Edgar Filing: UNITIL CORP

Cash Provided by Operating Activities (000’s)

20,373

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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 offices)		(Zip Code)

Registrant’s telephone number, including area code: (603) 772-0775

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Exchange on Which Registered
Common Stock, No Par Value		American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K x

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

Based on the closing price of June 30, 2006, the aggregate market value of common stock held by non-affiliates of the registrant was $132,492,742.

The number of common shares outstanding of the registrant was 5,660,619 as of February 21, 2007.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 19, 2007, are incorporated by reference into Part III of this Report

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2006

Table of Contents


Item	Description	Page
	PART I
1.	Business
	Unitil Corporation	2
	Operations	3
	Rates and Regulation	4
	Electric Power Supply	5
	Gas Supply	6
	Environmental Matters	7
	Employees	7
	Available Information	8
	Directors and Executive Officers of the Registrant	8
	Investor Information	10
1A.	Risk Factors	11
1B.	Unresolved Staff Comments	15
2.	Properties	15
3.	Legal Proceedings	16
4.	Submission of Matters to a Vote of Security Holders	16

	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
6.	Selected Financial Data	20
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
7A.	Quantitative and Qualitative Disclosures about Market Risk	41
8.	Financial Statements and Supplementary Data	42
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
9A.	Controls and Procedures	82
9B.	Other Information	82

	PART III
10.	Directors and Executive Officers of the Registrant .	83
11.	Executive Compensation .	83
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83
13.	Certain Relationships and Related Transactions .	83
14.	Principal Accountant Fees and Services	83

	PART IV
15.	Exhibits and Financial Statement Schedules	84
	Signatures	88


Exhibit 11.1		Computation in Support of Earnings per Share
Exhibit 12.1		Computation in Support of Ratio of Earnings to Fixed Charges
Exhibit 21.1		Subsidiaries of Registrant
Exhibit 23.1		Consent of Independent Registered Public Accounting Firm
Exhibit 23.2		Consent of Independent Registered Public Accounting Firm
Exhibits 31.1-31.3		Certifications of Chief Executive Officer, Chief Financial Officer and 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.
Exhibit 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.

PART I

Item 1.

Business

UNITIL CORPORATION

Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil was incorporated under the laws of the State of New Hampshire in 1984. The following companies are wholly-owned subsidiaries of Unitil:


Unitil Corporation Subsidiaries	State and Year of Organization	Principal Type of Business
Unitil Energy Systems, Inc. (UES)	NH - 1901	Retail Electric Distribution Utility
Fitchburg Gas and Electric Light Company (FG&E)	MA - 1852	Retail Electric & Gas Distribution Utility
Unitil Power Corp. (Unitil Power)	NH - 1984	Wholesale Electric Power Utility
Unitil Service Corp. (Unitil Service)	NH - 1984	Utility Service Company
Unitil Realty Corp. (Unitil Realty)	NH - 1986	Real Estate Management
Unitil Resources, Inc. (Unitil Resources)	NH - 1993	Non-regulated Energy Services
Usource Inc. and Usource L.L.C. (Usource)	DE - 2000	Energy Brokering and Advisory Services

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.

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. Unitil has two distribution utility subsidiaries, UES, which operates in New Hampshire and FG&E, which operates in Massachusetts (collectively referred to as the “retail distribution utilities”). Unitil’s 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” utility distribution companies with a combined investment in net utility plant of $231.8 million at December 31, 2006. Unitil’s total revenue was $260.9 million in 2006. Earnings applicable to common shareholders for 2006 was $7.9 million. Substantially all of Unitil’s revenue and earnings are derived from regulated utility operations.

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 substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with those contracts.

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 energy brokering and advisory services to large commercial and industrial customers in the northeastern United States.

OPERATIONS

Electric Utility Operations

Unitil’s electric utility operations are conducted through the retail distribution utilities, UES and FG&E. Revenue from Unitil’s electric utility operations was $225.2 million for 2006. Earnings from electric utility operations were $7.0 million for the same 12-month period.

The primary business of Unitil’s electric utility operations is the local distribution of electricity to customers in its franchise areas. 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 continue to deliver that supply of electricity over their distribution systems. Both UES and FG&E supply electricity 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.

UES distributes electricity to approximately 71,600 customers in New Hampshire in the capital city of Concord as well as 12 surrounding towns and all or part of 16 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. UES’ franchise areas consist of approximately 408 square miles. The state capital of New Hampshire is located within UES’ franchise areas, and includes the executive, legislative and judicial branches and offices and facilities for all major state government services as well as several federal government facilities. In addition, UES’ franchise areas are retail trading and recreation centers for the central and southeastern parts of the state. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wires and plastics. UES’ franchise areas include popular resort areas and beaches along the Atlantic Ocean, including the Hampton Beach recreational area. UES’ 2006 retail electric operating revenue was $155.8 million, of which approximately 45.0% was derived from residential sales and 55.0% from commercial/industrial sales.

FG&E is engaged in the retail distribution of both electricity and natural gas in the city of Fitchburg and several surrounding communities. FG&E’s franchise area encompasses approximately 170 square miles. Electricity is supplied and distributed by FG&E to approximately 27,700 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. FG&E’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries. FG&E’s 2006 retail electric operating revenue was $69.4 million, of which approximately 46.0% was derived from residential sales and 54.0% from commercial/industrial sales.

Gas Utility Operations

Natural gas is supplied and distributed by FG&E to approximately 15,000 retail customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts.

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.

FG&E’s 2006 gas operating revenue was $33.3 million, of which approximately 51.0% was derived from residential firm sales and 49.0% from commercial/industrial firm sales. Earnings from FG&E’s gas utility operations were $0.5 million for 2006.

Seasonality

Natural gas sales in New England are seasonal, and the Company’s results of operations reflect this seasonal nature. Accordingly, results of operations are typically positively impacted by gas operations during the five heating season months, from November through March. Electric sales in New England are far less seasonal than natural gas sales; however, the highest usage typically occurs in both the summer due to air conditioning demand and the winter months due to heating-related requirements and shorter daylight hours.

Non-regulated and Other Non-Utility Operations

Unitil’s non-regulated operations are conducted through Unitil Resources and its subsidiary Usource. Usource provides energy brokering and consulting services to large commercial and industrial customers in the northeastern United States. Revenue from Unitil’s non-regulated operations was $2.4 million in 2006. Earnings from Unitil’s non-regulated operations was a net loss of ($0.2 million) in 2006. Unitil’s other non-utility 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. The earnings of these other non-utility operations are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and is reported in Other segment income (for segment information, see Part II, Item 8, Note 10 herein). Net earnings from Unitil’s other non-utility operations was $0.6 million in 2006.

(For details on Unitil’s Results of Operations, see Part II, Item 7 herein.)

RATES AND REGULATION

Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 in regards to certain bookkeeping, accounting and reporting requirements. Unitil’s utility operations related to wholesale and interstate energy business activities are also regulated by FERC. 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 Telecommunications and Energy (MDTE), 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 a restructuring of the utility industry in Massachusetts and New Hampshire, Unitil’s customers have the opportunity to purchase their electric or natural gas supplies from third party vendors. Most customers, however, continue to purchase such supplies through UES and FG&E as the provider of last resort. UES and FG&E purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

regulatory assets. The remaining balance of these assets, to be recovered principally over the next four to six years, is $126.1 million as of December 31, 2006 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet (see Regulatory Assets table in Note 1.) 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.

ELECTRIC POWER SUPPLY

The transition to retail choice required the divestiture of Unitil’s existing power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility service. FG&E, UES, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s retail customers.

Unitil’s customers in both New Hampshire and Massachusetts now have the opportunity to purchase their electric supply from competitive retail suppliers. Retail choice has been successful for Unitil’s largest customers. As of December 2006, 45% of Unitil’s largest New Hampshire customers representing 18% of total New Hampshire electric sales and 87% of Unitil’s largest Massachusetts customers representing 42% of total Massachusetts electric sales are purchasing their electric power supply in the competitive market. However, 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 has been a common experience throughout the New England electricity market.

Regulated Energy Supply

In order to provide regulated electric supply as the provider of last resort to their respective retail customers, the retail distribution companies enter into wholesale electric power supply contracts with various wholesale suppliers.

FG&E has power supply contracts with various wholesale suppliers for the provision of Default Service. MDTE policy dictates the pricing structure and duration of each of these contracts. Currently, all Default Service power supply contracts for large general accounts are three months in duration. Default Service power supply contracts for residential and small and medium general service customers are acquired every 6 months, with each 12 month contract providing 50% of the class requirements. The MDTE is investigating alternatives to the current procurement policy for all accounts, other than the large general accounts. This process could potentially lead to the procurement of FG&E Default Service power supply for longer durations in order to provide more price stability for smaller customers throughout Massachusetts for whom competitive retail options are relatively scarce.

UES currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. UES procures Default Service for its largest general service accounts through successive competitive solicitations of three-months duration and procures Default Service for all other customers through a series of two one-year contracts and two three-year contracts with each contract covering 25% of the total requirements of the group. The first two contracts were of 6-months and 18-months duration in order to stagger the start dates of future 1-year and 3-year procurements.

Regional Transmission and 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 Regional Transmission Organization (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 is performed on a regional basis. The 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 MDTE and NHPUC.

GAS SUPPLY

FG&E’s natural gas customers now have the opportunity to purchase their natural gas supply from third-party suppliers, though most customers continue to purchase such supplies at regulated rates through FG&E as the provider of last resort. The costs associated with the acquisition of such wholesale natural gas supplies for customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically-adjusted rates and are included in Purchased Gas in the Consolidated Statements of Earnings.

FG&E purchases natural gas from domestic and Canadian suppliers under contracts of one year or less, as well as from producers and marketers on the spot market and arranges for the transportation to its distribution facilities under long-term contracts with the Tennessee interstate pipeline. FG&E has a four-year contract for liquefied natural gas (LNG) supply ending in 2008, which was approved by the MDTE. The following tables summarize actual gas purchases by source of supply and the cost of gas sold for the years 2004 through 2006.

Sources of Gas Supply

(Expressed as percent of total MMBtu of gas purchased)


	2006			2005			2004
Natural Gas:
Domestic firm		84.2	%		84.8	%		85.0	%
Canadian firm		2.0	%		3.4	%		5.4	%
Domestic spot market		11.0	%		9.3	%		5.9	%

Total natural gas		97.2	%		97.5	%		96.3	%
Supplemental gas		2.8	%		2.5	%		3.7	%

Total gas purchases		100.0	%		100.0	%		100.0	%


Cost of Gas Sold

	2006			2005			2004
Cost of gas purchased and sold per MMBtu	$	11.18		$	10.83		$	8.42
Percent Increase from prior year		3.2	%		28.7	%		17.9	%

FG&E has available under firm contract 14,057 MMbtu per day of year-round and seasonal transportation and underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, FG&E owns a propane air gas plant and a LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

ENVIRONMENTAL MATTERS

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 December 31, 2006, 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 December 31, 2006 in Environmental Obligations is $12.0 million related to estimated future 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.

EMPLOYEES

As of December 31, 2006, the Company and its subsidiaries had 304 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

There are approximately 100 employees represented by labor unions. These employees are covered by collective bargaining agreements, which expire May 31, 2010. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages. The Company expects to successfully negotiate new agreements prior to their expiration dates.

AVAILABLE INFORMATION

The Company’s Internet address is www.unitil.com. There, the Company makes available, free of charge, its SEC fillings, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other reports, as well as amendments to those reports. These reports are made available through the Investors section of Unitil’s website via a direct link to the section of the SEC’s website which contains Unitil’s SEC filings.

The Company’s current Code of Ethics was approved by Unitil’s Board of Directors on January 15, 2004. This Code of Ethics, along with any amendments or waivers, is also available on Unitil’s website.

Unitil’s common stock is listed on the American Stock Exchange under the ticker symbol “UTL.”

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides information about our directors and senior management as of February 21, 2007:


Name	Age	Position
Robert G. Schoenberger	56	Chairman of the Board, Chief Executive Officer and President
Mark H. Collin	47	Senior Vice President, Chief Financial Officer and Treasurer
Thomas P. Meissner, Jr.	44	Senior Vice President and Chief Operating Officer
Laurence M. Brock	53	Controller and Chief Accounting Officer
Todd R. Black	42	President, Usource
George R. Gantz	55	Senior Vice President, Customer Services and Communications, Unitil Service Corp.
George E. Long, Jr.	50	Vice President, Administration, Unitil Service Corp.
Raymond J. Morrissey	59	Vice President, Information Systems
Sandra L. Whitney	43	Corporate Secretary
Dr. Robert V. Antonucci	61	Director
David P. Brownell	63	Director
Michael J. Dalton	66	Director
Albert H. Elfner, III	62	Director
Edward F. Godfrey	57	Director
Michael B. Green	57	Director
Eben S. Moulton	60	Director
M. Brian O’Shaughnessy	63	Director
Charles H. Tenney, III	59	Director
Dr. Sarah P. Voll	64	Director

Robert G. Schoenberger has been Unitil’s Chairman of the Board and Chief Executive Officer since 1997 and Unitil’s President since 2003. Prior to his employment with Unitil, he was President and Chief Executive Officer of the New York Power Authority (a state owned public power enterprise) from 1993 until 1997. He is also a Trustee and Chairman of Exeter Health Resources.

Mark H. Collin has been Unitil’s Senior Vice President and Chief Financial Officer since February 2003. Mr. Collin has served as Unitil’s Treasurer since 1998. Since 1992, he has been Treasurer of UES and FG&E. Mr. Collin joined Unitil in 1988. Mr. Collin serves on the Board of Governors of New Hampshire Public Television.

Thomas P. Meissner, Jr. has been Unitil’s Senior Vice President and Chief Operating Officer since June 2005. Mr. Meissner served as Unitil’s Senior Vice President, Operations from February 2003 through June 2005. Mr. Meissner joined Unitil in 1994 and served as Unitil’s Director of Engineering from 1998 to 2003. From 1985 to 1994, he was employed by the Public Service Company of New Hampshire.

Laurence M. Brock has been Unitil’s Chief Accounting Officer and Controller since June 2005. Mr. Brock joined Unitil in 1995 as Vice President and Controller, and is a Certified Public Accountant in the State of New Hampshire. Prior to his employment with Unitil, Mr. Brock served as a Corporate Controller with a group of diversified financial services and manufacturing companies. Mr. Brock gained his public accounting experience with Coopers & Lybrand in Boston, Massachusetts.

Todd R. Black has been President of Usource since June 2003. He served as Vice President, Sales and Marketing for Usource from 1998 to 2003. Prior to his employment with Unitil, he served as Vice President, Services Delivery for Energy USA, the non-regulated subsidiary of Bay State Gas Company, from 1988 until 1998.

George R. Gantz has been Unitil’s Senior Vice President, Customer Services and Communications since January 2003. Mr. Gantz previously served as Unitil’s Senior Vice President, Communication and Regulation from 1994 to 2003. Mr. Gantz joined Unitil in 1983.

George E. Long, Jr. has been Unitil’s Vice President, Administration since February 2003. Mr. Long joined Unitil in 1994 and was Director, Human Resources from 1998 to 2003. Prior to his employment with Unitil, Mr. Long was the Director of Compensation and Benefits at Monarch Life Insurance Company from 1985 to 1994.

Raymond J. Morrissey has been Unitil’s Vice President, Information Systems since February 2003. From 1992 to 2003, he served as Unitil’s Vice President of Customer Service, and from 1991 to 1992, he was the General Manager of Unitil’s subsidiary, FG&E. Mr. Morrissey joined Unitil in 1985.

Sandra L. Whitney has been Unitil’s Corporate Secretary and Secretary of the Board since February 2003. Ms. Whitney has been the Corporate Secretary of Unitil’s subsidiary companies, FG&E, UES, Unitil Power, Unitil Realty and Unitil Service since 1994. Ms. Whitney joined Unitil in 1990.

Dr. Robert V. Antonucci has been President of Fitchburg State College since 2003. Dr. Antonucci was also President of the School Group of Riverdeep, Inc. from 2001 to 2003, and President and CEO of Harcourt Learning Direct and Harcourt Online College from 1998 to 2001. Dr. Antonucci also served as the Commissioner of Education for the Commonwealth of Massachusetts from 1992 to 1998. Dr. Antonucci also serves as a Director of Eastern Bank.

David P. Brownell was a Senior Vice President of Tyco International Ltd. from 1995 until his retirement in 2003. He had been with Tyco since 1984. Mr. Brownell is also Interim President of the University of New Hampshire Foundation.

Michael J. Dalton was Unitil’s President and Chief Operating Officer from 1984 until his retirement in 2003. Mr. Dalton is a member of the Industrial Advisory Board of the University of New Hampshire College of Engineering and Physical Sciences.

Albert H. Elfner, III was the Chairman, from 1994, and Chief Executive Officer, from 1995, of Evergreen Investment Management Company until his retirement in 1999. Mr. Elfner is also a Director of NGM Insurance Company (NGM), as well as a member of the NGM Finance Committee.

Edward F. Godfrey was the Executive Vice President and Chief Operating Officer of Keystone Investments, Incorporated from 1997 until his retirement in 1998. While at Keystone Investments, he was also a Senior Vice President, Chief Financial Officer and Treasurer from 1988 to 1996. Mr. Godfrey is also a Director of VehiCare, LLC since 2006.

Michael B. Green has been the President and Chief Executive Officer of Capital Region Health Care and Concord Hospital since 1992. Mr. Green is also a member of the Adjunct Faculty, Dartmouth Medical School, Dartmouth College. He also currently serves on the Board of the Foundation for Healthy Communities, is a Director and Chair of the New Hampshire Hospital Association, a Director of New Hampshire Business Committee for the Arts, a Director of Merrimack County Savings Bank, including membership on the bank’s Investment and Audit Committees, and a member of the Concord Monitor Board of Contributors.

Eben S. Moulton has been the Managing Partner of Seacoast Capital Corporation since 1995. Mr. Moulton is also a Director of IEC Electronics, a Director of six private companies and a Trustee of Colorado College.

M. Brian O’Shaughnessy has been the Chairman of the Board, Chief Executive Officer and President of Revere Copper Products, Inc. since 1988. Mr. O’Shaughnessy also serves on the Board of Directors of the National Association of Manufacturers, the International Copper Association, the Copper Development Association, and the Copper and Brass Fabricators Council. He also serves in New York State as Chairman of the Industrial Energy Consumer Coalition, and as a member of the Board of Directors of the Multiple Intervenors.

Charles H. Tenney, III has been Director of Operations for Brainshift.com, Inc. since 2002. He also served as a financial advisor for H&R Block Financial Advisors from 2001 to 2002. Mr. Tenney also served on the Board of Overseers of the Huntington Theater Company, Boston, Massachusetts from 2004 – 2006.

Dr. Sarah P. Voll has been the Vice President, National Economic Research Associates, Inc. (NERA) since 1999. Dr. Voll was also a Senior Consultant at NERA from 1996 to 1999. Prior to her employment with NERA, Dr. Voll was a staff member at the New Hampshire Public Utilities Commission from 1980 – 1996.

INVESTOR INFORMATION

Annual Meeting

The annual meeting of shareholders is scheduled to be held at the offices of the Company, 6 Liberty Lane West, Hampton, New Hampshire, on Thursday, April 19, 2007, at 10:30 a.m.

Transfer Agent

The Company’s transfer agent, Computershare, is responsible for shareholder records, issuance of stock certificates, and the distribution of Unitil’s dividends and IRS Form 1099-DIV. Shareholders may contact Computershare at:

Computershare

P.O. Box 43078

Providence, RI 02940-3078

Telephone: 800-736-3001

www.computershare.com

Investor Relations

For information about the Company and your investment, you may call the Company directly, toll-free, at: 800-999-6501 and ask for the Investor Relations Representative; visit the Investor page at www.unitil.com; or contact the transfer agent, Computershare, at the number listed above.

Special Services & Shareholder Programs Available

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Internet Account Access is available at www.computershare.com.

•

Dividend Reinvestment Plan:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

•

Dividend Direct Deposit Service:

To enroll, please contact the Company’s Investor Relations Representative or Computershare.

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Direct Registration:

For information, please contact Computershare at 800-935-9330 or the Company’s Investor Relations Representative at 800-999-6501.

Item 1A.

Risk Factors

Risks Relating to Our Business

Risks related to the regulation of our business could impact the rates we are able to charge, our costs and our profitability.

We are subject to comprehensive regulation by federal and state regulatory authorities, which significantly influences our operating environment and our ability to recover costs from our customers. In particular, we are regulated by the FERC and state regulatory authorities with jurisdiction over public utilities, including the NHPUC and the MDTE. These authorities regulate many aspects of our operations, including, but not limited to, construction and maintenance of facilities, operations, safety, issuance of securities, accounting matters, transactions between affiliates, the rates that we can charge customers and the rate of return that we are allowed to realize. Our ability to obtain rate adjustments to maintain our current rate of return depends upon regulatory action under applicable statutes, rules and regulations, and we cannot assure you that we will be able to obtain rate adjustments or continue receiving our current authorized rates of return. These regulatory authorities are also empowered to impose financial penalties and other sanctions on us if we are found to have violated statutes and regulations governing our utility operations.

We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Although we have attempted to actively manage the rate making process and have had recent success in obtaining rate increases, we can offer no assurances as to future success in the rate making process. Despite our requests, these regulatory commissions have authority under applicable statutes, rules and regulations to leave our rates unchanged, grant increases or order decreases in such rates. They have similar authority with respect to the recovery of our electricity and natural gas supply costs incurred by UES and FG&E in their role as a “provider of last resort” for customers who do not contract with third-party suppliers, or whose third-party supplier fails to deliver. In the event that we are unable to recover these costs or recovery of these costs were to be significantly delayed, our operating results could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have an adverse effect on our operating results.

As a result of industry restructuring, we have a significant amount of certain stranded energy supply costs, which are subject to recovery in future periods.

The stranded costs resulting from the implementation of industry restructuring mandated by the states of New Hampshire and Massachusetts are recovered by us on a pass-through basis through periodically adjusted rates. Any unrecovered balance of purchased power or stranded costs is deferred for future recovery as a regulatory asset. Such regulatory assets are subject to periodic regulatory review and approval for recovery in future periods.

Our power supply portfolio related stranded costs due to the electric industry restructuring in New Hampshire and Massachusetts for which regulatory approval has been obtained for recovery were approximately $50.0 million for FG&E and $42.6 million for UES as of December 31, 2006 (See total of $92.6 million on the Power Supply Buyout Obligations line of Regulatory Assets table of Note 1). Substantially all of FG&E’s stranded costs relate to owned generation assets and power purchase agreements divested by FG&E under a long-term contract buy-out agreement. Approximately $18.4 million of UES’ stranded costs are attributable to the long-term power purchase agreements divested by Unitil Power under a long-term contract buyout agreement. Because FG&E and Unitil Power remain ultimately responsible for purchase power payments underlying these long-term buyout agreements, FG&E and Unitil Power could incur additional stranded costs were they required to resell such divested entitlements prior to the end of their term for amounts less than the amounts agreed to under the existing long-term buyout agreements. We expect that any such additional stranded costs would be recovered from our customers, although such recovery would require approval from the MDTE or NHPUC, the receipt of which cannot be assured.

Our electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may negatively impact our customers and correspondingly our operating results and financial condition.

Our business is influenced by the economic activity of our franchise areas. The level of economic growth in our electric and natural gas distribution franchise areas directly affects our potential for future growth in our business. As a result, adverse changes in the economy may have negative effects on our revenues, operating results and financial condition.

Declines in the valuation of capital markets could require us to make substantial cash contributions to cover our pension obligations, which could negatively impact our financial condition. In addition, the recovery of certain pension obligations is subject to regulatory risks.

We made a voluntary cash contribution to our pension plan of $2.0 million in 2004. In 2005, we were required to make a minimum cash contribution of $0.7 million to our pension plan and made an additional voluntary cash contribution of $1.8 million for a total of $2.5 million. In 2006, we were required and made a minimum cash contribution of $2.5 million to our pension plan. If the valuation of capital markets were to significantly decline from current levels, we may be required to make cash contributions to our pension plans substantially in excess of the levels currently anticipated, which could adversely affect our financial condition.

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.

In September 2006, the Financial Accounting Standards Board (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. In the event that we are unable to recover these costs or recovery of these costs were to be significantly delayed, our operating results could be materially adversely affected. See Note 8 also.

Increases in interest rates could have a negative impact on our financial condition.

Our utility subsidiaries have ongoing capital expenditure requirements which they frequently fund by issuing short and long-term debt. Changes in interest rates do not affect interest expense associated with presently outstanding fixed rate long-term debt securities. However, changes in interest rates may affect the interest rate and corresponding interest expense on any new long-term debt securities that are issued. In addition, short-term debt borrowings are typically at variable rates of interest. As a result, changes in short-term interest rates will increase or decrease our interest expense associated with short-term borrowings. Increases in interest rates generally will increase our borrowing costs and could adversely affect our financial condition or results of operations.

Weather conditions may cause our sales to vary from year to year.

Our utility operating sales vary from year to year, depending on weather conditions. We estimate that approximately 75% of our annual natural gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year, particularly during the winter heating season. Our electric sales are generally less sensitive to weather than our gas sales, but may also be affected by weather conditions in both the winter and summer seasons.

We are a holding company and have no operating income of our own. Our ability to pay dividends on our common stock is dependent on dividends received from our subsidiaries and on factors directly affecting us, the parent corporation. We cannot assure you that our current annual dividend will be paid in the future.

We are a public utility holding company and we do not have any operating income of our own. Consequently, our ability to pay dividends on our common stock is dependent on dividends and other payments received from our subsidiaries, principally UES and FG&E. The ability of our subsidiaries to pay dividends or make distributions to us will depend on, among other things:

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the actual and projected earnings and cash flow, capital requirements and general financial condition of our subsidiaries;

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the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by our subsidiaries;

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the restrictions on the payment of dividends contained in the existing loan agreements of UES and FG&E and that may be contained in future debt agreements of our subsidiaries, if any;

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limitations imposed by New Hampshire and Massachusetts state regulatory agencies, which, among other things, may prohibit the payment of dividends by subsidiaries out of capital or unearned surplus without prior approval.

In addition, we may incur indebtedness in the future. Before we can pay dividends on our common stock, we have to satisfy our debt obligations and comply with any statutory or contractual limitations.

Our current annual dividend is $1.38 per share of common stock, payable quarterly. However, our board of directors reviews our dividend policy periodically in light of the factors referred to above, and we cannot assure you of the amount of dividends, if any, that may be paid in the future.

Transporting and storing natural gas and supplemental gas supplies, as well as electricity, involve numerous risks that may result in accidents and other operating risks and costs.

Inherent in our electric and gas distribution activities are a variety of hazards and operating risks, such as leaks, explosions, electrocutions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, and impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines, storage facilities and electric distribution equipment near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our financial position and results of operations.

Our business is subject to environmental regulation in all jurisdictions in which we operate and our costs of compliance are significant. Any changes in existing environmental regulation and the incurrence of environmental liabilities could negatively affect our results of operations and financial condition.

Our utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and the health and safety of our employees. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; imposition of remedial requirements; and even issuance of injunctions to ensure future compliance. Liability under certain environmental laws is strict, joint and several in nature. Although we believe we are in general compliance with all applicable environmental and safety laws and regulations, there can be no assurance that significant costs and liabilities will not be incurred in the future. Moreover, 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. See “Environmental Matters” in the Part I, Item 1, and Note 5 of this report for further detail.

Catastrophic events could have a material adverse effect on our financial condition or results of operations.

The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could have a material adverse effect on us, since they could inhibit our ability to continue providing electric and/or gas distribution services to our customers for an extended period, which is the principal source of our operating income.

Customers’ future performance under multi-year energy brokering contracts.

The Company’s non-regulated energy brokering business provides energy brokering and consulting services to large commercial and industrial customers in the northeastern United States. Revenues from this business are primarily derived from brokering fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts. The Company cannot guarantee customers’ future performance under multi-year energy brokering contracts.

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

As of December 31, 2006, Unitil owned, through its retail distribution utilities: two operation centers, approximately 2,155 pole miles of local transmission and distribution overhead electric lines and 518 conduit bank miles of underground electric distribution lines, along with 59 electric substations, including three mobile electric substations. FG&E’s natural gas operations property includes a liquid propane gas plant, a liquid natural gas plant and 317 miles of underground gas mains. In addition, Unitil’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the 12 acres on which it is located.

UES owns and maintains distribution operations centers in Concord, New Hampshire and Kensington, New Hampshire. UES’ 37 electric distribution substations, including a 5,000 kilovolt ampere (kVA) mobile substation, constitute 257,315 kVA of capacity (includes spares and mobile) for the transformation of electric energy from the 34.5 kV sub-transmission voltage to other primary distribution voltage levels. The electric substations are located on land owned by UES or occupied by UES pursuant to a perpetual easement.

UES has a total of approximately 1,598 pole miles of local transmission and distribution overhead electric lines and a total of 342 conduit bank miles of underground electric distribution lines. The electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by UES without objection by the owners. In the case of certain distribution lines, UES owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone companies.

Additionally, UES owns 139.2 acres of non-utility property located on the east bank of the Merrimack River in Concord, New Hampshire. Of the total acreage, 81.2 acres are located within an industrial park zone.

The physical utility properties of UES, with certain exceptions, and its franchises are pledged as security under its indenture of mortgage and deed of trust under which the respective series of first mortgage bonds of UES are outstanding.

FG&E’s electric properties consist principally of 557 pole miles of local transmission and distribution overhead electric lines, 176 conduit bank miles of underground electric distribution lines and 22 transmission and distribution stations including two mobile electric substations. The capacity of these substations totals 662,650 kVA.

FG&E owns a liquid propane gas plant and a liquid natural gas plant and the land on which they are located. FG&E also has 317 miles of underground steel, cast iron and plastic gas mains.

FG&E’s electric substations, with minor exceptions, are located on land owned by FG&E or occupied by FG&E pursuant to a perpetual easement. FG&E’s electric distribution lines and gas mains are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by FG&E without objection by the owners. FG&E leases its distribution operations center located in Fitchburg, Massachusetts.

The Company believes that its facilities are currently adequate for their intended uses.

Item 3.

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 Note 5 to the Consolidated Financial Statements. The Company believes, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

Item 4

Submission of Matters to a Vote of Security Holders

None

PART II

Item 5

Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

The Registrant’s Common Stock is traded on the American Stock Exchange. As of December 31, 2006, there were 1,389 Common Shareholders of record.

Common Stock Data


Dividends per Common Share					2006		2005
1st Quarter					$	0.345	$	0.345
2nd Quarter						0.345		0.345
3rd Quarter						0.345		0.345
4th Quarter						0.345		0.345

Total for Year					$	1.38	$	1.38


	2006				2005
Price Range of Common Stock	High/Ask		Low/Bid		High/Ask		Low/Bid
1st Quarter	$	26.11	$	24.59	$	27.80	$	25.50
2nd Quarter	$	26.05	$	23.70	$	28.05	$	25.31
3rd Quarter	$	24.97	$	23.80	$	28.70	$	27.00
4th Quarter	$	26.09	$	23.82	$	28.10	$	24.37

Information regarding Securities Authorized for Issuance Under Equity Compensation Plans is set forth in the table below.

EQUITY COMPENSATION PLAN BENEFIT INFORMATION


	(a)	(b)		(c)
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders
KESOP (1)	40,388	$	11.25	29,101
Restricted Stock Plan (2)	—		N/A	121,905
Equity compensation plans not approved by security holders
1998 Option Plan (3)	107,000	$	27.13	—

Total	147,388	$	22.78	151,006

NOTES: (also see Note 2 to the Consolidated Financial Statements)

(1)	The KESOP was approved by shareholders in July 1989. Options were granted between January 1989 and November 1997.

(2)

The Restricted Stock Plan was approved by shareholders in April 2003. 10,600 shares of restricted stock were awarded to Plan participants in May 2003; 10,700 shares of restricted stock were awarded to Plan participants in April 2004; 10,900 shares of restricted stock were awarded to Plan participants

in March 2005; 14,375 shares of restricted stock were awarded to Plan participants in February 2006; 9,020 shares of restricted stock were awarded to Plan participants in February 2007.

(3)

The 1998 Option Plan was adopted by the Board of Directors of the Company in December 1998. At the time of adoption, the 1998 Option Plan was not required, under American Stock Exchange rules, to obtain shareholder approval. Options were granted in March 1999, January 2000, and January 2001. On January 16, 2003, the Board of Directors terminated the Option Plan upon the recommendation of the Compensation Committee. In April 2004, the 177,500 remaining registered and ungranted shares in the Option Plan were deregistered with the Securities and Exchange Commission. The Option Plan will remain in effect solely for the purposes of the continued administration of all options currently outstanding under the Option Plan. No further grants of options will be made thereunder.

Stock Performance Graph

The following graph compares Unitil Corporation’s cumulative stockholder return since December 31, 2001 with the Peer Group index, comprised of the S&P Utility Index, and the S&P 500 index. The graph assumes that the value of the investment in the Company’s common stock and each index (including reinvestment of dividends) was $100 on December 31, 2001.

Comparative Five-Year Total Returns

LOGO

NOTES:

(1)	The graph above assumes $100 invested on December 31, 2001, in each category and the reinvestment of all dividends during the five-year period. The Peer Group is comprised of the S&P Utility Index.

Unregistered Sales of Equity Securities and Uses of Proceeds

(a) There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2006.

(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)
10/1/06 – 10/31/06	—	—	—	n/a
11/1/06 – 11/30/06	—	—	—	n/a
12/1/06 – 12/31/06	—	—	—	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.

Item 6.

Selected Financial Data


For the Years Ended December 31,	2006			2005			2004			2003			2002
(all data in thousands except % and per share data)
Consolidated Statements of Earnings:
Operating Revenue	$	260,861		$	232,145		$	214,137		$	220,654		$	188,386
Operating Income		15,855			15,541			15,193			15,449			13,248
(Gain) on Non-Utility Investments, net of tax		—			—			—			—			(82	)
Other Non-operating Expense (Income)		(19	)		147			193			(40	)		185

Income Before Interest Expense, net		15,874			15,394			15,000			15,489			13,145
Interest Expense, net		7,841			6,841			6,774			7,531			7,057

Net Income		8,033			8,553			8,226			7,958			6,088
Dividends on Preferred Stock		133			156			215			236			253

Earnings Applicable to Common Shareholders	$	7,900		$	8,397		$	8,011		$	7,722		$	5,835

Balance Sheet Data:
Utility Plant (Original Cost)	$	352,999		$	324,967		$	308,054		$	288,657		$	272,402
Total Assets	$	483,427		$	450,081		$	457,010		$	483,877		$	481,702
Capitalization:
Common Stock Equity	$	97,775		$	96,283		$	94,291		$	92,805		$	74,350
Preferred Stock		2,083			2,327			2,338			3,269			3,322
Long-Term Debt, less current portion		140,028			125,365			110,675			110,961			104,226

Total Capitalization	$	239,886		$	223,975		$	207,304		$	207,035		$	181,898

Current Portion of Long-Term Debt	$	336		$	308		$	285		$	3,263		$	3,243
Short-term Debt	$	26,000		$	18,700		$	25,675		$	22,410		$	35,990
Capital Structure Ratios:
Common Stock Equity		41	%		43	%		46	%		45	%		41	%
Preferred Stock		1	%		1	%		1	%		2	%		2	%
Long-Term Debt		58	%		56	%		53	%		53	%		57	%
Earnings Per Share Data:
Earnings Per Average Share—Basic and Diluted	$	1.41		$	1.51		$	1.45		$	1.58		$	1.23
Common Stock Data:
Shares of Common Stock—Diluted (Average)		5,612			5,568			5,525			4,896			4,762
Dividends Paid Per Share	$	1.38		$	1.38		$	1.38		$	1.38		$	1.38
Book Value Per Share (Year-End)	$	17.30		$	17.21		$	17.00		$	16.87		$	15.67
Electric and Gas Sales:
Electric Distribution Sales (kWh)		1,751,544			1,790,405			1,742,131			1,717,664			1,659,136
Firm Natural Gas Distribution Sales (Therms)		26,356			24,332			23,151			24,592			22,480

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) (Note references are to Notes to the Consolidated Financial Statements in Item 8.)

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 $231.8 million at December 31, 2006. Unitil’s total revenue was $260.9 million in 2006. Earnings applicable to common shareholders for 2006 was $7.9 million. 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. Usource’s total revenues were $2.4 million in 2006. 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.

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.

See also Item 1A. Risk Factors.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the three fiscal years ended December 31, 2006, 2005 and 2004 and should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Item 8 of this report.

Net Income and EPS Overview

The Company’s Earnings Applicable to Common Shareholders (Net Income) was $7.9 million for 2006. Earnings per common share were $1.41 for 2006 compared to $1.51 for 2005. Earnings in 2006 reflect lower electric and gas sales. The lower sales in 2006 were primarily driven by milder weather compared to 2005. Earnings in 2006 also reflect higher operating and maintenance expenses and interest costs. Partially offsetting these factors was an increase in electric distribution rates in 2006 for Unitil’s utility subsidiary in New Hampshire and increased gas delivery sales under a new contract with a large industrial customer in Massachusetts.

During the fourth quarter of 2006, the Company received final approval of a rate settlement that increased base distribution rates by about $3.1 million on an annualized basis for its electric utility operations in New Hampshire. The Company also recently received approval of a gas base rate settlement in Massachusetts for its gas distribution operations, which will phase-in rate increases of $1.2 million as of February 1, 2007, and an additional $1.0 million increase on November 1, 2007. Together these rate settlements represent an increase of about 10% on Unitil’s consolidated electric and gas distribution revenues.

Total electric sales decreased 2.2% in 2006 compared to 2005. This decrease reflects significantly milder weather in 2006 and overall lower average monthly energy usage by customers.

Total sales of natural gas increased 8.6% in 2006 compared to 2005, primarily due to a new transportation sales contract with a large industrial customer. Absent the sales from this new contract, total gas sales were approximately 10.7% lower in 2006 compared to 2005. These lower gas sales also reflect the significantly milder winter weather in 2006. The weather in the Company’s service territories in the winter of 2006 was approximately 12% warmer than in the same period for 2005, reflecting a record warm winter heating season.

Total electric and gas sales margin decreased $1.3 million in 2006 compared to 2005. The decline in average energy usage by customers, which was primarily driven by milder weather, negatively impacted total electric and gas sales margin by $1.7 million. This negative impact on electric and gas sales margin was partially offset by $0.4 million, net, due to changes in electric rates in 2006 compared to 2005, gas delivery sales under a new transportation contract with a large industrial customer, and higher revenues from Usource.

Total Operations & Maintenance expense increased $1.2 million in 2006 compared to 2005. This increase reflects higher retiree and employee benefit costs of $0.8 million, higher salaries and compensation expenses of $0.7 million and an increase in all other operating expenses of $0.2 million, net, partially offset by lower outside services expenses and professional fees of $0.5 million.

Depreciation, Amortization, Taxes and Other decreased $2.8 million in 2006 compared to 2005, due to lower amortization on regulatory assets and lower utility plant depreciation rates resulting from the New Hampshire rate settlement, partially offset by increased depreciation on utility plant additions and higher property and payroll taxes.

Interest Expense, Net increased $1.1 million in 2006 compared to 2005 due to higher borrowings and interest rates compared to last year.

Usource, our non-regulated energy brokering business, recorded revenues of $2.4 million in 2006, an increase of $0.4 million over 2005. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource. The Company will also realize future fees estimated at the end of December 2006 of $6.0 million from executed energy supply term contracts running from 2007 through 2011.

The Company’s Net Income was $8.4 million for 2005, an increase of $0.4 million, or 4.8%, compared to 2004. Earnings per common share were $1.51 for 2005, an increase of $0.06 per share compared with earnings of $1.45 per share for 2004. Compared to 2004, earnings for 2005 reflect higher electric sales, driven by customer growth and hotter summer weather in 2005, and higher gas sales reflecting a new contract with a large industrial customer.

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 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share.


Per Share Data	2006		2005		2004
Earnings per Common Share	$	1.41	$	1.51	$	1.45

Annual Dividend	$	1.38	$	1.38	$	1.38

A more detailed discussion of the Company’s 2006 results of operations and a year-to-year comparison of changes in financial position are presented below.

Balance Sheet

The Company’s investment in Net Utility Plant increased by $18.5 million in 2006 compared to 2005. This increase was due to capital expenditures related to UES’ and FG&E’s electric and gas distribution systems and expenditures of approximately $7.3 million for the Company’s Advanced Metering Infrastructure (AMI) project. AMI involves the integration of communication technology with metering technology to facilitate two-way communication between the utility and customer equipment. This technology is designed to provide more frequent, time-based metering information, enabling the recording and retrieval of interval metering data on at least an hourly basis.

Regulatory Assets increased $19.1 million in 2006 compared to 2005, 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 5), partially offset by a decrease in Regulatory Assets related to current year cost recoveries.

Long-Term Debt increased $14.7 million in 2006 compared to 2005 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 $17.8 million in 2006 compared to 2005 primarily reflecting the recording of deferred tax assets related to Retirement Benefit Obligations, discussed below.

Retirement Benefit Obligations increased $38.4 million in 2006 compared to 2005 primarily reflecting the recording of pension, PBOP and SERP obligations.

Environmental Obligations increased $12.0 million in 2006 compared to 2005 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.

Sales

Kilowatt-hour Sales—The following table details total kWh sales for the last three years by major customer class:


kWh Sales (millions)
				2006 vs. 2005				2005 vs. 2004
	2006	2005	2004	Change		Change %		Change	Change %
Residential	672.2	688.3	652.8	(16.1	)	(2.3	%)	35.5	5.4	%
Commercial / Industrial	1,079.3	1,102.1	1,089.3	(22.8	)	(2.1	%)	12.8	1.2	%

Total	1,751.5	1,790.4	1,742.1	(38.9	)	(2.2	%)	48.3	2.8	%

Unitil’s total kWh sales decreased 2.2% in 2006 compared to 2005. This decrease reflects a decline in average energy usage per customer, primarily due to significantly milder weather. The weather in the Company’s service territories in the winter of 2006 was approximately 12% warmer than in the same period for 2005, resulting in lower consumption of electricity for heating related purposes. During the summer of 2006 the weather in the Company’s service territories was approximately 11% cooler than in the same period for 2005, resulting in lower consumption of electricity for air conditioning purposes.

Unitil’s total kWh sales increased 2.8% in 2005 compared to 2004. This increase reflects growth in sales to residential and commercial customers primarily due to hotter summer weather and an increase in the number of customers served in 2005 than in 2004.

Therm Sales—The following table details total firm therm sales for the last three years, by major customer class:


Firm Therm Sales (millions)
				2006 vs. 2005				2005 vs. 2004
	2006	2005	2004	Change		Change %		Change		Change %
Residential	9.8	11.0	11.3	(1.2	)	(10.9	%)	(0.3	)	(2.7	%)
Commercial / Industrial	16.6	13.3	11.8	3.3		24.8	%	1.5		12.7	%

Total	26.4	24.3	23.1	2.1		8.6	%	1.2		5.2	%

Unitil’s total firm therm sales of natural gas increased 8.6% in 2006 compared to 2005, due to a new gas transportation sales contract with a large industrial customer. Sales to residential customers decreased 10.9% in 2006 compared to 2005 due to a milder winter heating season in 2006 compared to the prior year.

Sales to C&I customers increased 24.8% in 2006 compared to 2005. Absent the sales from the new contract, discussed above, sales to C&I customers were 10.4% lower in 2006 compared to 2005 primarily due to a milder winter heating season. The weather in the Company’s service territories in the winter of 2006 was approximately 12% warmer than in the same period for 2005, and the region as a whole experienced a record warm winter heating season.

In 2005, total firm therm sales of natural gas increased 5.2% compared to 2004, due to the new sales contract with a large industrial customer, discussed above. Sales to residential customers decreased 2.7% in 2005 compared to 2004 due to a milder winter heating season in 2005 compared to the prior year. Sales to C&I customers increased 12.7% in 2005 compared to 2004. Absent the sales from the new contract discussed above, sales to C&I customers were 3.4% lower in 2005 compared to 2004 due to lower natural gas usage by our largest customers.

Utility Revenues and Margin

Electric Operating Revenues—The following table details total Electric Operating Revenue and Sales Margin for the last three years by major customer class:


Electric Operating Revenues and Sales Margin (millions)
							2006 vs. 2005					2005 vs. 2004
	2006		2005		2004		$ Change			% Change⁽¹⁾		$ Change		% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	102.6	$	82.2	$	75.7	$	20.4		10.3	%	$	6.5	3.5	%
Commercial / Industrial		122.6		115.1		108.2		7.5		3.8	%		6.9	3.8	%

Total Electric Operating Revenue	$	225.2	$	197.3	$	183.9	$	27.9		14.1	%	$	13.4	7.3	%

Cost of Electric Sales:
Purchased Electricity	$	167.3	$	138.1	$	125.9	$	29.2		14.8	%	$	12.2	6.7	%
Conservation & Load Management		3.6		3.8		3.5		(0.2	)	(0.1	%)		0.3	0.1	%

Electric Sales Margin	$	54.3	$	55.4	$	54.5	$	(1.1	)	(0.6	%)	$	0.9	0.5	%

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

Total Electric Operating Revenues increased by $27.9 million, or 14.1%, in 2006 compared to 2005. 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 2006 reflects higher Purchased Electricity costs of $29.2 million, offset by lower sales margin of $1.1 million and lower C&LM revenues of $0.2 million.

Purchased Electricity and C&LM revenues increased a net $29.0 million, or 14.7%, of Total Electric Operating Revenues in 2006 compared to 2005, 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 was lower by $1.1 million in 2006 compared to 2005, reflecting a decrease in revenue of $3.2 million related to the expiration of the Seabrook Amortization Surcharge (SAS) in late 2005. This decrease in SAS revenue is largely matched with a corresponding decrease in amortization expenses on Regulatory Assets, and therefore has no material impact on net income (see discussion on Depreciation and Amortization below). Absent the decrease in SAS revenues, electric sales margin increased $2.1 million in 2006 compared to 2005. The higher sales margin in 2006 primarily reflects the

Company’s recently approved base rate increase in New Hampshire of $2.7 million, partially offset by lower sales margin of $0.6 million resulting from a decline in average energy usage per customer, primarily due to significantly milder weather.

In 2005, Total Electric Operating Revenues increased by $13.4 million, or 7.3%, compared to 2004. The net increase in Total Electric Operating Revenues in 2005 reflects higher Purchased Electricity costs of $12.2 million and higher C&LM revenues of $0.3 million and higher sales margin of $0.9 million. Purchased Electricity and C&LM revenues increased a combined $12.5 million, or 6.8%, of Total Electric Operating Revenues in 2005 compared to 2004, reflecting higher electricity unit sales and higher electric commodity prices and increased spending on energy efficiency programs. Electric sales margin increased by $0.9 million in 2005 compared to 2004, primarily reflecting increased kWh unit sales and higher base rates, partially offset by the expiration of the SAS in 2005, as discussed above.

Gas Operating Revenues—The following table details total Gas Operating Revenue and Margin for the last three years by major customer class:


Gas Operating Revenues and Sales Margin (millions)
							2006 vs. 2005					2005 vs. 2004
	2006		2005		2004		$ Change			% Change⁽¹⁾		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	18.0	$	19.0	$	16.3	$	(1.0	)	(3.1	%)	$	2.7		9.4	%
Commercial / Industrial		12.9		13.7		12.3		(0.8	)	(2.4	%)		1.4		4.9	%

Total Firm Gas Revenue	$	30.9	$	32.7	$	28.6	$	(1.8	)	(5.5	%)	$	4.1		14.3	%
Interruptible Gas Revenue		2.4		0.1		0.1		2.3		7.0	%		—		—

Total Gas Operating Revenue		33.3		32.8		28.7		0.5		1.5	%		4.1		14.3	%

Cost of Gas Sales:
Purchased Gas	$	22.4	$	21.2	$	17.5	$	1.2		3.7	%	$	3.7		12.9	%
Conservation & Load Management		0.2		0.3		0.5		(0.1	)	(0.4	%)		(0.2	)	(0.7	%)

Gas Sales Margin	$	10.7	$	11.3	$	10.7	$	(0.6	)	(1.8	%)	$	0.6		2.1	%

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

Total Gas Operating Revenues increased $0.5 million, or 1.5%, in 2006 compared to 2005. 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 2006 reflects higher Purchased Gas costs of $1.2 million, offset by lower sales margin of $0.6 million and lower C&LM revenues of $0.1 million.

Purchased Gas and C&LM revenues increased a net $1.1 million, or 3.3%, of Total Gas Operating Revenues in 2006 compared to 2005, reflecting higher gas commodity prices and higher unit sales during those periods. 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 for 2006 decreased $0.6 million compared to 2005. In the third quarter of 2005, the Company entered into a new gas sales contract with a large industrial customer which resulted in an increase in gas sales margin of $0.5 million in 2006 compared to 2005. Prior to the fourth quarter of 2006, the Company had recorded revenue from this contract on a reduced basis, pending the resolution of a margin sharing proceeding by the MDTE. As part of a settlement agreement with the MDTE for FG&E’s gas division, the Company is allowed to earn the full margin associated with this contract. As a result, the

Company recognized $0.2 million of gas margin in the fourth quarter of 2006 which had been deferred pending a decision by the MDTE. Absent the gas sales margin from this contract, gas sales margin decreased $1.1 million in 2006 compared to 2005. This decline in gas sales margin was due to lower therm sales, which, absent the sales from the new contract were 10.8% lower in 2006 compared to 2005. The lower gas sales were primarily due to a milder winter heating season. The weather in the Company’s service territories in the winter of 2006 was approximately 12% warmer than in the same period for 2005, reflecting a record warm winter heating season.

In 2005, Total Gas Operating Revenues increased $4.1 million, or 14.3%, compared to 2004. The net increase in Total Gas Operating Revenues in 2005 reflects higher Purchased Gas costs of $3.7 million and higher sales margin of $0.6 million, partially offset by lower C&LM revenues of $0.2 million.

Purchased Gas and C&LM revenues increased a net $3.5 million, or 12.2%, of Total Gas Operating Revenues in 2005 compared to 2004, reflecting higher gas commodity prices, higher unit sales and lower spending on energy efficiency programs that were implemented during those periods. Gas sales margin for 2005 increased $0.6 million compared to 2004. This increase in gas sales margin was attributable to an increase in firm therm sales and higher rates authorized by regulators to recover certain post retirement benefit costs.

Non-regulated Revenues

Total Other Revenue increased $0.4 million in 2006 compared to 2005 and $0.4 million in 2005 compared to 2004. These increases were the result of growth in revenues from the Company’s non-regulated energy brokering business, Usource. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource. The Company will also realize future fees, estimated at December 31, 2006, of $6.0 million from executed energy supply contracts running 2007 through 2011.

The following table details total Other Revenue for the last three years:


Other Revenue (millions)
							2006 vs. 2005				2005 vs. 2004
	2006		2005		2004		$ Change		% Change		$ Change		% Change
Usource	$	2.4	$	2.0	$	1.6	$	0.4	20.0	%	$	0.4	25.0	%

Total Other Revenue	$	2.4	$	2.0	$	1.6	$	0.4	20.0	%	$	0.4	25.0	%

Operating Expenses

Purchased Electricity—Purchased Electricity includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity increased $29.2 million, or 21.1%, in 2006 compared to 2005, reflecting higher electric commodity prices. The Company recovers the costs of Purchased Electricity in its rates at cost and therefore changes in these expenses do not affect earnings.

In 2005, Purchased Electricity expenses increased $12.2 million, or 9.7%, compared to 2004 due primarily to higher electric commodity prices.

Purchased Gas—Purchased Gas includes the cost of natural gas purchased and manufactured to supply the Company’s total gas supply requirements. Purchased Gas increased $1.2 million, or 5.6%, in 2006 compared to 2005. The increase in Purchased Gas is attributable to increased therm sales and higher gas commodity costs. 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.

In 2005, Purchased Gas increased by $3.7 million, or 21.4%, compared to 2004, reflecting increased therm sales and higher natural gas commodity costs.

Operation and Maintenance (O&M)—O&M expense includes electric and gas utility operating costs, and the operating cost of the Company’s non-regulated business activities. Total O&M expense increased $1.2 million, or 3.3%, in 2006 compared to 2005. This increase reflects higher retiree and employee benefit costs of $0.8 million, driven by higher medical claims, higher salaries and compensation expenses of $0.7 million, due to normal annual increases, and an increase in all other operating expenses of $0.2 million, net, offset by lower outside services expenses and professional fees of $0.5 million.

In 2005, total O&M expense increased $1.2 million, or 5.2%, compared to 2004, reflecting higher salaries and compensation expenses of $0.6 million, higher retiree and employee benefit costs of $0.5 million, higher audit fees of $0.2 million, higher utility operating and maintenance expenses $0.1 million and higher bad debt expenses of $0.1 million, partially offset by lower administrative and general expenses of $0.3 million.

Conservation & Load Management—Conservation and Load Management expenses are expenses associated with the development, management, and delivery of the Company’s energy efficiency programs. Energy efficiency programs are designed, in conformity to state regulatory requirements, to help consumers use natural gas and electricity more efficiently and thereby decrease their energy 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 Conservation & Load Management expenses decreased slightly, by $0.4 million, in 2006 compared to 2005. These costs are collected from customers on a fully reconciling basis and therefore, fluctuations in program costs do not affect earnings.

Total Conservation & Load Management expenses increased $0.1 million, in 2005 compared to 2004.

Depreciation and Amortization—Depreciation and Amortization expense decreased $3.1 million, or 16.0%, in 2006 compared to 2005, reflecting lower amortization on regulatory assets, including Seabrook Station, $3.3 million, and lower depreciation rates on utility plant resulting from the NHPUC’s order in UES’ base rate case, $0.6 million, partially offset by depreciation on utility plant additions, $0.8 million. The Company’s regulatory asset related to its former abandoned property investment in Seabrook Station became fully-amortized in the third quarter of 2005. The lower amortization on Seabrook Station is largely matched with a corresponding decrease in SAS revenues and therefore has no material impact on net income (see discussion of Electric Operating Revenues above).

In 2005, Depreciation and Amortization expense increased $0.3 million, or 1.6%, compared to 2004, reflecting higher depreciation on normal utility plant additions, partially offset by lower amortization in 2005 on the Company’s regulatory assets related to its former abandoned property investment in Seabrook Station, discussed above.

Local Property and Other Taxes—Local Property and Other Taxes increased by $0.3 million, or 5.4%, in 2006 compared to 2005. This increase was due to higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

In 2005, Local Property and Other Taxes increased by less than $0.1 million, or 0.7% compared to 2004. This increase was due to higher local property tax rates on higher levels of utility plant in service.

Federal and State Income Taxes—Federal and State Income Taxes were essentially flat in 2006 compared to 2005 due to lower pre-tax operating income in 2006 compared to 2005 offset by a higher effective tax rate in 2006 related to the Company’s former abandoned property investment in Seabrook Station, discussed above. Federal and State Income Taxes increased $0.1 million, or 1.6%, in 2005 compared to 2004 reflecting higher pre-tax operating income year over year.

Other Non-operating Expenses (Income)

Other Non-operating Expenses (Income) improved to income of $19,000 in 2006 compared to an expense of $147,000 in 2005 due to a gain on the sale of land in Massachusetts and timber harvest revenue recorded in New Hampshire. Other Non-operating expenses of $147,000 in 2005 were $46,000 lower compared to 2004 due to lower jobbing parts expenses and lower donations expenses.

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.

A summary of interest expense and interest income is provided in the following table:


Interest Expense, net (millions)										2006 vs. 2005			2005 vs. 2004
	2006			2005			2004			Change			Change
Interest Expense
Long-term Debt	$	9.5		$	8.4		$	8.5		$	1.1		$	(0.1	)
Short-term Debt		1.5			1.0			0.5			0.5			0.5
Regulatory Liabilities		0.3			0.2			0.1			0.1			0.1

Subtotal Interest Expense		11.3			9.6			9.1			1.7			0.5

Interest Income
Regulatory Assets		(3.1	)		(2.6	)		(2.3	)		(0.5	)		(0.3	)
AFUDC and Other		(0.4	)		(0.2	)		—			(0.2	)		(0.2	)

Subtotal Interest Income		(3.5	)		(2.8	)		(2.3	)		(0.7	)		(0.5	)

Total Interest Expense, net	$	7.8		$	6.8		$	6.8		$	1.0		$	—

In 2006, Total Interest Expense, Net increased by $1.0 million compared to 2005. 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. In December 2005, Unitil’s Massachusetts utility subsidiary, FG&E, issued $15 million of unsecured long-term notes to institutional investors at an interest rate of 5.90%. The proceeds from these long-term financings 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 compared to 2005 primarily due to higher variable short-term interest rates. These increases in interest expense were partially offset by an increase in interest income due to higher carrying charges on regulatory assets.

In 2005, Interest Expense, Net, increased by less than $0.1 million compared to 2004. The net change in Interest Expense, Net, reflects higher variable interest costs on short-term debt, partially offset by higher interest income from carrying charges on regulatory assets. A rise in bank borrowing rates and average daily bank borrowings during 2005 drove Interest Expense on short-term debt.

LIQUIDITY, COMMITMENTS AND 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 December 31, 2006, Unitil had an aggregate of $40.0 million in unsecured revolving lines of credit with three banks. On January 1, 2007, Unitil’s bank lines of credit increased to $41.0 million with the same three banks. The Company anticipates that it will be able to secure renewal or replacement of some or all of its revolving lines of credit, in accordance with projected requirements. The Company had short-term debt outstanding through bank borrowings of $26.0 million and $18.7 million at December 31, 2006 and December 31, 2005, respectively. In addition, Unitil had approximately $4.6 million in cash at December 31, 2006. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets.

The maximum amount of short-term borrowings that may be incurred by Unitil and its subsidiaries has been subject to periodic approval by the SEC under the PUHCA and state regulators of the Company’s retail distribution utilities, UES and FG&E. However, in 2005 the PUHCA was repealed. Under the Energy Policy Act of 2005, many regulatory oversight responsibilities of the SEC prior to the repeal of the PUHCA were transferred to the FERC. The FERC’s transition rule permits Unitil and its subsidiaries to rely on outstanding SEC orders issued under the PUHCA , including an order related to Unitil’s cash pooling and loan arrangement and certain maximum borrowing authorizations to be extended through December 31, 2007. At December 31, 2006, 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. In 2006, UES and FG&E had average short-term debt outstanding of $9.8 million and $20.8 million, respectively.

Unitil and its subsidiaries are individually and collectively members of the Unitil Cash Pool. The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool Agreement allows an efficient exchange of cash among Unitil and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on Unitil’s actual interest costs from its banks under the revolving lines of credit. At December 31, 2006, all Unitil subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

On September 26, 2006, UES issued and sold $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 (see Note 3). The proceeds from this long-term financing were used principally to permanently finance utility plant additions that had been previously financed on an interim basis with short-term bank borrowings. In December 2005, FG&E issued and sold $15.0 million of 5.90% unsecured long-term notes under a debenture note structure

(see Note 3). The proceeds were utilized to repay outstanding short-term indebtedness of FG&E. The Company expects to continue to be able to satisfy its external financing needs by utilizing additional short-term bank borrowings and to periodically replace short-term debt with long-term financings.

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.

Contractual Obligations

The table below lists the Company’s significant contractual obligations as of December 31, 2006.


			Payments Due by Period
Significant Contractual Obligations (000’s) as of December 31, 2006	Total		2007		2008- 2009		2010- 2011		2012 & Beyond
Long-term Debt	$	140,364	$	336	$	758	$	889	$	138,381
Capital Lease		442		233		207		2		—
Operating Leases		2,820		456		909		808		647
Power Supply Contract Obligations—MA		49,987		8,001		16,396		16,912		8,678
Power Supply Contract Obligations—NH		42,571		11,870		21,677		5,226		3,798
Gas Supply Contracts		16,128		12,967		1,855		1,216		90

Total Contractual Cash Obligations	$	252,312	$	33,863	$	41,802	$	25,053	$	151,594

The Company has material energy supply commitments that are discussed in Note 4. Cash outlays for the purchase of electricity and natural gas to serve our customers are subject to full recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over collected cash over subsequent 6-12 month periods.

The Company also provides limited guarantees on certain electric supply contracts entered into by the retail distribution utilities. The Company’s policy is to limit these guarantees to two years or less. As of December 31, 2006 there are $7.0 million of guarantees outstanding and these guarantees extend through October 8, 2008.

Benefit Plan Funding

In 2006 the Company and its subsidiaries made cash contributions to its pension plan in the amount of $2.5 million. In 2006 and 2005, the Company and its subsidiaries contributed approximately $2.2 million and $2.5 million, respectively to the Voluntary Employee Benefit Trusts (VEBT) and expects to continue to make contributions to the VEBT’s in future years in amounts consistent with the amounts recovered in retail distribution utility rates for these other postretirement benefit costs.

Off-Balance Sheet Arrangements

The Company does not currently use, and is not dependent on the use of off-balance sheet financing arrangements, such as securitization of receivables, or obtaining access to assets or cash through special purpose entities or variable interest entities. The Company does have an operating lease agreement with a major financial institution. The operating lease is used to finance the Company’s utility vehicles. (See Note 3).

Cash Flows

Cash Provided by Operating Activities—Cash Provided by Operating Activities was $20.4 million in 2006, a decrease of $3.7 million compared to 2005. Sources of cash from Net Income were lower by $0.5 million compared to last year and sources of cash from Depreciation and Amortization were lower by approximately $3.1 million in 2006 compared to 2005, primarily due to the lower amortization of the Seabrook regulatory asset. Working capital related cash flows decreased $6.0 million in 2006 compared to 2005. Major uses of cash working capital were due to: Accrued Revenue, which decreased by $5.7 million year over year principally due to the recording of a temporary rate deferral in 2006 that will be fully collected before the end of 2007 and Accounts Payable, which decreased by $5.1 million compared to last year reflecting a higher level of funding of energy costs and other operating expenses in 2006. Major sources of cash working capital were due to Accounts Receivable collection, which provided $6.6 million over 2005 due to improved cash remittance activity. Sources of cash related to Deferred Restructuring Costs increased by $5.4 million in 2006 as compared to 2005, reflecting improvement in net cash flows for the collection of deferred costs related to utility industry restructuring. All other changes in cash flows from operating activities were a net increase of $0.5 million in sources of cash in 2006 compared to 2005.


	2006			2005
Cash (Used in) Investing Activities (000’s)	$	(33,642	)	$	(24,367	)

Cash (Used in) Investing Activities—Cash (Used in) Investing Activities increased by $9.3 million in 2006 compared to 2005. Cash used in investing activities is primarily for capital expenditures related to UES’ and FG&E’s electric and gas distribution systems. Capital expenditures are projected to be $32.4 million in 2007, reflecting normal electric and gas utility system additions and expenditures for the last phase of the Company’s AMI project, discussed above.

Cash Provided by (Used in) Financing Activities—Cash Provided by (Used in) Financing Activities was $14.6 million in 2006. Cash was provided by financing proceeds from the issuance and sale of $15.0 million of First Mortgage Bonds by UES; short-term borrowings of $7.3 million from Unitil’s banks; and the issuance and sale of $1.0 million of Unitil’s Common Stock. Cash Used in Financing Activities reflects $7.9 million in Common and Preferred dividends paid; retirement of $0.3 million of preferred stock; and to repay long-term debt and capital leasing obligations, amounting to $0.5 million.

On September 26, 2006, UES completed the sale of $15.0 million of Series O First Mortgage Bonds through a private placement to institutional investors. The bonds have a term of 30 years and a coupon rate of 6.32%.

In 2005, Cash Provided by (Used in) Financing activities was $0.5 million. Cash was provided by financing proceeds from the issuance and sale of $15.0 million of long-term notes by FG&E and $1.0 million of Common Stock. Cash Used in Financing Activities included the payment of dividends amounting to $7.8 million and repayment of $7.0 million of short-term bank indebtedness.

On December 21, 2005, FG&E completed the sale of $15.0 million of unsecured long-term notes through a private placement to institutional investors. The notes have a term of 25 years and a coupon rate of 5.90%.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the long-term debt of the retail distribution utilities, UES and FG&E, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations, as described below.

UES utilizes a First Mortgage Bond (FMB) structure of long-term debt. In order to issue new FMB securities, the customary covenants of the existing Indenture Agreement must be met, including that UES have sufficient available net bondable plant to issue the securities and projected earnings available for interest charges equal to at least two times the annual interest requirement. The Indenture Agreements further require that if UES defaults on any FMB securities, it would constitute a default for all UES FMB securities. The default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

FG&E utilizes a debenture structure of long-term debt. Accordingly, in order for FG&E to issue new long-term debt, the covenants of the existing long-term agreements must be satisfied, including that FG&E have total funded indebtedness less than 65% of total capitalization and earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the Indenture Agreements, FG&E’s agreements require that if FG&E defaults on any long-term debt agreement, it would constitute a default under all FG&E long-term debt agreements. The FG&E default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.

In addition, the UES and FG&E long-term debt instruments and agreements contain certain restrictions on the payment of common dividends from Retained Earnings. On December 31, 2006, UES and FG&E had unrestricted Retained Earnings of $14.8 million and $7.2 million, respectively, available for the payment of common dividends (See Note 3.) UES and FG&E pay dividends to their sole shareholder, Unitil Corporation, and these dividends are the primary source of cash for the payment of dividends to Unitil shareholders.

Unitil Corporation has no long-term debt outstanding. The long-term debt and preferred stock of UES and FG&E are privately held, and the Company does not issue commercial paper. For these reasons, these securities of Unitil and its subsidiaries are not publicly rated.

DIVIDENDS

Unitil’s annualized common dividend was $1.38 per common share in 2006, 2005 and 2004. Unitil’s dividend policy is reviewed periodically by the Board of Directors. Unitil has maintained an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock. At its January, 2007 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors.

REGULATORY MATTERS

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 last resort. UES and FG&E purchase electricity or natural gas 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 NHPUC and MDTE, 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 four to six years, is $126.1 million as of December 31, 2006 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet (see Regulatory Assets table in Note 1.) 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 MDTE. Its current retail electric distribution rates were approved by the MDTE 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 MDTE. As of December 31, 2006, approximately 53 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 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 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 $33.3 million at December 31, 2006, and $34.4 million at December 31, 2005, and is expected to be recovered in FG&E’s rates over the next four to six years. In addition, as of December 31, 2006, FG&E had recorded on its balance sheet $50.0 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 (See Note 1.)

On March 7, 2006, the MDTE approved FG&E’s 2003 and 2004 annual reconciliation of costs and revenues for Transition, Transmission, Standard Offer Service, and Default Service filed under its restructuring plan. FG&E’s 2005 and 2006 filings, which are subject to investigation, are pending. 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 MDTE in 2002. 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 CGAC and recovers other related costs through a reconciling Local Distribution Adjustment Clause.

On January 26, 2007, the MDTE approved a rate Settlement Agreement (Settlement) which FG&E and the Attorney General of Massachusetts had signed and filed with the MDTE for FG&E’s Gas Division on November 29, 2006. 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 MDTE issued an order allowing FG&E to recover 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 based on a fixed rate formula that was resulting in a significant underrecovery 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 MDTE’s order of September 7, 2006. FG&E intends to support the MDTE’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 December 31, 2006, approximately 80 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 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 are subject to annual or periodic reconciliation or future review. As of December 31, 2006, UES had recorded on its balance sheets $42.6 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 four 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 17, 2006, UES made its third annual reconciliation and rate filing with the NHPUC under its restructuring plan, effective May 1, 2006, including reconciliation of prior year costs and revenues, power supply and power supply-related stranded costs. The NHPUC approved the filing on April 28, 2006.

On October 6, 2006, UES received approval from the NHPUC of a Settlement Agreement (Agreement) resolving all issues in 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 authorizes 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 Regional Transmission Organization (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 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 MDTE and NHPUC.

ENVIRONMENTAL MATTERS

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 December 31, 2006 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.

EMPLOYEES AND EMPLOYEE RELATIONS

As of December 31, 2006, the Company and its subsidiaries had 304 employees. The Company considers it relationships with employees to be good and has not experienced any major labor disruptions.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, the Company is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, the financial position of the Company could be materially affected and the results of operations of the Company could be materially different than reported. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the financial statements and Note 1: Summary of Significant Accounting Policies.

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 or refunded in future electric and gas retail rates.

SFAS No. 71 specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under SFAS No. 71. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under SFAS No. 71.

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. The Company’s regulatory assets and liabilities will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. The Company must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, 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, the 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.

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 has a defined benefit pension plan covering substantially all its employees and also provides certain other post-retirement benefits (PBOP), primarily medical and life insurance benefits to retired employees. The Company also has a Supplemental Executive Retirement Plan (SERP) covering certain executives of the Company.

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 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. See Note 8 for a table showing the incremental effect of applying SFAS No. 158 on individual line items of the Company’s Consolidated Balance Sheet at December 31, 2006.

The Company accounts for its pension and postretirement benefits in accordance with SFAS No. 158, SFAS No. 87 and SFAS No. 106. In applying these accounting policies, 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. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on these significant assumptions.

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’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. 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. 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 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 consolidated financial statements. See Note 8.

Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 8.50%, 8.50% and 8.75% for 2006, 2005 and 2004, respectively. In developing the expected long-term rate of return assumption, the Company evaluated input from actuaries and investment managers. The Company’s expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 60% in common stock equities and 40% in fixed income securities. The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2006. The Company will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2006, 2005 and 2004 was $2,609,128, $2,391,745 and $1,981,667, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2006, 2005 and 2004 would have been $2,759,208, $2,225,181 and $2,119,667 respectively.

The discount rate that is utilized in determining future pension obligations is based on a market average of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate used for 2006 was 5.50%. For the period January 1, 2005 through May 31, 2005, the discount rate used was 6.50%. In May 2005, the Company reached agreements with its union labor bargaining units for new five-year contracts, effective June 1, 2005, which resulted in amendments to the defined benefit pension plan. Effective for the period of June 1, 2005 through December 31, 2005, the Company lowered the assumed discount rate to 6.00%. The discount rate used for the 2004 fiscal year was 6.50%. For 2006, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 in the Net Periodic Pension Cost. Similarly, for 2005 and 2004, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000. The compensation cost increase assumption used for 2006, 2005 and 2004 was 3.50%, based on the expected long-term increase in compensation costs for personnel covered by the Plan.

Income Taxes—Income tax expense is 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 actual current tax liabilities as well as assessing temporary and permanent differences resulting from differing treatment of items, such as timing of the deduction of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the 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 applies to all tax positions related to income taxes subject to FAS 109. This includes tax positions considered to be “routine” as well as those with a high degree of uncertainty such as tax-advantaged transactions. FIN 48 effectively amends FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5), such that all references to income taxes in SFAS No. 5 have been deleted and FIN 48 is now the primary guidance in accounting for uncertainty in income taxes. FIN 48 creates a single model to address accounting for uncertainty in tax positions. Under FIN 48, tax positions accounted for under FAS 109 will be evaluated for recognition, derecognition, and classification and the cumulative affect of adopting FIN 48 may be recorded as an adjustment to retained earnings.

FIN 48 requires disclosures of items and amounts that would affect the Company’s effective tax rate in its statement of earnings. FIN 48 also provides guidance on disclosures for interim reporting periods for accounting for income taxes, interest and penalties. The Company will adopt FIN 48 as of January 1, 2007, as required. The Company does not expect that the adoption of FIN 48 will 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 December 31, 2006, the Company is not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and 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.

For further information regarding these types of activities, see Note 1, “Summary of Significant Accounting Policies,” Note 7, “Income Taxes,” Note 4, “Energy Supply,” Note 8, “Benefit Plans,” and Note 5, “Commitment and Contingencies,” to the consolidated financial statements.

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

Please also refer to Item 1A. “Risk Factors”.

INTEREST RATE RISK

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding 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. The average interest rate on short-term borrowings was 5.5%, 3.8% and 1.9% during 2006, 2005 and 2004, 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.

Item 8.

Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Shareholders of Unitil Corporation:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Unitil Corporation and subsidiaries as of December 31, 2006 and December 31, 2005, and the related consolidated statements of earnings, cash flows and changes in common stock equity for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Unitil Corporation and subsidiaries as of December 31, 2006 and December 31, 2005 and the consolidated results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Unitil Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 2, 2007 expressed an opinion on management’s assessment of internal control over financial reporting and a unqualified opinion on the effectiveness of internal control over financial reporting.

/s/ Vitale, Caturano & Co. Ltd.

Boston, Massachusetts

February 2, 2007

Report of Independent Registered Public Accounting Firm

To the Shareholders of Unitil Corporation:

We have audited the accompanying consolidated statements of earnings, cash flows and changes in common stock equity of Unitil Corporation and subsidiaries for the year ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of Unitil Corporation and subsidiaries’ operations and their cash flows for the year ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Unitil Corporation’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 17, 2005 (not separately included herein), expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Boston, Massachusetts

February 17, 2005

Report of Independent Registered Public Accounting Firm

To the Shareholders of Unitil Corporation:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that Unitil Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audits included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Unitil Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the COSO. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in the Internal Control-Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and consolidated statements of capitalization of Unitil Corporation and subsidiaries as of December 31, 2006, and the related consolidated statements of earnings, cash flows and changes in common stock equity for the years then ended, and our report dated February 2, 2007, expressed an unqualified opinion on those consolidated financial statements.

/s/ Vitale, Caturano & Co. Ltd.

Boston, Massachusetts

February 2, 2007

CONSOLIDATED STATEMENTS OF EARNINGS

(000’s, except common shares and per share data)


Year Ended December 31,	2006			2005		2004

Operating Revenues:

Electric	$	225,154		$	197,338	$	183,889

Gas		33,271			32,768		28,685

Other		2,436			2,039		1,563



Total Operating Revenues		260,861			232,145		214,137



Operating Expenses:

Purchased Electricity		167,333			138,134		125,940

Purchased Gas		22,405			21,225		17,486

Operation and Maintenance		25,680			24,514		23,297

Conservation & Load Management		3,752			4,115		4,003

Depreciation and Amortization		16,069			19,123		18,830

Provisions for Taxes:

Local Property and Other		5,501			5,218		5,182

Federal and State Income		4,266			4,275		4,206



Total Operating Expenses		245,006			216,604		198,944



Operating Income		15,855			15,541		15,193

Other Non-Operating Expenses (Income)		(19	)		147		193



Income Before Interest Expense		15,874			15,394		15,000

Interest Expense, net		7,841			6,841		6,774



Net Income		8,033			8,553		8,226

Less Dividends on Preferred Stock		133			156		215



Earnings Applicable to Common Shareholders	$	7,900		$	8,397	$	8,011



Average Common Shares Outstanding—Basic		5,597,465			5,551,420		5,509,321

Average Common Shares Outstanding—Diluted		5,611,734			5,567,718		5,524,835


Earnings per Common Share—Basic and Diluted	$	1.41		$	1.51	$	1.45

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

CONSOLIDATED BALANCE SHEETS (000’s)

ASSETS


December 31,	2006		2005

Utility Plant:

Electric	$	250,304	$	234,153

Gas		63,428		58,675

Common		25,220		26,515

Construction Work in Progress		14,047		5,624



Utility Plant		352,999		324,967

Less: Accumulated Depreciation		121,191		111,646



Net Utility Plant		231,808		213,321



Current Assets:

Cash		4,556		3,207

Accounts Receivable—(Net of Allowance for Doubtful Accounts of $1,737 and $470)		22,546		23,631

Accrued Revenue		13,766		8,905

Material and Supplies		4,536		3,675

Prepayments and Other		1,293		1,963



Total Current Assets		46,697		41,381



Noncurrent Assets:

Regulatory Assets		198,828		179,719

Prepaid Pension		—		11,099

Debt Issuance Costs, net		2,560		2,343

Other Noncurrent Assets		3,534		2,218



Total Noncurrent Assets		204,922		195,379



TOTAL	$	483,427	$	450,081

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

CONSOLIDATED BALANCE SHEETS (cont.) (000’s)

CAPITALIZATION AND LIABILITIES


December 31,	2006		2005

Capitalization:

Common Stock Equity	$	97,775	$	96,283

Preferred Stock, Non-Redeemable, Non-Cumulative		225		225

Preferred Stock, Redeemable, Cumulative		1,858		2,102

Long-Term Debt, Less Current Portion		140,028		125,365



Total Capitalization		239,886		223,975



Current Liabilities:

Long-Term Debt, Current Portion		336		308

Capitalized Leases, Current Portion		233		261

Accounts Payable		19,813		20,600

Short-Term Debt		26,000		18,700

Taxes Payable		888		—

Interest and Dividends Payable		1,646		1,403

Other Current Liabilities		4,554		4,708



Total Current Liabilities		53,470		45,980



Deferred Income Taxes		34,526		52,297



Noncurrent Liabilities:

Power Supply Contract Obligations		92,558		114,906

Retirement Benefit Obligations		49,663		11,289

Environmental Obligations		12,000		—

Capitalized Leases, Less Current Portion		209		324

Other Noncurrent Liabilities		1,115		1,310



Total Noncurrent Liabilities		155,545		127,829



TOTAL	$	483,427	$	450,081

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

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(000’s except number of shares and par value)


December 31,	2006		2005

Common Stock Equity

Common Stock, No Par Value (Authorized—8,000,000 shares; Outstanding—5,650,263 and 5,595,523 shares)	$	61,827	$	60,826

Stock Compensation Plans		1,661		1,310

Retained Earnings		34,287		34,147



Total Common Stock Equity		97,775		96,283



Preferred Stock

UES Preferred Stock, Non-Redeemable, Non-Cumulative:

6.00% Series, $100 Par Value		225		225

FG&E Preferred Stock, Redeemable, Cumulative:

5.125% Series, $100 Par Value		874		892

8.00% Series, $100 Par Value		984		1,210



Total Preferred Stock		2,083		2,327



Long-Term Debt

UES First Mortgage Bonds:

8.49% Series, Due October 14, 2024		15,000		15,000

6.96% Series, Due September 1, 2028		20,000		20,000

8.00% Series, Due May 1, 2031		15,000		15,000

6.32% Series, Due September 15, 2036		15,000		—

FG&E Long-Term Notes:

6.75% Notes, Due November 30, 2023		19,000		19,000

7.37% Notes, Due January 15, 2029		12,000		12,000

7.98% Notes, Due June 1, 2031		14,000		14,000

6.79% Notes, Due October 15, 2025		10,000		10,000

5.90% Notes, Due December 15, 2030		15,000		15,000

Unitil Realty Corp. Senior Secured Notes:

8.00% Notes, Due August 1, 2017		5,364		5,673



Total Long-Term Debt		140,364		125,673

Less: Current Portion		336		308



Total Long-Term Debt, Less Current Portion		140,028		125,365



Total Capitalization	$	239,886	$	223,975

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

CONSOLIDATED STATEMENTS OF CASH FLOWS (000’s)


Year Ended December 31,	2006			2005			2004

Operating Activities:

Net Income	$	8,033		$	8,553		$	8,226
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		16,069			19,123			18,830
Deferred Tax (Benefit) Provision		481			(240	)		3,166

Changes in Current Assets and Liabilities:
Accounts Receivable		1,085			(5,512	)		(658	)
Accrued Revenue		(4,861	)		849			275
Accounts Payable		(787	)		4,351			1,225
Taxes Payable		888			626			2,839
All Other Current Assets and Liabilities		(86	)		1,386			5,597

Deferred Restructuring Charges		1,129			(4,223	)		(5,820	)
Other, net		(1,578	)		(837	)		(3,032	)

Cash Provided by Operating Activities		20,373			24,076			30,648


Investing Activities:

Property, Plant and Equipment Additions		(33,642	)		(24,367	)		(22,922	)

Cash Used In Investing Activities		(33,642	)		(24,367	)		(22,922	)


Financing Activities:

Proceeds from (Repayment of) Short-Term Debt		7,300			(6,975	)		3,265
Issuance of Long-Term Debt		15,000			15,000			—
Repayment of Long-Term Debt		(310	)		(286	)		(3,264	)
Retirement of Preferred Stock		(243	)		(11	)		(931	)
Dividends Paid		(7,908	)		(7,843	)		(7,857	)
Issuance of Common Stock		1,001			1,031			947
Repayment of Capital Lease Obligations		(222	)		(450	)		(620	)

Cash Provided by (Used In) Financing Activities		14,618			466			(8,460	)


Net Increase (Decrease) in Cash		1,349			175			(734	)

Cash at Beginning of Year		3,207			3,032			3,766


Cash at End of Year	$	4,556		$	3,207		$	3,032


Supplemental Information:

Interest Paid	$	10,690		$	9,455		$	9,052

Income Taxes Paid	$	3,101		$	4,544		$	990

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

CONSOLIDATED STATEMENTS OF

CHANGES IN COMMON STOCK EQUITY

(000’s except number of shares)


	Common Shares		Stock Compensation Plans		Retained Earnings			Total
Balance at January 1, 2004	$	58,848	$	908	$	33,049		$	92,805

Net Income for 2004						8,226			8,226

Dividends on Preferred Shares						(215	)		(215	)

Dividends on Common Shares						(7,623	)		(7,623	)

Stock Compensation Plans				151					151

Issuance of 35,310 Common Shares		947							947


Balance at December 31, 2004		59,795		1,059		33,437			94,291

Net Income for 2005						8,553			8,553

Dividends on Preferred Shares						(156	)		(156	)

Dividends on Common Shares						(7,687	)		(7,687	)

Stock Compensation Plans				251					251

Issuance of 38,003 Common Shares		1,031							1,031


Balance at December 31, 2005		60,826		1,310		34,147			96,283

Net Income for 2006						8,033			8,033

Dividends on Preferred Shares						(133	)		(133	)

Dividends on Common Shares						(7,760	)		(7,760	)

Stock Compensation Plans				351					351

Issuance of 40,365 Common Shares		1,001							1,001


Balance at December 31, 2006	$	61,827	$	1,661	$	34,287		$	97,775

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

Note 1: Summary of Significant Accounting Policies

Nature of Operations—Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. 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.

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.

Basis of Presentation

Principles of Consolidation—In accordance with current accounting pronouncements, the Company’s consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries and all intercompany transactions are eliminated in consolidation.

Regulatory Accounting—The Company’s principal business is the distribution of electricity and natural gas by the Company-owned retail distribution utilities: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and FG&E is regulated by the Massachusetts Department of Telecommunications and Energy (MDTE) and UES is regulated by the New Hampshire Public Utilities Commission (NHPUC). Accordingly, the Company uses the provisions of Financial Accounting Standards Board (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 in future electric and gas retail rates.

enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under SFAS No. 71. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under SFAS No. 71.

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 primarily 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. The Company’s regulatory assets and liabilities will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.


	December 31,
Regulatory Assets consist of the following (millions)	2006		2005
Power Supply Buyout Obligations	$	92.6	$	114.9
Deferred Restructuring Costs		31.0		31.2
Generation-related Assets		2.5		3.3

Subtotal—Restructuring Related Items		126.1		149.4

Retirement Benefit Obligations		37.1		9.2
Income Taxes		19.1		17.5
Environmental Obligations		13.0		0.4
Other		3.5		3.2

Total Regulatory Assets	$	198.8	$	179.7

Massachusetts and New Hampshire have both passed utility industry restructuring legislation and the Company has filed and implemented its restructuring plans in both states. The Company is allowed to recover certain types of costs through ongoing assessments to be included in future retail rates. Based on the recovery mechanism that allows recovery of all of its stranded costs and deferred costs related to restructuring, the Company has recorded regulatory assets that it expects to fully recover in future periods. The Company expects to continue to meet the criteria for the application of SFAS No. 71 for the distribution portion of its assets and operations for the foreseeable future.

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 subsidiaries will be subject to SFAS No. 71 for the foreseeable future.

Cash—Cash includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. Financial instruments that subject the Company to credit risk concentrations consist of cash and cash equivalents and accounts receivable. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on cash. Under the Independent System Operator—New England (ISO-NE) Financial Assurance Policy (Policy), Unitil’s affiliates UES, FG&E and Unitil Power are required to provide assurance of their ability to satisfy their obligations to ISO-NE. Under this Policy, Unitil’s affiliates provide cash deposits covering approximately 2-1/2 months of outstanding obligations. On December 31, 2006 and 2005, the Unitil affiliates had deposited $2.0 million and $1.5 million, respectively to satisfy their ISO-NE obligations.

Goodwill and Intangible Assets—The Company does not have any goodwill recorded on its balance sheet as of December 31, 2006. There are no significant intangible assets recorded by the Company at December 31, 2006. Therefore, the Company is not currently involved in making estimates or seeking valuations of these items.

Off-Balance Sheet Arrangements—As of December 31, 2006, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases and, in the Company’s opinion, the amount of these transactions is not material.

Investments and Trading Activities—During the year, the Company does invest in U.S. Treasuries and short-term investments which traditionally have very little fluctuation in fair value. The Company does not engage in investing or trading activities involving non-exchange traded contracts or other instruments where a periodic analysis of fair value would be required for book accounting purposes.

Derivatives—The Company enters into wholesale electric and gas energy supply contracts to serve its customers. The Company’s policy is to review each contract and determine whether they meet the criteria for classification as derivatives under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) and / or FASB Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149). As of December 31, 2006, the Company determined that none of its wholesale electric and gas energy supply contracts met the criteria for classification as a derivative instrument. Additionally, the Company may enter into interest rate hedging transactions with respect to existing indebtedness and anticipated debt offerings. As of December 31, 2006, the Company has not entered into any such transactions. However, should the Company enter into any such transactions in the future, its policy will be to review each transaction and determine whether it meets the criteria for classification as derivatives under SFAS No. 133 and / or SFAS No. 149.

Revenue Recognition—Non-regulated Operations—Usource, Unitil’s competitive energy brokering subsidiary, records energy brokering revenues based upon the estimated amount of electricity and gas delivered to customers through the end of the accounting period.

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 years. Account write-offs, net of 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 takes into account an assumption about the cash recovery of delinquent receivables and also uses calculations related to customers who have chosen payment plans to resolve their arrears. The analysis also 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.

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. See Note 8 for a table showing the incremental effect of applying SFAS No. 158 on individual line items of the Company’s Consolidated Balance Sheet at December 31, 2006.

Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 8.50%, 8.50% and 8.75% for 2006, 2005 and 2004, respectively. In developing the expected long-term rate of return assumption, the Company evaluated input from actuaries and investment advisors. The Company’s expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 60% in common stock equities and 40% in fixed income securities. The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2006. The Company will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.

Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, and requires 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. Actual results could differ from those estimates. The Company policy is to record those estimates in accordance with the American Institute of Certified Public Accountants Statement of Position 94-6, “Disclosure of Certain Significant Risks and Uncertainties.”

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with FASB Statement No. 5, “Accounting for Contingencies” (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 December 31, 2006, 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 (See Note 5.)

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an

allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 4.92%, 2.33% and 1.64% in 2006, 2005 and 2004, respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of and the cost of removal, less salvage, are charged to the accumulated provision for depreciation. The Company does not account separately for negative salvage, or cost of retirement obligations as defined in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, depreciation amounts to provide for future negative salvage value. At December 31, 2006 and December 31, 2005, the Company estimates that the negative salvage value of future retirements recorded on the balance sheet in Accumulated Depreciation is $14.9 million and $13.4 million, respectively.

Depreciation and Amortization—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.

Depreciation provisions for Unitil’s utility operating subsidiaries are determined on a group straight-line basis. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 2006—4.40%, 2005—4.69% and 2004—4.70%.

Amortization provisions include the recovery, in 2004 and 2005, of a portion of FG&E’s former investment in Seabrook Station, a nuclear generating unit, in rates to its customers through the Seabrook Amortization Surcharge as ordered by the MDTE. FG&E’s asset related to Seabrook Station became fully-amortized in the third quarter of 2005. In addition, FG&E is amortizing the balance of its unrecovered electric generating related assets, which are recorded as Regulatory Assets, in accordance with its electric restructuring plan approved by the MDTE (See Note 5.)

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. In the past three years, the Company has performed work on two environmental remediation projects, the Sawyer Passway MGP Site and the Former Electric Generating Station. The Company has or will recover substantially all of the cost of the work performed to date from customers or from its insurance carriers. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2006, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in Note 5, Commitments and Contingencies. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

Stock-based Employee Compensation—Unitil accounts for stock-based employee compensation currently using the fair value-based method (See Note 2.)

Sales and Consumption Taxes—The Company bills its customers sales tax in Massachusetts and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.

Company’s actual current tax liabilities as well as assessing temporary and permanent differences resulting from differing treatment of items, such as timing of the deduction of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the 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 applies to all tax positions related to income taxes subject to FAS 109. This includes tax positions considered to be “routine” as well as those with a high degree of uncertainty such as tax-advantaged transactions. FIN 48 effectively amends SFAS No. 5, such that all references to income taxes in SFAS No. 5 have been deleted and FIN 48 is now the primary guidance in accounting for uncertainty in income taxes. FIN 48 creates a single model to address accounting for uncertainty in tax positions. Under FIN 48, tax positions accounted for under FAS 109 will be evaluated for recognition, derecognition, and classification and the cumulative affect of adopting FIN 48 may be recorded as an adjustment to retained earnings.

Dividends—The Company is currently paying a dividend at an annual rate of $1.38 per common share.

The Company’s dividend policy is reviewed periodically by the Board of Directors. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors.

Other Recently Issued Pronouncements—In October 2006, the FASB issued FASB Staff Position No. FAS 123(R)-5, (FSP FAS 123(R)-5), “Amendment of FASB Staff Position FAS 123(R)-1” and FASB Staff Position No. FAS 123(R)-6, (FSP FAS 123(R)-6), “Technical Corrections of FASB Statement No. 123(R)”. FSP FAS 123(R)-5 addresses whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under revised FASB Statement No. 123(R), “Share-Based Payment”, (SFAS No. 123(R)), which was issued in December 2004. FSP FAS 123(R)-6 addresses certain technical corrections of SFAS No. 123(R). SFAS No. 123(R) requires all entities to recognize the fair value of share-based payment awards classified in equity, unless they are unable to reasonably estimate the fair value of the award. Prior to the adoption of SFAS No. 123(R) the Company accounted for share-based payments under SFAS No. 123, “Accounting for Stock-Based Compensation.” The Company uses the fair value method for share-based payment awards and therefore the provisions of SFAS No. 123(R) have no impact on the Consolidated Financial Statements. The Company has adopted the provisions of FSP FAS 123(R)-5 and FSP FAS 123(R)-6.

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 does not expect SFAS No. 155 to have an impact on the Company’s Consolidated Financial Statements.

Note 2: Equity

The Company has both common and preferred stock outstanding. Details regarding these forms of capitalization follow:

Common Stock

Dividend Reinvestment and Stock Purchase Plan—During 2006, the Company sold 40,365 shares of its Common Stock, at an average price of $24.78 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans. Net proceeds of $1.0 million were used to reduce short-term borrowings. The DRP provides participants in the plan a method for investing cash dividends on the Company’s Common Stock and cash payments in additional shares of the Company’s Common Stock. During 2005 and 2004, the Company raised $1.0 million and $0.9 million, respectively, of additional common equity through the issuance of 38,003 and 35,310 shares, respectively, of its Common Stock in connection with its DRP and 401(k) plans.

Shares Repurchased, Cancelled and Retired—During 2006, 2005 and 2004, Unitil did not repurchase, cancel or retire any of its common stock. The Company has adopted SFAS No. 123(R), “Accounting for Stock Based Compensation,” and recognizes compensation costs at fair value at the date of grant.

Stock-Based Compensation Plans—Unitil maintains a Restricted Stock plan and two stock option plans, which provided for the granting of options to key employees. Details of the plans are as follows:

Restricted Stock Plan—On April 17, 2003, the Company’s shareholders ratified and approved a Restricted Stock Plan (the Plan) which had been approved by the Company’s Board of Directors at its January 16, 2003 meeting. Participants in the Plan are selected by the Compensation Committee of the Board of Directors from the eligible Participants to receive an annual award of restricted shares of Company Common Stock. The Compensation Committee has the power to determine the sizes of awards; determine the terms and conditions of awards in a manner consistent with the Plan; construe and interpret the Plan and any agreement or instrument entered into under the Plan as they apply to participants; establish, amend, or waive rules and regulations for the Plan’s administration as they apply to participants; and, subject to the provisions of the Plan, amend the terms and conditions of any outstanding award to the extent such terms and conditions are within the discretion of the Compensation Committee as provided for in the Plan. Awards fully vest over a period of four years at a rate of 25% each year.

During the vesting period, dividends on restricted shares underlying the Award may be credited to the participant’s account. Awards may be grossed up to offset the participant’s tax obligations in connection with the Award. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death. The maximum number of shares of Restricted Stock available for awards to participants under the Plan is 177,500. The maximum aggregate number of shares of Restricted Stock that may be awarded in any one calendar year to

any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make proportionate adjustments to prevent dilution or enlargement of rights, including, without limitation, an adjustment in the maximum number and kinds of shares available for awards and in the annual award limit.

On February 16, 2006, 14,375 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $0.4 million. On March 8, 2005, 10,900 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $0.3 million. On April 29, 2004, 10,700 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $0.3 million. On May 12, 2003, 10,600 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $0.3 million. The compensation expense associated with the issuance of shares under the Plan is being accrued on a monthly basis over the vesting period and was $0.4 million in 2006, including amounts for tax gross-up.

Unitil Corporation Key Employee Stock Option Plan—The “Unitil Corporation Key Employee Stock Option Plan” 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. At December 31, 2006, 29,101 shares underlying options had been approved and were available for future issuance as dividend equivalents earned under the plan. 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 expiration date of the remaining outstanding options is November 3, 2007. The plan provides dividend equivalents on options granted, which are recorded at fair value as compensation expense. The total compensation expenses recorded by the Company with respect to this plan were $54,000, $51,000 and $49,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

Share Option Activity of the “Unitil Corporation Key Employee Stock Option Plan” is presented in the following table:


	2006		2005		2004
Beginning Options Outstanding and Exercisable		25,000		25,000		25,000
Dividend Equivalents Earned—Prior Years		13,202		11,321		9,495
Dividend Equivalents Earned—Current Year		2,186		1,881		1,826
Options Exercised		—		—		—

Ending Options Outstanding and Exercisable		40,388		38,202		36,321

Weighted Average Exercise Price per Share		$11.25		$11.89		$12.51
Range of Option Exercise Price per Share	$	12.11-$18.28	$	12.11-$18.28	$	12.11-$18.28
Weighted Average Remaining Contractual Life		0.9 years		1.9 years		2.9 years

Unitil Corporation 1998 Stock Option Plan—The “Unitil Corporation 1998 Stock Option Plan” became effective on December 11, 1998. The number of shares granted under this plan, as well as the terms and conditions of each grant, are determined by the Compensation Committee of the Board of Directors, subject to plan limitations. All options granted under this plan vest over a three-year period from the date of the grant, with 25% vesting on the first anniversary of the grant, 25% vesting on the second anniversary, and 50% vesting on the third anniversary. Under the terms of this plan, key employees may be granted options to purchase the Company’s Common Stock at no less than 100% of the market price on the date the option is granted. All options must be exercised no later than 10 years after the date on which they were granted. This plan was terminated on January 16, 2003. There was no compensation expense associated with this plan in 2006, 2005 and 2004. The plan will remain in effect solely for the purposes of the continued administration of all options currently outstanding under the plan. No further grants of options will be made under this plan.

There were 107,000 vested and exercisable options outstanding, with an average exercise price of $27.13, at December 31, 2004, 2005 and 2006. There were no options granted or forfeited during those years.

The following summarizes certain data for the options outstanding at December 31, 2006:


Range of Exercise Prices	Options Vested, Exercisable and Outstanding	Weighted Average Exercise Price		Remaining Contractual Life
$20.00-$24.99	34,500	$	23.38	2.2 years
$25.00-$29.99	37,500	$	25.88	4.1 years
$30.00-$34.99	35,000	$	32.17	3.1 years

	107,000

Restrictions on Retained Earnings—Unitil Corporation has no restriction on the payment of common dividends from retained earnings.

Its two retail distribution subsidiaries, UES and FG&E, do have restrictions. Under the terms of the First Mortgage Bond Indentures, UES had $14.8 million available for the payment of cash dividends on its Common Stock at December 31, 2006. Under the terms of long-term debt purchase agreements, FG&E had $7.2 million of retained earnings available for the payment of cash dividends on its Common Stock at December 31, 2006. Common dividends declared by UES and FG&E are paid exclusively to Unitil Corporation.

Preferred Stock

Unitil’s two retail distribution companies, UES and FG&E, have preferred stock outstanding. At December 31, 2006, UES has a 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock series outstanding and FG&E has two series of Redeemable, Cumulative Preferred Stock outstanding, the 5.125% Series and the 8.00% Series.

FG&E is required to offer to redeem annually a given number of shares of each series of Redeemable, Cumulative Preferred Stock and to purchase such shares that shall have been tendered by holders of the respective stock. In addition, FG&E may opt to redeem the Redeemable, Cumulative Preferred Stock at a given redemption price, plus accrued dividends.

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2006, 2005 and 2004 related to the annual redemption offer were $22,000, $11,400 and $26,900, respectively. The aggregate amount of sinking fund requirements of the Redeemable, Cumulative Preferred Stock for each of the five years following 2006 is $117,000 per year.

On February 10, 2006, FG&E repurchased, canceled and retired 2,213 shares of its 8.00% series of Redeemable, Cumulative Preferred Stock at an aggregate par value of $221,300. FG&E used operating cash to effect this transaction.

On October 15, 2004, UES redeemed and retired the remaining three outstanding issues of its Redeemable, Cumulative Preferred Stock at par, aggregating $904,100. The three issues redeemed and retired were the 8.70% Series (aggregate par value of $215,000), the 8.75% Series (aggregate par value of $313,600) and the 8.25% Series (aggregate par value of $375,500). UES used operating cash to effect this transaction.

Note 3: Long-Term Debt, Credit Arrangements, Leases and Guarantees

The Company funds a portion of its operations through the issuance of long-term debt and through short-term borrowing arrangements. The Company’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery, vehicles and office equipment. Details regarding long-term debt, short-term debt and leases follow:

Long-Term Debt and Interest Expense

Substantially all the property of Unitil’s New Hampshire utility operating subsidiary, UES, is subject to liens of indenture under which First Mortgage bonds have been issued. UES utilizes a First Mortgage Bond (FMB) structure of long-term debt. In order to issue new FMB securities, the customary covenants of the existing UES Indenture Agreement must be met, including that UES have sufficient available net bondable plant to issue the securities and projected earnings available for interest charges equal to at least two times the annual interest requirement. The UES agreements further require that if UES defaults on any UES FMB securities, it would constitute a default for all UES FMB securities. The UES default provisions are not triggered by the actions or defaults of other companies in the Unitil System.

All of the long-term debt of Unitil’s Massachusetts utility operating subsidiary, FG&E, is issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of FG&E’s long-term debt ranks pari passu with its other senior unsecured long-term debt. The long-term debt’s negative pledge provisions contain restrictions which, among other things, limit the incursion of additional long-term debt. Accordingly, in order for FG&E to issue new long-term debt, the covenants of the existing long-term agreements must be satisfied, including that FG&E have total funded indebtedness less than 65% of total capitalization and earnings available for interest equal to at least two times the interest charges for funded indebtedness. As with the UES agreements, FG&E agreements require that if FG&E defaults on any FG&E long-term debt agreement, it would constitute a default under all FG&E long-term debt agreements. The FG&E default provisions are not triggered by the actions or defaults of other companies in the Unitil System.

Both the UES and FG&E instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets. In addition, the UES and FG&E long-term debt instruments and agreements contain certain restrictions on the payment of common dividends from Retained Earnings. On December 31, 2006, UES and FG&E had unrestricted Retained Earnings of $14.8 million and $7.2 million, respectively, available for the payment of common dividends. UES and FG&E pay dividends to their sole shareholder, Unitil Corporation, and these dividends are the primary source of cash for the payment of dividends to Unitil shareholders.

Total aggregate amount of sinking fund payments relating to bond issues and normal scheduled long-term debt repayments amounted to $310,136, $286,368 and $3,264,421 in 2006, 2005 and 2004, respectively.

The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 2006 is: 2007—$335,877, 2008—$363,755, 2009—$393,946, 2010—$426,643 and 2011—$462,055.

On September 26, 2006 UES issued and sold $15 million of Series O 6.32% First Mortgage Bonds, due September 15, 2036, to institutional investors in the form of a private placement. The proceeds from this long-term financing were used principally to permanently finance long-lived utility plant additions that had been previously financed on an interim basis with short-term bank borrowings.

FG&E, through a private placement, consummated the issuance and sale on December 21, 2005 of $15 million of unsecured long-term notes to institutional investors. The notes have a term of 25 years and a coupon rate of 5.90%. The net proceeds were used to reduce FG&E’s outstanding short-term indebtedness.

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 December 31, 2006 is estimated to be in a range of up to approximately $157 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 agreements under which the long-term debt of Unitil’s two principal subsidiaries, UES and FG&E, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations.

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.

A summary of interest expense and interest income is provided in the following table:


Interest Expense, net (millions)
										2006 vs. 2005			2005 vs. 2004
	2006			2005			2004			Change			Change
Interest Expense
Long-term Debt	$	9.5		$	8.4		$	8.5		$	1.1		$	(0.1	)
Short-term Debt		1.5			1.0			0.5			0.5			0.5
Regulatory Liabilities		0.3			0.2			0.1			0.1			0.1

Subtotal Interest Expense		11.3			9.6			9.1			1.7			0.5

Interest Income
Regulatory Assets		(3.1	)		(2.6	)		(2.3	)		(0.5	)		(0.3	)
AFUDC and Other		(0.4	)		(0.2	)		—			(0.2	)		(0.2	)

Subtotal Interest Income		(3.5	)		(2.8	)		(2.3	)		(0.7	)		(0.5	)

Total Interest Expense, net	$	7.8		$	6.8		$	6.8		$	1.0		$	—

Credit Arrangements

At December 31, 2006, Unitil had unsecured committed bank lines for short-term debt in the aggregate amount of $40.0 million with three banks for which it pays commitment fees. The weighted average interest

rates on all short-term borrowings were 5.5%, 3.8% and 1.9% during 2006, 2005 and 2004, respectively. The Company had short-term debt outstanding through bank borrowings of approximately $26.0 million and $18.7 million at December 31, 2006 and December 31, 2005, respectively. On January 1, 2007, Unitil’s unsecured committed bank lines of credit increased to $41.0 million with the same three banks.

Leases

Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements.

Total rental expense under operating leases charged to operations for the years ended December 31, 2006, 2005 and 2004 amounted to $410,000, $301,000 and $249,000 respectively. FG&E leases its operations facility in Fitchburg, Massachusetts under an operating lease, with a primary term through January 31, 2013. The lease agreement allows for three additional five-year renewal periods at the option of FG&E. The following is a schedule of future operating lease payment obligations as of December 31, 2006:


Year Ending December 31 (000’s)
2007	$	456
2008		456
2009		453
2010		430
2011		378
2012-2016		647

Total Future Operating Lease Payments	$	2,820

The following is a schedule of future minimum lease payments and present value of net minimum lease payments under capital leases, as of December 31, 2006:


Year Ending December 31 (000’s)
2007	$	233
2008		178
2009		29
2010		1
2011		1

Total Minimum Lease Payments	$	442

Guarantees

The Company also provides limited guarantees on certain energy contracts entered into by the retail distribution utilities. The Company’s policy is to limit these guarantees to two years or less. As of December 31, 2006 there are $7.0 million of guarantees outstanding and these guarantees extend through October 8, 2008. 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 4: Energy Supply

Electricity Supply:

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts now have the opportunity to purchase their

electric supply from competitive retail suppliers. Retail choice has been successful for Unitil’s largest customers. As of December 2006, 45% of Unitil’s largest New Hampshire customers representing 18% of total New Hampshire electric sales and 87% of Unitil’s largest Massachusetts customers representing 42% of total Massachusetts electric sales are purchasing their electric power supply in the competitive market. However, 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 has been a common experience throughout the New England electricity market.

The transition to retail choice required the divestiture of Unitil’s existing power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility service. FG&E, UES, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the ISO-NE markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s retail customers.

Wyman Unit No. IV—Information with respect to FG&E’s ownership in Wyman Unit No. IV, at December 31, 2006, is shown below:

Joint Ownership Unit

State

Proportionate

Ownership

Share of

Total MW

Company’s

Net Book

Value (000’s)

Wyman Unit No. IV

0.1822

1.13

FG&E continues to have a 0.1822% non-operating ownership interest in the Wyman Unit No. IV (Wyman IV), an oil-fired electric generating station located in Yarmouth, Maine. The lead operating owner of Wyman IV is FPL Energy Wyman IV, LLC. In accordance with the electric industry restructuring in Massachusetts, and pursuant to the generation assets and power supply divestiture process discussed below, FG&E effectively divested its economic interest in Wyman IV when it entered into an agreement to, among other things, sell its entire entitlement in the output from Wyman IV over the expected remaining operating life of the unit. Kilowatt-hour generation and operating expenses associated with Wyman IV are divided on the same basis as ownership. FG&E’s proportionate ownership costs in Wyman IV are reflected in the Consolidated Statements of Earnings. Revenues from the entitlement sale of Wyman IV reflect a matching and collection of these costs. Accordingly, the cost associated with FG&E’s ownership in Wyman IV does not have a material impact on earnings.

Power Supply Divestiture

Prior to May 1, 2003, UES purchased all of its power supply from Unitil Power under the Unitil System Agreement, a FERC-regulated tariff, which provided for the recovery of all of Unitil Power’s power supply-related costs on a cost pass-through basis. Effective May 1, 2003, UES and Unitil Power amended the Unitil System Agreement, such that power sales from Unitil Power to UES ceased, and Unitil Power sold substantially all of its entitlements under the remaining portfolio of power supply contracts. Under the amended Unitil System Agreement, UES continues to pay contract release payments to Unitil Power for stranded costs associated with the portfolio sale and its other ongoing power supply-related costs. Recovery of the contract release payments by UES from its retail customers has been approved by the NHPUC.

Unitil Power divested its long-term power supply contracts to Mirant Corporation (Mirant). The purchase of power to supply UES’ Transition Service and Default Service requirements by UES from Mirant was linked to the Unitil Power divestiture. The NHPUC Order completed the state approval process for Unitil’s restructuring plan under which UES implemented customer choice for its customers on May 1, 2003. The divested power supply contracts continue through October 2010. On July 14, 2003 Mirant filed for Chapter 11 Bankruptcy protection. Mirant is currently performing all of its contractual obligations to Unitil Power and has completed its power supply obligations to UES. Mirant has satisfied all of its pre-petition claims made by Unitil. On January 3, 2006 Mirant emerged from Chapter 11 Bankruptcy protection.

In March 1999, FG&E completed the sale of its 4.5% interest in the New Haven Harbor Station generating unit. FG&E divested its remaining owned generation assets and long-term power supply contracts to Select Energy, Inc., a subsidiary of Northeast Utilities. Under the Select Energy contract, which was approved by the MDTE in January 2000, and went into effect February 1, 2000, FG&E began selling the entire output from its remaining long-term power supply contracts and the output of its two joint ownership units, Millstone Unit 3 and Wyman Unit No. IV, to Select Energy. Upon the sale of FG&E’s share of Millstone Unit 3 in 2001, this portion of the contract sale ceased. Effective with the termination of the Purchased Power Contract between FG&E and Linweave, Inc. on December 1, 2004, this portion of the contract sale also ceased. On December 30, 2005 Select Energy assigned the FG&E contracts portfolio to Constellation Energy Commodities Group effective January 1, 2006. Recovery of all costs associated with the divestiture of the FG&E power supply portfolio has been approved by the MDTE.

In connection with the implementation of retail choice, Unitil Power and FG&E divested substantially all of their long-term power supply contracts and interests in generation assets through the sale of the interest in those assets or the sale of the entitlements to the electricity provided by those generation assets and long-term power supply 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 NHPUC and MDTE, 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 four to six years, is $126.1 million as of December 31, 2006 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet (see Regulatory Assets table in Note 1.) 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.

Regulated Energy Supply

Regional Transmission and Power Markets

Gas Supply:

FG&E’s natural gas customers now have the opportunity to purchase their natural gas supply from third-party vendors, though most customers continue to purchase such supplies at regulated rates through FG&E as the provider of last resort. The costs associated with the acquisition of such wholesale natural gas supplies for customers who do not contract with third-party suppliers are recovered on a pass-through basis through periodically-adjusted rates and are included in Purchased Gas in the Consolidated Statements of Earnings.

Sources of Gas Supply

(Expressed as percent of total MMBtu of gas purchased)


	2006			2005			2004
Natural Gas:
Domestic firm		84.2	%		84.8	%		85.0	%
Canadian firm		2.0	%		3.4	%		5.4	%
Domestic spot market		11.0	%		9.3	%		5.9	%

Total natural gas		97.2	%		97.5	%		96.3	%
Supplemental gas		2.8	%		2.5	%		3.7	%

Total gas purchases		100.0	%		100.0	%		100.0	%


Cost of Gas Sold

	2006			2005			2004
Cost of gas purchased and sold per MMBtu	$	11.18		$	10.83		$	8.42
Percent Increase (Decrease) from prior year		3.2	%		28.7	%		17.9	%

FG&E has available under firm contract 14,057 MMBtu per day of year-round and seasonal transportation and underground storage capacity to its distribution facilities. As a supplement to pipeline natural gas, FG&E owns a propane air gas plant and a LNG storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas.

Note 5: Commitments and Contingencies

Regulatory Matters

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 NHPUC and MDTE, 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 four to six years, is $126.1 million as of December 31, 2006 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet (See Regulatory Assets table in Note 1.) 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.

On September 7, 2006, the MDTE issued an order allowing FG&E to recover 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 based on a fixed rate formula that was resulting in a significant underrecovery 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 MDTE’s order of September 7, 2006. FG&E intends to support the MDTE’s order but the Company cannot predict the outcome of the Attorney General’s appeal at this time.

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 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 MDTE and NHPUC.

Environmental Matters

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 December 31, 2006 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.

Note 6: Bad Debts

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2004 – 2006.

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Additions				Accounts Written Off		Balance at End of Period
	Balance at Beginning of Period		(A) Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2006
Electric	$	342,791	$	1,963,222	$	136,399	$	1,178,310	$	1,264,102
Gas		110,031		1,325,650		134,802		1,132,324		438,159
Other		16,926		29,313		1,780		13,493		34,526

	$	469,748	$	3,318,185	$	272,981	$	2,324,127	$	1,736,787

Year Ended December 31, 2005
Electric	$	392,824	$	714,917	$	116,290	$	881,240	$	342,791
Gas		89,602		721,171		116,366		817,108		110,031
Other		18,297		9,602		—		10,973		16,926

	$	500,723	$	1,445,690	$	232,656	$	1,709,321	$	469,748

Year Ended December 31, 2004
Electric	$	395,432	$	821,077	$	121,974	$	945,659	$	392,824
Gas		132,964		524,905		96,411		664,678		89,602
Other		13,080		10,500		—		5,283		18,297

	$	541,476	$	1,356,482	$	218,385	$	1,615,620	$	500,723

(A)

In 2006, the Company recorded a provision for the energy commodity portion of bad debts of $1.7 million. This provision was recognized in Purchased Electricity and Purchased Gas expense as the associated electric and gas utility revenues were billed. Purchased Electricity and Purchased Gas costs are recovered from customers through periodic rate reconciling mechanisms. Prior to 2006, the commodity portion of bad debt expense was recognized in Purchased Electricity and Purchased Gas expense when the accounts were actually written off from accounts receivable.

Note 7: Income Taxes

In June 2006, the FASB issued FIN 48. 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 applies to all tax positions related to income taxes subject to FAS 109. This includes tax positions considered to be routine as well as those with a high degree of uncertainty such as tax-advantaged transactions. FIN 48 effectively amends SFAS No. 5, such that all references to income taxes in SFAS No. 5 have been deleted and FIN 48 is now the primary guidance in accounting for uncertainty in income taxes. FIN 48 creates a single model to address accounting for uncertainty in tax positions. Under FIN 48, tax positions accounted for under FAS 109 will be evaluated for recognition, derecognition, and classification and the cumulative affect of adopting FIN 48 may be recorded as an adjustment to retained earnings.

Federal Income Taxes were provided for the following items for the years ended December 31, 2006, 2005 and 2004, respectively:


	2006			2005			2004
Current Federal Tax Provision (000’s):
Operating Income	$	3,448		$	3,671		$	438

Total Current Federal Tax Provision		3,448			3,671			438

Deferred Federal Tax Provision (000’s)
Property Plant and Equipment		(656	)		(841	)		2,669
Abandoned Properties		—			(796	)		(769	)
Accrued Revenue		795			1,296			1,779
Deferred Compensation and Pensions		271			299			(3	)
Regulatory Assets and Liabilities		(5	)		—			(194	)
Net Operating Loss Carryforward		—			—			92
Alternative Minimum Tax		—			—			(355	)
Other, net		(87	)		(180	)		(151	)

Total Deferred Federal Tax Provision (Benefit)		318			(222	)		3,068

Total Federal Tax Provision	$	3,766		$	3,449		$	3,506

The components of the Federal and State income tax provisions reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2006, 2005 and 2004 are shown in the table below. In addition to the provisions for state income taxes, the Company recorded provisions of $211,000, $179,000 and $179,000 in 2006, 2005 and 2004, respectively for state Business Enterprise taxes which are included in Local Property and Other Taxes on the consolidated statements of earnings.


Federal and State Tax Provisions (000’s)	2006		2005			2004
Federal
Current	$	3,448	$	3,671		$	438
Deferred		318		(222	)		3,068

Total Federal Tax Provision		3,766		3,449			3,506

State
Current		337		844			602
Deferred		163		(18	)		98

Total State Tax Provision		500		826			700

Total Provision for Federal and State Income Taxes	$	4,266	$	4,275		$	4,206

The differences between the Company’s provisions for Income Taxes, including the provision for Business Enterprise taxes, and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below:


	2006		2005		2004
Statutory Federal Income Tax Rate	34	%	34	%	34	%
Income Tax Effects of:
State Income Taxes, Net	5		5		5
Abandoned Property	—		(6	)	(6	)
Utility Plant Differences	(4	)	—		1
Other, Net	1		—		—

Effective Income Tax Rate	36	%	33	%	34	%

Temporary differences which gave rise to deferred tax assets and liabilities are shown below:


Deferred Income Taxes (000’s)	2006			2005
Property, Plant and Equipment	$	27,209		$	27,186
Accrued Revenue		14,687			13,204
Regulatory Assets and Liabilities		8,905			8,700
Retirement Benefit Obligations		(17,644	)		1,615
Other		1,369			1,592

Total Deferred Income Tax Liabilities	$	34,526		$	52,297

Note 8: Retirement Benefit Plans

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. See below for a table showing the incremental effect of applying SFAS No. 158 on individual line items of the Company’s Consolidated Balance Sheet at December 31, 2006.

Incremental Effect of Applying SFAS No. 158—The table below shows the incremental effect of applying SFAS No. 158 on individual line items of the Company’s Consolidated Balance Sheet at December 31, 2006.

Incremental Effect of Applying SFAS No. 158

On Individual Line Items of the Company’s Consolidated Balance Sheet

December 31, 2006

(000’s)


	Before Application of SFAS No. 158		SFAS No. 158 Adjustments			After Application of SFAS No. 158
Prepaid Pension	$	11,000	$	(11,000	)	$	—
Regulatory Assets		5,261		26,455			31,716
Total Assets		467,972		15,455			483,427

Other Current Liabilities	$	—	$	70		$	70
Retirement Benefit Obligations		13,969		35,694			49,663
Deferred Income Taxes		2,665		(20,309	)		(17,644	)
Total Capitalization and Liabilities		467,972		15,455			483,427

Defined Benefit Pension Plan—The Company sponsors the Unitil Corporation Retirement Plan (the Plan), a defined benefit pension plan covering substantially all of its employees. Under the Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

On October 27, 2004 the MDTE approved FG&E’s request for a reconciliation rate adjustment mechanism (the Pension / PBOP Adjustment Factor (PAF)) to recover the costs associated with the Company’s pension and PBOP costs on an annually reconciling basis. As a result of this order, 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.

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. Under the Settlement Agreement UES will amortize its deferred pension costs as these amortization 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:


Components of NPPC (000’s)	2006			2005			2004
Service Cost	$	1,800		$	1,458		$	1,302
Interest Cost		3,153			3,085			3,028
Expected Return on Plan Assets		(3,775	)		(3,404	)		(3,393	)
Amortization of Prior Service Cost		107			107			101
Amortization of Net Loss		1,324			1,146			944

Subtotal NPPC		2,609			2,392			1,982
Amounts Capitalized and Deferred		(1,014	)		(1,751	)		(1,926	)

NPPC Recognized	$	1,595		$	641		$	56

The estimated amortization related to Actuarial Loss and Prior Service Cost included in NPPC over the next fiscal year is $1.4 million.


Key Assumptions (Weighted Average)	2006		2005		2004
Used to Determine Benefit Obligations at December 31:
Discount Rate	5.50	%	5.50	%	6.50	%
Rate of Compensation Increase	3.50	%	3.50	%	3.50	%

Used to Determine NPPC for years ended December 31:
Discount Rate	5.50	%	6.00	%	6.50	%
Expected Long-Term Rate of Return on Plan Assets	8.50	%	8.50	%	8.75	%
Rate of Compensation Increase	3.50	%	3.50	%	3.50	%

The following table represents information on the Plan’s Projected Benefit Obligation (PBO), fair value of plan assets and the Plan’s funded status. The PBO includes expectations of future employee service and compensation increases.


Change in PBO (000’s)	2006			2005
PBO at Beginning of Year	$	58,586		$	49,757
Service Cost		1,800			1,458
Interest Cost		3,153			3,085
Plan Amendments		—			110
Benefits Paid		(2,476	)		(2,404	)
Actuarial Loss		964			6,580

PBO at End of Year	$	62,027		$	58,586


Change in Plan Assets (000’s):
Fair Value of Plan Assets at Beginning of Year	$	44,535		$	42,304
Actual Return on Plan Assets		4,958			2,135
Employer Contributions		2,510			2,500
Benefits Paid		(2,476	)		(2,404	)

Fair Value of Plan Assets at End of Year	$	49,527		$	44,535


PBO and Funded Status (000’s):
Fair Value of Plan Assets	$	49,527		$	44,535
PBO		62,027			58,586

Funded Status		(12,500	)		(14,051	)
Unrecognized Actuarial Loss and Prior Service Cost		—			25,150

Prepaid (Unfunded) Pension Obligation	$	(12,500	)	$	11,099

The following table represents the Plan’s weighted-average investment asset allocations at December 31:


	Target Allocation 2007	Actual Allocation at December 31
	Target Allocation 2007	2006		2005		2004
Equity Securities	58-62%	61	%	60	%	61	%
Debt Securities	38-42%	39	%	40	%	39	%
Real Estate and Other	0-2%	0	%	0	%	0	%

Total		100	%	100	%	100	%

The desired investment objective is a long-term rate of return on assets that is approximately 6% greater than the assumed rate of inflation as measured by the Consumer Price Index. The target rate of return for the Plan has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

The following tables represent Plan contributions and benefit payments. There were no participant contributions.


(000’s)	2006		2005		2004
Employer Contributions	$	2,510	$	2,500	$	2,000
Benefit Payments	$	2,476	$	2,404	$	2,280


Estimated Future Benefit Payments
2007	2008	2009	2010	2011	2012-2016
$2,730	$2,873	$2,918	$3,115	$3,207	$18,422

Postretirement Benefits—The Company also sponsors the Unitil Employee Health and Welfare Benefits Plan (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.

In January 2004 and May 2004, the FASB issued, respectively, Statement No. 106-1 (SFAS No. 106-1) and Statement No. 106-2 (SFAS No. 106-2), “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, (the Act). The Act includes a subsidy to a plan sponsor that is based on 28 percent of an individual beneficiary’s annual prescription drug costs between $250 and $5,000 and the opportunity for a retiree to obtain a prescription drug benefit under Medicare. SFAS No. 106-1 and SFAS No. 106-2 require the disclosure of the effects, if any, of the Act on the reported measure of the accumulated postretirement benefit obligation and how that effect has been, or will be, reflected in the net postretirement benefit costs of current or subsequent periods. On January 28, 2005, the final Medicare Part D Prescription Drug Rules were posted to the Federal Register. Based on these rules, the Company’s estimated PBOP Projected Benefit Obligation was reduced by $5.1 million. Also, the Company has estimated that its annual PBOP costs will be reduced by $0.4 million under the Act. These reductions are reflected in the Company’s Consolidated Financial Statements. The Company’s health care insurance provider has concluded that the Company’s PBOP Plan is equal to or better than standard Medicare Part D coverage. Additionally, the Company’s recognition of the Act is not expected to have any impact on the rate of participation in the PBOP Plan or per capita claims.

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 components of net periodic postretirement benefit cost (NPPBC) are as follows:


Components of NPPBC (000’s)	2006			2005			2004
Service Cost	$	1,283		$	993		$	899
Interest Cost		2,028			1,795			1,827
Expected Return on Plan Assets		(194	)		(41	)		—
Amortization of Prior Service Cost		1,360			1,401			1,458
Amortization of Transition Obligation		21			21			21
Amortization of Net Loss		160			—			—

Subtotal NPPC		4,658			4,169			4,205
Amounts Capitalized and Deferred		(2,217	)		(2,051	)		(2,498	)

NPPBC Recognized	$	2,441		$	2,118		$	1,707

The estimated amortization related to Actuarial Loss and Prior Service Cost included in NPPBC over the next fiscal year is $1.5 million.

The following table includes assumptions used in determining the various PBOP values.


Key Assumptions (Weighted Average)	2006		2005		2004
Used to Determine Benefit Obligations at December 31:
Discount Rate	5.50	%	5.50	%	6.50	%
Rate of Compensation Increase	N/A		N/A		N/A
Health Care Cost Trend Rate Assumed for Next Year	8.50	%	9.00	%	8.00	%
Ultimate Health Care Cost Trend Rate	4.00	%	4.00	%	4.00	%
Year That the Health Care Cost Trend Rate Reaches the Ultimate Trend Rate	2016		2016		2013

Used to Determine NPPBC for years ended December 31:
Discount Rate	5.50	%	6.00	%	6.50	%
Expected Long-Term Rate of Return on Plan Assets	8.50%/5.50	%⁽¹⁾	8.50%/5.50	%⁽¹⁾	N/A
Rate of Compensation Increase	N/A		N/A		N/A
Health Care Cost Trend Rate Assumed for Next Year	9.00	%	8.00	%	9.00	%
Ultimate Health Care Cost Trend Rate	4.00	%	4.00	%	4.00	%
Year That the Health Care Cost Trend Rate Reaches the Ultimate Trend Rate	2016		2013		2013

⁽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.

Assumed health care cost trend rates have a significant effect on the amounts reported. A one-percentage-point change in the assumed health care cost trend rates would have the following effects:


1-Percentage Point Increase (000’s)	2006			2005			2004
Effect on Total of Service and Interest Cost	$	683		$	526		$	564
Effect on Postretirement Benefit Obligation	$	6,381		$	5,917		$	4,079

1-Percentage Point Decrease (000’s)
Effect on Total of Service and Interest Cost	$	(530	)	$	(413	)	$	(438	)
Effect on Postretirement Benefit Obligation	$	(5,091	)	$	(4,737	)	$	(3,290	)

The following table represents information on the PBOP Plan’s fair value of plan assets and the PBOP Plan’s funded status. The PBO includes expectations of future employee service and compensation increases.


Change in PBO (000’s)	2006			2005
PBO at Beginning of Year	$	37,528		$	27,917
Service Cost		1,283			993
Interest Cost		2,028			1,795
Plan Amendments		—			(1,797	)
Benefits Paid		(1,540	)		(1,334	)
Actuarial (Gain) or Loss		(1,192	)		9,954

PBO at End of Year	$	38,107		$	37,528


Change in Plan Assets (000’s):
Fair Value of Plan Assets at Beginning of Year	$	2,304		$	1,101
Actual Return on Plan Assets		78			37
Employer Contributions		2,210			2,500
Benefits Paid		(1,540	)		(1,334	)

Fair Value of Plan Assets at End of Year	$	3,052		$	2,304


Obligation and Funded Status (000’s):
Fair Value of Plan Assets	$	3,052		$	2,304
PBO		38,107			37,528

Funded Status		(35,055	)		(35,224	)
Unrecognized Actuarial Loss and Prior Service Cost		—			30,339

(Unfunded) PBOP Obligation	$	(35,055	)	$	(4,885	)

The following tables represent PBOP contributions and benefit payments made in 2004 – 2006 and estimated future benefit payments. There were no participant contributions.


(000’s)	Expected 2007		2006		2005		2004
Employer Contributions	$	2,500	$	2,210	$	2,500	$	2,355
Benefit Payments	$	1,398	$	1,540	$	1,334	$	1,257


Estimated Future Benefit Payments
2008	2009	2010	2011	2012-2016
$1,496	$1,585	$1,758	$1,898	$11,019

Supplemental Executive Retirement Plan—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 cost associated with the SERP amounted to approximately $305,000, $190,000 and $194,000 for the years ended December 31, 2006, 2005 and 2004, respectively.

The components of net periodic SERP cost are as follows:


Components of Net Periodic SERP Cost (000’s)	2006			2005			2004
Service Cost	$	148		$	90		$	89
Interest Cost		103			80			75
Amortization of Prior Service Cost		(2	)		(2	)		3
Amortization of Transition Obligation		17			17			17
Amortization of Net Loss		39			5			10

Net Periodic SERP Cost	$	305		$	190		$	194

The estimated amortization related to Actuarial Loss and Prior Service Cost included in Net Periodic SERP Cost over the next fiscal year is less than $0.1 million.

The following table includes information regarding Unitil’s SERP costs as well as key actuarial assumptions:


Additional Information (000’s):	2006			2005			2004
Accumulated Benefit Obligation	$	670		$	800		$	673

Weighted-Average Assumptions
Used to Determine Benefit Obligations at December 31:
Discount Rate		5.50	%		5.50	%		6.50	%
Rate of Compensation Increase		3.50	%		3.50	%		3.50	%

Used to Determine Net Periodic SERP Cost for years ended December 31:
Discount Rate		5.50	%		6.50	%		6.50	%
Expected Long-Term Rate of Return on Plan Assets		N/A			N/A			N/A
Rate of Compensation Increase		3.50	%		3.50	%		3.50	%

The following table represents information on the SERP’s Projected Benefit Obligation (PBO), fair value of plan assets and the plan’s funded status.


Change in PBO (000’s)	2006			2005
PBO at Beginning of Year	$	1,910		$	1,218
Service Cost		148			90
Interest Cost		103			80
Benefits Paid		(72	)		(72	)
Actuarial (Gain) or Loss		90			594

PBO at End of Year	$	2,179		$	1,910


Change in Plan Assets (000’s):
Fair Value of Plan Assets at Beginning of Year	$	—		$	—
Actual Return on Plan Assets		—			—
Employer Contributions		72			72
Benefits Paid		(72	)		(72	)

Fair Value of Plan Assets at End of Year	$	—		$	—



Obligation and Funded Status (000’s):	2006			2005
Fair Value of Plan Assets	$	—		$	—
PBO		2,179			1,910

Funded Status		(2,179	)		(1,910	)
Unrecognized Prior Service Cost and Actuarial Loss		—			767

(Unfunded) SERP Liability	$	(2,179	)	$	(1,143	)

The following tables represent SERP contributions and benefit payments made in 2004 – 2006 and estimated future benefit payments. There were no participant contributions.


(000’s)	2006		2005		2004
Employer Contributions	$	72	$	72	$	72
Benefit Payments	$	72	$	72	$	72


Estimated Future Benefit Payments
2007	2008	2009	2010	2011	2012-2016
$71	$69	$66	$63	$61	$1,256

Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k)) under Section 401(k) of the Internal Revenue Code, covering substantially all of the Company’s employees. Participants may elect to defer current compensation by contributing to the plan. The Company matches contributions, with a maximum matching contribution of 3% of current compensation. Employees may direct, at their sole discretion, the investment of their savings plan balances (both the employer and employee portions) into a variety of investment options, including a Company Common Stock fund. Participants are 100% vested in contributions made on their behalf, once they have completed three years of service. The Company’s share of contributions to the plan was $528,000, $503,000 and $499,000 for the years ended December 31, 2006, 2005, and 2004, respectively.

Note 9: Earnings Per Share

The following table reconciles basic and diluted earnings per share, assuming all dilutive outstanding stock options were converted to common shares per SFAS No. 128, “Earnings per Share.”


(000’s except share and per share data)	2006		2005		2004
Earnings Available to Common Shareholders	$	7,900	$	8,397	$	8,011

Weighted Average Common Shares Outstanding—Basic		5,597,465		5,551,420		5,509,321
Plus: Diluted Effect of Incremental Shares		14,269		16,298		15,514
Weighted Average Common Shares Outstanding—Diluted		5,611,734		5,567,718		5,524,835

Earnings per Share—Diluted	$	1.41	$	1.51	$	1.45

Weighted average options to purchase 72,500, 72,500 and 35,000 shares of Common Stock were outstanding during 2006, 2005 and 2004, respectively, but were not included in the computation of Weighted Average Common Shares Outstanding for purposes of computing diluted earnings per share, because the effect would have been antidilutive.

Note 10: Segment Information

Unitil reported four segments: utility electric operations, utility gas operations, other, and non-regulated. Unitil is engaged principally in the retail sale and distribution of electricity in New Hampshire and both electricity and natural gas service in Massachusetts through its retail distribution

subsidiaries UES and FG&E. 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. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies.

Unitil Realty, Unitil Service and the holding company are included in the “Other” column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company’s corporate headquarters. The earnings of the holding company are principally derived from income earned on short-term investments and real property owned for Unitil and its subsidiaries’ use. Unitil Resources and Usource are included in the Non-Regulated column below.

The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on cost allocation factors included in rate applications approved by the NHPUC and MDTE. Assets allocated to each segment are based upon specific identification of such assets provided by Company records.

The following table provides significant segment financial data for the years ended December 31, 2006, 2005 and 2004.


Year Ended December 31, 2006 (000’s)	Electric		Gas		Other			Non- Regulated			Total
Revenues	$	225,154	$	33,271	$	—		$	2,436		$	260,861
Interest Income		2,926		129		405			—			3,460
Interest Expense		9,508		1,137		580			76			11,301
Depreciation & Amortization Expense		11,213		3,489		1,301			66			16,069
Income Tax Expense (Benefit)		4,096		142		147			(119	)		4,266
Segment Profit (Loss)		6,984		481		634			(199	)		7,900

Segment Assets		346,744		113,065		22,685			933			483,427
Capital Expenditures		26,286		7,186		154			16			33,642

Year Ended December 31, 2005 (000’s)
Revenues	$	197,339	$	32,767	$	—		$	2,039		$	232,145
Interest Income		2,516		47		217			—			2,780
Interest Expense		8,144		858		569			50			9,621
Depreciation & Amortization Expense		14,514		3,098		1,443			68			19,123
Income Tax Expense (Benefit)		3,888		426		(41	)		2			4,275
Segment Profit (Loss)		6,957		911		536			(7	)		8,397

Segment Assets		328,208		98,184		22,516			1,173			450,081
Capital Expenditures		17,211		6,936		220			—			24,367

Year Ended December 31, 2004 (000’s)
Revenues	$	183,889	$	28,685	$	—		$	1,563		$	214,137
Interest Income		2,051		130		166			—			2,347
Interest Expense		7,601		906		595			19			9,121
Depreciation & Amortization Expense		14,431		2,709		1,622			68			18,830
Income Tax Expense (Benefit)		3,729		507		58			(88	)		4,206
Segment Profit (Loss)		6,649		1,202		300			(140	)		8,011

Segment Assets		340,800		94,239		21,069			902			457,010
Capital Expenditures		17,566		5,111		245			—			22,922

Note 11: Quarterly Financial Information (unaudited; 000’s except per share data)

Quarterly earnings per share may not agree with the annual amounts due to rounding. Basic and Diluted Earnings per Share are the same for the periods presented.


	Three Months Ended
	March 31,				June 30,				September 30,				December 31,
	2006		2005		2006		2005		2006		2005		2006		2005
Total Operating Revenues	$	70,703	$	60,000	$	60,226	$	51,439	$	66,287	$	56,654	$	63,645	$	64,052

Operating Income	$	3,935	$	4,504	$	3,329	$	3,311	$	3,812	$	3,240	$	4,779	$	4,486
Net Income Applicable to Common	$	2,013	$	2,671	$	1,401	$	1,497	$	1,792	$	1,562	$	2,694	$	2,667

	Per Share Data:
Earnings Per Common Share	$	0.36	$	0.48	$	0.25	$	0.27	$	0.32	$	0.28	$	0.48	$	0.48
Dividends Paid Per Common Share	$	0.345	$	0.345	$	0.345	$	0.345	$	0.345	$	0.345	$	0.345	$	0.345

On November 4, 2005, UES filed a request for an electric base rate increase with the NHPUC. On February 3, 2006, the NHPUC issued an order setting temporary rates based on which any final rate change approved by the NHPUC would be reconciled to be effective as of January 1, 2006. On August 24, 2006 a settlement agreement resolving the base rate case among UES, the Office of the Consumer Advocate, and the NHPUC Staff was filed, and on October 6, 2006, the agreement was approved by the NHPUC.

In the second quarter of 2006, when the rate filing was under review, the Company recorded an estimate of expected revenue and expenses for the first six months of 2006 based on the temporary rate order effective date and the current status of proceedings. In the third quarter of 2006, based on the approval by the NHPUC of the settlement agreement, the Company recorded final revenue and expense figures, aligning previously estimated amounts with the settlement agreement.

In the Company’s judgment, the impact of the estimated and final revenues and expenses recorded in 2006 related to this rate proceeding did not have a material impact on the interim quarterly results as reported on Form 10-Q and the Company’s current year operating income.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A.

Controls and Procedures

Management’s Report on Internal Control over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). In addition, management is required to report their assessment, including their evaluation criteria, on the design and operating effectiveness of the Company’s internal control over financial reporting in Form 10-K.

The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The Company’s internal control over financial reporting provides reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles. The Company’s internal control over financial reporting includes policies and procedures which provide reasonable assurances that transactions are properly initiated, authorized, recorded, reported and disclosed, and provide reasonable assurances regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

During 2006, management conducted an assessment of the Company’s internal control over financial reporting reflected in the financial statements, based upon criteria established in the “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on management’s assessment, which included a comprehensive review of the design and operating effectiveness of the Company’s internal control over financial reporting, management believes the Company’s internal control over financial reporting is designed and operating effectively as of December 31, 2006.

Vitale, Caturano and Company, an independent registered public accounting firm, has audited management’s assessment of the effectiveness of the internal control over financial reporting as stated in their report which is included herein.

Item 9B.

Other Information

None

PART III

Item 10.

Directors and Executive Officers of the Registrant

Information required by this Item is set forth in Part I, Item 1 of this Form 10-K. Information regarding the Company’s Code of Ethics is set forth in the “Corporate Governance and Policies of the Board” section of the 2006 Proxy Statement as filed with the Securities and Exchange Commission.

Item 11.

Executive Compensation

Information required by this Item is set forth in the “Compensation Discussion and Analysis” and “Compensation of Named Executive Officers” sections of the 2006 Proxy Statement as filed with the Securities and Exchange Commission.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this Item is set forth in the “Beneficial Ownership” and “As to the Election of Directors” sections of the 2006 Proxy Statement as filed with the Securities and Exchange Commission, as well as the Equity Compensation Plan Benefit Information table in Part II, Item 5 of this Form 10-K.

Item 13.

Certain Relationships and Related Transactions

None

Item 14.

Principal Accountant Fees and Services

Information required by this Item is set forth in the “Principal Accountant Fees and Services” section of the 2006 Proxy Statement as filed with the Securities and Exchange Commission.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a) (1) and (2) – LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data:

•

Report of Independent Registered Public Accounting Firm

•

Consolidated Balance Sheets—December 31, 2006 and 2005

•

Consolidated Statements of Earnings for the years ended December 31, 2006, 2005, and 2004

•

Consolidated Statements of Capitalization—December 31, 2006 and 2005

•

Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005, and 2004

•

Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2006, 2005, and 2004

•

Notes to Consolidated Financial Statements

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted.

(3) – LIST OF EXHIBITS


Exhibit Number	Description of Exhibit	Reference*
3.1	Articles of Incorporation of the Company.	Exhibit 3.1 to Form S-14 Registration Statement 2-93769

3.2	Articles of Amendment to the Articles of Incorporation Filed on March 4, 1992 and April 30, 1992.	Exhibit 3.2 to Form 10-K for 1991

3.3	By-laws of the Company.	Exhibit 4 to Form S-8 Registration Statement 333-73327

3.4	Articles of Exchange of Concord Electric Company (CECo), Exeter & Hampton Electric Company (E&H) and the Company.	Exhibit 3.3 to 10-K for 1984

3.5	Articles of Exchange of CECo, E&H, and the Company—Stipulation of the Parties Relative to Recordation and Effective Date.	Exhibit 3.4 to Form 10-K for 1984

3.6	The Agreement and Plan of Merger dated March 1, 1989 among the Company, Fitchburg Gas and Electric Light Company (FG&E) and UMC Electric Co., Inc. (UMC).	Exhibit 25(b) to Form 8-K dated March 1, 1989

3.7	Amendment No. 1 to The Agreement and Plan of Merger dated March 1, 1989 among the Company, FG&E and UMC.	Exhibit 28(b) to Form 8-K dated December 14, 1989


Exhibit Number	Description of Exhibit	Reference*
4.1	Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958.	Exhibit 4.1 to Form 10-K for 2002

4.2	FG&E Purchase Agreement dated March 20, 1992 for the 8.55% Senior Notes due March 31, 2004.	Exhibit 4.18 to Form 10-K for 1993

4.3	FG&E Note Agreement dated November 30, 1993 for the 6.75% Notes due November 23, 2023.	Exhibit 4.18 to Form 10-K for 1993

4.4	FG&E Note Agreement dated January 26, 1999 for the 7.37% Notes due January 15, 2028.	Exhibit 4.25 to Form 10-K for 1999

4.5	FG&E Note Agreement dated June 1, 2001 for the 7.98% Notes due June 1, 2031.	Exhibit 4.6 to Form 10-Q for June 30, 2001

4.6	Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for the 8.00% Senior Secured Notes due August 1, 2017.	Exhibit 4.22 to Form 10-K for 1997

4.7	FG&E Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025.	Exhibit 4.7 to Form 10-K for 2003

4.8	FG&E Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030.	**

4.9	Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006.	**

10.1	Unitil System Agreement dated June 19, 1986 providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.	Exhibit 10.9 to Form 10-K for 1986

10.2	Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale requirements electric service to CECo and E&H.	Exhibit 10.8 to Form 10-K for 1987

10.3	Transmission Agreement between Unitil Power Corp. and Public Service Company of New Hampshire, effective November 11, 1992.	Exhibit 10.6 to Form 10-K for 1993

10.4	Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.1 to Form 10-Q for September 30, 2003

10.5	Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.	Exhibit 10.2 to Form 10-Q for September 30, 2003

10.6	Key Employee Stock Option Plan effective January 17, 1989.	Exhibit 10.56 to Form 8 dated April 12, 1989

10.7	Unitil Corporation Key Employee Stock Option Plan Award Agreement.	Exhibit 10.63 to Form 10-K for 1989

10.8	Unitil Corporation Management Performance Compensation Plan.	Exhibit 10.94 to Form 10-K/A for 1993

10.9	Unitil Corporation Supplemental Executive Retirement Plan effective as of January 1, 1987.	Exhibit 10.95 to Form 10-K/A for 1993

10.10	Unitil Corporation 1998 Stock Option Plan.	Exhibit 10.12 to Form 10-K for 1998


Exhibit Number	Description of Exhibit	Reference*
10.11	Unitil Corporation Management Incentive Plan.	Exhibit 10.13 to Form 10-K for 1998

10.12	Entitlement Sale and Administrative Service Agreement with Select Energy.	Exhibit 10.14 to Form 10-K for 1999

10.13	Purchase and Sale Agreement For New Haven Harbor.	Exhibit 10.15 to Form 10-K for 1999

10.14	Labor Agreement effective June 1, 2000 between CECo and The International Brotherhood of Electrical Workers, Local Union No. 1837.	Exhibit 10.13 to Form 10-K for 2000

10.15	Labor Agreement effective June 1, 2000 between E&H and The International Brotherhood of Electrical Workers, Local Union No. 1837.	Exhibit 10.14 to Form 10-K for 2000

10.16	Labor Agreement effective June 1, 2000 between FG&E and The Utility Workers of America, AFL-CIO., Local Union No. B340, The Brotherhood of Utility Workers Council.	Exhibit 10.15 to Form 10-K for 2000

10.17	Unitil Corporation 2003 Restricted Stock Plan.	Exhibit 10.16 to Form 10-K for 2002

10.18	Portfolio Sale and Assignment and Transition Service and Default Service Supply Agreement By and Among Unitil Power Corp., Unitil Energy Systems, Inc. and Mirant Americas Energy Marketing, LP.	Exhibit 10.17 to Form 10-K for 2002

10.19	Unitil Corporation Tax Deferred Savings and Investment Plan—Trust Agreement.	Exhibit 10.1 to Form 10-Q for September 30, 2004

10.20	Employment Agreement effective as of November 1, 2006 by and between Unitil Corporation and Robert G. Schoenberger.	Exhibit 10.1 to Form 8-K dated September 29, 2006

11.1	Statement Re: Computation in Support of Earnings per Share For the Company.	Filed herewith

12.1	Statement Re: Computation in Support of Ratio of Earnings to Fixed Charges for the Company.	Filed herewith

21.1	Statement Re: Subsidiaries of Registrant.	Filed herewith

23.1	Consent of Independent Registered Public Accounting Firm.	Filed herewith

23.2	Consent of Independent Registered Public Accounting Firm.	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


Exhibit Number	Description of Exhibit	Reference*
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

*	The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference.

**	In accordance with Item 601(b)(4)(iii)(A) of Federal Securities Regulation S-K, the instrument defining the debt of the Registrant and its subsidiary, described above, has been omitted but will be furnished to the Commission upon request.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	UNITIL CORPORATION

Date February 21, 2007	By	/s/ ROBERT G. SCHOENBERGER
		Robert G. Schoenberger
		Chairman of the Board of Directors, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature	Capacity	Date

/s/ ROBERT G. SCHOENBERGER Robert G. Schoenberger	Principal Executive Officer; Director	February 21, 2007

/s/ MARK H. COLLIN Mark H. Collin	Principal Financial Officer	February 21, 2007

/s/ LAURENCE M. BROCK Laurence M. Brock	Principal Accounting Officer	February 21, 2007

/s/ MICHAEL J. DALTON Michael J. Dalton	Director	February 21, 2007

/s/ ALBERT H. ELFNER, III Albert H. Elfner, III	Director	February 21, 2007

/s/ ROSS B. GEORGE Ross B. George	Director	February 21, 2007

/s/ M. BRIAN O’SHAUGHNESSY M. Brian O’Shaughnessy	Director	February 21, 2007

/s/ CHARLES H. TENNEY, III Charles H. Tenney, III	Director	February 21, 2007

/s/ DR. SARAH P. VOLL Dr. Sarah P. Voll	Director	February 21, 2007

/s/ EBEN S. MOULTON Eben S. Moulton	Director	February 21, 2007

/s/ DAVID P. BROWNELL David P. Brownell	Director	February 21, 2007

/s/ EDWARD F. GODFREY Edward F. Godfrey	Director	February 21, 2007

/s/ MICHAEL B. GREEN Michael B. Green	Director	February 21, 2007

/s/ DR. ROBERT V. ANTONUCCI Dr. Robert V. Antonucci	Director	February 21, 2007