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 March 31, 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 April 26, 2007
Common Stock, No par value		5,669,951 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended March 31, 2007

Table of Contents


		Page No.
Part I. Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Earnings - Three Months Ended March 31, 2007 and 2006	15

	Consolidated Balance Sheets, March 31, 2007, March 31, 2006 and December 31, 2006	16-17

	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2007 and 2006	18

	Notes to Consolidated Financial Statements	19-29

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2-14

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	30

Item 1A.	Risk Factors	30

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	33

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 99,300 electric customers and 15,000 natural gas customers in their franchise areas. The retail distribution companies are local “pipes and wires” utilities with a combined investment in net utility plant of $237.7 million at March 31, 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 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 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 quarters ended March 31, 2007 and March 31, 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 $2.6 million for the first quarter of 2007, an increase of $0.6 million over Net Income for the first quarter of 2006. Earnings per common share (EPS) were $0.46 for the three months ended March 31, 2007, an improvement of $0.10 per share, or 28%, over the first quarter of 2006.

Unitil’s improved first quarter earnings in 2007 over 2006 were driven by higher electric and gas base distribution rates and higher total gas sales. Unitil’s non-regulated business, Usource, also realized higher revenues in 2007 which further contributed to the Company’s overall improved earnings. These favorable factors were partially offset by higher operating expenses and higher interest expense in the current year.

The following table presents the significant items contributing to the improvement in earnings per share in the first quarter of 2007:


	Earnings Per Share
Three Months Ended March 31, 2006:	$	0.36
Electric Sales Margin		0.06
Gas Sales Margin		0.08
Usource Sales Margin		0.03
Operation & Maintenance Expense		(0.02	)
Depreciation & Amortization		(0.03	)
Interest Expense, net		(0.02	)

Three Months Ended March 31, 2007:	$	0.46

In the first quarter of 2007, Unitil’s electric kWh sales to residential customers increased 0.4% while sales to Commercial and Industrial (C&I) customers decreased 0.8% compared to the same period in 2006. Gas sales to residential customers remained level in the first quarter of 2007 compared to the same period in 2006 while sales to C&I customers were 15.0% higher in the current quarter, primarily due to a special contract with a large industrial customer.

Electric and Gas sales margin increased $0.6 million and $0.9 million, respectively, in the three months ended March 31, 2007 compared to the same period in 2006. Usource, our non-regulated energy brokering business, recorded increased sales margin of $0.3 million in the first quarter of 2007, an increase of 50% over the first quarter of 2006.

In the three months ended March 31, 2007 operating expenses increased by $1.0 million including higher Operation and Maintenance expenses of $0.2 million and higher Depreciation, Amortization, Taxes and Other increased $0.8 million. In the first three months of 2007, Interest Expense, Net, increased by $0.2 million compared to the same period in 2006, due to higher interest rates and higher average borrowings in 2007.

In 2006, 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, 2007 and March, 2007 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 months ended March 31, 2007 and a period-to-period comparison of changes in financial position are presented below.

Balance Sheet

Regulatory Assets increased $19.7 million as of March 31, 2007 compared to March 31, 2006, primarily 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 in Regulatory Assets related to current year cost recoveries.

Long-Term Debt increased $14.7 million as of March 31, 2007 compared to March 31, 2006, reflecting the issuance and sale on September 26, 2006 by UES of $15.0 million of Series O 6.32% First Mortgage Bonds, due September 15, 2036, to institutional investors in the form of a private placement.

Deferred Income Taxes decreased $16.9 million as of March 31, 2007 compared to March 31, 2006, primarily reflecting the recording of deferred tax assets related to Retirement Benefit Obligations, discussed below.

Retirement Benefit Obligations increased $39.1 million as of March 31, 2007 compared to March 31, 2006, primarily reflecting the recording of pension, PBOP and SERP obligations.

Environmental Obligations increased $12.0 million as of March 31, 2007 compared to March 31, 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 – In the first quarter of 2007, Unitil’s total electric kWh sales decreased 0.3% compared to the first quarter of 2006. Sales to residential customers increased 0.4% while sales to C&I customers decreased 0.8%.

The following table details total kWh sales for the three months ended March 31, 2007 and 2006 by major customer class:


kWh Sales (millions)
	Three Months Ended March 31,
	2007	2006	Change		% Change
Residential	184.0	183.2	0.8		0.4	%
Commercial/Industrial	265.6	267.8	(2.2	)	(0.8	%)

Total	449.6	451.0	(1.4	)	(0.3	%)

Electric Operating Revenues and Sales Margin - The following table details total Electric Operating Revenues and Sales Margin for the three months ended March 31, 2007 and 2006:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended March 31,
	2007		2006		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	31.5	$	24.2	$	7.3		12.9	%
Commercial / Industrial		31.2		32.2		(1.0	)	(1.8	%)

Total Electric Operating Revenue	$	62.7	$	56.4	$	6.3		11.1	%

Cost of Electric Sales:
Purchased Electricity	$	48.2	$	42.8	$	5.4		9.6	%
Conservation & Load Management		1.0		0.7		0.3		0.5	%

Electric Sales Margin	$	13.5	$	12.9	$	0.6		1.2	%

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

Total Electric Operating Revenues increased by $6.3 million, or 11.1%, in the three months ended March 31, 2007 compared to the same period 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 increase in Total Electric Operating Revenues in the three months ended March 31, 2007 reflects higher Purchased Electricity costs of $5.4 million, higher C&LM revenues of $0.3 million and higher sales margin of $0.6 million.

Purchased Electricity and C&LM revenues increased a combined $5.7 million, or 10.1%, of Total Electric Operating Revenues in the three months ended March 31, 2007 compared to the same period in 2006, reflecting 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.

Electric sales margin increased by $0.6 million in the three months ended March 31, 2007 compared to the same period in 2006, reflecting a rate increase in New Hampshire approved by regulators in fourth quarter of 2006 of $0.7 million, partially offset by the decline in sales units, $0.1 million.

Gas Sales, Revenues and Margin

Therm Sales – Therm sales of natural gas increased 8.3% in the three months ended March 31, 2007 compared to the same period in 2006. Sales to residential customers remained level in the first quarter of 2007 compared to the same period in 2006. Sales to C&I customers were 15.0% higher in the current quarter, primarily due to a new special contract with a large industrial customer.

The following table details total firm therm sales for the three months ended March 31, 2007 and 2006, by major customer class:


Therm Sales (millions)
	Three Months Ended March 31,
	2007	2006	Change	% Change
Residential	4.9	4.9	—	—
Commercial/Industrial	6.9	6.0	0.9	15.0	%

Total	11.8	10.9	0.9	8.3	%

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three months ended March 31, 2007 and 2006:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended March 31,
	2007		2006		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	8.5	$	7.9	$	0.6		4.4	%
Commercial / Industrial		5.7		5.8		(0.1	)	(0.7	%)

Total Gas Operating Revenue	$	14.2	$	13.7	$	0.5		3.7	%

Cost of Gas Sales:
Purchased Gas	$	9.8	$	10.1	$	(0.3	)	(2.2	%)
Conservation & Load Management		—		0.1		(0.1	)	(0.7	%)

Gas Sales Margin	$	4.4	$	3.5	$	0.9		6.6	%

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

Total Gas Operating Revenues increased $0.5 million, or 3.7%, in the three months ended March 31, 2007 compared to the same period 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 increase in Total Gas Operating Revenues in three months ended March 31, 2007 reflects higher sales margin of $0.9 million, offset by lower Purchased Gas costs of $0.3 million and lower C&LM revenues of $0.1 million.

Purchased Gas and C&LM revenues decreased a combined $0.4 million, or 2.9%, of Total Gas Operating Revenues in 2007 compared to 2006, primarily reflecting an increase in the amount of natural gas purchased by customers 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.

Gas sales margin increased $0.9 million in the three months ended March 31, 2007 compared to the same period in 2006 due to higher rates approved and implemented in early 2007 and higher sales to large C&I customers, including sales to a large industrial customer under a special contract.

Operating Revenue - Other

The following table details total Other Revenue for the three months ended March 31, 2007 and 2006:


Other Revenue (Millions)
	Three Months Ended March 31,
	2007		2006		$ Change		% Change
Other	$	0.9	$	0.6	$	0.3	50.0	%

Total Other Revenue	$	0.9	$	0.6	$	0.3	50.0	%

Total Other Revenue increased $0.3 million, or 50.0%, in the three month period ended March 31, 2007 compared to the same period in 2006. The increase was 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 the other energy supply related restructuring costs, including long-term power supply contract buyout costs. Purchased Electricity increased $5.4 million, or 12.6%, in the three month period ended March 31, 2007 compared to the same period in 2006, reflecting 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 $0.3 million, or 3.0%, in the three month period ended March 31, 2007 compared to the same period in 2006, reflecting an increase in the amount of natural gas purchased by customers 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 expense increased $0.2 million in the three months ended March 31, 2007 compared to the same period in 2006. This increase was due to higher retiree and employee benefit costs of $0.3 million, driven by higher pension and post retirement benefit expenses, higher bad debt expenses of $0.1 million and higher salaries and compensation expenses of $0.1 million, partially offset by lower utility operating expenses of $0.1 million, lower outside services expenses of $0.1 million and all other operating expenses of $0.1 million, net.

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 electricity and natural gas 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 increased by $0.2 million, or 25.0%, in three month period ended March 31, 2007 compared to the same period in 2006. The increase reflects the timing of spending on the implementation of Energy Efficiency programs. 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 $0.3 million, or 7.1%, for the three month period ended March 31, 2007 compared to the same period in 2006. This increase was higher depreciation on normal utility plant additions.

Local Property and Other Taxes - Local Property and Other Taxes increased by less than $0.1 million, or 1.6% for the three month period ended March 31, 2007 compared to the same period in 2006. This increase was due to higher property tax rates.

Federal and State Income Taxes - Federal and State Income Taxes are higher by $0.4 million for the three months ended March 31, 2007 compared to the same period in 2006 reflecting higher pre-tax earnings.

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 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 March 31,
	2007			2006			Change
Interest Expense
Long-term Debt	$	2.6		$	2.3		$	0.3
Short-term Debt		0.4			0.3			0.1
Regulatory Liabilities		—			—			—

Subtotal Interest Expense		3.0			2.6			0.4

Interest Income
Regulatory Assets		(0.8	)		(0.7	)		(0.1	)
AFUDC and Other		(0.1	)		—			(0.1	)

Subtotal Interest Income		(0.9	)		(0.7	)		(0.2	)

Total Interest Expense, Net	$	2.1		$	1.9		$	0.2

Interest Expense, Net increased by $0.2 million in the three month period ended March 31, 2007 compared to the same period in 2006. Interest expense on long-term borrowings increased due to the issuance of new fixed rate long-term debt. Unitil’s New Hampshire subsidiary, UES, issued and sold $15 million of Series O 6.32% First Mortgage Bonds to institutional investors on September 26, 2006. The proceeds from this long-term financing were used principally to finance utility plant additions that had been previously financed on an interim basis with short-term bank borrowings. Interest expense on short-term debt increased in the three month period ended March 31, 2007 compared to the same period in 2006 due to higher short-term interest rates and higher levels of short-term borrowings. These increases in interest expense were partially offset by an increase in interest income due to higher earnings on funds used for capital projects and higher carrying charges earned on regulatory assets.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent 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. At March 31, 2007 Unitil had an aggregate of $41.0 million in unsecured revolving bank lines of credit through three banks. Average daily short-term borrowings during the first three months of 2007 were approximately $26.2 million, an increase of approximately $2.7 million over the comparable period in 2006.

The maximum amount of short-term borrowings that may be incurred by Unitil and its subsidiaries has been subject to periodic regulatory oversight. At March 31, 2007, Unitil had regulatory authorization to incur total short-term bank borrowings up to a maximum of $55 million, and UES and FG&E had regulatory authorizations to borrow up to a maximum of $16 million and $35 million, respectively.

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 April 2007, Unitil agreed to privately place up to $20 million of long-term Notes, subject to market and other conditions, with institutional investors. The terms of the Notes will be determined between the Company and the purchasers of the Notes. The Notes are expected to have a maturity of up to 15 years and an interest rate of 6.33%. The Company intends to use the proceeds from the long-term financing to make capital contributions to its principal utility affiliates, UES and FG&E, to enable them to refinance existing short-term debt and for general corporate purposes of the Company and its subsidiaries.

The tables below summarize the major sources and uses of cash (in millions) for the three months ended March 31, 2007 compared to the same period in 2006.


Cash Provided by Operating Activities	$	6.1	$	0.8

Cash Provided by Operating Activities - Cash Provided by Operating Activities was $6.1 million during the three months ended March 31, 2007, an increase of $5.3 million over the comparable period in 2006. Sources of cash from Net Income were $0.6 million higher in the first three months of 2007 compared to 2006. Sources of cash from Depreciation, Amortization and Deferred Taxes increased by $1.2 million in the current quarter compared to the same period in 2006. Working Capital related cash flows increased by $1.1 million during the first quarter of 2007 compared to the same period in 2006. All other changes in operating activities were a net $2.4 in sources of cash in the first three months of 2007 compared to 2006.


Cash (Used in) Investing Activities	$	(9.6	)	$	(5.6	)

Cash (Used in) Investing Activities - Cash (Used in) Investing Activities was $9.6 million for the three months ended March 31, 2007, an increase of $4.0 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. These 2007 projected capital expenditures include approximately $5.5 million of cash outlays for the Automated Metering Infrastructure (AMI) project, the second year of a two-year investment in the Company’s metering infrastructure. The Company’s AMI expenditures were $2.8 during the first quarter of 2007 compared to $0.4 during the comparable period in 2006. Capital expenditure projections are subject to changes during the fiscal year.


Cash Provided by Financing Activities	$	1.7	$	3.8

Cash Provided by Financing Activities - Cash Provided by Financing Activities was $1.7 million in the three months ended March 31, 2007, a decrease of $2.1 million over the comparable period in 2006. Cash provided from financing activities from the proceeds of short-term bank borrowings was $2.3 million lower in the current period. All other cash flows provided from financing activities were a net $0.2 million higher in the first three months of 2007 compared to 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 MDTE 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. 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, MDTE and NHPUC.

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. 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. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in enterprise’s financial statements. FIN 48 prescribes a “more-likely-than-not” recognition threshold for the recognition and measurement of the benefits of a tax position taken or expected to be taken. FIN 48 is now the primary guidance in accounting for uncertainty in income taxes. 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 March 31, 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 March 31, 2007 and March 31, 2006 were 5.77% and 5.00%, 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 March 31,
	2007		2006
Operating Revenues
Electric	$	62.7	$	56.4
Gas		14.2		13.7
Other		0.9		0.6

Total Operating Revenues		77.8		70.7

Operating Expenses
Purchased Electricity		48.2		42.8
Purchased Gas		9.8		10.1
Operation and Maintenance		6.5		6.3
Conservation & Load Management		1.0		0.8
Depreciation and Amortization		4.5		4.2
Provisions for Taxes:
Local Property and Other		1.5		1.4
Federal and State Income		1.6		1.2

Total Operating Expenses		73.1		66.8

Operating Income		4.7		3.9
Non-Operating (Income) Expenses		—		—

Income Before Interest Expense		4.7		3.9
Interest Expense, Net		2.1		1.9

Net Income		2.6		2.0
Less: Dividends on Preferred Stock		—		—

Earnings Applicable to Common Shareholders	$	2.6	$	2.0

Average Common Shares Outstanding – Basic (000’s)		5,627		5,577
Average Common Shares Outstanding – Diluted (000’s)		5,644		5,591

Earnings Per Common Share (Basic and Diluted)	$	0.46	$	0.36

Dividends Declared Per Share of Common Stock	$	0.69	$	0.69

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)


	(UNAUDITED) March 31,				December 31,
	2007		2006		2006
ASSETS:

Utility Plant:
Electric	$	255.3	$	237.2	$	250.3
Gas		63.9		59.0		63.5
Common		25.3		25.6		25.2
Construction Work in Progress		17.2		7.3		14.0

Total Utility Plant		361.7		329.1		353.0
Less: Accumulated Depreciation		124.0		113.8		121.2

Net Utility Plant		237.7		215.3		231.8

Current Assets:
Cash		2.8		2.2		4.6
Accounts Receivable – Net of Allowance for
Doubtful Accounts of $2.0, $1.0 and $1.7		28.4		26.5		22.5
Accrued Revenue		12.0		6.4		13.8
Materials and Supplies		2.5		2.6		4.5
Prepayments and Other		1.1		1.3		1.3

Total Current Assets		46.8		39.0		46.7

Noncurrent Assets:
Regulatory Assets		193.3		173.6		198.8
Prepaid Pension		—		10.4		—
Debt Issuance Costs		2.5		2.4		2.6
Other Noncurrent Assets		2.8		3.2		3.5

Total Noncurrent Assets		198.6		189.6		204.9

TOTAL	$	483.1	$	443.9	$	483.4

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)


	(UNAUDITED) March 31,				December 31,
	2007		2006		2006
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	96.8	$	94.8	$	97.8
Preferred Stock, Non-Redeemable, Non-Cumulative		0.2		0.2		0.2
Preferred Stock, Redeemable, Cumulative		1.9		1.9		1.9
Long-Term Debt, Less Current Portion		140.0		125.3		140.0

Total Capitalization		238.9		222.2		239.9

Current Liabilities:
Long-Term Debt, Current Portion		0.3		0.3		0.3
Accounts Payable		17.9		14.7		19.8
Short-Term Debt		29.7		24.7		26.0
Taxes Payable		2.1		1.9		0.9
Interest and Dividends Payable		4.5		4.4		1.6
Other Current Liabilities		4.1		4.1		4.8

Total Current Liabilities		58.6		50.1		53.4

Deferred Income Taxes		33.8		50.7		34.5

Noncurrent Liabilities:
Power Supply Contract Obligations		87.6		107.7		92.6
Retirement Benefit Obligations		51.0		11.9		49.7
Environmental Obligations		12.0		—		12.0
Other Noncurrent Liabilities		1.2		1.3		1.3

Total Noncurrent Liabilities		151.8		120.9		155.6

TOTAL	$	483.1	$	443.9	$	483.4

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Three Months Ended March 31,
	2007			2006
Operating Activities:
Net Income	$	2.6		$	2.0
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		4.5			4.2
Deferred Taxes		(0.5	)		(1.4	)
Changes in Current Assets and Liabilities:
Accounts Receivable		(5.9	)		(2.9	)
Accrued Revenue		1.8			1.6
Accounts Payable		(1.9	)		(5.9	)
Taxes Payable		1.2			2.3
All other Current Assets and Liabilities		2.4			1.4
Other, net		1.9			(0.5	)

Cash Provided by Operating Activities		6.1			0.8

Investing Activities:
Property, Plant and Equipment Additions		(9.6	)		(5.6	)

Cash (Used in) Investing Activities		(9.6	)		(5.6	)

Financing Activities:
Proceeds from Short-Term Debt, net		3.7			6.0
Repayment of Long-Term Debt		—			(0.1	)
Retirement of Preferred Stock		—			(0.2	)
Dividends Paid		(2.0	)		(2.0	)
Issuance of Common Stock		0.3			0.2
Other, net		(0.3	)		(0.1	)

Cash Provided by Financing Activities		1.7			3.8

Net (Decrease) in Cash		(1.8	)		(1.0	)
Cash at Beginning of Period		4.6			3.2

Cash at End of Period	$	2.8		$	2.2

Supplemental Cash Flow Information:
Interest Paid	$	2.0		$	1.5
Income Taxes Paid		1.8			0.8

(The accompanying notes are an integral part of these consolidated 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 months ended March 31, 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. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the Securities and Exchange Commission (SEC). As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed. 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. 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. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in enterprise’s financial statements. FIN 48 prescribes a “more-likely-than-not” recognition threshold for the recognition and measurement of the benefits of a tax position taken or expected to be taken. FIN 48 is now the primary guidance in accounting for uncertainty in income taxes. 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 for presentation purposes.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
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 quarter of 2007, the Company sold 9,628 shares of its Common Stock, at an average price of $26.19 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans. Net proceeds of approximately $252,000 were used to fund capital expenditures.

During the first quarter of 2006, the Company sold 9,967 shares of its Common Stock, at an average price of $24.60 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans. Net proceeds of approximately $245,000 were used to fund capital expenditures.

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 shares issued under the Plan is recognized on a monthly basis as the shares vest and was $0.1 million and $0.1

million for three months ended March 31, 2007 and 2006, respectively. At March 31, 2007, there was approximately $0.9 million of total unrecognized compensation cost related to non-vested shares under the Plan which is expected to be recognized over approximately 2.8 years as the shares vest.

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

(Amounts in Millions)


	(Unaudited) March 31,				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		0.9		0.9		0.9
8.00% Series, $100 Par Value		1.0		1.0		1.0

Total Preferred Stock	$	2.1	$	2.1	$	2.1

NOTE 4 – LONG-TERM DEBT

On April 16, 2007, Unitil Corporation agreed to privately place up to $20 million of long-term Notes, subject to market and other conditions, with institutional investors. The terms of the Notes will be determined by negotiations between the Company and the purchasers of the Notes. The Notes are expected to have a maturity of up to 15 years and an interest rate of 6.33%. The Company intends to use the proceeds from this long-term financing to make capital contributions to its principal affiliates, Unitil Energy Systems, Inc. and Fitchburg Gas and Electric Light Company, to enable them to refinance existing short-term debt and for general corporate purposes of the Company and its subsidiaries.

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

(Amounts in Millions)


	(Unaudited) March 31,				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

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 Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due August 1, 2017		5.3		5.6		5.3

Total		140.3		125.6		140.3
Less: Installments due within one year		0.3		0.3		0.3

Total Long-term Debt	$	140.0	$	125.3	$	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 March 31, 2007 is estimated to be in a range of up to approximately $156 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 two years or less. As of March 31, 2007 there are $10 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 months ended March 31, 2007 and March 31, 2006:


Three Months Ended March 31, 2007 (Millions)	Electric		Gas		Other			Non- Regulated			Total
Revenues	$	62.7	$	14.2	$	—		$	0.9		$	77.8
Segment Profit		1.4		1.1		0.1			—			2.6
Identifiable Segment Assets		347.1		114.0		20.9			1.1			483.1
Capital Expenditures		9.1		0.7		(0.2	)		—			9.6

Three Months Ended March 31, 2006 (Millions)
Revenues	$	56.4	$	13.7	$	—		$	0.6		$	70.7
Segment Profit (Loss)		1.3		0.7		0.1			(0.1	)		2.0
Identifiable Segment Assets		319.2		101.9		21.5			1.3			443.9
Capital Expenditures		5.2		0.4		—			—			5.6

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.

Overview – Unitil’s retail distribution utilities have the franchise to deliver electricity and/or natural gas to all customers in our 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 an 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 Massachusetts and New Hampshire, all of Unitil’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. Most small and medium-sized customers, however, continue to purchase such supplies through UES and FG&E as the providers of basic or default service energy supply. UES and FG&E purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

In connection with the implementation of retail choice, Unitil Power and FG&E divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the New Hampshire Public Utilities Commission (NHPUC) and Massachusetts Department of Public Utilities (MDPU) formerly the Massachusetts Department of Telecommunications and Energy, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, is $120.8 million as of March 31, 2007 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

FG&E – Electric Division – FG&E provides electric distribution service to customers under unbundled distribution rates approved by the MDPU. Its current retail electric distribution rates were approved by the MDPU in 2002. FG&E is required, as the provider of last resort, to purchase and provide power through Default Service for retail customers who chose not to buy, or were unable to purchase, energy from a competitive supplier. Prices for Default Service are set periodically based on market solicitations as approved by the MDPU. As of March 31, 2007, approximately 57 percent of FG&E’s electric load was served by Default Service. The remaining portion was served by competitive third party suppliers. The vast majority of customers being served by competitive third party suppliers are large commercial and industrial (C&I) customers. Most residential and small commercial customers continue to purchase their electric supply through the retail distribution utilities. The concentration of the competitive retail market on higher use customers within FG&E’s service area in Massachusetts has been a common experience throughout the New England electricity market.

As a result of the restructuring and the divestiture of FG&E’s owned generation assets and buyout of FG&E’s power supply obligations, Regulatory Assets on the Company’s balance sheets include the following three categories: Power Supply Buyout Obligations associated with the divestiture of its long-term purchase power obligations; Recoverable Deferred Restructuring Charges resulting from the restructuring legislation’s seven year rate cap; and Recoverable Generation-related Assets associated with the divestiture of its owned generation plant. FG&E earns carrying charges on the majority of the unrecovered balances of the Recoverable Deferred Restructuring Charges. The value of FG&E’s Recoverable Deferred Restructuring Charges and Recoverable Generation-related Assets was approximately $33.1 million at March 31, 2007, and $35.1 million at March 31, 2006, and is expected to be recovered in FG&E’s rates over the next three to five years. In addition, as of March 31, 2007, FG&E had recorded on its balance sheet $48.0 million as Power Supply Buyout Obligations and corresponding Regulatory Assets associated with the divestiture of its long-term purchase power contracts, which are included in Unitil’s consolidated financial statements, and on which carrying charges are not earned as the timing of cash disbursements and cash receipts associated with these long-term obligations is matched through rates.

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. This filing and FG&E’s 2005 filing are pending, subject to investigation. The Company expects that these filings will be approved without material changes or adjustments.

FG&E – Gas Division – FG&E provides natural gas delivery service to its customers on a firm or interruptible basis under unbundled distribution rates approved by the MDTE. Its current retail distribution rates were approved by the MDPU in 2007. FG&E's customers may purchase gas supplies from third-party vendors or purchase their gas from FG&E as the provider of last resort. FG&E collects its gas supply costs through a seasonal reconciling Cost of Gas Adjustment Clause and recovers other related costs through a reconciling Local Distribution Adjustment Clause.

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 will phase-in gas distribution rate changes with an initial rate increase of $1.2 million as of February 1, 2007, and an additional $1.0 million increase 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 of September 7, 2006. 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.

UES – UES provides electric distribution service to its customers pursuant to rates approved by the NHPUC. Its current retail electric distribution rates were approved by the NHPUC in 2006 under the Settlement Agreement

discussed below. As the provider of last resort, UES also provides its customers with electric power through Default Service at rates which reflect UES' costs for wholesale supply with no profit or markup. UES procures Default Service power for its larger commercial and industrial customers on a quarterly basis, and for its smaller commercial and residential customers through a portfolio of longer term contracts on a semi-annual basis. UES recovers its costs for this service on a pass-through basis through reconciling rate mechanisms. As of March 31, 2007, approximately 79 percent of UES’ electric load was served by Default Service. The remaining portion was served by competitive third party suppliers. The vast majority of customers being served by competitive third party suppliers are large C&I customers. Most residential and small commercial customers continue to purchase their electric supply through the retail distribution utilities. The concentration of the competitive retail market on higher use customers within UES’ service area in New Hampshire has been a common experience throughout the New England electricity market.

In the 2002 restructuring settlement, the NHPUC approved the divestiture of the long-term power supply portfolio by Unitil Power and tariffs for UES for stranded cost recovery, including certain charges that remain subject to annual or periodic reconciliation or future review. As of March 31, 2007, UES had recorded on its balance sheets $39.6 million as Power Supply Contract Obligations and corresponding Regulatory Assets associated with these long-term purchase power stranded costs, which are included in Unitil Corporation’s consolidated financial statements. These Power Supply Contract Obligations are expected to be recovered principally over a period of approximately three years. The Company does not earn carrying charges on these regulatory assets as the timing of cash receipts and cash disbursements associated with these long-term obligations is matched through rates.

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. The filing is pending, subject to investigation.

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 annually, 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.

FERC – Wholesale Power Markets – FG&E, UES and Unitil Power, as well as virtually all New England electric utilities, are participants in ISO New England Inc., the RTO in New England. The regional bulk power system is operated by an independent corporate entity, ISO-NE. The purpose of ISO-NE is to assure reliable operation of the bulk power system in the most economic manner for the region. Substantially all operation and dispatching of electric generation and bulk transmission capacity in New England are performed on a regional basis. The ISO-NE Tariff imposes generating capacity and reserve obligations, and provides for the use of major transmission facilities and support payments associated therewith. The most notable benefits of the ISO-NE are coordinated power system operation in a reliable manner and a supportive business environment for the development of a competitive electric marketplace. The formation of an RTO and other wholesale market changes are not expected to have a material impact on Unitil’s operations because of the cost recovery mechanisms for wholesale energy and transmission costs approved by the MDPU and NHPUC.

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 March 31, 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.

Sawyer Passway MGP Site – FG&E continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows FG&E to work towards temporary closure of the site. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed.

FG&E has recovered the environmental response costs incurred at this former MGP site in gas rates pursuant to an MDTE approved settlement agreement between the Massachusetts Attorney General and the natural gas utilities of the Commonwealth of Massachusetts (Agreement). The Agreement allows FG&E to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs. In addition FG&E has filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. Any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers.

FG&E is in the process of developing long range plans for a feasible permanent remediation solution for the Sawyer Passway site, including alternatives for re-use of the site. Included on the Company’s Consolidated Balance Sheet at March 31, 2007 in Environmental Obligations is $12.0 million related to estimated future clean up costs for permanent remediation of the site. A corresponding regulatory asset was recorded to reflect the future rate recovery for these costs. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties.

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

NOTE 8: 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 March 31,
	2007			2006
Components of NPPC (000’s)
Service Cost	$	492		$	450
Interest Cost		834			787
Expected Return on Plan Assets		(1,047	)		(912	)
Amortization of Prior Service Cost		27			27
Amortization of Net (Gain) Loss		336			355

Subtotal NPPC		642			707
Amounts Capitalized and Deferred		(217	)		(577	)

NPPC Recognized	$	425		$	130


Key Assumptions (Weighted Average)	2007		2006
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 March 31, 2007, the Company has not yet made any contributions to the Plan for 2007. The Company expects to contribute approximately $4.4 million to fund its pension plan 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.

As discussed above, on October 27, 2004 the MDTE approved FG&E’s request for a reconciliation rate adjustment mechanism, the PAF, to recover the costs associated with the Company's pension and PBOP costs on an annually reconciling basis. As discussed above, on October 6, 2006, the NHPUC approved a Settlement Agreement, resolving all issues in UES’ electric distribution base rate case filed in November 2005. As part of the Settlement Agreement, UES is allowed to recover its pension and PBOP expenses in base rates.

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 March 31,
	2007			2006
Components of NPPBC (000’s)
Service Cost	$	358		$	292
Interest Cost		514			450
Expected Return on Plan Assets		(61	)		(28	)
Amortization of Prior Service Cost		340			340
Amortization of Transition (Asset) Obligation		5			5
Amortization of Net (Gain) Loss		17			—

Subtotal NPPBC		1,173			1,059
Amounts Capitalized and Deferred		(513	)		(482	)

NPPBC Recognized	$	660		$	577


Weighted-Average Assumptions	2007	2006
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 March 31, 2007, the Company has made $0.5 million of contributions to the PBOP Plan. The Company presently anticipates contributing an additional $1.7 million to fund the Plan in 2007 for an estimated total of $2.2 million. 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 March 31,
	2007		2006
Components of NPPC (000’s)
Service Cost	$	41	$	36
Interest Cost		29		26
Amortization of Transition Obligation		—		4
Amortization of Net Loss		11		10

Net Periodic SERP Cost	$	81	$	76

Employer Contributions – As of March 31, 2007, the Company has made payments of $18,000 to beneficiaries. The Company presently anticipates making additional benefit payments of $54,000 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 March 31, 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, 2003; December 31, 2004; and December 31, 2005. Income tax filings for the year ended December 31, 2006 have been extended and are due September 15, 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 March 31, 2007.

(b) Not applicable.


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⁾
1/1/07 – 1/31/07	1,163 995	$ $	25.463 25.500	1,163 995	n/a n/a
2/1/07 – 2/28/07	—		—	—	n/a
3/1/07 – 3/31/07	289	$	27.095	289	n/a

Total	2,447	$	25.671	2,447	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.

Item 6.

Exhibits

(a) Exhibits


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

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

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

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

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

99.1	Unitil Corporation Press Release Dated April 26, 2007 Announcing Earnings For the Quarter Ended March 31, 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: April 27, 2007				/s/ Mark H. Collin
				Mark H. Collin
				Chief Financial Officer

Date: April 27, 2007				/s/ Laurence M. Brock
				Laurence M. Brock
				Chief Accounting Officer