Edgar Filing: UNITIL CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended September 30, 2007

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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨

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

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


Class		Outstanding at October 25, 2007
Common Stock, No par value		5,730,869 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended September 30, 2007

Table of Contents


			Page No.
Part I. Financial Information

	Item 1.	Financial Statements

		Consolidated Statements of Earnings - Three and Nine Months Ended September 30, 2007 and 2006	16

		Consolidated Balance Sheets, September 30, 2007, September 30, 2006 and December 31, 2006	17-18

		Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2007 and 2006	19

		Notes to Consolidated Financial Statements	20-29

	Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	2-15

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

	Item 4.	Controls and Procedures	29

	Item 4T.	Controls and Procedures	Inapplicable

Part II. Other Information

	Item 1.	Legal Proceedings	29

	Item 1A.	Risk Factors	29

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30

	Item 3.	Defaults Upon Senior Securities	Inapplicable

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

	Item 5.	Other Information	Inapplicable

	Item 6.	Exhibits	31

Signatures			32

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. Unitil’s principal business is the retail distribution of electricity and natural gas through two utility subsidiaries: Unitil Energy System’s Inc. (UES) and Fitchburg Gas and Electric Light Company (FG&E). UES is an electric utility with an operating franchise in the southeastern seacoast and capital city areas of New Hampshire. FG&E is a combination gas and electric utility with an operating franchise in the greater Fitchburg area of north central Massachusetts.

Unitil’s two retail distribution utilities serve approximately 99,400 electric customers and 15,000 natural gas customers in their franchise areas. The retail distribution companies are pure distribution utilities with a combined investment in net utility plant of $246.6 million at September 30, 2007. Substantially all of Unitil’s revenue and earnings are derived from regulated utility operations.

Unitil also conducts non-regulated operations principally through its Usource™ (Usource) subsidiary. Usource provides energy brokering and consulting services to large commercial and industrial customers in the northeastern United States. Unitil’s other subsidiaries include Unitil Service and Unitil Realty, which provide centralized facilities, management and administrative services to Unitil’s affiliated companies. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

RATES AND REGULATION

Unitil’s utility operations related to wholesale and interstate business activities are regulated by the Federal Energy Regulatory Commission (FERC). The retail distribution utilities, UES and FG&E, are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Public Utilities (MDPU), formerly the Massachusetts Department of Telecommunications and Energy, respectively, in regards to their rates, issuance of securities and other accounting and operational matters. 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 retail distribution utilities have the franchise to deliver electricity and/or natural gas to all customers in their franchise areas, at rates established under traditional cost of service regulation. Under this regulatory structure, UES and FG&E 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 the implementation of retail choice in New Hampshire and Massachusetts, Unitil’s customers are free to contract for their supply of electricity with third-party suppliers. The retail distribution utilities provide for the delivery of that supply of electricity over their distribution systems at regulated rates. Both UES and FG&E continue to provide basic or default electric supply service to those customers who do not obtain their supply from third-party suppliers, with the costs associated with electricity supplied by the Company being recovered on a pass-through basis under periodically-adjusted rates.

As a result of the introduction of retail choice for all natural gas customers in Massachusetts, FG&E’s customers are free to contract for their supply of natural gas with third-party suppliers. FG&E continues to provide natural gas supply services to those customers who do not obtain their supply from third-party suppliers. The costs associated with natural gas supplied by FG&E are recovered on a pass-through basis under periodically adjusted rates.

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 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 the following:

•

Variations in weather;

•

Changes in the regulatory environment;

•

Customers’ preferences on energy sources;

•

Interest rate fluctuation and credit market concerns;

•

General economic conditions;

•

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

•

Increased competition; and

•

Customers’ future 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. There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2006 as filed with the Securities and Exchange Commission on February 21, 2007.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended September 30, 2007 and September 30, 2006 and should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Item 1 of this report.

Earnings Overview

The Company’s Earnings Applicable to Common Shareholders (Net Income) was $1.6 million for the third quarter of 2007. Earnings per common share (EPS) were $0.28 for the three months ended September 30, 2007 compared with $0.32 in the third quarter of 2006. Earnings for the third quarter of 2007 reflect higher depreciation and interest expenses, partially offset by higher electric and gas utility sales margins and improved profits from Usource, Unitil’s non-regulated energy-brokering business. For the nine months ended September 30, EPS were $1.04 for 2007 compared to $0.93 for 2006, an increase of $0.11 per share, or 12%.

The following table presents the significant items (discussed below) contributing to the change in earnings per share in the three and nine month periods ended September 30, 2007:


2007 Earnings Per Share vs. 2006

		Period Ended September 30,
		QTD			YTD
	2006	$	0.32		$	0.93
Electric Sales Margin			0.03			0.07
Gas Sales Margin			0.02			0.16
Usource Sales Margin			0.04			0.10
Operation & Maintenance Expense			—			0.02
Depreciation, Amortization & Other			(0.09	)		(0.14	)
Interest Expense, Net			(0.04	)		(0.10	)

	2007	$	0.28		$	1.04

Unitil’s total electric kilowatt (kWh) sales decreased 3.9% and 1.4% in the three and nine month periods ended September 30, 2007, respectively compared to the same periods in 2006. The lower kWh sales in 2007 compared to 2006 were primarily driven by cooler summer weather this year and energy conservation by our residential and commercial and industrial (C&I) customers. Electric kWh sales to residential customers in the three and nine month periods ended September 30, 2007 decreased 4.7% and 1.1%, respectively, compared to the same periods in 2006 while sales to C&I customers decreased 3.3% and 1.5% in those periods compared to the same periods in 2006. Natural gas sales in the three and nine month periods ended September 30, 2007 increased 6.1% and 8.0%, respectively, compared to the same periods in 2006. The increase in gas sales in 2007 reflects a colder winter heating season this year and higher natural gas sales to C&I customers.

Electric sales margin increased $0.3 million and $0.7 million in the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The improvement in electric sales margin primarily reflects additional step rate increases approved and implemented in the last half of 2006 and the first half of 2007 in New Hampshire, partially offset by lower electric kWh sales volumes.

Natural gas sales margin increased $0.2 million and $1.6 million in the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006 primarily reflecting higher sales to commercial and industrial customers and new natural gas distribution rates approved and implemented in early 2007.

Usource increased revenues by $0.4 million and $1.0 million in the three and nine month periods ended September 30, 2007, increases of 67% and 56% respectively, over the comparable 2006 periods.

Total O&M expenses were flat for the three month period ended September 30, 2007 compared to the same period in 2006. For the nine month period ended September 30, 2007, total O&M expenses decreased $0.2 million compared to the same period in 2006. This decrease reflects lower Distribution Utility labor and operating expenses of $0.5 million in 2007 as the Company is realizing savings as a result of its recent significant investments in Automated Metering Infrastructure (AMI) improvements; as well as lower outside services expenses of $0.2 million, and lower bad debt expenses of $0.1 million and all other operating expenses of $0.3 million. These lower O&M costs were partially offset by higher retiree and employee benefit costs of $0.5 million and higher salaries and compensation expenses of $0.4 million in 2007.

Depreciation, Amortization, Taxes & Other expenses increased $0.7 million and $1.8 million in the three and nine month periods ended September 30, 2007 compared to the same periods in 2006 reflecting higher depreciation on utility plant and income taxes on higher levels of pre-tax earnings in 2007 compared to 2006. The higher depreciation on utility plant includes depreciation expense on normal plant additions in 2007 and the recognition, in the third quarter of 2006, of a non-recurring adjustment for lower depreciation rates on utility plant established in the Company’s electric rate case settlement in New Hampshire.

Interest Expense, Net increased $0.4 million and $1.0 million in the three and nine month periods ended September 30, 2007 compared to the same periods in 2006 reflecting higher debt outstanding and higher interest rates.

Also in the third quarter, the Unitil Corporation Board of Directors declared the regular quarterly dividend on the Company’s common stock of $0.345 per share. This quarterly dividend results in a current effective annual dividend rate of $1.38 per share representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

A more detailed discussion of the Company’s results of operations for the three and nine months ended September 30, 2007 and a period-to-period comparison of changes in financial position are presented below.

Balance Sheet

Regulatory Assets increased $19.3 million as of September 30, 2007 compared to September 30, 2006, reflecting the recording of Regulatory Assets for Retirement Benefit Obligations in accordance with newly issued Federal Accounting Standards Board (FASB) Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, (SFAS No. 158) (See Note 8) and the recording of a Regulatory Asset for future environmental remediation obligations associated with the Company’s former manufactured gas plant site at Sawyer Passway, located in Fitchburg, Massachusetts (See Note 7), partially offset by a decrease related to current year cost recoveries.

Long-Term Debt increased $19.7 million as of September 30, 2007 compared to September 30, 2006, reflecting the issuance and sale on May 2, 2007 by Unitil Corporation of $20 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors, in the form of a private placement.

Deferred Income Taxes decreased $19.1 million as of September 30, 2007 compared to September 30, 2006, primarily reflecting the recording of deferred tax assets related to Retirement Benefit Obligations, discussed below.

Retirement Benefit Obligations increased $37.0 million as of September 30, 2007 compared to September 30, 2006, primarily reflecting the recording of pension, PBOP and SERP obligations in accordance with SFAS No. 158, discussed above.

Environmental Obligations increased $12.0 million as of September 30, 2007 compared to September 30, 2006, reflecting the recording of a liability for future environmental remediation obligations associated with the Company’s former manufactured gas plant site at Sawyer Passway, discussed above.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kWh sales decreased 3.9% and 1.4% in the three and nine month periods ended September 30, 2007, respectively compared to the same periods in 2006. The lower kWh sales in 2007 compared to 2006 were primarily driven by cooler summer weather this year and energy conservation by our residential and commercial and industrial (C&I) customers. Electric kWh sales to residential customers in the three and nine month periods ended September 30, 2007 decreased 4.7% and 1.1%, respectively, compared to the same periods in 2006 while sales to C&I customers decreased 3.3% and 1.5% in those periods compared to the same periods in 2006.

The following table details total kWh sales for the three and nine months ended September 30, 2007 and 2006 by major customer class:


kWh Sales (millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007	2006	Change		% Change		2007	2006	Change		% Change
Residential	179.7	188.6	(8.9	)	(4.7	%)	515.6	521.5	(5.9	)	(1.1	%)
Commercial / Industrial	285.1	294.9	(9.8	)	(3.3	%)	813.2	825.5	(12.3	)	(1.5	%)

Total	464.8	483.5	(18.7	)	(3.9	%)	1,328.8	1,347.0	(18.2	)	(1.4	%)

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, 2007 and 2006:


Electric Operating Revenues and Sales Margin (millions)

	Three Months Ended September 30,									Nine Months Ended September 30,
	2007		2006		$ Change			% Change⁽¹⁾		2007		2006		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	29.5	$	29.3	$	0.2		0.3	%	$	85.7	$	76.9	$	8.8		5.1	%
Commercial / Industrial		27.4		31.9		(4.5	)	(7.4	%)		85.6		94.1		(8.5	)	(5.0	%)

Total Electric Operating Revenue	$	56.9	$	61.2	$	(4.3	)	(7.1	%)	$	171.3	$	171.0	$	0.3		0.1	%

Cost of Electric Sales:
Purchased Electricity	$	41.9	$	46.4	$	(4.5	)	(7.4	%)	$	126.4	$	126.9	$	(0.5	)	(0.3	%)
Conservation & Load Management		0.8		0.9		(0.1	)	(0.2	%)		2.8		2.7		0.1		0.1	%

Electric Sales Margin	$	14.2	$	13.9	$	0.3		0.5	%	$	42.1	$	41.4	$	0.7		0.3	%

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

Total Electric Operating Revenues, decreased by $4.3 million, or 7.1%, and increased by $0.3 million, or 0.1%, in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation & Load Management (C&LM) in Operating Expenses. The net decrease in Total Electric Operating Revenues in the three month period reflects lower Purchased Electricity costs of $4.5 million and lower C&LM revenues of $0.1 million, partially offset by higher sales margin of $0.3 million. The net increase in Total Electric Operating Revenues in the nine month period reflects lower Purchased Electricity costs of $0.5 million offset by higher C&LM revenues of $0.1 million and higher sales margin of $0.7 million.

Purchased Electricity and C&LM revenues decreased a net $4.6 million, or 7.6%, and $0.4 million, or 0.2%, of Total Electric Operating Revenues in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006. These decreases primarily reflect an increase in the amount of electricity purchased by customers directly from third-party suppliers partially offset by higher electric commodity prices. Purchased Electricity revenues include the recovery of the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. The Company recovers the cost of Purchased Electricity and C&LM in its rates at cost on a pass through basis.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas increased 6.1% and 8.0% in the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The increase in gas sales in 2007 reflects a colder winter heating season this year and higher natural gas sales to C&I customers. Gas sales to residential customers in the three month period ended September 30, 2007 were essentially unchanged compared to the same period in 2006 and increased 2.6% in the nine month period ended September 30, 2007, compared to the same period in 2006 while sales to C&I customers increased 7.7% and 11.3% in those periods compared to the same periods in 2006.

The following table details total firm therm sales for the three and nine months ended September 30, 2007 and 2006, by major customer class:


Therm Sales (millions)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2007	2006	Change	% Change		2007	2006	Change	% Change
Residential	0.7	0.7	—	—		7.9	7.7	0.2	2.6	%
Commercial / Industrial	2.8	2.6	0.2	7.7	%	13.8	12.4	1.4	11.3	%

Total	3.5	3.3	0.2	6.1	%	21.7	20.1	1.6	8.0	%

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, 2007 and 2006:


Gas Operating Revenues and Sales Margin (millions)

	Three Months Ended September 30,									Nine Months Ended September 30,
	2007		2006		$ Change			% Change⁽¹⁾		2007		2006		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	2.3	$	2.0	$	0.3		6.8	%	$	14.7	$	13.0	$	1.7		7.0	%
Commercial / Industrial		1.6		2.4		(0.8	)	(18.2	%)		9.8		11.4		(1.6	)	(6.6	%)

Total Gas Operating Revenue	$	3.9	$	4.4	$	(0.5	)	(11.4	%)	$	24.5	$	24.4	$	0.1		0.4	%

Cost of Gas Sales:
Purchased Gas	$	2.1	$	2.8	$	(0.7	)	(15.9	%)	$	15.8	$	17.2	$	(1.4	)	(5.7	%)
Conservation & Load Management		—		—		—		—			0.1		0.2		(0.1	)	(0.4	%)

Gas Sales Margin	$	1.8	$	1.6	$	0.2		4.5	%	$	8.6	$	7.0	$	1.6		6.5	%

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

Total Gas Operating Revenues decreased $0.5 million, or 11.4%, and increased $0.1 million, or 0.4%, in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006. Total Gas Operating Revenues include the recovery of the cost of sales, which are recorded as Purchased Gas and C&LM in Operating Expenses. The net decrease in Total Gas Operating Revenues in the three month period reflects lower Purchased Gas costs of $0.7 million partially offset by higher sales margin of $0.2 million. The net increase in Total Gas Operating Revenues in the nine month period reflects higher sales margin of $1.6 million, partially offset by lower Purchased Gas costs of $1.4 million and lower C&LM revenues of $0.1 million.

Purchased Gas and C&LM revenues decreased a net $0.7 million, or 15.9%, and $1.5 million, or 6.1%, of Total Gas Operating Revenues in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006, reflecting lower natural gas commodity prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. Purchased Gas revenues include the recovery of the cost of gas supply as well as the other energy supply related costs. C&LM revenues include the recovery of the cost of 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.

Operating Revenue – Other

The following table details total Other Revenue for the three and nine months ended September 30, 2007 and 2006:


Other Revenue (000’s)

	Three Months Ended September 30,								Nine Months Ended September 30,
	2007		2006		$ Change		% Change		2007		2006		$ Change		% Change
Other	$	1.0	$	0.6	$	0.4	66.7	%	$	2.8	$	1.8	$	1.0	55.6	%

Total Other Revenue	$	1.0	$	0.6	$	0.4	66.7	%	$	2.8	$	1.8	$	1.0	55.6	%

Total Other Revenue increased $0.4 million, or 66.7%, and $1.0 million, or 55.6% in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006. These increases were the result of growth in revenues from the Company’s non-regulated energy brokering business, Usource.

Operating Expenses

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 decreased $4.5 million, or 9.7% and $0.5 million, or 0.4%, in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006. These decreases reflect lower electric kWh sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher electric commodity prices. The Company recovers the costs of Purchased Electricity in its rates at cost on a pass through basis and therefore changes in these expenses do not affect Net Income.

Purchased Gas – Purchased Gas expenses include the cost of gas purchased and manufactured to supply the Company’s total gas supply requirements. Purchased Gas decreased $0.7 million, or 25.0%, and $1.4 million, or 8.1%, in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006. These decreases in Purchased Gas are attributable to lower natural gas commodity prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. The Company recovers the costs of Purchased Gas in its rates at cost on a pass through basis and therefore changes in these expenses do not affect Net Income.

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 were flat for the three month period ended September 30, 2007 compared to the same period in 2006. For the nine month period ended September 30, 2007, total O&M expenses decreased $0.2 million compared to the same period in 2006. This decrease reflects lower Distribution Utility labor and operating expenses of $0.5 million in 2007 as the Company is realizing savings as a result of its recent significant investments in Automated Metering Infrastructure (AMI) improvements; as well as, lower outside services expenses of $0.2 million, lower bad debt expenses of $0.1 million and all other operating expenses of $0.3 million, net, partially offset by higher retiree and employee benefit costs of $0.5 million (driven by higher pension and postretirement benefit costs other than pension (PBOP) costs of $1.1 million, partially offset by lower medical and other benefit costs of $0.6 million) and higher salaries and compensation expenses of $0.4 million. The Company recovers its pension and PBOP costs through base distribution rates in New Hampshire. In Massachusetts, the Company recovers its pension and PBOP costs on a dollar for dollar basis through a recovery mechanism and therefore the revenue associated with the recovery of these costs is included in electric and gas sales margin.

Conservation & Load Management – C&LM expenses are associated with the development, management, and delivery of the Company’s Energy Efficiency programs. Energy Efficiency programs are designed, in conformity with state regulatory requirements, to help consumers use natural gas and electricity more efficiently and thereby decrease their energy costs. Programs are tailored to residential, small business and large business customer groups and provide educational materials, technical assistance, and rebates that contribute toward the cost of purchasing and installing approved measures. Approximately 90% of these costs are related to electric operations and 10% to gas operations.

Total C&LM expenses decreased $0.1 million, or 11.1% in the three month period ended September 30, 2007 compared to the same period in 2006. This change reflects the timing of spending on the implementation of Energy Efficiency programs. Total C&LM expenses for the nine month period ended September 30, 2007 were unchanged compared to the same period in 2006. These costs are collected from customers on a pass through basis and therefore, fluctuations in program costs have no impact on Net Income.

Depreciation, Amortization and Taxes

Depreciation and Amortization – Depreciation and Amortization expense increased $1.1 million, or 32.4% and $1.4 million, or 11.7% in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006 reflecting higher depreciation on utility plant. The higher depreciation on utility plant includes depreciation expense on normal plant additions in 2007 and the recognition, in the third quarter of 2006, of a non-recurring adjustment for lower depreciation rates on utility plant established in the Company’s electric rate case settlement in New Hampshire.

Local Property and Other Taxes – Local Property and Other Taxes were flat for the three and nine month periods ended September 30, 2007 compared to the same periods in 2006.

Federal and State Income Taxes – Federal and State Income Taxes were lower by $0.3 million in the three month period ended September 30, 2007 compared to the same period in 2006 reflecting lower pre-tax earnings. Federal and State Income Taxes were higher by $0.3 million in the nine month period ended September 30, 2007 compared to the same period in 2006 reflecting higher pre-tax earnings.

Other Non-operating Expenses (Income)

Other Non-operating Expenses (Income) decreased by less than $0.1 million in the three period ended September 30, 2007 compared to the same period in 2006. For the nine month period ended September 30, 2007, Other Non-operating Expenses (Income) increased by $0.1 million compared to the same period in 2006. This change reflects the recognition in 2006 of a gain on the sale of land and timber harvest revenue.

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. 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.

The Company operates 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 Company’s rate tariff, interest is accrued on these balances and will produce either interest income or interest expense. 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,
	Three Months Ended September 30,									Nine Months Ended September 30,
	2007			2006			Change			2007			2006			Change
Interest Expense
Long-term Debt	$	2.9		$	2.3		$	0.6		$	8.2		$	7.0		$	1.2
Short-term Debt		0.1			0.4			(0.3	)		0.8			1.1			(0.3	)
Regulatory Liabilities		0.1			0.1			—			0.4			0.2			0.2

Subtotal Interest Expense		3.1			2.8			0.3			9.4			8.3			1.1

Interest Income
Regulatory Assets		(0.7	)		(0.8	)		0.1			(2.2	)		(2.3	)		0.1
AFUDC and Other		(0.1	)		(0.1	)		—			(0.4	)		(0.2	)		(0.2	)

Subtotal Interest Income		(0.8	)		(0.9	)		0.1			(2.6	)		(2.5	)		(0.1	)

Total Interest Expense, Net	$	2.3		$	1.9		$	0.4		$	6.8		$	5.8		$	1.0

Interest Expense, Net increased by $0.4 million and $1.0 million in the three and nine month periods ended September 30, 2007, respectively, compared to the same periods in 2006 reflecting an increase in the average cost of debt and higher debt outstanding. Interest expense on long-term borrowings increased in both the three and nine month periods in 2007 compared to 2006 due to the issuance of new fixed rate long-term debt. On May 2, 2007, Unitil Corporation issued and sold $20 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors in the form of a private placement. The proceeds from this fixed rate long-term financing were used to refinance existing variable rate short-term debt and for general corporate purposes of the Company and its subsidiaries, including the Company’s investment in the AMI project. The higher interest costs associated with the higher levels of long-term debt are partially offset by labor cost savings in Distribution Utility operating expenses resulting from the AMI project. Interest expense on short-term debt decreased $0.3 million and $0.3 million in the three and nine month periods ended September 30, 2007 compared to the same periods in 2006 primarily due to lower average short-term borrowings.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities, excluding payment of dividends. The Company initially supplements internally generated funds through bank borrowings, as needed, under unsecured short-term bank lines. Long-term financings, mainly in the form of first mortgage bonds, unsecured notes and equity, are periodically issued to complement the addition of long-term plant investments and for other corporate purposes.

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, if any; the level of the Company’s earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

On June 30, 2007 Unitil renewed $30 million in unsecured revolving lines of credit through three banks. Average daily short-term borrowings during the first nine months of 2007 were approximately $17.6 million, a decrease of approximately $7.8 million over the comparable period in 2006, reflecting principally the receipt of the Unitil Note financing proceeds in May 2007, described below.

On May 2, 2007, Unitil completed the sale of $20 million of Senior Long-Term Notes, through a private placement to institutional investors. The Notes have a term of 15 years maturity and a coupon rate of 6.33%. The Company utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other general corporate purposes of the Company’s principal utility subsidiaries. On September 26, 2006 the Company’s affiliate, UES sold $15 million of Series O 6.32% First Mortgage Bonds. The proceeds from this issuance were utilized to finance long-lived utility plant additions that had been previously financed by short-term indebtedness.

The tables below summarize the major sources and uses of cash (in millions) for the nine months ended September 30, 2007 compared to the same period in 2006.


Cash Provided by Operating Activities	$	23.6	$	17.0

Cash Provided by Operating Activities – Cash Provided by Operating Activities was $23.6 million during the first nine months ended September 30, 2007, an increase of $6.6 million over the comparable period in 2006. Sources of cash from Net Income were $0.7 million higher in the first nine months of 2007 compared to 2006. Sources of cash from Depreciation and Amortization increased by $1.4 million in the current period compared to the same period in 2006. An additional $1.3 million of cash was utilized for Deferred Taxes as compared to the comparable period in 2006. Working Capital related cash flows increased by $5.3 million during the first nine months of 2007 compared to the same period in 2006, principally due to recoveries of accrued revenue through reconciling mechanisms. All other changes in operating activities were a net $0.5 million in sources of cash in the first nine months of 2007 compared to 2006.


Cash (Used in) Investing Activities	$	(25.9	)	$	(24.7	)

Cash (Used in) Investing Activities – Cash (Used in) Investing Activities was $25.9 million for the nine months ended September 30, 2007, an increase of $1.2 million over the comparable period in 2006. Annual capital expenditures are projected to be $32.4 million in 2007 compared to $33.6 million expended in fiscal 2006. The

2007 projected capital expenditures include approximately $6.7 million of cash outlays for the last phase of investment for the AMI project. The Company’s AMI expenditures were $5.9 million during the first nine months of 2007 compared to $4.5 million during the comparable period in 2006. Capital expenditure projections are subject to changes during the fiscal year.


Cash Provided by Financing Activities	$	1.9	$	8.3

Cash Provided by Financing Activities – Cash Provided by Financing Activities was $1.9 million in the nine months ended September 30, 2007, a decrease of $6.4 million over the comparable period in 2006. Cash provided from short term debt was $11.9 million lower at September 30, 2007, as compared to December 31, 2006, principally reflecting the issuance of $20 million in Senior Long-Term Notes in May 2007, as described above. Proceeds from Long-Term Debt issuances increased by $5 million in the current nine month period of 2007 compared to the same period last year, reflecting the net difference between the issuance of the $20 million 2007 Unitil Notes and $15 million 2006 UES Bond financings, described above. All other cash flows provided from other financing activities aggregated to a net $0.5 million increase in the first nine months of 2007 as compared to the same period in 2006.

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 management 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, management 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 judgments, the financial statements 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 21, 2007.

Regulatory Accounting – The Company’s principal business is the distribution of electricity and natural gas by the retail distribution companies: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and FG&E is regulated by the MDPU and UES is regulated by the NHPUC. Accordingly, the Company uses the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

The Company’s principal regulatory assets and liabilities are detailed on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided below. Generally, the Company is currently receiving or being credited with a return on all of its regulatory assets for which a cash outflow has been made. Generally, the Company is currently paying or being charged with a return on all of its regulatory liabilities for which a cash inflow has been received.

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 utility companies will recover their investments in long-lived assets, including regulatory assets. The Company also has commitments under long-term contracts for the purchase of electricity and natural gas from various suppliers. The annual costs under these contracts are included in Purchased Electricity and Purchased Gas in the Consolidated Statements of Earnings and these costs are recoverable in current and future rates under various orders issued by the FERC, MDPU and NHPUC.


	September 30,				December 31,
	2007		2006		2006
Regulatory Assets consist of the following (millions)
Power Supply Buyout Obligations	$	77.7	$	97.3	$	92.6
Deferred Restructuring Costs		29.5		30.5		31.0
Generation-related Assets		1.8		2.7		2.5

Subtotal – Restructuring Related Items		109.0		130.5		126.1

Retirement Benefit Obligations		37.3		10.5		37.1
Income Taxes		17.9		16.4		19.1
Environmental Obligations		13.1		0.9		13.0
Other		3.5		3.2		3.5

Total Regulatory Assets	$	180.8	$	161.5	$	198.8

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 SFAS No. 71. If unable to continue to apply the provisions of SFAS No. 71, the Company would be required to apply the provisions of FASB Statement No. 101, “Regulated Enterprises – Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In the Company’s opinion, its regulated operations will be subject to SFAS No. 71 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. 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. The amount of the monthly Provision is based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior periods. Account write-offs and recoveries, are processed monthly. At the end of each month, an analysis of the delinquent receivables is performed and the adequacy of the Allowance for Doubtful Accounts is reviewed. The analysis calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company is authorized by regulators to recover the supply-related portion of its written-off accounts from customers through periodically reconciling rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis. Also, the Company has experienced periods when state regulators have extended the periods during which certain standard credit and collection activities of utility companies are suspended. In periods when account write-offs exceed estimated levels, the Company adjusts the Provision for Doubtful Accounts to maintain an adequate Allowance for Doubtful Accounts balance.

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.

In September 2006, the FASB issued FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, (SFAS No. 158), an amendment of SFAS No. 87, “Employers’ Accounting for Pensions”, SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” SFAS No. 158 requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas retail 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 health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. 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 (See Note 8.)

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 income 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. The Company accounts for income tax assets, liabilities and expenses in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109) which is the authoritative pronouncement on accounting for and reporting income taxes.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of FAS 109. Under FIN 48, tax positions accounted for under FAS 109 will be evaluated for recognition, derecognition and classification. The Company adopted FIN 48 as of January 1, 2007, as required. The adoption of FIN 48 did not have a significant impact on the Company’s financial position and results of operations.

Depreciation – Depreciation expense is calculated 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 SFAS No. 5. SFAS No. 5 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, 2007, 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

There are approximately 100 employees of the Company represented by labor unions. In May 2005, the Company reached agreements with its bargaining units for new five-year contracts, effective June 1, 2005. These agreements replace contracts that expired on May 31, 2005.

INTEREST RATE RISK

The majority of the Company’s 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 long-term debt securities issued by the Company. In addition, the Company’s short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease the Company’s interest expense in future periods. For example, if the Company had an average amount of short-term debt outstanding of $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 (pre-tax). The average interest rates on the Company’s short-term borrowings for the three months ended September 30, 2007 and September 30, 2006 were 5.71% and 5.82%, respectively. The average interest rates on the Company’s short-term borrowings for the nine months ended September 30, 2007 and September 30, 2006 were 5.75% and 5.44%, respectively.

MARKET RISK

Although Unitil’s utility operating companies 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,
	2007		2006		2007		2006
Operating Revenues
Electric	$	56.9	$	61.2	$	171.3	$	171.0
Gas		3.9		4.4		24.5		24.4
Other		1.0		0.6		2.8		1.8

Total Operating Revenues		61.8		66.2		198.6		197.2

Operating Expenses
Purchased Electricity		41.9		46.4		126.4		126.9
Purchased Gas		2.1		2.8		15.8		17.2
Operation and Maintenance		6.5		6.5		19.8		20.0
Conservation & Load Management		0.8		0.9		2.9		2.9
Depreciation and Amortization		4.5		3.4		13.4		12.0
Provisions for Taxes:
Local Property and Other		1.3		1.3		4.2		4.2
Federal and State Income		0.8		1.1		3.2		2.9

Total Operating Expenses		57.9		62.4		185.7		186.1

Operating Income		3.9		3.8		12.9		11.1
Non-Operating Expenses		—		0.1		0.1		—

Income Before Interest Expense		3.9		3.7		12.8		11.1
Interest Expense, Net		2.3		1.9		6.8		5.8

Net Income		1.6		1.8		6.0		5.3
Less: Dividends on Preferred Stock		—		—		0.1		0.1

Earnings Applicable to Common Shareholders	$	1.6	$	1.8	$	5.9	$	5.2


Average Common Shares Outstanding – Basic (000’s)		5,659		5,605		5,643		5,592

Average Common Shares Outstanding – Diluted (000’s)		5,668		5,619		5,659		5,606

Earnings Per Common Share (Basic and Diluted)	$	0.28	$	0.32	$	1.04	$	0.93

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,
	2007		2006		2006
ASSETS:
Utility Plant:
Electric	$	260.5	$	245.3	$	250.3
Gas		65.5		60.7		63.5
Common		25.8		25.3		25.2
Construction Work in Progress		24.2		14.6		14.0

Total Utility Plant		376.0		345.9		353.0
Less: Accumulated Depreciation		129.4		118.4		121.2

Net Utility Plant		246.6		227.5		231.8

Current Assets:
Cash		4.2		3.8		4.6
Accounts Receivable – Net of Allowance for Doubtful Accounts of $2.1, $1.3 and $1.7		22.8		22.6		22.5
Accrued Revenue		9.5		9.6		13.8
Materials and Supplies		4.4		4.2		4.5
Prepayments and Other		1.2		1.2		1.3

Total Current Assets		42.1		41.4		46.7

Noncurrent Assets:
Regulatory Assets		180.8		161.5		198.8
Prepaid Pension Costs		—		9.1		—
Debt Issuance Costs		2.8		2.6		2.6
Other Noncurrent Assets		2.2		2.4		3.5

Total Noncurrent Assets		185.8		175.6		204.9

TOTAL	$	474.5	$	444.5	$	483.4

(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,
	2007		2006		2006
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common Stock Equity	$	97.4	$	94.8	$	97.8
Preferred Stock, Non-Redeemable, Non-Cumulative		0.2		0.2		0.2
Preferred Stock, Redeemable, Cumulative		1.8		1.9		1.9
Long-Term Debt, Less Current Portion		159.8		140.1		140.0

Total Capitalization		259.2		237.0		239.9

Current Liabilities:
Long-Term Debt, Current Portion		0.4		0.3		0.3
Accounts Payable		15.0		16.1		19.8
Short-Term Debt		13.0		17.6		26.0
Taxes Payable		3.5		1.2		0.9
Interest and Dividends Payable		5.0		4.5		1.6
Other Current Liabilities		4.9		4.8		4.8

Total Current Liabilities		41.8		44.5		53.4

Deferred Income Taxes		31.4		50.5		34.5

Noncurrent Liabilities:
Power Supply Contract Obligations		77.7		97.3		92.6
Retirement Benefit Obligations		50.8		13.8		49.7
Environmental Obligations		12.0		—		12.0
Other Noncurrent Liabilities		1.6		1.4		1.3

Total Noncurrent Liabilities		142.1		112.5		155.6

TOTAL	$	474.5	$	444.5	$	483.4

(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,
	2007			2006
Operating Activities:
Net Income	$	6.0		$	5.3
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		13.4			12.0
Deferred Taxes		(2.5	)		(1.2	)
Changes in Current Assets and Liabilities:
Accounts Receivable		(0.3	)		1.0
Accrued Revenue		4.3			(0.7	)
Accounts Payable		(4.8	)		(4.5	)
Taxes Payable		2.6			1.6
All other Current Assets and Liabilities		1.7			0.8
Other, net		3.2			2.7

Cash Provided by Operating Activities		23.6			17.0

Investing Activities:
Property, Plant and Equipment Additions		(25.9	)		(24.7	)

Cash (Used in) Investing Activities		(25.9	)		(24.7	)

Financing Activities:
Repayment of Short-Term Debt, net		(13.0	)		(1.1	)
Proceeds from Issuance of Long-Term Debt		20.0			15.0
Repayment of Long-Term Debt		(0.1	)		(0.3	)
Dividends Paid		(6.0	)		(5.9	)
Issuance of Common Stock		1.3			0.8
Retirement of Preferred Stock		(0.1	)		(0.2	)
Other, net		(0.2	)		—

Cash Provided by Financing Activities		1.9			8.3

Net Increase (Decrease) in Cash		(0.4	)		0.6
Cash at Beginning of Period		4.6			3.2

Cash at End of Period	$	4.2		$	3.8

Supplemental Cash Flow Information:
Interest Paid	$	7.6		$	7.0
Income Taxes Paid	$	3.3		$	2.7

(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

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, 2007 are not necessarily indicative of results to be expected for the year ending December 31, 2007. 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, 2006, as filed with the SEC on February 21, 2007, for a description of the Company’s Basis of Presentation.

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. (UES), Fitchburg Gas and Electric Light Company (FG&E), 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. (Usource) are subsidiaries of Unitil Resources.

Unitil’s principal business is the retail distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the retail distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts, through the Company’s two wholly-owned subsidiaries, UES and FG&E, collectively referred to as the retail distribution utilities.

A third utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for UES. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of UES 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 UES’ 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 and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.

Recently Issued Pronouncements – In February 2007, the FASB issued FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” (SFAS No. 159), effective for fiscal years beginning after November 15, 2007. SFAS No. 159 includes an amendment of FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” SFAS No. 159 permits entities to choose, at specified election dates, to measure eligible items at fair value and requires unrealized gains and losses on items for which the fair value option has been elected to be reported in earnings. The Company does not expect SFAS No. 159 to have a material impact on the Company’s Consolidated Financial Position.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of FAS 109. Under FIN 48, tax positions accounted for under FAS 109 will be evaluated for recognition, derecognition, and classification. The Company adopted FIN 48 as of January 1, 2007, as required. The adoption of FIN 48 did not have a significant impact on the Company’s financial position and results of operations. See Note 9.

In September 2006, the FASB issued FASB Statement No. 157, “Fair Value Measurements”, (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company does not expect SFAS No. 157 to have an impact on the Company’s Consolidated Financial Statements.

In February 2006, the FASB issued FASB Statement No. 155, “Accounting for Certain Hybrid Financial Instruments”, (SFAS No. 155), which amends SFAS No.133 and FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”, (SFAS No. 140), effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation and clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS No. 133. The Company’s adoption of SFAS No. 155 did not have an impact on the Company’s Consolidated Financial Statements.

Reclassifications – Certain amounts previously reported have been reclassified to conform to current year presentation. The Company reclassified retirement benefit obligations from Other Noncurrent Liabilities to Retirement Benefit Obligations on the balance sheet and certain expenses between Purchased Electricity, Purchased Gas and Operations and Maintenance Expenses for presentation purposes.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
09/13/07	11/15/07	11/01/07	$0.345
06/21/07	08/15/07	08/01/07	$0.345
03/22/07	05/15/07	05/01/07	$0.345
01/18/07	02/15/07	02/01/07	$0.345

09/29/06	11/15/06	11/01/06	$0.345
06/22/06	08/15/06	08/01/06	$0.345
03/23/06	05/15/06	05/01/06	$0.345
01/12/06	02/15/06	02/01/06	$0.345

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

During the first nine months of 2007, the Company sold 28,675 shares of its Common Stock, at an average price of $27.65 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans. Net proceeds of approximately $793,000 were used to reduce short-term borrowings.

During the first nine months of 2006, the Company sold 30,782 shares of its Common Stock, at an average price of $24.59 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans. Net proceeds of approximately $757,000 were used to reduce short-term borrowings.

Also, in the third quarter of 2007, the Company issued and sold 42,437 shares of its Common Stock, at a final average price of $10.70 per share, in connection with the exercise of stock options under the Unitil Corporation Key Employee Stock Option Plan (KESOP). As disclosed in Note 2 to the Company’s Form 10-K for the year ended December 31, 2006, the KESOP was a 10-year plan which began in March 1989. The number of shares underlying options granted under this plan, as well as the terms and conditions of each grant, were determined by the Key Employee Stock Option Plan Committee of the Board of Directors, subject to plan limitations. All options granted under this plan vested upon grant. The 10-year period in which options could be granted under this plan expired in March 1999. The plan provides dividend equivalents on options granted, which are recorded at fair value as compensation expense. As of September 30, 2007, there are no options remaining under the KESOP. Net proceeds of $454,000 were used by the Company to reduce short-term borrowings.

The Company maintains a Restricted Stock Plan (the Plan) which has been ratified and approved by the Company’s shareholders. On February 9, 2007, 9,020 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $230,461. Compensation expense associated with annual grants of shares issued under the Plan is recognized on a monthly basis as the shares vest and was $0.3 million and $0.3 million for the nine months ended September 30, 2007 and 2006, respectively. At September 30, 2007, there was approximately $0.8 million of total unrecognized compensation cost related to non-vested shares under the Plan which is expected to be recognized over approximately 2.4 years as the shares vest.

Details on preferred stock at September 30, 2007, September 30, 2006 and December 31, 2006 are shown below:

(Amounts in Millions)


	(Unaudited) September 30,				December 31,
	2007		2006		2006
Preferred Stock
UES Preferred Stock, Non-Redeemable, Non-Cumulative:
6.00% Series, $100 Par Value	$	0.2	$	0.2	$	0.2
FG&E Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value		0.8		0.9		0.9
8.00% Series, $100 Par Value		1.0		1.0		1.0

Total Preferred Stock	$	2.0	$	2.1	$	2.1

NOTE 4 – LONG-TERM DEBT

On May 2, 2007, Unitil Corporation issued and sold $20 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors in the form of a private placement. The proceeds from this long-term financing were used to refinance existing short-term debt and for general corporate purposes of the Company and its subsidiaries.

Details on long-term debt at September 30, 2007, September 30, 2006 and December 31, 2006 are shown below:

(Amounts in Millions)


	(Unaudited) September 30,				December 31,
	2007		2006		2006
Unitil Energy Systems, Inc.:
First Mortgage Bonds:
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

Unitil Corporation:
Senior Notes:
6.33% Notes, Due May 1, 2022		20.0		—		—

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due August 1, 2017		5.2		5.4		5.3

Total		160.2		140.4		140.3
Less: Installments due within one year		0.4		0.3		0.3

Total Long-term Debt	$	159.8	$	140.1	$	140.0

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, 2007 is estimated to be in a range of up to approximately $170 million, before considering any costs, including prepayment costs, to market the Company’s debt. Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

The Company provides limited guarantees on certain energy contracts entered into by its regulated subsidiary companies. The Company’s policy is to limit these guarantees to the duration of the contracts, which range from three months to three years. As of September 30, 2007 there are $8.3 million of guarantees outstanding and these guarantees extend through March 13, 2009. These guarantees are not required to be recorded under the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and nine months ended September 30, 2007 and September 30, 2006 (Millions):


	Electric		Gas			Other			Non-Regulated			Total
Three Months Ended:

September 30, 2007
Revenues	$	56.9	$	3.9		$	—		$	1.0		$	61.8
Segment Profit (Loss)		2.3		(0.7	)		(0.1	)		0.1			1.6
Capital Expenditures		4.7		1.7			0.1			—			6.5

September 30, 2006
Revenues	$	61.2	$	4.4		$	—		$	0.6		$	66.2
Segment Profit (Loss)		2.5		(0.8	)		0.1			—			1.8
Capital Expenditures		7.0		3.3			—			—			10.3

Nine Months Ended:

September 30, 2007
Revenues	$	171.3	$	24.5		$	—		$	2.8		$	198.6
Segment Profit (Loss)		5.7		—			—			0.2			5.9
Capital Expenditures		21.8		3.9			0.4			—			26.1
Segment Assets		339.0		110.2			24.4			0.9			474.5

September 30, 2006
Revenues	$	171.0	$	24.4		$	—		$	1.8		$	197.2
Segment Profit (Loss)		5.5		(0.5	)		0.4			(0.2	)		5.2
Capital Expenditures		18.6		6.0			0.1			—			24.7
Segment Assets		323.5		100.0			19.9			1.1			444.5

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2006 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 21, 2007.

FG&E – Electric Division – On December 1, 2006, FG&E submitted its annual reconciliation of costs and revenues for Transition, Transmission, Standard Offer Service, and Default Service filed under its restructuring plan (the Annual Reconciliation Filing). On May 25, 2007 the MDPU approved FG&E’s 2005 Annual Reconciliation Filing. On September 7, 2007, a Settlement Agreement between FG&E and the Attorney General of Massachusetts was filed resolving all disputes with regard to FG&E’s 2006 Annual Reconciliation Filing. Approval of the Settlement Agreement is pending.

On August 17, 2007, FG&E filed an electric distribution rate increase of $3.3 million, which represents an increase of 4.7 percent over FG&E’s 2006 total electric operating revenue. The MDPU has suspended the effective date until March 1, 2008 in order to investigate the propriety of the Company’s request.

FG&E – Gas Division – On January 26, 2007, the MDPU approved a rate Settlement Agreement (Settlement) between FG&E and the Attorney General of Massachusetts for FG&E’s Gas Division. Under the Settlement, FG&E increased its gas distribution rates by $1.2 million on February 1, 2007, and an additional $1.0 million

increase will occur on November 1, 2007. The Settlement also includes agreement on several other rate matters and service quality performance measures for the company’s Gas Division in the areas of safety, customer service and satisfaction.

On September 7, 2006, the MDPU issued an order allowing FG&E to recover the costs of its actual gas and electric supply-related bad debt effective December 1, 2005. Prior to this final approval, FG&E had recovered supply-related bad debt costs based on a fixed rate formula that produced a significant under-recovery of these costs. On September 27, 2006, the Attorney General filed a Petition for Appeal with the Massachusetts Supreme Judicial Court seeking to set aside the MDPU’s order. FG&E intends to support the MDPU’s order but the Company cannot predict the outcome of the Attorney General’s appeal at this time.

FG&E – Other – On June 22, 2007, the MDPU opened an investigation to review ratemaking practices for gas and electric utility distribution companies in Massachusetts, and consider whether existing mechanisms may be changed to better align utility companies’ financial interests with the need to capture end use efficiencies and foster the advancement of price responsive demand in the wholesale energy market. This matter remains pending.

UES – On March 16, 2007, UES made its annual reconciliation and rate filing with the NHPUC under its restructuring plan, effective May 1, 2007, including reconciliation of prior year costs and revenues, power supply and power supply-related stranded costs. On April 30, 2007 the NHPUC approved UES’ filing subject to adjustment and reconciliation depending on the Staff audit and Staff’s on-going review with regard to the method for calculating unbilled revenues. No exceptions were noted in the final audit report, which was issued on July 11, 2007.

On October 6, 2006, UES received approval from the NHPUC of a Settlement Agreement (Agreement) resolving its electric distribution base rate case filed in November, 2005. The terms of the Agreement provide for an increase in base distribution rates of $2.3 million effective as of January 1, 2006. Additionally, the Agreement authorizes two step increases in base distribution rates, related to utility plant additions in 2006, of approximately $0.4 million and $0.1 million annually, effective as of November 1, 2006 and May 1, 2007, respectively. Also, the Agreement provides for the recovery of approximately $0.3 million annually of supply-related operating and administrative costs through default energy service rates and a reduction of approximately $0.6 million in annual depreciation expense, primarily reflecting an increase in utility plant and equipment average service lives. The stipulated rate of return under the settlement is 8.70%, including a return on equity of 9.67%. The Agreement also authorized a temporary rate surcharge for recovery of certain rate case expenses and recoupment of the authorized distribution rate increase from January through October 2006. On August 30, 2007, UES filed a reconciliation of the surcharge, which is expected to expire effective November 1, 2007.

On June 22, 2007, the NHPUC issued an order in its investigation into implementation of the federal Energy Policy Act of 2005 regarding the adoption of standards for time-based metering and interconnection. This order sets the framework for implementation of time based rates for utility provided default service, though a number of technical issues remain to be resolved. Under the order, UES is required to file draft tariffs to provide for fixed, time-based pricing of default service for all customer classes no later than November 30, 2007. On August 31, 2007, the NHPUC issued an order on motion for rehearing, staying the June 22, 2007 order pending hearing and reconsideration of the issues. This matter remains pending.

On May 14, 2007, the NHPUC issued an order opening an investigation into the merits of instituting, for electric utilities, appropriate rate mechanisms, such as revenue decoupling, which would have the effect of removing obstacles to, and encouraging investment in, energy efficiency. The matter remains pending.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2006 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 21, 2007.

The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company believes it is in compliance with all applicable

environmental and safety laws and regulations, and the Company believes that as of September 30, 2007, there are no material losses reasonably possible 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 on the Company’s Consolidated Balance Sheet at September 30, 2007 in Environmental Obligations is $12.0 million related to estimated future clean up costs for permanent remediation of a former manufactured gas plant site at Sawyer Passway, located in Fitchburg, Massachusetts. A corresponding regulatory asset was recorded to reflect the future rate recovery of these costs. As noted above, please refer to Note 5 to the financial statements in Item 8 of Part II of the Company’s Form 10-K for December 31, 2006 for additional information.

NOTE 8: RETIREMENT BENEFIT OBLIGATIONS

The Company provides certain pension and postretirement benefit plans for its retirees and current employees including defined benefit pension plans, postretirement health and welfare plans, a supplemental executive retirement plan and an employee 401(k) savings plan.

In September 2006, the FASB issued SFAS No. 158 which requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas retail rates.

Pension Plan – The Company’s defined benefit pension plan covers substantially all of its employees. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

FG&E recovers the costs associated with its pension and PBOP costs on an annually reconciling basis through a rate adjustment mechanism (the Pension / PBOP Adjustment Factor (PAF). FG&E records a regulatory asset to recognize the deferral for the difference between the level of pension and PBOP expenses that are currently included in its base rates and the amounts that are required to be recorded in accordance with SFAS No. 87 and SFAS No. 106 and amortizes increases and/or decreases in that deferral balance into the PAF for recovery over a three year period.

UES recovers its pension and PBOP expenses in base rates and amortizes deferred pension costs as these costs are recovered over a six year period in base rates.

The following tables show the components of net periodic pension cost, (NPPC), as well as key actuarial assumptions used in determining the various pension plan values:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Components of NPPC (000’s)
Service Cost	$	492		$	450		$	1,476		$	1,350
Interest Cost		834			788			2,502			2,365
Expected Return on Plan Assets		(1,050	)		(944	)		(3,146	)		(2,831	)
Amortization of Prior Service Cost		27			27			80			80
Amortization of Net Loss		336			331			1,008			993

Subtotal NPPC		639			652			1,920			1,957

Amounts Capitalized and Deferred		(215	)		(127	)		(651	)		(772	)

NPPC Recognized	$	424		$	525		$	1,269		$	1,185


	2007		2006
Key Assumptions (Weighted Average)

Used to Determine Benefit Obligations:
Discount Rate	5.50	%	5.50	%
Rate of Compensation Increase	3.50	%	3.50	%

Used to Determine NPPC:
Discount Rate	5.50	%	5.50	%
Expected Long-Term Rate of Return on Plan Assets	8.50	%	8.50	%
Rate of Compensation Increase	3.50	%	3.50	%

Employer Contributions – On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA are new minimum funding rules which will go into effect for plan years beginning in 2008. The funding target will be 100% of a plan’s liability with any shortfall amortized over seven years, with lower (92% - 100%) funding targets available to well-funded plans during the transition period. As of September 30, 2007, the Company has made contributions of $2.8 million to the Plan in 2007 and does not anticipate making any additional contributions in 2007. The Company contributed $2.5 million in 2006.

PBOP Plan – The Company sponsors the PBOP Plan, primarily to provide health care and life insurance benefits to employees and retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

The following tables show the components of net periodic postretirement benefit cost (NPPBC), as well as key actuarial assumptions used in determining the various PBOP Plan values:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Components of NPPBC (000’s)
Service Cost	$	358		$	321		$	1,073		$	962
Interest Cost		514			507			1,543			1,522
Expected Return on Plan Assets		(61	)		(49	)		(184	)		(146	)
Amortization of Prior Service Cost		341			340			1,020			1,020
Amortization of Transition (Asset) Obligation		5			5			16			16
Amortization of Net (Gain) Loss		17			40			52			120

Subtotal NPPBC		1,174			1,164			3,520			3,494

Amounts Capitalized and Deferred		(489	)		(559	)		(1,506	)		(1,673	)

NPPBC Recognized	$	685		$	605		$	2,014		$	1,821


	2007		2006
Weighted-Average Assumptions

Used to Determine Benefit Obligations:
Discount Rate	5.50	%	5.50	%
Health Care Cost Trend Rate Assumed for Next Year	8.50	%	8.50	%
Ultimate Health Care Cost Trend Rate	4.00	%	4.00	%
Year That the Health Care Cost Trend Rate Reaches the Ultimate Trend Rate	2016		2016
Used to Determine NPPBC:
Discount Rate	5.50	%	5.50	%
Expected Long-Term Rate of Return on Plan Assets	8.50%/5.50	% ⁽¹⁾	8.50%/5.50	% ⁽¹⁾
Health Care Cost Trend Rate Assumed for Next Year	9.00	%	8.50	%
Ultimate Health Care Cost Trend Rate	4.00	%	4.00	%
Year That the Health Care Cost Trend Rate Reaches the Ultimate Trend Rate	2016		2016

⁽¹⁾

Funding of the PBOP Plan is made into two VEBT’s; one is a union VEBT and the other is a non-union VEBT. The expected long-term rate of return on plan assets for the union VEBT is 8.50%. The non-union VEBT is subject to income taxes and therefore the expected long-term rate of return on plan assets is 5.50%, reflecting the effect of taxes.

Employer Contributions – As of September 30, 2007, the Company had made $1.7 million of contributions to the PBOP Plan in 2007. The Company presently anticipates contributing an additional $0.8 million to fund the Plan in 2007 for an estimated funding total of $2.5 million in the year. The Company contributed $2.2 million in 2006.

SERP – The Company also sponsors an unfunded retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (the SERP), with participation limited to executives selected by the Board of Directors.

The components of net periodic SERP cost are as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007			2006
Components of NPSC (000’s)
Service Cost	$	40	$	36	$	122		$	110
Interest Cost		29		26		88			78
Amortization of Transition Obligation		—		4		—			13
Amortization of Prior Service Cost		—		—		(1	)		(1	)
Amortization of Net Loss		11		10		33			29

Net Periodic SERP Cost	$	80	$	76	$	242		$	229

Employer Contributions – As of September 30, 2007, the Company has made payments of $54,000 to beneficiaries. The Company presently anticipates making additional benefit payments of $18,000 in 2007 for a total of $72,000.

NOTE 9: INCOME TAXES

The Company evaluated its tax positions at December 31, 2006 and for the current interim reporting period ended September 30, 2007 in accordance with FIN 48, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by FIN 48 is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Massachusetts and New Hampshire tax authorities for the tax periods

ended December 31, 2004; December 31, 2005; and December 31, 2006. Income tax filings for the year ended December 31, 2006 were filed on or before September 17, 2007. The Company classifies penalty and interest expense related to income tax liabilities as an income tax expense. There are no interest and penalties recognized in the statement of earnings or accrued on the balance sheet.

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

As of the end of the quarter covered by this Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company’s periodic SEC filings.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, our 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, 2006 as filed with the Securities and Exchange Commission on February 21, 2007.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

(a)

There were no sales of unregistered equity securities by the Company for the fiscal period ended September 30, 2007.

(b)

Not applicable.

(c)

Issuer 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⁽¹⁾	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs⁽¹⁾
7/1/07 – 7/31/07	—	—	—	n/a
8/1/07 – 8/31/07	—	—	—	n/a
9/1/07 – 9/30/07	—	—	—	n/a

Total	—	—	—	n/a

(1)

Represents Common Stock purchased on the open market related to Board of Director Retainer Fees and Employee Length of Service Awards. Shares are not purchased as part of a specific plan or program and therefore there is no pool or maximum number of shares related to these purchases. The Company expects to continue with these purchases indefinitely.

Item 6.

Exhibits

(a)

Exhibits


Exhibit No.	Description of Exhibit	Reference
11	Computation in Support of Earnings Per Average Common Share	Filed herewith

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

99.1	Unitil Corporation Press Release Dated October 25, 2007 Announcing Earnings For the Quarter Ended September 30, 2007	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, 2007		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: October 26, 2007		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer