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UNITIL 10-K 2006
FORM 10-K
Table of Contents

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 


 

FORM 10-K

 


 

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

 

For the fiscal year ended December 31, 2005

 

OR

 

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

 

Commission file number 1-8858

 


 

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

 


 

New Hampshire   02-0381573

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

6 Liberty Lane West, Hampton, New Hampshire   03842-1720
(Address of principal executive offices)   (Zip Code)

 

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

 


 

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

 

Title of Each Class


 

Name of Exchange on Which Registered


Common Stock, No Par Value   American Stock Exchange

 

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

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

 

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

 

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

 

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

 

Based on the closing price of June 30, 2005, the aggregate market value of common stock held by non-affiliates of the registrant was $147,884,697.

 

The number of common shares outstanding of the registrant was 5,618,664 as of February 22, 2006.

 


 

Documents Incorporated by Reference:

 

Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 20, 2006, are incorporated by reference into Part III of this Report

 



Table of Contents

 

UNITIL CORPORATION

FORM 10-K

For the Fiscal Year Ended December 31, 2005

Table of Contents

 

Item

  

Description


   Page

     PART I     
1.   

Business

    
    

Unitil Corporation

   2
    

Operations

   3
    

Rates and Regulation

   4
    

Electric Power Supply

   5
    

Gas Supply

   7
    

Environmental Matters

   8
    

Employees

   8
    

Available Information

   9
    

Directors and Executive Officers of the Registrant

   9
    

Investor Information

   11
1A.   

Risk Factors

   12
1B.   

Unresolved Staff Comments

   15
2.   

Properties

   15
3.   

Legal Proceedings

   16
4.   

Submission of Matters to a Vote of Security Holders

   16
     PART II     
5.   

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

   17
6.   

Selected Financial Data

   19
7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   20
7A.   

Quantitative and Qualitative Disclosures about Market Risk

   38
8.   

Financial Statements and Supplementary Data

   40
9.   

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   83
9A.   

Controls and Procedures

   83
9B.   

Other Information

   83
     PART III     
10.   

Directors and Executive Officers of the Registrant

   84
11.   

Executive Compensation

   84
12.   

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

   84
13.   

Certain Relationships and Related Transactions

   84
14.   

Principal Accountant Fees and Services

   84
     PART IV     
15.   

Exhibits and Financial Statement Schedules

   85
    

Signatures

   88

 

Exhibit 11.1

   Computation in Support of Earnings per Share

Exhibit 12.1

   Computation in Support of Ratio of Earnings to Fixed Charges

Exhibit 21.1

   Subsidiaries of Registrant

Exhibit 23.1

   Consent of Independent Registered Public Accounting Firm

Exhibit 23.2

   Consent of Independent Registered Public Accounting Firm

Exhibits 31.1-31.3

   Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.1

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

 

1

 


Table of Contents

 

PART I

 

Item 1. Business

 

UNITIL CORPORATION

 

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

 

Unitil Corporation

Subsidiaries


 

State and Year of
Organization


  

Principal Type

of Business


Unitil Energy Systems, Inc. (UES)   NH - 1901    Retail Electric Distribution Utility
Fitchburg Gas and Electric Light Company (FG&E)   MA - 1852    Retail Electric & Gas Distribution Utility
Unitil Power Corp. (Unitil Power)   NH - 1984    Wholesale Electric Power Utility
Unitil Service Corp. (Unitil Service)   NH - 1984    Utility Service Company
Unitil Realty Corp. (Unitil Realty)   NH - 1986    Real Estate Management
Unitil Resources, Inc. (Unitil Resources)   NH - 1993    Non-utility, Unregulated Energy Services
Usource Inc. and Usource L.L.C. (Usource)   DE - 2000    Energy Brokering and Advisory Services

 

Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the Securities and Exchange Commission (SEC). As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed.

 

Unitil’s principal business is the retail distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the retail distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. Unitil has two distribution utility subsidiaries, UES, which operates in New Hampshire and FG&E, which operates in Massachusetts (collectively referred to as the “retail distribution utilities”). Unitil’s retail distribution utilities serve approximately 98,600 electric customers and 15,000 natural gas customers in their franchise areas. The retail distribution companies are local “pipes and wires” utility distribution companies with a combined investment in net utility plant of $213.0 million at December 31, 2005. Unitil’s total revenue was $232.1 million in 2005. Earnings applicable to common shareholders for 2005 was $8.4 million. Substantially all of Unitil’s revenue and earnings are derived from regulated utility operations.

 

A third utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for UES. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of UES on May 1, 2003 and divested of substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with those contracts.

 

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-utility unregulated subsidiary that provides consulting and management related services. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides energy brokering and advisory services to large commercial and industrial customers in the northeastern United States.

 

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Table of Contents

OPERATIONS

 

Electric Utility Operations

 

Unitil’s electric utility operations are conducted through the retail distribution utilities, UES and FG&E. Revenue from Unitil’s electric utility operations was $197.3 million for 2005. Earnings from electric utility operations were $7.0 million for the same 12-month period.

 

The primary business of Unitil’s electric utility operations is the local distribution of electricity to customers in its franchise areas. As a result of the implementation of retail choice in New Hampshire and Massachusetts, Unitil’s customers are free to contract for their supply of electricity with third-party suppliers. The retail distribution utilities continue to deliver that supply of electricity over their distribution systems. Both UES and FG&E supply electricity to those customers who do not obtain their supply from third-party suppliers, with the costs associated with electricity supplied by the Company being recovered on a pass-through basis under periodically-adjusted rates.

 

UES distributes electricity to approximately 71,100 customers in New Hampshire in the capital city of Concord as well as 12 surrounding towns and all or part of 16 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson and Plaistow. UES’ franchise areas consist of approximately 408 square miles. The state capital of New Hampshire is located within UES’ franchise areas, and includes the executive, legislative and judicial branches and offices and facilities for all major state government services as well as several federal government facilities. In addition, UES’ franchise areas are retail trading and recreation centers for the central and southeastern parts of the state. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wires and plastics. UES’ franchise areas include popular resort areas and beaches along the Atlantic Ocean, including the Hampton Beach recreational area. UES’ 2005 retail electric operating revenue was $134.7 million, of which approximately 41.0% was derived from residential sales and 59.0% from commercial/industrial sales. UES’ earnings in 2005 were $3.8 million.

 

FG&E is engaged in the retail distribution of both electricity and natural gas in the city of Fitchburg and several surrounding communities. FG&E’s franchise area encompasses approximately 170 square miles. Electricity is supplied and distributed by FG&E to approximately 27,500 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. FG&E’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries. FG&E’s 2005 retail electric operating revenue was $62.6 million, of which approximately 44.0% was derived from residential sales and 56.0% from commercial/industrial sales. FG&E’s earnings from electric utility operations were $3.2 million in 2005.

 

Gas Utility Operations

 

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

 

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

 

FG&E’s 2005 gas operating revenue was $32.8 million, of which approximately 58.0% was derived from residential firm sales and 42.0% from commercial/industrial firm sales. Earnings from FG&E’s gas utility operations were $0.9 million for 2005.

 

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Table of Contents

Seasonality

 

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

 

Non-Utility, Unregulated Operations and Other

 

Unitil’s non-utility, unregulated operations are comprised of Unitil Resources and Usource. Unitil Resources provides energy consulting and management services. Usource provides energy brokering and consulting services to large commercial and industrial customers in the northeastern United States. Revenue from Unitil’s unregulated operations was $2.0 million in 2005. Unitil’s other subsidiaries include Unitil Service and Unitil Realty, which provide centralized facilities, management and administrative services to Unitil’s affiliated companies. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries. In addition to the earnings from unregulated operations, the earnings of these subsidiaries are principally derived from income earned on short-term investments and real property owned for Unitil’s and its subsidiaries’ use and is reported in Other segment income. Non-utility, unregulated operations and Other segment earnings for 2005 were approximately $0.5 million.

 

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

(For segment information, see Part II, Item 8, Note 10 herein.)

 

RATES AND REGULATION

 

Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 in regards to certain bookkeeping, accounting and reporting requirements. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the SEC with respect to various matters, including: the issuance of securities, capital structure, and certain acquisitions and dispositions of assets. As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed. Unitil’s utility operations related to wholesale and interstate business activities are also regulated by FERC. The retail distribution utilities, UES and FG&E, are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE), respectively, in regards to their rates, issuance of securities and other accounting and operational matters. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

 

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

 

In connection with the implementation of retail choice, Unitil Power and FG&E divested substantially all of their long-term power supply contracts and interests in generation assets through the sale of the interest in those assets or the sale of the entitlements to the electricity provided by those generation assets and long-term power supply contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power

 

4


Table of Contents

supply portfolios and have secured regulatory approval from the NHPUC and MDTE, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next 5 to 7 years, is $154 million as of December 31, 2005 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

 

ELECTRIC POWER SUPPLY

 

Unitil’s customers in both New Hampshire and Massachusetts now have the opportunity to purchase their electric supply from competitive retail suppliers, though most customers continue to purchase such supplies through the retail distribution utilities. The transition to retail choice required the divestiture of Unitil’s existing power supply arrangements and the procurement of replacement supplies which provided the flexibility for migration of customers to and from utility service. FG&E, UES, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s retail customers.

 

Power Supply Divestiture

 

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

 

Unitil Power divested its long-term power supply contracts to Mirant Corporation (Mirant). The purchase of power to supply UES’ Transition Service and Default Service requirements by UES from Mirant was linked to the Unitil Power divestiture. The NHPUC Order completed the state approval process for Unitil’s restructuring plan under which UES implemented customer choice for its customers on May 1, 2003. The divested power supply contracts continue through October 2010.

 

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

 

Regulated Energy Supply

 

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

 

5


Table of Contents

suppliers. In particular, FG&E has entered into power supply contracts to meet its power supply obligations associated with the provision of Standard Offer Service and Default Service. Standard Offer Service was offered only to customers who had both taken service from FG&E since the inception of retail choice in 1998 and had not switched to a competitive retail supplier. Consistent with MDTE regulations, Standard Offer Service ended February 28, 2005. Effective March 1, 2005 FG&E customers are eligible for Default Service. FG&E has power supply contracts with various wholesale suppliers for the provision of Default Service. MDTE policy dictates the pricing structure and duration of each of these contracts. Currently, all Default Service power supply contracts for large general accounts are three months in duration. Default Service power supply contracts for residential and small and medium general service customers are acquired every 6 months, with each 12 month contract providing 50% of the class requirements.

 

The MDTE is investigating alternatives to the current procurement policy for all accounts, other than the large general accounts. This process could potentially lead to the procurement of FG&E Default Service power supply for longer duration in order to provide more price stability for smaller customers throughout Massachusetts for whom competitive retail options are relatively scarce.

 

UES has entered into a power supply contract to meet its power supply obligations associated with the provision of Transition Service and Default Service. Transition Service is available to any UES customer who has not chosen a competitive retail supplier. UES’ Default Service is available to any customer who has chosen a competitive retail energy supplier and returns to retail energy supply from UES. UES has entered into a power supply contract for the provision of Transition Service and Default Service with Mirant. This power supply contract provided fixed unit prices for both Transition Service and Default Service for UES’ largest general service accounts through April 2005 and for all other accounts through April 2006.

 

On July 14, 2003 Mirant filed for Chapter 11 Bankruptcy protection. Mirant is currently performing all of its contractual obligations to both Unitil Power and UES and has satisfied all of its pre-petition claims made by Unitil. On January 3, 2006 Mirant emerged from Chapter 11 Bankruptcy protection.

 

In January, 2005 the NHPUC approved two six-month supply contracts for Transition Service and Default Service for UES’ large general service customers for the period May, 2005 through April, 2006. In September, 2005 the NHPUC approved a Settlement among UES, NHPUC Staff and the Office of Consumer Advocate which provides for UES to procure Default Service for its largest general service accounts through successive competitive solicitations of three-months duration and to procure Default Service for all other customers through a series of two one-year contracts and two three-year contracts with each contract covering 25% of the total requirements of the group. The first two contracts were of 6-months and 18-months duration in order to stagger the start dates of future 1-year and 3-year procurements. On November 2, 2005, the NHPUC approved those two initial Default Service contracts for service starting May 1, 2006.

 

Regional Transmission and Power Markets

 

FG&E, UES and Unitil Power are members of the NEPOOL, formed in 1971 to assure reliable operation of the bulk power system in the most economic manner for the region. NEPOOL is governed by an agreement (NEPOOL Agreement) that is filed with and subject to the jurisdiction of the FERC. Under the NEPOOL Agreement and the NEPOOL Open Access Transmission Tariff (OATT), to which virtually all New England electric utilities are parties, substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. The NEPOOL Agreement and the OATT impose generating capacity and reserve obligations, and provide for the use of major transmission facilities and support payments associated therewith. The most notable benefits of NEPOOL are coordinated power system operation in a reliable manner and a supportive business environment for the development of a competitive electric marketplace. The regional bulk power system is operated by an independent corporate entity, ISO-NE, in order to avoid any opportunity for conflicting financial interests between the system operator and the market-driven participants.

 

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Table of Contents

As of February 1, 2005, a Regional Transmission Organization (RTO) was established in New England. ISO-NE became the entity responsible for operating the RTO. The market rules and requirements to participate in the markets previously covered under the NEPOOL Agreement were transferred to the new RTO structure under control of ISO-NE. FERC approved the formation of the RTO in orders issued March 24, 2004 and November 3, 2004 to begin operation of the RTO structure effective February 1, 2005. As a result of the formation of the RTO, companies seeking transmission service throughout New England will be able to obtain that service under common terms, with much of their focus on dealing with ISO-NE, in cooperation with the local transmission providers.

 

On March 1, 2004, ISO-NE filed a proposal to implement Locational Installed Capacity (LICAP) in New England to allow for the imposition of incentive pricing for transmission constrained areas. UES and FG&E have intervened in the proceeding. Both UES and FG&E are located in a non-constrained area of the power pool. On October 21, 2005 the FERC issued an order directing that Settlement discussions take place and indicating that implementation of LICAP, if it proceeds, will not be earlier than October 1, 2006. This case is still before the FERC.

 

The formation of an RTO, LICAP and other wholesale market changes are not expected to have a material impact on Unitil’s operations because of the cost recovery mechanisms for wholesale energy and transmission costs approved by the MDTE and NHPUC.

 

GAS SUPPLY

 

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

 

FG&E purchases natural gas from domestic and Canadian suppliers under contracts of one year or less, as well as from producers and marketers on the spot market and arranges for the transportation to its distribution facilities under long-term contracts with the Tennessee interstate pipeline. FG&E has a four-year contract for LNG supply which ends in 2008 which was approved by the MDTE. The following tables summarize actual gas purchases by source of supply and the cost of gas sold for the years 2003 through 2005.

 

Sources of Gas Supply

(Expressed as percent of total MMBtu of gas purchased)

 

     2005

    2004

    2003

 

Natural Gas:

                  

Domestic firm

   84.8 %   85.0 %   94.0 %

Canadian firm

   3.4 %   5.4 %   1.3 %

Domestic spot market

   9.3 %   5.9 %   1.3 %
    

 

 

Total natural gas

   97.5 %   96.3 %   96.6 %

Supplemental gas

   2.5 %   3.7 %   3.4 %
    

 

 

Total gas purchases

   100.0 %   100.0 %   100.0 %
    

 

 

 

Cost of Gas Sold

 

     2005

    2004

    2003

 

Cost of gas purchased and sold per MMBtu

   $ 10.83     $ 8.42     $ 7.14  

Percent Increase (Decrease) from prior year

     28.7 %     17.9 %     43.9 %

 

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

 

ENVIRONMENTAL MATTERS

 

The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company is in general compliance with all applicable environmental and safety laws and regulations, and management believes that as of December 31, 2005, there are no material losses reasonably possible in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

 

Sawyer Passway MGP Site—The Company continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows the Company to work towards temporary remediation of the site. Work performed in 2002 was associated with the five-year review of the Temporary Solution submittal (Class C Response Action Outcome) under the Massachusetts Contingency Plan (MCP) that was filed for the site in 1997. Completion of this work has confirmed the Temporary Solution status of the site for an additional five years, to January 2008. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed. During 2005, FG&E continued developing a long range plan for a Permanent Solution for the site, including alternatives for re-use of the site.

 

On May 13, 2004 FG&E discovered an unauthorized excavation by another property owner on the site at Sawyer Passway in which tainted soils related to MGP by-products were exposed and relocated onto property owned by FG&E. FG&E promptly reported this discovery to the DEP and subsequently received a Notice of Responsibility on May 20, 2004. FG&E has properly disposed of the relocated materials and taken other steps in accordance with DEP directives to remedy the situation. The Completion Report for this release was submitted May 9, 2005.

 

Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to an MDTE approved settlement agreement between the Massachusetts Attorney General and the natural gas utilities of the Commonwealth of Massachusetts (Agreement). The Agreement allows FG&E to amortize and recover from gas customers over succeeding seven-year periods the environmental response costs incurred each year. Environmental response costs are defined to include liabilities related to manufactured gas sites, waste disposal sites or other sites onto which hazardous material may have migrated as a result of the operation or decommissioning of Massachusetts gas manufacturing facilities from 1822 through 1978. In addition, any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers. The total annual charge for such costs assessed to gas customers cannot exceed five percent of FG&E’s total revenue for firm gas sales during the preceding year. Costs in excess of five percent will be deferred for recovery in subsequent years.

 

EMPLOYEES

 

As of December 31, 2005, the Company and its subsidiaries had 310 employees. Management considers the Company’s relationship with employees to be good and has not experienced any major labor disruptions since the early 1960’s.

 

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

 

AVAILABLE INFORMATION

 

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

 

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

 

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

 

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

 

The following table provides information about our directors and senior management as of February 22, 2006:

 

Name


   Age

  

Position


Robert G. Schoenberger

   55    Chairman of the Board, Chief Executive Officer and President

Mark H. Collin

   46    Senior Vice President, Chief Financial Officer and Treasurer

Thomas P. Meissner, Jr.  

   43    Senior Vice President and Chief Operating Officer

Laurence M. Brock

   52    Controller and Chief Accounting Officer

Todd R. Black

   41    Vice President, Energy Markets

George R. Gantz

   54    Senior Vice President, Customer Services and Communications

George E. Long, Jr.  

   49    Vice President, Administration

Raymond J. Morrissey

   58    Vice President, Information Systems

Sandra L. Whitney

   42    Corporate Secretary

Dr. Robert V. Antonucci

   60    Director

David P. Brownell

   62    Director

Michael J. Dalton

   65    Director

Albert H. Elfner, III

   61    Director

Edward F. Godfrey

   56    Director

Michael B. Green

   56    Director

Eben S. Moulton

   59    Director

M. Brian O’Shaughnessy

   62    Director

Charles H. Tenney, III

   58    Director

Dr. Sarah P. Voll

   63    Director

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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Edward F. Godfrey was the Executive Vice President and Chief Operating Officer of Keystone Investments, Incorporated from 1997 until his retirement in 1998. While at Keystone Investments, he was also a Senior Vice President, Chief Financial Officer and Treasurer from 1988 to 1996. Mr. Godfrey is also a Director of Reilly Mortgage Group and serves on their Audit Committee.

 

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

 

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

 

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

 

Charles H. Tenney, III has been Director of Operations for Brainshift.com, Inc. since 2002. He also served as a financial advisor for H&R Block Financial Advisors from 2001 to 2002 and as the Director of Corporate Services for Log On America, Inc. from 1999 to 2000. Mr. Tenney also currently serves on the Board of Overseers of the Huntington Theater Company, Boston, Massachusetts.

 

Dr. Sarah P. Voll has been the Vice President, National Economic Research Associates, Inc. (“NERA”) since 1999. Dr. Voll was also a Senior Consultant at NERA from 1996 to 1999.

 

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 20, 2006, at 10:30 a.m.

 

Transfer Agent

 

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

 

Mail: Computershare, P.O. Box 43010, Providence, RI 02940-3010

 

Telephone: 800-736-3001 (Outside MA); 781-575-3100 (Within MA)

 

Investor Relations

 

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

 

Special Services & Shareholder Programs Available

 

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

 

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    Dividend Reinvestment Plan:

 

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

 

    Dividend Direct Deposit Service:

 

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

 

    Direct Registration:

 

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

 

Item 1A. Risk Factors

 

Risks Relating to Our Business

 

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

 

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

 

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

 

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

 

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

 

Our power supply portfolio related stranded costs due to the electric industry restructuring in New Hampshire and Massachusetts for which regulatory approval has been obtained for recovery were approximately $57.9 million for FG&E and $57.0 million for UES as of December 31, 2005. Substantially all of FG&E’s stranded costs relate to owned generation assets and long-term power purchase agreements divested by FG&E to Select Energy. Approximately $57.6 million of UES’ stranded costs are attributable to the long-term power

 

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purchase agreements divested by Unitil Power to Mirant. Because FG&E and Unitil Power remain ultimately responsible for payments under the power purchase agreements divested by them, if either Select or Mirant were to fail to fulfill their obligations to purchase the entitlements to electricity provided for in those agreements, FG&E and Unitil Power could incur additional stranded costs were they to resell such entitlements for amounts less than the amounts agreed to be paid by Select and Mirant. We expect that any such additional stranded costs would be recovered from our customers, although such recovery would require approval from the MDTE or NHPUC, the receipt of which cannot be assured.

 

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

 

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

 

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

 

We made voluntary cash contributions to our pension plans of $1.2 million and $2.0 million in 2003 and 2004, respectively. In 2005 we were required to make a minimum cash contribution of $0.7 million to our pension plans and made an additional voluntary cash contribution of $1.8 million for a total of $2.5 million. If the valuation of capital markets were to significantly decline from current levels, we may be required to make cash contributions to our pension plans substantially in excess of the levels currently anticipated, which could adversely affect our financial condition.

 

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

 

Our subsidiaries have ongoing capital expenditure requirements which they frequently fund through borrowings from outside lenders. Changes in interest rates do not affect interest expense associated with our subsidiaries’ presently outstanding fixed rate long-term debt securities. However, our subsidiaries periodically issue new long-term debt securities either to refinance short-term borrowings or to fund capital expenditures. Changes in interest rates may affect the interest rate and corresponding interest expense on any such new long-term debt securities. In addition, our subsidiaries’ short-term borrowings are at variable rates of interest. As a result, changes in short-term interest rates will increase or decrease our interest expense associated with short-term borrowings. Increases in interest rates generally will increase our borrowing costs and could adversely affect our financial condition or results of operations.

 

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

 

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

 

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

 

We are a public utility holding company and we do not have any operating income of our own. Consequently, our ability to pay dividends on our common stock is dependent on dividends and other payments

 

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received from our subsidiaries, principally UES and FG&E. Our subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts to us, whether through dividends, loans or other payments. The ability of our subsidiaries to pay dividends or make distributions to us will depend on, among other things:

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic

 

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occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could have a material adverse effect on us, since they could inhibit our ability to continue providing electric and/or gas distribution services to our customers for an extended period, which is the principal source of our operating income.

 

Item 1B. Unresolved Staff Comments

 

None.

 

Item 2. Properties

 

As of December 31, 2005, Unitil owned, through its retail distribution utilities: two operation centers, approximately 2,145 pole miles of local transmission and distribution overhead electric lines and 507 conduit bank miles of underground electric distribution lines, along with 55 electric substations, including three mobile electric substations. FG&E’s natural gas operations property includes a liquid propane gas plant, a liquid natural gas plant and 316 miles of underground gas mains. In addition, Unitil’s real estate subsidiary, Unitil Realty, owns the Company’s corporate headquarters building and the 12 acres on which it is located in Hampton, New Hampshire.

 

UES owns and maintains distribution operations centers in Concord, New Hampshire and Kensington, New Hampshire. UES’ 34 electric distribution substations, including a 5,000 kilovolt ampere (kVA) mobile substation, constitute 233,237 kVA of capacity (includes spares and mobile) for the transformation of electric energy from the 34.5 kV subtransmission voltage to other primary distribution voltage levels. The electric substations are located on land owned by UES or occupied by UES pursuant to a perpetual easement.

 

UES has a total of approximately 1,590 pole miles of local transmission and distribution overhead electric lines and a total of 336 conduit bank miles of underground electric distribution lines. The electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by UES without objection by the owners. In the case of certain distribution lines, UES owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone companies.

 

Additionally, UES owns 137.7 acres of non-utility property located on the east bank of the Merrimack River in Concord, New Hampshire. Of the total acreage, 81.2 acres are located within an industrial park zone.

 

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

 

FG&E’s electric properties consist principally of 555 pole miles of local transmission and distribution overhead electric lines, 171 conduit bank miles of underground electric distribution lines and 21 transmission and distribution stations including two mobile electric substations. The capacity of these substations totals 562,650 kVA.

 

FG&E owns a liquid propane gas plant and a liquid natural gas plant and the land on which they are located. FG&E also has 316 miles of underground steel, cast iron and plastic gas mains.

 

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

 

Management believes that the Company’s facilities are currently adequate for their intended uses.

 

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Item 3. Legal Proceedings

 

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Note 5 to the Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

 

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

 

None

 

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

 

The Registrant’s Common Stock is traded on the American Stock Exchange. As of December 31, 2005, there were 1,847 Common Shareholders of record.

 

Common Stock Data

 

Dividends per Common Share


   2005

   2004

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
    

  

 

     2005

   2004

Price Range of Common Stock


   High/Ask

   Low/Bid

   High/Ask

   Low/Bid

1st Quarter

   $ 27.80    $ 25.50    $ 27.72    $ 25.60

2nd Quarter

   $ 28.05    $ 25.31    $ 28.25    $ 25.33

3rd Quarter

   $ 28.70    $ 27.00    $ 27.24    $ 25.56

4th Quarter

   $ 28.10    $ 24.37    $ 28.75    $ 27.08

 

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

 

EQUITY COMPENSATION PLAN BENEFIT INFORMATION

 

     (a)    (b)    (c)

Plan Category


   Number of securities
to be issued upon exercise
of outstanding options,
warrants and rights


   Weighted-average
exercise price of
outstanding options,
warrants and rights


   Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))


Equity compensation plans approved by security holders

                

KESOP (1)

   38,202    $ 11.89    29,101

Restricted Stock Plan (2)

        N/A    130,925

Equity compensation plans not approved by security holders

1998 Option Plan (3)

   107,000    $ 27.13   
    
  

  

Total

   145,202    $ 23.12    160,026
    
  

  

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

(1) The KESOP was approved by shareholders in July 1989. Options were granted between January 1989 and November 1997.
(2) The Restricted Stock Plan was approved by shareholders in April 2003. 10,600 shares of restricted stock were awarded to Plan participants in May 2003; 10,700 shares of restricted stock were awarded to Plan participants in April 2004; 10,900 shares of restricted stock were awarded to Plan participants in March 2005; 14,375 shares of restricted stock were awarded to Plan participants in February 2006.

 

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

 

Unregistered Sales of Equity Securities and Uses of Proceeds

 

(a) There were no sales of unregistered equity securities by the Company for the fiscal period ended December 31, 2005.

 

(b) Not applicable.

 

(c) Issuer repurchases are shown in the table below for the monthly periods noted:

 

Period


   Total
Number of
Shares
Purchased


   Average
Price Paid
per Share


   Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs(1)


  

Maximum Number of
Shares that May Yet
Be Purchased Under
the Plans or
Programs(1)


10/1/05 – 10/31/05

              n/a

11/1/05 – 11/30/05

              n/a

12/1/05 – 12/31/05

   93
2,174
   $
$
24.90
25.29
   93
2,174
   n/a
    
  

  
  

Total

   2,267    $ 25.28    2,267    n/a
    
  

  
  

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

 

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Item 6. Selected Financial Data

 

For the Years Ended December 31,


  2005

    2004

    2003

    2002

    2001

 

(all data in thousands except % and per share data)

                                       

Consolidated Statements of Earnings:

                                       

Operating Revenue

  $ 232,145     $ 214,137     $ 220,654     $ 188,386     $ 207,022  

Operating Income

    15,541       15,193       15,449       13,248       14,394  

(Gain) Loss on Non-Utility Investments, net of tax

                      (82 )     2,400  

Other Non-operating Expense

    147       193       (40 )     185       170  
   


 


 


 


 


Income Before Interest Expense and Extraordinary Item

    15,394       15,000       15,489       13,145       11,824  

Interest Expense, net

    6,841       6,774       7,531       7,057       6,797  
   


 


 


 


 


Income before Extraordinary Item

    8,553       8,226       7,958       6,088       5,027  

Extraordinary Item, net of tax

                            3,937  
   


 


 


 


 


Net Income

    8,553       8,226       7,958       6,088       1,090  

Dividends on Preferred Stock

    156       215       236       253       257  
   


 


 


 


 


Earnings Applicable to Common Shareholders

  $ 8,397     $ 8,011     $ 7,722     $ 5,835     $ 833  
   


 


 


 


 


Balance Sheet Data:

                                       

Utility Plant (Original Cost)

  $ 324,967     $ 308,054     $ 288,657     $ 272,402     $ 255,498  

Total Assets

  $ 450,081     $ 457,010     $ 483,877     $ 481,702     $ 376,762  

Capitalization:

                                       

Common Stock Equity

  $ 96,283     $ 94,291     $ 92,805     $ 74,350     $ 74,746  

Preferred Stock

    2,327       2,338       3,269       3,322       3,609  

Long-Term Debt, less current portion

    125,365       110,675       110,961       104,226       107,470  
   


 


 


 


 


Total Capitalization

  $ 223,975     $ 207,304     $ 207,035     $ 181,898     $ 185,825  
   


 


 


 


 


Current Portion of Long-Term Debt

  $ 308     $ 285     $ 3,263     $ 3,243     $ 3,224  

Short-term Debt

  $ 18,700     $ 25,675     $ 22,410     $ 35,990     $ 13,800  

Capital Structure Ratios:

                                       

Common Stock Equity

    43 %     46 %     45 %     41 %     40 %

Preferred Stock

    1 %     1 %     2 %     2 %     2 %

Long-Term Debt

    56 %     53 %     53 %     57 %     58 %

Earnings Per Share Data:

                                       

Earnings Per Average Share – Basic and Diluted

  $ 1.51     $ 1.45     $ 1.58     $ 1.23     $ 0.18  

Common Stock Data:

                                       

Shares of Common Stock – Diluted (Average)

    5,568       5,525       4,896       4,762       4,760  

Dividends Paid Per Share

  $ 1.38     $ 1.38     $ 1.38     $ 1.38     $ 1.38  

Book Value Per Share (Year-End)

  $ 17.21     $ 17.00     $ 16.87     $ 15.67     $ 15.76  

Electric and Gas Sales:

                                       

Electric Distribution Sales (kWh)

    1,790,405       1,742,131       1,717,664       1,659,136       1,596,390  

Firm Natural Gas Distribution Sales (Therms)

    24,332       23,151       24,592       22,480       23,067  

 

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Table of Contents
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Note references are to Notes to the Consolidated Financial Statements in Item 8.)

 

Forward-Looking Information

 

This report and the documents we incorporate by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.

 

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

 

    Variations in weather;

 

    Changes in the regulatory environment;

 

    Customers’ preferences on energy sources;

 

    Interest rate fluctuation and credit market concerns;

 

    General economic conditions;

 

    Increased competition; and

 

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

 

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.

 

EARNINGS & DIVIDENDS

 

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

 

Total electric kilowatt-hour (kWh) sales increased by 2.8% in 2005 compared to 2004. The Company’s service territories experienced hotter weather during the summer of 2005 compared to the same period in 2004. Also contributing to the increase in unit sales was continued growth in the number of customers served.

 

Total firm therm natural gas sales increased by 5.1% in 2005 compared to 2004. This increase was due to a new contract with a large industrial customer.

 

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Table of Contents

Combined electric and gas sales margins increased $1.5 million in 2005 compared to 2004. The increases in electric and gas sales margins reflect increases in electric and gas sales in addition to increased utility rates authorized by regulators.

 

Total O&M expense increased $1.2 million, or 5.2%, in 2005 compared to 2004. This increase reflects higher salaries and compensation expenses of $0.6 million, higher retiree and employee benefit costs of $0.5 million, higher audit fees of $0.2 million, higher utility operating and maintenance expenses of $0.1 million and higher bad debt expenses of $0.1 million, partially offset by lower administrative and general expenses of $0.3 million. The higher audit fees include expenditures to comply with Section 404 of the Sarbanes-Oxley Act of 2002 (SOXA).

 

Depreciation and Amortization expense increased $0.3 million, or 1.6%, in 2005 compared to 2004, reflecting higher depreciation expense of $0.6 million, due to increased investment in utility plant additions, partially offset by lower amortization in 2005 on the Company’s regulatory assets related to its former abandoned property investment in Seabrook Station, which became fully-amortized in the third quarter of 2005.

 

Interest Expense, net increased $0.1 million, or 1.0% in 2005 compared to 2004. This increase was driven by increases in interest expense on short-term borrowings partially offset by increases in interest income, primarily due to increased carrying charges on regulatory assets.

 

In 2005, Unitil’s annual common dividend was $1.38. At its January, 2006 meeting, the Unitil Board of Directors declared a quarterly dividend on the Company’s common stock of $0.345 per share.

 

Per Share Data


   2005

   2004

   2003

Earnings per Common Share

   $ 1.51    $ 1.45    $ 1.58
    

  

  

Annual Dividend

   $ 1.38    $ 1.38    $ 1.38

 

A more detailed discussion of the Company’s 2005 Results of Operations and a year-to-year comparison of changes in financial position for the three-year period 2003 through 2005 are presented below.

 

RESULTS OF OPERATIONS

 

Operating Revenue—Electric

 

Electric Operating Revenue—Electric Operating Revenue increased by $13.4 million, or 7.3%, in 2005 as compared to 2004. Electric Operating Revenue includes the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation & Load Management (C&LM) in operating expenses. The increase in Electric Operating Revenue primarily reflects an increase in Purchased Electricity costs and electricity unit sales volumes compared to the prior period. The Purchased Electricity cost of sales component increased $12.2 million, or 9.7%, in 2005 as compared to 2004, due to higher wholesale electric commodity prices. Purchased Electricity expenses include the cost of electric supply as well as the other energy supply related restructuring costs, including long-term power supply contract buyout costs. The Company recovers the cost of Purchased Electricity in its rates at cost on a pass through basis. C&LM revenue related to electric operations increased $0.3 million, or 9.0% in 2005 as compared to 2004. The Company also recovers the costs of C&LM on a pass through basis.

 

Gross electric sales margin (Electric Operating Revenue less Cost of Electric Sales) was $55.4 million in 2005. This represents an increase of $0.9 million compared to 2004. This increase reflects increased kWh unit sales to both residential and commercial and industrial customer classes and higher base rates as discussed above, partially offset by the expiration in 2005 of a rate surcharge on Regulatory Assets.

 

In 2004, Electric Operating Revenue decreased by $7.0 million, or 3.7% compared to 2003. The Purchased Electricity cost of sales component decreased $8.1 million, or 6.0% in 2004 compared to 2003, reflecting lower

 

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Table of Contents

electric wholesale commodity prices. Electric sales margin was $54.4 million in 2004, an increase of $1.2 million over 2003. This increase reflects increased kWh unit sales to both residential and commercial and industrial customer classes.

 

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

 

 

Electric Operating Revenue and Sales Margin (000’s)


                           
                    % Change

 
     2005

   2004

   2003

   2005 vs. 2004

    2004 vs. 2003

 

Electric Operating Revenue:

                                 

Residential

   $ 82,244    $ 75,689    $ 76,893    8.7 %   (1.6 %)

Commercial/Industrial

     115,094      108,200      113,971    6.4 %   (5.1 %)
    

  

  

            

Total Electric Operating Revenue

   $ 197,338    $ 183,889    $ 190,864    7.3 %   (3.7 %)
    

  

  

            

Cost of Electric Sales:

                                 

Purchased Electricity

   $ 138,134    $ 125,940    $ 134,036    9.7 %   (6.0 %)

Conservation & Load Management

     3,845      3,527      3,643    9.0 %   (3.2 %)
    

  

  

            

Gross Electric Sales Margin

   $ 55,359    $ 54,422    $ 53,185    1.7 %   2.3 %
    

  

  

            

 

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

 

Sales to residential customers increased 5.4% in 2005 compared to 2004, due to customer growth and hotter weather. Sales to commercial and industrial (C&I) customers increased 1.2% in 2005 compared to 2004, due primarily to customer growth and the hotter summer weather. The hotter summer temperatures in the Company’s service territories resulted in increased usage of electricity for air conditioning and other cooling purposes. According to ISO-NE, the entity which operates the regional bulk power system, New England’s electricity use reached an all-time high on July 27, 2005. Our service territories hit two all-time system load peaks on July 19, 2005 and July 27, 2005.

 

Unitil’s total electric kilowatt-hour (kWh) sales increased by 1.4% in 2004 compared to 2003. This increase reflects growth in sales to residential and commercial and industrial customer classes driven by customer growth year over year.

 

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

 

kWh Sales (000’s)


                  % Change

 
     2005

   2004

   2003

   2005 vs. 2004

    2004 vs. 2003

 

Residential

   688,318    652,763    645,711    5.4 %   1.1 %

Commercial/Industrial

   1,102,087    1,089,368    1,071,953    1.2 %   1.6 %
    
  
  
            

Total

   1,790,405    1,742,131    1,717,664    2.8 %   1.4 %
    
  
  
            

 

Operating Revenue—Gas

 

Gas Operating Revenue—Gas Operating Revenue increased $4.1 million, or 14.2%, in 2005 compared to 2004. Gas Operating Revenue includes the recovery of the costs of gas sales, which are recorded as Purchased Gas and C&LM in operating expenses.

 

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Purchased Gas increased $3.7 million, or 21.4%, in 2005 compared to 2004. The increase in Purchased Gas is attributable to higher gas commodity costs. Purchased Gas costs include the cost of gas supply as well as the other energy supply related costs. The Company recovers the cost of Purchased Gas in its rates at cost on a pass through basis. C&LM expenses related to gas operations decreased $0.2 million in 2005 compared to 2004. The Company also recovers the costs of C&LM on a pass through basis.

 

Gross gas sales margin (Gas Operating Revenue less the Costs of Gas Sales) was $11.3 million in 2005. This represents an increase of $0.6 million compared to 2004. Approximately 22% of the increase in gross gas sales margin is attributable to a 5.1% increase in firm therm sales. This increase in firm therm sales is due to a new firm transportation contract with a large industrial customer. The remaining increase in gas sales margin is attributable to higher rates authorized by regulators to recover certain post retirement benefit costs.

 

Gas sales margin was $10.7 million in 2004. This represents a decrease of $0.2 million compared to 2003. Total firm therm unit sales decreased 5.9% in 2004 compared to 2003 reflecting milder winter weather in 2004 compared to 2003.

 

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

 

Gas Operating Revenue and Sales Margin (000’s)


      
                    % Change

 
     2005

   2004

   2003

   2005 vs. 2004

    2004 vs. 2003

 

Gas Operating Revenue:

                                 

Residential

   $ 18,977    $ 16,313    $ 16,267    16.3 %   0.3 %

Commercial/Industrial

     13,644      12,323      11,979    10.7 %   2.9 %
    

  

  

            

Total Firm Gas Revenue

   $ 32,621    $ 28,636    $ 28,246    13.9 %   1.4 %

Interruptible Gas Revenue

     147      49      366    200.0 %   (86.6 %)
    

  

  

            

Total Gas Operating Revenue

   $ 32,768    $ 28,685    $ 28,612    14.2 %   0.3 %

Cost of Gas Sales:

                                 

Purchased Gas

   $ 21,225    $ 17,486    $ 17,421    21.4 %   0.4 %

Conservation & Load Management

     270      476      287    (43.3 %)   66.0 %
    

  

  

            

Gross Gas Sales Margin

   $ 11,273    $ 10,723    $ 10,904    5.1 %   (1.7 %)
    

  

  

            

 

Therm Sales—Unitil’s total firm therm sales of natural gas increased 5.1% in 2005 compared to 2004, due to a new sales contract with a large industrial customer. Sales to residential customers decreased 2.7% in 2005 compared to 2004 due to a milder winter heating season in 2005 compared to the prior year. Sales to C&I customers increased 12.6% in 2005 compared to 2004. Absent the sales from the new contract discussed above, sales to C&I customers were 2.9% lower in 2005 compared to 2004 due to a milder winter heating season and lower natural gas usage by our largest customers for production processes.

 

In 2004, total firm therm sales decreased 5.9% compared to 2003, due to a milder winter heating season in early 2004 and lower average natural gas usage by our largest customers year over year.

 

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

 

Firm Therm Sales (000’s)


                  % Change

 
     2005

   2004

   2003

   2005 vs. 2004

    2004 vs. 2003

 

Residential

   11,011    11,319    12,181    (2.7 %)   (7.1 %)

Commercial/Industrial

   13,321    11,832    12,411    12.6 %   (4.7 %)
    
  
  
            

Total

   24,332    23,151    24,592    5.1 %   (5.9 %)
    
  
  
            

 

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Operating Revenue—Other

 

Total Other Revenue increased $0.5 million, including a 31% increase in revenue from the Company’s energy brokering business, Usource, in 2005 compared to 2004. Total Other Revenue increased $0.4 million in 2004 compared to 2003, including an increase of 36.1% in revenue from Usource.

 

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

 

Other Revenue (000’s)


                           
                    % Change

 
     2005

   2004

   2003

   2005 vs. 2004

    2004 vs. 2003

 

Usource

   $ 2,039    $ 1,563    $ 1,148    30.5 %   36.1 %

Other

               30         
    

  

  

            

Total Other Revenue

   $ 2,039    $ 1,563    $ 1,178    30.5 %   32.7 %
    

  

  

            

 

Operating Expenses

 

Purchased Electricity—Purchased Electricity includes the cost of electric supply as well as the other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity increased $12.2 million, or 9.7%, in 2005 compared to 2004, due primarily to higher electric commodity prices. The Company recovers the costs of Purchased Electricity in its rates at cost and therefore changes in these expenses do not affect earnings.

 

In 2004, Purchased Electricity expenses decreased $8.1 million, or 6.0%, compared to 2003, reflecting lower 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 $3.7 million, or 21.4%, in 2005 compared to 2004. The increase in Purchased Gas is attributable to higher natural gas commodity costs. The Company recovers the costs of Purchased Gas in its rates at cost on a pass through basis and therefore changes in these expenses do not affect Net Income.

 

In 2004, Purchased Gas increased by $0.1 million, or 0.4%, compared to 2003, reflecting higher natural gas commodity costs.

 

Operation and Maintenance (O&M)—O&M expense includes electric and gas utility operating costs, and the operating cost of the Company’s unregulated business activities. Total O&M expense increased $1.2 million, or 5.2%, in 2005 compared to 2004.

 

This increase reflects higher salaries and compensation expenses of $0.6 million, higher retiree and employee benefit costs of $0.5 million, higher audit fees of $0.2 million, higher utility operating and maintenance expenses $0.1 million and higher bad debt expenses of $0.1 million, partially offset by lower administrative and general expenses of $0.3 million. The higher audit fees include expenditures to comply with Section 404 of the Sarbanes Oxley Act of 2002.

 

In 2004, total O&M expense increased $0.6 million, or 2.6%, compared to 2003, primarily reflecting higher salaries and compensation expenses of $0.6 million, higher employee benefits costs of $0.6 million, and higher audit, regulatory and professional fees of $0.2 million. These increases were partially offset by lower utility operating and maintenance costs, $0.5 million and lower other expenses, net of $0.3 million.

 

Conservation & Load Management—Conservation and Load Management expenses are expenses associated with the development, management, and delivery of the Company’s energy efficiency programs.

 

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Table of Contents

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 increased $0.1 million, or 2.8%, in 2005 compared to 2004. These costs are collected from customers on a fully reconciling basis and therefore, fluctuations in program costs do not affect earnings.

 

Total Conservation & Load Management expenses increased $0.1 million, or 1.9%, in 2004 compared to 2003.

 

Depreciation, Amortization and Taxes

 

Depreciation and Amortization—Depreciation and Amortization expense increased $0.3 million, or 1.6%, in 2005 compared to 2004, reflecting higher depreciation expense of $0.6 million, due to increased investment in utility plant additions, partially offset by lower amortization in 2005 on the Company’s regulatory assets related to its former abandoned property investment in Seabrook Station, which became fully-amortized in the third quarter of 2005.

 

In 2004, Depreciation and Amortization expense increased $0.1 million, or 0.4%, compared to 2003, due to the increased investment in utility plant additions partially offset by lower amortization in 2004 on intangible assets.

 

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

 

In 2004, Local Property and Other Taxes increased by $0.4 million, or 7.8% compared to 2003. This increase was related to higher local property tax rates coupled with higher levels of utility plant in service.

 

Federal and State Income Taxes—Federal and State Income Taxes increased $0.1 million, or 1.6%, in 2005 compared to 2004, and by $0.7 million, or 18.4%, in 2004 compared to 2003. These increases were related to higher pre-tax operating income year over year.

 

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Table of Contents

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 interest on regulatory liabilities. Interest income is mainly derived from carrying charges on restructuring related stranded costs and other deferred costs recorded as regulatory assets by the retail distribution utilities as approved by regulators in New Hampshire and Massachusetts. Over the long run, as deferred costs are recovered through rates, the interest costs associated with these deferrals are expected to decrease together with a decrease in interest income. A summary of interest expense and interest income is provided in the following table:

 

Interest Expense, net (000’s)


   2005

    2004

    2003

 

Interest Expense

                        

Long-term Debt

   $ 8,423     $ 8,492     $ 8,170  

Short-term Debt

     1,046       629       1,071  
    


 


 


Subtotal Interest Expense

     9,469       9,121       9,241  
    


 


 


Interest Income

                        

Regulatory Assets

     (2,525 )     (2,310 )     (1,657 )

AFUDC and Other

     (103 )     (37 )     (53 )
    


 


 


Subtotal Interest Income

     (2,628 )     (2,347 )     (1,710 )
    


 


 


Total Interest Expense, net

   $ 6,841     $ 6,774     $ 7,531  
    


 


 


 

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

 

In 2004, Interest Expense, net, declined by approximately $0.8 million compared to 2003. The reduction in Interest Expense, net, is mainly due to the increase in interest income of $0.7 million during 2004, principally related to carrying charges applicable to regulatory assets. These gains were partially offset by increased interest expense on long-term debt of $0.3 million. In addition, interest expense on short-term debt decreased $0.4 million due to lower levels of average short-term borrowings outstanding.

 

Capital Requirements and Liquidity

 

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities, excluding payment of dividends. The Company initially supplements internally generated funds through bank borrowings, as needed, under unsecured short-term bank lines. At December 31, 2005, Unitil had an aggregate of $44.0 million in unsecured revolving lines of credit with three banks. The Company anticipates that it will be able to secure renewal or replacement of some or all of its revolving lines of credit, in accordance with projected requirements. The Company had short-term debt outstanding through bank borrowings of approximately $18.7 million and $25.7 million at December 31, 2005 and December 31, 2004, respectively. In addition, Unitil had approximately $3.2 million in cash at December 31, 2005. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term lives of its utility assets.

 

The maximum amount of short-term borrowings that may be incurred by Unitil and its subsidiaries has been subject to periodic approval by the SEC under the Public Utility Holding Company Act of 1935 and state regulators of the Company’s retail distribution utilities, UES and FG&E. However, in 2005 the Public Utility Holding Company Act of 1935 (PUHCA) was repealed. Under the Energy Policy Act of 2005 many regulatory

 

26


Table of Contents

oversight responsibilities of the SEC, prior to the repeal of PUHCA were transferred to the FERC. The FERC’s transition rule permits Unitil and its subsidiaries to rely on outstanding SEC orders issued under PUHCA, including an order related to Unitil’s cash pooling and loan arrangement and certain maximum borrowing authorizations to be extended through December 31, 2007. At December 31, 2005, Unitil had regulatory authorization to incur total short-term bank borrowings up to a maximum of $55 million, and UES and FG&E had regulatory authorizations to borrow up to a maximum of $16 million and $35 million, respectively. In 2005, UES and FG&E had average short-term debt outstanding of $3.2 million and $25.7 million, respectively.

 

Unitil and its subsidiaries are individually and collectively members of the Unitil Cash Pool. The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool Agreement allows an efficient exchange of cash among Unitil and its subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on Unitil’s actual interest costs from its banks under the revolving lines of credit. In addition, Unitil has been required by the SEC to maintain a minimum 30% common equity ratio, including short-term debt, in order to utilize the Cash Pool. At December 31, 2005, all Unitil subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

 

During December, 2005, FG&E issued and sold $15.0 million of 5.90% unsecured long-term notes under a debenture note structure (see Note 3). The proceeds were utilized to repay outstanding short-term indebtedness of FG&E. In 2003, FG&E issued $10.0 million in long-term notes under a debenture note structure (see Note 3). The Company expects to continue to be able to satisfy its external financing needs by utilizing additional short-term bank borrowings and to periodically replace short-term debt with long-term financings.

 

On October 29, 2003, the Company raised approximately $16.9 million (after deducting underwriting discounts and commissions and the estimated expenses of the offering) through the sale of 717,600 shares of its common stock at a price of $25.40 per share in a registered public offering. The offering was increased from an original 520,000 shares to reflect a 20% upsizing of the transaction (104,000 shares) and the exercise of a 15% underwriters’ over-allotment (93,600 shares). The Company used the proceeds from this offering to make capital contributions of $6 million to UES and $6 million to FG&E and for other general corporate purposes.

 

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

 

Benefit Plan Funding

 

In 2005, 2004 and 2003, the Company and its subsidiaries made cash contributions to their pension plans in the amounts of $2.5 million, $2.0 million and $1.2 million, respectively. The Company may elect to fund the pension plan in future periods. In January 2004, Unitil established Voluntary Employee Benefit Trusts (VEBT) to provide post-retirement benefits. In 2005 and 2004, the Company and its subsidiaries contributed approximately $2.5 million and $2.4 million, respectively to the VEBT and expects to continue to make contributions to the VEBT in future years in amounts consistent with the amounts recovered in retail distribution utility rates for these benefit costs. Prior to the establishment of the VEBT, post-retirement benefits for employees of the Company and its subsidiaries were funded through contributions to the Unitil Retiree Trust (URT). (See Note 8).

 

Off-Balance Sheet Arrangements

 

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

 

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Table of Contents

Contractual Obligations

 

The table below lists the Company’s significant contractual obligations as of December 31, 2005.

 

          Payments Due by Period

Significant Contractual Obligations (000’s) as of December 31, 2005


   Total

   2006

   2007-
2008


   2009-
2010


   2011 &
Beyond


Long-term Debt

   $ 125,673    $ 308    $ 700    $ 821    $ 123,844

Capital Lease

     645      291      342      11      1

Operating Leases

     2,739      390      780      751      818

Power Supply Contract Obligations—MA

     57,891      7,904      16,137      16,655      17,195

Power Supply Contract Obligations—NH

     57,015      13,847      23,807      14,535      4,826

Gas Supply Contracts

     23,612      19,989      2,734      790      99
    

  

  

  

  

Total Contractual Cash Obligations

   $ 267,575    $ 42,729    $ 44,500    $ 33,563    $ 146,783
    

  

  

  

  

 

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

 

The Company also provides limited guarantees on certain electric supply contracts entered into by the retail distribution utilities. The Company’s policy is to limit these guarantees to two years or less. As of December 31, 2005 there are $6.0 million of guarantees outstanding and these guarantees extend through October 24, 2007.

 

Financial Covenants and Restrictions

 

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

 

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

 

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

 

Both the UES and FG&E instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into or to sell or otherwise dispose of all or substantially all of its assets.

 

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In addition, the UES and FG&E long-term debt instruments and agreements contain certain restrictions on the payment of common dividends from Retained Earnings. On December 31, 2005, UES and FG&E had unrestricted Retained Earnings of $13,300,000 and $7,842,000, respectively, available for the payment of common dividends. (See Note 3). UES and FG&E pay dividends to their sole shareholder, Unitil Corporation, and these dividends are the primary source of cash for the payment of dividends to Unitil shareholders.

 

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

 

Results of Operations—Cash Flows

 

Cash Provided by Operating Activities—Cash provided by operating activities was $24.1 million in 2005, a decrease of $6.6 million compared to 2004. This decrease is due to changes in the Company’s working capital requirements. Uses of cash for Accounts Receivable increased by $4.9 million due to higher receivable balances at year-end related to higher energy costs in 2005. Sources of cash from Accounts Payable increased by $3.1 million, due to payables on higher year over year wholesale energy contracts. Sources of cash from Prepayments and Other decreased by $4.2 million in 2005, compared to 2004, primarily related to prepayments to wholesale electricity suppliers made in 2003 that were applied in 2004. Income tax payments increased by $3.6 million in 2005 compared to the previous fiscal year. Sources of cash from Other, net increased by $4.1 million in 2005 compared to 2004, due to a refund to customers in 2004 of $1.2 million and an increase of $2.9 million in liabilities related to the Company’s retiree benefit plans and other liabilities in 2005. All other changes in cash flows from operating activities were a net increase of $1.1 million in uses of cash in 2005 compared to 2004.

 

Cash flows from operating activities of $30.6 million increased by $15.0 million in 2004 compared to 2003. This increase is due to changes in the Company’s working capital requirements. Sources of cash from Accrued Revenues increased $7.1 million, principally due to the recovery of 2003 deferred energy costs. In addition, sources of cash from Prepayments and Other increased $8.8 million in 2004 compared to 2003, primarily related to prepayments to wholesale electricity suppliers made in 2003 that were applied in 2004. All other changes in cash flows from operating activities were a net increase of ($0.8 million) in uses of cash in 2004 compared to 2003.

 

     2005

   2004

   2003

Cash Provided by Operating Activities (000’s)

   $ 24,076    $ 30,648    $ 15,621
    

  

  

 

Cash (Used in) Investing Activities—Cash flows used in investing activities increased by $1.4 million in 2005 compared to 2004, and by $1.0 million in 2004 as compared to 2003. Cash used in investing activities is primarily for capital expenditures related to UES’ and FG&E’s electric and gas distribution systems. Capital expenditures are projected to be $37.2 million in 2006, reflecting normal electric and gas utility system additions and a $10.8 million expenditure for the initial phase of the Company’s Automated Metering Infrastructure (AMI) project. The 2006 AMI projected expenditures compares with approximately $2.2 million of AMI expenditures in 2005.

 

     2005

    2004

    2003

 

Cash (Used in) Investing Activities (000’s)

   $ (24,367 )   $ (22,922 )   $ (21,939 )
    


 


 


 

Cash Provided by (Used in) Financing Activities—Cash provided by financing activities was $0.5 million in 2005, principally reflecting financing proceeds from the issuance of $15.0 million of long-term notes and $1.0 million of Common Stock which were substantially offset by the payment of dividends amounting to $7.8 million and repayment of $7.0 million of short-term bank indebtedness.

 

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

 

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Cash used in financing activities was $8.5 million in 2004. In 2004, cash sources from increasing short-term debt by $3.3 million were offset by cash uses of $3.3 million to repay long-term debt, resulting in no net increase in total debt outstanding. In addition, the Company paid $7.9 million in common and preferred dividends in 2004 and redeemed Preferred Stock for $0.9 million.

 

Cash provided by financing activities in 2003 was $2.9 million, reflecting financing proceeds of $27.7 million from the issuance of common stock equity and new long-term debt, which was partially offset by the repayment of short-term borrowings of $13.6 million and long-term debt sinking fund payments of $3.2 million.

 

On October 29, 2003, the Company raised approximately $16.9 million (after deducting underwriting discounts and commissions and the expenses of the offering) through the sale of 717,600 shares of its common stock at a price of $25.40 per share in a registered public offering. The offering was increased from an original 520,000 shares to reflect a 20% upsizing of the transaction (104,000 shares) and the exercise of a 15% underwriters’ over-allotment (93,600 shares).

 

On October 28, 2003, FG&E completed a $10 million private placement of long-term unsecured notes with a major insurance company. The notes have a term of 22 years and a coupon rate of 6.79%.

 

     2005

   2004

    2003

Cash Provided by (Used in) Financing Activities (000’s)

   $ 466    $ (8,460 )   $ 2,924
    

  


 

 

Dividends

 

Unitil’s annualized common dividend was $1.38 per common share in 2005, 2004 and 2003. Unitil’s dividend policy is reviewed periodically by the Board of Directors. 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.

 

Interest Rate Risk

 

As discussed above, Unitil meets its external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if the average amount of short-term debt outstanding of $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rate on short-term borrowings was 3.8%, 1.9% and 1.8% during 2005, 2004 and 2003, respectively.

 

Market Risk

 

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

 

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Regulatory Matters

 

Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 in regards to certain bookkeeping, accounting and reporting requirements. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the SEC with respect to various matters, including: the issuance of securities, capital structure, and certain acquisitions and dispositions of assets. As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed. Unitil’s utility operations related to wholesale and interstate business activities are also regulated by FERC. The retail distribution utilities, UES and FG&E, are subject to regulation by the NHPUC and the MDTE, respectively, in regards to their rates, issuance of securities and other accounting and operational matters. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

 

Unitil’s retail distribution utilities have the franchise to deliver electricity and/or natural gas to all customers in our franchise areas, at rates established under traditional cost of service regulation. Under this regulatory structure, UES and FG&E recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in Massachusetts and New Hampshire, Unitil’s customers have the opportunity to purchase their electric or natural gas supplies from third-party vendors. Most customers, however, continue to purchase such supplies through UES and FG&E as the provider of last resort. UES and FG&E purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling rate mechanisms that are periodically adjusted.

 

In connection with the implementation of retail choice, Unitil Power and FG&E divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDTE, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next five to seven years, is $154 million as of December 31, 2005 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

 

FG&E—Electric Division—FG&E’s primary business is providing electric distribution service under rates approved by the MDTE in 2002. FG&E had been required to purchase and provide power, as the provider of last resort, through either Standard Offer Service (Standard Offer) or Default Service, for retail customers who chose not to buy, or were unable to purchase, energy from a competitive supplier. The seven year term of Standard Offer, which included a requirement to provide service at rate levels which reflected state-mandated rate reductions, expired on February 28, 2005. FG&E continues to be required to be the supplier of last resort for its customers, however, and on March 1, 2005, customers previously on Standard Offer were automatically placed on Default Service. Prices for Default Service are set periodically based on market solicitations as approved by the MDTE. As of December 31, 2005, competitive suppliers were serving approximately 35 percent of FG&E’s electric load.

 

As a result of the restructuring and the divestiture of FG&E’s owned generation assets and buyout of FG&E’s power supply obligations, Regulatory Assets on the Company’s balance sheets include the following three categories: Power Supply Buyout Obligations associated with the divestiture of its long-term purchase power obligations; Recoverable Deferred Restructuring Charges resulting from the restructuring legislation’s seven year rate cap; and Recoverable Generation-related Assets associated with the divestiture of its owned generation plant. FG&E earns carrying charges on the majority of the unrecovered balances of the Recoverable Deferred Restructuring Charges. The value of FG&E’s Recoverable Deferred Restructuring Charges and Recoverable Generation-related Assets was approximately $38.0 million at December 31, 2005, and $35.0

 

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million at December 31, 2004, and is expected to be recovered in FG&E’s rates over the next five to seven years. In addition, as of December 31, 2005, FG&E had recorded on its balance sheets $57.9 million as Power Supply Buyout Obligations and corresponding Regulatory Assets associated with the divestiture of its long-term purchase power contracts, which are included in Unitil’s consolidated financial statements, and on which carrying charges are not earned as the timing of cash disbursements and cash receipts associated with these long-term obligations is matched through rates. See Note 1.

 

In May, 2005, the MDTE approved a Settlement Agreement among FG&E, the Massachusetts Office of the Attorney General (Attorney General), and representatives of industrial and low-income customers, in regards to future recovery of the deferred and unrecovered amounts described above. The Settlement Agreement provides for a rate path to allow recovery of FG&E’s deferred stranded costs.

 

In March 2003, the MDTE opened an investigation into whether FG&E is in compliance with relevant statutes and regulations pertaining to transactions with affiliated companies and the MDTE’s requirements for the pricing and procurement of Default Service. FG&E has asserted that the transaction in question with Enermetrix was not an affiliate transaction and resulted in net benefits to FG&E’s customers. Hearing and briefing of the case were completed in 2003 and an MDTE decision is pending. Management believes the outcome of this matter will not have a material adverse effect on the financial position of the Company.

 

On December 1, 2005, FG&E filed its annual reconciliation and rate filing with the MDTE under its restructuring plan, seeking revised rates for transmission charges, transition charges, and default service adjustment. The revised rates were approved to go into effect January 1, 2006, subject to further investigation. FG&E made similar filings in 2002, 2003, and 2004, which were also approved subject to further investigation. On May 19, 2005, the MDTE, after investigation, issued an order approving FG&E’s 2002 filing. Final review of FG&E’s 2003 and 2004 filings, and FG&E’s 2005 filing which is subject to investigation, are pending. Management believes that these filings will be approved without material change or adjustment.

 

FG&E—Gas Division—FG&E provides natural gas delivery service to its customers on a firm or interruptible basis under unbundled distribution rates approved by the MDTE in 2002. FG&E’s customers may purchase gas supplies from third-party vendors or purchase their gas from FG&E as the provider of last resort. FG&E collects its gas supply costs through a seasonal Cost of Gas Adjustment Clause (CGAC) and recovers other related costs through a reconciling Local Distribution Adjustment Clause. FG&E filed, and received MDTE approval of rate changes for reconciling clauses effective January 1, 2005, May 1, 2005, October 1, 2005 and November 1, 2005.

 

In 2001, the MDTE required the mandatory assignment of local distribution company’s (LDC’s) pipeline capacity to competitive marketers selling gas to FG&E’s customers, thus protecting FG&E from exposure to costs for stranded capacity. In January 2004, the MDTE opened an investigation on whether the mandatory assignment of pipeline capacity should be continued. On June 6, 2005, the MDTE issued its order ruling that mandatory capacity assignment shall continue.

 

FG&E—Other—On October 27, 2004 the MDTE approved FG&E’s request for a reconciliation rate adjustment mechanism to provide for the recovery of costs associated with the Company’s employee pension benefits and Post Retirement Benefits Other than Pension (PBOP) expenses. FG&E is allowed to record a regulatory asset in lieu of taking a charge to expense for the difference between the level of pension and PBOP expenses that are included in its base rates and the amounts that are required to be recorded in accordance with SFAS No. 87 and SFAS No. 106, since the effective date of its last base rate change. This mechanism provides for an annual filing and rate adjustment with the MDTE. As of December 31, 2005, FG&E has recorded a regulatory asset of $2.5 million which is included as part of Regulatory Assets in the Company’s Consolidated Balance Sheets. FG&E filed, and received MDTE approval of, revised pension/PBOP adjustment factors (PAFs) effective November 1, 2005 for its gas division and January 1, 2006 for its electric division.

 

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On November 30, 2005, the MDTE announced a change in its method for recovery of gas cost-related bad debt, and determined that it would allow for full recovery of these costs on a reconciling basis. On December 15, 2005, FG&E filed a revised CGAC tariff reflecting this change which was approved effective January 1, 2006. FG&E also requested approval to recover its under-recovered gas cost-related bad debt for 2005 of approximately $164 thousand. A decision on this request is expected in 2006.

 

UES—UES provides electric distribution service to its customers pursuant to rates established under a 2002 restructuring settlement. On May 1, 2004, these distribution rates were increased by $1.0 million to provide for the recovery of PBOP costs. As the provider of last resort, UES also provides its customers with electric power through either Transition or Default Service at rates which reflect UES’ costs for wholesale supply with no profit or markup. UES recovers its costs for this service through reconciling rate mechanisms.

 

In the 2002 restructuring settlement, the NHPUC approved the divestiture of the long-term power supply portfolio by Unitil Power and tariffs for UES for stranded cost recovery and Transition and Default Service, including certain charges that are subject to annual or periodic reconciliation or future review. As of December 31, 2005, UES had recorded on its balance sheets $57.0 million as Power Supply Contract Obligations and corresponding Regulatory Assets associated with these long-term purchase power stranded costs, which are included in Unitil Corporation’s consolidated financial statements. These Power Supply Contract Obligations are expected to be recovered principally over a period of approximately five years. The Company does not earn carrying charges on these regulatory assets as the timing of cash receipts and cash disbursements associated with these long-term obligations is matched through rates.

 

The NHPUC approved UES’ second annual reconciliation and rate filing under its restructuring plan effective May 1, 2005, including revised rates for the Transition Service Charge, Default Service Charge, Stranded Cost Charge, and External Delivery Charge.

 

On December 11, 2004, UES filed with the NHPUC a Petition for an accounting order to defer certain pension costs above those included in its base rates, until UES filed its next base rate case, which, pursuant to the last base rate case settlement, was required to be filed no later than October 2007 (also see Note 8 below). On April 7, 2005, the NHPUC issued an order denying UES’ Petition for an accounting order. In its analysis denying UES’ request, the NHPUC indicated that pension expense is an ordinary category of expense included in the revenue requirement for a utility under traditional cost of service ratemaking principles and that a full examination of UES’ income and expenses would be undertaken when UES files a rate case. As of December 31, 2005, UES has recorded deferred pension costs of $1.0 million.

 

On November 4, 2005, UES filed a request for a base rate increase of $4.65 million. The filing includes a request to recover pension and PBOP costs through an annual reconciling rate mechanism, and a step adjustment for certain future rate base additions. The filing also requested that temporary rates be established at current rate levels effective December 4, 2005. On February 3, 2006, the NHPUC issued an order approving this request. Any rate change ultimately awarded by the NHPUC will be retroactive to January 1, 2006. The overall rate filing is currently under review, with an NHPUC order anticipated before November 2006. It is anticipated that the final determination of the amount and method of recovering UES’ pension and PBOP costs will be decided in the base rate case. The Company cannot determine the ultimate outcome of this proceeding.

 

On January 7, 2005, the NHPUC approved UES’ petition for a one year extension of Transition Service and Default Service for rate class G1, and the associated solicitation process whereby UES intends to secure energy supplies for such extended service. As a result, UES’ Transition Service supply obligation for all rate classes will end at the same time on April 30, 2006. The Company recovers the costs of Transition Service and Default Service in its rates at cost on a pass-through basis and therefore changes in these expenses do not affect earnings.

 

On April 1, 2005, UES filed a petition with the NHPUC for approval of a plan for procurement of Default Service power supply for service, commencing on May 1, 2006 for all rate classes. A settlement supporting the plan between UES, the Office of Consumer Advocate and the NHPUC Staff, was approved by the NHPUC on

 

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September 9, 2005. Under the approved plan, UES will procure Default Service power for its larger commercial and industrial customers on a quarterly basis, and for its smaller commercial and residential customers through a portfolio of longer term contracts on a semi-annual basis.

 

Under the 2002 restructuring plan approved by the NHPUC, Unitil Power sold the entitlements to its long-term power supply portfolio to Mirant and UES purchased supplies for Transition and Default Service from Mirant for up to three years. Following the Chapter 11 bankruptcy filing by Mirant in July, 2003, Mirant agreed to continue to perform all obligations under its contracts with Unitil Power and UES pursuant to a settlement approved by the bankruptcy court in December 2003. As a result of the Mirant bankruptcy, UES and Unitil Power also pursued claims with Mirant with regards to a potential future default. In January 2005, UES, Unitil Power and Mirant filed a settlement with the bankruptcy court under which Mirant has agreed to put in place a replacement guarantee, or comparable security, to guarantee performance of its responsibilities under the agreement beginning May 2006. That settlement was approved by the bankruptcy court on January 18, 2005. On January 3, 2006, Mirant emerged from Chapter 11.

 

FERC—Wholesale Power Market Restructuring—FG&E, UES and Unitil Power are members of the NEPOOL, formed in 1971 to assure reliable operation of the bulk power system in the most economic manner for the region. NEPOOL is governed by the NEPOOL Agreement that is filed with and subject to the jurisdiction of the FERC. Under the NEPOOL Agreement and the OATT, to which virtually all New England electric utilities are parties, substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. The NEPOOL Agreement and the OATT impose generating capacity and reserve obligations, and provide for the use of major transmission facilities and support payments associated therewith. The most notable benefits of NEPOOL are coordinated power system operation in a reliable manner and a supportive business environment for the development of a competitive electric supply marketplace. The regional bulk power system is operated by an independent corporate entity, the ISO-NE, in order to avoid any opportunity for conflicting financial interests between the system operator and the market-driven participants.

 

As of February 1, 2005, a RTO was established in New England. ISO-NE became the entity responsible for operating the RTO. The market rules and requirements to participate in the markets previously covered under the NEPOOL Agreement were transferred to the new RTO structure under control of ISO-NE. FERC approved the formation of the RTO in orders issued March 24, 2004 and November 3, 2004 to begin operation of the RTO structure effective February 1, 2005. As a result of the formation of the RTO, companies seeking transmission service throughout New England will be able to obtain that service under common terms, with much of their focus on dealing with ISO-NE, in cooperation with the local transmission providers. Several parties have appealed various issues associated with the FERC’s approval of the RTO to Federal District Court of Appeals. Those proceedings are ongoing.

 

On March 1, 2004, ISO-NE filed a proposal to implement LICAP in New England to allow for the imposition of incentive pricing for transmission constrained areas. Both UES and FG&E are located in a non-constrained area of the power pool which should have modest LICAP prices for several years under the filed proposal. UES and FG&E have intervened in the proceeding. On October 21, 2005 the FERC issued an order directing that Settlement discussions take place and indicating that implementation of LICAP, if it proceeds, will not be earlier than October 1, 2006. This case continues to be contested at the FERC.

 

The formation of an RTO, LICAP and other wholesale market changes, including changes to transmission rates, is not expected to have a material impact on Unitil’s operations because of the cost recovery mechanisms for wholesale energy costs approved by the MDTE and NHPUC. It is possible, however, that retail rates will be significantly increased over the next several years if LICAP is implemented consistent with the Initial Decision.

 

FERC—Other—In August 2003, Northeast Utilities (NU) filed with FERC to revise its comprehensive network service transmission rates to establish and implement a formula based rate, replacing a fixed rate tariff. A settlement among certain parties was approved by the FERC in September 2004, which reduced the allowed return on equity in the formula rates and resulted in refunds to the tariff customers, including UES.

 

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On March 30, 2005, NU filed an executed Distribution Service Agreement (DSA) settlement between UES and NU with the FERC for effect on June 1, 2005. The DSA provides for cost recovery by NU for facilities used by UES that had been reclassified from transmission plant to distribution plant. On April 20, 2005 UES intervened in support of the DSA. Costs to UES under the DSA are estimated to be approximately $2 million annually. These costs are expected to be recovered through reconciling cost recovery mechanisms. On May 19, 2005 the FERC accepted NU’s DSA filing and the rates went into effect on June 1, 2005.

 

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 is in general compliance with all applicable environmental and safety laws and regulations, and management believes that as of December 31, 2005, there are no material losses reasonably possible in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

 

Sawyer Passway MGP Site—The Company continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows the Company to work towards temporary remediation of the site. Work performed in 2002 was associated with the five-year review of the Temporary Solution submittal (Class C Response Action Outcome) under the Massachusetts Contingency Plan (MCP) that was filed for the site in 1997. Completion of this work has confirmed the Temporary Solution status of the site for an additional five years, to January 2008. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed. During 2005, FG&E continued developing a long range plan for a Permanent Solution for the site, including alternatives for re-use of the site.

 

On May 13, 2004 FG&E discovered an unauthorized excavation by another property owner on the site at Sawyer Passway in which tainted soils related to MGP by-products were exposed and relocated onto property owned by FG&E. FG&E promptly reported this discovery to the DEP and subsequently received a Notice of Responsibility on May 20, 2004. FG&E has properly disposed of the relocated materials and taken other steps in accordance with DEP directives to remedy the situation. The Completion Report for this release was submitted May 9, 2005.

 

Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to an MDTE approved settlement agreement between the Massachusetts Attorney General and the natural gas utilities of the Commonwealth of Massachusetts (Agreement). The Agreement allows FG&E to amortize and recover from gas customers over succeeding seven-year periods the environmental response costs incurred each year. Environmental response costs are defined to include liabilities related to manufactured gas sites, waste disposal sites or other sites onto which hazardous material may have migrated as a result of the operation or decommissioning of Massachusetts gas manufacturing facilities from 1822 through 1978. In addition, any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers. The total annual charge for such costs assessed to gas customers cannot exceed five percent of FG&E’s total revenue for firm gas sales during the preceding year. Costs in excess of five percent will be deferred for recovery in subsequent years.

 

Critical Accounting Policies

 

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect

 

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

 

Regulatory Accounting—The Company’s principal business is the distribution of electricity and natural gas by the retail distribution companies: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and FG&E is regulated by the MDTE and UES is regulated by the NHPUC. Accordingly, the Company uses the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered or refunded in future electric and gas retail rates.

 

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

 

The Company’s principal regulatory assets and liabilities are detailed on the Company’s Consolidated Balance Sheet. The Company is currently receiving or being credited with a return on all of its regulatory assets for which a cash outflow has been made. The Company is currently paying or being charged with a return on all of its regulatory liabilities for which a cash inflow has been received. The Company’s regulatory assets and liabilities will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

 

The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s consolidated financial statements. Management believes it is probable that the Company’s regulated utility companies will recover their investments in long-lived assets, including regulatory assets. The Company also has commitments under long-term contracts for the purchase of electricity and natural gas from various suppliers. The annual costs under these contracts are included in Purchased Electricity and Purchased Gas in the Consolidated Statements of Earnings and these costs are recoverable in current and future rates under various orders issued by the FERC, MDTE and NHPUC.

 

If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. If unable to continue to apply the provisions of SFAS No. 71, the Company would be required to apply the provisions of FASB Statement No. 101, “Regulated

 

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Enterprises—Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In management’s opinion, the Company’s regulated operations will be subject to SFAS No. 71 for the foreseeable future.

 

Utility Revenue Recognition—Regulated utility revenues are based on rates approved by state and federal regulatory commissions. These regulated rates are applied to customers’ accounts based on their actual or estimated use of energy. Energy sales to customers are based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

 

Allowance for Doubtful Accounts—The Company recognizes a Provision for Doubtful Accounts each month. The amount of the monthly Provision is based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. Account write-offs, net of recoveries, are processed monthly. At the end of each month, an analysis of the delinquent receivables is performed and the adequacy of the Allowance for Doubtful Accounts is reviewed. The analysis takes into account an assumption about the cash recovery of delinquent receivables and also uses calculations related to customers who have chosen payment plans to resolve their arrears. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis. Also, the Company has experienced periods when state regulators have extended the periods during which certain standard credit and collection activities of utility companies are suspended. In periods when account write-offs exceed estimated levels, the Company adjusts the Provision for Doubtful Accounts to maintain an adequate Allowance for Doubtful Accounts balance.

 

Pension and Postretirement Benefit Obligations—The Company has a defined benefit pension plan covering substantially all its employees and also provides certain other post-retirement benefits (PBOP), primarily medical and life insurance benefits to retired employees. The Company also has a Supplemental Executive Retirement Plan (SERP) covering certain executives of the Company. The Company accounts for these benefits in accordance with FASB Statement No. 87, “Employers’ Accounting for Pensions” and FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions.” In applying these accounting policies, the Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on several significant assumptions.

 

The Company’s reported costs of providing pension and PBOP benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company’s health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. Pension and PBOP costs (collectively “postretirement costs”) 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 postretirement costs. Postretirement costs 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 postretirement costs and benefit obligations. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s consolidated financial statements. See Note 8.

 

Pension expense is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets. In developing the expected long-term rate of return assumption, the Company evaluated input from actuaries and investment managers. The Company’s expected long-term rate of return on

 

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Plan assets is based on target asset allocation assumptions of 60% in common stock equities and 40% in fixed income securities. The Company will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.

 

The discount rate that is utilized in determining future pension obligations is based on long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For 2005, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 in the Net Periodic Pension Cost. Similarly, for 2004 and 2003, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 and $150,000, respectively. The compensation cost increase assumptions used for 2005, 2004 and 2003 were 3.50%, 3.50% and 4.00%, respectively, based on the expected long-term increase in compensation costs for personnel covered by the Plan.

 

Income Taxes—Income tax expense is calculated in each of the jurisdictions in which the Company operates for each period for which a statement of income is presented. This process involves estimating the Company’s actual current tax liabilities as well as assessing temporary and permanent differences resulting from differing treatment of items, such as timing of the deduction of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. The Company must also assess the likelihood that the deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation allowances. The Company accounts for deferred taxes under FASB Statement No. 109, “Accounting for Income Taxes.” The Company does not currently have any valuation allowances against its recorded deferred tax amounts. See Note 7.

 

Depreciation—Depreciation expense is calculated based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. 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.

 

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, 2005, the Company is not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

 

Refer to “Recently Issued Accounting Pronouncements’ in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.

 

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

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 

Reference is made to Item 1A. “Risk Factors” and the “Interest Rate Risk” and “Market Risk” sections of Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (above).

 

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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 sheet and consolidated statement of capitalization of Unitil Corporation and subsidiaries as of December 31, 2005, and the related consolidated statements of earnings, cash flows and changes in common stock equity for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

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

 

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

 

/s/ Vitale, Caturano & Co. Ltd.

 

Boston, Massachusetts

February 3, 2006

 

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Report of Independent Registered Public Accounting Firm

 

To the Shareholders of Unitil Corporation:

 

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Unitil Corporation and subsidiaries as of December 31, 2004, and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the two years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

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

 

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

 

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

 

/s/ GRANT THORNTON LLP

 

Boston, Massachusetts

February 17, 2005

 

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Report of Independent Registered Public Accounting Firm

 

To the Shareholders of Unitil Corporation:

 

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that Unitil Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

 

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

 

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

 

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

 

In our opinion, management’s assessment that Unitil Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the COSO. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in the Internal Control-Integrated Framework issued by COSO.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and consolidated statements of capitalization of Unitil Corporation and subsidiaries as of December 31, 2005, and the related consolidated statements of earnings, cash flows and changes in common stock equity for the year then ended, and our report dated February 3, 2006, expressed an unqualified opinion on those consolidated financial statements.

 

/s/ Vitale, Caturano & Co. Ltd.

 

Boston, Massachusetts

February 3, 2006

 

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CONSOLIDATED STATEMENTS OF EARNINGS

 

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

 

Year Ended December 31,


   2005

   2004

   2003

 

Operating Revenues:

                      

Electric

   $ 197,338    $ 183,889    $ 190,864  

Gas

     32,768      28,685      28,612  

Other

     2,039      1,563      1,178  
    

  

  


Total Operating Revenues

     232,145      214,137      220,654  
    

  

  


Operating Expenses:

                      

Purchased Electricity

     138,134      125,940      134,036  

Purchased Gas

     21,225      17,486      17,421  

Operation and Maintenance

     24,514      23,297      22,706  

Conservation & Load Management

     4,115      4,003      3,930  

Depreciation and Amortization

     19,123      18,830      18,756  

Provisions for Taxes:

                      

Local Property and Other

     5,218      5,182      4,805  

Federal and State Income

     4,275      4,206      3,551  
    

  

  


Total Operating Expenses

     216,604      198,944      205,205  
    

  

  


Operating Income

     15,541      15,193      15,449  

Other Non-Operating Expenses (Income)

     147      193      (40 )
    

  

  


Income Before Interest Expense

     15,394      15,000      15,489  

Interest Expense, net

     6,841      6,774      7,531  
    

  

  


Net Income

     8,553      8,226      7,958  

Less Dividends on Preferred Stock

     156      215      236  
    

  

  


Earnings Applicable to Common Shareholders

   $ 8,397    $ 8,011    $ 7,722  
    

  

  


Average Common Shares Outstanding—Basic

     5,551,420      5,509,321      4,877,933  

Average Common Shares Outstanding—Diluted

     5,567,718      5,524,835      4,896,329  
    

  

  


Earnings per Common Share—Basic and Diluted

   $ 1.51    $ 1.45    $ 1.58  
    

  

  


 

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

 

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CONSOLIDATED BALANCE SHEETS (000’s)

 

ASSETS

 

December 31,


   2005

   2004

Utility Plant:

             

Electric

   $ 234,153    $ 222,121

Gas

     58,675      53,208

Common

     26,515      28,271

Construction Work in Progress

     5,624      4,454
    

  

Utility Plant

     324,967      308,054

Less: Accumulated Depreciation

     111,646      104,051
    

  

Net Utility Plant

     213,321      204,003
    

  

Current Assets:

             

Cash

     3,207      3,032

Accounts Receivable—(Net of Allowance for Doubtful Accounts of $470 and $501)

     23,631      18,119

Accrued Revenue

     8,905      9,754

Refundable Taxes

     351      977

Material and Supplies

     3,675      3,080

Prepayments and Other

     1,612      1,771
    

  

Total Current Assets

     41,381      36,733
    

  

Noncurrent Assets:

             

Regulatory Assets

     179,719      199,608

Prepaid Pension

     11,099      10,990

Debt Issuance Costs, net

     2,343      2,265

Other Noncurrent Assets

     2,218      3,411
    

  

Total Noncurrent Assets

     195,379      216,274
    

  

TOTAL

   $ 450,081    $ 457,010
    

  

 

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

 

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

 

CAPITALIZATION AND LIABILITIES

 

December 31,


   2005

   2004

Capitalization:

             

Common Stock Equity

   $ 96,283    $ 94,291

Preferred Stock, Non-Redeemable, Non-Cumulative

     225      225

Preferred Stock, Redeemable, Cumulative

     2,102      2,113

Long-Term Debt, Less Current Portion

     125,365      110,675
    

  

Total Capitalization

     223,975      207,304
    

  

Current Liabilities:

             

Long-Term Debt, Current Portion

     308      285

Capitalized Leases, Current Portion

     261      413

Accounts Payable

     20,600      16,249

Short-Term Debt

     18,700      25,675

Dividends Declared and Payable

     50      50

Refundable Customer Deposits

     2,031      1,545

Interest Payable

     1,353      1,328

Other Current Liabilities

     2,677      5,607
    

  

Total Current Liabilities

     45,980      51,152
    

  

Deferred Income Taxes

     52,297      56,156
    

  

Noncurrent Liabilities:

             

Power Supply Contract Obligations

     114,906      140,448

Capitalized Leases, Less Current Portion

     324      183

Other Noncurrent Liabilities

     12,599      1,767
    

  

Total Noncurrent Liabilities

     127,829      142,398
    

  

TOTAL

   $ 450,081    $ 457,010
    

  

 

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

 

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CONSOLIDATED STATEMENTS OF CAPITALIZATION

 

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

 

December 31,


   2005

   2004

Common Stock Equity

             

Common Stock, No Par Value (Authorized—8,000,000 shares;
Outstanding—5,595,523 and 5,546,620 shares)

   $ 60,826    $ 59,795

Stock Compensation Plans

     1,310      1,059

Retained Earnings

     34,147      33,437
    

  

Total Common Stock Equity

     96,283      94,291
    

  

Preferred Stock

             

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

             

6.00% Series, $100 Par Value

     225      225

FG&E Preferred Stock, Redeemable, Cumulative:

             

5.125% Series, $100 Par Value

     892      899

8.00% Series, $100 Par Value

     1,210      1,214
    

  

Total Preferred Stock

     2,327      2,338
    

  

Long-Term Debt

             

UES First Mortgage Bonds:

             

8.49% Series, Due October 14, 2024

     15,000      15,000

6.96% Series, Due September 1, 2028

     20,000      20,000

8.00% Series, Due May 1, 2031

     15,000      15,000

FG&E Long-Term Notes:

             

6.75% Notes, Due November 30, 2023

     19,000      19,000

7.37% Notes, Due January 15, 2029

     12,000      12,000

7.98% Notes, Due June 1, 2031

     14,000      14,000

6.79% Notes, Due October 15, 2025

     10,000      10,000

5.90% Notes, Due December 15, 2030

     15,000     

Unitil Realty Corp. Senior Secured Notes:

             

8.00% Notes, Due August 1, 2017

     5,673      5,960
    

  

Total Long-Term Debt

     125,673      110,960

Less: Long-Term Debt, Current Portion

     308      285
    

  

Total Long-Term Debt, Less Current Portion

     125,365      110,675
    

  

Total Capitalization

   $ 223,975    $ 207,304
    

  

 

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

 

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CONSOLIDATED STATEMENTS OF CASH FLOWS (000’s)

 

 

Year Ended December 31,


   2005

    2004

    2003

 

Operating Activities:

                        

Net Income

   $ 8,553     $ 8,226     $ 7,958  

Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:

                        

Depreciation and Amortization

     19,123       18,830       18,756  

Deferred Tax (Benefit) Provision

     (240 )     3,166       6,375  

Changes in Current Assets and Liabilities:

                        

Accounts Receivable

     (5,512 )     (658 )     2,052  

Accrued Revenue

     849       275       (6,795 )

Refundable Taxes

     626       2,839       1,035  

Materials and Supplies

     (595 )     (219 )     (538 )

Prepayments and Other

     159       4,375       (4,411 )

Accounts Payable

     4,351       1,225       803  

Refundable Customer Deposits

     486       116       93  

Interest Payable

     25       (28 )     45  

Other Current Liabilities

     1,311       1,353       (4,808 )

Deferred Restructuring and Other Charges

     (6,256 )     (5,900 )     (6,058 )

Other, net

     1,196       (2,952 )     1,114  
    


 


 


Cash Provided by Operating Activities

     24,076       30,648       15,621  
    


 


 


Investing Activities:

                        

Property, Plant and Equipment Additions

     (24,367 )     (22,922 )     (21,939 )
    


 


 


Cash Used In Investing Activities

     (24,367 )     (22,922 )     (21,939 )
    


 


 


Financing Activities:

                        

Proceeds from (Repayment of) Short-Term Debt

     (6,975 )     3,265       (13,580 )

Issuance of Long-Term Debt

     15,000             10,000  

Repayment of Long-Term Debt

     (286 )     (3,264 )     (3,244 )

Retirement of Preferred Stock

     (11 )     (931 )     (53 )

Dividends Paid

     (7,843 )     (7,857 )     (7,056 )

Issuance of Common Stock

     1,031       947       17,628  

Repayment of Capital Lease Obligations

     (450 )     (620 )     (771 )
    


 


 


Cash Provided by (Used In) Financing Activities

     466       (8,460 )     2,924  
    


 


 


Net Increase (Decrease) in Cash

     175       (734 )     (3,394 )

Cash at Beginning of Year

     3,032       3,766       7,160  
    


 


 


Cash at End of Year

   $ 3,207     $ 3,032     $ 3,766  
    


 


 


Supplemental Information:

                        

Interest Paid

   $ 9,455     $ 9,052     $ 9,113  

Income Taxes Paid (Refunded)

   $ 4,544     $ 990     $ (2,541 )

Supplemental Schedule of Noncash Activities:

                        

Capital Leases Incurred

   $ 439     $ 246     $ 109  

 

 

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

 

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CONSOLIDATED STATEMENTS OF

CHANGES IN COMMON STOCK EQUITY

 

(000’s except number of shares)

 

     Common
Shares


   Stock
Compensation
Plans


    Retained
Earnings


    Total

 

Balance at January 1, 2003

   $ 41,220    $ 990     $ 32,140     $ 74,350  

Net Income for 2003

                    7,958       7,958  

Dividends on Preferred Shares

                    (236 )     (236 )

Dividends on Common Shares

                    (6,813 )     (6,813 )

Stock Compensation Plans

            (82 )             (82 )

Common Stock Offering—717,600 Shares

     16,911                      16,911  

Issuance of 28,714 Common Shares

     717                      717  
    

  


 


 


Balance at December 31, 2003

     58,848      908       33,049       92,805  

Net Income for 2004

                    8,226       8,226  

Dividends on Preferred Shares

                    (215 )     (215 )

Dividends on Common Shares

                    (7,623 )     (7,623 )

Stock Compensation Plans

            151               151  

Issuance of 35,310 Common Shares

     947                      947  
    

  


 


 


Balance at December 31, 2004

     59,795      1,059       33,437       94,291  

Net Income for 2005

                    8,553       8,553  

Dividends on Preferred Shares

                    (156 )     (156 )

Dividends on Common Shares

                    (7,687 )     (7,687 )

Stock Compensation Plans

            251               251  

Issuance of 38,003 Common Shares

     1,031                      1,031  
    

  


 


 


Balance at December 31, 2005

   $ 60,826    $ 1,310     $ 34,147     $ 96,283  
    

  


 


 


 

(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. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the Securities and Exchange Commission (SEC). As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (UES) (formed in 2002 by the combination and merger of Unitil’s former utility subsidiaries Concord Electric Company and Exeter & Hampton Electric Company), Fitchburg Gas and Electric Light Company (FG&E), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource, Inc. and Usource L.L.C. are subsidiaries of Unitil Resources.

 

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

 

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

 

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-utility unregulated subsidiary that provides consulting and management related services. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.

 

Basis of Presentation

 

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

 

Regulatory Accounting—The Company’s principal business is the distribution of electricity and natural gas in the Company-owned retail distribution utilities: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and FG&E is regulated by the Massachusetts Department of Telecommunications and Energy (MDTE) and UES is regulated by the New Hampshire Public Utilities Commission (NHPUC). Accordingly, the Company uses the provisions of Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered in future electric and gas retail rates.

 

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

 

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provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under SFAS No. 71. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under SFAS No. 71.

 

The Company’s principal regulatory assets and liabilities are detailed on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided below. The Company is currently receiving or being credited with a return on all of its regulatory assets for which a cash outflow has been made. The Company is currently paying or being charged with a return on all of its regulatory liabilities for which a cash inflow has been received. The Company’s regulatory assets and liabilities will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

 

The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s consolidated financial statements. Management believes it is probable that the Company’s regulated utility companies will recover their investments in long-lived assets, including regulatory assets. The Company also has commitments under long-term contracts for the purchase of electricity and natural gas from various suppliers. The annual costs under these contracts are included in Purchased Electricity and Purchased Gas in the Consolidated Statements of Earnings and these costs are recoverable in current and future rates under various orders issued by the FERC, MDTE and NHPUC.

 

     December 31,

Regulatory Assets consist of the following (000’s)


   2005

   2004

Power Supply Buyout Obligations

   $ 114,906    $ 140,448

Income Taxes

     17,546      20,670

Recoverable Deferred Restructuring Charges

     35,826      30,840

Recoverable Generation-related Assets

     3,316      5,169

Pension / Post-retirement Benefits Other than Pension

     8,125      2,481
    

  

Total Regulatory Assets

   $ 179,719    $ 199,608
    

  

 

Massachusetts and New Hampshire have both passed utility industry restructuring legislation and the Company has filed and implemented its restructuring plans in both states. The Company is allowed to recover certain types of costs through ongoing assessments to be included in future regulated service rates. Based on the recovery mechanism that allows recovery of all of its stranded costs and deferred costs related to restructuring, the Company has recorded regulatory assets that it expects to fully recover in future periods. The Company expects to continue to meet the criteria for the application of SFAS No. 71 for the distribution portion of its assets and operations for the foreseeable future. If a change in accounting for regulatory assets under SFAS No. 71 were to occur to the distribution portion of the Company’s operations, it could have a material adverse effect on the Company’s earnings and retained earnings in that year and could have a material adverse effect on the Company’s ongoing financial condition as well.

 

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 management’s opinion, the Company’s regulated subsidiaries will be subject to SFAS No. 71 for the foreseeable future.

 

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Cash—Cash includes all cash and cash equivalents to which the Company has legal title. Cash equivalents include short-term investments with original maturities of three months or less and interest bearing deposits. Financial instruments that subject the Company to credit risk concentrations consist of cash and cash equivalents and accounts receivable. The Company’s cash and cash equivalents are held at financial institutions and at times may exceed federally insured limits. The Company has not experienced any losses in such accounts. The Company believes it is not exposed to any significant credit risk on cash.

 

Goodwill and Intangible Assets—The Company does not have any goodwill recorded on its balance sheet as of December 31, 2005. There are no significant intangible assets recorded by the Company at December 31, 2005. Therefore, the Company is not currently involved in making estimates or seeking valuations of these items.

 

Off-Balance Sheet Arrangements—As of December 31, 2005, the Company does not have any significant arrangements that would be classified as Off-Balance Sheet Arrangements. In the ordinary course of business, the Company does contract for certain office equipment, vehicles and other equipment under operating leases and, in management’s opinion, the amount of these transactions is not material.

 

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

 

Derivatives—The Company enters into wholesale electric and gas energy supply contracts to serve its customers. The Company’s policy is to review each contract and determine whether they meet the criteria for classification as derivatives under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) and / or FASB Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149). As of December 31, 2005, the Company determined that none of its wholesale electric and gas energy supply contracts met the criteria for classification as a derivative instrument. Additionally, the Company may enter into interest rate hedging transactions with respect to existing indebtedness and anticipated debt offerings. As of December 31, 2005, the Company has not entered into any such transactions. However, should the Company enter into any such transactions in the future, its policy will be to review each transaction and determine whether it meets the criteria for classification as derivatives under SFAS No. 133 and / or SFAS No. 149.

 

Utility Revenue Recognition—Regulated utility revenues are based on rates approved by federal and state regulatory commissions. These regulated rates are applied to customers’ accounts based on their actual or estimated use of energy. Energy sales to customers are 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. The amount of the monthly Provision is based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. Account write-offs, net of recoveries, are processed monthly. At the end of each month, an analysis of the delinquent receivables is performed and the adequacy of the Allowance for Doubtful Accounts is reviewed. The analysis takes into account an assumption about the cash recovery of delinquent receivables and also uses calculations related to customers who have chosen payment plans to resolve their arrears. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. Evaluating the adequacy of the Allowance for

 

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Doubtful Accounts requires judgment about the assumptions used in the analysis. Also, the Company has experienced periods when state regulators have extended the periods during which certain standard credit and collection activities of utility companies are suspended. In periods when account write-offs exceed estimated levels, the Company adjusts the Provision for Doubtful Accounts to maintain an adequate Allowance for Doubtful Accounts balance.

 

Pension and Postretirement Benefit Obligations—The Company has a defined benefit pension plan covering substantially all its employees and also provides certain other post-retirement benefits (PBOP), primarily medical and life insurance benefits to retired employees. The Company also has a Supplemental Executive Retirement Plan (SERP) covering certain executives of the Company. The Company accounts for these benefits in accordance with FASB Statement No. 87, “Employers’ Accounting for Pensions” (SFAS No. 87) and FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions” (SFAS No. 106). In applying these accounting policies, the Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on several significant assumptions.

 

The Company’s reported costs of providing pension and PBOP benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company’s health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. Pension and PBOP costs (collectively “postretirement costs”) 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 postretirement costs. Postretirement costs 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 postretirement costs and benefit obligations. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s consolidated financial statements. See Note 8.

 

Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 8.50%, 8.75% and 8.75% for 2005, 2004 and 2003, respectively. In developing the expected long-term rate of return assumption, the Company evaluated input from actuaries and investment managers. The Company’s expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 60% in common stock equities and 40% in fixed income securities. The combination of these target allocations and expected returns resulted in the overall assumed long-term rate of return of 8.50% for 2005. The Company will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.

 

The Company bases the actuarial determination of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a three-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a three-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. The Company’s pension expense for the years 2005, 2004 and 2003 was $2,391,745, $1,981,667 and $1,106,827, respectively. Had the Company used the fair value of assets instead of the market-related value, pension expense for the years 2005, 2004 and 2003 would have been $2,225,181, $2,119,667 and $2,332,699 respectively.

 

The discount rate that is utilized in determining future pension obligations is based on a market average of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For the period January 1, 2005 through May 31, 2005, the discount rate used was 6.50%. In May 2005, the Company reached agreements with its union labor bargaining units for new five-year contracts, effective June 1, 2005, which

 

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resulted in amendments to the defined benefit pension plan. Effective for the period of June 1, 2005 through December 31, 2005, the Company lowered the assumed discount rate to 6.00%. The discount rates used for the 2004 and 2003 fiscal years were 6.50% and 7.00%, respectively. For 2005, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 in the Net Periodic Pension Cost. Similarly, for 2004 and 2003, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 and $150,000, respectively. The compensation cost increase assumptions used for 2005, 2004 and 2003 were 3.50%, 3.50% and 4.00%, respectively, based on the expected long-term increase in compensation costs for personnel covered by the Plan.

 

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

 

Commitments and Contingencies—The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5). SFAS No. 5 applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2005, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below. See Note 5.

 

Utility Plant—The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The average interest rates applied to AFUDC were 2.33%, 1.64% and 2.14% in 2005, 2004 and 2003, respectively. The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of and the cost of removal, less salvage, are charged to the accumulated provision for depreciation. The Company does not account separately for negative salvage, or cost of retirement obligations as defined in FASB Statement No. 143, “Accounting for Asset Retirement Obligations” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” The Company includes in its mass asset depreciation rates, which are periodically reviewed as part of its ratemaking proceedings, depreciation amounts to provide for future negative salvage value. At December 31, 2005 and December 31, 2004, the Company estimates that the negative salvage value of future retirements recorded on the balance sheet in Accumulated Depreciation is $13.4 million and $12.7 million, respectively.

 

Depreciation and Amortization—Depreciation expense is calculated based on the useful lives of assets, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements. 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.

 

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: 2005 – 4.69%, 2004 – 4.70% and 2003 – 4.73%.

 

Amortization provisions include the recovery of a portion of FG&E’s former investment in Seabrook Station, a nuclear generating unit, in rates to its customers through the Seabrook Amortization Surcharge as ordered by the

 

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MDTE. FG&E’s asset related to Seabrook Station became fully-amortized in the third quarter of 2005. In addition, FG&E is amortizing the balance of its unrecovered electric generating related assets, which are recorded as Regulatory Assets, in accordance with its electric restructuring plan approved by the MDTE. See Note 5.

 

Environmental Matters—The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. In the past three years, the Company has performed work on two environmental remediation projects, the Sawyer Passway MGP Site and the Former Electric Generating Station. The Company has or will recover substantially all of the cost of the work performed to date from customers or from its insurance carriers. The Company is in general compliance with all applicable environmental and safety laws and regulations, and management believes that as of December 31, 2005, there are no material losses that would require additional liability reserves to be recorded. Changes in future environmental compliance regulations or in future cost estimates of environmental remediation costs could have a material effect on the Company’s financial position if those amounts are not recoverable in regulatory rate mechanisms.

 

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

 

Income Taxes—Income tax expense is calculated in each of the jurisdictions in which the Company operates for each period for which a statement of income is presented. This process involves estimating the Company’s actual current tax liabilities as well as assessing temporary and permanent differences resulting from differing treatment of items, such as timing of the deduction of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. The Company must also assess the likelihood that the deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation allowances. The Company accounts for deferred taxes under FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109). The Company does not currently have any valuation allowances against its recorded deferred tax amounts. See Note 7.

 

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.

 

Recently Issued Pronouncements—In May 2005, the FASB issued FASB Statement No. 154, “Accounting Changes and Error Corrections”, (SFAS No. 154), which replaces Accounting Principles Board Opinion No. 20, “Accounting Changes” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. SFAS No. 154 also provides that (1) a change in the method of depreciating or amortizing a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The Company has adopted SFAS No. 154 and determined that it does not expect that it will have an impact on the Company’s Consolidated Financial Statements.

 

In December 2004, the FASB issued revised Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R), effective as of the beginning of the first annual reporting period that begins after June 15, 2005. SFAS No. 123(R) requires all entities to recognize the fair value of share-based payment awards classified in equity, unless they are unable to reasonably estimate the fair value of the award. The Company uses the fair value method for share-based payment awards and therefore the provisions of SFAS No. 123(R) will have no impact on the Consolidated Financial Statements.

 

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

 

In December 2003, the FASB issued Statement No. 132(R) (SFAS 132(R)), a revision of its original Statement No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (SFAS 132). SFAS 132(R) revises employers’ disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by SFAS No. 87, FASB Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” and SFAS No. 106”. SFAS 132(R) retains the disclosure requirements contained in SFAS 132 and requires additional disclosures about the assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The Company adopted this statement in 2003.

 

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46) and in December 2003 issued a revised FIN 46. This interpretation clarified the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” and replaced the current accounting guidance relating to the consolidation of variable interest entities (VIE’s) established on the basis of contractual, ownership or other monetary interests. The Company reviewed its investments and affiliations and determined that it had a variable interest in the Unitil Retiree Trust (URT), a special purpose entity established January 1993. URT was an organization of retirees, incorporated in 1993 to provide social, health and welfare benefits to its members, who are eligible former employees of the Company. URT was under the direction of an independent Board of Trustees whose voting members were comprised of former employees of the Company, elected by and from the membership of URT. In the fourth quarter of 2003, URT was dissolved by a vote of its trustees and the Company assumed the obligations of URT as of October 1, 2003. There are no other entities identified by the Company that qualify as VIE’s under FIN 46. See Note 8 for additional discussion regarding FIN 46 and the Company’s accounting for Postretirement Benefits other than Pensions.

 

In December 2002, the FASB issued Statement No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure.” (SFAS No. 148). SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair value-based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method on reported results. The Company recognizes compensation cost at fair value at the date of grant. The Company has already adopted the provisions of SFAS No. 148 and therefore there is no impact on the Consolidated Financial Statements.

 

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Note 2: Equity

 

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

 

Common Stock

 

Public Offering 2003—On October 29, 2003, the Company raised approximately $16.9 million (after deducting underwriting discounts and commissions and the estimated expenses of the offering) through the sale of 717,600 shares of its common stock at a price of $25.40 per share in a registered public offering. The offering was increased from an original 520,000 shares to reflect a 20% upsizing of the transaction (104,000 shares) and the exercise of a 15% underwriters’ over-allotment (93,600 shares). The Company used the proceeds from this offering to make capital contributions of $6 million to UES and $6 million to FG&E and for other general corporate purposes.

 

Dividend Reinvestment and Stock Purchase Plan—During 2005, the Company sold 38,003 shares of its Common Stock, at an average price of $27.15 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan (DRP) and its 401(k) plans. Net proceeds of $1,031,786 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 2004 and 2003, the Company raised $946,883 and $716,936, respectively, of additional common equity through the issuance of 35,310 and 28,714 shares, respectively, of its Common Stock in connection with its DRP and 401(k) plans.

 

Shares Repurchased, Cancelled and Retired—During 2005, 2004 and 2003, 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. 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 in the Plan. Awards fully vest over a period of four years at a rate of 25% each year. During the vesting period, dividends on restricted shares underlying the Award may be credited to the participant’s account. Awards may be grossed up to offset the participant’s tax obligations in connection with the Award. Prior to the end of the vesting period, the restricted shares are subject to forfeiture if the participant ceases to be employed by the Company other than due to the participant’s death. The maximum number of shares of Restricted Stock available for awards to participants under the Plan is 177,500. The maximum aggregate number of shares of Restricted Stock that may be awarded in any one calendar year to any one participant is 20,000. In the event of any change in capitalization of the Company, the Compensation Committee is authorized to make proportionate adjustments to prevent dilution or enlargement of rights, including, without limitation, an adjustment in the maximum number and kinds of shares available for awards and in the annual award limit. On March 8, 2005, 10,900 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $299,423. On April 29, 2004, 10,700 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $293,715. On May 12, 2003, 10,600 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $259,170. The compensation expense associated with the issuance of shares under the Plan is being accrued on a monthly basis over the vesting period and was $265,900 in 2005, including amounts for tax gross-up.

 

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Unitil Corporation Key Employee Stock Option Plan—The “Unitil Corporation Key Employee Stock Option Plan” was a 10-year plan which began in March 1989. The number of shares underlying options granted under this plan, as well as the terms and conditions of each grant, were determined by the Key Employee Stock Option Plan Committee of the Board of Directors, subject to plan limitations. At December 31, 2005, 29,101 shares underlying options had been approved and were available for future issuance as dividend equivalents earned under the plan. All options granted under this plan vested upon grant. The 10-year period in which options could be granted under this plan expired in March 1999. The expiration date of the remaining outstanding options is November 3, 2007. The plan provides dividend equivalents on options granted, which are recorded at fair value as compensation expense. The total compensation expenses recorded by the Company with respect to this plan were $51,000, $49,000 and $46,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

 

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

 

     2005

   2004

   2003

Beginning Options Outstanding and Exercisable

   25,000    25,000    25,000

Dividend Equivalents Earned—Prior Years

   11,321    9,495    7,645

Dividend Equivalents Earned—Current Year

   1,881    1,826    1,850

Options Exercised

        
    
  
  

Ending Options Outstanding and Exercisable

   38,202    36,321    34,495
    
  
  

Weighted Average Exercise Price per Share

   $11.89    $12.51    $13.17

Range of Option Exercise Price per Share

   $12.11-$18.28    $12.11-$18.28    $12.11-$18.28

Weighted Average Remaining Contractual Life

   1.9 years    2.9 years    3.9 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. There was no compensation expense associated with this plan in 2005 and 2004. The total compensation expense recorded by the Company with respect to this plan was ($178,000) for the year ended December 31, 2003, reflecting a reversal of prior compensation expense due to stock option forfeitures. This plan was terminated on January 16, 2003. 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.

 

     2005

   2004

   2003

     Number
of Shares


   Average
Exercise
Price


   Number
of Shares


   Average
Exercise
Price


   Number
of Shares


    Average
Exercise
Price


Beginning Options Outstanding

   107,000    $ 27.13    107,000    $ 27.13    172,500     $ 26.99

Options Granted

                        

Options Forfeited

                   (65,500 )   $ 26.77
    
  

  
  

  

 

Ending Options Outstanding

   107,000    $ 27.13    107,000    $ 27.13    107,000     $ 27.13
    
  

  
  

  

 

Options Vested and Exercisable-end of year

   107,000    $ 27.13    107,000    $ 27.13    107,000     $ 27.13

 

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

 

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The following summarizes certain data for options outstanding at December 31, 2005:

 

Range of
Exercise Prices


  

Options Vested,

Exercisable and
Outstanding


  

Weighted

Average

Exercise Price


  

Remaining

Contractual
Life


$20.00-$24.99

   34,500    $ 23.38    3.2 years

$25.00-$29.99

   37,500    $ 25.88    5.1 years

$30.00-$34.99

   35,000    $ 32.17    4.1 years
    
           
     107,000            
    
           

 

There were no options granted during 2005, 2004 or 2003.

 

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

 

Its two retail distribution subsidiaries, UES and FG&E, do have restrictions. Under the terms of the First Mortgage Bond Indentures, UES had $13,300,000 available for the payment of cash dividends on its Common Stock at December 31, 2005. Under the terms of long-term debt purchase agreements, FG&E had $7,842,000 of retained earnings available for the payment of cash dividends on its Common Stock at December 31, 2005. Common dividends declared by UES and FG&E are paid exclusively to Unitil Corporation.

 

Preferred Stock

 

Unitil’s two retail distribution companies, UES and FG&E, have preferred stock outstanding. At December 31, 2005, UES has a 6.00% Series Non-Redeemable, Non-Cumulative Preferred Stock series outstanding and FG&E has two series of Redeemable, Cumulative Preferred Stock outstanding, the 5.125% Series and the 8.00% Series.

 

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

 

The aggregate purchases of Redeemable, Cumulative Preferred Stock during 2005, 2004 and 2003 related to the annual redemption offer were $11,400, $26,900 and $53,400, respectively. The aggregate amount of sinking fund requirements of the Redeemable, Cumulative Preferred Stock for each of the five years following 2005 is $117,000 per year.

 

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

 

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

 

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

 

Long-Term Debt and Interest Expense

 

Substantially all the property of Unitil’s New Hampshire utility operating subsidiary, UES, is subject to liens of indenture under which First Mortgage bonds have been issued. UES utilizes a First Mortgage Bond (FMB) structure of long-term debt. In order to issue new FMB securities, the customary covenants of the existing

 

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UES Indenture Agreement must be met, including that UES have sufficient available net bondable plant to issue the securities and projected earnings available for interest charges equal to at least two times the annual interest requirement. The UES agreements further require that if UES defaults on any UES FMB securities, it would constitute a default for all UES FMB securities. The UES default provisions are not triggered by the actions or defaults of other companies in the Unitil System.

 

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

 

Both the UES and FG&E instruments and agreements contain covenants restricting the ability of each company to incur liens and to enter into sale and leaseback transactions, and restricting the ability of each company to consolidate with, to merge with or into, or to sell or otherwise dispose of all or substantially all of its assets.

 

Total aggregate amount of sinking fund payments relating to bond issues and normal scheduled long-term debt repayments amounted to $286,368, $3,264,421 and $3,244,156 in 2005, 2004 and 2003, respectively.

 

The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 2005 is: 2006 – $308,082, 2007 – $335,877, 2008 – $363,755, 2009 – $393,946 and 2010 – $426,643.

 

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

 

On October 28, 2003, FG&E completed a $10 million private placement of long-term unsecured notes with a major insurance company. The notes have a term of 22 years and a coupon rate of 6.79%. The net proceeds were used to replace short-term indebtedness.

 

The fair value of the Company’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt at December 31, 2005 is estimated to be in a range of up to approximately $140 million, before considering any costs, including prepayment costs, to market the Company’s debt. Currently, management believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

 

The agreements under which the long-term debt of Unitil’s two principal subsidiaries, UES and FG&E, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations.

 

Interest Expense, net—Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and interest on regulatory liabilities. Interest income is mainly derived from carrying charges on restructuring related stranded costs and other deferred costs recorded as regulatory assets by the Company’s retail distribution utilities as approved by regulators in New

 

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Hampshire and Massachusetts. Over the long run, as deferred costs are recovered through rates, the interest costs associated with these deferrals are expected to decrease together with a decrease in interest income. A summary of interest expense and interest income is provided in the following table:

 

Interest Expense, net (000’s)


   2005

     2004

     2003

 

Interest Expense

                          

Long-term Debt

   $ 8,423      $ 8,492      $ 8,170  

Short-term Debt

     1,046        629        1,071  
    


  


  


Subtotal Interest Expense

     9,469        9,121        9,241  
    


  


  


Interest Income

                          

Regulatory Assets

     (2,525 )      (2,310 )      (1,657 )

AFUDC and Other

     (103 )      (37 )      (53 )
    


  


  


Subtotal Interest Income

     (2,628 )      (2,347 )      (1,710 )
    


  


  


Total Interest Expense, net

   $ 6,841      $ 6,774      $ 7,531  
    


  


  


 

Credit Arrangements

 

At December 31, 2005, Unitil had unsecured committed bank lines for short-term debt in the aggregate amount of $44.0 million with three banks for which it pays commitment fees. The weighted average interest rates on all short-term borrowings were 3.8%, 1.9% and 1.8% during 2005, 2004 and 2003, respectively. The Company had short-term debt outstanding through bank borrowings of approximately $18.7 million and $25.7 million at December 31, 2005 and December 31, 2004, respectively.

 

Leases

 

Unitil’s subsidiaries conduct a portion of their operations in leased facilities and also lease some of their vehicles, machinery and office equipment. FG&E had a 22-year facility lease in which the primary term was scheduled to end on January 31, 2003. On February 1, 2003, a 10-year extended term commenced extending the lease term through January 31, 2013. Furthermore, the amended lease agreement allows for three additional five-year renewal periods at the option of FG&E. This lease, as well as other leases for equipment used by Unitil’s subsidiaries, is recorded as an operating lease. In prior years, this lease was classified as a capital lease. The change in classification was the result of the renegotiation of the lease terms described above.

 

The following is a schedule of the leased property under capital leases by major classes:

 

     Asset Balances at
December 31,


Classes of Utility Plant (000’s)


   2005

   2004

Common Plant

   $ 985    $ 2,769

Less: Accumulated Depreciation

     400      2,197
    

  

Net Plant

   $ 585    $ 572
    

  

 

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The following is a schedule of future minimum lease payments and present value of net minimum lease payments under capital leases, as of December 31, 2005:

 

Year Ending December 31 (000’s)


    

2006

   $ 291

2007

     203

2008

     139

2009

     9

2010

     2

2011-2015

     1
    

Total Minimum Lease Payments

   $ 645

Less: Amount Representing Interest

     60
    

Present Value of Net Minimum Lease Payments

   $ 585
    

 

Total rental expense charged to operations for the years ended December 31, 2005, 2004 and 2003 amounted to $301,000, $249,000 and $294,000 respectively.

 

The following is a schedule of future operating lease payment obligations as of December 31, 2005:

 

Year Ending December 31 (000’s)


    

2006

   $ 390

2007

     390

2008

     390

2009

     387

2010

     364

2011-2015

     818
    

Total Future Operating Lease Payments

   $ 2,739
    

 

Guarantees

 

The Company also provides limited guarantees on certain energy contracts entered into by the retail distribution utilities. The Company’s policy is to limit these guarantees to two years or less. As of December 31, 2005 there are $6.0 million of guarantees outstanding and these guarantees extend through October 24, 2007. These guarantees are not required to be recorded under the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

 

Note 4: Energy Supply

 

Electricity Supply:

 

Unitil’s customers in both New Hampshire and Massachusetts now have the opportunity to purchase their electric supply from competitive retail suppliers, though most customers continue to purchase such supplies through the retail distribution utilities. The transition to retail choice required the divestiture of Unitil’s existing power supply arrangements and the procurement of replacement supplies which provided the flexibility for migration of customers to and from utility service. FG&E, UES, and Unitil Power each are members of the New England Power Pool (NEPOOL) and participate in the Independent System Operator—New England (ISO-NE) markets for the purpose of facilitating these wholesale electric power supply transactions, which are necessary to serve Unitil’s retail customers.

 

Wyman Unit No. IV—FG&E continues to have a 0.1822% non-operating ownership interest in the Wyman Unit No. IV (Wyman IV), an oil-fired electric generating station located in Yarmouth, Maine. The lead operating

 

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owner of Wyman IV is FPL Energy Wyman IV, LLC. In accordance with the electric industry restructuring in Massachusetts, and pursuant to the generation assets and power supply divestiture process discussed below, FG&E effectively divested its economic interest in Wyman IV when it entered into an agreement with Select Energy, Inc. to, among other things, sell its entire entitlement in the output from Wyman IV over the expected remaining operating life of the unit. Kilowatt-hour generation and operating expenses associated with Wyman IV are divided on the same basis as ownership. FG&E’s proportionate ownership costs in Wyman IV are reflected in the Consolidated Statements of Earnings. Revenues from the entitlement sale of Wyman IV reflect a matching and collection of these costs. Accordingly, the cost associated with FG&E’s ownership in Wyman IV does not have a material impact on earnings.

 

Information with respect to FG&E’s ownership in Wyman Unit No. IV, at December 31, 2005, is shown below:

 

Joint Ownership Unit


   State

   Proportionate
Ownership


    Share of
Total MW


   Company’s
Net Book
Value (000’s)


Wyman Unit No. IV

   ME    0.1822 %   1.13    $ 40

 

Power Supply Divestiture

 

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

 

Unitil Power divested its long-term power supply contracts to a subsidiary of Mirant in 2003. The purchase of power to supply UES’ Transition Service and Default Service requirements by UES from Mirant was linked to the Unitil Power divestiture. The NHPUC Order completed the state approval process for Unitil’s restructuring plan under which UES implemented customer choice for its customers on May 1, 2003. The divested power supply contracts continue through October 2010.

 

In March 1999, FG&E completed the sale of its 4.5% interest in the New Haven Harbor Station generating unit. FG&E divested its remaining owned generation assets and long-term power supply contracts to Select Energy, Inc., a subsidiary of Northeast Utilities. Under the Select Energy contract, which was approved by the MDTE in January 2000, and went into effect February 1, 2000, FG&E began selling the entire output from its remaining long-term power supply contracts and the output of its two joint ownership units, Millstone Unit 3 and Wyman IV, to Select Energy. Upon the sale of FG&E’s share of Millstone Unit 3 in 2001, this portion of the contract sale ceased. Effective with the termination of the Purchased Power Contract between FG&E and Linweave, Inc. on December 1, 2004, this portion of the contract sale also ceased. On December 30, 2005 Select Energy assigned the FG&E contracts portfolio to Constellation Energy Commodities Group (Constellation) effective January 1, 2006. Recovery of all costs associated with the divestiture of the FG&E power supply portfolio has been approved by the MDTE.

 

Regulated Energy Supply

 

In order to provide regulated electric supply as the provider of last resort to their respective retail customers, the retail distribution companies enter into wholesale electric power supply contracts with various wholesale suppliers. In particular, FG&E has entered into power supply contracts to meet its power supply obligations associated with the provision of Standard Offer Service (Standard Offer) and Default Service. Standard Offer

 

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was offered only to customers who had both taken service from FG&E since the inception of retail choice in 1998 and had not switched to a competitive retail supplier. Consistent with MDTE regulations, Standard Offer ended January 31, 2005. Effective February 1, 2005 FG&E customers are eligible for Default Service. FG&E has power supply contracts with various wholesale suppliers for the provision of Default Service. MDTE policy dictates the pricing structure and duration of each of these contracts. Currently, all Default Service power supply contracts for large general accounts are three months in duration. Default Service power supply contracts for residential and small and medium general service customers are acquired every 6 months, with each 12 month contract providing 50% of the class requirements.

 

The MDTE is investigating alternatives to the current procurement policy for all accounts, other than the large general accounts. This process could potentially lead to the procurement of FG&E Default Service power supply for longer duration in order to provide more price stability for smaller customers throughout Massachusetts for whom competitive retail options are relatively scarce.

 

UES has entered into a power supply contract to meet its power supply obligations associated with the provision of Transition Service and Default Service. Transition Service is available to any UES customer who has not chosen a competitive retail supplier. UES’ Default Service is available to any customer who has chosen a competitive retail energy supplier and returns to retail energy supply from UES. UES has entered into a power supply contract for the provision of Transition Service and Default Service with Mirant. This power supply contract provides fixed unit prices for both Transition Service and Default Service for UES’ largest general service accounts through April 2005 and for all other accounts through April 2006.

 

On July 14, 2003 Mirant filed for Chapter 11 Bankruptcy protection. Mirant is currently performing all of its contractual obligations to both Unitil Power and UES and has satisfied all of its pre-petition claims made by Unitil. On January 3, 2006 Mirant emerged from Chapter 11 Bankruptcy protection.

 

In January, 2005 the NHPUC approved two six-month supply contracts for Transition Service and Default Service for UES’ large general service customers for the period May, 2005 through April, 2006. In September, 2005 the NHPUC approved a Settlement among UES, NHPUC Staff and the Office of Consumer Advocate which provides for UES to procure Default Service for its largest general service accounts through successive competitive solicitations of three-months duration and to procure Default Service for all other customers through a series of two one-year contracts and two three-year contracts with each contract covering 25% of the total requirements of the group. The first two contracts were of 6-months and 18-months duration in order to stagger the start dates of future 1-year and 3-year procurements. On November 2, 2005, the NHPUC approved those two initial Default Service contracts for service starting May 1, 2006.

 

Regional Transmission and Power Markets

 

FG&E, UES and Unitil Power are members of the NEPOOL, formed in 1971 to assure reliable operation of the bulk power system in the most economic manner for the region. NEPOOL is governed by the NEPOOL Agreement that is filed with and subject to the jurisdiction of the FERC. Under the NEPOOL Agreement and the OATT, to which virtually all New England electric utilities are parties, substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. The NEPOOL Agreement and the OATT impose generating capacity and reserve obligations, and provide for the use of major transmission facilities and support payments associated therewith. The most notable benefits of NEPOOL are coordinated power system operation in a reliable manner and a supportive business environment for the development of a competitive electric marketplace. The regional bulk power system is operated by an independent corporate entity, ISO-NE, in order to avoid any opportunity for conflicting financial interests between the system operator and the market-driven participants.

 

As of February 1, 2005, a RTO was established in New England. ISO-NE became the entity responsible for operating the RTO. The market rules and requirements to participate in the markets previously covered under the NEPOOL Agreement were transferred to the new RTO structure under control of ISO-NE. FERC approved the

 

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formation of the RTO in orders issued March 24, 2004 and November 3, 2004 to begin operation of the RTO structure effective February 1, 2005. As a result of the formation of the RTO, companies seeking transmission service throughout New England will be able to obtain that service under common terms, with much of their focus on dealing with ISO-NE, in cooperation with the local transmission providers.

 

On March 1, 2004, ISO-NE filed a proposal to implement LICAP in New England to allow for the imposition of incentive pricing for transmission constrained areas. UES and FG&E have intervened in the proceeding. Both UES and FG&E are located in a non-constrained area of the power pool. On October 21, 2005 the FERC issued an order directing that Settlement discussions take place and indicating that implementation of LICAP, if it proceeds, will not be earlier than October 1, 2006. This case is still before the FERC.

 

The formation of an RTO, LICAP and other wholesale market changes are not expected to have a material impact on Unitil’s operations because of the cost recovery mechanisms for wholesale energy and transmission costs approved by the MDTE and NHPUC.

 

Gas Supply:

 

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

 

FG&E purchases natural gas from domestic and Canadian suppliers under contracts of one year or less, as well as from producers and marketers on the spot market and arranges for the transportation to its distribution facilities under firm long-term contracts with the Tennessee interstate pipeline. FG&E has a four-year contract for LNG supply which ends in 2008 which was approved by the MDTE. The following tables summarize actual gas purchases by source of supply and the cost of gas sold for the years 2003 through 2005.

 

Sources of Gas Supply

(Expressed as percent of total MMBtu of gas purchased)

 

     2005

    2004

    2003

 

Natural Gas:

                  

Domestic firm

   84.8 %   85.0 %   94.0 %

Canadian firm

   3.4 %   5.4 %   1.3 %

Domestic spot market

   9.3 %   5.9 %   1.3 %
    

 

 

Total natural gas

   97.5 %   96.3 %   96.6 %

Supplemental gas

   2.5 %   3.7 %   3.4 %
    

 

 

Total gas purchases

   100.0 %   100.0 %   100.0 %
    

 

 

 

Cost of Gas Sold

 

     2005

    2004

    2003

 

Cost of gas purchased and sold per MMBtu

   $ 10.83     $ 8.42     $ 7.14  

Percent Increase (Decrease) from prior year

     28.7 %     17.9 %     43.9 %

 

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

 

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Note 5: Commitments and Contingencies

 

Regulatory Matters

 

Overview—Unitil and its subsidiaries are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 in regards to certain bookkeeping, accounting and reporting requirements. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the SEC with respect to various matters, including: the issuance of securities, capital structure, and certain acquisitions and dispositions of assets. As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed. Unitil’s utility operations related to wholesale and interstate business activities are also regulated by FERC. The retail distribution utilities, UES and FG&E, are subject to regulation by the NHPUC and the MDTE, respectively, in regards to their rates, issuance of securities and other accounting and operational matters. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

 

Unitil’s retail distribution utilities have the franchise to deliver electricity and/or natural gas to all customers in our franchise areas, at rates established under traditional cost of service regulation. Under this regulatory structure, UES and FG&E recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in Massachusetts and New Hampshire, Unitil’s customers have the opportunity to purchase their electric or natural gas supplies from third-party vendors. Most customers, however, continue to purchase such supplies through UES and FG&E as the provider of last resort. UES and FG&E purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup on a pass-through basis, through reconciling rate mechanisms that are periodically adjusted.

 

In connection with the implementation of retail choice, Unitil Power and FG&E divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDTE, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next five to seven years, is $154 million as of December 31, 2005 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

 

FG&E—Electric Division—FG&E’s primary business is providing electric distribution service under rates approved by the MDTE in 2002. FG&E had been required to purchase and provide power, as the provider of last resort, through either Standard Offer or Default Service, for retail customers who chose not to buy, or were unable to purchase, energy from a competitive supplier. The seven year term of Standard Offer, which included a requirement to provide service at rate levels which reflected state-mandated rate reductions, expired on February 28, 2005. FG&E continues to be required to be the supplier of last resort for its customers, however, and on March 1, 2005, customers previously on Standard Offer were automatically placed on Default Service. Prices for Default Service are set periodically based on market solicitations as approved by the MDTE. As of December 31, 2005, competitive suppliers were serving approximately 35 percent of FG&E’s electric load.

 

As a result of the restructuring and the divestiture of FG&E’s owned generation assets and buyout of FG&E’s power supply obligations, Regulatory Assets on the Company’s balance sheets include the following three categories: Power Supply Buyout Obligations associated with the divestiture of its long-term purchase power obligations; Recoverable Deferred Restructuring Charges resulting from the restructuring legislation’s seven year rate cap; and Recoverable Generation-related Assets associated with the divestiture of its owned generation plant. FG&E earns carrying charges on the majority of the unrecovered balances of the Recoverable Deferred Restructuring Charges. The value of FG&E’s Recoverable Deferred Restructuring Charges and Recoverable Generation-related Assets was approximately $38.0 million at December 31, 2005, and $35.0

 

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million at December 31, 2004, and is expected to be recovered in FG&E’s rates over the next five to seven years. In addition, as of December 31, 2005, FG&E had recorded on its balance sheets $57.9 million as Power Supply Buyout Obligations and corresponding Regulatory Assets associated with the divestiture of its long-term purchase power contracts, which are included in Unitil’s consolidated financial statements, and on which carrying charges are not earned as the timing of cash disbursements and cash receipts associated with these long-term obligations is matched through rates. See Note 1.

 

In May, 2005, the MDTE approved a Settlement Agreement among FG&E, the Massachusetts Office of the Attorney General (Attorney General), and representatives of industrial and low-income customers, in regards to future recovery of the deferred amounts described above. The Settlement Agreement provides for a rate path to allow recovery of FG&E’s deferred stranded costs.

 

In March 2003, the MDTE opened an investigation into whether FG&E is in compliance with relevant statutes and regulations pertaining to transactions with affiliated companies and the MDTE’s requirements for the pricing and procurement of Default Service. FG&E has asserted that the transaction in question with Enermetrix was not an affiliate transaction and resulted in net benefits to FG&E’s customers. Hearing and briefing of the case were completed in 2003 and an MDTE decision is pending. Management believes the outcome of this matter will not have a material adverse effect on the financial position of the Company.

 

On December 1, 2005, FG&E filed its annual reconciliation and rate filing with the MDTE under its restructuring plan, seeking revised rates for transmission charges, transition charges, and default service adjustment. The revised rates were approved to go into effect January 1, 2006, subject to further investigation. FG&E made similar filings in 2002, 2003, and 2004, which were also approved subject to further investigation. On May 19, 2005, the MDTE, after investigation, issued an order approving FG&E’s 2002 filing. Final review of FG&E’s 2003 and 2004 filings, and FG&E’s 2005 filing which is subject to investigation, are pending. Management believes that these filings will be approved without material changes or adjustments.

 

FG&E—Gas Division—FG&E provides natural gas delivery service to its customers on a firm or interruptible basis under unbundled distribution rates approved by the MDTE in 2002. FG&E’s customers may purchase gas supplies from third-party vendors or purchase their gas from FG&E as the provider of last resort. FG&E collects its gas supply costs through a seasonal CGAC and recovers other related costs through a reconciling Local Distribution Adjustment Clause. FG&E filed, and received MDTE approval of rate changes for reconciling clauses effective January 1, 2005, May 1, 2005, October 1, 2005 and November 1, 2005.

 

In 2001, the MDTE required the mandatory assignment of LDC’s pipeline capacity to competitive marketers selling gas to FG&E’s customers, thus protecting FG&E from exposure to costs for stranded capacity. In January 2004, the MDTE opened an investigation on whether the mandatory assignment of pipeline capacity should be continued. On June 6, 2005, the MDTE issued its order ruling that mandatory capacity assignment shall continue.

 

FG&E—Other—On October 27, 2004 the MDTE approved FG&E’s request for a reconciliation rate adjustment mechanism to provide for the recovery of costs associated with the Company’s employee pension benefits and PBOP expenses. FG&E is allowed to record a regulatory asset in lieu of taking a charge to expense for the difference between the level of pension and PBOP expenses that are included in its base rates and the amounts that are required to be recorded in accordance with SFAS No. 87 and SFAS No. 106, since the effective date of its last base rate change. This mechanism provides for an annual filing and rate adjustment with the MDTE. As of December 31, 2005, FG&E has recorded a regulatory asset of $2.5 million which is included as part of Regulatory Assets in the Company’s Consolidated Balance Sheets. FG&E filed, and received MDTE approval of, revised pension/PBOP adjustment factors (PAFs) effective November 1, 2005 for its gas division and January 1, 2006 for its electric division.

 

On November 30, 2005, the MDTE announced a change in its method for recovery of gas cost-related bad debt, and determined that it would allow for full recovery of these costs on a reconciling basis. On December 15,

 

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2005, FG&E filed a revised CGAC tariff reflecting this change which was approved effective January 1, 2006. FG&E also requested approval to recover its under-recovered gas cost-related bad debt for 2005 of approximately $164 thousand. A decision on this request is expected in 2006.

 

UES—UES provides electric distribution service to its customers pursuant to rates established under a 2002 restructuring settlement. On May 1, 2004, these distribution rates were increased by $1.0 million to provide for the recovery of PBOP costs. As the provider of last resort, UES also provides its customers with electric power through either Transition or Default Service at rates which reflect UES’ costs for wholesale supply with no profit or markup. UES recovers its costs for this service on a pass-through basis through reconciling rate mechanisms.

 

In the 2002 restructuring settlement, the NHPUC approved the divestiture of the long-term power supply portfolio by Unitil Power and tariffs for UES for stranded cost recovery and Transition and Default Service, including certain charges that are subject to annual or periodic reconciliation or future review. As of December 31, 2005, UES had recorded on its balance sheets $57.0 million as Power Supply Contract Obligations and corresponding Regulatory Assets associated with these long-term purchase power stranded costs, which are included in Unitil Corporation’s consolidated financial statements. These Power Supply Contract Obligations are expected to be recovered principally over a period of approximately five years. The Company does not earn carrying charges on these regulatory assets as the timing of cash receipts and cash disbursements associated with these long-term obligations is matched through rates.

 

The NHPUC approved UES’ second annual reconciliation and rate filing under its restructuring plan effective May 1, 2005, including revised rates for the Transition Service Charge, Default Service Charge, Stranded Cost Charge, and External Delivery Charge.

 

On December 11, 2004, UES filed with the NHPUC a Petition for an accounting order to defer certain pension costs above those included in its base rates, until UES filed its next base rate case, which, pursuant to the last base rate case settlement, was required to be filed no later than October 2007 (also see Note 8 below). On April 7, 2005, the NHPUC issued an order denying UES’ Petition for an accounting order. In its analysis denying UES’ request, the NHPUC indicated that pension expense is an ordinary category of expense included in the revenue requirement for a utility under traditional cost of service ratemaking principles and that a full examination of UES’ income and expenses would be undertaken when UES files a rate case. As of December 31, 2005, UES has recorded deferred pension costs of $1.0 million.

 

On November 4, 2005, UES filed a request for a base rate increase of $4.65 million. The filing includes a request to recover pension and PBOP costs through an annual reconciling rate mechanism, and a step adjustment for certain future rate base additions. The filing also requested that temporary rates be established at current rate levels effective December 4, 2005. On February 3, 2006, the NHPUC issued an order approving this request. Any rate change ultimately awarded by the NHPUC will be retroactive to January 1, 2006. The overall rate filing is currently under review, with an NHPUC order anticipated before November 2006. It is anticipated that the final determination of the amount and method of recovering UES’ pension and PBOP costs will be decided in the base rate case. The Company cannot determine the ultimate outcome of this proceeding. The Company expects a decision in 2006.

 

On January 7, 2005, the NHPUC approved UES’ petition for a one year extension of Transition Service and Default Service for rate class G1, and the associated solicitation process whereby UES intends to secure energy supplies for such extended service. As a result, UES’ Transition Service supply obligation for all rate classes will end at the same time on April 30, 2006. The Company recovers the costs of Transition Service and Default Service in its rates at cost on a pass-through basis and therefore changes in these expenses do not affect earnings.

 

On April 1, 2005, UES filed a petition with the NHPUC for approval of a plan for procurement of Default Service power supply for service, commencing on May 1, 2006 for all rate classes. A settlement supporting the plan between UES, the Office of Consumer Advocate and the NHPUC Staff, was approved by the NHPUC on

 

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September 9, 2005. Under the approved plan, UES will procure Default Service power for its larger commercial and industrial customers on a quarterly basis, and for its smaller commercial and residential customers through a portfolio of longer term contracts on a semi-annual basis.

 

Under the 2002 restructuring plan approved by the NHPUC, Unitil Power sold the entitlements to its long-term power supply portfolio to Mirant and UES purchased supplies for Transition and Default Service from Mirant for up to three years. Following the Chapter 11 bankruptcy filing by Mirant in July, 2003, Mirant agreed to continue to perform all obligations under its contracts with Unitil Power and UES pursuant to a settlement approved by the bankruptcy court in December 2003. As a result of the Mirant bankruptcy, UES and Unitil Power also pursued claims with Mirant with regards to a potential future default. In January 2005, UES, Unitil Power and Mirant filed a settlement with the bankruptcy court under which Mirant has agreed to put in place a replacement guarantee, or comparable security, to guarantee performance of its responsibilities under the agreement beginning May 2006. That settlement was approved by the bankruptcy court on January 18, 2005. On January 3, 2006, Mirant emerged from Chapter 11.

 

FERC—Wholesale Power Market Restructuring—FG&E, UES and Unitil Power are members of the NEPOOL, formed in 1971 to assure reliable operation of the bulk power system in the most economic manner for the region. NEPOOL is governed by the NEPOOL Agreement that is filed with and subject to the jurisdiction of the FERC. Under the NEPOOL Agreement and the OATT, to which virtually all New England electric utilities are parties, substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. The NEPOOL Agreement and the OATT impose generating capacity and reserve obligations, and provide for the use of major transmission facilities and support payments associated therewith. The most notable benefits of NEPOOL are coordinated power system operation in a reliable manner and a supportive business environment for the development of a competitive electric marketplace. The regional bulk power system is operated by an independent corporate entity, the ISO-NE, in order to avoid any opportunity for conflicting financial interests between the system operator and the market-driven participants.

 

As of February 1, 2005, a RTO was established in New England. ISO-NE became the entity responsible for operating the RTO. The market rules and requirements to participate in the markets previously covered under the NEPOOL Agreement were transferred to the new RTO structure under control of ISO-NE. FERC approved the formation of the RTO in orders issued March 24, 2004 and November 3, 2004 to begin operation of the RTO structure effective February 1, 2005. As a result of the formation of the RTO, companies seeking transmission service throughout New England will be able to obtain that service under common terms, with much of their focus on dealing with ISO-NE, in cooperation with the local transmission providers. Several parties have appealed various issues associated with the FERC’s approval of the RTO to Federal District Court of Appeals. Those proceedings are ongoing.

 

On March 1, 2004, ISO-NE filed a proposal to implement LICAP in New England to allow for the imposition of incentive pricing for transmission constrained areas. Both UES and FG&E are located in a non-constrained area of the power pool which should have modest LICAP prices for several years under the filed proposal. UES and FG&E have intervened in the proceeding. On October 21, 2005 the FERC issued an order directing that Settlement discussions take place and indicating that implementation of LICAP, if it proceeds, will not be earlier than October 1, 2006. This case continues to be contested at the FERC.

 

The formation of an RTO, LICAP and other wholesale market changes, including changes to transmission rates, is not expected to have a material impact on Unitil’s operations because of the cost recovery mechanisms for wholesale energy costs approved by the MDTE and NHPUC. It is possible, however, that retail rates will be significantly increased over the next several years if LICAP is implemented consistent with the Initial Decision.

 

FERC—Other—In August 2003, NU filed with FERC to revise its comprehensive network service transmission rates to establish and implement a formula based rate, replacing a fixed rate tariff. A settlement among certain parties was approved by the FERC in September 2004, which reduced the allowed return on equity in the formula rates and resulted in refunds to the tariff customers, including UES.

 

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On March 30, 2005, NU filed an executed DSA settlement between UES and NU with the FERC for effect on June 1, 2005. The DSA provides for cost recovery by NU for facilities used by UES that had been reclassified from transmission plant to distribution plant. On April 20, 2005 UES intervened in support of the DSA. Costs to UES under the DSA are estimated to be approximately $2 million annually. These costs are expected to be recovered through reconciling cost recovery mechanisms. On May 19, 2005 the FERC accepted NU’s DSA filing and the rates went into effect on June 1, 2005.

 

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 is in general compliance with all applicable environmental and safety laws and regulations, and management believes that as of December 31, 2005, there are no material losses reasonably possible in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

 

Sawyer Passway MGP Site—The Company continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows the Company to work towards temporary remediation of the site. Work performed in 2002 was associated with the five-year review of the Temporary Solution submittal (Class C Response Action Outcome) under the Massachusetts Contingency Plan (MCP) that was filed for the site in 1997. Completion of this work has confirmed the Temporary Solution status of the site for an additional five years, to January 2008. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed.

 

During 2005, FG&E continued developing a long range plan for a Permanent Solution for the site, including alternatives for re-use of the site.

 

On May 13, 2004 FG&E discovered an unauthorized excavation by another property owner on the site at Sawyer Passway in which tainted soils related to MGP by-products were exposed and relocated onto property owned by FG&E. FG&E promptly reported this discovery to the DEP and subsequently received a Notice of Responsibility on May 20, 2004. FG&E has properly disposed of the relocated materials and taken other steps in accordance with DEP directives to remedy the situation. The Completion Report for this release was submitted May 9, 2005.

 

Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to an MDTE approved settlement agreement between the Massachusetts Attorney General and the natural gas utilities of the Commonwealth of Massachusetts (Agreement). The Agreement allows FG&E to amortize and recover from gas customers over succeeding seven-year periods the environmental response costs incurred each year. Environmental response costs are defined to include liabilities related to manufactured gas sites, waste disposal sites or other sites onto which hazardous material may have migrated as a result of the operation or decommissioning of Massachusetts gas manufacturing facilities from 1822 through 1978. In addition, any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers. The total annual charge for such costs assessed to gas customers cannot exceed five percent of FG&E’s total revenue for firm gas sales during the preceding year. Costs in excess of five percent will be deferred for recovery in subsequent years.

 

Former Electric Generating Station—In 2003, FG&E completed environmental remediation action to abate and remove asbestos-containing and other hazardous materials at a former electric generating station

 

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located at Sawyer Passway in Fitchburg, Massachusetts, which FG&E sold in 1983 to a general partnership, Rockware. FG&E received significant coverage from its insurance carrier for this remediation project and the resolution of this matter did not have a material adverse effect on the Company’s financial position.

 

Note 6: Bad Debts

 

The following table shows the balances and activity in the Company’s Allowance for Doubtful Accounts for 2003—2005.

 

ALLOWANCE FOR DOUBTFUL ACCOUNTS

 

     Balance at
Beginning
of Period


   Additions

   Accounts
Written
Off


   Balance at
End of
Period


        (A)
Provision


   Recoveries

     

Year Ended December 31, 2005

                                  

Electric

   $ 392,824    $ 714,917    $ 116,290    $ 881,240    $ 342,791

Gas

     89,602      721,171      116,366      817,108      110,031

Other

     18,297      9,602           10,973      16,926