Edgar Filing: UNITIL CORP

Cash Provided by Operating Activities

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, 2007

¨	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, 2007, the aggregate market value of common stock held by non-affiliates of the registrant was $151,539,461.

The number of common shares outstanding of the registrant was 5,756,795 as of February 12, 2008.

Documents Incorporated by Reference:

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 17, 2008, are incorporated by reference into Part III of this Report

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2007

Table of Contents


Item	Description	Page
	PART I
1.	Business	2
	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	14
2.	Properties	14
3.	Legal Proceedings	15
4.	Submission of Matters to a Vote of Security Holders	15
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
6.	Selected Financial Data	19
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
7A.	Quantitative and Qualitative Disclosures about Market Risk	35
8.	Financial Statements and Supplementary Data	37
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71
9A.	Controls and Procedures	71
9B.	Other Information	71
	PART III
10.	Directors and Executive Officers of the Registrant	72
11.	Executive Compensation	72
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
13.	Certain Relationships and Related Transactions	72
14.	Principal Accountant Fees and Services	72
	PART IV
15.	Exhibits and Financial Statement Schedules	73
	Signatures	77


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
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.

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 100,000 electric customers and 15,100 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 $248.9 million at December 31, 2007. Unitil’s total revenue was $262.9 million in 2007. Earnings applicable to common shareholders for 2007 was $8.6 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 $225.0 million for 2007. Earnings from electric utility operations were $7.3 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 72,200 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’ 2007 retail electric operating revenue was $157.8 million, of which approximately 51.0% was derived from residential sales and 49.0% 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 27,800 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 2007 retail electric operating revenue was $67.2 million, of which approximately 52.0% was derived from residential sales and 48.0% from commercial/industrial sales.

Gas Utility Operations

Natural gas is supplied and distributed by FG&E to approximately 15,100 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 2007 gas operating revenue was $34.2 million, of which approximately 55.0% was derived from residential firm sales and 45.0% from commercial/industrial firm sales. Earnings from FG&E’s gas utility operations were $1.0 million for 2007.

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 $3.7 million in 2007. Earnings from Unitil’s non-regulated operations were $0.3 million in 2007. 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 9 herein). Net earnings from Unitil’s other non-utility operations were zero in 2007 as earnings on the short-term investments and real property discussed above were offset by interest expense.

(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 Public Utilities (MDPU), 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.

MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, is $104.8 million as of December 31, 2007 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.

As a result of restructuring of the electric utility industry in Massachusetts and New Hampshire, Unitil’s customers in both New Hampshire and Massachusetts 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 2007, 94, or 60%, of Unitil’s largest New Hampshire customers representing 23% of total New Hampshire electric sales and 27, or 84%, of Unitil’s largest Massachusetts customers representing 35% of total Massachusetts electric sales are purchasing their electric power supply in the competitive market. This represents an increase of 25 in the number of large customers, primarily in New Hampshire, participating in the competitive market as of December 2007 compared to December 2006. 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 load-following 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 energy supply. MDPU 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 and provide 100% of supply requirements. Default Service power supply contracts for residential and small and medium general service customers are acquired every 6 months, are 12 months in duration and provide 50% of the supply requirements. The MDPU regularly investigates alternatives to its statewide procurement policy, which could lead to future changes in the procurement structure described above.

UES currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. UES procures Default Service supply for its large general service accounts through competitive solicitations for power contracts of three-months in duration for 100% of supply requirements. UES procures Default Service supply for its other customers through a series of two one-year contracts and two three-year contracts, each providing 25% of the total supply requirements of the group.

Regional Transmission and Power Markets

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 MDPU and NHPUC.

GAS SUPPLY

FG&E’s natural gas customers have the opportunity to purchase their natural gas supply from third-party vendors, although 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. FG&E arranges for gas delivery to its city gate station or underground storage through its own long-term contracts with the Tennessee interstate pipeline. The suppliers do have the option to deliver to the city gate station or in the case of liquefied natural gas (LNG) or liquefied propane gas (LPG) trucked to each storage facility within FG&E’s service territory.

Sources of Gas Supply

(Expressed as percent of total MMBtu of gas purchased)


	2007		2006		2005
Natural Gas:
Domestic firm	94.6	%	84.2	%	84.8	%
Canadian firm	2.2	%	2.0	%	3.4	%
Domestic spot market	2.3	%	11.0	%	9.3	%

Total natural gas	99.1	%	97.2	%	97.5	%
Supplemental gas	0.9	%	2.8	%	2.5	%

Total gas purchases	100.0	%	100.0	%	100.0	%

Cost of Gas Sold


	2007			2006			2005
Cost of gas purchased and sold per MMBtu	$	10.41		$	11.18		$	10.83
Percent Increase (Decrease) from prior year		(6.9	%)		3.2	%		28.7	%

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, 2007, there are no material losses reasonably possible in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

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

FG&E recovers the environmental response costs incurred at this former MGP site not recovered by insurance or other means in gas rates pursuant to terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, FG&E is authorized 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, 2007 and 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.

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, 2007, the Company and its subsidiaries had 291 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.

There are approximately 85 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 12, 2008:


Name	Age	Position
Robert G. Schoenberger	57	Chairman of the Board, Chief Executive Officer and President
Mark H. Collin	48	Senior Vice President, Chief Financial Officer and Treasurer
Thomas P. Meissner, Jr.	45	Senior Vice President and Chief Operating Officer
Laurence M. Brock	54	Controller and Chief Accounting Officer
Todd R. Black	43	President, Usource
George R. Gantz	56	Senior Vice President, Customer Services and Communications, Unitil Service Corp.
George E. Long, Jr.	51	Vice President, Administration, Unitil Service Corp.
Raymond J. Morrissey	60	Vice President, Information Systems
Sandra L. Whitney	44	Corporate Secretary
Dr. Robert V. Antonucci	62	Director
David P. Brownell	64	Director
Michael J. Dalton	67	Director
Albert H. Elfner, III	63	Director
Edward F. Godfrey	58	Director
Michael B. Green	58	Director
Eben S. Moulton	61	Director
M. Brian O’Shaughnessy	64	Director
Charles H. Tenney, III	60	Director
Dr. Sarah P. Voll	65	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 operating officer of the New York Power Authority (state-owned utility operating 6000 Mw of generation and 1400 miles of high voltage transmission) from 1993 until 1997. He also serves as chairman and trustee of Exeter Health Resources, and as a director of SatCon Technology Corporation.

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 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 trustee 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 was 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 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.

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 of Revere Copper Products, Inc. since 1988. Mr. O’Shaughnessy also served as chief executive officer and president of Revere from 1988 — 2007. Mr. O’Shaughnessy also serves on the board of directors of the Coalition for a Prosperous America, three copper industry trade associations, three manufacturing associations in New York State regarding energy-related issues, and the Economic Development Growth Enterprise of Mohawk Valley.

Charles H. Tenney, III has been director of Operations for Brainshift.com, Inc. since 2002. Mr. Tenney is also a director and treasurer of “The BrainShift Foundation”. Mr. Tenney also served on the board of overseers of the Huntington Theater Company, Boston, Massachusetts from 2004 – 2006.

Dr. Sarah P. Voll was vice president, National Economic Research Associates, Inc. (NERA) from 1999 until her retirement in 2007. 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 17, 2008, 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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Dividend Reinvestment Plan:

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 MDPU. 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 adjustments, 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 $42.0 million for FG&E and $30.7 million for UES as of December 31, 2007 (See total of $72.7 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. UES’ stranded costs are attributable to the long-term power purchase agreements divested by Unitil Power under long-term contract buyout agreements. 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 MDPU 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.

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.

The Company made cash contributions of $2.8 million, $2.5 million and $2.5 million to its pension plan in 2007, 2006 and 2005, respectively, which exceeded minimum funding requirements. 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.

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) which requires companies to record on their balance sheets the funded status of their retirement benefit obligations (RBO). The Company has recognized a liability for the projected RBO of its plans and 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:

•

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

•

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

•

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;

•

limitations that may be imposed by New Hampshire and Massachusetts state regulatory agencies.

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, 2007, Unitil owned, through its retail distribution utilities: two operation centers, approximately 2,160 pole miles of local transmission and distribution overhead electric lines and 584 conduit bank miles of underground electric distribution lines, along with 49 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 264 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’ 30 electric distribution substations, including a 5,000 kilovolt Ampere (kVA) mobile substation, constitute 214,037 kVA of capacity, which excludes capacity of spare transformers, 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 1,601 pole miles of local transmission and distribution overhead electric lines and a total of 406 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.

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 559 pole miles of local transmission and distribution overhead electric lines, 178 conduit bank miles of underground electric distribution lines and 19 transmission and distribution stations (including two mobile electric substations). The capacity of these substations totals 443,150 kVA, which excludes capacity of spare transformers.

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 264 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. 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, 2007, there were 1,342 Common Shareholders of record.

Common Stock Data


Dividends per Common Share	2007		2006
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


	2007				2006
Price Range of Common Stock	High/Ask		Low/Bid		High/Ask		Low/Bid
1st Quarter	$	27.30	$	25.10	$	26.11	$	24.59
2nd Quarter	$	28.40	$	26.65	$	26.05	$	23.70
3rd Quarter	$	31.73	$	27.07	$	24.97	$	23.80
4th Quarter	$	29.97	$	25.75	$	26.09	$	23.82

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)	—		N/A	—
Restricted Stock Plan (2)	—		N/A	106,365
Equity compensation plans not approved by security holders 1998 Option Plan (3)	107,000	$	27.13	—

Total	107,000	$	27.13	106,365

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. The last outstanding KESOP option was exercised in September 2007. No options remain outstanding and no additional options may be granted under the KESOP.

(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; 15,540 shares of restricted stock were awarded to Plan participants in February 2008.

(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, 2002 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, 2002.

Comparative Five-Year Total Returns

LOGO

NOTES:

(1)	The graph above assumes $100 invested on December 31, 2002, 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

There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2007.

The Company periodically repurchases shares of its Common Stock on the open market related to Employee Length of Service Awards. Shares are not purchased as part of a specific plan or program and therefore there is no pool or maximum number of shares related to these purchases. The Company expects to continue with these purchases indefinitely. Company repurchases are shown in the table below for the monthly periods noted:


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
10/1/07 – 10/31/07	182	$	29.10	182	n/a
11/1/07 – 11/30/07	—		—	—	n/a
12/1/07 – 12/31/07	—		—	—	n/a

Total	182	$	29.10	182	n/a

Item 6.

Selected Financial Data


For the Years Ended December 31,	2007			2006			2005			2004			2003
(all data in millions except shares, % and per share data) Consolidated Statements of Earnings:
Operating Revenue	$	262.9		$	260.9		$	232.1		$	214.1		$	220.7
Operating Income		18.5			15.8			15.5			15.2			15.4
Other Non-operating Expense (Income)		0.2			—			0.1			0.2			—

Income Before Interest Expense, net		18.3			15.8			15.4			15.0			15.4
Interest Expense, net		9.6			7.8			6.8			6.8			7.5

Net Income		8.7			8.0			8.6			8.2			7.9
Dividends on Preferred Stock		0.1			0.1			0.2			0.2			0.2

Earnings Applicable to Common Shareholders	$	8.6		$	7.9		$	8.4		$	8.0		$	7.7

Balance Sheet Data:
Utility Plant (Original Cost)	$	380.5		$	353.0		$	325.0		$	308.1		$	288.7
Total Assets	$	474.6		$	483.4		$	450.1		$	457.0		$	483.9
Capitalization:
Common Stock Equity	$	100.4		$	97.8		$	96.3		$	94.3		$	92.8
Preferred Stock		2.1			2.1			2.3			2.3			3.3
Long-Term Debt, less current portion		159.6			140.0			125.4			110.7			110.9

Total Capitalization	$	262.1		$	239.9		$	224.0		$	207.3		$	207.0

Current Portion of Long-Term Debt	$	0.4		$	0.3		$	0.3		$	0.3		$	3.3
Short-term Debt	$	18.8		$	26.0		$	18.7		$	25.7		$	22.4
Capital Structure Ratios:
Common Stock Equity		38	%		41	%		43	%		46	%		45	%
Preferred Stock		1	%		1	%		1	%		1	%		2	%
Long-Term Debt		61	%		58	%		56	%		53	%		53	%
Earnings Per Share Data:
Earnings Per Average Share	$	1.52		$	1.41		$	1.51		$	1.45		$	1.58
Common Stock Data:
Shares of Common Stock (000’s)		5,672			5,612			5,568			5,525			4,896
Dividends Paid Per Share	$	1.38		$	1.38		$	1.38		$	1.38		$	1.38
Book Value Per Share (Year-End)	$	17.50		$	17.30		$	17.21		$	17.00		$	16.87
Electric and Gas Sales:
Electric Distribution Sales ( Millions kWh)		1,743.0			1,751.5			1,790.4			1,742.1			1,717.7
Firm Natural Gas Distribution Sales (Millions Therms)		28.4			26.4			24.3			23.2			24.6

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 its two principal 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 100,000 electric customers and 15,100 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 $248.9 million at December 31, 2007. Unitil’s total revenue was $262.9 million in 2007. Earnings applicable to common shareholders for 2007 was $8.6 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 $3.7 million in 2007. 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, 2007, 2006 and 2005 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

2007 Compared to 2006—The Company’s Earnings Applicable to Common Shareholders (Net Income) was $8.6 million for 2007, an increase of 9% over 2006 Net Income of $7.9 million. Earnings per common share were $1.52 for 2007, $0.11 per share higher than last year.

Earnings in 2007 reflect higher electric and gas sales margins, driven by higher rates and increased sales of natural gas, and improved profits from Usource, Unitil’s non-regulated energy-brokering business. Partially offsetting these factors were higher operating expenses.

The following table presents the significant items (discussed below) contributing to the change in earnings per share in 2007 as compared to 2006:

2007 Earnings Per Share vs. 2006


	2006	$ 1.41
Electric Sales Margin			0.21
Gas Sales Margin			0.23
Usource Sales Margin			0.14
Operation & Maintenance Expense			(0.06	)
Depreciation, Amortization & Other			(0.22	)
Interest Expense, Net			(0.19	)

	2007	$	1.52

Unitil’s total electric kWh sales decreased 0.5% in 2007 compared to 2006. Electric kWh sales to residential customers increased 0.4% in 2007 compared to 2006. The lower kWh sales in 2007 compared to 2006 were primarily driven by cooler summer weather this year, energy conservation by our customers and a slowing economy.

Unitil’s total therm sales of natural gas increased 7.6% in 2007 compared to 2006. The increase in gas sales in 2007 reflects a colder winter heating season this year and higher natural gas sales to C&I customers. In 2007, natural gas sales to residential customers increased 4.1% compared to 2006 while sales to C&I customers increased 9.6% compared to 2006, primarily due to a special contract with a large industrial customer.

Total electric and gas sales margin increased $3.9 million in 2007 compared to 2006. This increase reflects higher gas and electric rates and increased sales of natural gas.

Total O&M expense increased $0.5 million, or 1.9%, in 2007 compared to 2006. This increase reflects higher employee and retiree compensation and benefit expenses of $0.8 million, higher bad debt expenses of $0.1 million and an increase in all other operating expenses of $0.2 million, net, offset by lower distribution utility operating expenses of $0.6 million.

Depreciation, Amortization, Taxes and Other expenses increased $2.2 million in 2007 compared to 2006 reflecting higher depreciation on normal utility plant additions in 2007 and income taxes on higher levels of pre-tax earnings in 2007 compared to 2006.

Interest Expense, Net increased $1.8 million in 2007 compared to 2006 reflecting higher debt outstanding, higher interest rates and higher interest expense recorded on reconciling mechanisms.

Usource, our non-regulated energy brokering business, recorded revenues of $3.7 million in 2007, an increase of $1.3 million over 2006. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

In 2007, 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, 2008 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share.

2006 Compared to 2005—The Company’s 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.

A more detailed discussion of the Company’s 2007 and 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 $17.1 million in 2007 compared to 2006. This increase was due to capital expenditures related to UES’ and FG&E’s electric and gas distribution systems, including expenditures of approximately $6.6 million for the Company’s Advanced Metering Infrastructure (AMI) project.

Regulatory Assets decreased $28.3 million in 2007 compared to 2006, primarily reflecting current year cost recoveries. A significant portion of this decrease is matched by a corresponding decrease of $19.9 million in Power Supply Contract Obligations.

Long-Term Debt increased $19.6 million in 2007 compared to 2006 reflecting the issuance and sale on May 2, 2007 by Unitil Corporation of $20.0 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors in the form of a private placement. Short-term Debt decreased $7.2 million in 2007 compared to 2006, as short-term borrowings were refinanced with the issuance of Senior Long-Term Notes, discussed above.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales—Unitil’s total electric kWh sales decreased 0.5% in 2007 compared to 2006. Electric kWh sales to residential customers increased 0.4% in 2007 compared to 2006. The lower total kWh sales in 2007 compared to 2006 were driven by cooler summer weather this year, energy conservation by customers in response to higher overall energy prices and environmental concerns, and a slowing economy.

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 milder weather in 2006 compared to 2005 and increased energy conservation by customers.

The following table details total kWh sales for the last three years by major customer class:


kWh Sales (millions)
				2007 vs. 2006				2006 vs. 2005
	2007	2006	2005	Change kWh		Change %		Change kWh		Change %
Residential	674.8	672.2	688.3	2.6		0.4	%	(16.1	)	(2.3	%)
Commercial / Industrial	1,068.2	1,079.3	1,102.1	(11.1	)	(1.0	%)	(22.8	)	(2.1	%)

Total	1,743.0	1,751.5	1,790.4	(8.5	)	(0.5	%)	(38.9	)	(2.2	%)

Electric Operating Revenues and Sales Margin—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)
							2007 vs. 2006					2006 vs. 2005
	2007		2006		2005		$ Change			% Change⁽¹⁾		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	114.7	$	105.9	$	85.3	$	8.8		3.9	%	$	20.6		10.4	%
Commercial / Industrial		110.3		119.3		112.0		(9.0	)	(4.0	%)		7.3		3.7	%

Total Electric Operating Revenue	$	225.0	$	225.2	$	197.3	$	(0.2	)	(0.1	%)	$	27.9		14.1	%

Cost of Electric Sales:
Purchased Electricity	$	165.4	$	167.3	$	138.1	$	(1.9	)	(0.8	%)	$	29.2		14.8	%
Conservation & Load Management		3.4		3.6		3.8		(0.2	)	(0.1	%)		(0.2	)	(0.1	%)

Electric Sales Margin	$	56.2	$	54.3	$	55.4	$	1.9		0.8	%	$	(1.1	)	(0.6	%)

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

Total Electric Operating Revenues decreased by $0.2 million, or 0.1%, in 2007 compared to 2006. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation & Load Management (C&LM) in Operating Expenses. The net decrease in Total Electric Operating Revenues in 2007 reflects lower Purchased Electricity costs of $1.9 million and lower C&LM revenues of $0.2 million, offset by higher sales margin of $1.9 million.

Purchased Electricity and C&LM revenues decreased $2.1 million, or 0.9%, of Total Electric Operating Revenues in 2007 compared to 2006, primarily reflecting an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher electric commodity prices. Purchased Electricity revenues include the recovery of the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. The Company recovers the cost of Purchased Electricity and C&LM in its rates at cost on a pass through basis.

Electric sales margin increased $1.9 million in 2007 compared to 2006. The improvement in electric sales margin reflects higher average distribution rates in 2007 compared to 2006, partially offset by lower sales volumes due to cooler summer weather this year, energy conservation by customers in response to higher overall energy prices and environmental concerns, and a slowing economy.

In 2006, Total Electric Operating Revenues increased by $27.9 million, or 14.1%, compared to 2005. 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.

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. 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 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 and energy conservation.

Gas Sales, Revenues and Margin

Therm Sales—Unitil’s total therm sales of natural gas increased 7.6% in 2007 compared to 2006. The increase in gas sales in 2007 reflects a colder winter heating season this year and higher natural gas sales to C&I customers. In 2007, natural gas sales to residential customers increased 4.1% compared to 2006 while sales to C&I customers increased 9.6% compared to 2006, primarily due to a special contract with a large industrial customer.

Unitil’s total 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 following table details total therm sales for the last three years, by major customer class:


Therm Sales (millions)
	2007	2006	2005	2007 vs. 2006			2006 vs. 2005
	2007	2006	2005	Change	Change %		Change		Change %
Residential	10.2	9.8	11.0	0.4	4.1	%	(1.2	)	(10.9	%)
Commercial / Industrial	18.2	16.6	13.3	1.6	9.6	%	3.3		24.8	%

Total	28.4	26.4	24.3	2.0	7.6	%	2.1		8.6	%

Gas Operating Revenues and Sales Margin—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)
							2007 vs. 2006					2006 vs. 2005
	2007		2006		2005		$ Change			% Change⁽¹⁾		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	18.8	$	17.2	$	18.1	$	1.6		4.8	%	$	(0.9	)	(2.8	%)
Commercial / Industrial		15.4		16.1		14.7		(0.7	)	(2.1	%)		1.4		4.3	%

Total Gas Operating Revenue	$	34.2	$	33.3	$	32.8	$	0.9		2.7	%	$	0.5		1.5	%

Cost of Gas Sales:
Purchased Gas	$	21.3	$	22.4	$	21.2	$	(1.1	)	(3.3	%)	$	1.2		3.7	%
Conservation & Load Management		0.2		0.2		0.3		—		—			(0.1	)	(0.4	%)

Gas Sales Margin	$	12.7	$	10.7	$	11.3	$	2.0		6.0	%	$	(0.6	)	(1.8	%)

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

Total Gas Operating Revenues increased $0.9 million, or 2.7%, in 2007 compared to 2006. Total Gas Operating Revenues include the recovery of the cost of sales, which are recorded as Purchased Gas and C&LM in Operating Expenses. The increase in Total Gas Operating Revenues in 2007 reflects higher sales margin of $2.0 million, partially offset by lower Purchased Gas costs of $1.1 million.

Purchased Gas and C&LM revenues decreased $1.1 million, or 3.3%, of Total Gas Operating Revenues in 2007 compared to 2006, reflecting lower natural gas commodity prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. Purchased Gas revenues include the recovery of the cost of gas supply as well as the other energy supply related costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. The Company recovers the cost of Purchased Gas and C&LM in its rates at cost on a pass through basis.

Natural gas sales margin increased $2.0 million in 2007 compared to 2006 reflecting higher sales and new natural gas distribution rates approved and implemented in 2007.

In 2006, Total Gas Operating Revenues increased $0.5 million, or 1.5%, compared to 2005. 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.

Gas sales margin for 2006 decreased $0.6 million 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.

Operating Revenue—Other

Total Other Revenue increased $1.3 million in 2007 compared to 2006 and $0.4 million in 2006 compared to 2005. 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 following table details total Other Revenue for the last three years:


Other Revenue (millions)
							2007 vs. 2006				2006 vs. 2005
	2007		2006		2005		$ Change		% Change		$ Change		% Change
Usource	$	3.7	$	2.4	$	2.0	$	1.3	54.2	%	$	0.4	20.0	%

Total Other Revenue	$	3.7	$	2.4	$	2.0	$	1.3	54.2	%	$	0.4	20.0	%

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 decreased $1.9 million, or 1.1%, in 2007 compared to 2006. This decrease reflects lower electric kWh sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher electric commodity prices. The Company recovers the costs of Purchased Electricity in its rates at cost and therefore changes in these expenses do not affect earnings.

In 2006, Purchased Electricity expenses increased $29.2 million, or 21.1%, compared to 2005 due 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 decreased $1.1 million, or 4.9%, in 2007 compared to 2006. The decrease in Purchased Gas is attributable to lower gas commodity prices and an increase in the amount of natural gas purchased by customers directly from third party suppliers, partially offset by increased therm sales. 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 2006, Purchased Gas increased by $1.2 million, or 5.7%, compared to 2005, reflecting increased therm sales and higher gas commodity costs.

Operation and Maintenance (O&M)—O&M expense includes electric and gas utility operating costs, and the operating costs of the Company’s non-regulated business activities. Total O&M expense increased $0.5 million, or 1.9%, in 2007 compared to 2006. This increase reflects higher employee and retiree compensation and benefit expenses of $0.8 million, higher bad debt expenses of $0.1 million and an increase in all other operating expenses of $0.2 million, net, offset by lower distribution utility operating expenses of $0.6 million.

In 2006, total O&M expense increased $1.2 million, or 4.9%, compared to 2005. This increase reflects higher retiree and employee compensation and benefit costs of $1.1 million and an increase in all other operating expenses of $0.1 million, net.

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 $0.2 million, in 2007 compared to 2006. 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 decreased $0.3 million in 2006 compared to 2005.

Depreciation and Amortization—Depreciation and Amortization expense increased $1.7 million, or 10.6% in 2007 compared to 2006 reflecting higher depreciation on normal utility plant additions in 2007.

In 2006, Depreciation and Amortization expense decreased $3.0 million, or 15.7%, compared to 2005, reflecting lower amortization on regulatory assets, including Seabrook Station, and lower depreciation rates on utility plant established in the Company’s electric rate case settlement in New Hampshire, partially offset by depreciation on normal utility plant additions. The Company’s regulatory asset related to its former abandoned property investment in Seabrook Station became fully-amortized in the third quarter of 2005.

Local Property and Other Taxes—Local Property and Other Taxes increased by $0.1 million, or 1.8%, in 2007 compared to 2006. This increase was due to higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

In 2006, Local Property and Other Taxes increased by $0.2 million, or 3.8% 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.

Federal and State Income Taxes—Federal and State Income Taxes increased by $0.2 million in 2007 compared to 2006 due to higher pre-tax operating income in 2007 compared to 2006.

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.

Other Non-operating Expenses (Income)

Other Non-operating Expenses (Income) increased by $0.2 million in 2007 compared to 2006. This change reflects the recognition in 2006 of a gain on the sale of land and timber harvest revenue.

Other Non-operating Expenses (Income) improved to income of $19,000 in 2006 compared to an expense of $147,000 in 2005, due to the gain discussed above.

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 (See Note 3).

In 2007, Total Interest Expense, net, rose by $1.8 million compared to 2006. This increase principally reflects the issuance of new long-term debt by Unitil on May 2, 2007. Unitil issued and sold $20 million of Senior Long-Term Notes at a coupon rate of 6.33%, through a private placement to institutional investors. The Company utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of the Company’s principal utility subsidiaries. The resulting reduction in average daily short-term bank borrowings lowered short-term interest expense for the year which partially offset the increase in long-term interest expense.

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.

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, 2007, Unitil had an aggregate of $30.0 million in unsecured revolving lines of credit with 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 $18.8 million and $26.0 million at December 31, 2007 and December 31, 2006, respectively. In addition, Unitil had approximately $4.6 million in cash at December 31, 2007. 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 Company’s regulatory agencies. At December 31, 2007, Unitil had regulatory authorization to incur total short-term bank borrowings up to a maximum of $55 million, and UES and FG&E had regulatory authorizations to borrow up to a maximum of $16 million and $35 million, respectively. In 2007, UES and FG&E had average short-term debt outstanding of $7.9 million and $18.1 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 for 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, 2007, all Unitil subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

On May 2, 2007, Unitil completed the sale of $20 million of Senior Long-Term Notes, through a private placement to institutional investors. The Notes have a term of 15 years maturity and a coupon rate of 6.33%. The Company utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of the Company’s principal utility subsidiaries (see Note 3).

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 to repay short-term bank borrowings and permanently finance utility plant additions. 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 and permanently finance utility plant additions. 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, 2007.


			Payments Due by Period
Significant Contractual Obligations (millions) as of December 31, 2007	Total		2008		2009- 2010		2011- 2012		2013 & Beyond
Long-term Debt	$	160.0	$	0.4	$	0.8	$	1.0	$	157.8
Capital Leases		0.8		0.3		0.3		0.2		—
Operating Leases		2.8		0.5		1.0		0.9		0.4
Power Supply Contract Obligations—MA		42.0		8.1		16.7		16.6		0.6
Power Supply Contract Obligations—NH		30.7		11.9		14.4		1.2		3.2
Gas Supply Contracts		23.2		16.0		3.9		3.0		0.3

Total Contractual Cash Obligations	$	259.5	$	37.2	$	37.1	$	22.9	$	162.3

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 reconciling 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, 2007 there are $6.5 million of guarantees outstanding and these guarantees extend through March 13, 2009.

Benefit Plan Funding

In 2007 and 2006, the Company and its subsidiaries made cash contributions to its pension plan in the amount of $2.8 million and $2.5 million, respectively. In 2007 and 2006, the Company and its subsidiaries contributed approximately $2.5 million and $2.2 million, respectively, to Voluntary Employee Benefit Trusts (VEBT). The Company and its subsidiaries expect to continue to make contributions to its pension plan and the VEBT’s in future years in amounts consistent with the amounts recovered in retail distribution utility rates for these other postretirement benefit costs. (See Note 8).

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

The tables below summarize the major sources and uses of cash (in millions) for 2007 compared to 2006.

Cash Provided by Operating Activities—Cash Provided by Operating Activities was $26.8 million in 2007, an increase of $6.4 million compared to 2006. Sources of cash from Net Income were higher by $0.7 million compared to last year and sources of cash from Depreciation and Amortization rose by approximately $1.7 million. An additional $1.4 million of cash was utilized for Deferred Tax Provisions during the current year. Working capital related cash flows decreased $0.8 million in 2007 compared to 2006. Included in this change in working capital cash flows was an increase of $6.0 million year over year from Accrued Revenue, principally due to the recoveries of accrued revenues through reconciling cost recovery mechanisms. Sources of cash related to Deferred Restructuring Costs increased by $5.5 million in 2007 year over year, 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 $0.7 million in sources of cash in 2007 compared to 2006.


	2007			2006
Cash (Used in) Investing Activities	$	(32.5	)	$	(33.6	)

Cash (Used in) Investing Activities—Cash (Used in) Investing Activities in 2007 was $32.5 million, a decrease of $1.1 million compared to 2006. 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 $29.3 million in 2008, reflecting normal electric and gas utility plant additions. Capital expenditure projections are subject to changes during the fiscal year.

Cash Provided by Financing Activities—Cash Provided by Financing Activities was $5.7 million in 2007, a decrease of $8.9 compared to 2006. Cash provided from short-term debt declined by $14.5 million in 2007, principally reflecting the repayment of short-term debt from the issuance of $20 million in Senior Long-Term Notes by Unitil in May 2007, described above. Proceeds from long-term debt issuances increased by $5.0 million in 2007 as compared to 2006, reflecting the issuance of $20 million in Unitil Notes in 2007 and the $15 million in UES Bond financings in 2006, described above. All other cash flows provided from other financing activities aggregated to a net change in cash flows of $0.6 million in 2007.

FINANCIAL COVENANTS AND RESTRICTIONS

The agreements under which the long-term debt of Unitil and its 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 (See Note 3).

The long-term debt and preferred stock of Unitil, UES and FG&E are privately held, and the Company does not issue commercial paper. For these reasons, the debt securities of Unitil and its subsidiaries are not publicly rated.

DIVIDENDS

Unitil’s annualized common dividend was $1.38 per common share in 2007, 2006 and 2005. 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, 2008 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 the Company’s 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 representative test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in Massachusetts and New Hampshire, all of Unitil’s customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. Most small and medium-sized customers, however, continue to purchase such supplies through UES and FG&E as the providers of basic or default service energy supply. UES and FG&E purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

In connection with the implementation of retail choice, Unitil Power and FG&E divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the New Hampshire Public Utilities Commission (NHPUC) and Massachusetts Department of Public Utilities (MDPU), respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, is $104.8 million as of December 31, 2007 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans (See Note 5).

FG&E—Electric Division—On August 17, 2007, FG&E filed an electric distribution rate increase of $3.3 million, which represents an increase of 4.7 percent over FG&E’s 2006 total electric operating revenue. The MDPU has suspended the effective date until March 1, 2008 in order to investigate the propriety of the Company’s request. Evidentiary hearings were held in November 2007 and briefing was completed in January 2008. The Company anticipates that it will receive a final order from the MDPU with an effective date for new electric rates of March 1, 2008.

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 MDPU. Its current retail distribution rates were approved by the MDPU in 2007. FG&E’s customers may purchase gas supplies from third-party vendors or purchase their gas from FG&E as the provider of last resort. FG&E collects its gas supply costs through a seasonal reconciling Cost of Gas Adjustment Clause and recovers other related costs through a reconciling Local Distribution Adjustment Clause.

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

FG&E—Other—On June 22, 2007, the MDPU opened an inquiry into revenue decoupling, generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utility’s distribution revenues on sales. Revenue decoupling is adopted with the intent of removing the disincentive a utility has to administer and promote customer efforts to reduce energy consumption and demand or to install distributed generation to displace electricity delivered by the utility. The order included a straw

proposal for a base revenue adjustment mechanism that severs the link between electric and gas companies’ revenues and sales, and instead, ties company revenues to the number of customers served. Many interested parties filed comments on the elements of the straw proposal and on revenue decoupling in general. Several parties also provided comments in panel hearings organized by the MDPU. Unitil filed comments generally supporting revenue decoupling and recommended modifications to the MDPU’s straw proposal. This matter remains pending.

On June 22, 2007, the NHPUC issued an order in its investigation into implementation of the federal Energy Policy Act of 2005 regarding the adoption of standards for time-based metering and interconnection. This order set the framework for implementation of time based rates for utility provided default service. On August 31, 2007, the NHPUC issued an order on motion for rehearing, staying the June 22, 2007 order pending hearing and reconsideration of the issues. An order following hearing was issued on January 22, 2008 finding that it is appropriate to implement time-based metering standards and ordering that the details, including cost-benefit analyses, form of rate design, time of implementation and applicable customer classes shall be determined in separate proceedings to be initiated by the Commission.

On May 14, 2007, the NHPUC issued an order opening an investigation into the merits of instituting appropriate rate mechanisms, such as revenue decoupling, which would have the effect of removing obstacles to, and encouraging investment in, energy efficiency. Several parties attended the prehearing conference on June 18, 2007 and subsequent technical sessions. On July 30, 2007, the gas and electric utilities made baseline presentations designed to assist the parties in understanding current regulatory methods and the utilities’ assessment of existing incentives and barriers to energy efficiency investment. On November 7, 2007, the Commission hosted expert presentations about the potential of various regulatory approaches to promote energy efficiency. The proceeding remains open.

ENVIRONMENTAL MATTERS

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.

EMPLOYEES AND EMPLOYEE RELATIONS

As of December 31, 2007, the Company and its subsidiaries had 291 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 MDPU and UES is regulated by the NHPUC. Accordingly, the Company uses the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered 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.

If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. If unable to continue to apply the provisions of SFAS No. 71, the Company would be required to apply the provisions of FASB Statement No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In the Company’s opinion, its regulated operations will be subject to SFAS No. 71 for the foreseeable future.

Utility Revenue Recognition—Regulated utility revenues are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

Allowance for Doubtful Accounts—The Company recognizes a Provision for Doubtful Accounts each month. 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.

Retirement Benefit Obligations—The Company sponsors the following retirement benefit plans to provide certain pension and postretirement benefits for its retirees and current employees: the Unitil Corporation Retirement Plan (Pension Plan), a defined benefit pension plan covering substantially all of its employees; the Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan) which provides health care and life insurance benefits to retirees; and the Unitil Corporation Supplemental Executive Retirement Plan (SERP), an unfunded retirement plan, with participation limited to executives selected by the Board of Directors.

No. 158), SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions”. 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. 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 corresponding Regulatory Assets, to recognize the future collection of these obligations in electric and gas retail rates. (See Notes 1 and 8).

The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. 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.)

Income Taxes—Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of income is presented. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s consolidated balance sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109) and under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of FAS 109.

Depreciation—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements.

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with 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, 2007, 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 5.6%, 5.5% and 3.8% during 2007, 2006 and 2005, 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 statements of capitalization of Unitil Corporation and subsidiaries (the Company) as of December 31, 2007 and 2006, and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the years ended December 31, 2007, 2006 and 2005. We also have audited Unitil Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2007, 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 these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included 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 by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Unitil Corporation and subsidiaries as of December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, Unitil Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Vitale, Caturano & Co. Ltd.

Boston, Massachusetts

February 8, 2008

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions, except common shares and per share data)


Year Ended December 31,	2007		2006		2005

Operating Revenues:

Electric	$	225.0	$	225.2	$	197.3

Gas		34.2		33.3		32.8

Other		3.7		2.4		2.0



Total Operating Revenues		262.9		260.9		232.1



Operating Expenses:

Purchased Electricity		165.4		167.3		138.1

Purchased Gas		21.3		22.4		21.2

Operation and Maintenance		26.2		25.7		24.5

Conservation & Load Management		3.6		3.8		4.1

Depreciation and Amortization		17.8		16.1		19.1

Provisions for Taxes:

Local Property and Other		5.6		5.5		5.3

Federal and State Income		4.5		4.3		4.3



Total Operating Expenses		244.4		245.1		216.6



Operating Income		18.5		15.8		15.5

Other Non-Operating Expenses		0.2		—		0.1



Income Before Interest Expense		18.3		15.8		15.4

Interest Expense, net		9.6		7.8		6.8



Net Income		8.7		8.0		8.6

Less Dividends on Preferred Stock		0.1		0.1		0.2



Earnings Applicable to Common Shareholders	$	8.6	$	7.9	$	8.4



Average Common Shares Outstanding (000’s)—Basic		5,659		5,597		5,551

Average Common Shares Outstanding (000’s)—Diluted		5,672		5,612		5,568



Earnings per Common Share—Basic and Diluted	$	1.52	$	1.41	$	1.51

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

CONSOLIDATED BALANCE SHEETS (Millions)

ASSETS


December 31,	2007		2006

Utility Plant:

Electric	$	266.2	$	250.3

Gas		67.8		63.4

Common		26.2		25.3

Construction Work in Progress		20.3		14.0



Utility Plant		380.5		353.0

Less: Accumulated Depreciation		131.6		121.2



Net Utility Plant		248.9		231.8



Current Assets:

Cash		4.6		4.6

Accounts Receivable—(Net of Allowance for Doubtful Accounts of $1.3 and $1.7)		24.9		22.5

Accrued Revenue		12.7		13.8

Refundable Taxes		0.7		—

Material and Supplies		4.5		4.5

Prepayments and Other		1.5		1.3



Total Current Assets		48.9		46.7



Noncurrent Assets:

Regulatory Assets		170.5		198.8

Debt Issuance Costs, net		2.8		2.6

Other Noncurrent Assets		3.5		3.5



Total Noncurrent Assets		176.8		204.9



TOTAL	$	474.6	$	483.4

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

CONSOLIDATED BALANCE SHEETS (cont.) (Millions)

CAPITALIZATION AND LIABILITIES


December 31,	2007		2006

Capitalization:

Common Stock Equity	$	100.4	$	97.8

Preferred Stock, Non-Redeemable, Non-Cumulative		0.2		0.2

Preferred Stock, Redeemable, Cumulative		1.9		1.9

Long-Term Debt, Less Current Portion		159.6		140.0


Total Capitalization		262.1		239.9


Current Liabilities:

Long-Term Debt, Current Portion		0.4		0.3

Capitalized Leases, Current Portion		0.3		0.2

Short-Term Debt		18.8		26.0

Accounts Payable		17.6		19.8

Taxes Payable		—		0.9

Interest and Dividends Payable		1.9		1.6

Other Current Liabilities		5.1		4.6


Total Current Liabilities		44.1		53.4


Deferred Income Taxes		33.4		34.5


Noncurrent Liabilities:

Power Supply Contract Obligations		72.7		92.6

Retirement Benefit Obligations		48.2		49.7

Environmental Obligations		12.0		12.0

Capitalized Leases, Less Current Portion		0.5		0.2

Other Noncurrent Liabilities		1.6		1.1


Total Noncurrent Liabilities		135.0		155.6


TOTAL	$	474.6	$	483.4

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

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(Millions, except number of shares and par value)


December 31,	2007		2006

Common Stock Equity

Common Stock, No Par Value (Authorized (000’s)—8,000 shares; Outstanding—5,740 and 5,650 shares)	$	64.5	$	62.2

Stock Compensation Plans		0.8		1.3

Retained Earnings		35.1		34.3


Total Common Stock Equity		100.4		97.8


Preferred Stock

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

6.00% Series, $100 Par Value		0.2		0.2

FG&E Preferred Stock, Redeemable, Cumulative:

5.125% Series, $100 Par Value		0.9		0.9

8.00% Series, $100 Par Value		1.0		1.0


Total Preferred Stock		2.1		2.1


Long-Term Debt

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

UES First Mortgage Bonds:
8.49% Series, Due October 14, 2024		15.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0

FG&E Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0

Unitil Realty Corp. Senior Secured Notes:
8.00% Notes, Due August 1, 2017		5.0		5.3


Total Long-Term Debt		160.0		140.3

Less: Current Portion		0.4		0.3


Total Long-Term Debt, Less Current Portion		159.6		140.0


Total Capitalization	$	262.1	$	239.9

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

CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions)


Year Ended December 31,	2007			2006			2005

Operating Activities:

Net Income	$	8.7		$	8.0		$	8.6
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		17.8			16.1			19.1
Deferred Taxes		(0.9	)		0.5			(0.2	)

Changes in Current Assets and Liabilities:
Accounts Receivable		(2.4	)		1.1			(5.5	)
Accrued Revenue		1.1			(4.9	)		0.9
Accounts Payable		(2.2	)		(0.8	)		4.4
Taxes Payable / (Refundable)		(1.6	)		0.9			0.6
All Other Current Assets and Liabilities		0.5			(0.1	)		1.4

Deferred Restructuring Charges		3.5			(2.0	)		(4.2	)
Other, net		2.3			1.6			(1.0	)

Cash Provided by Operating Activities		26.8			20.4			24.1


Investing Activities:

Property, Plant and Equipment Additions		(32.5	)		(33.6	)		(24.4	)

Cash (Used In) Investing Activities		(32.5	)		(33.6	)		(24.4	)


Financing Activities:

Proceeds from (Repayment of) Short-Term Debt		(7.2	)		7.3			(7.0	)
Proceeds from Issuance of Long-Term Debt		20.0			15.0			15.0
Repayment of Long-Term Debt		(0.3	)		(0.3	)		(0.3	)
Dividends Paid		(7.9	)		(7.9	)		(7.8	)
Issuance of Common Stock		1.5			1.0			1.0
Retirement of Preferred Stock		—			(0.2	)		—
Other, net		(0.4	)		(0.3	)		(0.4	)

Cash Provided by Financing Activities		5.7			14.6			0.5


Net Increase (Decrease) in Cash		—			1.4			0.2

Cash at Beginning of Year		4.6			3.2			3.0


Cash at End of Year	$	4.6		$	4.6		$	3.2


Supplemental Information:

Interest Paid	$	12.2		$	10.7		$	9.5

Income Taxes Paid	$	5.3		$	3.1		$	4.5

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

CONSOLIDATED STATEMENTS OF

CHANGES IN COMMON STOCK EQUITY

(Millions, except number of shares)


	Common Shares		Stock Compensation Plans			Retained Earnings			Total
Balance at January 1, 2005	$	59.9	$	1.0		$	33.4		$	94.3

Net Income for 2005							8.6			8.6

Dividends on Preferred Shares							(0.2	)		(0.2	)

Dividends on Common Shares							(7.7	)		(7.7	)

Stock Compensation Plans		0.1		0.2						0.3

Issuance of 38,003 Common Shares		1.0								1.0


Balance at December 31, 2005		61.0		1.2			34.1			96.3

Net Income for 2006							8.0			8.0

Dividends on Preferred Shares							(0.1	)		(0.1	)

Dividends on Common Shares							(7.7	)		(7.7	)

Stock Compensation Plans		0.2		0.1						0.3

Issuance of 40,365 Common Shares		1.0								1.0


Balance at December 31, 2006		62.2		1.3			34.3			97.8

Net Income for 2007							8.7			8.7

Dividends on Preferred Shares							(0.1	)		(0.1	)

Dividends on Common Shares							(7.8	)		(7.8	)

Stock Compensation Plans		0.3								0.3

Exercised Stock Options – 42,437 Common Shares		1.0		(0.5	)					0.5

Issuance of 38,303 Common Shares		1.0								1.0


Balance at December 31, 2007	$	64.5	$	0.8		$	35.1		$	100.4

(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. 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 Public Utilities (MDPU) 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.

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.

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, MDPU and NHPUC.


	December 31,
Regulatory Assets consist of the following (millions)	2007		2006
Power Supply Buyout Obligations	$	72.7	$	92.6
Deferred Restructuring Costs		30.5		31.0
Generation-related Assets		1.6		2.5

Subtotal—Restructuring Related Items		104.8		126.1

Retirement Benefit Obligations		35.1		37.1
Income Taxes		14.6		19.1
Environmental Obligations		13.1		13.0
Other		2.9		3.5

Total Regulatory Assets	$	170.5	$	198.8

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. 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.

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, 2007 and 2006, the Unitil affiliates had deposited $2.5 million and $2.0 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, 2007. There are no significant intangible assets recorded by the Company at December 31, 2007. Therefore, the Company is not currently involved in making estimates or seeking valuations of these items.

Off-Balance Sheet Arrangements—As of December 31, 2007, 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), FASB Statement No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities”, an amendment of SFAS No. 133 (SFAS No. 138) and / or FASB Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149). As of December 31, 2007, 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, 2007, 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, SFAS No. 138 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.

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.

The Company accounts for its pension and postretirement benefits in accordance with FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, (SFAS No. 158), FASB Statement No. 87, “Employers’ Accounting for Pensions”, (SFAS No. 87) and FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions”, (SFAS No. 106). The Company has recognized Regulatory Assets, to recognize the future collection of these obligations in electric and gas retail rates (See Note 8).

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’s 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, 2007, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below (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 5.73%, 4.92% and 2.33% in 2007, 2006 and 2005, 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. The Company is not mandated by any state or federal regulations or other commitments to retire assets other than those currently included in it mass asset depreciation base. At December 31, 2007 and December 31, 2006, the Company estimates that the negative salvage value of future retirements recorded on the balance sheet in Accumulated Depreciation is $16.2 million and $14.9 million, respectively.

Depreciation and Amortization—Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements.

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: 2007—4.29%, 2006—4.40% and 2005—4.69%.

Amortization provisions include the recovery, in 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 MDPU. 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 MDPU (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, 2007, 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).

Income Taxes—Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of income is presented. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s consolidated balance sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109) and under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of FAS 109.

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 December 2007, the FASB issued FASB Statement No. 141 (Revised 2007), “Business Combinations” (SFAS No. 141R), effective prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS No. 141R establishes principles and requirements on how an acquirer recognizes and measures in its financial statements identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree, goodwill or gain from a bargain purchase and accounting for transaction costs. Additionally, SFAS No. 141R determines what information must be disclosed to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The Company will adopt SFAS No. 141R upon its effective date as appropriate for any future business combinations.

In February 2007, the FASB issued FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159), effective for fiscal years beginning after November 15, 2007. SFAS No. 159 includes an amendment of FASB Statement No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” SFAS No. 159 permits entities to choose, at specified election dates, to measure eligible items at fair value and requires unrealized gains and losses on items for which the fair value option has been elected to be reported in earnings. The Company adopted SFAS No. 159 which had no impact on the Company’s Consolidated Financial Position.

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. Certain requirements of SFAS No. 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS No. 157 has been deferred for one year by the FASB. The Company adopted the sections of SFAS No. 157 which are effective for fiscal years beginning after November 15, 2007 and there was no impact on the Company’s Consolidated Financial Statements. The Company does not expect that the adoption of the delayed sections of SFAS No. 157 will have an impact on the Company’s Consolidated Financial Statements.

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

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 2007, the Company sold 38,303 shares of its Common Stock, at an average price of $27.44 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 2006 and 2005, the Company raised $1.0 million and $1.0 million, respectively, of additional common equity through the issuance of 40,365 and 38,003 shares, respectively, of its Common Stock in connection with its DRP and 401(k) plans.

Shares Repurchased, Cancelled and Retired—During 2007, 2006 and 2005, Unitil did not repurchase, cancel or retire any of its common stock.

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. The Company has adopted FASB Statement No. 123(R), “Accounting for Stock Based Compensation,” and recognizes compensation costs at fair value at the date of grant. 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.

Restricted shares issued for 2005 – 2007 in conjunction with the Plan are presented in the following table:


Issuance Date	Shares	Aggregate Market Value (millions)
3/8/05	10,900	$0.3
2/16/06	14,375	$0.4
2/9/07	9,020	$0.2

The compensation expense associated with the issuance of shares under the Plan is being accrued over the vesting period and was $0.4 million, $0.4 million and $0.3 million in 2007, 2006 and 2005, respectively, including amounts for tax gross-up. At December 31, 2007, there was approximately $0.7 million of total unrecognized compensation cost related to non-vested shares under the Plan which is expected to be recognized over a weighted average of approximately 2.2 years as the shares vest. There were 18,511 and 21,215 non-vested shares under the Plan as of December 31, 2007 and 2006, respectively. The weighted average grant date fair value of these shares was $25.95 and $26.34, respectively. There were no

cancellations or forfeitures under the Plan during 2007. As shares vest, the Company’s equity associated with those shares moves from “Stock Compensation Plans” to “Common Shares” in the presentation of the Consolidated Changes in Common Stock Equity.

Unitil Corporation Key Employee Stock Option Plan—In the third quarter of 2007, the Company issued and sold 42,437 shares of its Common Stock, at a final average price of $10.70 per share, in connection with the exercise of stock options under the Unitil Corporation Key Employee Stock Option Plan (KESOP) which expired in 2007. As of December 31, 2007, there are no options remaining under the KESOP. Net proceeds of $0.5 million were used by the Company to reduce short-term borrowings.

The total compensation expenses recorded by the Company with respect to this plan were $57,000, $54,000 and $51,000 for the years ended December 31, 2007, 2006 and 2005, respectively.

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


	2007		2006		2005
Beginning Options Outstanding and Exercisable		25,000		25,000		25,000
Dividend Equivalents Earned—Prior Years		15,388		13,202		11,321
Dividend Equivalents Earned—Current Year		2,049		2,186		1,881
Options Exercised		42,437		—		—

Ending Options Outstanding and Exercisable		—		40,388		38,202

Weighted Average Exercise Price per Share		$10.70		$11.25		$11.89
Range of Option Exercise Price per Share	$	12.11-$18.28	$	12.11-$18.28	$	12.11-$18.28
Weighted Average Remaining Contractual Life		n/a		0.9 years		1.9 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 2007, 2006 and 2005. 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 weighted average exercise price of $27.13, at December 31, 2005, 2006 and 2007. There were no options granted or forfeited during those years.

The following summarizes certain data for the options outstanding at December 31, 2007:


Range of Exercise Prices	Options Vested, Exercisable and Outstanding	Weighted Average Exercise Price		Remaining Contractual Life
$20.00-$24.99	34,500	$	23.38	1.2 years
$25.00-$29.99	37,500	$	25.88	3.1 years
$30.00-$34.99	35,000	$	32.17	2.1 years

	107,000

Preferred Stock

Unitil’s two retail distribution companies, UES and FG&E, have preferred stock outstanding. At December 31, 2007, 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 2007, 2006 and 2005 related to the annual redemption offer were $21,700, $22,000 and $11,400, respectively. The aggregate amount of sinking fund requirements of the Redeemable, Cumulative Preferred Stock for each of the five years following 2007 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.

Earnings Per Share

The following table reconciles basic and diluted earnings per share.


(Millions except shares and per share data)
	2007		2006		2005
Earnings Available to Common Shareholders	$	8.6	$	7.9	$	8.4

Weighted Average Common Shares Outstanding—Basic (000’s)		5,659		5,597		5,551
Plus: Diluted Effect of Incremental Shares (000’s)		13		15		17
Weighted Average Common Shares Outstanding—Diluted (000’s)		5,672		5,612		5,568

Earnings per Share—Basic and Diluted	$	1.52	$	1.41	$	1.51

Weighted average options to purchase 35,000, 72,500 and 72,500 shares of Common Stock were outstanding during 2007, 2006 and 2005, 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. Additionally, 2,030, 24,256 and 12,841 weighted average non-vested restricted shares for 2007, 2006 and 2005, respectively, were not included in the above computation because the effect would have been antidilutive.

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

Long-Term Debt Structure and Covenants—The agreements under which the long-term debt of Unitil and its 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.

Unitil utilizes a debenture structure of long-term debt. The long-term debt of Unitil is issued under Unsecured Promissory Notes with negative pledge provisions. 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 Unitil to issue new long-term debt, the covenants of the existing long-term agreement(s), must be satisfied, including that Unitil have total funded indebtedness less than 70% of total capitalization, and earnings available for interest equal to at least two times the interest charges for funded indebtedness. Each future senior long-term debt issuance of Unitil will rank pari passu with all other senior unsecured long-term debt issuances. The Unitil agreement requires that if Unitil defaults on any other future long-term debt agreement(s), it would constitute a default under its present long-term debt agreement. Furthermore, the default provisions are triggered by the defaults of its Principal Utility Subsidiaries or certain other actions against subsidiary companies in the Unitil System.

UES utilizes a First Mortgage Bond (FMB) structure of long-term debt. Substantially all the property of UES is subject to liens of indenture under which FMB’s have been issued. 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 Unitil or its other subsidiaries.

FG&E utilizes a debenture structure of long-term debt. All of the long-term debt of 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 Unitil or its other subsidiaries.

The Unitil, UES and FG&E long-term debt 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 Unitil, 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, 2007, Unitil, UES and FG&E had unrestricted Retained Earnings of $18.4 million, $15.7 million and $7.1 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’s common shareholders.

Debt Repayment and Sinking Funds—The total aggregate amount of sinking fund payments relating to bond issues and normal scheduled long-term debt repayments amounted to $335,877, $310,136 and $286,368 in 2007, 2006 and 2005, respectively.

The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 2007 is: 2008—$363,755; 2009—$393,946; 2010—$426,643; 2011—$462,055; and 2012—$500,405, respectively.

Long-Term Debt Issuances—On May 2, 2007, Unitil completed the sale of $20 million of Senior Long-Term Notes, through a private placement to institutional investors. The Notes have a term of 15 years maturity and a coupon rate of 6.33%. The Company utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of the Company’s principal utility subsidiaries.

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.

Fair Value of Long-Term Debt—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, 2007 is estimated to be in a range of up to approximately $168 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.

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)
	2007			2006			2005
Interest Expense
Long-term Debt	$	11.1		$	9.5		$	8.4
Short-term Debt		1.1			1.5			1.0
Regulatory Liabilities		0.8			0.3			0.2

Subtotal Interest Expense		13.0			11.3			9.6

Interest Income
Regulatory Assets		(2.9	)		(3.1	)		(2.6	)
AFUDC and Other		(0.5	)		(0.4	)		(0.2	)

Subtotal Interest Income		(3.4	)		(3.5	)		(2.8	)

Total Interest Expense, net	$	9.6		$	7.8		$	6.8

Credit Arrangements

At December 31, 2007, Unitil had unsecured committed bank lines for short-term debt in the aggregate amount of $30.0 million with three banks for which it pays commitment fees. The weighted average interest rates on all short-term borrowings were 5.6%, 5.5% and 3.8% during 2007, 2006 and 2005, respectively. The Company had short-term debt outstanding through bank borrowings of approximately $18.8 million and $26.0 million at December 31, 2007 and December 31, 2006, respectively.

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, 2007, 2006 and 2005 amounted to $433,000, $410,000 and $301,000 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 and future minimum lease payments under capital leases as of December 31, 2007:


Year Ending December 31, (000’s)	Operating Leases		Capital Leases
2008	$	524	$	313
2009		521		169
2010		498		127
2011		442		81
2012		414		81
2013-2017		435		27

Total Payments	$	2,834	$	798

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, 2007 there are $6.5 million of guarantees outstanding and these guarantees extend through March 13, 2009. These guarantees are not required to be recorded under the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

Note 4: Energy Supply

Electric Supply:

The transition to retail choice required the divestiture of Unitil’s power supply arrangements and the procurement of load-following 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.

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.

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 MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, is $104.8 million as of December 31, 2007 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

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 MDPU and NHPUC.

Gas Supply:

Sources of Gas Supply

(Expressed as percent of total MMBtu of gas purchased)


	2007		2006		2005
Natural Gas:
Domestic firm	94.6	%	84.2	%	84.8	%
Canadian firm	2.2	%	2.0	%	3.4	%
Domestic spot market	2.3	%	11.0	%	9.3	%

Total natural gas	99.1	%	97.2	%	97.5	%
Supplemental gas	0.9	%	2.8	%	2.5	%

Total gas purchases	100.0	%	100.0	%	100.0	%

Cost of Gas Sold


	2007			2006			2005
Cost of gas purchased and sold per MMBtu	$	10.41		$	11.18		$	10.83
Percent Increase (Decrease) from prior year		(6.9	%)		3.2	%		28.7	%

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 MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, is $104.8 million as of December 31, 2007 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

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

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 $32.1 million at December 31, 2007, and $33.3 million at December 31, 2006 and is expected to be recovered in FG&E’s rates over the next three to five years. In addition, as of December 31, 2007, FG&E had recorded on its balance sheet $42.0 million as Power Supply Buyout Obligations and corresponding Regulatory Assets associated with the divestiture of its long-term purchase power contracts, which are included in Unitil’s consolidated financial statements, and on which carrying charges are not earned as the timing of cash disbursements and cash receipts associated with these long-term obligations is matched through rates.

On August 17, 2007, FG&E filed an electric distribution rate increase of $3.3 million, which represents an increase of 4.7 percent over FG&E’s 2006 total electric operating revenue. The MDPU has suspended the effective date until March 1, 2008 in order to investigate the propriety of the Company’s request. Evidentiary hearings were held in November 2007 and briefing was completed in January 2008. The Company anticipates that it will receive a final order from the MDPU with an effective date for new electric rates of March 1, 2008.

install distributed generation to displace electricity delivered by the utility. The order included a straw proposal for a base revenue adjustment mechanism that severs the link between electric and gas companies’ revenues and sales, and instead, ties company revenues to the number of customers served. Many interested parties filed comments on the elements of the straw proposal and on revenue decoupling in general. Several parties also provided comments in panel hearings organized by the MDPU. Unitil filed comments generally supporting revenue decoupling and recommended modifications to the MDPU’s straw proposal. This matter remains pending.

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, 2007, approximately 74 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 utility.

In the 2002 restructuring settlement, the NHPUC approved the divestiture of the long-term power supply portfolio by Unitil Power and tariffs for UES for stranded cost recovery, including certain charges that remain subject to annual or periodic reconciliation or future review. As of December 31, 2007, UES had recorded on its balance sheets $30.7 million as Power Supply Contract Obligations and corresponding Regulatory Assets associated with these long-term purchase power stranded costs, which are included in Unitil Corporation’s consolidated financial statements. These Power Supply Contract Obligations are expected to be recovered principally over a period of approximately three years. The Company does not earn carrying charges on these regulatory assets as the timing of cash receipts and cash disbursements associated with these long-term obligations is matched through rates.

On October 6, 2006, UES received approval from the NHPUC of a Settlement Agreement (Agreement) resolving its electric distribution base rate case filed in November, 2005. The terms of the Agreement provided for an increase in base distribution rates of $2.3 million effective as of January 1, 2006. Additionally, the NHPUC has authorized two step increases in base distribution rates in accordance with the terms of the Agreement, 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.

On June 22, 2007, the NHPUC issued an order in its investigation into implementation of the federal Energy Policy Act of 2005 regarding the adoption of standards for time-based metering and interconnection. This order set the framework for implementation of time based rates for utility-provided default service. On August 31, 2007, the NHPUC issued an order on motion for rehearing, staying the June 22, 2007 order pending hearing and reconsideration of the issues. An order following hearing was issued on January 22, 2008 finding that it is appropriate to implement time-based metering standards and ordering that the details, including cost-benefit analyses, form of rate design, time of implementation and applicable customer classes shall be determined in separate proceedings to be initiated by the Commission.

utilities made baseline presentations designed to assist the parties in understanding current regulatory methods and the utilities’ assessment of existing incentives and barriers to energy efficiency investment. On November 7, 2007, the Commission hosted expert presentations about the potential of various regulatory approaches to promote energy efficiency. The proceeding remains open.

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

Environmental Matters

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.

The following table shows the balances and activity in the Company’s liability for Environmental Obligations for 2007. The liability for Environmental Obligations was initially recognized on the Company’s Consolidated Balance Sheet at December 31, 2006.

ENVIRONMENTAL OBLIGATIONS


(Millions)	Balance at Beginning of Period		Provision		Payments / Reductions		Balance at End of Period
Year Ended December 31, 2007	$	12.0	$	—	$	—	$	12.0

Note 6: Bad Debts

FG&E and UES are authorized by the MDPU and NHPUC, respectively, to recover the costs of their energy commodity portion of bad debts through reconciling mechanisms. In 2006 and 2007, the Company recorded provisions for the energy commodity portion of bad debts of $1.7 million and $1.5 million, respectively. These provisions were 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.

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2005 – 2007.

ALLOWANCE FOR DOUBTFUL ACCOUNTS


	Balance at Beginning of Period		Additions				Accounts Written Off		Balance at End of Period
	Balance at Beginning of Period		Provision		Recoveries		Accounts Written Off		Balance at End of Period
Year Ended December 31, 2007
Electric	$	1,264,102	$	1,434,356	$	147,497	$	1,840,407	$	1,005,548
Gas		438,159		971,958		113,924		1,298,740		225,301
Other		34,526		34,659		—		33,644		35,541

	$	1,736,787	$	2,440,973	$	261,421	$	3,172,791	$	1,266,390

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

Note 7: Income Taxes

Federal Income Taxes were provided for the following items for the years ended December 31, 2007, 2006 and 2005, respectively:


	2007			2006			2005
Current Federal Tax Provision (000’s):
Operating Income	$	4,522		$	3,448		$	3,671

Total Current Federal Tax Provision		4,522			3,448			3,671

Deferred Federal Tax Provision (000’s)
Accelerated Tax Depreciation		(444	)		(656	)		(668	)
Abandoned Properties		—			—			(796	)
Accrued Revenue		(287	)		795			1,296
Retirement Benefit Obligations		303			271			299
Regulatory Assets and Liabilities		(113	)		(5	)		—
Other, net		(243	)		(87	)		(353	)

Total Deferred Federal Tax Provision (Benefit)		(784	)		318			(222	)

Total Federal Tax Provision	$	3,738		$	3,766		$	3,449

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, 2007, 2006 and 2005 are shown in the table below. In addition to the provisions for federal and state income taxes, the Company recorded provisions of $203,000, $211,000 and $179,000 in 2007, 2006 and 2005, 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)	2007			2006		2005
Federal
Current	$	4,522		$	3,448	$	3,671
Deferred		(784	)		318		(222	)

Total Federal Tax Provision		3,738			3,766		3,449

State
Current		896			337		844
Deferred		(138	)		163		(18	)

Total State Tax Provision		758			500		826

Total Provision for Federal and State Income Taxes	$	4,496		$	4,266	$	4,275

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:


	2007		2006		2005
Statutory Federal Income Tax Rate	34	%	34	%	34	%
Income Tax Effects of:
State Income Taxes, Net	5		5		5
Utility Plant Differences	(4	)	(4	)	(6	)
Other, Net	—		1		—

Effective Income Tax Rate	35	%	36	%	33	%

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


Deferred Income Taxes (000’s)	2007			2006
Accelerated Depreciation	$	19,776		$	25,232
Regulatory Assets / Liabilities & Mechanisms		23,239			23,592
Retirement Benefit Obligations		(15,585	)		(17,644	)
Contributions in Aid to Construction		(4,651	)		(4,759	)
Retirement Loss		5,711			4,945
Percentage Repair Allowance		1,869			1,994
Other		3,024			1,166

Total Deferred Income Tax Liabilities	$	33,383		$	34,526

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. The Company adopted FIN 48 as of January 1, 2007 and there was no impact on the Company’s Consolidated Financial Statements.

The Company evaluated its tax positions at December 31, 2007 in accordance with FIN 48, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by FIN 48 is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Massachusetts and New Hampshire tax authorities for the tax periods ended December 31, 2004; December 31, 2005; and December 31, 2006. Income tax filings for the year ended December 31, 2007 are due March 15, 2008 but likely will be extended until September 15, 2008. The Company classifies penalty and interest expense related to income tax liabilities as an income tax expense. There are no material interest and penalties recognized in the statement of earnings or accrued on the balance sheet.

Note 8: Retirement Benefit Plans

The Company sponsors the following retirement benefit plans to provide certain pension and postretirement benefits for its retirees and current employees as follows:

•

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

•

The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan)—The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

•

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

The following table includes the key assumptions used in determining the Company’s benefit plan costs and obligations:


Used to Determine Plan costs for years ended December 31:	2007			2006			2005
Discount Rate		5.50	%		5.50	%		6.00	%
Rate of Compensation Increase		3.50	%		3.50	%		3.50	%
Expected Long-term rate of return on plan assets		8.50	%		8.50	%		8.50	%
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 Ultimate Health Care Cost Trend Rate is reached		2016			2016			2013
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	690		$	683		$	526
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(539	)	$	(530	)	$	(413	)

Used to Determine Benefit Obligations at December 31:
Discount Rate		6.00	%		5.50	%		5.50	%
Rate of Compensation Increase		3.50	%		3.50	%		3.50	%
Health Care Cost Trend Rate Assumed for Next Year		8.50	%		8.50	%		9.00	%
Ultimate Health Care Cost Trend Rate		4.00	%		4.00	%		4.00	%
Year that Ultimate Health care Cost Trend Rate is reached		2017			2016			2016
Effect of 1% Increase in Health Care Cost Trend Rate (000’s)	$	6,282		$	6,381		$	5,917
Effect of 1% Decrease in Health Care Cost Trend Rate (000’s)	$	(5,030	)	$	(5,091	)	$	(4,737	)

The Discount Rate assumptions used in determining retirement plan costs and retirement plan obligations are based on a market average of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For 2007, 2006 and 2005, 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 Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2007, 2006 and 2005 was 3.50%, based on the expected long-term increase in compensation costs for personnel covered by the plans.

The Expected Long-Term Rate of Return on plan assets assumption used by the Company is developed based on input from actuaries and investment managers. The Company’s Expected Long-Term Rate of Return on plan assets is based on target investment allocation of 60% in common stock equities and 40% in fixed income securities. The actual investment allocations are shown in the table below.


	Target Allocation 2007	Actual Allocation at December 31,
	Target Allocation 2007	2007		2006		2005
Equity Securities	58-62%	57	%	61	%	60	%
Debt Securities	38-42%	43	%	39	%	40	%
Real Estate and Other	0-2%	0	%	0	%	0	%

Total		100	%	100	%	100	%

The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2007. The Company evaluates the actuarial assumptions, including the expected rate of return, at least annually. 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 Plans has been based upon an analysis of historical returns supplemented with an economic and structural review for each asset class.

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


	Pension Plan									PBOP Plan									SERP
	2007			2006			2005			2007			2006			2005			2007			2006			2005
Service Cost	$	1,968		$	1,800		$	1,458		$	1,431		$	1,283		$	993		$	163		$	148		$	90
Interest Cost		3,336			3,153			3,085			2,057			2,028			1,795			118			103			80
Expected Return on Plan Assets		(4,195	)		(3,775	)		(3,404	)		(245	)		(194	)		(41	)		—			—			—
Prior Service Cost Amortization		106			107			107			1,360			1,360			1,401			(2	)		(2	)		(2	)
Transition Obligation Amortization		—			—			—			21			21			21			—			17			17
Actuarial Loss Amortization		1,345			1,324			1,146			70			160			—			44			39			5

Sub-total		2,560			2,609			2,392			4,694			4,658			4,169			323			305			190
Amounts Capitalized and Deferred		(873	)		(1,014	)		(1,751	)		(2,033	)		(2,217	)		(2,051	)		—			—			—

NPBC Recognized	$	1,687		$	1,595		$	641		$	2,661		$	2,441		$	2,118		$	323		$	305		$	190

The estimated amortizations related to Actuarial Loss and Prior Service Cost included in the Company’s Retirement plan costs over the next fiscal year is $1.4 million, $1.4 million and less than $0.1 million for the Pension, PBOP and SERP plans, respectively.

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 2007, 2006 and 2005 was $2.6 million, $2.6 million and $2.4 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2007, 2006 and 2005 would have been $2.5 million, $2.8 million and $2.2 million respectively.

The following table represents information on the plans’ assets, projected benefit obligations (PBO), and funded status ($000’s):


	Pension Plan						PBOP Plan						SERP
Change in Plan Assets:	2007			2006			2007			2006			2007			2006
Plan Assets at Beginning of Year	$	49,527		$	44,535		$	3,052		$	2,304		$	—		$	—
Actual Return on Plan Assets		2,480			4,958			89			78			—			—
Employer Contributions		2,800			2,510			2,500			2,210			72			72
Benefits Paid		(2,645	)		(2,476	)		(1,497	)		(1,540	)		(72	)		(72	)

Plan Assets at End of Year	$	52,162		$	49,527		$	4,144		$	3,052		$	—		$	—


Change in PBO:
PBO at Beginning of Year	$	62,027		$	58,586		$	38,107		$	37,528		$	2,179		$	1,910
Service Cost		1,968			1,800			1,431			1,283			163			148
Interest Cost		3,336			3,153			2,057			2,028			118			103
Benefits Paid		(2,645	)		(2,476	)		(1,497	)		(1,540	)		(72	)		(72	)
Actuarial (Gain) or Loss		(257	)		964			(2,115	)		(1,192	)		(244	)		90

PBO at End of Year	$	64,429		$	62,027		$	37,983		$	38,107		$	2,144		$	2,179

Funded Status: Assets vs PBO	$	(12,267	)	$	(12,500	)	$	(33,839	)	$	(35,055	)	$	(2,144	)	$	(2,179	)

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 based on the projected benefit obligation. The Company has recognized Regulatory Assets of $35.1 million and $37.1 million at December 31, 2007 and 2006, respectively, to recognize the future collection of these plan obligations in electric and gas retail rates.

In accordance with SFAS No. 132 “Employers Disclosures about Pensions and Other Postretirement Benefits,” the Accumulated Benefit Obligation (ABO) is required to be disclosed for all plans where the ABO is in excess of plan assets. The difference between the PBO and the ABO is that the PBO includes projected compensation increases. The ABO for the Pension Plan was $55.1 million and $52.8 million as of December 31, 2007 and 2006, respectively. The ABO for the SERP was $0.6 million and $0.7 million as of December 31, 2007 and 2006, respectively. For the PBOP Plan, the ABO and PBO are the same.

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. The Company expects to contribute approximately $2.8 million to fund its Pension Plan in 2008.

The following table represents employer contributions and benefit payments ($000’s). There were no participant contributions.


	Pension Plan						PBOP Plan						SERP
	2007		2006		2005		2007		2006		2005		2007		2006		2005
Employer Contributions	$	2,800	$	2,510	$	2,500	$	2,500	$	2,210	$	2,500	$	72	$	72	$	72
Benefit Payments	$	2,645	$	2,476	$	2,404	$	1,497	$	1,540	$	1,334	$	72	$	72	$	72

The following table represents estimated future benefit payments ($000’s).


Estimated Future Benefit Payments
	Pension		PBOP		SERP
2008	$	2,940	$	1,401	$	71
2009		3,021		1,509		69
2010		3,224		1,670		66
2011		3,324		1,819		63
2012		3,432		1,942		61
2013 - 2017	$	20,313	$	11,361	$	258

Employee 401(k) Tax Deferred Savings Plan—The Company sponsors the Unitil Corporation Tax Deferred Savings and Investment Plan (the 401(k) Plan) under Section 401(k) of the Internal Revenue Code and 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 401(k) Plan was $533,000, $528,000 and $503,000 for the years ended December 31, 2007, 2006, and 2005, respectively.

Note 9: 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 and preferred stock dividends. 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 MDPU. 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, 2007, 2006 and 2005 ($ Millions):


Year Ended December 31, 2007	Electric		Gas		Other		Non- Regulated			Total
Revenues	$	225.0	$	34.2	$	—	$	3.7		$	262.9
Interest Income		2.8		0.1		0.5		—			3.4
Interest Expense		9.6		2.1		1.3		—			13.0
Depreciation & Amortization Expense		12.6		3.8		1.3		0.1			17.8
Income Tax Expense (Benefit)		3.8		0.4		0.1		0.2			4.5
Segment Profit (Loss)		7.3		1.0		—		0.3			8.6

Segment Assets		334.1		111.9		27.8		0.8			474.6
Capital Expenditures		26.2		6.1		0.2		—			32.5

Year Ended December 31, 2006
Revenues	$	225.2	$	33.3	$	—	$	2.4		$	260.9
Interest Income		3.0		0.1		0.4		—			3.5
Interest Expense		9.5		1.1		0.6		0.1			11.3
Depreciation & Amortization Expense		11.2		3.5		1.3		0.1			16.1
Income Tax Expense (Benefit)		4.2		0.1		0.1		(0.1	)		4.3
Segment Profit (Loss)		7.0		0.5		0.6		(0.2	)		7.9

Segment Assets		346.7		113.1		22.7		0.9			483.4
Capital Expenditures		26.3		7.2		0.1		—			33.6

Year Ended December 31, 2005
Revenues	$	197.3	$	32.8	$	—	$	2.0		$	232.1
Interest Income		2.5		0.1		0.2		—			2.8
Interest Expense		8.1		0.9		0.6		—			9.6
Depreciation & Amortization Expense		14.5		3.1		1.4		0.1			19.1
Income Tax Expense (Benefit)		3.9		0.4		—		—			4.3
Segment Profit (Loss)		7.0		0.9		0.5		—			8.4

Segment Assets		328.2		98.2		22.5		1.2			450.1
Capital Expenditures		17.3		6.9		0.2		—			24.4

Note 10: Quarterly Financial Information (unaudited; Millions, 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,
	2007		2006		2007		2006		2007		2006		2007		2006
Total Operating Revenues	$	77.8	$	70.7	$	59.0	$	60.3	$	61.8	$	66.2	$	64.3	$	63.7
Operating Income	$	4.7	$	3.9	$	4.3	$	3.4	$	3.9	$	3.8	$	5.6	$	4.7
Net Income Applicable to Common	$	2.6	$	2.0	$	1.7	$	1.4	$	1.6	$	1.8	$	2.7	$	2.7

	Per Share Data:
Earnings Per Common Share	$	0.46	$	0.36	$	0.30	$	0.25	$	0.28	$	0.32	$	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

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A.

Controls and Procedures

Disclosure Controls and Procedures

Management of the Company, under the supervision and with the participation of the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures as of December 31, 2007. Based upon this evaluation, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2007 that the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15(d)-15(e)) are effective.

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) and 15d-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 this 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 2007, 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, 2007.

The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Vitale, Caturano and Company, an independent registered public accounting firm. Their report appears in Item 8.

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 2007 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 2007 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 2007 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 2007 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, 2007 and 2006

•

Consolidated Statements of Earnings for the years ended December 31, 2007, 2006, and 2005

•

Consolidated Statements of Capitalization—December 31, 2007 and 2006

•

Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006, and 2005

•

Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2007, 2006, and 2005

•

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.	**

4.10	Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022.	**

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


Exhibit Number	Description of Exhibit	Reference*
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

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

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


Exhibit Number	Description of Exhibit	Reference*

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

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

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

*	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 12, 2008	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 12, 2008

/S/ MARK H. COLLIN Mark H. Collin	Principal Financial Officer	February 12, 2008

/S/ LAURENCE M. BROCK Laurence M. Brock	Principal Accounting Officer	February 12, 2008

/S/ MICHAEL J. DALTON Michael J. Dalton	Director	February 12, 2008

/S/ ALBERT H. ELFNER, III Albert H. Elfner, III	Director	February 12, 2008

/S/ M. BRIAN O’SHAUGHNESSY M. Brian O’Shaughnessy	Director	February 12, 2008

/S/ CHARLES H. TENNEY, III Charles H. Tenney, III	Director	February 12, 2008

/S/ DR. SARAH P. VOLL Dr. Sarah P. Voll	Director	February 12, 2008

/S/ EBEN S. MOULTON Eben S. Moulton	Director	February 12, 2008

/S/ DAVID P. BROWNELL David P. Brownell	Director	February 12, 2008

/S/ EDWARD F. GODFREY Edward F. Godfrey	Director	February 12, 2008

/S/ MICHAEL B. GREEN Michael B. Green	Director	February 12, 2008

/S/ DR. ROBERT V. ANTONUCCI Dr. Robert V. Antonucci	Director	February 12, 2008