Load Management		1.0		0.8		0.2		0.4	%		3.6		2.1		1.5			0.9	%

Total Cost of Electric Sales	$	40.6	$	39.7	$	0.9		1.7	%	$	110.7	$	121.6	$	(10.9	)		(6.7	%)

Electric Sales Margin	$	16.9	$	14.5	$	2.4		4.4	%	$	44.2	$	41.7	$	2.5			1.5	%

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

Total Electric Operating Revenue, increased by $3.3 million, or 6.1%, and decreased by $8.4 million, or 5.2%, in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. Total Electric Operating Revenues include the recovery of the approved cost of electric sales, which are recorded as Purchased Electricity and C&LM in Operating Expenses. The increase in Total Electric Operating Revenues in the third quarter of 2010 reflects higher Purchased Electricity revenues of $0.7 million, higher C&LM revenues of $0.2 million and higher electric sales margin of $2.4 million. The decrease in Total Electric Operating Revenues in the first nine months of 2010 reflects lower Purchased Electricity revenues of $12.4 million, partially offset by higher C&LM revenues of $1.5 million and higher electric sales margin of $2.5 million.

The Purchased Electricity and C&LM components of Total Electric Operating Revenues increased a combined $0.9 million, or 1.7%, and decreased a combined $10.9 million, or 6.7%, of Total Electric Operating Revenues in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. The increase in the three month period primarily reflects higher kWh sales in the current period. The decrease in the nine month period primarily reflects an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower electric commodity costs, partially offset by higher spending on energy efficiency and conservation programs and increased sales. The Company recovers the cost of Purchased Electricity and C&LM in its rates at cost on a pass through basis.

Operating Revenue - Other

The following table details total Other Revenue for the three and nine months ended September 30, 2010 and 2009:


Other Revenue (000’s)
	Three Months Ended September 30,									Nine Months Ended September 30,
	2010		2009		$ Change		% Change			2010		2009		$ Change		% Change
Other	$	1.2	$	1.0	$	0.2		20.0	%	$	3.4	$	3.2	$	0.2		6.3	%

Total Other Revenue	$	1.2	$	1.0	$	0.2		20.0	%	$	3.4	$	3.2	$	0.2		6.3	%

Total Other Revenue increased $0.2 million, or 20.0%, and $0.2 million, or 6.3%, in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. Other Revenues represents revenues from the Company’s non-regulated energy brokering business, Usource.

Operating Expenses

Purchased Gas – Purchased Gas expenses include the cost of gas purchased and manufactured to supply the Company’s total gas supply requirements. Purchased Gas increased $2.0 million, or 29.0%, and decreased $5.6 million, or 8.4%, in the three and nine months ended September 30, 2010, respectively, compared to the same periods in 2009. The increase in the third quarter of 2010 is due to higher natural gas commodity costs partially offset by lower sales of natural gas. The decrease in the nine month period of 2010 primarily reflects lower sales of natural gas. 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 of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. Purchased Electricity increased $0.7 million, or 1.8%, and decreased $12.4 million, or 10.4%, in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. The increase in the three month period primarily reflects increased sales in the current period. The decrease in the nine month period primarily reflects an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower electric commodity costs, 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 $1.1 million, or 9.2%, and $2.5 million, or 7.3%, for the three and nine months ended September 30, 2010, respectively, compared to the same periods in 2009. The changes in O&M expenses reflect higher utility operating costs and professional fees. Utility operating costs primarily consist of compensation and benefit costs, utility distribution and transmission system maintenance costs, bad debt expenses, office expenses and insurance costs. O&M expenses reflect the full integration of Northern Utilities and Granite State into the Company’s consolidated operating results.

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 60% of these costs are related to electric operations and 40% to gas operations.

Total C&LM expenses increased $0.4 million, or 33.3% and $2.1 million, or 56.8%, in the three and nine month periods ended September 30, 2010 compared to the same periods in 2009. 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 decreased $0.4 million, or 6.1%, and increased $1.1 million, or 5.7% in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009, reflecting higher depreciation on normal utility plant additions partially offset by lower amortization expense in the current year.

Local Property and Other Taxes – Local Property and Other Taxes increased $0.3 million and $0.7 million in the three and nine month periods ended September 30, 2010, respectively, compared to the same periods in 2009. These increases reflect higher local property tax rates on higher levels of utility plant in service and higher payroll taxes on higher compensation expenses.

Federal and State Income Taxes – Federal and State Income Taxes were higher by $0.4 million in the three month period ended September 30, 2010 compared to the same period in 2009 reflecting higher pre-tax earnings in the current period. For the nine month period ended September 30, 2010, Federal and State Income Taxes were lower by $2.1 million compared to the same period in 2009 reflecting lower pre-tax earnings in the current period.

Other Non-Operating Expenses (Income)

Other Non-Operating Expenses were on par in the three month period ended September 30, 2010 compared to the same period in 2009 and increased by $0.1 million in the nine month period ended September 30, 2010 compared to the same period in 2009.

Interest Expense, Net

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

Unitil’s utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an

under-collected or an over-collected balance of costs. In accordance with the distribution utilities’ rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. Consistent with regulatory precedent, interest income is recorded on an under-collection of costs which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.


Interest Expense, Net (Millions)	Three Months Ended September 30,									Nine Months Ended September 30,
		2010			2009			Change			2010			2009			Change
Interest Expense
Long-term Debt	$	5.1		$	4.5		$	0.6		$	14.9		$	13.7		$	1.2
Short-term Debt		0.3			0.5			(0.2	)		1.1			1.6			(0.5	)
Regulatory Liabilities		0.1			0.1			—			0.2			0.2			—

Subtotal Interest Expense		5.5			5.1			0.4			16.2			15.5			0.7

Interest (Income)
Regulatory Assets		(0.6	)		(0.6	)		—			(2.3	)		(1.9	)		(0.4	)
AFUDC⁽¹⁾ and Other		(0.2	)		(0.5	)		0.3			(0.4	)		(1.1	)		0.7

Subtotal Interest (Income)		(0.8	)		(1.1	)		0.3			(2.7	)		(3.0	)		0.3

Total Interest Expense, Net	$	4.7		$	4.0		$	0.7		$	13.5		$	12.5		$	1.0

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

On March 2, 2010, Unitil Energy completed the sale of $15 million of First Mortgage Bonds through a private placement to institutional investors. The First Mortgage Bonds have a maturity of ten years and a coupon rate of 5.24%. The Company used the proceeds from this long-term financing to repay short-term debt and for general corporate purposes.

On March 2, 2010, Northern Utilities completed the sale of $25 million of Senior Unsecured Notes through a private placement to institutional investors. The Senior Unsecured Notes have a maturity of ten years and a coupon rate of 5.29%. The Company used the proceeds from this long-term financing to repay short-term debt and for general corporate purposes.

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 facility with a group of banks that extends to October 8, 2013. The borrowing limit under the revolving credit facility is $80.0 million. There was $46.3 million and $64.5 million in short-term debt outstanding through bank borrowings under the revolving credit facility at September 30, 2010 and December 31, 2009, respectively. The total amount of credit available under the Company’s revolving credit facility was $33.7 million and $15.5 million at September 30, 2010 and December 31, 2009, 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, 2010, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

On October 8, 2010, the Company entered into the Fourth Amendment Agreement with Bank of America, N.A., as administrative agent, and a syndicate of other lenders party thereto (the “Fourth Amendment Agreement”), further amending the credit agreement dated as of November 26, 2008 among Unitil, Bank of America, N.A., as administrative agent, and a syndicate of other lenders party thereto. The credit agreement was previously amended on January 2, 2009, March 16, 2009, and October 13, 2009 to, among other things, increase the maximum borrowings under the facility to $80.0 million. The Fourth Amendment Agreement extends the scheduled termination date of the credit agreement to October 8, 2013 and provides for two conditional one-year extensions subsequent to the October 8, 2013 termination date (if agreed to among the lenders and Unitil). The Fourth Amendment Agreement also provides the Company a mechanism to request an increase in maximum borrowings of $20.0 million (in increments of not less than $5.0 million). The Fourth Amendment Agreement also provides a new letter of credit sub-facility pursuant to which up to $25.0 million of the credit agreement may be used for the purpose of issuing letters of credit for Unitil or its subsidiaries. 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 $12.3 million, $7.6 million and $10.0 million outstanding at September 30, 2010, September 30, 2009 and December 31, 2009, respectively, related to these asset management agreements.

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 limit these guarantees to two years or less. As of September 30, 2010 there are $34.5 million of guarantees outstanding and the longest of these guarantees extends through February 29, 2012. Of this amount, $12.0 million is related to Unitil’s guarantee of payment for the term of the Northern Utilities’ gas storage agreement discussed above.

The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite. As of September 30, 2010, the principal amount outstanding for the 8% Unitil Realty notes was $4.0 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 notes due 2018. As of September 30, 2010, the principal amount outstanding for the 7.15% Granite 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, 2010 compared to the same period in 2009.


		Nine Months Ended September 30,
		2010		2009
Cash Provided by Operating Activities	$	21.5	$	45.4

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $21.5 million for the first nine months of 2010 compared to $45.4 million in the same period of 2009. In the first nine months of 2010 as compared to the first nine months of 2009, net sources of cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes decreased by $9.3 million, changes in working capital items decreased $30.0 million, and changes in all other Operating Activities increased $15.4 million. A portion of the $30.0 million decrease in changes in working capital items resulted from a decrease in sources of cash from gas inventory of $19.4 million driven by changes in natural gas prices. The Company finances its gas inventory requirements with asset management agreements (see Credit Arrangements in Note 4), and reflects this activity in Cash Provided by Financing Activities.


	Nine Months Ended September 30,
	2010			2009
Cash (Used in) Investing Activities	$	(33.8	)	$	(49.8	)

Cash (Used in) Investing Activities – Cash (Used in) Investing Activities was ($33.8) million for the nine months ended September 30, 2010 compared to ($49.8) million for the same period in 2009. In the first nine months of 2010, the Company recorded ($1.3) million in capital expenditures related to the February 2010 wind storm. Capital spending in the same period of 2009 included ($8.2) million related to the December 2008 ice storm and ($6.8) million of acquisition costs related to the acquisitions of Northern Utilities and Granite. All other remaining capital spending is representative of normal distribution utility capital expenditures and was ($32.5) million in the first nine months of 2010 compared to ($34.8) million compared to the same period of 2009. Capital expenditures are projected to be approximately ($55.0) million for 2010 and ($60.0) million for 2011, reflecting normal electric and gas utility system additions.


	Nine Months Ended September 30,
	2010		2009
Cash Provided by Financing Activities	$	12.6	$	1.9

Cash Provided by Financing Activities – Cash Provided by Financing Activities was $12.6 million for the nine months ended September 30, 2010 compared to $1.9 million for the same period in 2009. In March 2010, Unitil Energy and Northern Utilities closed long-term debt financings of $15.0 million and $25.0 million, respectively. The net proceeds of $39.7 million from these financings were used to

refinance short-term borrowings. Short-term borrowings were reduced by ($18.2) million in the first nine months of 2010. Other uses of cash include ($11.3) million for quarterly dividend payments compared to ($9.4) million for the same period in 2009. Proceeds from issuances of common stock and gas inventory financing provided a source of cash of $0.7 million and $2.3 million, respectively. All other uses of cash were ($0.6) 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 10, 2010.

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, the Company’s natural gas transmission pipeline, is regulated by the FERC. Accordingly, the Company uses the Regulated Operations guidance as set forth in the FASB Codification. The Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


Regulatory Assets consist of the following (millions)

	September 30,				December 31,
	2010		2009		2009
Energy Supply Contract Obligations	$	24.3	$	38.1	$	34.7
Deferred Restructuring Costs		25.8		27.7		28.3
Generation-related Assets		—		0.2		—

Subtotal – Restructuring Related Items		50.1		66.0		63.0
Retirement Benefit Obligations		43.6		46.3		43.7
Income Taxes		13.2		15.1		14.5
Environmental Obligations		20.6		21.4		22.7
Deferred Storm Charges		21.0		14.1		14.6
Other		10.1		8.2		7.9

Total Regulatory Assets	$	158.6	$	171.1	$	166.4
Less: Current Portion of Regulatory Assets⁽¹⁾		16.6		20.5		21.9

Regulatory Assets – noncurrent	$	142.0	$	150.6	$	144.5

⁽¹⁾	Reflects amounts included in Accrued Revenue on the Company’s 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 – Regulated utility revenues 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.

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

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

The 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 years ended December 31, 2009 and 2008, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $300,000 and $200,000, respectively, in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2009 and 2008, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $735,000 and $675,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $576,000 and $531,000, respectively. See Note 9 to the accompanying Consolidated Financial Statements.

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. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s consolidated balance sheets.

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, 2010, 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, 2010, the Company and its subsidiaries had 437 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

As of September 30, 2010, 150 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 discreet 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, 2010 and September 30, 2009 were 2.32% and 2.05%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2010 and September 30, 2009 were 2.30% and 3.82%, 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,
	2010			2009			2010		2009
Operating Revenues
Gas	$	17.4		$	15.2		$	102.2	$	111.0
Electric		57.5			54.2			154.9		163.3
Other		1.2			1.0			3.4		3.2

Total Operating Revenues		76.1			70.4			260.5		277.5

Operating Expenses
Purchased Gas		8.9			6.9			61.5		67.1
Purchased Electricity		39.6			38.9			107.1		119.5
Operation and Maintenance		13.1			12.0			36.9		34.4
Conservation & Load Management		1.6			1.2			5.8		3.7
Depreciation and Amortization		6.2			6.6			20.4		19.3
Provisions (Benefit) for Taxes:
Local Property and Other		2.7			2.4			8.3		7.6
Federal and State Income		(0.6	)		(1.0	)		2.3		4.4

Total Operating Expenses		71.5			67.0			242.3		256.0

Operating Income		4.6			3.4			18.2		21.5
Non-Operating Expenses (Income)		—			—			0.3		0.2

Income Before Interest Expense		4.6			3.4			17.9		21.3
Interest Expense, Net		4.7			4.0			13.5		12.5

Net Income (Loss)		(0.1	)		(0.6	)		4.4		8.8
Less: Dividends on Preferred Stock		—			—			0.1		0.1

Earnings (Loss) Applicable to Common Shareholders	$	(0.1	)	$	(0.6	)	$	4.3	$	8.7


Weighted Average Common Shares Outstanding – Basic (000’s)		10,830			10,767			10,817		9,267
Weighted Average Common Shares Outstanding – Diluted (000’s)		10,830			10,767			10,818		9,267
Earnings Per Common Share (Basic and Diluted)	$	(0.01	)	$	(0.06	)	$	0.40	$	0.94
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,
	2010		2009		2009
ASSETS:

Utility Plant:
Electric	$	313.5	$	300.0	$	302.3
Gas		348.5		316.9		325.5
Common		30.4		28.8		28.9
Construction Work in Progress		18.9		19.6		26.0

Total Utility Plant		711.3		665.3		682.7
Less: Accumulated Depreciation		247.7		227.4		233.0

Net Utility Plant		463.6		437.9		449.7

Current Assets:
Cash		8.0		9.0		7.7
Accounts Receivable – Net of Allowance for Doubtful Accounts of $2.6, $2.4 and $2.5		27.2		27.2		33.5
Accrued Revenue		35.7		34.0		44.0
Gas Inventory		15.9		13.8		14.3
Materials and Supplies		3.3		2.9		2.6
Prepayments and Other		3.0		8.3		4.7

Total Current Assets		93.1		95.2		106.8

Noncurrent Assets:
Regulatory Assets		142.0		150.6		144.5
Other Noncurrent Assets		26.3		27.5		24.2

Total Noncurrent Assets		168.3		178.1		168.7

TOTAL ASSETS	$	725.0	$	711.2	$	725.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)

(UNAUDITED)


	September 30,				December 31,
	2010		2009		2009
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	183.5	$	191.6	$	193.1
Preferred Stock		2.0		2.0		2.0
Long-Term Debt, Less Current Portion		288.5		249.0		248.9

Total Capitalization		474.0		442.6		444.0

Current Liabilities:
Long-Term Debt, Current Portion		0.5		0.4		0.4
Accounts Payable		16.0		18.6		25.1
Short-Term Debt		46.3		54.0		64.5
Energy Supply Contract Obligations		23.0		21.4		23.1
Other Current Liabilities		24.2		25.0		16.6

Total Current Liabilities		110.0		119.4		129.7

Deferred Income Taxes		37.2		38.2		39.8

Noncurrent Liabilities:
Energy Supply Contract Obligations		13.6		24.3		21.7
Retirement Benefit Obligations		67.2		69.2		65.5
Environmental Obligations		14.2		10.9		14.3
Other Noncurrent Liabilities		8.8		6.6		10.2

Total Noncurrent Liabilities		103.8		111.0		111.7

TOTAL CAPITALIZATION AND LIABILITIES	$	725.0	$	711.2	$	725.2

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Nine Months Ended September 30,
	2010			2009
Operating Activities:
Net Income	$	4.4		$	8.8
Adjustments to Reconcile Net Income to Cash
Provided by Operating Activities:
Depreciation and Amortization		20.4			19.3
Deferred Tax Provision		(0.9	)		5.1
Changes in Working Capital Items:
Accounts Receivable		6.3			12.5
Accrued Revenue		8.3			22.9
Gas Inventory		(1.6	)		17.8
Accounts Payable		(9.1	)		(9.9	)
Other Changes in Working Capital Items		1.2			(8.2	)
Deferred Regulatory and Other Charges		(4.0	)		(14.3	)
Other, net		(3.5	)		(8.6	)

Cash Provided by Operating Activities		21.5			45.4


Investing Activities:
Property, Plant and Equipment Additions		(33.8	)		(43.0	)
Acquisition Costs		—			(6.8	)

Cash (Used in) Investing Activities		(33.8	)		(49.8	)


Financing Activities:
Repayment of Short-Term Debt		(18.2	)		(20.1	)
Proceeds From Issuance (Repayment of) Long-Term Debt, net		39.7			(0.3	)
Net Increase (Decrease) in Gas Inventory Financing		2.3			(24.2	)
Dividends Paid		(11.3	)		(9.4	)
Proceeds from Issuance of Common Stock, net		0.7			56.2
Other, net		(0.6	)		(0.3	)

Cash Provided by Financing Activities		12.6			1.9

Net Increase (Decrease) in Cash		0.3			(2.5	)
Cash at Beginning of Period		7.7			11.5

Cash at End of Period	$	8.0		$	9.0


Supplemental Cash Flow Information:
Interest Paid	$	12.5		$	11.6
Income Taxes Paid	$	1.0		$	0.6

(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), 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.

On December 1, 2008, the Company purchased: (i) all of the outstanding capital stock of Northern Utilities, a natural gas distribution utility serving customers in Maine and New Hampshire, from Bay State Gas Company (Bay State) and (ii) all of the outstanding capital stock of Granite, an interstate gas transmission pipeline company primarily serving the needs of Northern Utilities, from NiSource, Inc. (NiSource) pursuant to the Stock Purchase agreement dated as of February 15, 2008 by and among NiSource, Bay State, and Unitil (the “Acquisitions”). The final purchase price allocation is disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 as filed with the Securities and Exchange Commission on February 10, 2010.

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 is a natural gas transportation pipeline, operating 87 miles of underground gas transmission pipeline primarily located in Maine, New Hampshire and Massachusetts. Granite 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 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 is a wholly-owned subsidiary of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.

Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all

adjustments considered necessary for a fair presentation have been included. The results of operations for the three and nine months ended September 30, 2010 are not necessarily indicative of results to be expected for the year ending December 31, 2010. 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, 2009, as filed with the Securities and Exchange Commission (SEC) on February 10, 2010, for a description of the Company’s Basis of Presentation.

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

As of September 30, 2010, September 30, 2009 and December 31, 2009, the Company had 1.3 billion, 2.1 billion and 1.9 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, as of:
			Fair Value
Description	Balance Sheet Location		September 30, 2010		September 30, 2009		December 31, 2009
Natural Gas Futures Contracts		Other Current Liabilities	$	1.7	$	3.6	$	2.2

Natural Gas Futures Contracts		Other Noncurrent Liabilities		0.3		—		0.1

Total			$	2.0	$	3.6	$	2.3


	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010		2009
Amount of (Gain) / Loss Recognized in Regulatory Assets for Derivatives:
Natural Gas Futures Contracts	$	0.7	$	(1.9	)	$	3.6	$	3.7
Amount of Loss Reclassified into Consolidated Statements of Earnings⁽¹⁾:
Purchased Gas	$	—	$	—		$	3.9	$	5.8

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

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.

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

Recently Issued Pronouncements – There are no recently issued pronouncements that the Company has not already adopted.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
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

09/23/09	11/16/09	11/02/09	$0.345
06/18/09	08/14/09	07/31/09	$0.345
03/26/09	05/15/09	05/01/09	$0.345
01/15/09	02/16/09	02/02/09	$0.345

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

Common Stock

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

On September 10, 2008, the Company’s shareholders, at a Special Meeting of Shareholders, approved an increase in the number of 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 8,000,000 shares to 16,000,000 shares in the aggregate. The Company had 10,879,741, 10,827,061 and 10,836,759 of common shares outstanding at September 30, 2010, September 30, 2009 and December 31, 2009, respectively.

Unitil Corporation Common Stock Offering – Between December 2008 and June 2009, the Company sold 4,970,000 shares of its common stock at a price of $20.00 per share in registered public offerings. The Company used the net proceeds of $93.1 million from these offerings primarily to complete the acquisitions of Northern Utilities and Granite. Please see Note 3 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2009 as filed with the SEC on February 10, 2010 for additional information.

Dividend Reinvestment and Stock Purchase Plan – During the first nine months of 2010, the Company sold 30,934 shares of its Common Stock, at an average price of $21.68 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans, resulting in net proceeds of approximately $671,000.

During the first nine months of 2009, the Company sold 33,184 shares of its Common Stock, at an average price of $20.88 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans, resulting in net proceeds of approximately $693,000.

Restricted Stock Plan – The Company maintains a Restricted Stock Plan (the Plan) which has been ratified and approved by the Company’s shareholders. On February 5, 2010, 12,520 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $262,920. There were 33,608 and 40,153 non-vested shares under the Plan as of September 30, 2010 and 2009, respectively. The weighted average grant date fair value of these shares was $21.92 and $22.87, respectively. The compensation expense associated with the issuance of shares under the Plan is being recognized over the vesting period and was $0.4 million and $0.4 million for the nine months ended September 30, 2010 and 2009, respectively. At September 30, 2010, there was approximately $0.9 million of total unrecognized compensation cost under the Plan which is expected to be recognized over approximately 2.5 years. There were 472 restricted shares forfeited under the Plan during the nine months ended September 30, 2010. There were no cancellations under the Plan during the nine months ended September 30, 2010.

Preferred Stock

Details on preferred stock at September 30, 2010, September 30, 2009 and December 31, 2009 are shown below:

(Amounts in Millions)


	September 30,				December 31,
	2010		2009		2009
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

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

Long-Term Debt

Details on long-term debt at September 30, 2010, September 30, 2009 and December 31, 2009 are shown below ($ Millions):


	September 30,				December 31,
	2010		2009		2009
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		—		—
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		—		—
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		4.0		4.4		4.3

Total Long-Term Debt		289.0		249.4		249.3
Less: Current Portion		0.5		0.4		0.4

Total Long-term Debt, Less Current Portion	$	288.5	$	249.0	$	248.9

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, 2010 is estimated to be approximately $329 million, before considering any costs, including prepayment costs, which generally require a “make-whole” payment, 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, 2010, the Company had $46.3 million 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 is $80.0 million. The total amount of credit available under the Company’s revolving credit facility at September 30, 2010 was $33.7 million. 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, 2010, the Company was in compliance with the financial covenants contained in the revolving credit agreement.

Guarantees

The Company also provides limited guarantees on certain energy and natural gas storage management contracts entered into by the three distribution utilities. The Company’s policy is to limit these guarantees to two years or less. As of September 30, 2010 there are $34.5 million of guarantees outstanding and the longest of these guarantees extends through October 31, 2011. Of this amount, $12.0 million is related to Unitil’s guarantee of payment for the term of the Northern Utilities’ gas storage agreement discussed above.

2018. As of September 30, 2010, the principal amount outstanding for the 7.15% Granite notes was $10.0 million. This guarantee will terminate if Granite reorganizes and merges with and into Northern Utilities.

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2010 and September 30, 2009 (Millions):


Three Months Ended September 30, 2010	Electric		Gas			Other			Non- Regulated		Total
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

Three Months Ended September 30, 2009
Revenues	$	54.2	$	15.2		$	—		$	1.0	$	70.4
Segment Profit (Loss)		1.9		(2.9	)		—			0.4		(0.6	)
Capital Expenditures		6.1		10.1			0.7			—		16.9

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		356.8		356.6			6.9			4.7		725.0

Nine Months Ended September 30, 2009
Revenues	$	163.3	$	111.0		$	—		$	3.2	$	277.5
Segment Profit (Loss)		3.2		4.2			0.1			1.2		8.7
Capital Expenditures		21.2		21.0			0.8			—		43.0
Segment Assets		348.5		352.6			8.0			2.1		711.2

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED MORE FULLY IN NOTE 7 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2009 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 10, 2010.

Legal Proceedings

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 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 the fall of 2011. The Company continues to believe the suit is without merit, and will defend itself vigorously.

Regulatory Matters

Unitil Energy Rate Case Filing – On April 15, 2010, Unitil Energy filed a proposed base rate increase of $10.1 million, an increase of 6.5 percent above present rates. In addition, Unitil Energy requested adjustments for a Rate Year Step Adjustment, a Large Capital Project Step Adjustment and a long-term rate plan establishing step adjustments associated with the Company’s Reliability Enhancement Plan and Vegetation Management Plan. On June 29, 2010, the NHPUC issued an order approving a temporary rate increase for Unitil Energy of $5.2 million (annual) effective July 1, 2010 which is being collected by a uniform per kilowatt-hour (kWh) surcharge of $0.00438 on each of Unitil Energy’s current rate schedules. Of the $5.2 million rate increase, $500,000 of the increase is intended to permit Unitil Energy to annually recover expenses incurred during the December 2008 ice storm and another $500,000 of the increase is intended to fund higher planned vegetation management program expenditures. Once permanent rates are approved by the NHPUC, they will be reconciled to the date temporary rates were ordered, July 1, 2010. Final review and approval by the NHPUC of Unitil Energy’s permanent base rate increase request is scheduled to be completed by February 2011.

Major Ice Storm – On December 11 and 12, 2008, a severe ice storm (December 2008 Ice Storm) struck the New England region. The Company spent approximately $23.3 million for the repair and replacement of electric distribution systems damaged during the storm, including $8.3 million related to capital construction and $15.0 million, including carrying charges, which has been deferred as a regulatory asset, based on orders issued by the MDPU and NHPUC, discussed below. Also, the Company expensed $3.0 million for professional fees related to the ice storm, in addition to normal anticipated expenditures related to emergency storm preparedness. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations. However, if it were ultimately determined that certain of these costs were not recoverable in rates, and/or the Company were required to incur additional costs to defend itself, there may be a significant impact on the Company’s results of operations in future periods.

The MDPU conducted an investigation of Fitchburg’s preparation for and response to the December 2008 Ice Storm during the first half of 2009. On November 2, 2009, the MDPU issued its order with respect to its investigation, finding that Fitchburg’s preparation for, and response to, the December 2008 Ice Storm constituted a failure of the Company to meet its public service obligation to provide safe and reliable service, and ordered several remedial actions. First, the MDPU ordered a comprehensive independent management audit of Fitchburg’s management practices. The management audit, which will be performed by Jacobs Consultancy Inc., will begin in the fourth quarter of 2010. Second, the MDPU directed Fitchburg to implement a series of operational and capital improvements which had been identified and recommended through the Company’s self-assessment review. All of these operational and capital improvements have either been completed or are currently underway, and remain subject to MDPU review. Finally, the MDPU noted that the costs incurred by Fitchburg for the December 2008 Ice Storm would be subject to review in Fitchburg’s next electric rate case, along with Fitchburg’s rate of return.

On December 30, 2009, the MDPU approved Fitchburg’s petition to defer and record as a regulatory asset costs associated with the repair of its electric distribution system from damage caused by the December 2008 Ice Storm for future recovery in rates. The order of approval made no findings as to whether the subject expenses were reasonable or whether they can be recovered from ratepayers, and confirmed that the MDPU will consider the subsequent ratemaking treatment of the expense as part of Fitchburg’s next rate case. As of September 30, 2010, Fitchburg has deferred approximately $13.0 million, including carrying charges, associated with the repair of its electric distribution system for future recovery in rates.

On November 9, 2009, the NHPUC granted Unitil Energy’s petition to defer and record as a regulatory asset costs associated with electric distribution system damage from the December 2008 Ice Storm until such time as the Commission issues a final order in Unitil Energy’s pending base rate case. The Order clarified that the issues of the appropriate amount of the storm related expenses to be recovered, the

timing and manner of recovery, and what, if any, return should be applied to the unrecovered balance are to be reviewed in the rate case. As of September 30, 2010, Unitil Energy has deferred approximately $2.0 million, including carrying charges, associated with the repair of its electric distribution system for future recovery in rates.

On January 8, 2010, the NHPUC opened a docket to consider Unitil Energy’s response to the December 2008 Ice Storm, including the timing of its response, its restoration priorities and strategies and the procurement and allocation of its resources in New Hampshire and Massachusetts. On September 24, 2010, the NHPUC issued its final order in this matter and closed its investigation, accepting the NHPUC Staff’s Report finding that UES had acted reasonably.

Fitchburg – Electric Operations – On November 25, 2009, Fitchburg submitted to the MDPU its annual (2009) reconciliation of costs and revenues for Transition and Transmission under its restructuring plan (the Annual Reconciliation Filing). The rates were approved effective January 1, 2010, subject to reconciliation pending further investigation by the MDPU. This matter remains pending. A final order approving Fitchburg’s 2008 Annual Reconciliation Filing was issued on April 12, 2010.

On November 12, 2009, the Governor of Massachusetts signed House Bill 4329. The bill (i) requires the MDPU to establish regulations for utilities to respond to emergencies, (ii) requires utilities to file with the MDPU annual emergency response plans, (iii) authorizes the MDPU to impose penalties for a utility’s failure to comply with the MDPU’s regulations, and (iv) allows the chair of the MDPU to issue operational and management directives during an emergency. The bill also authorizes the Massachusetts Attorney General to bring a court action for receivership of a small investor-owned utility where an emergency exists and the utility has materially violated the MDPU’s standards for responding to emergencies. On February 2, 2010, the MDPU issued an order adopting regulations concerning the items required by House Bill 4329. Fitchburg has complied with the requirements concerning the filing of its emergency response plans and has met with MDPU Staff to review them. On July 30, 2010, the MDPU approved Fitchburg’s electric and gas Emergency Response Plans.

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 the gas procurement order to the Massachusetts Supreme Judicial Court. 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. This appeal remains pending before the Massachusetts Supreme Judicial Court. Immediately after the MDPU opened its investigation of this matter in March 2009, Fitchburg ceased making the gas procurement purchases in question and filed a request with the MDPU for approval of a gas procurement plan for future gas purchases. This matter remains pending before the MDPU.

Fitchburg – Other – On July 16, 2008, the MDPU issued an order establishing a comprehensive plan for Revenue Decoupling to be adopted by gas and electric distribution utilities on a going-forward basis, through company-specific rate cases. Revenue decoupling is generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utility’s distribution revenues on sales, and is intended to remove the disincentive a utility has to promote efforts to reduce energy consumption by its customers or to facilitate installation of distributed generation to displace electricity delivered by the utility. It is anticipated that, with limited exceptions, all distribution companies will be operating under decoupling plans by year-end 2012.

On February 11, 2009, the Massachusetts Supreme Judicial Court (SJC) issued its decision in the Attorney General’s (AG) appeal of the MDPU orders relating to Fitchburg’s recovery of bad debt expense. The SJC agreed with the AG that the MDPU was required to hold hearings regarding changes in Fitchburg’s tariff and rates, and on that basis vacated the MDPU orders. The Court, however, declined to

rule on an appropriate remedy, and remanded the cases back to the MDPU for consideration of that issue. This matter remains pending before the MDPU.

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

On March 1, 2010, Fitchburg submitted its annual filing to the MDPU of the 2009 Service Quality Reports for its gas division. On October 20, 2010, the MDPU issued its Order on the 2009 Service Quality Reports of the Massachusetts local gas distribution utilities and noted that Fitchburg met or exceeded its established benchmarks in all Service Quality penalty measures. Fitchburg’s Service Quality performance was consistent with the MDPU’s Service Quality Guidelines and Fitchburg’s respective Service Quality plan.

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. 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. Unitil Energy plans to file adjustments to base distribution rates to collect actual costs associated with authorized DER projects.

On February 25, 2010, a significant wind storm struck portions of the New England region, causing extensive damage to electric facilities and loss of service to significant numbers of customers of several utilities. An estimated one million electric customers in the region were affected, including approximately 85% of the Company’s customers. Unitil Energy was able to restore power to 96% percent of its customers by day three, and its final customers, including those with individual service problems, were restored by day four. The Company spent approximately $7.3 million for the repair and replacement of electric distribution systems damaged during the storm, including $1.3 million related to capital construction and $6.0 million which has been deferred as a regulatory asset. Unitil Energy, in its base rate case filing discussed above, has requested recovery in rates for the costs associated with the emergency repair of its electric distribution system for damage caused by this storm. The amount and timing of the cost recovery of the storm restoration expenditures will be determined in the base rate case proceeding. The Company does not believe these storm restoration expenditures and the timing of cost recovery will have a material adverse impact on the Company’s financial condition or results of operations. However, if it were ultimately determined that certain of these costs were not recoverable in rates, and/or the Company were required to incur additional costs to defend itself, there may be a significant impact on the Company’s results of operations in future periods.

On June 17, 2010, Unitil Energy made its annual reconciliation and rate filing with the NHPUC under its restructuring plan, for rates effective August 1, 2010, including reconciliation of prior year costs and revenues. On July 30, 2010, the NHPUC approved the rate filing and reconciliation.

Northern Utilities – 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’s 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 balance sheet at September 30, 2010 was $0.7 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. An Agreement resolving this matter, filed on behalf of Northern Utilities, the Maine Office of the Public Advocate, and several state legislator intervenors, was filed with the MPUC on July 6, 2010. Under the Agreement, Northern Utilities will proceed with a comprehensive upgrade and replacement program (the “Program”), which will provide for the systematic replacement of cast iron, wrought iron and bare steel pipe in Northern Utilities’ natural gas distribution system in Portland and Westbrook, Maine and the conversion of the system to intermediate pressure. The Agreement establishes the objective of completing the Program by the end of the 2024 construction season. 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’ next base rate case proceeding, which is anticipated to be filed in early 2011. On July 30, 2010, the MPUC issued its Final Order approving the Settlement Agreement.

Granite State Gas Transmission, Inc. – Base Rate Case Filing – On June 29, 2010, Granite filed a base transportation rate increase which would provide for an initial increase of approximately $2.3 million in annual revenue with the FERC. This represents Granite’s first filing for a rate change since its last general rate case in 1997. The effect of this initial rate increase would result in an approximate increase of two percent in the total annual bill to an average residential natural gas heating customer served by Northern Utilities. In addition to its request for new base transportation rates, Granite is seeking FERC approval to implement a capital cost surcharge that would allow Granite to implement a rate surcharge annually to recover certain projected capital expenditures in future periods. On July 30, 2010, the FERC ordered the rate increase to be effective on January 1, 2011, subject to refund and hearing and settlement procedures that are in progress.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED MORE FULLY IN NOTE 7 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2009 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 10, 2010.

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, 2010, 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 Consolidated Balance Sheet at September 30, 2010 are accrued liabilities totaling $12.0 million related to estimated future clean up 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. Also included in Environmental Obligations on the Company’s Consolidated Balance Sheet at September 30, 2010 are accrued liabilities totaling $2.3 million associated with Northern Utilities’ environmental remediation obligations for former MGP sites. In addition to the amounts noted above, there are $0.2 million of accrued liabilities in Other Current Liabilities on the Company’s Consolidated Balance Sheet at September 30, 2010 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 Consolidated Statements of Earnings.

The Company evaluated its tax positions at December 31, 2009 and for the current interim reporting period ended September 30, 2010 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 classifies penalty and interest expense related to income tax liabilities as an income tax expense. There are no material interest and penalties recognized in the statement of earnings or accrued on the balance sheet.

During the third quarter of 2010, the Company changed its method of tax accounting for certain construction-related costs previously capitalized as depreciable assets, to accounting for those expenditures as repairs expense deductions under Sections 162 and 263(a) of the Internal Revenue Code. In applying the new tax accounting method, certain costs which were previously capitalized and recognized as depreciation deductions over various useful lives for tax accounting purposes are now to be deducted in the year incurred. The Company applied the change retroactively for additional deductions of $20.4 million related to the tax accounting method change in its 2009 federal and state returns.

The Company remains subject to examination by Federal, Massachusetts and New Hampshire tax authorities for the tax periods ended December 31, 2006; December 31, 2007; and December 31, 2008. Income tax filings for the year ended December 31, 2009 were filed with the Internal Revenue Service (IRS) in September 2010. In its Federal Income Tax return filings for the year ended December 31, 2008, the Company recognized net operating loss (NOL) carrybacks against its Federal Income Tax returns for the years ended December 31, 2006 and 2007 in the amounts of $5.0 million and $6.7 million, respectively. These NOL carrybacks resulted in a refund to the Company of $4.0 million which was received in November 2009. According to Internal Revenue Code rules, NOL refunds in excess of $2.0 million fall under the jurisdiction of the Joint Committee of Congress (Joint Committee) and are subject to review by the IRS and attorneys of the Joint Committee. As a result, on December 30, 2009, the Company received notice that its Federal Income Tax return filings for the years ended December 31, 2006, December 31, 2007, and December 31, 2008 are 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.

NOTE 9: RETIREMENT BENEFIT OBLIGATIONS

The Company co-sponsors the Unitil Corporation Retirement Plan (Pension Plan), the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan), and the Unitil Corporation Supplemental Executive Retirement Plan (SERP) to provide certain pension and postretirement benefits for its retirees and current employees. Please see Note 9 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2009 as filed with the SEC on February 10, 2010 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:


	2010			2009
Used to Determine Plan Costs
Discount Rate		5.75	%		6.25	%
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		7.50	%		8.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached		2017			2017

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


	Pension Plan						PBOP Plan						SERP
Three Months Ended September 30,	2010			2009			2010			2009			2010		2009
Service Cost	$	653		$	571		$	366		$	357		$	71	$	54
Interest Cost		1,114			1,073			504			578			56		46
Expected Return on Plan Assets		(1,045	)		(1,108	)		(150	)		(89	)		—		—
Prior Service Cost Amortization		63			66			395			428			—		—
Transition Obligation Amortization		—			—			5			5			—		—
Actuarial Loss Amortization		601			399			—			—			34		17

Sub-total		1,386			1,001			1,120			1,279			161		117
Amounts Capitalized and Deferred		(522	)		(388	)		(231	)		(486	)		—		—

Net Periodic Benefit Cost Recognized	$	864		$	613		$	889		$	793		$	161	$	117


	Pension Plan						PBOP Plan						SERP
Nine Months Ended September 30,	2010			2009			2010			2009			2010		2009
Service Cost	$	1,957		$	1,713		$	1,099		$	1,071		$	213	$	162
Interest Cost		3,343			3,220			1,512			1,735			170		136
Expected Return on Plan Assets		(3,136	)		(3,324	)		(449	)		(267	)		—		—
Prior Service Cost Amortization		190			198			1,184			1,284			2		(1	)
Transition Obligation Amortization		—			—			16			15			—		—
Actuarial Loss Amortization		1,804			1,197			—			—			100		53

Sub-total		4,158			3,004			3,362			3,838			485		350
Amounts Capitalized and Deferred		(1,625	)		(1,034	)		(818	)		(1,286	)		—		—

Net Periodic Benefit Cost Recognized	$	2,533		$	1,970		$	2,544		$	2,552		$	485	$	350

Employer Contributions

On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA were new minimum funding rules which went into effect for plan years beginning in 2008. The funding target was 100% of a plan’s liability (as determined under the PPA) with any shortfall amortized over

seven years, with lower (92%—100%) funding targets available to well-funded plans during the transition period. Due to the significant declines in the valuation of capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum funding rules set forth in the PPA such that all plans, except those that were subject to deficit reduction contribution requirements in 2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the 2008—2010 plan years. This did not affect the Company’s Pension Plan in 2009 as its Pension Plan was 94% funded under the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) as of January 1, 2008 and met the exemption from the shortfall amortization. As of September 30, 2010, the Company had made $3.7 million of contributions to the Pension Plan in 2010. The Company presently anticipates contributing an additional $0.6 million to fund its Pension Plan in 2010.

As of September 30, 2010, the Company had made $2.6 million and $40,000 of contributions to the PBOP and SERP Plans, respectively, in 2010. The Company presently anticipates contributing an additional $0.9 million and $13,000 to the PBOP and SERP Plans, respectively, in 2010.

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, 2010. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of September 30, 2010 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, 2009 as filed with the SEC on February 10, 2010.

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, 2010.

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 25, 2010, 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 automatically terminate when $80,700 in value of shares have been purchased, or, if sooner, on March 25, 2011.

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
7/1/10 – 7/31/10		—		—		—
8/1/10 – 8/31/10		—		—		—
9/1/10 – 9/30/10		218	$	21.50		218

Total		218	$	21.50		218

Item 5.

Other Information

On October 25, 2010, the Company issued a press release announcing its results of operations for the three- and nine-month periods ended September 30, 2010. 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 25, 2010 Announcing Earnings For the Quarter Ended September 30, 2010.	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 26, 2010				/s/ Mark H. Collin
				Mark H. Collin
				Chief Financial Officer

Date: October 26, 2010				/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 25, 2010 Announcing Earnings For the Quarter Ended September 30, 2010.		Filed herewith

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