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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549



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FORM 10-K



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



For the fiscal year ended December 31, 2008



OR



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



Commission file number 1-8858



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UNITIL CORPORATION

(Exact name of registrant as specified in its charter)



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|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|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



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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 |  | New York 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   ̈        Smaller reporting company   ̈



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, 2008, the aggregate market value of common stock held by non-affiliates of the
registrant was $148,801,666.



The number of common shares
outstanding of the registrant was 8,095,724 as of February 17, 2009.



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Documents Incorporated by Reference:



Portions of the Proxy Statement relating to the Annual Meeting of
Shareholders to be held April 16, 2009 are incorporated by reference into Part III of this Report



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UNITIL
CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2008

Table of Contents



|     |  |                                                                                                              |  |     
|---- |  | ------------------------------------------------------------------------------------------------------------ |  | ----
|Item |  | Description                                                                                                  |  | Page
|     |  | PART I                                                                                                       |  |     
|1.   |  | Business                                                                                                     |  | 1   
|     |  | Unitil Corporation                                                                                           |  | 1   
|     |  | Operations                                                                                                   |  | 2   
|     |  | Rates and Regulation                                                                                         |  | 4   
|     |  | Electric Power Supply                                                                                        |  | 4   
|     |  | Natural Gas Supply                                                                                           |  | 6   
|     |  | Environmental Matters                                                                                        |  | 7   
|     |  | Employees                                                                                                    |  | 7   
|     |  | Available Information                                                                                        |  | 8   
|     |  | Directors and Executive Officers of the Registrant                                                           |  | 8   
|     |  | Investor Information                                                                                         |  | 10  
|1A.  |  | Risk Factors                                                                                                 |  | 11  
|1B.  |  | Unresolved Staff Comments                                                                                    |  | 15  
|2.   |  | Properties                                                                                                   |  | 16  
|3.   |  | Legal Proceedings                                                                                            |  | 17  
|4.   |  | Submission of Matters to a Vote of Security Holders                                                          |  | 17  
|     |  |                                                                                                             
|     |  | PART II                                                                                                      |  |     
|5.   |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 18  
|6.   |  | Selected Financial Data                                                                                      |  | 21  
|7.   |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                        |  | 22  
|7A.  |  | Quantitative and Qualitative Disclosures about Market Risk                                                   |  | 44  
|8.   |  | Financial Statements and Supplementary Data                                                                  |  | 45  
|9.   |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                         |  | 87  
|9A.  |  | Controls and Procedures                                                                                      |  | 87  
|9B.  |  | Other Information                                                                                            |  | 88  
|     |  |                                                                                                             
|     |  | PART III                                                                                                     |  |     
|10.  |  | Directors and Executive Officers of the Registrant                                                           |  | 89  
|11.  |  | Executive Compensation                                                                                       |  | 89  
|12.  |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters               |  | 89  
|13.  |  | Certain Relationships and Related Transactions                                                               |  | 89  
|14.  |  | Principal Accountant Fees and Services                                                                       |  | 89  
|     |  |                                                                                                             
|     |  | PART IV                                                                                                      |  |     
|15.  |  | Exhibits and Financial Statement Schedules                                                                   |  | 90  
|     |  | Signatures                                                                                                   |  | 94  





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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:



|                                                     |  |                               |  |                                       
|---------------------------------------------------- |  | ----------------------------- |  | --------------------------------------
|Company Name                                         |  | State and Year ofOrganization |  | Principal Business                    
|                                                     |  |                              
|Unitil Energy Systems, Inc. (Unitil Energy)          |  | NH - 1901                     |  | Electric Distribution Utility         
|                                                     |  |                              
|Fitchburg Gas and Electric Light Company (Fitchburg) |  | MA - 1852                     |  | Electric & Gas Distribution Utility   
|                                                     |  |                              
|Northern Utilities, Inc. (Northern Utilities)        |  | NH - 1979                     |  | Natural Gas Distribution Utility      
|                                                     |  |                              
|Granite State Gas Transmission, Inc. (Granite State) |  | NH - 1955                     |  | Natural Gas Transmission Pipeline     
|                                                     |  |                              
|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.



On December 1, 2008, the Company purchased: (i) all of the outstanding capital stock of Northern Utilities, a natural gas distribution utility
serving customers in Maine and New Hampshire, originally founded as Portland Gas Light Company in 1849, from Bay State Gas Company (Bay State) and (ii) all of the outstanding capital stock of Granite State, an interstate natural gas
transmission pipeline company primarily serving the needs of Northern Utilities, from NiSource Inc. (NiSource) pursuant to the Stock Purchase Agreement dated as of February 15, 2008 by and among NiSource, Bay State, and Unitil (the
Acquisitions). Bay State is a wholly owned subsidiary of NiSource. The aggregate purchase price for the Acquisitions was $160 million in cash, plus an additional working capital adjustment of $49.2 million, including approximately $30.0 million of
natural gas storage inventory. To finance the Acquisitions and recapitalize Northern Utilities and Granite State, the Company issued additional equity and debt (see Liquidity, Commitments and Capital Requirements section in Part II,
Item 7 below).



Unitils principal business is the
local distribution of electricity and natural gas throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly owned distribution utilities: i) Unitil Energy, which provides
electric service in the southeastern seacoast and state capital regions of New Hampshire, including the city of Concord, New Hampshire, ii) Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north
central Massachusetts, and iii) Northern Utilities, which provides natural gas service in southeastern New Hampshire and portions of southern and central Maine, including the city of Portland and the Lewiston-Auburn area. In addition, Unitil is the
parent company of Granite State, an interstate natural gas transmission pipeline company that principally provides interstate natural gas pipeline access and transportation services to Northern Utilities in its New Hampshire and Maine service
territory. Together, Unitils three distribution utilities serve approximately 100,300 electric customers and 69,300 natural gas customers.



Unitils distribution utilities are local pipes and wires operating companies and, combined with Granite State, had an investment in net
utility plant of $422.8 million at December 31, 2008. Unitils total revenue was $288.2 million in 2008. Earnings applicable to common shareholders for 2008 was $9.6 million. Substantially all of Unitils revenue and earnings are
derived from regulated utility operations.



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A fifth utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power
supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1, 2003 and divested of 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 energy supply 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. Unitil Resources is the Companys wholly owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are indirect subsidiaries
that are wholly owned by Unitil Resources. Usource provides energy brokering and advisory services to large commercial and industrial customers in the northeastern United States.



OPERATIONS



Electric Distribution Utility Operations



Unitils electric utility operations are conducted through two of the Companys distribution utilities, Unitil Energy and Fitchburg. Revenue
from Unitils electric utility operations was $227.5 million for 2008. Earnings from electric utility operations were $5.2 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 service territory in New Hampshire and Massachusetts. As a result of the implementation of choice in New Hampshire and Massachusetts, Unitils customers are free to contract for their supply of electricity with third-party suppliers. The
distribution utilities continue to deliver that supply of electricity over their distribution systems. Both Unitil Energy and Fitchburg supply electricity to those customers who do not obtain their supply from third-party suppliers, with the costs
associated with electricity supplied by the distribution utilities being recovered on a pass-through basis under periodically-adjusted rates.



Unitil Energy distributes electricity to approximately 72,500 customers in New Hampshire in the capital city of Concord as well as parts of 12 surrounding
towns and all or part of 18 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. Unitil Energys service territory consists of approximately 408 square miles. In
addition, Unitil Energys service territory encompasses retail trading and recreation centers for the central and southeastern parts and includes the Hampton Beach recreational area. These areas serve diversified commercial and industrial
businesses, including manufacturing firms engaged in the production of electronic components, wires and plastics, healthcare and education. Unitil Energys 2008 electric operating revenue was $161.0 million, of which approximately 49.0% was
derived from residential sales and 51.0% from commercial/industrial sales.



Fitchburg is engaged in the distribution of both electricity and natural gas in the city of Fitchburg and several surrounding communities. Fitchburgs service territory encompasses approximately 170 square miles.
Electricity is supplied and distributed by Fitchburg to approximately 27,800 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. Fitchburgs industrial customers include paper manufacturing and paper products companies,
rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries and education. Fitchburgs 2008 electric operating revenue was $66.5 million, of which approximately 54.0% was derived from
residential sales and 46.0% from commercial/industrial sales.



Gas
Operations



Unitils Gas Operations include gas
distribution utility operations and gas transportation pipeline company operations, discussed below. Revenue from Unitils gas operations was $56.9 million for 2008. Earnings from gas operations were $4.3 million for the same 12-month period.
In 2008, the Company significantly expanded its gas operations by acquiring Northern Utilities and Granite State on December 1, 2008.



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Gas Distribution Utility Operations



Unitils natural gas utility operations are conducted through two of the Companys distribution utilities, Northern Utilities and
Fitchburg. The primary business of Unitils natural gas distribution utility operations is the local distribution of natural gas to customers in its service territory in New Hampshire, Massachusetts and Maine. As a result of a restructuring of
the gas utility industry in New Hampshire, Massachusetts and Maine, Fitchburgs residential and commercial and industrial (C&I) customers and Northern Utilities C&I customers have the opportunity to purchase their natural gas
supplies from third party vendors. Most customers, however, continue to purchase such supplies through Northern Utilities and Fitchburg as the provider of last resort. Northern Utilities and Fitchburg purchase natural gas from unaffiliated wholesale
suppliers and recover the actual costs of these supplies on a pass-through basis through reconciling rate mechanisms that are periodically adjusted.



Natural gas is supplied and distributed by Northern Utilities to approximately 54,200 customers in 44 New Hampshire and southern Maine communities, from
Plaistow, New Hampshire in the south to the city of Portland, Maine and then extending to Lewiston-Auburn, Maine in the north. Northern Utilities has a diversified customer base both in Maine and New Hampshire. Commercial businesses include
healthcare, education, government and retail. Northern Utilities industrial base includes manufacturers in the industries of auto, housing, rubber, printing, textile, pharmaceutical, electronics, wires and food production as well as a military
installation. Northern Utilities 2008 gas operating revenue was $19.5 million, of which approximately 35.0% was derived from residential firm sales and 65.0% from commercial/industrial firm sales.



Natural gas is supplied and distributed by Fitchburg to approximately 15,100
customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Fitchburgs industrial customers include paper manufacturing and paper products companies, rubber and plastics
manufacturers, chemical products companies and printing, publishing and associated industries. Fitchburgs 2008 gas operating revenue was $37.0 million, of which approximately 54.0% was derived from residential firm sales and 46.0% from
commercial/industrial firm sales.



Gas Transmission Pipeline Company
Operations



Granite State is an interstate natural gas
transmission pipeline company, operating 87 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to major natural gas pipelines and access to
domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State had operating revenue of $0.4 million for 2008. Granite State derives its revenues principally from the transportation services provided to
Northern Utilities and, to a lesser extent, third-party marketers.



Seasonality



Natural gas sales in New England
are seasonal, and our results of operations reflect this seasonal nature. In particular, the Company expects that consolidated results of operations in future reporting periods will reflect to a greater degree the seasonal nature of natural gas
sales by Northern Utilities, which was acquired by the Company on December 1, 2008. Accordingly, the Company expects that as a result of the Acquisitions consolidated results of operations will be positively affected during the first and fourth
quarters, and negatively affected during the second and third quarters of future reporting years.



Electric sales in New England are far less seasonal than natural gas sales; however, the highest usage typically occurs in both the summer months due to
air conditioning demand and the winter months due to heating-related requirements and shorter daylight hours. Unitil Energy, Fitchburg and Northern Utilities are not dependent on a single customer or a few customers for their electric and natural
gas sales.



Non-regulated and Other Non-Utility Operations



Unitils non-regulated operations are conducted through Usource, a
subsidiary of Unitil Resources. 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 $3.8 million in 2008.
Earnings from Unitils non-regulated operations were $0.3 million in 2008.



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The results of Unitils other non-utility subsidiaries, Unitil Service and Unitil Realty, and the
holding company are included in the Companys consolidated results of operations. The results of these 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 are reported in Other segment income (for segment information, see Part II, Item 8, Note 11 herein). Unitils other non-utility operations recognized a net loss of ($0.2) million in 2008.



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



RATES AND REGULATION



Unitil is subject to comprehensive regulation by
federal and state regulatory authorities. Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 with regard to certain bookkeeping, accounting and reporting requirements.
Unitils utility operations related to wholesale and interstate energy business activities are also regulated by FERC. Unitils distribution utilities are subject to regulation by the applicable state public utility commissions, with
regard to their rates, issuance of securities and other accounting and operational matters: Unitil Energy is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC); Fitchburg is subject to regulation by the Massachusetts
Department of Public Utilities (MDPU); and Northern Utilities is regulated by the NHPUC and Maine Public Utilities Commission (MPUC). Because Unitil's primary operations are subject to rate regulation, the regulatory treatment of various matters
could significantly affect the Company's operations and financial position.



Unitils distribution utilities deliver electricity and/or natural gas to all customers in their service territory, at rates established under traditional cost of service regulation. Under this regulatory
structure, Unitils distribution utilities recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a
restructuring of the utility industry in New Hampshire, Massachusetts and Maine, Unitils customers have the opportunity to purchase their electricity or natural gas supplies from third party vendors. Most customers, however, continue to
purchase such supplies through the distribution utilities. Unitils distribution utilities purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual costs of these supplies on a pass-through basis, as well
as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.



The regulatory process in both New Hampshire and Maine, in connection with those states approvals of the Acquisitions, included the negotiation and
filing of settlement agreements reflecting commitments by Unitil with respect to Northern Utilities rates, customer service and operations. The settlement agreements were separately negotiated and filed in each state but reflect a number of
common features.



Also see Managements Discussion and
Analysis of Financial Condition and Results of OperationsRegulatory Matters and Note 7 to the accompanying Consolidated Financial Statements for additional information on Regulatory Matters.



ELECTRIC POWER SUPPLY



The transition to retail choice required the divestiture of Unitils
power supply arrangements and the procurement of replacement supplies, which provided the flexibility for migration of customers to and from utility service. Fitchburg, Unitil Energy, and Unitil Power each are members of the New England Power Pool
(NEPOOL) and participate in the ISO New England, Inc. (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitils 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 suppliers. Retail choice has been successful for Unitils largest
customers. As of December 2008, 82 or 55% of Unitils largest New Hampshire customers representing 18% of total New Hampshire electric sales and 27 or 84% of Unitils largest Massachusetts customers representing 35%



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of total Massachusetts electric sales are purchasing their electric power supply in the competitive market. However, most residential and small commercial
customers continue to purchase their electric supply through Unitils distribution utilities. The concentration of the competitive market on higher use customers has been a common experience throughout the New England electricity market.



Regulated Electric Power Supply



In order to provide regulated electric supply service to their customers,
Unitils distribution utilities enter into load-following wholesale electric power supply contracts with various wholesale suppliers.



Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing
structure and duration of each of these contracts. Currently, all Basic Service power supply contracts for large general accounts are three months in duration and provide 100% of supply requirements. Basic Service power supply contracts for
residential and small and medium general service customers are acquired every six months, are 12 months in duration and provide 50% of the supply requirements.



Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Unitil
Energy 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. Unitil Energy 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.



The NHPUC and MDPU regularly investigate alternatives to their procurement policy, which may lead to future changes in this procurement structure.



Regional Electric Transmission and Power Markets



Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New
England electric utilities, are participants in the ISO-NE markets. ISO-NE is the Regional Transmission Organization (RTO) in New England. 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 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.



Electric Power Supply Divestiture



Prior to May 1, 2003, Unitil Energy 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, Unitil
Energy and Unitil Power amended the Unitil System Agreement, such that power sales from Unitil Power to Unitil Energy ceased, and Unitil Power sold substantially all of its entitlements under the remaining portfolio of power supply contracts. Under
the amended Unitil System Agreement, Unitil Energy 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. In connection with the
implementation of retail choice, Unitil Power and Fitchburg 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.



Unitil Energy and Fitchburg 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.



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Unitils distribution utilities 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.



Also see Managements Discussion and Analysis of Financial Condition and Results of OperationsRegulatory Matters and Note 6 to the accompanying
Consolidated Financial Statements for additional information on Electric Power Supply.



NATURAL GAS SUPPLY



With the purchase of Northern Utilities on December 1, 2008, Unitil now manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.



Fitchburgs residential and C&I customers have the opportunity to
purchase their natural gas supply from third-party vendors, although most of Fitchburgs customers continue to purchase such supplies at regulated rates from Fitchburg. Northern Utilities C&I natural gas customers have the opportunity
to purchase their natural gas supply from third-party vendors, and third-party supply is prevalent among Northern Utilities larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply
at regulated rates from Northern Utilities 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.



Regulated Natural Gas Supply



Fitchburg purchases natural gas under contracts of one year or less, as well as from producers and marketers on the spot market. Fitchburg arranges for
gas delivery to its city gate station or underground storage through its own long-term contracts with Tennessee Gas Pipeline. Fitchburgs gas supply is delivered to the city gate station or in the case of liquefied natural gas (LNG) or
liquefied propane gas (LPG), by truck to each storage facility within Fitchburgs service territory.



Fitchburg 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, Fitchburg 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.



Northern Utilities purchases a majority of its
natural gas from U.S. domestic and Canadian suppliers under contracts of one year or less, and on occasion from producers and marketers on the spot market. Northern Utilities arranges for gas delivery to its city gate station or underground storage
through its own long-term contracts with various interstate pipeline and storage facilities, or through peaking supply contracts delivered to its city gate station. Northern Utilities gas supply is delivered to its city gate stations or in the case
of LNG or LPG, by truck to each storage facility within Northern Utilities service territory.



Northern Utilities has available under firm contract 100,000 MMbtu per day of year-round and seasonal transportation capacity to its distribution
facilities, and 3.4 Bcf of underground storage. As a supplement to pipeline natural gas, Northern Utilities 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.



Also see
Managements Discussion and Analysis of Financial Condition and Results of OperationsRegulatory Matters and Note 6 to the accompanying Consolidated Financial Statements for additional information on Natural Gas Supply.



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ENVIRONMENTAL MATTERS



Unitils past and present operations include activities that are
generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in compliance with applicable environmental and safety laws and regulations, and the Company believes that as of
December 31, 2008, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that
other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.



Fitchburgs Manufactured Gas Plant SiteFitchburg 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. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts
Department of Environmental Protection, which allows Fitchburg to work towards temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed
and completed. Also, see Note 7 for additional discussion of Fitchburgs regulatory and environmental matters.



Fitchburg 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, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs. In
addition, Fitchburg 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 Fitchburg receives from insurance or third parties with respect to
environmental response costs, net of the unrecovered costs associated therewith, are split equally between Fitchburg and its gas customers.



Northern Utilities Manufactured Gas Plant SitesNorthern Utilities has an extensive program to identify, investigate and remediate
former MGP sites that were operated from the mid 1800s through the mid 1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston
and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.



The NHPUC and MPUC have approved the recovery of MGP environmental costs. For
Northern Utilities New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. Northern Utilities believes material future costs will be recovered. For Northern Utilities
Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.



Also, see Discussion and Analysis of Financial Condition and Results of OperationsEnvironmental Matters and Note 7 to the accompanying Consolidated
Financial Statements for additional information on Environmental Matters.



EMPLOYEES



As
of December 31, 2008, the Company and its subsidiaries had 406 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.



As of December 31, 2008, 144 of the Companys employees were
represented by labor unions. These employees are covered by collective bargaining agreements. Two of these agreements expire on March 31, 2009, two agreements expire on May 31, 2010, and one agreement expires on June 5, 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.



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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 New York 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 18, 2009:



|                        |  |     |  |                                                                            
|----------------------- |  | --- |  | ---------------------------------------------------------------------------
|Name                    |  | Age |  | Position                                                                   
|Robert G. Schoenberger  |  | 58  |  | Chairman of the Board, Chief Executive Officer and President               
|Mark H. Collin          |  | 49  |  | Senior Vice President, Chief Financial Officer and Treasurer               
|Thomas P. Meissner, Jr. |  | 46  |  | Senior Vice President and Chief Operating Officer                          
|Laurence M. Brock       |  | 55  |  | Controller and Chief Accounting Officer                                    
|Todd R. Black           |  | 44  |  | President, Usource                                                         
|George R. Gantz         |  | 57  |  | Senior Vice President, Customer Services and Communications, Unitil Service
|George E. Long, Jr.     |  | 52  |  | Vice President, Administration, Unitil Service                             
|Raymond J. Morrissey    |  | 61  |  | Vice President, Information Systems, Unitil Service                        
|Sandra L. Whitney       |  | 45  |  | Corporate Secretary                                                        
|Dr. Robert V. Antonucci |  | 63  |  | Director                                                                   
|David P. Brownell       |  | 65  |  | Director                                                                   
|Michael J. Dalton       |  | 68  |  | Director                                                                   
|Albert H. Elfner, III   |  | 64  |  | Director                                                                   
|Edward F. Godfrey       |  | 59  |  | Director                                                                   
|Michael B. Green        |  | 59  |  | Director                                                                   
|Eben S. Moulton         |  | 62  |  | Director                                                                   
|M. Brian OShaughnessy  |  | 65  |  | Director                                                                   
|Charles H. Tenney, III  |  | 61  |  | Director                                                                   
|Dr. Sarah P. Voll       |  | 66  |  | Director                                                                   



Robert G. Schoenberger
has been Unitils Chairman of the Board of Directors and Chief Executive Officer since 1997, as well as President since 2003. Prior to his employment with Unitil, Mr. Schoenberger was president and chief operating officer of the New York
Power Authority (a state-owned utility operating 6,000 MW of generation and 1,400 miles of high voltage transmission) from 1993 until 1997. Mr. Schoenberger also serves as chairman and trustee of Exeter Health Resources, Exeter, New Hampshire,
since 1998, and as a director of SatCon Technology Corporation, Boston, Massachusetts (a company engaged in the development and manufacture of power electronics and control systems) since 2007. Mr. Schoenberger was director of the Greater
Seacoast (New Hampshire) United Way from 1998 until 2004, the New England Gas Association from 1999 until 2002 and the Southwest Power Pool from 2003 until 2005.



Mark H. Collin has been Unitils Senior Vice President and Chief Financial Officer since February 2003. Mr. Collin
has also served as Treasurer since 1998. Mr. Collin joined Unitil in 1988, and served as Vice President of Finance from 1995 until 2003.



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Thomas P. Meissner, Jr. has been Unitils Senior Vice President and Chief Operating Officer since
June 2005. Mr. Meissner served as Senior Vice President, Operations, from February 2003 until June 2005. Mr. Meissner joined Unitil in 1994 and served as Director of Engineering from 1998 until 2003.



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



Todd R. Black has been President of Usource since June 2003. Mr. Black
joined Unitil in 1998 and served as Vice President, Sales and Marketing, for Usource from 1998 until 2003.



Laurence M. Brock has been Unitils Controller and Chief Accounting Officer 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.



George E. Long, Jr. has been Unitils Vice President, Administration, Unitil Service, since February 2003. Mr. Long joined Unitil in 1994 and was Director, Human Resources, from 1998 until 2003.



Raymond J. Morrissey has been Unitils Vice President, Information
Systems, Unitil Service, since February 2003. Mr. Morrissey served as Unitils Vice President of Customer Service from 1992 until 2003, and general manager of Fitchburg from 1991 until 1992. Mr. Morrissey joined Unitil in 1985.



Sandra L. Whitney has been Unitils Corporate Secretary
and secretary of our Board of Directors since February 2003. Ms. Whitney joined Unitil in 1990 and also serves as the Corporate Secretary of Unitils subsidiary companies.



Dr. Robert V. Antonucci has been a member of Unitils Board of Directors since 2004. Dr. Antonucci has
been the president of Fitchburg State College (FSC) in Fitchburg, Massachusetts, since 2003. Prior to his employment with FSC, Dr. Antonucci was president of the School Group of Riverdeep, Inc., San Francisco, California, from 2001 until 2003
and president and chief executive officer of Harcourt Learning Direct and Harcourt Online College, Chestnut Hill, Massachusetts from 1998 until 2001. Dr. Antonucci also served as the commissioner of education for the Commonwealth of
Massachusetts from 1992 until 1998. Dr. Antonucci also serves as a trustee of Eastern Bank (formerly Plymouth (Massachusetts) Savings Bank) since 1988.



David P. Brownell has been a member of Unitils Board of Directors since 2001. Mr. Brownell has been a retired senior vice president of Tyco
International Ltd. (Tyco) (a diversified global manufacturing and service company), Portsmouth, New Hampshire, since 2003. Mr. Brownell had been with Tyco since 1984. Mr. Brownell was also interim president of the University of New
Hampshire Foundation (UNHF), former vice chairman of the board of UNHF, former volunteer board president of the United Way of the Greater Seacoast, and a former board member of the New Hampshire Junior Achievement Advisory Council.



Michael J. Dalton has been a member of Unitils Board of Directors since
1984. Mr. Dalton has been the retired president and chief operating officer of Unitil since 2003. Mr. Dalton has been a member of the Industrial Advisory Board of the University of New Hampshire College of Engineering and Physical Sciences
since 2003. Mr. Dalton was a director of the New England Gas Association from 2002 until 2003, the Electric Council of New England, the UNHF, the University of New Hampshire Alumni Association, and the University of New Hampshire
Presidents Council.



Albert H. Elfner, III has been a
member of Unitils Board of Directors since 1999. Mr. Elfner was the chairman of Evergreen Investment Management Company, Boston, Massachusetts, from 1994 until 1999 and its chief executive officer from 1995 until 1999. Mr. Elfner is
also a director of NGM Insurance Company (NGM), Jacksonville, Florida, as well as a member of the NGM finance committee.



Edward F. Godfrey has been a member of Unitils Board of Directors since 2002. Mr. Godfrey was the executive vice president and chief operating
officer of Keystone Investments, Incorporated (Keystone),



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Boston, Massachusetts, from 1997 until 1998. Mr. Godfrey was senior vice president, chief financial officer and treasurer of Keystone from 1988 until
1996. Mr. Godfrey is also a director of VehiCare, LLC, Charlotte, North Carolina, since 2006.



Michael B. Green has been a member of Unitils Board of Directors since 2001. Mr. Green has been the president and chief executive officer of
Capital Region Health Care and Concord Hospital, Concord, New Hampshire, since 1992. Mr. Green is also a member of the adjunct faculty, Dartmouth Medical School, Dartmouth College, Hanover, New Hampshire. In addition, Mr. Green 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, and a director of Merrimack County Savings Bank including membership
on the banks investment and audit committees.



Eben S.
Moulton has been a member of Unitils Board of Directors since 2000. Mr. Moulton has been the managing partner of Seacoast Capital Corporation, Danvers, Massachusetts, (a private investment company) since 1995. Mr. Moulton is also a
director of IEC Electronics (a complex circuit boards manufacturer), a director of six private companies, and a trustee of Colorado College, Colorado Springs, Colorado.



M. Brian OShaughnessy has been a member of Unitils Board of Directors since 1998. Mr. OShaughnessy has been the
chairman of the board of Revere Copper Products, Inc. (Revere), Rome, New York, since 1988. Mr. OShaughnessy also served as chief executive officer and president of Revere from 1988 until 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 a member of
Unitils Board of Directors since 1992. Mr. Tenney was the director of operations of BrainShift.com, Inc., Medford, Massachusetts (a learning technology development company) from 2002 until 2008. Mr. Tenney is currently a director of
The BrainShift Foundation (a non-profit division of BrainShift.com, Inc. engaged in energy conservation). Mr. Tenney also served as a member of the board of overseers of the Huntington Theater Company, Boston, Massachusetts, from 2004 until
2006.



Dr. Sarah P. Voll has been a member of
Unitils Board of Directors since 2003. Dr. Voll has been a retired vice president, National Economic Research Associates, Inc. (NERA), Washington, District of Columbia, a firm of consulting economists specializing in industrial and
financial economics, since 2007. Dr. Voll had been with NERA in the position of vice president since 1999, and in the position of senior consultant from 1996 until 1999. Prior to her employment with NERA, Dr. Voll was a staff member at the
NHPUC from 1980 until 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 16, 2009, at 10:30 a.m.



Transfer Agent



The
Companys transfer agent, Computershare, is responsible for shareholder records, issuance of common stock, administration of the Dividend Reinvestment and Stock Purchase Plan, 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



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Investor Relations



For information about the Company, 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 to Holders of Record



If a shareholders shares of common stock are registered directly in the shareholders name with the
Companys transfer agent, the shareholder is considered a holder of record of the shares. The following services and programs are available to shareholders of record:



| |  |  | Internet Account Access is available at www.computershare.com.
| | - |  | --------------------------------------------------------------



| |  |  | Dividend Reinvestment and Stock Purchase Plan:
| | - |  | ----------------------------------------------



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



| |  |  | Dividend Direct Deposit Service:
| | - |  | --------------------------------



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



| |  |  | 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 the Companys business could impact the rates it is able to charge, its costs and its profitability.



The Company is subject to comprehensive regulation by federal and state regulatory authorities, which significantly
influences the Companys operating environment and its ability to recover costs from its customers. In particular, the Company is regulated by the FERC and state regulatory authorities with jurisdiction over public utilities, including the
NHPUC, MDPU and MPUC. These authorities regulate many aspects of the Companys operations, including, but not limited to, construction and maintenance of facilities, operations, safety, issuance of securities, accounting matters, transactions
between affiliates, the rates that the Company can charge customers and the rate of return that it is allowed to realize. The Companys ability to obtain rate adjustments to maintain its current rate of return depends upon regulatory action
under applicable statutes, rules and regulations, and the Company cannot assure you that it will be able to obtain rate adjustments or continue receiving its current authorized rates of return. These regulatory authorities are also empowered to
impose financial penalties and other sanctions on the Company if it is found to have violated statutes and regulations governing its utility operations. The Company is unable to predict the impact on its operating results from the regulatory
activities of any of these agencies. Although the Company has attempted to actively manage the rate making process and has had recent success in obtaining rate adjustments, it can offer no assurances as to future success in the rate making process.
Despite the Companys requests, these regulatory commissions have authority under applicable statutes, rules and regulations to leave the Companys rates unchanged, grant increases or order decreases in such rates.



The regulators also have authority with respect to the recovery of the
Companys electricity and natural gas supply costs incurred by Unitil Energy, Fitchburg, and Northern Utilities. In the event that the Company is unable to recover these costs or recovery of these costs were to be significantly delayed, the
Companys operating results could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have an adverse effect on the Companys operating results.



As a result of electric industry restructuring, the Company has a significant amount of
certain stranded electric generation and generation related supply costs.



The stranded costs resulting from the implementation of electric industry restructuring mandated by the states of New Hampshire and Massachusetts are recovered by the Company on a pass-through basis through



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periodically reconciled 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.



The Companys 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 $33.8 million for Fitchburg and $18.9 million for Unitil Energy as of December 31, 2008, including $8.3 million and $9.8 million for Fitchburg and Unitil Energy,
respectively, in Accrued Revenue on the Companys Consolidated Balance Sheet. Additionally, the Companys other restructuring-related regulatory assets for which regulatory approval has been obtained for recovery were approximately $29.1
million in the aggregate as of December 31, 2008, including $4.0 million in Accrued Revenue on the Companys Consolidated Balance Sheet.



Substantially all of Fitchburgs stranded costs relate to owned generation assets and purchase power agreements divested by Fitchburg under a
long-term contract buy-out agreement. Unitil Energys stranded costs are attributable to the long-term power purchase agreements divested by Unitil Power under long-term contract buyout agreements. Because Fitchburg and Unitil Power remain
ultimately responsible for purchase power payments underlying these long-term buyout agreements, Fitchburg 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. The Company expects that any such additional stranded costs would be recovered from its customers, although such recovery would require approval from the
MDPU or NHPUC, the receipt of which cannot be assured.



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



The Companys business is
influenced by the economic activity of its service territory. The level of economic growth in the Companys electric and natural gas distribution service territory directly affects its potential for future growth in its business. As a result,
adverse changes in the economy, including the significant adverse changes in the economy in 2008, may have negative effects on the Companys revenues, operating results and financial condition.



The Company may not be able to obtain debt financing, obtain debt financing on
acceptable terms, or obtain debt financing under its current credit facilities because of the deterioration of the credit and capital markets, which could have an adverse affect on the Companys operating results and financial
condition.



The Company requires capital to fund
utility plant additions, working capital and other utility expenditures. While the capital necessary to meet these requirements is derived primarily from internally-generated funds, the Company initially supplements internally generated funds
through short-term debt financings, as needed, and periodically replaces portions of its short-term debt with long-term debt. General economic conditions, including recent distress in the financial markets, have had an adverse impact on the
availability of credit resources generally, which could negatively affect the Companys ability to obtain short- and long-term debt financings and the terms of such financings. In addition, the Company may be unable to obtain debt financing
under its current credit facilities because its lending counterparties may be unwilling or unable to meet their funding obligations. In each case, this could hinder or prevent the Company from meeting its future capital needs, which could
correspondingly have an adverse affect on the Companys operating results and financial condition. In addition, the material terms of the Companys existing indebtedness will also restrict its ability to incur any material amount of
additional indebtedness, which could negatively impact its operating results and financial condition. See Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity, Commitments and Capital Requirements
and Note 5 to the accompanying Consolidated Financial Statements.



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Declines in the valuation of capital markets could require the Company to make substantial cash contributions to
cover its pension obligations, which could negatively impact its financial condition.



On August 17, 2006, the Pension Protection Act of 2006 (the PPA) was signed into law. Included in the PPA are new minimum funding rules which came 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 provided pursuant to the PPA. Due to the significant
declines in the valuation of capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum
funding rules set forth in the PPA such that all plans, except those that were subject to deficit reduction contribution requirements in 2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the
2008  2010 plan years.



The Company made cash
contributions of $2.8 million, $2.8 million and $2.5 million to its pension plan in 2008, 2007 and 2006, respectively, which exceeded minimum funding requirements. Recent and future declines in the valuation of capital markets could require the
Company to make cash contributions to its pension plans substantially in excess of its cash contributions in prior years, which could adversely affect its financial condition.



In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards
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 rates. In the event that the Company is unable to
recover these costs or recovery of these costs were to be significantly delayed, the Companys operating results could be materially adversely affected. See Managements Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity, Commitments and Capital Requirements and Note 10 to the accompanying Consolidated Financial Statements.



Increases in interest rates could have a negative impact on the Companys financial condition and the Company may need to use a significant portion of its cash
flow to repay its outstanding indebtedness.



The
Company and its utility subsidiaries have ongoing capital expenditure and cash funding requirements that they frequently fund by issuing short-term debt and long-term debt.



Short-term debt borrowings are typically at variable rates of interest. Therefore, changes in short-term interest rates will
increase or decrease the Companys interest expense associated with short-term borrowings. Increases in interest rates generally will increase the Companys borrowing costs with respect to short-term debt and could adversely affect its
financial condition or results of operations. As of December 31, 2008, the Company had approximately $39.1 million outstanding under a bank financing facility, which provides for a loan which matures on November 1, 2009, and $35.0 million
outstanding under a revolving credit facility.



Long-term debt
borrowings are typically at fixed rates of interest. Therefore, 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. See Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity, Commitments and Capital
Requirements and Note 5 to the accompanying Consolidated Financial Statements.



The Company may need to use a significant portion of its cash flow to repay its short-term debt and long-term debt, which would limit the amount of cash it has available for working capital, capital expenditures and
other general corporate purposes and could negatively affect its liquidity, financial condition and results of operations.



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The Companys and its subsidiaries indebtedness contains covenants that could restrict the
Companys business operations.



See
Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity, Commitments and Capital Requirements and Note 5 to the accompanying Consolidated Financial Statements.



Weather conditions may cause the Companys sales to vary from year to year.



Sales by the Companys distribution utilities
vary from year to year, depending on weather conditions. The Company estimates that approximately 50% of its annual natural gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of natural gas
sold by the Company in any year, particularly during the winter heating season. The Companys electric sales are generally less sensitive to weather than its natural gas sales, but may also be affected by weather conditions in both the winter
and summer seasons. The highest usage of electricity typically occurs in both the summer months due to air conditioning demand and the winter months due to heating-related requirements and shorter daylight hours.



The Companys results of operations reflect this seasonal nature. In
particular, the Company expects that consolidated results of operations in future reporting periods will reflect to a greater degree the seasonal nature of natural gas sales by Northern Utilities, which was acquired by the Company on
December 1, 2008. Accordingly, the Company expects that consolidated results of operations will be positively affected during the first and fourth quarters, and negatively affected during the second and third quarters of future reporting years.



Unitil is a holding company and has no operating income of its own. The
Companys ability to pay dividends on its common stock is dependent on dividends received from its subsidiaries and on factors directly affecting Unitil, the parent corporation. The Company cannot assure you that its current annual dividend
will be paid in the future.



Unitil is a public
utility holding company and it does not have any operating income of its own. Consequently, the Companys ability to pay dividends on its common stock is dependent on dividends and other payments received from its subsidiaries, principally
Unitil Energy, Fitchburg, Northern Utilities and Granite State. The ability of the Companys subsidiaries to pay dividends or make distributions to Unitil 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 the Companys subsidiaries;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the restrictions on the payment of dividends contained in the existing loan agreements of Unitil Energy, Fitchburg, Northern Utilities and Granite State and that
may be contained in future debt agreements of the Companys subsidiaries, if any; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | limitations that may be imposed by New Hampshire, Massachusetts and Maine state regulatory agencies.
| | - |  | ----------------------------------------------------------------------------------------------------



In addition, the Company may incur indebtedness in the future. Before the
Company can pay dividends on its common stock, it has to satisfy its debt obligations, including the bank financing facility that the Company used to partially finance the Acquisitions and the long-term notes issued by Northern Utilities and Granite
State, and comply with any statutory or contractual limitations.



The Companys current annual dividend is $1.38 per share of common stock, payable quarterly. However, the Companys Board of Directors reviews Unitils dividend policy periodically in light of the factors referred to above,
and the Company cannot assure the amount of dividends, if any, that may be paid in the future.



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



Inherent in the Companys electric and natural 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 the Companys operations and substantial losses to Unitil. In accordance with
customary industry practice, the Company maintains 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 the Companys financial position and
results of operations.



The Companys business is subject to
environmental regulation in all jurisdictions in which it operates and its costs of compliance are significant. Any changes in existing environmental regulation and the incurrence of environmental liabilities could negatively affect the
Companys results of operations and financial condition.



The Companys 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 the Companys 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 the Company believes it is 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.



Catastrophic events could have
a material adverse effect on the Companys 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 the Company since they could inhibit its
ability to continue providing electric and/or natural gas distribution services to its customers for an extended period, which is the principal source of the Companys operating income.



The Companys business could be adversely affected if it is unable to retain its
existing customers or attract new customers.



The
success of the Companys business depends, in part, on its ability to maintain and increase its customer base. The Companys failure to maintain or attract customers could have a material adverse effect on its business, financial condition
and operating results.



The Company cannot guarantee 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.



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|Item 2. | Properties
|------- | ----------



As of December 31, 2008, Unitil owned, through its distribution utilities, three utility operation centers, approximately 2,173 pole miles of local
transmission and distribution overhead electric lines and 593 conduit bank miles of underground electric distribution lines, along with 49 electric substations, including three mobile electric substations. Our natural gas operations property
includes two liquid propane gas plants, two liquid natural gas plants and 1,199 miles of underground gas mains. In addition, our real estate subsidiary, Unitil Realty, owns our corporate headquarters building and the 12 acres of land on which it is
located.



Unitil Energy owns and maintains distribution
operations centers in Concord, New Hampshire and Kensington, New Hampshire. Unitil Energys 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 power from the 34.5 kV subtransmission voltage to other primary distribution voltage levels. The electric substations are located on land owned by Unitil Energy or land occupied by
Unitil Energy pursuant to perpetual easements.



Unitil Energy
has a total of approximately 1,613 pole miles of local transmission and distribution overhead electric lines and a total of 413 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 Unitil Energy without objection by the owners. In the case of certain
distribution lines, Unitil Energy 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 Unitil Energy, with certain exceptions, and its franchises are subject to its indenture of mortgage and
deed of trust under which the respective series of first mortgage bonds of Unitil Energy are outstanding.



Fitchburgs electric properties consist principally of 560 pole miles of local transmission and distribution overhead electric lines, 180 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.



Fitchburg owns a liquid propane gas plant and a liquid natural
gas plant, both of which are located on land owned by Fitchburg. Fitchburg also has 264 miles of underground steel, cast iron and plastic gas mains.



Fitchburgs electric substations, with minor exceptions, are located on land owned by Fitchburg or occupied by Fitchburg pursuant to perpetual
easements. Fitchburg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 Fitchburg without objection by the owners. Fitchburg leases its distribution operations center located in Fitchburg, Massachusetts.



Northern Utilities distribution system is comprised of 935 miles of gas mains and 38,262 service pipes. The gas mains are primarily made up of
polyethylene plastic (65%), coated and wrapped cathodically protected steel (22%), cast/wrought iron (8%), and unprotected bare and coated steel (5%).



Northern Utilities New Hampshire division serving 21 communities has 470 miles of distribution gas mains and 19,288 service pipes. Northern
Utilities Maine division serving 23 communities has 465 miles of distribution and 18,974 service pipes. Northern Utilities also owns a liquid propane gas plant on land owned by Northern Utilities.



Granite State is a natural gas transmission pipeline, regulated by the FERC,
operating 87 miles of underground gas transmission pipeline located in Maine and New Hampshire.



16



---

##### Table of Contents

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.



A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in
Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company. The complaint seeks an unspecified amount of damages including the cost of temporary housing and alternative fuel sources, emotional and physical pain
and suffering and property damages allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburgs service territory in December, 2008. As of this date the complaint has not been served on
Fitchburg. The Company believes this complaint is without merit, and will defend itself vigorously.



|Item 4. | Submission of Matters to a Vote of Security Holders
|------- | ---------------------------------------------------



None



17



---

##### Table of Contents

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 listed on the New York Stock Exchange
under the symbol UTL. As of December 31, 2008, there were 1,667 shareholders of record.



Common Stock Data



|                           |  |      |       |      |   |      
|-------------------------- |  | ---- | ----- | ---- | - | -----
|Dividends per Common Share |  | 2008 |       | 2007
|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 
|                           |  |      |       |      |   |      



|                            |  |          |       |         |   |          |  |         |       |  |   |      
|--------------------------- |  | -------- | ----- | ------- | - | -------- |  | ------- | ----- |  | - | -----
|                            |  | 2008     |       | 2007   
|Price Range of Common Stock |  | High/Ask |       | Low/Bid |   | High/Ask |  | Low/Bid
|1st Quarter                 |  | $        | 29.00 |         | $ | 25.75    |  | $       | 27.30 |  | $ | 25.10
|2nd Quarter                 |  | $        | 28.60 |         | $ | 26.41    |  | $       | 28.40 |  | $ | 26.65
|3rd Quarter                 |  | $        | 27.94 |         | $ | 25.46    |  | $       | 31.73 |  | $ | 27.07
|4th Quarter                 |  | $        | 26.60 |         | $ | 19.50    |  | $       | 29.97 |  | $ | 25.75



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 securitiesto be issued upon exerciseof outstanding options,warrants and rights |  | Weighted-averageexercise price ofoutstanding options,warrants
and rights |       | Number of securitiesremaining available forfuture issuance underequity compensationplans (excludingsecurities reflected incolumn
(a))
|Equity compensation plans approved by security holders     |  |                                                                                          |  |                                                                          |       |                                                                                                                                       |       
|Restricted Stock Plan (1)                                  |  |                                                                                         |  |                                                                          | N/A   |                                                                                                                                       | 74,105
|Equity compensation plans not approved by security holders |  |                                                                                          |  |                                                                          |       |                                                                                                                                       |       
|1998 Option Plan (2)                                       |  | 97,200                                                                                   |  | $                                                                        | 27.16 |                                                                                                                                       |      
|                                                           |  |                                                                                          |  |                                                                          |       |                                                                                                                                       |       
|Total                                                      |  | 97,200                                                                                   |  | $                                                                        | 27.16 |                                                                                                                                       | 74,105
|                                                           |  |                                                                                          |  |                                                                          |       |                                                                                                                                       |       

---

NOTES: (also see
Note 4 to the accompanying Consolidated Financial Statements)

|(1) | 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; 32,260 shares of restricted stock were awarded to Plan participants in February 2009.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | 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 (the exchange upon which the Company was then listed) rules, to obtain shareholder approval. Options
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



18



---

##### Table of Contents

| | were granted in March 1999, January 2000, and January 2001. On January 16, 2003, the Board of Directors terminated the 1998 Option Plan upon the
recommendation of the Compensation Committee. In April 2004, the 177,500 remaining registered and ungranted shares in the 1998 Option Plan were deregistered with the Securities and Exchange Commission. The 1998 Option Plan will remain in effect
solely for the purposes of the continued administration of all options currently outstanding under the 1998 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, 2003 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, 2003.



Comparative Five-Year Total Returns



LOGO



---

NOTES:



|(1) | The graph above assumes $100 invested on December 31, 2003, 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



19



---

##### Table of Contents

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, 2008.



Pursuant to the
written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the Exchange Act), adopted by the Company on March 20, 2008, the Company periodically repurchases shares of its Common Stock on the open market
related to Employee Length of Service Awards and the stock portion of the Directors annual retainer. The Company may suspend or terminate its Rule 10b5-1 trading plan at any time, so long as the suspension or termination is made in good faith
and not as part of a plan or scheme to evade the prohibitions of Rule 10b-5 under the Exchange Act, or other applicable securities laws. There is no pool or maximum number of shares related to these purchases; however, the trading plan will
terminate when $82,500 in value of shares have been purchased or on March 20, 2009. As of December 31, 2008, the approximate value of shares that may yet be purchased under the plans or programs was $4,000. Company repurchases are shown in
the table below for the monthly periods noted:



|                   |  |                               |  |                            |       |                                                                              |      
|------------------ |  | ----------------------------- |  | -------------------------- | ----- | ---------------------------------------------------------------------------- | -----
|Period             |  | TotalNumberof SharesPurchased |  | AveragePrice Paidper Share |       | Total Number ofShares Purchased asPart of PubliclyAnnounced Plans orPrograms
|10/1/08  10/31/08 |  |                              |  |                            |      |                                                                              |     
|11/1/08  11/30/08 |  |                              |  |                            |      |                                                                              |     
|12/1/08  12/31/08 |  | 2,754                         |  | $                          | 22.33 |                                                                              | 2,754
|                   |  |                               |  |                            |       |                                                                              |      
|Total              |  | 2,754                         |  | $                          | 22.33 |                                                                              | 2,754
|                   |  |                               |  |                            |       |                                                                              |      



20



---

##### Table of Contents

|Item 6. | Selected Financial Data
|------- | -----------------------



|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|--------------------------------------------------------------------------------------------------- |  | ---- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | - |  | ---- | ------- | - |  | - | ------- | -
|For the Years Ended December 31,                                                                    |  | 2008 |         |   | 2007 |   |         | 2006 |  |   | 2005    |   |  | 2004 |        
|                                                                                                    |  |      |         |   |     
|(all data in millions except shares, % and per share data) (1) Consolidated Statements of Earnings: |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Operating Revenue                                                                                   |  | $    | 288.2   |   |      | $ | 262.9   |      |  | $ | 260.9   |   |  | $    | 232.1   |   |  | $ | 214.1   |  
|                                                                                                    |  |      |         |   |     
|Operating Income                                                                                    |  |      | 20.5    |   |      |   | 18.5    |      |  |   | 15.8    |   |  |      | 15.5    |   |  |   | 15.2    |  
|                                                                                                    |  |      |         |   |     
|Other Non-operating Expense (Income)                                                                |  |      | 0.3     |   |      |   | 0.2     |      |  |   |        |   |  |      | 0.1     |   |  |   | 0.2     |  
|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Income Before Interest Expense, net                                                                 |  |      | 20.2    |   |      |   | 18.3    |      |  |   | 15.8    |   |  |      | 15.4    |   |  |   | 15.0    |  
|                                                                                                    |  |      |         |   |     
|Interest Expense, net                                                                               |  |      | 10.5    |   |      |   | 9.6     |      |  |   | 7.8     |   |  |      | 6.8     |   |  |   | 6.8     |  
|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Net Income                                                                                          |  |      | 9.7     |   |      |   | 8.7     |      |  |   | 8.0     |   |  |      | 8.6     |   |  |   | 8.2     |  
|                                                                                                    |  |      |         |   |     
|Dividends on Preferred Stock                                                                        |  |      | 0.1     |   |      |   | 0.1     |      |  |   | 0.1     |   |  |      | 0.2     |   |  |   | 0.2     |  
|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Earnings Applicable to Common Shareholders                                                          |  | $    | 9.6     |   |      | $ | 8.6     |      |  | $ | 7.9     |   |  | $    | 8.4     |   |  | $ | 8.0     |  
|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Balance Sheet Data:                                                                                 |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Utility Plant (Original Cost)                                                                       |  | $    | 641.4   |   |      | $ | 380.5   |      |  | $ | 353.0   |   |  | $    | 325.0   |   |  | $ | 308.1   |  
|                                                                                                    |  |      |         |   |     
|Total Assets                                                                                        |  | $    | 735.2   |   |      | $ | 474.6   |      |  | $ | 483.4   |   |  | $    | 450.1   |   |  | $ | 457.0   |  
|                                                                                                    |  |      |         |   |     
|Capitalization:                                                                                     |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Common Stock Equity                                                                                 |  | $    | 139.5   |   |      | $ | 100.4   |      |  | $ | 97.8    |   |  | $    | 96.3    |   |  | $ | 94.3    |  
|                                                                                                    |  |      |         |   |     
|Preferred Stock                                                                                     |  |      | 2.0     |   |      |   | 2.1     |      |  |   | 2.1     |   |  |      | 2.3     |   |  |   | 2.3     |  
|                                                                                                    |  |      |         |   |     
|Long-Term Debt, less current portion                                                                |  |      | 249.3   |   |      |   | 159.6   |      |  |   | 140.0   |   |  |      | 125.4   |   |  |   | 110.7   |  
|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Total Capitalization                                                                                |  | $    | 390.8   |   |      | $ | 262.1   |      |  | $ | 239.9   |   |  | $    | 224.0   |   |  | $ | 207.3   |  
|                                                                                                    |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Current Portion of Long-Term Debt                                                                   |  | $    | 0.4     |   |      | $ | 0.4     |      |  | $ | 0.3     |   |  | $    | 0.3     |   |  | $ | 0.3     |  
|                                                                                                    |  |      |         |   |     
|Short-term Debt                                                                                     |  | $    | 74.1    |   |      | $ | 18.8    |      |  | $ | 26.0    |   |  | $    | 18.7    |   |  | $ | 25.7    |  
|                                                                                                    |  |      |         |   |     
|Capital Structure Ratios:                                                                           |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Common Stock Equity                                                                                 |  |      | 36      | % |      |   | 38      | %    |  |   | 41      | % |  |      | 43      | % |  |   | 46      | %
|                                                                                                    |  |      |         |   |     
|Preferred Stock                                                                                     |  |      | 1       | % |      |   | 1       | %    |  |   | 1       | % |  |      | 1       | % |  |   | 1       | %
|                                                                                                    |  |      |         |   |     
|Long-Term Debt                                                                                      |  |      | 63      | % |      |   | 61      | %    |  |   | 58      | % |  |      | 56      | % |  |   | 53      | %
|                                                                                                    |  |      |         |   |     
|Earnings Per Share Data:                                                                            |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Earnings Per Average Share                                                                          |  | $    | 1.65    |   |      | $ | 1.52    |      |  | $ | 1.41    |   |  | $    | 1.51    |   |  | $ | 1.45    |  
|                                                                                                    |  |      |         |   |     
|Common Stock Data:                                                                                  |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Shares of Common Stock  (Average Outstanding, 000s)                                               |  |      | 5,830   |   |      |   | 5,672   |      |  |   | 5,612   |   |  |      | 5,568   |   |  |   | 5,525   |  
|                                                                                                    |  |      |         |   |     
|Dividends Paid Per Share                                                                            |  | $    | 1.38    |   |      | $ | 1.38    |      |  | $ | 1.38    |   |  | $    | 1.38    |   |  | $ | 1.38    |  
|                                                                                                    |  |      |         |   |     
|Book Value Per Share (Year-End)                                                                     |  | $    | 17.90   |   |      | $ | 17.50   |      |  | $ | 17.30   |   |  | $    | 17.21   |   |  | $ | 17.00   |  
|                                                                                                    |  |      |         |   |     
|Electric and Gas Sales:                                                                             |  |      |         |   |      |   |         |      |  |   |         |   |  |      |         |   |  |   |         |  
|                                                                                                    |  |      |         |   |     
|Electric Distribution Sales (Millions kWh)                                                          |  |      | 1,695.9 |   |      |   | 1,743.0 |      |  |   | 1,751.5 |   |  |      | 1,790.4 |   |  |   | 1,742.1 |  
|                                                                                                    |  |      |         |   |     
|Firm Natural Gas Distribution Sales (Millions Therms)                                               |  |      | 47.2    |   |      |   | 28.4    |      |  |   | 26.4    |   |  |      | 24.3    |   |  |   | 23.2    |  

---

|(1) | As a result of the acquisitions of Northern Utilities and Granite State on December 1, 2008, consolidated results for the Company in the current period may not be directly
comparable to prior period results until such time as the acquisitions are fully reflected in both reporting periods.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



21



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##### Table of Contents

|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 is a public utility holding company headquartered in Hampton, New
Hampshire. Unitil is subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005. On December 1, 2008, the Company purchased: (i) all of the outstanding capital stock of Northern Utilities, a natural
gas distribution utility serving customers in New Hampshire and Maine, from Bay State and (ii) all of the outstanding capital stock of Granite State, an interstate gas transmission pipeline company primarily serving the needs of Northern
Utilities, from NiSource.



Unitils principal business is
the local distribution of electricity and natural gas throughout its service territory in the states of New Hampshire, Massachusetts and Maine. Unitil is the parent company of three wholly-owned distribution utilities:



| | i) | Unitil Energy, which provides electric service in southeastern seacoast and state capital regions of New Hampshire;
| | -- | -------------------------------------------------------------------------------------------------------------------



| | ii) | Fitchburg, which provides both electric and natural gas service in the greater Fitchburg area of north central Massachusetts; and
| | --- | ---------------------------------------------------------------------------------------------------------------------------------



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



Unitil Energy, Fitchburg
and Northern Utilities are collectively referred to as the distribution utilities. Together, the distribution utilities serve approximately 100,300 electric customers and 69,300 natural gas customers in their service territory.



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



The
distribution utilities are local pipes and wires operating companies and, combined with Granite State, had an investment in Net Utility Plant of $422.8 million at December 31, 2008. Unitils total revenue was $288.2 million in
2008, which includes revenue to recover the cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, the Companys earnings are not affected by changes in the cost of
purchased electricity and natural gas. Earnings applicable to common shareholders for 2008 were $9.6 million. Substantially all of Unitils earnings are derived from the return on investment in the three distribution utilities and Granite.



Unitil also conducts non-regulated operations principally
through Usource, which is wholly-owned by Unitil Resources. Usource provides energy brokering and consulting services to large commercial and industrial customers in the northeastern United States. Usources total revenues were $3.8 million in
2008. The Companys other subsidiaries include Unitil Service, which provides, at cost, a variety of administrative and professional services to Unitils affiliated companies, and Unitil Realty, which owns and manages Unitils
corporate office building and property located in Hampton, New Hampshire. 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, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical
fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Companys future operations, are forward-looking
statements.



22



---

##### Table of Contents

These statements include declarations regarding the Companys beliefs and current expectations. In
some cases, forward-looking statements can be identified by terminology such as may, will, should, expects, plans, anticipates, believes, estimates,
predicts, potential or continue or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and
conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in Item 1A (Risk Factors) and the following:



| |  |  | The Companys ability to complete the integration of the business, operations and personnel of Northern Utilities and Granite State and to achieve the
estimated potential synergy savings attributable to the Acquisitions;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The Companys ability to retain existing customers and gain new customers;
| | - |  | --------------------------------------------------------------------------



| |  |  | Variations in weather;
| | - |  | ----------------------



| |  |  | Major storms;
| | - |  | -------------



| |  |  | Changes in the regulatory environment;
| | - |  | --------------------------------------



| |  |  | Customers preferences on energy sources;
| | - |  | -----------------------------------------



| |  |  | Interest rate fluctuation and credit market concerns;
| | - |  | -----------------------------------------------------



| |  |  | General economic conditions, including recent distress in the financial markets that has had an adverse impact on the availability of credit and liquidity
resources generally and could jeopardize certain of our counterparty obligations, including those of our insurers and financial institutions;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | Increased competition; and
| | - |  | --------------------------



| |  |  | Customers performance under multi-year energy brokering contracts.
| | - |  | -------------------------------------------------------------------



Many of these risks are beyond the Companys control. Any forward-looking statements speak only as of the date of this
report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge
from time to time, and it is not possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to
differ materially from those contained in any forward-looking statements.



See also Item 1A Risk Factors.



RESULTS OF OPERATIONS



The following
discussion of the Companys financial condition and results of operations 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



2008 Compared to 2007The Companys Earnings
Applicable to Common Shareholders was $9.6 million for 2008, an increase of 12% over 2007 Earnings of $8.6 million. Earnings per common share were $1.65 for 2008, $0.13 per share higher than last year.



Earnings in 2008 reflect the acquisitions, on December 1, 2008, of
Northern Utilities and Granite State, which drove higher gas sales margins.



23



---

##### Table of Contents

The following table presents the significant items (discussed below) contributing to the change in
earnings per share in 2008 as compared to 2007:



2008
Earnings Per Share vs. 2007



|                                     |  |      |  |       |       |  
|------------------------------------ |  | ---- |  | ----- | ----- | -
|                                     |  | 2007 |  | $1.52 |      
|Electric Sales Margin                |  |      |  |       | (0.15 | )
|Gas Sales Margin                     |  |      |  |       | 0.72  |  
|Usource Sales Margin                 |  |      |  |       | 0.01  |  
|Operation and Maintenance Expense    |  |      |  |       | (0.14 | )
|Depreciation, Amortization and Other |  |      |  |       | (0.22 | )
|Interest Expense, Net                |  |      |  |       | (0.09 | )
|                                     |  |      |  |       |       |  
|                                     |  | 2008 |  | $     | 1.65  |  
|                                     |  |      |  |       |       |  



Electric sales margin
decreased $1.4 million in 2008 compared to 2007. The decrease in electric sales margin primarily reflects lower sales volumes, partially offset by higher electric base rates implemented in March of 2008. Total electric kilowatt-hour (kWh) sales
decreased 2.7% in 2008 compared to 2007 driven by lower average usage per customer reflecting milder summer temperatures, a slowing economy and energy conservation.



Natural gas sales margin increased $6.7 million in 2008 compared to 2007. This increase reflects $5.4 million of gas sales
margin from Northern Utilities and Granite State and an additional increase of $1.3 million in gas sales margin reflecting higher rates implemented in November 2007 and higher sales to Commercial and Industrial (C&I) customers. Overall, natural
gas sales increased 66.2% in 2008 compared to 2007. Excluding the contribution of the acquisition of Northern Utilities, total therm sales of natural gas increased 1.1% in 2008 compared to 2007.



Total Operation & Maintenance (O&M) expenses increased $1.3
million, or 5.0%, in 2008 compared to 2007. The acquisitions of Northern Utilities and Granite State accounted for $0.9 million of the increase. In addition, the increase in O&M expenses reflects higher employee and retiree compensation and
benefit expenses of $2.7 million, including increased employee benefits of $1.4 million, driven primarily by higher medical claims in 2008 and higher employee benefits related to staffing increases, and higher salaries and compensation of $1.3
million, due to normal annual increases and staffing additions. Also contributing to the increase in O&M expenses were higher utility operating costs of $0.3 million and higher bad debt expenses of $0.3 million, partially offset by a reduction
of $2.8 million from the proceeds of an insurance settlement and lower professional fees of $0.1 million.



Depreciation, Amortization, Taxes and Other expenses increased $2.2 million in 2008 compared to 2007. The acquisitions of Northern Utilities and Granite
State accounted for $0.9 million of the increase. In addition, the increase in Depreciation, Amortization, Taxes and Other expenses reflects the amortization, in the first quarter of 2008, of $0.7 million of natural gas inventory carrying costs
deferred under a previous regulatory ruling, higher depreciation on normal utility plant additions and higher property and payroll taxes. Partially offsetting these increases were lower amortization costs of $0.8 million.



Interest Expense, Net increased $0.9 million in 2008 compared to 2007. The
acquisitions of Northern Utilities and Granite State accounted for $0.3 million of the increase. The increase associated with the acquisitions is due to $0.5 million of interest expense from the issuance of long-term notes by Northern Utilities and
Granite State in December 2008, partially offset by interest income on regulatory mechanisms. In addition to the increase related to the acquisitions, the remaining $0.6 million increase in Interest Expense, Net reflects higher debt outstanding and
lower interest earned on regulatory assets compared to the prior period.



Usource, our non-regulated energy brokering business, recorded revenues of $3.8 million in 2008, an increase of $0.1 million over 2007. 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.



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##### Table of Contents

On December 11, 2008 a severe ice storm hit the Northeast creating massive extended power outages
for many residents of Massachusetts and New Hampshire, including Unitils electric customers in New Hampshire and the greater Fitchburg, Massachusetts service area. Based on its preliminary assessment, the Company has accrued and deferred
approximately $10 million in costs for the repair and replacement of electric distribution systems damaged during the storm. The amount and timing of the cost recovery of storm restoration expenditures will be determined in future regulatory
proceedings.



In 2008, 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, 2009 meeting, the Unitil Board of Directors declared a quarterly dividend on the Companys common stock of
$0.345 per share.



As a result of the acquisitions of Northern
Utilities and Granite State on December 1, 2008, consolidated results for the Company in the current period may not be directly comparable to prior period results until such time as the acquisitions are fully reflected in both reporting
periods. In particular, the Company expects that consolidated results of operations in future reporting periods will reflect to a greater degree the seasonal nature of natural gas sales by the acquired operating utilities. Accordingly, the Company
expects that as a result of the acquisitions, consolidated results of operations will be positively affected during the first and fourth quarters, and negatively affected during the second and third quarters of future reporting years.



2007 Compared to 2006The Companys Earnings
Applicable to Common Shareholders was $8.6 million for 2007, an increase of 9% over 2006 Earnings of $7.9 million. Earnings per common share were $1.52 for 2007, $0.11 per share higher than 2006. 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.



A more detailed discussion of the Companys 2008 and 2007 results of
operations and a year-to-year comparison of changes in financial position are presented below.



Subsequent Event



On
December 15, 2008, the Company issued and sold 2,000,000 shares of its common stock at a price of $20.00 per share in a registered public offering. As part of this offering, the Company granted the underwriters a 30-day over-allotment option to
purchase additional shares. The underwriters exercised the over-allotment option and purchased an additional 270,000 shares of the Companys common stock in January 2009. The Companys net increases to Common Equity and Cash from the
over-allotment sales were approximately $5.1 million (after payment of the underwriting discount and offering expenses) and were used to repay a portion of the short-term indebtedness used for the Companys acquisitions of Northern Utilities
and Granite State. The Company recorded the issuance of the 270,000 shares, the sale proceeds and the increase in Common Equity in January 2009.



Balance Sheet



The Companys Balance Sheet as of December 31, 2008 reflects the acquisitions of Northern Utilities and Granite State, which closed on
December 1, 2008. Certain prior period balances have been reclassified to conform to current year presentation. Most significant has been the reclassification of certain balance sheet amounts between Regulatory Assets and Accrued Revenue and
between current and noncurrent Energy Supply Contract Obligations.



The Companys Total Assets increased by $260.6 million in 2008 compared to 2007. The increase in Total Assets was driven by: an increase of $173.9 million in the Companys investment in Net Utility Plant, due to the acquisitions
of Northern Utilities and Granite State and to capital expenditures related to Unitil Energys and Fitchburgs electric and gas distribution systems; increases in Cash, Accounts Receivable, Accrued Revenue, Gas Inventory and other current
assets of $77.4 million, primarily due to the acquisitions of Northern Utilities and Granite State; an increase in Other Noncurrent Assets of $9.6 million in 2008 compared to 2007, due to deferred amortizable charges for transition and transaction
costs of $7.6 million associated with the acquisitions of Northern Utilities and Granite State, partially offset by a decrease in all other assets of $0.3 million.



25



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##### Table of Contents

The Companys Total Capitalization increased by $128.7 million in 2008 compared to 2007. This
increase reflects an increase of $39.1 million in Common Equity, primarily due to the issuance of common shares by the Company as part of its financing of the acquisitions of Northern Utilities and Granite State (See Note 4 to the accompanying
Consolidated Financial Statements), and an increase in Long-Term Debt of $89.7 million reflecting the issuance and sale of $80 million of Senior Unsecured Notes by Northern Utilities on December 3, 2008 and the issuance and sale of $10 million
of Senior Unsecured Notes by Granite State on December 15, 2008, both through private placements to institutional investors (See Note 5 to the accompanying Consolidated Financial Statements).



The Companys Total Liabilities increased $131.9 million in 2008
compared to 2007 reflecting an increase in Current Liabilities and Non-Current Liabilities of $124.5 million and $9.7 million respectively, partially offset by a decrease in Deferred Income Taxes of $2.3 million. The increase in Current Liabilities
was driven by an increase in Accounts Payable of $18.7 million, primarily due to the acquisitions of Northern Utilities and Granite State; an increase of $55.3 million in Short-Term Debt, including the $39.1 million remaining on the bank financing
facility which was used to finance a portion of the acquisitions of Northern Utilities and Granite State, and increased borrowings for utility operating purposes; an increase of $22.0 million in Energy Supply Contract Obligations, primarily related
to natural gas payment obligations associated with Northern Utilities; and an increase in Other Current Liabilities of $28.5 million. The increase in Other Current Liabilities includes: accrued storm restoration costs of $9.5 million related to the
December 2008 ice storm experienced in the Companys service territories, $7.7 million of payments due to NiSource, Inc. in connection with the Companys acquisitions of Northern Utilities and Granite State, and $4.5 million of
recoverable, accrued gas supply costs and an increase of $6.8 million in all other items.



The increase in Noncurrent Liabilities was driven by: an increase of $19.2 million in Retirement Benefit Obligations reflecting $4.4 million of retirement plan obligations associated with the acquisitions of Northern
Utilities and Granite State and a net increase of $14.8 million in the actuarial obligations of the Companys other pension and postretirement benefit obligations, primarily due to the poor performance of capital markets during 2008 which
adversely affected the Companys pension plan assets (See Note 10 to the accompanying Consolidated Financial Statements); an increase of $8.3 million in Other Noncurrent Liabilities, reflecting $3.1 million of accrued regulatory compliance
costs for Northern Utilities (See Note 7 to the accompanying Consolidated Financial Statements), $2.6 of accrued integration costs associated with the acquisitions of Northern Utilities and Granite State, $1.1 million of long-term recoverable
accrued gas supply costs and an increase in all other items of $1.5 million; and an increase of $0.3 million in Environmental Obligations. These increases were partially offset by a decrease of $18.1 million in Energy Supply Contract Obligations,
reflecting current year cost recoveries.



Electric Sales, Revenues and
Margin



Kilowatt-hour
SalesUnitils total electric kWh sales decreased 2.7% in 2008 compared to 2007. Electric kWh sales to residential customers and C&I customers decreased 2.2% and 3.0%, respectively, in 2008 compared to 2007. The lower electric
kWh sales in 2008 compared to 2007 were driven by lower average usage per customer reflecting milder summer temperatures, a slowing economy and energy conservation.



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 milder summer temperatures in 2007 compared to 2006, energy conservation by customers in response to higher overall energy prices and a
slowing economy.



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



|                        |  |         |  |         |  |         |  |               |   |  |               |    |  |            |   |  |          |   
|----------------------- |  | ------- |  | ------- |  | ------- |  | ------------- | - |  | ------------- | -- |  | ---------- | - |  | -------- | --
|kWh Sales (millions)    |  |         |  |         |  |         |  |               |   |  |               |    |  |            |   |  |          |   
|                        |  |         |  |         |  |         |  | 2008 vs. 2007 |   |  | 2007 vs. 2006 |   
|                        |  | 2008    |  | 2007    |  | 2006    |  | Change kWh    |   |  | Change %      |    |  | Change kWh |   |  | Change % |   
|Residential             |  | 660.2   |  | 674.8   |  | 672.2   |  | (14.6         | ) |  | (2.2          | %) |  | 2.6        |   |  | 0.4      | % 
|Commercial / Industrial |  | 1,035.7 |  | 1,068.2 |  | 1,079.3 |  | (32.5         | ) |  | (3.0          | %) |  | (11.1      | ) |  | (1.0     | %)
|                        |  |         |  |         |  |         |  |               |   |  |               |    |  |            |   |  |          |   
|Total                   |  | 1,695.9 |  | 1,743.0 |  | 1,751.5 |  | (47.1         | ) |  | (2.7          | %) |  | (8.5       | ) |  | (0.5     | %)
|                        |  |         |  |         |  |         |  |               |   |  |               |    |  |            |   |  |          |   



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##### Table of Contents

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 (millions) |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |  
|                                       |  |      |       |      |   |       |  | 2008 vs. 2007 |       |  | 2007 vs. 2006 |     
|                                       |  | 2008 |       | 2007 |   | 2006  |  | $Change       |       |  | %Change(1)    |      |   | $Change |      |    | %Change(1) |  
|Electric Operating Revenue:            |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   
|Residential                            |  | $    | 114.5 |      | $ | 114.7 |  | $             | 105.9 |  | $             | (0.2 | ) |         | (0.1 | %) |            | $ | 8.8  |   |  | 3.9  | % 
|Commercial / Industrial                |  |      | 113.0 |      |   | 110.3 |  |               | 119.3 |  |               | 2.7  |   |         | 1.2  | %  |            |   | (9.0 | ) |  | (4.0 | %)
|                                       |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   
|Total Electric Operating Revenue       |  | $    | 227.5 |      | $ | 225.0 |  | $             | 225.2 |  | $             | 2.5  |   |         | 1.1  | %  |            | $ | (0.2 | ) |  | (0.1 | %)
|                                       |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   
|Cost of Electric Sales:                |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   
|Purchased Electricity                  |  | $    | 170.1 |      | $ | 165.4 |  | $             | 167.3 |  | $             | 4.7  |   |         | 2.1  | %  |            | $ | (1.9 | ) |  | (0.8 | %)
|Conservation & Load Management         |  |      | 2.6   |      |   | 3.4   |  |               | 3.6   |  |               | (0.8 | ) |         | (0.4 | %) |            |   | (0.2 | ) |  | (0.1 | %)
|                                       |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   
|Total Cost of Electric Sales           |  | $    | 172.7 |      | $ | 168.8 |  | $             | 170.9 |  | $             | 3.9  |   |         | 1.7  | %  |            | $ | (2.1 | ) |  | (0.9 | %)
|                                       |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   
|Electric Sales Margin                  |  | $    | 54.8  |      | $ | 56.2  |  | $             | 54.3  |  | $             | (1.4 | ) |         | (0.6 | %) |            | $ | 1.9  |   |  | 0.8  | % 
|                                       |  |      |       |      |   |       |  |               |       |  |               |      |   |         |      |    |            |   |      |   |  |      |   

---

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



Total Electric Operating Revenues increased by $2.5 million, or 1.1%, in 2008
compared to 2007. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation and Load Management (C&LM) in Operating Expenses. The net increase in Total
Electric Operating Revenues in 2008 reflects higher Purchased Electricity costs of $4.7 million offset by lower C&LM revenues of $0.8 million and lower sales margin of $1.4 million.



Purchased Electricity and C&LM revenues increased $3.9 million, or 1.7%, of Total Electric Operating Revenues in 2008
compared to 2007, primarily reflecting higher electric commodity prices, partially offset by lower sales volumes and lower spending on energy efficiency and conservation programs. 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 decreased $1.4 million in 2008 compared to 2007. The decrease in electric sales margin primarily reflects lower sales volumes,
partially offset by higher electric base rates implemented in March of 2008. Total electric sales decreased 2.7% in 2008 compared to 2007 driven by lower average usage per customer reflecting milder summer temperatures, a slowing economy and energy
conservation.



Total Electric Operating Revenues decreased by
$0.2 million, or 0.1%, in 2007 compared to 2006. 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.



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 milder summer temperatures this year, energy conservation by
customers in response to higher overall energy prices and a slowing economy.



Gas Sales, Revenues and Margin



Therm
SalesOverall, Unitils total therm sales of natural gas increased 66.2% in 2008 compared to 2007. Excluding the contribution of the acquisition of Northern Utilities, total therm sales of natural gas increased 1.1% in 2008
compared to 2007, reflecting a decrease of 2.0% in sales to residential customers offset by an increase of 2.7% in sales to C&I customers. The lower sales to residential customers in 2008 reflects a milder winter heating season earlier this year
and lower average usage by our customers reflecting a slowing economy and energy conservation. The increase in gas sales to C&I customers in 2008 reflects increased usage of natural gas in those customers production operations.



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##### Table of Contents

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 in 2007 compared to 2006 and higher natural gas sales to C&I customers. In 2007, natural gas sales to residential customers increased 4.1% compared to 2006 driven by the colder winter
weather. Sales to C&I customers increased 9.6% compared to 2006, primarily due to a special contract with a large industrial customer.



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



|                        |  |      |  |      |        |      |          |               |  |        |               |          |     |  |     |  
|----------------------- |  | ---- |  | ---- | ------ | ---- | -------- | ------------- |  | ------ | ------------- | -------- | --- |  | --- | -
|Therm Sales (millions)  |  |      | 
|                        |  | 2008 |  | 2007 |        | 2006 |          | 2008 vs. 2007 |  |        | 2007 vs. 2006 |         
|                        |  |      |  |      | Change |      | Change % |               |  | Change |               | Change % |    
|Residential             |  | 13.3 |  | 10.2 |        | 9.8  |          | 3.1           |  | 30.4   | %             |          | 0.4 |  | 4.1 | %
|Commercial / Industrial |  | 33.9 |  | 18.2 |        | 16.6 |          | 15.7          |  | 86.3   | %             |          | 1.6 |  | 9.6 | %
|                        |  |      |  |      |        |      |          |               |  |        |               |          |     |  |     |  
|Total                   |  | 47.2 |  | 28.4 |        | 26.4 |          | 18.8          |  | 66.2   | %             |          | 2.0 |  | 7.6 | %
|                        |  |      |  |      |        |      |          |               |  |        |               |          |     |  |     |  



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) | 
|                                                   |  | 2008 |      | 2007 |         | 2006 |            | 2008 vs. 2007 |      |         | 2007 vs. 2006 |     
|                                                   |  |      |      |      | $Change |      | %Change(1) |               |      | $Change |               |      | %Change(1) |     
|Gas Operating Revenue:                             |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |  
|Residential                                        |  | $    | 27.5 |      | $       | 18.8 |            | $             | 17.2 |         | $             | 8.7  |            | 25.4 | % |  | $ | 1.6  |   |  | 4.8  | % 
|Commercial / Industrial                            |  |      | 29.4 |      |         | 15.4 |            |               | 16.1 |         |               | 14.0 |            | 41.0 | % |  |   | (0.7 | ) |  | (2.1 | %)
|                                                   |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |   |  |      |   
|Total Gas Operating Revenue                        |  | $    | 56.9 |      | $       | 34.2 |            | $             | 33.3 |         | $             | 22.7 |            | 66.4 | % |  | $ | 0.9  |   |  | 2.7  | % 
|                                                   |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |   |  |      |   
|Cost of Gas Sales:                                 |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |  
|Purchased Gas                                      |  | $    | 37.3 |      | $       | 21.3 |            | $             | 22.4 |         | $             | 16.0 |            | 46.8 | % |  | $ | (1.1 | ) |  | (3.3 | %)
|Conservation & Load Management                     |  |      | 0.2  |      |         | 0.2  |            |               | 0.2  |         |               |     |            |     |   |  |   |     |   |  |     |   
|                                                   |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |   |  |      |   
|Total Cost of Gas Sales                            |  | $    | 37.5 |      | $       | 21.5 |            | $             | 22.6 |         | $             | 16.0 |            | 46.8 | % |  | $ | (1.1 | ) |  | (3.3 | %)
|                                                   |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |   |  |      |   
|Gas Sales Margin                                   |  | $    | 19.4 |      | $       | 12.7 |            | $             | 10.7 |         | $             | 6.7  |            | 19.6 | % |  | $ | 2.0  |   |  | 6.0  | % 
|                                                   |  |      |      |      |         |      |            |               |      |         |               |      |            |      |   |  |   |      |   |  |      |   

---

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



Total Gas Operating Revenues increased $22.7 million, or 66.4%, in 2008
compared to 2007, largely reflecting the acquisition of Northern Utilities and Granite State on December 1, 2008 and the 1.1% increase in gas sales, net of the effect of the acquisitions, and higher rates implemented in November 2007. 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 2008 reflects higher Purchased Gas costs of $16.0 million and
higher sales margin of $6.7 million.



Purchased Gas and
C&LM revenues increased $16.0 million, or 46.8%, of Total Gas Operating Revenues in 2008 compared to 2007, largely reflecting the acquisition of Northern Utilities and Granite State on December 1, 2008 as well as higher natural gas
commodity prices. 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 $6.7 million in 2008 compared to 2007. This increase reflects $5.4 million of gas sales margin from Northern Utilities and Granite State and an additional increase of $1.3 million in
gas sales margin reflecting higher rates implemented in November 2007 and higher sales to C&I customers.



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.



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##### Table of Contents

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 November 2007.



Operating RevenueOther



Total Other
Revenue increased $0.1 million in 2008 compared to 2007 and $1.3 million in 2007 compared to 2006. 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) | 
|                         |  | 2008 |     | 2007 |         | 2006 |         | 2008 vs. 2007 |     |         | 2007 vs. 2006 |        
|                         |  |      |     |      | $Change |      | %Change |               |     | $Change |               | %Change | 
|Usource                  |  | $    | 3.8 |      | $       | 3.7  |         | $             | 2.4 |         | $             | 0.1     |  | 2.7 | % |  | $ | 1.3 |  | 54.2 | %
|                         |  |      |     |      |         |      |         |               |     |         |               |         |  |     |   |  |   |     |  |      |  
|Total Other Revenue      |  | $    | 3.8 |      | $       | 3.7  |         | $             | 2.4 |         | $             | 0.1     |  | 2.7 | % |  | $ | 1.3 |  | 54.2 | %
|                         |  |      |     |      |         |      |         |               |     |         |               |         |  |     |   |  |   |     |  |      |  



Operating Expenses



Purchased ElectricityPurchased
Electricity includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity increased $4.7 million, or 2.8%, in 2008 compared to 2007. This increase reflects
higher electric commodity prices partially offset by lower sales volumes. The Company recovers the costs of Purchased Electricity in its rates at cost and therefore changes in these expenses do not affect earnings.



In 2007, Purchased Electricity expenses decreased $1.9 million, or 1.1%,
compared to 2006 due 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.



Purchased GasPurchased Gas includes the cost of natural gas
purchased and manufactured to supply the Companys total gas supply requirements. Purchased Gas increased $16.0 million, or 75.1%, in 2008 compared to 2007. The increase in Purchased Gas largely reflects the acquisition of Northern Utilities
and Granite State on December 1, 2008. In addition to the increase in Purchased Gas due to the acquisitions, Purchased Gas increased $1.5 million, or 7.0%, in 2008 compared to 2007 reflecting higher natural gas commodity prices and higher sales
to C&I customers. 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 2007, Purchased Gas decreased by $1.1 million, or 4.9%, compared to 2006, reflecting 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.



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 expenses increased $1.3 million, or 5.0%, in 2008 compared to 2007. The acquisitions of Northern Utilities and Granite State accounted for $0.9 million of the increase. In addition, the
increase in O&M expenses reflects higher employee and retiree compensation and benefit expenses of $2.7 million, including increased employee benefits of $1.4 million, driven primarily by higher medical claims in 2008 and higher employee
benefits related to staffing increases, and higher salaries and compensation of $1.3 million, due to normal annual increases and staffing additions. Also contributing to the increase in O&M expenses were higher utility operating costs of $0.3
million and higher bad debt expenses of $0.3 million, partially offset by a reduction of $2.8 million from the proceeds of an insurance settlement and lower professional fees of $0.1 million.



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In 2007, total O&M expense increased $0.5 million, or 1.9%, compared to 2006. This increase reflects
higher employee and retiree compensation and benefit expenses of $0.8 million, including higher retiree benefit costs of $0.9 million, driven by higher pension and other postretirement benefit costs, and higher salaries and compensation of $0.8
million due to normal annual increases, partially offset by lower employee benefit costs of $0.9 million, driven by lower medical insurance costs. Also contributing to the increase in O&M expense were 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.



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 by $0.8 million, in 2008 compared to 2007. 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 $0.2 million in 2007 compared to 2006.



Depreciation and AmortizationDepreciation and Amortization expense increased $1.3 million, or 7.3% in 2008 compared to 2007. The acquisitions
of Northern Utilities and Granite State accounted for $0.6 million of the increase. In addition, the increase in Depreciation and Amortization expense reflects the amortization, in the first quarter of 2008, of $0.7 million of natural gas inventory
carrying costs deferred under a previous regulatory ruling, and higher depreciation on normal utility plant additions. Partially offsetting these increases were lower amortization costs of $0.8 million of information systems related costs.



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



Local Property and Other TaxesLocal Property and Other Taxes increased by $0.9 million, or 16.1%, in 2008 compared to 2007. The acquisitions
of Northern Utilities and Granite State accounted for $0.3 million of the increase. In addition, the increase in Local Property and Other Taxes reflects higher local property tax rates on higher levels of utility plant in service and higher payroll
taxes on higher compensation expenses.



In 2007, Local Property
and Other Taxes increased by $0.1 million, or 1.8% 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.



Federal and State Income TaxesFederal and State Income Taxes
decreased by $0.1 million in 2008 compared to 2007 due to a lower effective tax rate year over year due to the recognition of higher permanent book/tax differences, including higher tax credits and prior year tax return true-up adjustments, in the
third quarter of 2008, partially offset by higher pre-tax operating income in 2008 compared to 2007.



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.



Other Non-operating Expenses (Income)



Other Non-operating Expenses (Income) increased by $0.1 million in 2008
compared to 2007. This change reflects an adjustment of $0.1 million in conjunction with the Companys electric base distribution rate increase in Massachusetts which was implemented in March of 2008.



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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.



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 utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated (See Note 5 to the accompanying Consolidated Financial Statements).



Interest Expense, Net increased $0.9 million in 2008 compared to 2007. The acquisitions of Northern Utilities and Granite
State accounted for $0.3 million of the increase. The increase associated with the acquisitions is due to $0.5 million of interest expense from the issuance of long-term notes by Northern Utilities and Granite State in December 2008, partially
offset by interest income on regulatory mechanisms. In addition to the increase related to the acquisitions, the remaining $0.6 million increase in Interest Expense, Net reflects higher debt outstanding and lower interest earned on regulatory assets
compared to the prior period.



On December 15, 2008,
Granite State completed the sale of $10 million of Senior Unsecured Notes, through a private placement to institutional investors. The Notes have a term of 10 years maturity and a coupon rate of 7.15%. The Company used the proceeds from the
long-term Note financing to repay a portion of the bank financing for Unitils acquisition of Granite State.



On December 3, 2008, Northern Utilities completed the sale of $80 million of Senior Unsecured Notes, through a private placement to institutional
investors. The debt financing included $50 million of 30-year notes with a coupon rate of 7.72% and $30 million of 10-year notes with a coupon rate of 6.95%. The Company used the proceeds from the long-term Note financing to repay a portion of the
bank financing for Unitils acquisition of Northern Utilities.



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
distribution utilities. 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.



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. The Company initially supplements internally generated funds through bank borrowings, as needed, under unsecured short-term bank credit facilities. Periodically, the Company replaces portions of its short-term debt with long-term
financings more closely matched to the long-term nature of its utility assets. The Companys utility operations are seasonal in nature and are therefore subject to seasonal fluctuations in cash flows.



The continued availability of various methods of financing, as well as the
choice of a specific form of security, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions; the level of earnings,
cash flows, financial position; and the competitive pricing offered by financing sources.



The Company, along with its subsidiaries, are individually and collectively members of the Unitil Cash Pool (the Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing.



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The Cash Pool allows for an efficient exchange of cash among the Company and its subsidiaries. The interest rates charged to the subsidiaries for borrowing
from the Cash Pool are based on actual interest costs from lenders under the Companys revolving line of credit. At December 31, 2008 and 2007, all of the Companys subsidiaries were in compliance with the regulatory requirements to
participate in the Cash Pool.



On December 1, 2008, the
Company acquired all of the outstanding stock of Northern Utilities and Granite State for $160 million plus an additional working capital adjustment of $49.2 million, including approximately $30.0 million of natural gas storage
inventory. The Company initially financed the Acquisitions and the related costs and expenses using borrowings under a bank financing facility with the Royal Bank of Canada. During December 2008, the Company repaid a portion of the bank financing
facility using the net proceeds from: (i) the offering of the Companys common stock issued on December 15, 2008; (ii) the sale and issuance by Northern Utilities to institutional investors in a private placement of $80 million
aggregate principal amount of long-term unsecured Notes on December 3, 2008; (iii) the sale and issuance by Granite State to institutional investors in a private placement of $10 million aggregate principal amount of long-term
unsecured notes on December 15, 2008; and (iv) the receipt of proceeds from the financing by Northern Utilities of its gas storage inventory contemporaneously with the closing of the Acquisitions. At December 31, 2008, the amount
remaining under the bank financing facility was $39.1 million. The Company expects to repay the outstanding balance under the bank financing facility prior to its maturity date of November 1, 2009 by issuing additional equity or debt. The bank
financing facility contains customary terms and conditions for credit facilities of this type, including financial covenants. As of December 31, 2008, the Company was in compliance with the financial covenants contained in the bank financing
facility.



At December 31, 2008 and December 31,
2007, Unitil had an aggregate of $35.0 million and $18.8 million, respectively, in short-term debt outstanding through bank borrowings (excluding amounts borrowed under the bank financing facility discussed above). On November 26, 2008, Unitil
entered into a $60 million, 364-day revolving credit agreement with Bank of America, N.A., as administrative agent, and a syndicate of bank lenders. This facility replaces certain bilateral credit agreements with Bank of America, N.A., and RBS
Citizens, N.A. The revolving credit agreement contains a covenant restricting the Companys ability to permit long-term debt to exceed 65% of capitalization at the end of each fiscal quarter. The revolving credit agreement also contains
customary terms and conditions for credit facilities of this type, including certain financial covenants. As of December 31, 2008, the Company was in compliance with financial covenants contained in the revolving credit agreement.



On December 15, 2008, the Company issued and sold 2,000,000 shares of
its common stock at a price of $20.00 per share in a registered public offering. As part of this offering, the Company granted the underwriters a 30-day over-allotment option to purchase additional shares. The underwriters exercised the
over-allotment option and purchased an additional 270,000 shares of the Companys common stock in January 2009. The Companys net proceeds were approximately $43 million (after payment of the underwriting discount, but excluding estimated
offering expenses) and were used to repay a portion of the bank financing for the Companys acquisition of Northern Utilities and Granite State, as discussed above, and to repay other short-term indebtedness.



In connection with the Acquisitions, Northern Utilities issued $80.0 million
aggregate principal amount of senior unsecured notes on December 3, 2008, and Granite State issued $10.0 million aggregate principal amount of senior unsecured notes on December 15, 2008. The net proceeds from the Northern Utilities and
Granite State notes were used to recapitalize Northern Utilities and Granite State and to ultimately repay a portion of the Companys short-term bank financing facility used to fund the purchase price of the Acquisitions. The notes consist of:



| | (i) | $30.0 million aggregate principal amount of 6.95% senior unsecured notes of Northern Utilities, which are due in 2018;
| | --- | ----------------------------------------------------------------------------------------------------------------------



| | (ii) | $50.0 million aggregate principal amount of 7.72% senior unsecured notes of Northern Utilities, which are due in 2038; and
| | ---- | --------------------------------------------------------------------------------------------------------------------------



| | (iii) | $10.0 million aggregate principal amount of 7.15% senior unsecured notes of Granite State, which are due in 2018, along with a guarantee from Unitil for the payment
of principal, interest and
| | ----- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | other amounts payable on the Granite State notes. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------



Contractual Obligations



The table below lists the Companys significant contractual obligations
as of December 31, 2008.



|                                                                       |  |       |       |                        |   |           |  |           |       |              |   |      |  |   |      
|---------------------------------------------------------------------- |  | ----- | ----- | ---------------------- | - | --------- |  | --------- | ----- | ------------ | - | ---- |  | - | -----
|                                                                       |  |       |       | Payments Due by Period
|Significant Contractual Obligations (millions) as of December 31, 2008 |  | Total |       | 2009                   |   | 2010-2011 |  | 2012-2013 |       | 2014 &Beyond
|Long-term Debt                                                         |  | $     | 249.7 |                        | $ | 0.4       |  | $         | 0.9   |              | $ | 1.0  |  | $ | 247.4
|Interest on Long-term Debt                                             |  |       | 302.0 |                        |   | 17.9      |  |           | 35.8  |              |   | 35.6 |  |   | 212.7
|Gas Supply Contracts(1)                                                |  |       | 189.2 |                        |   | 72.9      |  |           | 66.6  |              |   | 49.7 |  |   |     
|Power Supply Contract Obligations                                      |  |       | 52.7  |                        |   | 18.1      |  |           | 22.1  |              |   | 9.6  |  |   | 2.9  
|Other                                                                  |  |       | 4.8   |                        |   | 1.3       |  |           | 2.1   |              |   | 0.9  |  |   | 0.5  
|                                                                       |  |       |       |                        |   |           |  |           |       |              |   |      |  |   |      
|Total Contractual Cash Obligations                                     |  | $     | 798.4 |                        | $ | 110.6     |  | $         | 127.5 |              | $ | 96.8 |  | $ | 463.5
|                                                                       |  |       |       |                        |   |           |  |           |       |              |   |      |  |   |      

---

|(1) | Primarily reflects demand charges associated with natural gas transportation contracts.
|--- | ---------------------------------------------------------------------------------------



The Company and its subsidiaries have material energy supply commitments that
are discussed in Note 6 to the accompanying Consolidated Financial Statements. Cash outlays for the purchase of electricity and natural gas to serve 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 of less than a year.



The Company also provides limited guarantees on certain energy and natural gas storage management contracts entered into by the distribution utilities.
The Companys policy is to limit these guarantees to two years or less. As of December 31, 2008 there were $18.0 million of guarantees outstanding and these guarantees extend through October 31, 2009. Of this amount, $15 million is
related to Unitils guarantee of payment for the term of the Northern Utilities gas storage management agreement, discussed below.



On November 1, 2008, Northern Utilities entered into a gas storage management agreement (the Agreement) pursuant to which (i) Northern Utilities
released certain pipeline and storage capacity to an asset manager from November 1, 2008 through April 30, 2009 and (ii) the asset manager financed inventories associated with the released storage capacity from Northern Utilities
contemporaneously with the closing of the Acquisitions. The Agreement requires Northern Utilities to repurchase quantities of natural gas over the course of the 2008/2009 winter heating season at a specified price and any remaining balance of the
gas inventory on April 30, 2009 at the same price initially paid by the asset manager. The Agreement provides for the Company to issue a guarantee of payment of $15 million for the term of the agreement. There is $24.0 million outstanding at
December 31, 2008 related to this Agreement included in Gas Supply Contracts in the Significant Contractual Obligations table above.



The Company also guarantees the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty and Granite State. As of
December 31, 2008, the principal amount outstanding for the 8% Unitil Realty notes was $4.7 million. On December 15, 2008, the Company entered into a guarantee for the payment of principal, interest and other amounts payable on the
$10 million Granite State notes due 2018, as described above. As of December 31, 2008, the principal amount outstanding for the 7.15% Granite State notes was $10 million. This guarantee will terminate if Granite State reorganizes and
merges with and into Northern Utilities.



Benefit Plan Funding



The Company, along with its subsidiaries (other than Northern
Utilities and Granite State), made cash contributions to its Pension Plan in the amount of $2.8 million and $2.8 million in 2008 and 2007, respectively. The Company, along with is subsidiaries (other than Northern Utilities and Granite State),



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contributed $2.7 million and $2.5 million to Voluntary Employee Benefit Trusts (VEBT) in 2008 and 2007, respectively. The Company expects to contribute
approximately $4.0 million and $2.7 million, respectively to fund its Pension and PBOP Plans in 2009. The Company, along with its subsidiaries, expects to continue to make contributions to its Pension Plan and the VEBTs in future years in amounts
consistent with the amounts recovered in the distribution utilities rates for these other postretirement benefit costs. (See Note 10 to the accompanying Consolidated Financial Statements.)



Off-Balance Sheet Arrangements



The Company and its subsidiaries do not currently use, and are not dependent
on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. Unitils subsidiaries conduct a portion of their
operations in leased facilities and also lease some of their vehicles, machinery and office equipment under both capital and operating lease arrangements. (See Note 5 to the accompanying Consolidated Financial Statements.)



Cash Flows



On December 1, 2008, the Company acquired Northern Utilities and Granite State. Cash flow results for 2008 include one
month of activity for the acquired companies, which contributed to the increase in cash flow period over period. Unitils utility operations, taken as a whole, are seasonal in nature and are therefore subject to seasonal fluctuations in cash
flows. The tables below summarize the major sources and uses of cash (in millions) for 2008 and 2007.



|                                      |  |      |      |      |   |     
|------------------------------------- |  | ---- | ---- | ---- | - | ----
|(millions)                            |  | 2008 |      | 2007
|Cash Provided by Operating Activities |  | $    | 47.3 |      | $ | 26.8
|                                      |  |      |      |      |   |     



Cash Provided by
Operating ActivitiesCash Provided by Operating Activities was $47.3 million in 2008, an increase of $20.5 million over the comparable period in 2007. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization
and deferred taxes, was $36.2 million in 2008, a $10.6 million increase over 2007. Working Capital changes in Current Assets and Liabilities required a $0.7 million use of cash in 2008, an increase in sources of cash of $3.9 million compared to
2007. Deferred Restructuring Charges provided $2.6 million and $3.5 million in cash in 2008 and 2007, respectively, reflecting a net decrease of cash flows of $0.9 million for the collection of deferred costs related to utility industry
restructuring. All other items resulted in net sources of cash of $9.2 million and $2.3 million in 2008 and 2007, respectively.



|                                    |  |      |        |   |      |   |       |  
|----------------------------------- |  | ---- | ------ | - | ---- | - | ----- | -
|(millions)                          |  | 2008 |        |   | 2007 |  
|Cash (Used in) Investing Activities |  | $    | (238.2 | ) |      | $ | (32.5 | )
|                                    |  |      |        |   |      |   |       |  



Cash (Used in)
Investing ActivitiesCash used in Investing Activities was $238.2 million for 2008, an increased use of cash of $205.7 million over 2007, of which $209.9 million was for the Companys acquisitions of Northern Utilities and Granite
State on December 1, 2008. The purchase price of the acquisitions was $160 million plus $49.2 million for working capital, including approximately $30 million of natural gas storage inventory. As part of the Acquisitions, the Company acquired
cash of $6.9 million and incurred transition and transaction costs of $7.6 million. Capital expenditures for utility property, plant and equipment were $28.3 million in 2008 compared to $32.5 million in 2007, a decrease of $4.2 million. Capital
expenditures for ongoing electric and gas operations reflect normal utility plant additions, which were $5.0 million lower in 2008 mainly due to the funding in 2007 of the Advanced Metering Infrastructure project.



|                                      |  |      |       |      |   |    
|------------------------------------- |  | ---- | ----- | ---- | - | ---
|(millions)                            |  | 2008 |       | 2007
|Cash Provided by Financing Activities |  | $    | 197.8 |      | $ | 5.7
|                                      |  |      |       |      |   |    



Cash Provided by
Financing ActivitiesCash provided by Financing Activities was $197.8 million in 2008, an increase of $192.1 million compared to 2007. Sources of cash primarily reflect the financing activity related to the Companys acquisitions of
Northern Utilities and Granite State on December 1, 2008. These financing activities (discussed above) included proceeds from the issuance of common stock, the sale



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and issuance of senior unsecured notes and a bank financing facility. In addition, Cash Provided by Financing Activities also reflect the financing of
Northern Utilities gas inventory and the issuance of short-term debt to fund utility plant additions and working capital requirements. Uses of cash for financing activities primarily reflect regular quarterly dividend payments on common and
preferred stock of $8.1 million, and the scheduled repayment of long-term debt of $0.4 million.



FINANCIAL COVENANTS AND RESTRICTIONS



The agreements under which the Companys and its subsidiaries long-term debt 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 and
covenants restricting the ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets. (See Note 5 to
the accompanying Consolidated Financial Statements.)



The
long-term debt and preferred stock of Unitil, Unitil Energy, Fitchburg, Northern Utilities, Granite State and Unitil Realty 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.



The Company financed the
Acquisitions and the related costs and expenses in part using borrowings under a bank financing facility, as described above. As of December 31, 2008, there was $39.1 million outstanding on this bank financing facility. The bank financing
facility contains customary terms and conditions, including, without limitation, covenants restricting the Companys ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity
or (iv) sell, lease or otherwise dispose of all or substantially all assets.



On November 26, 2008, Unitil entered into a $60 million, 364-day revolving credit agreement. The revolving credit agreement contains customary terms and conditions for credit facilities of this type, including
certain financial covenants, including, without limitation, covenants restricting the Companys ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also contains a
covenant restricting the Companys ability to permit long-term debt to exceed 65% of capitalization at the end of each fiscal quarter.



The Company and its subsidiaries are currently in compliance with all such covenants in these debt instruments.



DIVIDENDS



Unitils annualized common dividend was $1.38 per common share in 2008,
2007 and 2006. 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, 2009 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.



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.



A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned Bellerman v. Fitchburg Gas and Electric Light Company.
The complaint seeks an unspecified amount of damages including the cost of temporary housing and alternative



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fuel sources, emotional and physical pain and suffering and property damages allegedly incurred by customers in connection with the loss of electric service
during the ice storm in Fitchburgs service territory in December, 2008. As of this date the complaint has not been served on Fitchburg. The Company believes this complaint is without merit, and will defend itself vigorously.



REGULATORY MATTERS



Overview (Unitil Energy, Fitchburg, and Northern
Utilities)Unitils distribution utilities deliver electricity and/or natural gas to customers in the Companys service territory, at rates established under traditional cost of service regulation. Under this regulatory structure,
Unitil Energy, Fitchburg, and Northern Utilities 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 New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern Utilities, only business
customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy, Fitchburg and Northern Utilities
as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities 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 Fitchburg divested their long-term power supply contracts through the sale of the
entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg 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 two to four years, is $81.9 million as of
December 31, 2008 including $22.1 million in Accrued Revenue on the Companys Consolidated Balance Sheet. Unitils 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 7 for additional information on these filings.



Unitil EnergyOn January 22, 2008, 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. The NHPUC determined that it is appropriate to implement some form of time-based metering standards and ordered that the details,
including cost-benefit analyses, form of rate design, time of implementation and applicable customer classes are to be determined in separate proceedings initiated by the NHPUC. The NHPUC also found that additional review of the energy standards for
net metering, fuel diversity and fossil fuel generation efficiency as proposed in the Energy Policy Act of 2005 is not required due to action of the New Hampshire legislature and the NHPUC in adopting comparable standards.



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. On January 16, 2009, the NHPUC issued its decision in
this matter, concluding that such rate mechanisms should only be implemented on a company-by-company basis in the context of an examination of company specific costs and revenues, service territory, customer mix and rate base investment.



In July 2008, the State of New Hampshire enacted legislation that allows
electric utilities to make investments in distributed energy resources, including energy efficiency and demand reduction technologies, as well as clean cogeneration and renewable generation.



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FitchburgElectric OperationsThe Company received a final order from the MDPU on
February 29, 2008 approving an electric rate increase of $2.1 million, effective March 1, 2008.



Major Ice StormOn December 11 and 12, 2008, a severe ice storm struck the New England region, causing extensive damage to electric
facilities and loss of service to significant numbers of customers of several utilities. An estimated one million electric customers in the region were affected, including all of Unitils 28,000 Massachusetts customers, and approximately half
of its New Hampshire customers. Unitil was able to restore power to one-third of its Massachusetts customers within three days, and 80 percent of its customers by day seven, and the final Massachusetts customers, including those with individual
service problems, were restored by day 13, December 24, 2008. On January 7, 2009, the MDPU opened an investigation into the preparation and response of the Massachusetts electric distribution companies to the December 12, 2008
Winter Storm. Each electric distribution company has been ordered to file a report detailing its response to the storm and outages, and its service restoration efforts with the MDPU by February 23, 2009. Public hearings have been held in each
of the electric distribution utilities service areas in Massachusetts. Based on its preliminary assessment, the Company has accrued and deferred approximately $10 million in costs for the repair and replacement of electric distribution systems
damaged during the storm. The amount and timing of the cost recovery of these storm restoration expenditures will be determined in future regulatory proceedings. The Company does not believe these storm restoration expenditures and the timing of
cost recovery will have a material adverse impact on the Companys financial condition or results of operations. This matter remains pending.



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



FitchburgOtherOn June 22, 2007, the MDPU opened an
inquiry into revenue decoupling for gas and electric distribution utilities, generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utilitys distribution revenues on sales. Revenue decoupling is
intended to remove the disincentive a utility has to promote efforts to reduce energy consumption by its customers or to facilitate installation of distributed generation to displace electricity delivered by the utility. On July 16, 2008, the
MDPU issued an order establishing a comprehensive plan for decoupling to be adopted by gas and electric distribution utilities on a going-forward basis, including company specific rate cases. Lost base revenue recovery associated with incremental
energy efficiency savings will be allowed through 2012 consistent with the MDPUs expectation that, with limited exceptions, distribution companies will be operating under decoupling plans by year-end 2012. Each distribution company was
required to notify the MDPU of when the company expects to file a rate case to implement decoupling. Fitchburg notified the MDPU that it will be prepared to file rate cases for each of its divisions by the third quarter of 2009, based upon a
calendar 2008 test year, along with a comprehensive decoupling proposal and associated base rate adjustment mechanism. This matter remains pending before the MDPU.



On July 2, 2008, the Governor of Massachusetts signed into law The Green Communities Act (the GC
Act), an energy policy legislation designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act includes provisions that:



| |  |  | Require electric and natural gas distribution companies to file three-year energy efficiency investment plans designed to implement all available cost-effective
energy efficiency and demand reduction resources; the plans are to include fully reconciling funding mechanisms;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Require utility distribution companies to undertake various Green programs, including the solicitation of bids for long-term renewable energy procurement contracts
for which utilities would be allowed remuneration on certain contract commitments;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | Establishes expanded authority for the MDPU to investigate mergers involving holding companies of public utilities;
| | - |  | -------------------------------------------------------------------------------------------------------------------



| |  |  | Increase the Renewable Portfolio Standard by 1% annually, requiring that by the year 2020 utilities and other electricity suppliers obtain 15% of the power they
sell from renewable resources;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Authorize electric distribution companies to construct, own, and operate up to 50 megawatts of solar generating capacity; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | Modify the service quality performance penalty provision.
| | - |  | ---------------------------------------------------------



The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs.



Northern Utilities Acquisition: On December 1, 2008 Unitil
completed the purchase of Northern Utilities from Bay State and Granite State from NiSource. Joint petitions on behalf of Unitil and Northern Utilities requesting approval of the purchase of Northern Utilities by Unitil were filed with the NHPUC and
the MPUC on March 31, 2008. State regulatory approvals of Unitils purchase of Granite State were not required. In August 2008, unopposed settlement agreements resolving all outstanding issues and recommending approval of the acquisition
were filed with the MPUC and NHPUC on behalf of Unitil, Northern Utilities and the active parties to the respective Maine and New Hampshire proceedings. The NHPUC approved the transaction on October 10, 2008. The MPUC issued an order approving
the transaction on November 5, 2008.



Although separately
negotiated and filed with the MPUC and the NHPUC, the settlement agreements reflect several common topics (including regulatory authorizations, matters affecting rates, customer service provisions, service quality, gas safety and reliability,
agreements regarding Granite State and reporting requirements) as follows:



The settlement agreements include the following authorizations and approvals:



| |  |  | approval of Unitils acquisition of Northern Utilities;
| | - |  | -------------------------------------------------------



| |  |  | approval of the amended Unitil Service Agreement adding Northern Utilities as a party;
| | - |  | --------------------------------------------------------------------------------------



| |  |  | approval of the amended Unitil Cash Pooling Agreement adding Northern Utilities as a party; and
| | - |  | -----------------------------------------------------------------------------------------------



| |  |  | approval of Northern Utilities accounting deferral and 10-year amortization of transaction costs and transition costs resulting from the Companys
acquisition of Northern Utilities and the Companys agreement not to seek recovery of these costs, or the transaction or transition costs of any other utility subsidiary, in rates.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements include the following commitments related to rates:



| |  |  | agreement that synergy savings resulting from our acquisition of Northern Utilities will be retained by the Company until the next base rate change and then will
flow to customers;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement not to request a base rate change for Northern Utilities before November 1, 2010 unless (i) Northern Utilities projected annual revenues
are more than 8% below the level of total 2007 distribution revenues or (ii) the MPUC or NHPUC, as applicable, approves a plan to subject Granite States rates to state regulation;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to allow Northern Utilities to recover prudently incurred integration costs for capitalized expenditures to build or upgrade systems or facilities
required to independently operate Northern Utilities;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement not to seek recovery in Northern Utilities rates of any acquisition premium resulting from Unitils acquisition of Northern Utilities and that
any acquisition adjustment (positive or negative) shall be accounted for below the line for ratemaking purposes over a 10-year period;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to hold Northern Utilities customers harmless for the elimination of historical accumulated deferred income tax (ADIT) liabilities resulting from
its Internal Revenue Service Section 338(h)(10) election;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | agreement to use an imputed weighted cost of debt for ratemaking purposes until Northern Utilities existing debt instruments would have matured; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement not to change Northern Utilities existing depreciation rates for its Maine division until approved in the next general rate case.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements also contain the
following commitments related to customers:



| |  |  | agreement to implement a Low Income Program for Northern Utilities Maine division, to provide additional customer payment options (including credit or debit
cards and by internet and telephone) for Maine customers and to continue low income programs in Northern Utilities New Hampshire division;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to review with the parties to the settlements communications that we develop to inform Northern Utilities customers about our acquisition of
Northern Utilities and to keep them apprised of the transition; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | with respect to Maine, agreement to conduct a study of alternatives for the sale, lease, or use of the unused Portland manufactured gas site property that would
best serve ratepayers interests.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The
settlement agreements contain the following commitments related to service quality, gas safety and reliability:



| |  |  | agreement to improve and adhere to Northern Utilities existing service quality plans in each jurisdiction; and
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | agreement to provide notifications and safety reports based on several service quality and gas safety metrics, as well as implementing gas operations programs and
practices.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements contain
the following commitments related to Granite State:



| |  |  | agreement to work collaboratively with the parties to the settlements to design and to conduct a comprehensive study of the issues and costs for modification of the
physical, operational, regulatory, and corporate structure necessary for state regulation of Granite State and to provide a report within one year of the closing; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | authorization for Northern Utilities to execute a firm service contract with Granite State for 100,000 Dekatherms (Dth) of capacity at Granite States current
recourse rate of $1.6666/ Dth for the period November 1, 2008 through October 31, 2010.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements contain the following commitments regarding affiliate books and records and transaction reporting:



| |  |  | agreement to provide timely access to the books and records of any of Northern Utilities affiliates at the discretion of the MPUC or the NHPUC, as applicable;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to file reports on our transition progress, business integration, costs, the Transition Services Agreement and costs while our acquisition of Northern
Utilities was pending; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to notify the MPUC and the NHPUC of any substantial changes in the financing terms.
| | - |  | ---------------------------------------------------------------------------------------------



In Massachusetts, the GC Act expanded the authority of the MDPU to review
holding company mergers and sales of subsidiaries to determine how such transactions would affect the holding companies Massachusetts utility operating companies and their ratepayers. Unitil and Bay State filed a joint Petition with the
MDPU on August 13 seeking an advisory determination that the recent statutory amendment was inapplicable to the proposed sale, or, alternatively, sought approval of the proposed sale. The MDPU declined to issue the advisory ruling, and
determined that it had the requisite authority to review the transaction. After investigation and hearing, the MDPU issued its approval of the transaction on November 18, 2008.



Northern UtilitiesNotices of Probable ViolationBeginning in October 2007, the MPUC initiated formal
investigations into a number of Notices of Probable Violation (NOPVs) alleging that Northern



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Utilities had violated various provisions of the federal pipeline safety regulations, as adopted by the MPUC. Northern Utilities, the MPUC Staff and Unitil
filed a comprehensive settlement (Settlement), which was approved by the MPUC on November 21, 2008, resolving these matters. Under the Settlement, Northern Utilities will incur total expenditures of approximately $3.8 million for certain safety
related improvements for which no rate recovery will be allowed and obligations to be undertaken for Northern Utilities distribution system to ensure compliance with the relevant state and federal gas safety laws. These compliance costs were
accrued by Northern Utilities prior to the acquisition date and the remaining amount on the Companys balance sheet at December 31, 2008 was $3.1 million.



Northern UtilitiesNH 2007/2008 Winter Cost of GasOn October 31, 2007, the NHPUC issued Order
No. 24,798 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities New Hampshire division. In that order, the NHPUC noted that Northern Utilities had identified an unusually high level of lost and unaccounted for gas
(UAFG), and ordered Northern Utilities to file a detailed report concerning its investigation of this matter. Through its investigation, Northern Utilities determined that the unaccounted for gas affected both its New Hampshire and Maine divisions,
and that the cause appeared to be incorrect metering at the Maritimes & Northeast (M&NE) / Portland Natural Gas Transmission Systems (PNGTS) Newington Gate Station caused by an erroneous meter module change. The metering equipment
was operated and maintained by a third party, Spectra Energy, the parent company of M&NE. PNGTS and M&NE share joint ownership of the section of the pipeline connected to Granite State at the Newington Gate Station. The error caused Granite
State to be billed for 758,702 Dth of natural gas, with Granite State then billing Northern Utilities for an equivalent amount, although the volumes of gas were not actually consumed. The meter error was corrected and Northern Utilities, Granite
State, Spectra Energy and PNGTS reached an agreement whereby PNGTS will provide to Northern Utilities, through Granite State, gas volumes equal to the misread amounts to correct for the error, over a period of approximately 18 months. Both the NHPUC
and the MPUC have approved this arrangement, as well as Northern Utilities methodology for allocating the gas received to its Maine and New Hampshire divisions based upon the actual gas use over the period the meters were misread. As of
December 31, 2008, Northern Utilities has recorded approximately $4.0 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.



See Note 7 to the accompanying Consolidated Financial Statements for
additional information on Regulatory Matters.



ENVIRONMENTAL MATTERS



The Companys past and present operations include
activities that are generally subject to extensive and complex federal and state environmental laws and regulations. The Company believes it is in compliance with applicable environmental and safety laws and regulations, and the Company believes
that as of December 31, 2008, there were no material losses reasonably likely to be incurred in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is
possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.



Fitchburgs Manufactured Gas Plant SiteFitchburg continues to work with environmental regulatory agencies
to identify and assess environmental issues at the former MGP site at Sawyer Passway, located in Fitchburg, Massachusetts. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department
of Environmental Protection, which allows Fitchburg to work towards temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed and
completed.



Fitchburg 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, Fitchburg is authorized to amortize and recover environmental
response costs from gas customers over succeeding seven-year periods, without carrying costs. In addition, Fitchburg 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 Fitchburg receives from insurance or third



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parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between Fitchburg and its gas
customers.



Northern Utilities Manufactured Gas Plant
SitesNorthern Utilities has an extensive program to identify, investigate and remediate former MGP sites that were operated from the mid 1800s through the mid 1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth,
Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in
both New Hampshire and Maine to address environmental concerns with these sites.



The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization
period. Northern Utilities believes material future costs will be recovered. For Northern Utilities Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.



See Note 7 to the accompanying Consolidated Financial Statements for
additional information on Environmental Matters.



EMPLOYEES AND EMPLOYEE
RELATIONS



As of December 31, 2008, the Company
and its subsidiaries had 406 employees. The Company considers its relationship with employees to be good and has not experienced any major labor disruptions.



As of December 31, 2008, 144 of the Companys employees were represented by labor unions. These employees are covered by collective bargaining
agreements. Two of these agreements expire on March 31, 2009, two agreements expire on May 31, 2010, and one agreement expires on June 5, 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.



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 three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation
by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the NHPUC and Northern Utilities is regulated by the MPUC and NHPUC. Granite State, the Companys natural gas transmission pipeline, is regulated by the FERC.
Accordingly, the Company uses the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets
and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.



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



The Companys principal regulatory assets and liabilities are detailed on the Companys Consolidated Balance Sheet and a summary of the
Companys Regulatory Assets is provided in Note 1 thereto. The Company receives a return on investment on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of
costs, which can have a material impact on the Companys consolidated financial statements.



The Company believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets,
including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate
recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet
the criteria for application of 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 based upon
the Companys experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed which takes into account an assumption about the cash
recovery of delinquent receivables. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Companys distribution utilities are authorized by regulators to
recover the costs of their energy commodity portion of bad debts through rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance
payments from governmental authorities and the level of customers enrolling in payment plans with the Company. It has been the Companys experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful
Accounts have proven to be reasonably accurate.



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



In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, (SFAS No. 158), an amendment of SFAS No. 87,
Employers Accounting for Pensions, SFAS No. 88, Employers Accounting for Settlements and Curtailments of



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Defined Benefit Pension Plans and for Termination Benefits, SFAS No. 106, Employers Accounting for Postretirement Benefits other than
Pensions and SFAS No. 132(R), Employers Disclosures about Pensions and Other Postretirement Benefits. SFAS No. 158 requires companies to record on their balance sheets as an asset or liability the overfunded or
underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas
rates.



The Companys reported costs of providing
retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns
on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Companys RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care
cost trends. Changes made to the provisions of these plans may also affect current and future costs.



The Companys RBO may also be significantly affected by changes in key actuarial assumptions, including, anticipated rates of return on plan assets
and the discount rates used in determining the Companys RBO. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact
on the Companys financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on a market average of long-term bonds that receive one of the two highest ratings given by
a recognized rating agency. For the years ended December 31, 2008 and 2007, 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 for the Pension Plan.
For the years ended December 31, 2008 and 2007, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $675,000 and $690,000, respectively.
Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $531,000 and $539,000, respectively. (See Note 10 to the
accompanying Consolidated Financial Statements).



Income
TaxesProvisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. This process involves estimating the Companys current tax
liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax
assets and liabilities, which are included in the Companys consolidated balance sheets. 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, 2008, 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.



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For further information regarding these types of activities, see Note 1, Summary of Significant
Accounting Policies, Note 9, Income Taxes, Note 6, Energy Supply, Note 10, Benefit Plans, and Note 7, 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 was $25 million for the period of one year,
a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rate on short-term borrowings was 3.8%, 5.6%, and 5.5% during 2008, 2007, and 2006, respectively.



MARKET RISK



Although Unitils three distribution utilities are subject to commodity price risk as part of their traditional
operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after
consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.



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|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 of Unitil Corporation and subsidiaries (the Company) as of December 31, 2008 and 2007,
and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the years ended December 31, 2008, 2007 and 2006. We also have audited Unitil Corporation and subsidiaries internal control
over financial reporting as of December 31, 2008, 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 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.



As
indicated in the accompanying Managements Report on Internal Control Over Financial Reporting, managements assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal
controls of Northern Utilities, Inc. and Granite State Gas Transmission, Inc., businesses acquired by the Company during the year ended December 31, 2008, which are included in the 2008 consolidated financial statements of the Company and
constituted approximately $273.7 million and $161.2 million of total and net assets, respectively, as of December 31, 2008 and approximately $22.2 million and $1.9 million of revenues and net income respectively, for the year ended
December 31, 2008. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Northern Utilities, Inc. and Granite State Gas Transmission, Inc.



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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the
years in the three-year period ended December 31, 2008 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, 2008, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).



Vitale, Caturano & Company,
P.C.



Boston, Massachusetts

February 13, 2009



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CONSOLIDATED STATEMENTS OF EARNINGS



(Millions, except common shares and per share data)



|                                                  |  |      |       |      |   |       |  |   |      
|------------------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|Year Ended December 31,                           |  | 2008 |       | 2007 |   | 2006 
|                                                  |  |      |      
|Operating Revenues:                               |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Electric                                          |  | $    | 227.5 |      | $ | 225.0 |  | $ | 225.2
|                                                  |  |      |      
|Gas                                               |  |      | 56.9  |      |   | 34.2  |  |   | 33.3 
|                                                  |  |      |      
|Other                                             |  |      | 3.8   |      |   | 3.7   |  |   | 2.4  
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Total Operating Revenues                          |  |      | 288.2 |      |   | 262.9 |  |   | 260.9
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Operating Expenses:                               |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Purchased Electricity                             |  |      | 170.1 |      |   | 165.4 |  |   | 167.3
|                                                  |  |      |      
|Purchased Gas                                     |  |      | 37.3  |      |   | 21.3  |  |   | 22.4 
|                                                  |  |      |      
|Operation and Maintenance                         |  |      | 27.5  |      |   | 26.2  |  |   | 25.7 
|                                                  |  |      |      
|Conservation & Load Management                    |  |      | 2.8   |      |   | 3.6   |  |   | 3.8  
|                                                  |  |      |      
|Depreciation and Amortization                     |  |      | 19.1  |      |   | 17.8  |  |   | 16.1 
|                                                  |  |      |      
|Provisions for Taxes:                             |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Local Property and Other                          |  |      | 6.5   |      |   | 5.6   |  |   | 5.5  
|                                                  |  |      |      
|Federal and State Income                          |  |      | 4.4   |      |   | 4.5   |  |   | 4.3  
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Total Operating Expenses                          |  |      | 267.7 |      |   | 244.4 |  |   | 245.1
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Operating Income                                  |  |      | 20.5  |      |   | 18.5  |  |   | 15.8 
|                                                  |  |      |      
|Other Non-Operating Expenses                      |  |      | 0.3   |      |   | 0.2   |  |   |     
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Income Before Interest Expense                    |  |      | 20.2  |      |   | 18.3  |  |   | 15.8 
|                                                  |  |      |      
|Interest Expense, net                             |  |      | 10.5  |      |   | 9.6   |  |   | 7.8  
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Net Income                                        |  |      | 9.7   |      |   | 8.7   |  |   | 8.0  
|                                                  |  |      |      
|Less Dividends on Preferred Stock                 |  |      | 0.1   |      |   | 0.1   |  |   | 0.1  
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Earnings Applicable to Common Shareholders        |  | $    | 9.6   |      | $ | 8.6   |  | $ | 7.9  
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Average Common Shares Outstanding (000s)Basic   |  |      | 5,830 |      |   | 5,659 |  |   | 5,597
|                                                  |  |      |      
|Average Common Shares Outstanding (000s)Diluted |  |      | 5,830 |      |   | 5,672 |  |   | 5,612
|                                                  |  |      |      
|                                                  |  |      |       |      |   |       |  |   |      
|                                                  |  |      |      
|Earnings per Common ShareBasic and Diluted       |  | $    | 1.65  |      | $ | 1.52  |  | $ | 1.41 
|                                                  |  |      |       |      |   |       |  |   |      



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



47





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CONSOLIDATED BALANCE SHEETS(Millions)



ASSETS



|                                                                             |  |      |       |      |   |      
|---------------------------------------------------------------------------- |  | ---- | ----- | ---- | - | -----
|December 31,                                                                 |  | 2008 |       | 2007
|                                                                             |  |     
|Utility Plant:                                                               |  |      |       |      |   |      
|                                                                             |  |     
|Electric                                                                     |  | $    | 289.0 |      | $ | 266.2
|                                                                             |  |     
|Gas                                                                          |  |      | 304.2 |      |   | 67.8 
|                                                                             |  |     
|Common                                                                       |  |      | 30.5  |      |   | 26.2 
|                                                                             |  |     
|Construction Work in Progress                                                |  |      | 17.7  |      |   | 20.3 
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|Utility Plant                                                                |  |      | 641.4 |      |   | 380.5
|                                                                             |  |     
|Less: Accumulated Depreciation                                               |  |      | 218.6 |      |   | 131.6
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|Net Utility Plant                                                            |  |      | 422.8 |      |   | 248.9
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|Current Assets:                                                              |  |      |       |      |   |      
|                                                                             |  |     
|Cash                                                                         |  |      | 11.5  |      |   | 4.6  
|                                                                             |  |     
|Accounts Receivable(Net of Allowance for Doubtful Accounts of $3.0and $1.3) |  |      | 39.7  |      |   | 24.9 
|                                                                             |  |     
|Accrued Revenue                                                              |  |      | 58.9  |      |   | 36.7 
|                                                                             |  |     
|Gas Inventory                                                                |  |      | 31.6  |      |   | 2.7  
|                                                                             |  |     
|Material and Supplies                                                        |  |      | 2.7   |      |   | 1.8  
|                                                                             |  |     
|Prepayments and Other                                                        |  |      | 5.9   |      |   | 2.2  
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|Total Current Assets                                                         |  |      | 150.3 |      |   | 72.9 
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|Noncurrent Assets:                                                           |  |      |       |      |   |      
|                                                                             |  |     
|Regulatory Assets                                                            |  |      | 146.2 |      |   | 146.5
|                                                                             |  |     
|Other Noncurrent Assets                                                      |  |      | 15.9  |      |   | 6.3  
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|Total Noncurrent Assets                                                      |  |      | 162.1 |      |   | 152.8
|                                                                             |  |     
|                                                                             |  |      |       |      |   |      
|                                                                             |  |     
|TOTAL                                                                        |  | $    | 735.2 |      | $ | 474.6
|                                                                             |  |      |       |      |   |      



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



48



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CONSOLIDATED BALANCE SHEETS (cont.)(Millions)



CAPITALIZATION AND LIABILITIES



|                                     |  |      |       |      |   |      
|------------------------------------ |  | ---- | ----- | ---- | - | -----
|December 31,                         |  | 2008 |       | 2007
|                                     |  |     
|Capitalization:                      |  |      |       |      |   |      
|                                     |  |     
|Common Stock Equity                  |  | $    | 139.5 |      | $ | 100.4
|                                     |  |     
|Preferred Stock                      |  |      | 2.0   |      |   | 2.1  
|                                     |  |     
|Long-Term Debt, Less Current Portion |  |      | 249.3 |      |   | 159.6
|                                     |  |      |       |      |   |      
|                                     |  |     
|Total Capitalization                 |  |      | 390.8 |      |   | 262.1
|                                     |  |      |       |      |   |      
|                                     |  |     
|Current Liabilities:                 |  |      |       |      |   |      
|                                     |  |     
|Long-Term Debt, Current Portion      |  |      | 0.4   |      |   | 0.4  
|                                     |  |     
|Accounts Payable                     |  |      | 36.3  |      |   | 17.6 
|                                     |  |     
|Short-Term Debt                      |  |      | 74.1  |      |   | 18.8 
|                                     |  |     
|Energy Supply Contract Obligations   |  |      | 42.0  |      |   | 20.0 
|                                     |  |     
|Other Current Liabilities            |  |      | 35.8  |      |   | 7.3  
|                                     |  |      |       |      |   |      
|                                     |  |     
|Total Current Liabilities            |  |      | 188.6 |      |   | 64.1 
|                                     |  |      |       |      |   |      
|                                     |  |     
|Deferred Income Taxes                |  |      | 31.1  |      |   | 33.4 
|                                     |  |      |       |      |   |      
|                                     |  |     
|Noncurrent Liabilities:              |  |      |       |      |   |      
|                                     |  |     
|Energy Supply Contract Obligations   |  |      | 34.6  |      |   | 52.7 
|                                     |  |     
|Retirement Benefit Obligations       |  |      | 67.4  |      |   | 48.2 
|                                     |  |     
|Environmental Obligations            |  |      | 12.3  |      |   | 12.0 
|                                     |  |     
|Other Noncurrent Liabilities         |  |      | 10.4  |      |   | 2.1  
|                                     |  |      |       |      |   |      
|                                     |  |     
|Total Noncurrent Liabilities         |  |      | 124.7 |      |   | 115.0
|                                     |  |      |       |      |   |      
|                                     |  |     
|TOTAL                                |  | $    | 735.2 |      | $ | 474.6
|                                     |  |      |       |      |   |      



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



49





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CONSOLIDATED STATEMENTS OF CASH FLOWS(Millions)



|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|----------------------------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ----- | ---- |  | - | ----- | -
|Year Ended December 31,                                                       |  | 2008 |        |   | 2007 |   |       | 2006 | 
|                                                                              |  |      |       
|Operating Activities:                                                         |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Net Income                                                                    |  | $    | 9.7    |   |      | $ | 8.7   |      |  | $ | 8.0   |  
|                                                                              |  |      |       
|Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: |  |      |        |   |      |   |       |      |  |   |       |  
|Depreciation and Amortization                                                 |  |      | 19.1   |   |      |   | 17.8  |      |  |   | 16.1  |  
|Deferred Taxes Provision                                                      |  |      | 7.4    |   |      |   | (0.9  | )    |  |   | 0.5   |  
|                                                                              |  |      |       
|Changes in Current Assets and Liabilities:                                    |  |      |        |   |      |   |       |      |  |   |       |  
|Accounts Receivable                                                           |  |      | (6.4   | ) |      |   | (2.4  | )    |  |   | 1.1   |  
|Accrued Revenue                                                               |  |      | (10.3  | ) |      |   | 1.1   |      |  |   | (4.9  | )
|Accounts Payable                                                              |  |      | 11.4   |   |      |   | (2.2  | )    |  |   | (0.8  | )
|All Other Current Assets and Liabilities                                      |  |      | 4.6    |   |      |   | (1.1  | )    |  |   | 0.8   |  
|                                                                              |  |      |       
|Deferred Restructuring Charges                                                |  |      | 2.6    |   |      |   | 3.5   |      |  |   | (2.0  | )
|                                                                              |  |      |       
|Other, net                                                                    |  |      | 9.2    |   |      |   | 2.3   |      |  |   | 1.6   |  
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|Cash Provided by Operating Activities                                         |  |      | 47.3   |   |      |   | 26.8  |      |  |   | 20.4  |  
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Investing Activities:                                                         |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Property, Plant and Equipment Additions                                       |  |      | (28.3  | ) |      |   | (32.5 | )    |  |   | (33.6 | )
|                                                                              |  |      |       
|Acquisitions, net (See Note 3)                                                |  |      | (209.9 | ) |      |   |      |      |  |   |      |  
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Cash (Used In) Investing Activities                                           |  |      | (238.2 | ) |      |   | (32.5 | )    |  |   | (33.6 | )
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Financing Activities:                                                         |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Proceeds from (Repayment of) Short-Term Debt                                  |  |      | 55.3   |   |      |   | (7.2  | )    |  |   | 7.3   |  
|                                                                              |  |      |       
|Proceeds from Issuance of Long-Term Debt                                      |  |      | 90.0   |   |      |   | 20.0  |      |  |   | 15.0  |  
|                                                                              |  |      |       
|Repayment of Long-Term Debt                                                   |  |      | (0.4   | ) |      |   | (0.3  | )    |  |   | (0.3  | )
|                                                                              |  |      |       
|Net Increase in Gas Inventory Financing                                       |  |      | 24.0   |   |      |   |      |      |  |   |      |  
|                                                                              |  |      |       
|Dividends Paid                                                                |  |      | (8.1   | ) |      |   | (7.9  | )    |  |   | (7.9  | )
|                                                                              |  |      |       
|Proceeds from Issuance of Common Stock                                        |  |      | 37.4   |   |      |   | 1.5   |      |  |   | 1.0   |  
|                                                                              |  |      |       
|Other, net                                                                    |  |      | (0.4   | ) |      |   | (0.4  | )    |  |   | (0.5  | )
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Cash Provided by Financing Activities                                         |  |      | 197.8  |   |      |   | 5.7   |      |  |   | 14.6  |  
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Net Increase in Cash                                                          |  |      | 6.9    |   |      |   |      |      |  |   | 1.4   |  
|                                                                              |  |      |       
|Cash at Beginning of Year                                                     |  |      | 4.6    |   |      |   | 4.6   |      |  |   | 3.2   |  
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Cash at End of Year                                                           |  | $    | 11.5   |   |      | $ | 4.6   |      |  | $ | 4.6   |  
|                                                                              |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Supplemental Information:                                                     |  |      |        |   |      |   |       |      |  |   |       |  
|                                                                              |  |      |       
|Interest Paid                                                                 |  | $    | 12.5   |   |      | $ | 12.2  |      |  | $ | 10.7  |  
|                                                                              |  |      |       
|Income Taxes Paid (Refunded)                                                  |  | $    | (0.5   | ) |      | $ | 5.3   |      |  | $ | 3.1   |  





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



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CONSOLIDATED STATEMENTS OF

CHANGES IN COMMON STOCK EQUITY



(Millions)



|                                                 |  |              |       |                  |   |      |       |  |   |       |  
|------------------------------------------------ |  | ------------ | ----- | ---------------- | - | ---- | ----- |  | - | ----- | -
|                                                 |  | CommonEquity |       | RetainedEarnings |   |      | Total | 
|                                                 |  |              |      
|Balance at January 1, 2006                       |  | $            | 62.2  |                  | $ | 34.1 |       |  | $ | 96.3  |  
|                                                 |  |              |      
|Net Income for 2006                              |  |              |       |                  |   | 8.0  |       |  |   | 8.0   |  
|                                                 |  |              |      
|Dividends                                        |  |              |       |                  |   | (7.8 | )     |  |   | (7.8  | )
|                                                 |  |              |      
|Shares Issued Under Stock Plans                  |  |              | 0.3   |                  |   |      |       |  |   | 0.3   |  
|                                                 |  |              |      
|Issuance of 40,365 Common Shares                 |  |              | 1.0   |                  |   |      |       |  |   | 1.0   |  
|                                                 |  |              |      
|                                                 |  |              |       |                  |   |      |       |  |   |       |  
|                                                 |  |              |      
|Balance at December 31, 2006                     |  |              | 63.5  |                  |   | 34.3 |       |  |   | 97.8  |  
|                                                 |  |              |      
|Net Income for 2007                              |  |              |       |                  |   | 8.7  |       |  |   | 8.7   |  
|                                                 |  |              |      
|Dividends                                        |  |              |       |                  |   | (7.9 | )     |  |   | (7.9  | )
|                                                 |  |              |      
|Shares Issued Under Stock Plans                  |  |              | 0.8   |                  |   |      |       |  |   | 0.8   |  
|                                                 |  |              |      
|Issuance of 38,303 Common Shares                 |  |              | 1.0   |                  |   |      |       |  |   | 1.0   |  
|                                                 |  |              |      
|                                                 |  |              |       |                  |   |      |       |  |   |       |  
|                                                 |  |              |      
|Balance at December 31, 2007                     |  |              | 65.3  |                  |   | 35.1 |       |  |   | 100.4 |  
|                                                 |  |              |      
|Net Income for 2008                              |  |              |       |                  |   | 9.7  |       |  |   | 9.7   |  
|                                                 |  |              |      
|Dividends                                        |  |              |       |                  |   | (8.0 | )     |  |   | (8.0  | )
|                                                 |  |              |      
|Shares Issued Under Stock Plans                  |  |              | 0.4   |                  |   |      |       |  |   | 0.4   |  
|                                                 |  |              |      
|Issuance of 32,754 Common Shares                 |  |              | 0.8   |                  |   |      |       |  |   | 0.8   |  
|                                                 |  |              |      
|Issuance of 2,000,000 Common Shares (See Note 4) |  |              | 36.2  |                  |   |      |       |  |   | 36.2  |  
|                                                 |  |              |      
|                                                 |  |              |       |                  |   |      |       |  |   |       |  
|                                                 |  |              |      
|Balance at December 31, 2008                     |  | $            | 102.7 |                  | $ | 36.8 |       |  | $ | 139.5 |  
|                                                 |  |              |       |                  |   |      |       |  |   |       |  





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



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Note 1: Summary of Significant Accounting
Policies



Nature of OperationsUnitil Corporation (Unitil or
the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. The following companies are
wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (Unitil Energy), Fitchburg Gas and Electric Light Company (Fitchburg), Northern Utilities, Inc. (Northern Utilities), Granite State Gas Transmission, Inc. (Granite State), 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.



On December 1, 2008, the Company purchased: (i) all
of the outstanding capital stock of Northern Utilities, a natural gas distribution utility serving customers in Maine and New Hampshire, from Bay State Gas Company (Bay State) and (ii) all of the outstanding capital stock of Granite State, an
interstate gas transmission pipeline company primarily serving the needs of Northern Utilities, from NiSource, Inc. (NiSource) pursuant to the Stock Purchase Agreement dated as of February 15, 2008 by and among NiSource, Bay State, and Unitil
(the Acquisitions). Bay State is a wholly owned subsidiary of NiSource.



Unitils principal business is the local distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the greater Fitchburg area of north central Massachusetts and the local distribution of
natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil Energy, which operates in
New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine (collectively referred to as the distribution utilities).



Granite State is an interstate natural gas transmission pipeline company,
operating 87 miles of underground gas transmission pipeline primarily located in Maine, New Hampshire and Massachusetts. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic
natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers.



A fifth utility subsidiary, Unitil Power, formerly functioned
as the full requirements wholesale power supply provider for Unitil Energy. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of Unitil Energy on May 1,
2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve Unitil Energys customers.



Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil
Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology, energy management and management
services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Companys corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil
Resources is the Companys wholly owned non-regulated subsidiary. Usource, 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. The
operations of Northern Utilities and Granite State are included in the Companys consolidated financial statements from December 1, 2008 through December 31, 2008.



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Regulatory
AccountingThe Companys principal business is the distribution of electricity and natural gas by the three distribution utilities: Unitil Energy, Fitchburg and Northern Utilities. Unitil Energy and Fitchburg are subject to regulation
by the FERC. Fitchburg is also regulated by the MDPU, Unitil Energy is regulated by the NHPUC and Northern Utilities is regulated by the MPUC and NHPUC. Granite State, the Companys natural gas transmission pipeline, is regulated by the FERC.
Accordingly, the Company uses the provisions of FASB Statement No. 71, Accounting for the Effects of Certain Types of Regulation. (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets
and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.



|                                                      |  |              |       |      |   |      
|----------------------------------------------------- |  | ------------ | ----- | ---- | - | -----
|                                                      |  | December 31,
|Regulatory Assets consist of the following (millions) |  | 2008         |       | 2007
|Energy Supply Contract Obligations                    |  | $            | 52.7  |      | $ | 72.7 
|Deferred Restructuring Costs                          |  |              | 28.3  |      |   | 30.5 
|Generation-related Assets                             |  |              | 0.8   |      |   | 1.6  
|                                                      |  |              |       |      |   |      
|SubtotalRestructuring Related Items                  |  |              | 81.8  |      |   | 104.8
|                                                      |  |              |       |      |   |      
|Retirement Benefit Obligations                        |  |              | 45.5  |      |   | 35.1 
|Income Taxes                                          |  |              | 16.0  |      |   | 14.6 
|Environmental Obligations                             |  |              | 19.7  |      |   | 13.1 
|Other                                                 |  |              | 10.1  |      |   | 2.9  
|                                                      |  |              |       |      |   |      
|Total Regulatory Assets                               |  | $            | 173.1 |      | $ | 170.5
|Less: Current Portion of Regulatory Assets(1)         |  |              | 26.9  |      |   | 24.0 
|                                                      |  |              |       |      |   |      
|Regulatory Assetsnoncurrent                          |  | $            | 146.2 |      | $ | 146.5
|                                                      |  |              |       |      |   |      

| | 
| | 

| | (1) | Reflects amounts included in Accrued Revenue on the Companys Consolidated Balance Sheets.
| | --- | ------------------------------------------------------------------------------------------



The Company receives a return on investment
on its regulated assets for which a cash outflow has been made. Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Companys consolidated financial statements. The Company
believes it is probable that its regulated distribution and transmission utilities will recover their investments in long-lived assets, including regulatory assets. If the Company, or a portion of its assets or operations, were to cease meeting the
criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in
which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of 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.



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. 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. Under the Independent System OperatorNew England (ISO-NE) Financial Assurance Policy (Policy), Unitils affiliates Unitil Energy, Fitchburg 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, 2008 and 2007, the Unitil affiliates had deposited $3.7
million and $2.5 million, respectively to satisfy their ISO-NE obligations. In addition, Northern Utilities has cash margin deposits to satisfy requirements for its natural gas hedging program. On December 31, 2008, there was $7.0 million
deposited for this purpose.



Goodwill and Intangible
AssetsAs a result of the acquisitions of Northern Utilities and Granite State, the Company recognized a bargain purchase adjustment as a reduction to Utility Plant, to be amortized over a ten year period, beginning with the date of the
Acquisitions, as authorized by regulators. (See Note 3).



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Off-Balance Sheet
ArrangementsAs of December 31, 2008, 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 (See Note 5).



Investments and Trading ActivitiesThe Company invests 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 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), SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of SFAS No. 133 (SFAS No. 138), SFAS No. 149, Amendment of Statement 133 on Derivative
Instruments and Hedging Activities (SFAS No. 149), SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 and FASB Staff Position No. FAS 133-1 and FIN
45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of SFAS No. 133 and FASB Interpretation No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others, (FIN 45); and Clarification of the Effective Date of SFAS No. 161 (FSP FAS 133-1 and FIN 45-4). The Company has a regulatory approved hedging program, discussed below, which meets 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, 2008, the Company has not entered
into any interest rate hedging 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.



The Company has a regulatory approved hedging program for Northern Utilities designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases New York Mercantile Exchange
futures that correspond to the associated delivery month. Any gains or losses on the fair value of these derivatives are passed through to ratepayers directly through a regulatory commission approved recovery mechanism. As a result of the ratemaking
process, the Company records gains and losses as regulatory liabilities or assets and recognizes such gains or losses in Purchased Gas when recovered in revenues. The Companys Consolidated Balance Sheets include derivative liabilities related
to net unrealized losses on current futures contracts of $4.5 million in Other Current Liabilities and on noncurrent futures contracts of $1.2 million in Noncurrent Liabilities at December 31, 2008. These amounts are offset in Accrued Revenues
on the Companys Consolidated Balance Sheets.



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.



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



Allowance for Doubtful AccountsThe Company recognizes
a provision for doubtful accounts each month based upon the Companys experience in collecting electric and gas utility service accounts receivable in prior years. At the end of each month, an analysis of the delinquent receivables is performed
which takes into account an assumption about the cash recovery of delinquent receivables. The analysis also



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calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Companys distribution
utilities are authorized by regulators to recover the costs of their energy commodity portion of bad debts through rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the
analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company. It has been the Companys experience that the assumptions it has used in evaluating the
adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.



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



In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans,
(SFAS No. 158), an amendment of SFAS No. 87, Employers Accounting for Pensions, SFAS No. 88, Employers Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination
Benefits, SFAS No. 106, Employers Accounting for Postretirement Benefits other than Pensions and SFAS No. 132(R), Employers Disclosures about Pensions and Other Postretirement Benefits. SFAS
No. 158 requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a
corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas rates. See Note 10.



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, 2008, 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 7).



Utility PlantThe cost of
additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average
interest rates applied to AFUDC were 4.58%, 5.73% and 4.92% in 2008, 2007 and 2006, 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 includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking
proceedings, depreciation amounts to provide for future negative salvage value. At December 31, 2008 and December 31, 2007, the Company estimates that the negative salvage value of future retirements recorded on the balance sheet in
Accumulated Depreciation, including $17.4 million in 2008 related to Northern Utilities, is $33.9 million and $16.2 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



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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: 2008  3.94%, 2007  4.29% and 2006  4.40%.



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 has or will recover substantially all of the costs of the environmental remediation 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, 2008, there are no material losses that would require additional liability reserves to be recorded other than those disclosed in
Note 7, 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 using the fair value-based method as prescribed under FASB No. 123(R), Share-Based Payment (See Note 4).



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



Income TaxesProvisions for
income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of earnings is presented. This process involves estimating the Companys current tax liabilities as well as assessing
temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are
included in the Companys consolidated balance sheets. 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 SFAS No. 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On
December 30, 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position No. FAS 132(R)-1, Employers Disclosures about Postretirement Benefit Plan Assets, (FSP FAS 132(R)-1) to provide guidance on an
employers disclosures about plan assets of a defined benefit pension or other postretirement plan. The disclosures about plan assets required by FSP FAS 132(R)-1 are to be provided for fiscal years ending after December 15, 2009. The
Company does not expect that the adoption of the deferred sections of FSP FAS 132(R)-1 will have an impact on the Companys Consolidated Financial Statements.



On September 12, 2008, the FASB issued FASB Staff Position No. FAS 133-1 and FIN 45-4, Disclosures about Credit
Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS No. 133) and FASB Interpretation No. 45, Guarantors Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, (FIN 45); and Clarification of the Effective Date of FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging
Activities, an amendment of FASB Statement No. 133 (SFAS No. 161), (FSP FAS 133-1 and FIN 45-4). FSP FAS 133-1 and FIN 45-4 is effective for reporting periods ending after November 15, 2008, with early adoption permitted.
FSP



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FAS 133-1 and FIN 45-4 (i) amends SFAS No. 133 to require disclosures by sellers of credit derivatives, including credit derivatives embedded in a
hybrid instrument, (ii) amends FIN 45 to require an additional disclosure about the current status of the payment/performance risk of a guarantee, and (iii) clarifies the FASBs intent about the effective date of SFAS No. 161.
The Company adopted FSP FAS 133-1 and FIN 45-4 and there was no impact on its financial statements.



In May 2008, the FASB issued FASB Statement No. 162, The Hierarchy of Generally Accepted Accounting Principles, (SFAS No. 162),
effective 60 days following the SECs September 2008 approval of the Public Company Accounting Oversight Boards amendments to AU Section 411. SFAS No. 162 identifies the sources of accounting principles and the framework for
selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. The Company adopted SFAS No. 162 and there
was no impact on its financial statements.



In March 2008, the
FASB issued SFAS No. 161, effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption allowed. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent
to provide users of financial statements with an enhanced understanding of an entitys use of derivative instruments and the effect of those derivative instruments on an entitys financial statements. The Company adopted SFAS No. 161
and there was no impact on its financial statements.



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 adopted SFAS No. 141R upon its effective date on January 1, 2009 and it will only impact future acquisitions, if any.



ReclassificationsBased on the Companys analysis
certain amounts previously reported have been reclassified to conform to improve the financial statements presentation and to conform to current year presentation, including the reclassification of $24.0 million of Noncurrent Assets to Current
Assets and $20.0 million of Noncurrent Liabilities to Current Liabilities principally related to current collections and obligations of Regulatory Assets and Regulatory Liabilities for 2007.



Note 2: Subsequent EventIssuance of Common Shares



As discussed in Note 3 below, on December 15, 2008, the Company issued
and sold 2,000,000 shares of its common stock at a price of $20.00 per share in a registered public offering. As part of this offering, the Company granted the underwriters a 30-day over-allotment option to purchase additional shares. The
underwriters exercised the over-allotment option and purchased an additional 270,000 shares of the Companys common stock in January 2009. The Companys net increases to Common Equity and Cash from the over-allotment sales were
approximately $5.1 million (after payment of the underwriting discount and offering expenses) and were used to repay a portion of the short-term indebtedness used for the Companys acquisitions of Northern Utilities and Granite State. The
Company recorded the issuance of the 270,000 shares, the sale proceeds and the increase in Common Equity in January 2009.



Note 3: Acquisitions



On December 1, 2008, the Company purchased (i) all of the outstanding capital stock of Northern Utilities, a natural gas distribution utility
serving customers in Maine and New Hampshire, from Bay State and (ii) all of the outstanding capital stock of Granite State, an interstate gas transmission pipeline company primarily serving the needs of Northern Utilities, from NiSource
pursuant to the Stock Purchase Agreement (SPA) dated as of February 15, 2008 by and among NiSource, Bay State, and Unitil. The aggregate



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purchase price for the Acquisitions was $160 million in cash, plus an additional working capital adjustment of $49.2 million, including approximately $30.0
million of natural gas storage inventory. As part of the acquisition, the Company acquired cash of $6.9 million and incurred transition and transaction costs of $7.6 million.



The Company initially financed the Acquisitions and the related costs and expenses using borrowings under a bank financing
facility with the Royal Bank of Canada. During December 2008, the Company repaid a portion of the bank financing facility using the net proceeds from: (i) the offering of the Companys common stock issued on December 15, 2008;
(ii) the sale and issuance by Northern Utilities to institutional investors in a private placement of $80 million aggregate principal amount of long-term unsecured Notes on December 3, 2008; (iii) the sale and issuance by Granite
State to institutional investors in a private placement of $10.0 million aggregate principal amount of long-term unsecured notes on December 15, 2008; and (iv) the receipt of proceeds from the financing by Northern Utilities of its gas
storage inventory contemporaneously with the closing of the Acquisitions. At December 31, 2008, the amount remaining under the bank financing facility was $39.1 million. The Company expects to repay the outstanding balance under the bank
financing facility prior to its maturity date of November 1, 2009 by issuing additional equity or debt.



The Company accounted for the Acquisitions under the purchase method of accounting for business combinations, in accordance with FASB Statement
No. 141, Business Combinations (SFAS No. 141) and SFAS No. 71. In that process, the Company recognized and measured the identifiable assets acquired and the liabilities assumed. In compliance with SFAS No. 71
regulatory accounting, the Company carried forward the historical book amounts of Northern Utilities and Granite States utility plant and regulatory assets and liabilities. The remaining identifiable assets and liabilities have been
recorded at fair value at the date of acquisition. Also, the Company measured and recognized an acquisition adjustment related to a bargain purchase relative to these values acquired against the purchase price. The results of Northern Utilities and
Granite State have been included in the accompanying consolidated financial statements from the date of acquisition.



The following table represents the allocation of the total purchase price of Northern Utilities and Granite State to the acquired assets and liabilities
of Northern Utilities and Granite State. The allocation represents the values assigned to each of the assets acquired and liabilities assumed. The purchase price allocation is preliminary and is subject to change due to several factors, including,
but not limited to: (1) changes in the fair values of Northern Utilities and Granite States current assets and liabilities as of the date of the acquisition; (2) the actual transition and transaction costs incurred; and
(3) changes in the Companys valuation estimates that may be made between now and the time the purchase price allocation is finalized.



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Purchase Price Allocation

($ Millions)



|                                               |  |                  |        |  
|---------------------------------------------- |  | ---------------- | ------ | -
|                                               |  | December 1, 2008 |       
|Equity Purchase Price                          |  | $                | 160.0  |  
|Plus: Working Capital Adjustment               |  |                  | 49.2   |  
|                                               |  |                  |        |  
|Aggregate Purchase Price                       |  |                  | 209.2  |  
|Transaction and Transition Costs               |  |                  | 7.6    |  
|                                               |  |                  |        |  
|Total Cash Purchase Price                      |  |                  | 216.8  |  
|Allocation To:                                 |  |                  |        |  
|Book Value of Net Utility Plant                |  |                  | (196.0 | )
|Cash Acquired                                  |  |                  | (6.9   | )
|Accounts Receivable and Other Current Assets   |  |                  | (22.2  | )
|Accrued Revenue                                |  |                  | (9.4   | )
|Gas Inventory                                  |  |                  | (32.3  | )
|Regulatory Assets                              |  |                  | (27.4  | )
|Accounts Payable and Other Current Liabilities |  |                  | 17.8   |  
|Regulatory Liabilities                         |  |                  | 31.3   |  
|                                               |  |                  |        |  
|Plant Acquisition Adjustment                   |  | $                | (28.3  | )
|                                               |  |                  |        |  



The Company will
amortize, over a 10-year period, the transition and transaction costs co-terminus with the Plant Acquisition Adjustment.



Note 4: Equity



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



Common Stock



As of August 21, 2008 the Companys common stock began trading on the New York Stock Exchange and ceased trading
on the American Stock Exchange. The Companys common stock will continue to trade under its current symbol, UTL.



On September 10, 2008, the Companys shareholders, at a Special Meeting of Shareholders, approved an increase in the authorized shares of the
Companys common stock. Shareholders approved an amendment to the Companys Articles of Incorporation to increase the authorized number of shares of the Companys common stock, from 8,000,000 shares to 16,000,000 shares in the
aggregate. The Company had 7,791,617, and 5,740,023 of common shares outstanding at December 31, 2008 and December 31, 2007, respectively.



Unitil Corporation Common Stock OfferingOn December 15, 2008, the Company issued and sold 2,000,000 shares of its common stock at a
price of $20.00 per share in a registered public offering. The Company repaid $36.8 million outstanding under the bank financing facility for the Companys acquisitions of Northern Utilities and Granite State with the net proceeds from the sale
and issuance of its common stock.



As part of this offering,
the Company granted the underwriters a 30-day over-allotment option to purchase additional shares. The underwriters exercised the over-allotment option and purchased an additional 270,000 shares of the Companys common stock in January 2009.
The Companys net increase to Common Equity and Cash proceeds from the over-allotment sales were approximately $5.1 million (after payment of the underwriting discount, but excluding estimated offering expenses) and were used to repay a portion
of the bank financing for the Companys acquisitions of Northern Utilities and Granite State and to repay other short-term indebtedness. The Company recorded the issuance of the 270,000 shares, the sale proceeds and the increase in Common
Equity in January 2009.



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Dividend Reinvestment and
Stock Purchase PlanDuring 2008, the Company sold 32,754 shares of its common stock, at an average price of $25.87 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans. Net
proceeds of $0.8 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 2007 and 2006, the Company raised $1.0 million and $1.0 million, respectively, of additional common equity through the issuance of 38,309 and 40,365 shares, respectively, of its common stock in connection with its DRP and 401(k)
plans.



Shares Repurchased, Cancelled and
RetiredDuring 2008, 2007 and 2006, 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 2006  2008 in
conjunction with the Plan are presented in the following table:



|              |  |        |  |                                 
|------------- |  | ------ |  | --------------------------------
|Issuance Date |  | Shares |  | AggregateMarket Value (millions)
|2/16/06       |  | 14,375 |  | $0.4                            
|2/9/07        |  | 9,020  |  | $0.2                            
|2/6/08        |  | 15,540 |  | $0.4                            



The compensation
expense associated with the issuance of shares under the Plan is being accrued over the vesting period and was $0.5 million, $0.4 million and $0.4 million in 2008, 2007 and 2006, respectively. At December 31, 2008, there was approximately $0.8
million of total unrecognized compensation cost related to non-vested shares under the Plan which is expected to be recognized over a weighted average of approximately 2.4 years as the shares vest. There were 21,024 and 18,511 non-vested shares
under the Plan as of December 31, 2008 and 2007, respectively. The weighted average grant date fair value of these shares was $27.38 and $25.95, respectively. There were no cancellations or forfeitures under the Plan during 2008.



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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. The aggregate intrinsic value of the options exercised was $0.8 million. 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 and $54,000 for the years ended December 31, 2007 and 2006, respectively. There was no compensation expense recorded for the year ended
December 31, 2008 with respect to this plan.



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



|                                              |  |      |              |   |      |   |             
|--------------------------------------------- |  | ---- | ------------ | - | ---- | - | ------------
|                                              |  | 2007 |              |   | 2006
|Beginning Options Outstanding and Exercisable |  |      | 25,000       |   |      |   | 25,000      
|Dividend Equivalents EarnedPrior Years       |  |      | 15,388       |   |      |   | 13,202      
|Dividend Equivalents EarnedCurrent Year      |  |      | 2,049        |   |      |   | 2,186       
|Options Exercised                             |  |      | (42,437      | ) |      |   |            
|                                              |  |      |              |   |      |   |             
|Ending Options Outstanding and Exercisable    |  |      |             |   |      |   | 40,388      
|                                              |  |      |              |   |      |   |             
|Weighted Average Exercise Price per Share     |  |      | $10.70       |   |      |   | $11.25      
|Range of Option Exercise Price per Share      |  | $    | 12.11-$18.28 |   |      | $ | 12.11-$18.28
|Weighted Average Remaining Contractual Life   |  |      | n/a          |   |      |   | 0.9 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.



In 2008, the Company issued and sold 3,300 shares of its common stock, at a final average price of $24.51 per share, in connection with the exercise of
stock options under the Unitil Corporation 1998 Stock Option Plan. The aggregate intrinsic value of the options exercised was less than $0.1 million. Net proceeds of $0.1 million were used by the Company to reduce short-term borrowings. There was no
compensation expense associated with this plan in 2008, 2007 and 2006. 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. As of December 31, 2008, there was no aggregate intrinsic value of the options exercisable. As of December 31, 2007, the intrinsic value of the options exercisable was $0.1 million.



|                                            |  |                 |   |      |                      |       |                |         |                      |   |                |  |                      |  |   |      
|------------------------------------------- |  | --------------- | - | ---- | -------------------- | ----- | -------------- | ------- | -------------------- | - | -------------- |  | -------------------- |  | - | -----
|                                            |  | 2008            |   | 2007 |                      | 2006 
|                                            |  | Number ofShares |   |      | AverageExercisePrice |       | NumberofShares |         | AverageExercisePrice |   | NumberofShares |  | AverageExercisePrice
|Beginning Options Outstanding               |  | 107,000         |   |      | $                    | 27.13 |                | 107,000 |                      | $ | 27.13          |  | 107,000              |  | $ | 27.13
|Options Granted                             |  |                |   |      |                      |      |                |        |                      |   |               |  |                     |  |   |     
|Options Exercised                           |  | (3,300          | ) |      | $                    | 24.51 |                |        |                      |   |               |  |                     |  |   |     
|Options Forfeited                           |  | (6,500          | ) |      | $                    | 27.99 |                |        |                      |   |               |  |                     |  |   |     
|                                            |  |                 |   |      |                      |       |                |         |                      |   |                |  |                      |  |   |      
|Ending Options Outstanding                  |  | 97,200          |   |      | $                    | 27.16 |                | 107,000 |                      | $ | 27.13          |  | 107,000              |  | $ | 27.13
|                                            |  |                 |   |      |                      |       |                |         |                      |   |                |  |                      |  |   |      
|Options Vested and Exercisable- end of year |  | 97,200          |   |      | $                    | 27.16 |                | 107,000 |                      | $ | 27.13          |  | 107,000              |  | $ | 27.13



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The following summarizes
certain data for the options outstanding at December 31, 2008:



|                         |  |                                           |  |                               |       |                           |          
|------------------------ |  | ----------------------------------------- |  | ----------------------------- | ----- | ------------------------- | ---------
|Range of Exercise Prices |  | Options Vested,Exercisable andOutstanding |  | WeightedAverageExercise Price |       | RemainingContractual Life
|$20.00-$24.99            |  | 30,700                                    |  | $                             | 23.38 |                           | 0.2 years
|$25.00-$29.99            |  | 34,500                                    |  | $                             | 25.88 |                           | 2.1 years
|$30.00-$34.99            |  | 32,000                                    |  | $                             | 32.17 |                           | 1.1 years
|                         |  |                                           |  |                               |       |                           |          
|                         |  | 97,200                                    |  |                               |       |                           |          
|                         |  |                                           |  |                               |       |                           |          



Preferred Stock



Two of Unitils distribution companies, Unitil Energy and Fitchburg,
have $2.0 million of preferred stock outstanding. At December 31, 2008, Unitil Energy has $0.2 million of 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock series outstanding and Fitchburg has two series of Redeemable, Cumulative
Preferred Stock outstanding, $0.8 million of 5.125% Series and $1.0 million of 8.00% Series.



Fitchburg 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, Fitchburg 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 2008, 2007 and 2006 related to the annual redemption offer were $21,200, $21,700
and $22,000, respectively. The aggregate amount of sinking fund requirements of the Redeemable, Cumulative Preferred Stock for each of the five years following 2008 is $117,000 per year.



Earnings Per Share



The following table reconciles basic and diluted earnings per share.



|                                                           |  |      |       |      |   |       |  |   |      
|---------------------------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|(Millions except shares and per share data)                |  | 2008 |       | 2007 |   | 2006 
|Earnings Available to Common Shareholders                  |  | $    | 9.6   |      | $ | 8.6   |  | $ | 7.9  
|                                                           |  |      |       |      |   |       |  |   |      
|Weighted Average Common Shares OutstandingBasic (000s)   |  |      | 5,830 |      |   | 5,659 |  |   | 5,597
|Plus: Diluted Effect of Incremental Shares (000s)         |  |      |      |      |   | 13    |  |   | 15   
|Weighted Average Common Shares OutstandingDiluted (000s) |  |      | 5,830 |      |   | 5,672 |  |   | 5,612
|                                                           |  |      |       |      |   |       |  |   |      
|Earnings per ShareBasic and Diluted                       |  | $    | 1.65  |      | $ | 1.52  |  | $ | 1.41 
|                                                           |  |      |       |      |   |       |  |   |      



Weighted average
options to purchase 97,200, 35,000 and 72,500 shares of common stock were outstanding during 2008, 2007 and 2006, 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, 15,985, 2,030 and 24,256 weighted average non-vested restricted shares for 2008, 2007 and 2006, respectively, were not included in the above computation because the
effect would have been antidilutive.



Note 5: 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 utility subsidiaries, Unitil Energy, Fitchburg, Northern Utilities, and Granite State, were
issued



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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.



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 Unitil Energy and Fitchburg or certain other actions against subsidiary companies in the
Unitil System.



Substantially all of the property of Unitil
Energy is subject to liens of indenture under which First Mortgage Bonds (FMB) have been issued. In order to issue new FMB, the customary covenants of the existing Unitil Energy Indenture Agreement must be met, including that Unitil Energy 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 Unitil Energy agreements further require that if Unitil Energy
defaults on any Unitil Energy FMB, it would constitute a default for all Unitil Energy FMB. The Unitil Energy default provisions are not triggered by the actions or defaults of Unitil or its other subsidiaries.



All of the long-term debt of Fitchburg, Northern Utilities and Granite State
are issued under Unsecured Promissory Notes with negative pledge provisions. Each issue of long-term debt ranks pari passu with its other senior unsecured long-term debt within that subsidiary. 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 Fitchburg, Northern Utilities or Granite State to issue new long-term debt, the covenants of the existing long-term
agreements of that subsidiary must be satisfied, including that the subsidiary 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 Unitil Energy agreements, the Fitchburg, Northern Utilities and Granite State agreements each require that if that subsidiary defaults on any of its own long-term debt agreements, it would constitute a default under all of
that subsidiarys long-term debt agreements. Each of the Fitchburg, Northern Utilities and Granite State default provisions are not triggered by the actions or defaults of Unitil or any of its other subsidiaries.



The Unitil, Unitil Energy, Fitchburg, Northern Utilities and Granite State
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. The Granite State notes are guaranteed by Unitil for the payment of principal, interest and other amounts payable. This guarantee will terminate if Granite State is
reorganized and merges with and into Northern Utilities.



At
December 31, 2008, there were no restrictions on Unitils Retained Earnings for the payment of common dividends. Unitil Energy, Fitchburg, Northern Utilities and Granite State 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 $363,755, $335,877, and $310,136 in 2008, 2007 and 2006, respectively.



The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 2008 is: 2009
 $393,946; 2010  $426,643; 2011  $462,055; 2012  $500,405; and 2013  $541,938, respectively.



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Long-Term Debt
IssuancesIn connection with the Acquisitions, Northern Utilities issued $80.0 million aggregate principal amount of senior unsecured notes on December 3, 2008, and Granite State issued $10.0 million aggregate principal amount of
senior unsecured notes on December 15, 2008., The net proceeds from the Northern Utilities and Granite State notes were used to recapitalize Northern Utilities and Granite State and to ultimately repay a portion of the Companys short-term
bank financing facility used to fund the purchase price of the Acquisitions. The notes consist of:



| | (i) | $30.0 million aggregate principal amount of 6.95% senior unsecured notes of Northern Utilities, which are due in 2018;
| | --- | ----------------------------------------------------------------------------------------------------------------------



| | (ii) | $50.0 million aggregate principal amount of 7.72% senior unsecured notes of Northern Utilities, which are due in 2038; and
| | ---- | --------------------------------------------------------------------------------------------------------------------------



| | (iii) | $10.0 million aggregate principal amount of 7.15% senior unsecured notes of Granite State, which are due in 2018, along with a guarantee from Unitil for the payment of principal,
interest and other amounts payable on the Granite State notes. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.
| | ----- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 Unitil Energy 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.



Fair Value of Long-Term DebtThe fair value of the long-term debt of the Company and its subsidiaries 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 long-term debt of the Company and its subsidiaries at
December 31, 2008 is estimated to be in a range of up to approximately $229 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.



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Details on long-term debt at
December 31, 2008 and 2007 are shown below:



|                                                   |  |              |       |      |   |      
|-------------------------------------------------- |  | ------------ | ----- | ---- | - | -----
|                                                   |  | December 31,
|Long-Term Debt (millions)                          |  | 2008         |       | 2007
|Unitil Corporation Senior Notes:                   |  |              |       |      |   |      
|6.33% Notes, Due May 1, 2022                       |  | $            | 20.0  |      | $ | 20.0 
|                                                   |  |             
|Unitil Energy 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 
|                                                   |  |             
|Fitchburg 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 
|                                                   |  |             
|Northern Utilities Senior Notes:                   |  |              |       |      |   |      
|6.95% Senior Notes, Series A, Due December 3, 2018 |  |              | 30.0  |      |   |     
|7.72% Senior Notes, Series B, Due December 3, 2038 |  |              | 50.0  |      |   |     
|                                                   |  |             
|Granite State Senior Notes:                        |  |              |       |      |   |      
|7.15% Senior Notes, Due December 15, 2018          |  |              | 10.0  |      |   |     
|                                                   |  |             
|Unitil Realty Corp. Senior Secured Notes:          |  |              |       |      |   |      
|8.00% Notes, Due August 1, 2017                    |  |              | 4.7   |      |   | 5.0  
|                                                   |  |              |       |      |   |      
|Total Long-Term Debt                               |  |              | 249.7 |      |   | 160.0
|Less: Current Portion                              |  |              | 0.4   |      |   | 0.4  
|                                                   |  |              |       |      |   |      
|Total Long-Term Debt, Less Current Portion         |  | $            | 249.3 |      | $ | 159.6
|                                                   |  |              |       |      |   |      



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



Unitils utility subsidiaries operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass through basis. These
reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the
distribution utilities rate tariffs, interest is accrued on these balances and will produce either interest income or interest expense. 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.



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



|                                 |  |      |      |   |      |   |      |      |  |   |      |  
|-------------------------------- |  | ---- | ---- | - | ---- | - | ---- | ---- |  | - | ---- | -
|Interest Expense, net (millions) | 
|                                 |  | 2008 |      |   | 2007 |   |      | 2006 | 
|Interest Expense                 |  |      |      |   |      |   |      |      |  |   |      |  
|Long-term Debt                   |  | $    | 12.0 |   |      | $ | 11.1 |      |  | $ | 9.5  |  
|Short-term Debt                  |  |      | 1.0  |   |      |   | 1.1  |      |  |   | 1.5  |  
|Regulatory Liabilities           |  |      | 0.1  |   |      |   | 0.8  |      |  |   | 0.3  |  
|                                 |  |      |      |   |      |   |      |      |  |   |      |  
|Subtotal Interest Expense        |  |      | 13.1 |   |      |   | 13.0 |      |  |   | 11.3 |  
|                                 |  |      |      |   |      |   |      |      |  |   |      |  
|Interest Income                  |  |      |      |   |      |   |      |      |  |   |      |  
|Regulatory Assets                |  |      | (2.5 | ) |      |   | (2.9 | )    |  |   | (3.1 | )
|AFUDC(1)and Other                |  |      | (0.1 | ) |      |   | (0.5 | )    |  |   | (0.4 | )
|                                 |  |      |      |   |      |   |      |      |  |   |      |  
|Subtotal Interest Income         |  |      | (2.6 | ) |      |   | (3.4 | )    |  |   | (3.5 | )
|                                 |  |      |      |   |      |   |      |      |  |   |      |  
|Total Interest Expense, net      |  | $    | 10.5 |   |      | $ | 9.6  |      |  | $ | 7.8  |  
|                                 |  |      |      |   |      |   |      |      |  |   |      |  

| | 
| | 

| | (1) | AFUDCAllowance for Funds Used During Construction
| | --- | --------------------------------------------------



Credit Arrangements



On November 26, 2008, Unitil entered into a $60 million, 364-day revolving credit agreement with Bank of America, N.A.,
as administrative agent, and a syndicate of lenders. Borrowings under the revolving credit agreement bear interest at a floating annual rate equal to the daily LIBOR (the London Interbank Offered Rate) reported by the British Banking Association
plus the applicable margin. The Company has the option of locking in the daily rate applicable to outstanding loans for one-, two-, three- or six-month interest periods. The applicable margin was initially equal to 1.75%, increased to 3.50% on
January 2, 2009, and may be increased over time if the Company does not meet specified conditions with respect to its equity capital. The revolving credit agreement contains customary terms and conditions for credit facilities of this type,
including certain financial covenants, including, without limitation, covenants restricting the Companys ability to incur liens, merge or consolidate with another entity or change its line of business. The revolving credit agreement also
contains a covenant restricting the Companys ability to permit long-term debt to exceed 65% of capitalization at the end of each fiscal quarter. The Company had short-term debt outstanding through its revolving credit agreement of
approximately $35.0 million and $18.8 million at December 31, 2008 and December 31, 2007, respectively.



The Company financed the Acquisitions and the related costs and expenses in part using borrowings under a bank financing facility. As of December 31,
2008, there was $39.1 million outstanding on this bank financing facility. Amounts outstanding under the bank financing facility accrue interest at either the Eurodollar Rate or the base rate, in each case plus the applicable margin. The Eurodollar
Rate is based on an applicable LIBOR as increased by statutory reserve requirements. The base rate is the higher of (i) the prime rate of interest announced publicly by Royal Bank of Canada from time to time and (ii) the Federal Funds Rate
plus 0.50%. The applicable margin is a range of interest rates that varies from 2.50% to 5.00% depending on the remaining term of the borrowings. The bank financing facility contains customary terms and conditions, including, without limitation,
covenants restricting the Companys ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all assets.



The weighted average interest rates on all short-term
borrowings were 3.8%, 5.6% and 5.5% during 2008, 2007 and 2006, respectively.



On November 1, 2008, Northern Utilities entered into a gas storage management agreement (the Agreement) pursuant to which (i) Northern Utilities released certain pipeline and storage capacity to an asset
manager from November 1, 2008 through April 30, 2009 and (ii) the asset manager financed inventories associated with the released storage capacity from Northern Utilities contemporaneously with the closing of the Acquisitions. The
Agreement requires Northern Utilities to repurchase quantities of natural gas over the course of the 2008/2009 winter heating season at a specified price and any remaining



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balance of the gas inventory on April 30, 2009 at the same price initially paid by the asset manager. The Agreement provides for the Company to issue a
guarantee of payment of $15 million for the term of the agreement. There is $24.0 million outstanding at December 31, 2008 related to this Agreement.



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, 2008, 2007 and 2006 amounted to $389,000, $433,000 and $410,000 respectively. Fitchburg 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 Fitchburg.



The following is a schedule of future operating lease payment obligations and future minimum lease payments under capital leases as of December 31,
2008:



|                                 |  |                 |       |               |   |      
|-------------------------------- |  | --------------- | ----- | ------------- | - | -----
|Year Ending December 31, (000s) |  | OperatingLeases |       | CapitalLeases
|2009                             |  | $               | 929   |               | $ | 385  
|2010                             |  |                 | 823   |               |   | 345  
|2011                             |  |                 | 676   |               |   | 257  
|2012                             |  |                 | 549   |               |   | 97   
|2013                             |  |                 | 234   |               |   | 41   
|2014-2018                        |  |                 | 478   |               |   |     
|                                 |  |                 |       |               |   |      
|Total Payments                   |  | $               | 3,689 |               | $ | 1,125
|                                 |  |                 |       |               |   |      



Guarantees



The Company also provides limited guarantees on certain energy and
natural gas storage management contracts entered into by the three distribution utilities. The Companys policy is to limit these guarantees to two years or less. As of December 31, 2008 there are $18.0 million of guarantees outstanding
and these guarantees extend through October 31, 2009. Of this amount, $15 million is related to Unitils guarantee of payment for the term of the Northern Utilities gas storage management agreement. 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.



The Company also guarantees the payment of principal, interest and other
amounts payable on the notes issued by Unitil Realty and Granite State. As of December 31, 2008, the principal amount outstanding for the 8% Unitil Realty notes was $4.7 million. On December 15, 2008, the Company entered into a guarantee
for the payment of principal, interest and other amounts payable on the $10 million Granite State notes due 2018. As of December 31, 2008, the principal amount outstanding for the 7.15% Granite State notes was $10.0 million. This guarantee will
terminate if Granite State reorganizes and merges with and into Northern Utilities.



Note 6: Energy Supply



Electric Supply:



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



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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 suppliers. Retail choice has been successful
for Unitils largest customers. As of December 2008, 82 or 55% of Unitils largest New Hampshire customers representing 18% 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. However, most residential and small commercial customers continue to purchase their electric supply through Unitils local
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 Electric Power Supply



In order to provide regulated electric supply service to their customers, Unitils distribution utilities enter into load-following wholesale
electric power supply contracts with various wholesale suppliers.



Fitchburg has power supply contracts with various wholesale suppliers for the provision of Basic Service energy supply. MDPU policy dictates the pricing structure and duration of each of these contracts. Currently, all Basic Service power
supply contracts for large general accounts are three months in duration and provide 100% of supply requirements. Basic Service power supply contracts for residential and small and medium general service customers are acquired every six months, are
12 months in duration and provide 50% of the supply requirements.



Unitil Energy currently has power supply contracts with various wholesale suppliers for the provision of Default Service to its customers. Unitil Energy 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. Unitil Energy 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.



The NHPUC and MDPU regularly investigate alternatives to their procurement policy, which may lead to future changes in this procurement structure.



Regional Electric Transmission and Power Markets



Fitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are participants in the ISO-NE markets. ISO-NE is the
Regional Transmission Organization (RTO) in New England. 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 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.



Electric Power Supply Divestiture



Prior to May 1, 2003, Unitil Energy 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, Unitil Energy and Unitil
Power amended the Unitil System Agreement, such that power sales from Unitil Power to Unitil Energy ceased, and Unitil Power sold substantially all of its entitlements under the remaining portfolio of power supply contracts. Under the amended Unitil
System Agreement, Unitil Energy 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. In connection with the implementation of retail
choice, Unitil Power and Fitchburg 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.



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Unitil Energy and Fitchburg
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. Unitils 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.



Natural Gas Supply:



With the purchase of Northern Utilities on
December 1, 2008, Unitil now manages gas supply for customers served by Northern Utilities in Maine and New Hampshire as well as customers served by Fitchburg in Massachusetts.



Fitchburgs residential and commercial and industrial (C&I) customers have the opportunity to purchase their
natural gas supply from third-party vendors, although most of Fitchburgs customers continue to purchase such supplies at regulated rates from Fitchburg. Northern Utilities C&I natural gas customers have the opportunity to purchase
their natural gas supply from third-party vendors, and third-party supply is prevalent among Northern Utilities larger C&I customers. Most small C&I customers, as well as all residential customers, purchase their gas supply at
regulated rates from Northern Utilities 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.



Regulated Natural Gas Supply



Fitchburg purchases natural gas under contracts of one year or less, as well as from producers and marketers on the spot market. Fitchburg arranges for
gas delivery to its city gate station or underground storage through its own long-term contracts with Tennessee Gas Pipeline, or in the case of liquefied natural gas (LNG) or liquefied propane gas (LPG), to truck supplies to each storage facility
within Fitchburgs service territory.



Fitchburg 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, Fitchburg 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.



Northern purchases a majority of its natural gas from U.S. domestic and Canadian suppliers under contracts of one year or less, and on occasion from
producers and marketers on the spot market. Northern arranges for gas delivery to its city gate station or underground storage through its own long-term contracts with various interstate pipeline and storage facilities, through peaking supply
contracts delivered to its city gate station, or in the case of liquefied natural gas (LNG) or liquefied propane gas (LPG), to truck supplies to each storage facility within Northern Utilities service territory.



Northern has available under firm contract 100,000 MMbtu per day of
year-round and seasonal transportation capacity to its distribution facilities, and 3.4 Bcf of underground storage. As a supplement to pipeline natural gas, Northern 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 7: Commitments and Contingencies



Subsequent Event



On December 15, 2008,
the Company issued and sold 2,000,000 shares of its common stock at a price of $20.00 per share in a registered public offering. As part of this offering, the Company granted the underwriters a 30-day over-allotment option to purchase additional
shares. The underwriters exercised the over-allotment option and purchased an additional 270,000 shares of the Companys common stock in January 2009. The Companys net increases to Common Equity and Cash from the over-allotment sales were
approximately $5.1 million (after payment of the underwriting discount and offering expenses) and



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were used to repay a portion of the short-term indebtedness used for the Companys acquisitions of Northern Utilities and Granite State. The Company
recorded the issuance of the 270,000 shares, the sale proceeds and the increase in Common Equity in January 2009.



Legal Proceedings



A putative class action complaint was filed against Fitchburg on January 7, 2009 in Worcester Superior Court in Worcester, Massachusetts, captioned
Bellerman v. Fitchburg Gas and Electric Light Company. The complaint seeks an unspecified amount of damages including the cost of temporary housing and alternative fuel sources, emotional and physical pain and suffering and property damages
allegedly incurred by customers in connection with the loss of electric service during the ice storm in Fitchburgs service territory in December, 2008. As of this date the complaint has not been served on Fitchburg. The Company believes this
complaint is without merit, and will defend itself vigorously.



Regulatory
Matters



Overview (Unitil Energy, Fitchburg, and
Northern Utilities)Unitils distribution utilities deliver electricity and/or natural gas to all customers in the Companys service territory, at rates established under traditional cost of service regulation. Under this
regulatory structure, Unitil Energy, Fitchburg, and Northern Utilities 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 New Hampshire, Massachusetts and Maine, most Unitil customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. For Northern
Utilities, only business customers have the opportunity to purchase their natural gas supplies from third-party suppliers at this time. Most small and medium-sized customers, however, continue to purchase such supplies through Unitil Energy,
Fitchburg and Northern Utilities as the providers of basic or default service energy supply. Unitil Energy, Fitchburg and Northern Utilities 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 Fitchburg divested their long-term power supply contracts through the sale of the
entitlements to the electricity sold under those contracts. Unitil Energy and Fitchburg 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 two to four years, is $81.9 million as of
December 31, 2008 including $22.1 million in Accrued Revenue on the Companys Consolidated Balance Sheet. Unitils 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.



Unitil EnergyUnitil Energy provides electric distribution service to its customers pursuant to rates approved by the NHPUC. Its current
electric distribution base rates were approved by the NHPUC in 2006 under a Settlement Agreement with the NHPUC. As the provider of last resort, Unitil Energy also provides its customers with electric power through Default Service at rates which
reflect Unitil Energys costs for wholesale supply with no profit or markup. Unitil Energy 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 procured on a semi-annual basis. Unitil Energy recovers its costs for this service on a pass-through basis through reconciling rate mechanisms. As of December 31, 2008, approximately 80
percent of Unitil Energys electric load was served by Default Service. The remaining portion was served by competitive third party suppliers. The vast majority of customers being served by competitive third party suppliers are large C&I
customers. Most residential and small commercial customers continue to purchase their electric supply through the distribution utility.



Under its 2002 restructuring settlement, the NHPUC approved the divestiture of the long-term power supply portfolio by Unitil Power and tariffs for Unitil
Energy for stranded cost recovery, including certain charges that remain subject to annual or periodic reconciliation or future review. Unitil Energy had recorded



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on its balance sheets $18.9 and $30.7 million as Energy Supply Contract Obligations, respectively, on the Companys Consolidated Balance Sheet as of
December 31, 2008 and 2007, respectively, associated with these long-term purchase power stranded costs, which are included in Unitils consolidated financial statements. These Energy Supply Contract Obligations are expected to be
recovered principally over a period of approximately two years. Unitil Energy does not earn carrying charges on these regulatory assets as the timing of cash receipts and cash disbursements associated with these long-term obligations is matched
through rates.



On March 14, 2008, Unitil Energy made its
annual reconciliation and rate filing with the NHPUC under its restructuring plan, for rates effective May 1, 2008, including reconciliation of prior year costs and revenues, power supply and power supply-related stranded costs. The filing was
approved on April 23, 2008. On July 9, 2008, Unitil Energy proposed an increase to its External Delivery Charge, effective September 1, 2008, reflecting higher transmission costs. The filing was approved on August 29, 2008.



On January 22, 2008, 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. The NHPUC determined that it is appropriate to implement some form of time-based metering
standards and ordered that the details, including cost-benefit analyses, form of rate design, time of implementation and applicable customer classes are to be determined in separate proceedings initiated by the NHPUC. The NHPUC also found that
additional review of the energy standards for net metering, fuel diversity and fossil fuel generation efficiency as proposed in the Energy Policy Act of 2005 is not required due to action of the New Hampshire legislature and the NHPUC in adopting
comparable standards.



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. On January 16,
2009, the NHPUC issued its decision in this matter, concluding that such rate mechanisms should only be implemented on a company-by-company basis in the context of an examination of company specific costs and revenues, service territory, customer
mix and rate base investment.



Unitil EnergyOther:In July 2008, the State of New Hampshire enacted legislation that allows electric utilities to make investments in distributed energy resources, including energy efficiency and demand reduction technologies, as well as clean cogeneration and
renewable generation.



FitchburgElectric
OperationsFitchburg provides electric distribution service to customers under unbundled distribution rates approved by the MDPU. Its current electric distribution base rates were approved by the MDPU in 2008. Fitchburg, as the provider of
last resort, also provides its customers with electric power through Basic Service at rates which reflect Fitchburgs costs for wholesale supply with no profit or markup. Prices for Basic Service are set periodically based on market
solicitations as approved by the MDPU. As of December 31, 2008, approximately 59 percent of Fitchburgs electric load was served by Basic 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.



As a result of the restructuring and the divestiture of Fitchburgs owned generation assets and buyout of Fitchburgs power supply obligations,
Regulatory Assets on the Companys balance sheets include the following three categories: Energy Supply Contract 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 generation plant owned by Fitchburg. Fitchburg earns carrying charges on the majority of the
unrecovered balances of the Recoverable Deferred Restructuring Charges. The value of Fitchburgs Recoverable Deferred Restructuring Charges and Recoverable Generation-related Assets was approximately $29.1 million at December 31, 2008, and
$32.1 million at December 31, 2007, including $4.1 million and $3.9 million, respectively, included in Accrued Revenue, and is expected to be recovered in Fitchburgs rates over the next four years. In addition, Fitchburg had recorded on
its balance sheet $33.8 million at December 31, 2008, and $42.0 million at December 31, 2007, as Energy Supply Contract Obligations associated with the divestiture of its long-term purchase power contracts, which are included in
Unitils



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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.



The Company
received a final order from the MDPU on February 29, 2008 approving an electric rate increase of $2.1 million, effective March 1, 2008.



Pursuant to its approved electric restructuring plan, toward the end of each year Fitchburg submits its annual reconciliation of costs and revenues for
Transition, Transmission, Standard Offer Service, and Default Service. Fitchburgs 2007 filing, submitted on December 3, 2007, was approved by the MDPU on August 19, 2008. On November 26, 2008, Fitchburg submitted its annual
reconciliation filing for 2008. The rates were approved effective January 1, 2009, subject to further investigation. This matter remains pending.



Major Ice StormOn December 11 and 12, 2008, a severe ice storm struck the New England region, causing extensive damage to electric
facilities and loss of service to significant numbers of customers of several utilities. An estimated one million electric customers in the region were affected, including all of Unitils 28,000 Massachusetts customers, and approximately half
of its New Hampshire customers. Unitil was able to restore power to one-third of its Massachusetts customers within three days, and 80 percent of its customers by day seven, and the final Massachusetts customers, including those with individual
service problems, were restored by day 13, December 24, 2008. On January 7, 2009, the MDPU opened an investigation into the Preparation and Response of the Massachusetts electric distribution companies to the December 12, 2008
Winter Storm. Each electric distribution company has been ordered to file a report detailing its response to the storm and outages, and its service restoration efforts with the MDPU by February 23, 2009. Public hearings have been held in each
of the electric distribution utilities service areas in Massachusetts. Based on its preliminary assessment, the Company has accrued and deferred approximately $10 million in costs for the repair and replacement of electric distribution systems
damaged during the storm. The amount and timing of the cost recovery of these storm restoration expenditures will be determined in future regulatory proceedings. The Company does not believe these storm restoration expenditures and the timing of
cost recovery will have a material adverse impact on the Companys financial condition or results of operations. This matter remains pending.



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



FitchburgOtherOn June 22, 2007, the
MDPU opened an inquiry into revenue decoupling for gas and electric distribution utilities, generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utilitys distribution revenues on sales. Revenue
decoupling is intended to remove the disincentive a utility has to promote efforts to reduce energy consumption by its customers or to facilitate installation of distributed generation to displace electricity delivered by the utility. On
July 16, 2008, the MDPU issued an order establishing a comprehensive plan for decoupling to be adopted by gas and electric distribution utilities on a going-forward basis, including company specific rate cases. Lost base revenue recovery
associated with incremental energy efficiency savings will be allowed through 2012 consistent with the MDPUs expectation that, with limited exceptions, distribution companies will be operating under decoupling plans by year-end 2012. Each
distribution company was required to notify the MDPU of when the company expects to file a rate case to implement decoupling. Fitchburg notified the MDPU that it will be prepared to file rate cases for each of its divisions by the third quarter of
2009, based upon a calendar 2008 test year, along with a comprehensive decoupling proposal and associated base rate adjustment mechanism. This matter remains pending before the MDPU.



On July 2, 2008, the Governor of Massachusetts signed into law The Green Communities Act (the
GC Act), an energy policy legislation designed to substantially increase energy efficiency and the development of renewable energy resources in Massachusetts. The GC Act includes provisions that:



| |  |  | Require electric and natural gas distribution companies to file three-year energy efficiency investment plans designed to implement all available cost-effective
energy efficiency and demand reduction resources; the plans are to include fully reconciling funding mechanisms;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | Require utility distribution companies to undertake various Green programs, including the solicitation of bids for long-term renewable energy procurement contracts
for which utilities would be allowed remuneration on certain contract commitments;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Establishes expanded authority for the MDPU to investigate mergers involving holding companies of public utilities;
| | - |  | -------------------------------------------------------------------------------------------------------------------



| |  |  | Increase the Renewable Portfolio Standard by 1% annually, requiring that by the year 2020 utilities and other electricity suppliers obtain 15% of the power they
sell from renewable resources;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Authorize electric distribution companies to construct, own, and operate up to 50 megawatts of solar generating capacity; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | Modify the service quality performance penalty provision.
| | - |  | ---------------------------------------------------------



The GC Act provides for utilities to recover in rates the incremental costs associated with its various mandated programs.



Northern Utilities AcquisitionNorthern Utilities is a New
Hampshire corporation and a public utility under both New Hampshire and Maine law. Northern Utilities provides natural gas distribution services to a total of 52,000 customers in 44 New Hampshire and southern Maine communities. On December 1,
2008 Unitil completed the purchase of Northern Utilities from Bay State Gas Company (a subsidiary of NiSource, Inc.) and Granite State from NiSource Inc. The purchase agreement between Bay State, NiSource and Unitil was announced on
February 19, 2008. Joint petitions on behalf of Unitil and Northern Utilities requesting approval of the purchase of Northern Utilities by Unitil were filed with the NHPUC and the MPUC on March 31, 2008. State regulatory approvals of
Unitils purchase of Granite State were not required. In August 2008, unopposed settlement agreements resolving all outstanding issues and recommending approval of the acquisition were filed with the NHPUC and MPUC on behalf of Unitil, Northern
Utilities and the active parties to the respective New Hampshire and Maine proceedings. The NHPUC approved the transaction on October 10, 2008. The MPUC issued an order approving the transaction with conditions on October 22, 2008, which
it modified on November 5, 2008.



Although separately
negotiated and filed with the MPUC and the NHPUC, the settlement agreements reflect several common topics (including regulatory authorizations, matters affecting rates, customer service provisions, service quality, gas safety and reliability,
agreements regarding Granite State and reporting requirements) as follows:



The settlement agreements include the following authorizations and approvals:



| |  |  | approval of Unitils acquisition of Northern Utilities;
| | - |  | -------------------------------------------------------



| |  |  | approval of the amended Unitil Service Agreement adding Northern Utilities as a party;
| | - |  | --------------------------------------------------------------------------------------



| |  |  | approval of the amended Unitil Cash Pooling Agreement adding Northern Utilities as a party; and
| | - |  | -----------------------------------------------------------------------------------------------



| |  |  | approval of Northern Utilities accounting deferral and 10-year amortization of transaction costs and transition costs resulting from the Companys
acquisition of Northern Utilities and the Companys agreement not to seek recovery of these costs, or the transaction or transition costs of any other utility subsidiary, in rates.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements include the following commitments related to rates:



| |  |  | agreement that synergy savings resulting from our acquisition of Northern Utilities will be retained by the Company until the next base rate change and then will
flow to customers;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement not to request a base rate change for Northern Utilities before November 1, 2010 unless (i) Northern Utilities projected annual revenues
are more than 8% below the level of total 2007 distribution revenues or (ii) the MPUC or NHPUC, as applicable, approves a plan to subject Granite States rates to state regulation;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to allow Northern Utilities to recover prudently incurred integration costs for capitalized expenditures to build or upgrade systems or facilities
required to independently operate Northern Utilities;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | agreement not to seek recovery in Northern Utilities rates of any acquisition premium resulting from Unitils acquisition of Northern Utilities and that
any acquisition adjustment (positive or negative) shall be accounted for below the line for ratemaking purposes over a 10-year period;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to hold Northern Utilities customers harmless for the elimination of historical accumulated deferred income tax (ADIT) liabilities resulting from
its Internal Revenue Service Section 338(h)(10) election;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to use an imputed weighted cost of debt for ratemaking purposes until Northern Utilities existing debt instruments would have matured; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement not to change Northern Utilities existing depreciation rates for its Maine division until approved in the next general rate case.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements also contain the
following commitments related to customers:



| |  |  | agreement to implement a Low Income Program for Northern Utilities Maine division, to provide additional customer payment options (including credit or debit
cards and by internet and telephone) for Maine customers and to continue low income programs in Northern Utilities New Hampshire division;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to review with the parties to the settlements communications that we develop to inform Northern Utilities customers about our acquisition of
Northern Utilities and to keep them apprised of the transition; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | with respect to Maine, agreement to conduct a study of alternatives for the sale, lease, or use of the unused Portland manufactured gas site property that would
best serve ratepayers interests.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The
settlement agreements contain the following commitments related to service quality, gas safety and reliability:



| |  |  | agreement to improve and adhere to Northern Utilities existing service quality plans in each jurisdiction; and
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | agreement to provide notifications and safety reports based on several service quality and gas safety metrics, as well as implementing gas operations programs and
practices.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements contain
the following commitments related to Granite State:



| |  |  | agreement to work collaboratively with the parties to the settlements to design and to conduct a comprehensive study of the issues and costs for modification of the
physical, operational, regulatory, and corporate structure necessary for state regulation of Granite State and to provide a report within one year of the closing; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | authorization for Northern Utilities to execute a firm service contract with Granite State for 100,000 Dekatherms (Dth) of capacity at Granite States current
recourse rate of $1.6666/ Dth for the period November 1, 2008 through October 31, 2010.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The settlement agreements contain the following commitments regarding affiliate books and records and transaction reporting:



| |  |  | agreement to provide timely access to the books and records of any of Northern Utilities affiliates at the discretion of the MPUC or the NHPUC, as applicable;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to file reports on our transition progress, business integration, costs, the Transition Services Agreement and costs while our acquisition of Northern
Utilities was pending; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | agreement to notify the MPUC and the NHPUC of any substantial changes in the financing terms.
| | - |  | ---------------------------------------------------------------------------------------------



In Massachusetts, the GC Act expanded the authority of the MDPU to review
holding company mergers and sales of subsidiaries to determine how such transactions would affect the holding companies Massachusetts utility operating companies and their ratepayers. Unitil and Bay State filed a joint Petition with the
MDPU on August 13 seeking an advisory determination that the recent statutory amendment was inapplicable to the proposed sale, or, alternatively, sought approval of the proposed sale. The MDPU



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declined to issue the advisory ruling, and determined that it had the requisite authority to review the transaction. After investigation and hearing, the
MDPU issued its approval of the transaction on November 18, 2008.



Northern UtilitiesNotices of Probable ViolationBeginning in October 2007, the MPUC initiated formal investigations into a number of Notices of Probable Violation (NOPVs) alleging that Northern Utilities had violated
various provisions of the federal pipeline safety regulations, as adopted by the MPUC. Northern Utilities, the MPUC Staff and Unitil filed a comprehensive settlement (Settlement), which was approved by the MPUC on November 21, 2008, resolving
these matters. Under the Settlement, Northern Utilities will incur total expenditures of approximately $3.8 million for certain safety related improvements for which no rate recovery will be allowed and obligations to be undertaken for Northern
Utilities distribution system to ensure compliance with the relevant state and federal gas safety laws. These compliance costs were accrued by Northern Utilities prior to the acquisition date and the remaining amount on the Companys
balance sheet at December 31, 2008 was $3.1 million.



Northern UtilitiesNew Hampshire 2007/2008 Winter Cost of GasOn October 31, 2007, the NHPUC issued Order No. 24,798 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities New
Hampshire division. In that order, the NHPUC noted that Northern Utilities had identified an unusually high level of lost and unaccounted for gas (UAFG), and ordered Northern Utilities to file a detailed report concerning its investigation of this
matter. Through its investigation, Northern Utilities determined that the unaccounted for gas affected both its New Hampshire and Maine divisions, and that the cause appeared to be incorrect metering at the Maritimes & Northeast (M&NE)
/ Portland Natural Gas Transmission Systems (PNGTS) Newington Gate Station caused by an erroneous meter module change. The metering equipment was operated and maintained by a third party, Spectra Energy, the parent company of M&NE. PNGTS
and M&NE share joint ownership of the section of the pipeline connected to Granite State at the Newington Gate Station. The error caused Granite State to be billed for 758,702 Dth of natural gas, with Granite State then billing Northern
Utilities for an equivalent amount, although the volumes of gas were not actually consumed. The meter error was corrected and Northern Utilities, Granite State, Spectra Energy and PNGTS reached an agreement whereby PNGTS will provide to Northern
Utilities, through Granite State, gas volumes equal to the misread amounts to correct for the error, over a period of approximately 18 months. Both the NHPUC and the MPUC have approved this arrangement, as well as Northern Utilities
methodology for allocating the gas received to its Maine and New Hampshire divisions based upon the actual gas use over the period the meters were misread. As of December 31, 2008, Northern Utilities has recorded approximately $4.0 million
reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.



Northern UtilitiesMaine Capacity CostsIn its October 28, 2008 approval of Northern Utilities Maine Divisions Cost of
Gas Factor for the 2008-2009 Winter Period, the MPUC approved recovery of an additional $0.5 million of annual demand costs that had been inadvertently omitted from Northern Utilities reconciliation of the 2008-2009 Winter Period rates,
although analogous costs had been included in its calculation of 2007-2008 Winter Period rates. The MPUC determined that recovery of these Local Production Capacity Costs was consistent with previous MPUC orders.



Northern Utilities also reported that, upon investigation, these annual
demand costs, though approved, were incorrectly excluded from its reconciliation for five previous annual periods. The total impact for the five years is $2.4 million. On November 7, 2008, Northern Utilities filed a request with the MPUC
seeking an accounting order allowing it to defer and amortize for recovery these unrecovered gas costs over a three year period. This matter remains pending.



Granite StateGranite States interstate natural gas transmission pipeline system is regulated by the FERC under the Natural Gas Act, the
Natural Gas Policy Act of 1978, and the Energy Policy Act of 2005. Granite States system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms, and terms and conditions of service for its customers.
Additionally, interstate pipeline companies such as Granite State are subject to regulation by the U.S. Department of Transportation pursuant to the Natural Gas Pipeline Safety Act, which authorizes safety requirements in the design, construction,
operations and maintenance of interstate natural gas transmission facilities. Granite States last base rate case was resolved through stipulation and approved by the FERC on October 20, 1997. Granite States Phase II rates,
consistent with this stipulation became effective May 1, 1998.



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FERCWholesale Power
MarketsFitchburg, Unitil Energy and Unitil Power, as well as virtually all New England electric utilities, are market participants in the regional bulk power system administered by ISO-NE, the RTO in New England. 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 coordinated 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
utility operations because of the cost recovery mechanisms for wholesale energy and transmission costs approved by the NHPUC and MDPU.



Environmental Matters



The Companys past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws
and regulations. The Company believes it is in compliance with applicable environmental and safety laws and regulations, and the Company believes that as of December 31, 2008, there were no material losses reasonably likely to be incurred in
excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental
laws and regulations could result in increased environmental compliance costs.



Fitchburgs Manufactured Gas Plant SiteFitchburg 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. Fitchburg has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection, which allows Fitchburg to work towards
temporary closure of the site. A status of temporary closure requires Fitchburg to monitor the site until a feasible permanent remediation alternative can be developed and completed.



Fitchburg 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, Fitchburg is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods,
without carrying costs. In addition, Fitchburg 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 Fitchburg receives from insurance or
third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between Fitchburg and its gas customers.



Fitchburg 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, 2008 and 2007 in Environmental Obligations is $11.1 million and $12.0 million, respectively, related to estimated future
clean up costs for permanent remediation of the Sawyer Passway site. A corresponding Regulatory Asset was recorded to reflect that the recovery of this environmental remediation cost is probable through the regulatory process. The amounts recorded
do not assume any amounts are recoverable from insurance companies or other third parties.



Northern Utilities Manufactured Gas Plant SitesNorthern Utilities has an extensive program to identify, investigate and remediate former MGP sites that were operated from the mid 1800s through the mid
1900s. In New Hampshire, MGP sites were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. This program has also documented the presence of MGP sites in Lewiston and Portland, Maine and a former MGP disposal site in Scarborough,
Maine. Northern Utilities has worked with the environmental regulatory agencies in both New Hampshire and Maine to address environmental concerns with these sites.



Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, and
Scarborough sites. The sites in Lewiston and Portland have been



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investigated and remedial activities are currently underway. Future operation, maintenance and remedial costs have been accrued, although there will be
uncertainty regarding future costs until all remedial activities are completed.



The NHPUC and MPUC have approved the recovery of MGP environmental costs. For Northern Utilities New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization
period. Northern Utilities believes material future costs will be recovered. For Northern Utilities Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule.



Include in the Companys Consolidated Balance Sheet at
December 31, 2008 are current and non-current accrued liabilities totaling $1.6 million associated with Northern Utilities environmental remediation obligations for these former MGP sites. A corresponding Regulatory Asset was recorded to
reflect that the recovery of these environmental remediation cost is probable through the regulatory process.



The Companys ultimate liability for future environmental remediation costs, including MGP site 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 2008. The liability for
Environmental Obligations was initially recognized on the Companys Consolidated Balance Sheet at December 31, 2006.



ENVIRONMENTAL OBLIGATIONS



|                                                              |  |              |      |      |   |     
|------------------------------------------------------------- |  | ------------ | ---- | ---- | - | ----
|                                                              |  | December 31,
|(Millions)                                                    |  | 2008         |      | 2007
|Balance at Beginning of Period                                |  | $            | 12.0 |      | $ | 12.0
|Liabilities Assumed                                           |  |              | 1.6  |      |   |    
|Provision                                                     |  |              |     |      |   |    
|Payments / Reductions                                         |  |              | 0.9  |      |   |    
|                                                              |  |              |      |      |   |     
|Total Environmental ObligationsBalance at End of Period      |  |              | 12.7 |      |   | 12.0
|Less: Current Portion(1)                                      |  |              | 0.4  |      |   |    
|                                                              |  |              |      |      |   |     
|Environmental ObligationsnoncurrentBalance at End of Period |  | $            | 12.3 |      | $ | 12.0
|                                                              |  |              |      |      |   |     

---

|(1) | Reflects amounts included in Other Current Liabilities on the Companys Consolidated Balance Sheets.
|--- | ----------------------------------------------------------------------------------------------------



Note 8: Bad Debts



Unitils distribution utilities are authorized by regulators to recover
the costs of their energy commodity portion of bad debts through rate mechanisms. In 2006, 2007 and 2008, the Company recorded provisions for the energy commodity portion of bad debts of $1.7 million, $1.5 million and $2.1 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.



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The following table shows
the balances and activity in the Companys Allowance for Doubtful Accounts for 2006  2008.



ALLOWANCE FOR DOUBTFUL ACCOUNTS



|                             |  |                              |           |          |   |           |  |            |           |                     |   |                        |  |   |           |  |   |          
|---------------------------- |  | ---------------------------- | --------- | -------- | - | --------- |  | ---------- | --------- | ------------------- | - | ---------------------- |  | - | --------- |  | - | ---------
|                             |  | Balance atBeginningof Period |           | (a)Other |   | Provision |  | Recoveries |           | AccountsWritten Off |   | Balance atEnd ofPeriod
|Year Ended December 31, 2008 |  |                              |           |          |   |           |  |            |           |                     |   |                        |  |   |           |  |   |          
|Electric                     |  | $                            | 1,005,548 |          | $ |          |  | $          | 2,235,784 |                     | $ | 239,752                |  | $ | 2,334,627 |  | $ | 1,146,457
|Gas                          |  |                              | 225,301   |          |   | 1,361,889 |  |            | 1,430,914 |                     |   | 164,821                |  |   | 1,401,236 |  |   | 1,781,689
|Other                        |  |                              | 35,541    |          |   |          |  |            | 49,928    |                     |   | 2,364                  |  |   | 1,945     |  |   | 85,888   
|                             |  |                              |           |          |   |           |  |            |           |                     |   |                        |  |   |           |  |   |          
|                             |  | $                            | 1,266,390 |          | $ | 1,361,889 |  | $          | 3,716,626 |                     | $ | 406,937                |  | $ | 3,737,808 |  | $ | 3,014,034
|                             |  |                              |           |          |   |           |  |            |           |                     |   |                        |  |   |           |  |   |          
|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
|                             |  |                              |           |          |   |           |  |            |           |                     |   |                        |  |   |           |  |   |          

---

|(a) | Includes Allowance for Doubtful Accounts of Northern Utilities and Granite State, which were acquired on
December 1, 2008.
|--- | --------------------------------------------------------------------------------------------------------------------------



Note 9: Income Taxes



Federal Income Taxes were provided for the following
items for the years ended December 31, 2008, 2007 and 2006, respectively:



|                                                 |  |      |        |   |      |   |       |      |  |   |       |  
|------------------------------------------------ |  | ---- | ------ | - | ---- | - | ----- | ---- |  | - | ----- | -
|                                                 |  | 2008 |        |   | 2007 |   |       | 2006 | 
|Current Federal Tax Provision (Benefit) (000s): |  |      |        |   |      |   |       |      |  |   |       |  
|Operating Income                                 |  | $    | (2,914 | ) |      | $ | 4,522 |      |  | $ | 3,448 |  
|                                                 |  |      |        |   |      |   |       |      |  |   |       |  
|Total Current Federal Tax Provision (Benefit)    |  |      | (2,914 | ) |      |   | 4,522 |      |  |   | 3,448 |  
|                                                 |  |      |        |   |      |   |       |      |  |   |       |  
|Deferred Federal Tax Provision (Benefit) (000s) |  |      |        |   |      |   |       |      |  |   |       |  
|Depreciation and Utility Plant                   |  |      | 5,159  |   |      |   | (444  | )    |  |   | (656  | )
|Regulatory Assets and Liabilities                |  |      | 1,534  |   |      |   | (400  | )    |  |   | 790   |  
|Other, net                                       |  |      | 121    |   |      |   | 60    |      |  |   | 184   |  
|                                                 |  |      |        |   |      |   |       |      |  |   |       |  
|Total Deferred Federal Tax Provision (Benefit)   |  |      | 6,814  |   |      |   | (784  | )    |  |   | 318   |  
|                                                 |  |      |        |   |      |   |       |      |  |   |       |  
|Total Federal Tax Provision                      |  | $    | 3,900  |   |      | $ | 3,738 |      |  | $ | 3,766 |  
|                                                 |  |      |        |   |      |   |       |      |  |   |       |  



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, 2008, 2007 and 2006 are shown in the table below. In addition to the provisions for
federal and state income taxes, the Company recorded provisions of $165,000, $203,000 and $211,000 in 2008, 2007 and 2006, respectively for state Business Enterprise taxes, which are included in Local Property and Other Taxes on the consolidated
statements of earnings.



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|                                                   |  |      |        |   |      |   |       |      |  |   |      
|-------------------------------------------------- |  | ---- | ------ | - | ---- | - | ----- | ---- |  | - | -----
|Federal and State Tax Provision (Benefit) (000s)  |  | 2008 |        |   | 2007 |   |       | 2006
|Federal                                            |  |      |        |   |      |   |       |      |  |   |      
|Current                                            |  | $    | (2,914 | ) |      | $ | 4,522 |      |  | $ | 3,448
|Deferred                                           |  |      | 6,814  |   |      |   | (784  | )    |  |   | 318  
|                                                   |  |      |        |   |      |   |       |      |  |   |      
|Total Federal Tax Provision                        |  |      | 3,900  |   |      |   | 3,738 |      |  |   | 3,766
|                                                   |  |      |        |   |      |   |       |      |  |   |      
|State                                              |  |      |        |   |      |   |       |      |  |   |      
|Current                                            |  |      | (42    | ) |      |   | 896   |      |  |   | 337  
|Deferred                                           |  |      | 592    |   |      |   | (138  | )    |  |   | 163  
|                                                   |  |      |        |   |      |   |       |      |  |   |      
|Total State Tax Provision                          |  |      | 550    |   |      |   | 758   |      |  |   | 500  
|                                                   |  |      |        |   |      |   |       |      |  |   |      
|Total Provision for Federal and State Income Taxes |  | $    | 4,450  |   |      | $ | 4,496 |      |  | $ | 4,266
|                                                   |  |      |        |   |      |   |       |      |  |   |      



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:



|                                  |  |      |   |  |      |   |  |      |  
|--------------------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|                                  |  | 2008 |   |  | 2007 |   |  | 2006 |  
|Statutory Federal Income Tax Rate |  | 34   | % |  | 34   | % |  | 34   | %
|Income Tax Effects of:            |  |      |   |  |      |   |  |      |  
|State Income Taxes, Net           |  | 5    |   |  | 5    |   |  | 5    |  
|Utility Plant Differences         |  | (6   | ) |  | (4   | ) |  | (4   | )
|Tax Credits and Other, Net        |  | (1   | ) |  |     |   |  | 1    |  
|                                  |  |      |   |  |      |   |  |      |  
|Effective Income Tax Rate         |  | 32   | % |  | 35   | % |  | 36   | %
|                                  |  |      |   |  |      |   |  |      |  



Temporary differences,
including the effect of deferred tax accounting on the assets and liabilities of Northern Utilities and Granite State acquired on December 1, 2008 (see Note 3 above), which gave rise to deferred tax assets and liabilities are shown below:



|                                             |  |      |         |   |      |   |         |  
|-------------------------------------------- |  | ---- | ------- | - | ---- | - | ------- | -
|Deferred Income Taxes (000s)                |  | 2008 |         |   | 2007 |  
|Depreciation and Utility Plant               |  | $    | 26,719  |   |      | $ | 27,356  |  
|Regulatory Assets / Liabilities & Mechanisms |  |      | 30,071  |   |      |   | 23,239  |  
|Retirement Benefit Obligations               |  |      | (23,029 | ) |      |   | (15,585 | )
|Other                                        |  |      | (2,677  | ) |      |   | (1,627  | )
|                                             |  |      |         |   |      |   |         |  
|Total Deferred Income Tax Liabilities        |  | $    | 31,084  |   |      | $ | 33,383  |  
|                                             |  |      |         |   |      |   |         |  



The Company evaluated
its tax positions at December 31, 2008 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, 2005; December 31, 2006; and December 31, 2007. Income tax filings for the year ended December 31, 2008 are due March 15, 2009 but likely
will be extended until September 15, 2009. 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 10: 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:



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| |  |  | 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.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Effective with
the acquisitions of Northern Utilities and Granite State, the Company assumed the assets and obligations of the Northern Utilities and Granite State pension plans with respect to active union employees. All other active employees of Northern
Utilities and Granite State effectively became members of the Companys Pension Plan as of the acquisitions closing date.



Certain employees of Northern Utilities qualified for participation in the Companys PBOP Plan effective with the acquisition closing date.



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:    |  | 2008 |        |   | 2007 |   |        | 2006 | 
|Discount Rate                                                |  |      | 6.00   | % |      |   | 5.50   | %    |  |   | 5.50   | %
|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   | % |      |   | 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) |  | $    | 675    |   |      | $ | 690    |      |  | $ | 683    |  
|Effect of 1% Decrease in Health Care Cost Trend Rate (000s) |  | $    | (531   | ) |      | $ | (539   | )    |  | $ | (530   | )
|                                                             |  |      |       
|Used to Determine Benefit Obligations at December 31:        |  |      |        |   |      |   |        |      | 
|Discount Rate                                                |  |      | 6.25   | % |      |   | 6.00   | %    |  |   | 5.50   | %
|Rate of Compensation Increase                                |  |      | 3.50   | % |      |   | 3.50   | %    |  |   | 3.50   | %
|Health Care Cost Trend Rate Assumed for Next Year            |  |      | 8.00   | % |      |   | 8.50   | %    |  |   | 8.50   | %
|Ultimate Health Care Cost Trend Rate                         |  |      | 4.00   | % |      |   | 4.00   | %    |  |   | 4.00   | %
|Year that Ultimate Health care Cost Trend Rate is reached    |  |      | 2017   |   |      |   | 2017   |      |  |   | 2016   |  
|Effect of 1% Increase in Health Care Cost Trend Rate (000s) |  | $    | 6,084  |   |      | $ | 6,282  |      |  | $ | 6,381  |  
|Effect of 1% Decrease in Health Care Cost Trend Rate (000s) |  | $    | (4,890 | ) |      | $ | (5,030 | )    |  | $ | (5,091 | )



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 2008, 2007 and 2006, a change
in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 in the Net Periodic Benefit Cost (NPBC). The Rate of Compensation Increase assumption used for 2008, 2007 and 2006 was 3.50%, based on the
expected long-term increase in compensation costs for personnel covered by the plans.



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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 Allocation2009 |      |  | Actual Allocation at December 31, |     
|                  |  |                       | 2008 |  |                                   | 2007 |  |     | 2006 | 
|Equity Securities |  | 58                    | %    |  | 54                                | %    |  | 57  | %    |  | 61  | %
|Debt Securities   |  | 32                    | %    |  | 35                                | %    |  | 43  | %    |  | 39  | %
|Other             |  | 10                    | %    |  | 11                                | %    |  | 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 2008. 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 | 
|                                   |  | 2008         |        |   | 2007      |   |        | 2006 |  |   | 2008   |   |  | 2007 |        |   | 2006 |   |        | 2008 |  |   | 2007   |   |  | 2006 |    
|                                   |  |              |        |   |           |   |        |      | 
|Service Cost                       |  | $            | 1,979  |   |           | $ | 1,968  |      |  | $ | 1,800  |   |  | $    | 1,447  |   |      | $ | 1,431  |      |  | $ | 1,283  |   |  | $    | 150 |   |  | $ | 163 |   |  | $ | 148 |  
|                                   |  |              |        |   |           |   |        |      | 
|Interest Cost                      |  |              | 3,800  |   |           |   | 3,336  |      |  |   | 3,153  |   |  |      | 2,212  |   |      |   | 2,057  |      |  |   | 2,028  |   |  |      | 126 |   |  |   | 118 |   |  |   | 103 |  
|                                   |  |              |        |   |           |   |        |      | 
|Expected Return on Plan Assets     |  |              | (4,390 | ) |           |   | (4,195 | )    |  |   | (3,775 | ) |  |      | (325   | ) |      |   | (245   | )    |  |   | (194   | ) |  |      |    |   |  |   |    |   |  |   |    |  
|                                   |  |              |        |   |           |   |        |      | 
|Prior Service Cost Amortization    |  |              | 119    |   |           |   | 106    |      |  |   | 107    |   |  |      | 1,390  |   |      |   | 1,360  |      |  |   | 1,360  |   |  |      | (1  | ) |  |   | (2  | ) |  |   | (2  | )
|                                   |  |              |        |   |           |   |        |      | 
|Transition Obligation Amortization |  |              |       |   |           |   |       |      |  |   |       |   |  |      | 21     |   |      |   | 21     |      |  |   | 21     |   |  |      |    |   |  |   |    |   |  |   | 17  |  
|                                   |  |              |        |   |           |   |        |      | 
|Actuarial Loss Amortization        |  |              | 1,274  |   |           |   | 1,345  |      |  |   | 1,324  |   |  |      |       |   |      |   | 70     |      |  |   | 160    |   |  |      | 24  |   |  |   | 44  |   |  |   | 39  |  
|                                   |  |              |        |   |           |   |        |      | 
|                                   |  |              |        |   |           |   |        |      |  |   |        |   |  |      |        |   |      |   |        |      |  |   |        |   |  |      |     |   |  |   |     |   |  |   |     |  
|                                   |  |              |        |   |           |   |        |      | 
|Sub-total                          |  |              | 2,782  |   |           |   | 2,560  |      |  |   | 2,609  |   |  |      | 4,745  |   |      |   | 4,694  |      |  |   | 4,658  |   |  |      | 299 |   |  |   | 323 |   |  |   | 305 |  
|                                   |  |              |        |   |           |   |        |      | 
|Amounts Capitalized and Deferred   |  |              | (893   | ) |           |   | (873   | )    |  |   | (1,014 | ) |  |      | (1,872 | ) |      |   | (2,033 | )    |  |   | (2,217 | ) |  |      |    |   |  |   |    |   |  |   |    |  
|                                   |  |              |        |   |           |   |        |      | 
|                                   |  |              |        |   |           |   |        |      |  |   |        |   |  |      |        |   |      |   |        |      |  |   |        |   |  |      |     |   |  |   |     |   |  |   |     |  
|                                   |  |              |        |   |           |   |        |      | 
|NPBC Recognized                    |  | $            | 1,889  |   |           | $ | 1,687  |      |  | $ | 1,595  |   |  | $    | 2,873  |   |      | $ | 2,661  |      |  | $ | 2,441  |   |  | $    | 299 |   |  | $ | 323 |   |  | $ | 305 |  
|                                   |  |              |        |   |           |   |        |      |  |   |        |   |  |      |        |   |      |   |        |      |  |   |        |   |  |      |     |   |  |   |     |   |  |   |     |  



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 $1.9 million, $1.7 million and $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 2008, 2007 and 2006 before capitalization and deferral was $2.8
million, $2.6 million and $2.6 million, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2008, 2007 and 2006 would have been $2.9 million, $2.5 million and $2.8 million
respectively.



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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:           |  | 2008         |         |   | 2007      |   |         | 2008 |  |   | 2007    |   |  | 2008 |         |   | 2007 |  
|                                 |  |              |         |   |           |  
|Plan Assets at Beginning of Year |  | $            | 52,162  |   |           | $ | 49,527  |      |  | $ | 4,144   |   |  | $    | 3,052   |   |      | $ |       |   |  | $ |       |  
|                                 |  |              |         |   |           |  
|Actual Return on Plan Assets     |  |              | (15,542 | ) |           |   | 2,480   |      |  |   | (784    | ) |  |      | 89      |   |      |   |       |   |  |   |       |  
|                                 |  |              |         |   |           |  
|Employer Contributions           |  |              | 2,800   |   |           |   | 2,800   |      |  |   | 2,700   |   |  |      | 2,500   |   |      |   | 59     |   |  |   | 72     |  
|                                 |  |              |         |   |           |  
|Estimated Acquired Plan Assets   |  |              | 2,500   |   |           |   |        |      |  |   |        |   |  |      |        |   |      |   |       |   |  |   |       |  
|                                 |  |              |         |   |           |  
|Benefits Paid                    |  |              | (2,796  | ) |           |   | (2,645  | )    |  |   | (1,699  | ) |  |      | (1,497  | ) |      |   | (59    | ) |  |   | (72    | )
|                                 |  |              |         |   |           |  
|                                 |  |              |         |   |           |   |         |      |  |   |         |   |  |      |         |   |      |   |        |   |  |   |        |  
|                                 |  |              |         |   |           |  
|Plan Assets at End of Year       |  | $            | 39,124  |   |           | $ | 52,162  |      |  | $ | 4,361   |   |  | $    | 4,144   |   |      | $ |       |   |  | $ |       |  
|                                 |  |              |         |   |           |   |         |      |  |   |         |   |  |      |         |   |      |   |        |   |  |   |        |  
|                                 |  |              |         |   |           |  
|Change in PBO:                   |  |              |         |   |           |   |         |      |  |   |         |   |  |      |         |   |      |  
|                                 |  |              |         |   |           |  
|PBO at Beginning of Year         |  | $            | 64,429  |   |           | $ | 62,027  |      |  | $ | 37,983  |   |  | $    | 38,107  |   |      | $ | 2,144  |   |  | $ | 2,179  |  
|                                 |  |              |         |   |           |  
|Service Cost                     |  |              | 1,979   |   |           |   | 1,968   |      |  |   | 1,447   |   |  |      | 1,431   |   |      |   | 150    |   |  |   | 163    |  
|                                 |  |              |         |   |           |  
|Interest Cost                    |  |              | 3,800   |   |           |   | 3,336   |      |  |   | 2,212   |   |  |      | 2,057   |   |      |   | 126    |   |  |   | 118    |  
|                                 |  |              |         |   |           |  
|Estimated Acquired Obligations   |  |              | 4,442   |   |           |   |        |      |  |   | 2,610   |   |  |      |        |   |      |   |       |   |  |   |       |  
|                                 |  |              |         |   |           |  
|Benefits Paid                    |  |              | (2,796  | ) |           |   | (2,645  | )    |  |   | (1,699  | ) |  |      | (1,497  | ) |      |   | (59    | ) |  |   | (72    | )
|                                 |  |              |         |   |           |  
|Actuarial (Gain) or Loss         |  |              | (1,468  | ) |           |   | (257    | )    |  |   | (4,898  | ) |  |      | (2,115  | ) |      |   | 569    |   |  |   | (244   | )
|                                 |  |              |         |   |           |  
|                                 |  |              |         |   |           |   |         |      |  |   |         |   |  |      |         |   |      |   |        |   |  |   |        |  
|                                 |  |              |         |   |           |  
|PBO at End of Year               |  | $            | 70,386  |   |           | $ | 64,429  |      |  | $ | 37,655  |   |  | $    | 37,983  |   |      | $ | 2,930  |   |  | $ | 2,144  |  
|                                 |  |              |         |   |           |  
|                                 |  |              |         |   |           |   |         |      |  |   |         |   |  |      |         |   |      |   |        |   |  |   |        |  
|                                 |  |              |         |   |           |  
|Funded Status: Assets vs PBO     |  | $            | (31,262 | ) |           | $ | (12,267 | )    |  | $ | (33,294 | ) |  | $    | (33,839 | ) |      | $ | (2,930 | ) |  | $ | (2,144 | )
|                                 |  |              |         |   |           |   |         |      |  |   |         |   |  |      |         |   |      |   |        |   |  |   |        |  



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 $45.5 million and $35.1 million at December 31, 2008 and 2007, respectively, to recognize the future collection of these plan obligations in electric and gas 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 $61.1 million and $55.1 million as of December 31, 2008 and 2007, respectively. The ABO for the SERP was $0.5 million and $0.6 million as of December 31, 2008 and 2007,
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 were new minimum funding rules which went into effect for plan years beginning in 2008. The funding target was 100% of a plans
liability (as determined under the PPA) with any shortfall amortized over seven years, with lower (92% - 100%) funding targets available to well-funded plans during the transition period. Due to the significant declines in the valuation of
capital markets during 2008, the Worker, Retiree, and Employer Recovery Act of 2008 (Recovery Act) was signed into law on December 23, 2008. Included in the Recovery Act are temporary modifications to the minimum funding rules set forth in the
PPA such that all plans, except those that were subject to deficit reduction contribution requirements in



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2007, are allowed to amortize any shortfall from the lower funding targets, rather than the 100% target, for the 2008 - 2010 plan years. This did not affect
the Companys Pension Plan in 2008 as its Pension Plan was 99% funded under the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) as of January 1, 2008 and met the exemption from the shortfall amortization. The
Company expects to contribute approximately $4.0 million to fund its Pension Plan in 2009.



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



|                       |  |              |       |           |   |       |  |      |       |      |   |       |  |      |       |      |   |       |  |   |    |  |   |    |  |   |   
|---------------------- |  | ------------ | ----- | --------- | - | ----- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ----- |  | - | -- |  | - | -- |  | - | --
|                       |  | Pension Plan |       | PBOP Plan |   | SERP 
|                       |  | 2008         |       | 2007      |   | 2006  |  | 2008 |       | 2007 |   | 2006  |  | 2008 |       | 2007 |   | 2006 
|Employer Contributions |  | $            | 2,800 |           | $ | 2,800 |  | $    | 2,510 |      | $ | 2,700 |  | $    | 2,500 |      | $ | 2,210 |  | $ | 59 |  | $ | 72 |  | $ | 72
|Benefit Payments       |  | $            | 2,796 |           | $ | 2,645 |  | $    | 2,476 |      | $ | 1,699 |  | $    | 1,497 |      | $ | 1,540 |  | $ | 59 |  | $ | 72 |  | $ | 72



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



|                                  |  |         |        |      |   |        |  |   |      
|--------------------------------- |  | ------- | ------ | ---- | - | ------ |  | - | -----
|Estimated Future Benefit Payments
|                                  |  | Pension |        | PBOP |   | SERP  
|2009                              |  | $       | 3,356  |      | $ | 1,360  |  | $ | 52   
|2010                              |  |         | 3,557  |      |   | 1,554  |  |   | 51   
|2011                              |  |         | 3,718  |      |   | 1,709  |  |   | 50   
|2012                              |  |         | 3,834  |      |   | 1,844  |  |   | 49   
|2013                              |  |         | 4,166  |      |   | 1,983  |  |   | 315  
|2014 - 2018                       |  | $       | 23,669 |      | $ | 11,555 |  | $ | 1,551



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 $542,000, $533,000 and $528,000 for the years ended December 31, 2008, 2007, and 2006, respectively.



Note 11: Segment Information



Unitil reports four segments: utility electric operations, utility gas
operations, other, and non-regulated. Unitils principal business is the local distribution of electricity in the southeastern seacoast and state capitol regions of New Hampshire and the greater Fitchburg area of north central Massachusetts and
the local distribution of natural gas in southeastern New Hampshire, portions of southern Maine to the Lewiston-Auburn area and in the greater Fitchburg area of north central Massachusetts. Unitil has three distribution utility subsidiaries, Unitil
Energy, which operates in New Hampshire, Fitchburg, which operates in Massachusetts and Northern Utilities, which operates in New Hampshire and Maine.



Granite State is an interstate natural gas transmission pipeline company, operating 87 miles of underground gas transmission pipeline primarily located in
Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State
derives its revenues principally from the transmission services provided to Northern Utilities and, to a lesser extent, third-party marketers.



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.



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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, MDPU, and MPUC. Assets allocated to each segment are based
upon specific identification of such assets provided by Company records.



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The following table provides
significant segment financial data for the years ended December 31, 2008, 2007 and 2006 (Millions):



|                                    |  |          |       |     |   |       |  |   |               |   |  |       |      |   |  |   |      
|----------------------------------- |  | -------- | ----- | --- | - | ----- |  | - | ------------- | - |  | ----- | ---- | - |  | - | -----
|Year Ended December 31, 2008        |  | Electric |       | Gas |   | Other |  |   | Non-Regulated |   |  | Total
|                                    |  |          |       |     |  
|Revenues                            |  | $        | 227.5 |     | $ | 56.9  |  | $ |              |   |  | $     | 3.8  |   |  | $ | 288.2
|                                    |  |          |       |     |  
|Interest Income                     |  |          | 2.2   |     |   | 0.1   |  |   | 0.3           |   |  |       |     |   |  |   | 2.6  
|                                    |  |          |       |     |  
|Interest Expense                    |  |          | 8.7   |     |   | 2.3   |  |   | 2.1           |   |  |       |     |   |  |   | 13.1 
|                                    |  |          |       |     |  
|Depreciation & Amortization Expense |  |          | 13.1  |     |   | 5.2   |  |   | 0.8           |   |  |       |     |   |  |   | 19.1 
|                                    |  |          |       |     |  
|Income Tax Expense (Benefit)        |  |          | 1.9   |     |   | 2.6   |  |   | (0.3          | ) |  |       | 0.2  |   |  |   | 4.4  
|                                    |  |          |       |     |  
|Segment Profit (Loss)               |  |          | 5.2   |     |   | 4.3   |  |   | (0.2          | ) |  |       | 0.3  |   |  |   | 9.6  
|                                    |  |          |       |     |  
|Segment Assets                      |  |          | 351.9 |     |   | 362.3 |  |   | 20.0          |   |  |       | 1.0  |   |  |   | 735.2
|                                    |  |          |       |     |  
|Capital Expenditures                |  |          | 19.7  |     |   | 7.6   |  |   | 1.0           |   |  |       |     |   |  |   | 28.3 
|                                    |  |          |       |     |  
|Year Ended December 31, 2007        |  |          |       |     |   |       |  |   |               |   |  |      
|                                    |  |          |       |     |  
|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 



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Note 12: 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,
|                                |  | 2008               |       | 2007     |   | 2008          |  | 2007         |       | 2008 |   | 2007  |  | 2008 |       | 2007
|                                |  |                    |       |          |   |               |  |             
|Total Operating Revenues        |  | $                  | 71.9  |          | $ | 77.8          |  | $            | 59.4  |      | $ | 59.0  |  | $    | 69.1  |      | $ | 61.8  |  | $ | 87.8  |  | $ | 64.3 
|                                |  |                    |       |          |   |               |  |             
|Operating Income                |  | $                  | 6.0   |          | $ | 4.7           |  | $            | 4.2   |      | $ | 4.3   |  | $    | 3.9   |      | $ | 3.9   |  | $ | 6.4   |  | $ | 5.6  
|                                |  |                    |       |          |   |               |  |             
|Net Income Applicable to Common |  | $                  | 3.3   |          | $ | 2.6           |  | $            | 1.6   |      | $ | 1.7   |  | $    | 1.5   |      | $ | 1.6   |  | $ | 3.2   |  | $ | 2.7  
|                                | 
|                                |  | Per Share Data:   
|                                |  |                    |       |          |   |               |  |             
|Earnings Per Common Share       |  | $                  | 0.57  |          | $ | 0.46          |  | $            | 0.28  |      | $ | 0.30  |  | $    | 0.27  |      | $ | 0.28  |  | $ | 0.53  |  | $ | 0.48 
|                                |  |                    |       |          |   |               |  |             
|Dividends Paid Per Common Share |  | $                  | 0.345 |          | $ | 0.345         |  | $            | 0.345 |      | $ | 0.345 |  | $    | 0.345 |      | $ | 0.345 |  | $ | 0.345 |  | $ | 0.345



Note 13: Unaudited Pro Forma
Financial Data Related To Acquisitions



On December 1,
2008, the Company acquired Northern Utilities and Granite State, as discussed in Note 3. Had the results of operations for Northern Utilities and Granite State been combined with the Company as of the beginning of 2007, the Companys pro forma
results for 2008 and 2007 would have been as follows:



|                                                 |  |                         |       |      |   |      
|------------------------------------------------ |  | ----------------------- | ----- | ---- | - | -----
|                                                 |  | Year ended December 31,
|(Millions, except per share amounts) (Unaudited) |  | 2008                    |       | 2007
|                                                 |  |                        
|Revenues                                         |  | $                       | 395.5 |      | $ | 396.2
|                                                 |  |                        
|Earnings Applicable to Common Shareholders       |  | $                       | 6.9   |      | $ | 10.2 
|                                                 |  |                        
|Earnings per Share                               |  |                         |       |      |   |      
|Basic                                            |  | $                       | 0.88  |      | $ | 1.33 
|Diluted                                          |  | $                       | 0.88  |      | $ | 1.33 



The Unaudited Pro
Forma Financial Data include non-recurring charges to operating expenses of $1.7 million, after tax, related to compliance violation penalties incurred by Northern Utilities in 2007 and $2.5 million, after tax, related to compliance violation
penalties incurred by Northern Utilities in 2008.



The
Unaudited Pro Forma Financial Data are presented for illustrative purposes only and do not indicate the financial results of the combined companies had the companies actually been combined and had the impact of possible revenue enhancements and
expense efficiencies, among other factors, been considered, and is not intended to be a projection of future results.



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|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, 2008. Based upon this evaluation, the Companys Chief
Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded as of December 31, 2008 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 2008, 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).



Our
assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Northern Utilities, Inc. and Granite State Gas Transmission, Inc., businesses that we acquired on
December 1, 2008 and which are included in the Companys 2008 consolidated financial statements. Total assets for Northern Utilities and Granite State were $250.8 million and $22.9 million, respectively, as of December 31, 2008. Total
revenues for Northern Utilities and Granite State were $21.8 million and $0.4 million, respectively, for the year ended December 31, 2008, reflecting the period of December 1, 2008 through December 31, 2008.



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,
2008.



The effectiveness of our internal control over financial
reporting as of December 31, 2008 has been audited by Vitale, Caturano and Company, an independent registered public accounting firm. Their report appears in Item 8.



87



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##### Table of Contents

Changes in Internal Control over Financial Reporting



There have been no changes in our internal controls over financial reporting
(as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the fiscal quarter ended December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial
reporting.



|Item 9B. | Other Information
|-------- | -----------------



None



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##### Table of Contents

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 Proxy Statement relating to the Annual Meeting of Shareholders to be held April 16, 2009.



|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 Proxy Statement relating to the Annual Meeting of Shareholders to be held April 16, 2009.



|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 Proxy Statement relating to the Annual Meeting of Shareholders to be held April 16, 2009, 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 Proxy Statement relating to the
Annual Meeting of Shareholders to be held April 16, 2009.



89



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##### Table of Contents

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, 2008 and 2007
| | - |  | ------------------------------------------------------



| |  |  | Consolidated Statements of Earnings for the years ended December 31, 2008, 2007, and 2006
| | - |  | -----------------------------------------------------------------------------------------



| |  |  | Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007, and 2006
| | - |  | -------------------------------------------------------------------------------------------



| |  |  | Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2008, 2007, and 2006
| | - |  | ---------------------------------------------------------------------------------------------------------------



| |  |  | 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 Statement2-93769
|               |  |                                                                                                                                                               
|3.2            |  | Articles of Amendment to the Articles of Incorporation Filed on March 4, 1992.                                                                                 |  | Exhibit 3.2 to Form 10-K for 1991                     
|               |  |                                                                                                                                                               
|3.3            |  | Articles of Amendment to the Articles of Incorporation Filed on September 23, 2008.                                                                            |  | Exhibit 3.3 to Form S-3/A dated November 25, 2008     
|               |  |                                                                                                                                                               
|3.4            |  | By-laws of the Company.                                                                                                                                        |  | Exhibit 4 to Form S-8 Registration Statement 333-73327
|               |  |                                                                                                                                                               
|3.5            |  | 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                          
|               |  |                                                                                                                                                               
|3.6            |  | 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                     
|               |  |                                                                                                                                                               
|3.7            |  | The Agreement and Plan of Merger dated March 1, 1989 among the Company, Fitchburg Gas and Electric Light Company (Fitchburg) and UMC Electric Co., Inc. (UMC). |  | Exhibit 25(b) to Form 8-K dated March 1, 1989         
|               |  |                                                                                                                                                               
|3.8            |  | Amendment No. 1 to The Agreement and Plan of Merger dated March 1, 1989 among the Company, Fitchburg and UMC.                                                  |  | Exhibit 28(b) to Form 8-K dated December 14, 1989     



90



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##### Table of Contents

|               |  |                                                                                                                                                                                                                                                            |  |                                                 
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------------
|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            |  | Fitchburg Note Agreement dated November 30, 1993 for the 6.75% Notes due November 23, 2023.                                                                                                                                                                |  | Exhibit 4.18 to Form 10-K for 1993              
|               |  |                                                                                                                                                                                                                                                           
|4.3            |  | Fitchburg Note Agreement dated January 26, 1999 for the 7.37% Notes due January 15, 2028.                                                                                                                                                                  |  | Exhibit 4.25 to Form 10-K for 1999              
|               |  |                                                                                                                                                                                                                                                           
|4.4            |  | Fitchburg 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      
|               |  |                                                                                                                                                                                                                                                           
|4.5            |  | 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              
|               |  |                                                                                                                                                                                                                                                           
|4.6            |  | Fitchburg Note Agreement dated October 15, 2003 for the 6.79% Notes due October 15, 2025.                                                                                                                                                                  |  | Exhibit 4.7 to Form 10-K for 2003               
|               |  |                                                                                                                                                                                                                                                           
|4.7            |  | Fitchburg Note Agreement dated December 21, 2005 for the 5.90% Notes due December 15, 2030.                                                                                                                                                                |  | **                                              
|               |  |                                                                                                                                                                                                                                                           
|4.8            |  | Thirteenth Supplemental Indenture of Unitil Energy Systems, Inc., dated as of September 26, 2006.                                                                                                                                                          |  | **                                              
|               |  |                                                                                                                                                                                                                                                           
|4.9            |  | Unitil Corporation Note Purchase Agreement, dated as of May 2, 2007, for the 6.33% Senior Notes due May 1, 2022.                                                                                                                                           |  | **                                              
|               |  |                                                                                                                                                                                                                                                           
|4.10           |  | Northern Utilities Note Purchase Agreement, dated as of December 3, 2008, for the 6.95% Senior Notes, Series A due December 3, 2018 and the 7.72% Senior Notes, Series B due December 3, 2038.                                                             |  | Exhibit 4.1 to Form 8-K dated December 3, 2008  
|               |  |                                                                                                                                                                                                                                                           
|4.11           |  | Granite State Note Purchase Agreement, dated as of December 15, 2008, for the 7.15% Senior Notes due December 15, 2018                                                                                                                                     |  | Exhibit 99.1 to Form 8-K dated December 15, 2008
|               |  |                                                                                                                                                                                                                                                           
|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***        |  | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.                                                                                                                                  |  | Exhibit 10.2 to Form 8-K datedJune 19, 2008     
|               |  |                                                                                                                                                                                                                                                           
|10.5***        |  | Amended and Restated Form of Severance Agreement between the Company and the persons listed at the end of such Agreement.                                                                                                                                  |  | Exhibit 10.3 to Form 8-K datedJune 19,
2008     
|               |  |                                                                                                                                                                                                                                                           
|10.6***        |  | Amended and Restated Unitil Corporation Supplemental Executive Retirement Plan effective as of December 31, 2007.                                                                                                                                          |  | Exhibit 10.4 to Form 8-K datedJune 19,
2008     



91



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##### Table of Contents

|               |  |                                                                                                                                                                                                  |  |                                                 
|-------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ------------------------------------------------
|Exhibit Number |  | Description of Exhibit                                                                                                                                                                           |  | Reference*                                      
|10.7***        |  | Unitil Corporation 1998 Stock Option Plan.                                                                                                                                                       |  | Exhibit 10.12 to Form 10-K for 1998             
|               |  |                                                                                                                                                                                                 
|10.8***        |  | Amended and Restated Unitil Corporation Management Incentive Plan effective as of June 19, 2008 as further amended on December 1, 2008.                                                          |  | Filed herewith                                  
|               |  |                                                                                                                                                                                                 
|10.9           |  | Entitlement Sale and Administrative Service Agreement with Select Energy.                                                                                                                        |  | Exhibit 10.14 to Form 10-K for 1999             
|               |  |                                                                                                                                                                                                 
|10.10***       |  | Unitil Corporation 2003 Restricted Stock Plan.                                                                                                                                                   |  | Exhibit 10.16 to Form 10-K for 2002             
|               |  |                                                                                                                                                                                                 
|10.11          |  | 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             
|               |  |                                                                                                                                                                                                 
|10.12          |  | Unitil Corporation Tax Deferred Savings and Investment Plan  Trust Agreement.                                                                                                                   |  | Exhibit 10.1 to Form 10-Q for September 30, 2004
|               |  |                                                                                                                                                                                                 
|10.13***       |  | Amended and Restated Employment Agreement effective as of June 30, 2008 by and between Unitil Corporation and Robert G. Schoenberger.                                                            |  | Exhibit 10.1 to Form 8-K dated June 19, 2008    
|               |  |                                                                                                                                                                                                 
|10.14          |  | Credit Agreement between Unitil Corporation and Bank of America, N.A. dated November 26, 2008                                                                                                    |  | Exhibit 10.1 to Form 8-K dated November 26, 2008
|               |  |                                                                                                                                                                                                 
|10.15          |  | Amendment Agreement dated as of January 2, 2009 to the Credit Agreement between Unitil Corporation and Bank of America, N.A. dated November 26, 2008                                             |  | Exhibit 10.1 to Form 8-K dated January 2, 2009  
|               |  |                                                                                                                                                                                                 
|10.16          |  | Credit Agreement between Unitil Corporation and Royal Bank of Canada dated December 1, 2008                                                                                                      |  | Exhibit 10.2 to Form 8-K dated November 26, 2008
|               |  |                                                                                                                                                                                                 
|10.17          |  | Transition Services Agreement between Unitil Corporation and NiSource, Inc. dated December 1, 2008                                                                                               |  | Exhibit 10.3 to Form 8-K dated November 26, 2008
|               |  |                                                                                                                                                                                                 
|10.18          |  | Parent Guaranty of Unitil Corporation for the Granite State 7.15% Senior Notes due December 15, 2018                                                                                             |  | Exhibit 10.1 to Form 8-K dated December 15, 2008
|               |  |                                                                                                                                                                                                 
|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                                  
|               |  |                                                                                                                                                                                                 
|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                                  



92



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|               |  |                                                                                                                                                                                                           |  |               
|-------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------
|Exhibit Number |  | Description of Exhibit                                                                                                                                                                                    |  | Reference*    
|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.
|-- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|*** | These exhibits represent a management contract or compensatory plan.
|--- | --------------------------------------------------------------------



93



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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 18, 2009 |  |  |  | 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. SCHOENBERGERRobert G. Schoenberger   |  | Principal Executive Officer; Director |  | February 18, 2009
|                                                      |  |                                      
|/S/    MARK H. COLLINMark H. Collin                   |  | Principal Financial Officer           |  | February 18, 2009
|                                                      |  |                                      
|/S/    LAURENCE M. BROCKLaurence M. Brock             |  | Principal Accounting Officer          |  | February 18, 2009
|                                                      |  |                                      
|/S/    MICHAEL J. DALTONMichael J. Dalton             |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    ALBERT H. ELFNER, IIIAlbert H. Elfner, III     |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    M. BRIAN OSHAUGHNESSYM. Brian OShaughnessy   |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    CHARLES H. TENNEY, IIICharles H. Tenney, III   |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    DR. SARAH P. VOLLDr. Sarah P. Voll             |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    EBEN S. MOULTONEben S. Moulton                 |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    DAVID P. BROWNELLDavid P. Brownell             |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    EDWARD F. GODFREYEdward F. Godfrey             |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    MICHAEL B. GREENMichael B. Green               |  | Director                              |  | February 18, 2009
|                                                      |  |                                      
|/S/    DR. ROBERT V. ANTONUCCIDr. Robert V. Antonucci |  | Director                              |  | February 18, 2009



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EXHIBIT INDEX



|            |  |                                                                                                                                                                                                                   
|----------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit No. |  | Description                                                                                                                                                                                                       
|            | 
|            |  |                                                                                                                                                                                                                   
|10.8        |  | Amended and Restated Unitil Corporation Management Incentive Plan effective as of June 19, 2008 as further amended on December 1, 2008.                                                                           
|            | 
|11.1        |  | Computation in Support of Earnings per Share                                                                                                                                                                      
|            | 
|12.1        |  | Computation in Support of Ratio of Earnings to Fixed Charges                                                                                                                                                      
|            | 
|21.1        |  | Subsidiaries of Registrant                                                                                                                                                                                        
|            | 
|23.1        |  | Consent of Independent Registered Public Accounting Firm                                                                                                                                                          
|            | 
|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.
|            | 
|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.