(Exact name of registrant as specified in its charter)

Item 1.  Business

Item 2.  Properties

Item 3.  Legal Proceedings

Item 4   Submission of Matters to a Vote of Security Holders

Item 5   Market for Registrant's Common Equity and Related Stockholder Matters

Unitil's annual Common Stock dividend in 2001 was $1.38 per share. This annual dividend resulted in a payout ratio of 91%, for the year, before the Investment Write-down and Extraordinary Item. Excluding the loss from Non-regulated Operations, the payout ratio was 80% based on earnings from Utility Operations, before the Investment Write-down and Extraordinary Item. At its January 2002 meeting, the Unitil Board of Directors declared a regular quarterly dividend on the Company's Common Stock of $0.345 per share. This quarterly dividend reflects the current annual dividend rate of $1.38 per share.

As shown in the following table, Utility Operations contributed $1.72 per share to 2001 earnings from Operations, compared to $1.82 per share in 2000. The reduction in earnings from Utility Operations primarily reflects lower sales to industrial customers due to a slowing economy, warmer winter weather and lower electric rates for Unitil's Massachusetts based operating utility. The Company's non-regulated energy brokerage business, Usource, recorded a loss of $0.21 per share in 2001, an improvement of $0.14 over the loss of $0.35 recorded in 2000. The decreased loss from Usource operations is related to increased brokerage fees and the Company's refocused operating plan.

The graph below shows Quarterly Earnings per Share from Operations for 2000 and 2001.

Key external factors impacting our business operating environment in 2001 included volatile gas and electric energy markets, a recessionary economy, utility industry restructuring-related issues, regulatory decisions and new initiatives. As we complete the transition to a restructured utility environment in our Massachusetts and New Hampshire service territories, we are setting a course to achieve continued improvement in operating results for our Utility Operations business unit. Our non-regulated business unit, Usource, also has an opportunity for improved results as more regulatory jurisdictions throughout the nation are restructured and opened to customer choice.

Utility Operations - Despite a slowing economy in 2001, our electric energy sales to residential and commercial customers were up in all three of Unitil's distribution utility service areas, compared to the prior year. Our New Hampshire distribution operating companies experienced record-high system peak electric loads during a sustained summer heat wave. However, the national economic slowdown has directly impacted our industrial sales, as manufacturing utilization and output have been curtailed. For 2001, total electric kWh sales increased slightly by 0.6% compared to 2000. Residential electric sales increased 3.4%, while commercial electric sales increased 3.1%. Electric sales to industrial customers decreased 3.7% in 2001 compared to 2000. Gas sales were up 4.3% through the first three quarters of the year, then dipped below prior year levels due to unseasonably mild temperatures in the fourth quarter of 2001. On a full-year basis, gas sales were down 3.9% compared to prior year.

Total Operating Revenues in 2001 increased to $207 million, or 13%, over year 2000 Operating Revenues. This increase primarily reflects a period of rising and highly volatile wholesale energy prices for electric and natural gas energy commodities, during 2000 and early 2001, which resulted in increased gas and electric supply related revenues and costs. Energy related supply costs are reconciled and recovered in revenues through regulated cost recovery adjustment mechanisms with no markup or profit margin. By mid-2001, energy costs began to ease allowing the Company to flow-through those savings to customers. Unitil has implemented several gas and electric energy related rate decreases in the latter half of 2001, principally due to the decline in these wholesale energy costs.

Operating Expenses (excluding energy supply related costs) increased 2.1% in 2001 compared to 2000, primarily reflecting higher system maintenance expenses, an increase in uncollectable account write-offs and increases in Depreciation and Amortization on new plant additions and improvements, offset by lower franchise tax expense.

Interest Expense, net, was relatively unchanged in 2001 compared to 2000. A higher level of interest expense related to debt outstanding offset an increase in accrued interest income associated with deferred rate recovery mechanisms for restructuring-related Regulatory Assets.

Unitil's utility operating companies continued to develop and implement comprehensive gas and electric utility industry restructuring plans and strategies in 2001. The Company's Massachusetts combination gas and electric utility, Fitchburg Gas and Electric Light Company (FG&E), received a series of state regulatory Orders during October 2001, which completed the review and disposition of a number of pending ratemaking and restructuring-related issues. As further discussed below (see Extraordinary Item), these regulatory Orders reflected a significant turning point in the Company's regulated business environment and determined the treatment and recovery of restructuring-related Regulatory Assets and costs in Massachusetts.

One of the Orders also completed an investigation into the overall earnings level of FG&E's electric division. As a result of this investigation, FG&E was directed to reduce its base electric distribution rates prospectively by $1.2 million annually, or approximately 8.4%. In compliance with this Order, the Company reduced its electric distribution rates, effective October 19, 2001. The Company is now in the process of preparing Performance Based Ratemaking (PBR) plans for FG&E's gas and electric distribution divisions. Under PBR, a company's earnings are tied to performance targets and penalties can be imposed for deterioration of service quality. The PBR plan will establish new distribution rates based on traditional cost of service ratemaking, service quality standards and penalties, and procedures for adjusting retail rates in future periods to reflect cost inflation and other factors over the term of the PBR plan.

During the first quarter of 2001, FG&E completed the restructuring-related divestiture of its interest in Millstone Unit No. 3 Nuclear Generating Station (Millstone 3). This sale ended the Company's involvement in nuclear power generation and eliminated all potential future liabilities related to this nuclear generating facility, including environmental and decommissioning liabilities.

During the year, Unitil's New Hampshire utility operating companies also completed the preparation of an electric restructuring plan and offer of settlement, which was filed in January 2002 for regulatory review and approval. This filing will result in the divestiture of Unitil's remaining regulated long-term power supply portfolio, the combination of Unitil's New Hampshire Utility Operations into a single utility, the unbundling and setting of new separate rates for energy and delivery services, and the introduction of retail choice allowing customers to choose a competitive energy supplier or to continue to receive their energy supply from Unitil during a transition period.

As a result of the progress Unitil continues to make towards the restructuring of its Massachusetts and New Hampshire Utility Operations, the Company expects all of its utility operating subsidiaries to be operating by the end of 2002 in a post-restructuring environment that reflects the unbundling of energy and delivery services, the recovery of restructuring and transition-related costs through appropriate rate mechanisms and newly established retail distribution rates. The Company is and will continue to be dedicated to the provision of the highest quality gas and electric distribution services to its customers at the lowest or among the lowest rates in the region.

Usource Energy Brokering - In the face of a market contraction of Internet-based business expansion opportunities aimed at mid-market customers, the Company quickly refocused its energy brokering business in the first half of 2001 toward our core customer base. Usource has succeeded in brokerage energy transactions for large and medium-size customers and, in 2001, the Company targeted a deeper penetration of these customer segments and achieved good revenue growth. Usource was able to extend its reach in the Northeast to include new and expanding markets in Connecticut, Maine, Massachusetts and Pennsylvania.

Usource increased revenues to $384,000 in 2001 from $131,000 in 2000 and is prepared to target new customer segments as energy markets continue to deregulate, allowing more customers to choose their energy suppliers. Usource is a broker of electric and natural gas energy supply contracts and does not take title to the commodity being traded. The Company reorganized its Usource operations in 2001 in order to control costs and improve financial performance. The current revenue stream of Usource covers the variable costs of operating this segment, which demonstrated marked improvement in earnings performance over 2000.

Usource serves its customer base by providing a wide range of energy brokering and related services. One way that Usource processes brokering transactions is through an Internet-based retail energy exchange operated by Enermetrix, Inc. (Enermetrix), in which Unitil is an investor. The Enermetrix exchange serves customers in several markets in the Northeast. During the fourth quarter, Unitil recorded a non-cash charge to earnings of $2.4 million, net of tax (See Investment Write-down) to recognize the decrease in market valuation of its investment in Enermetrix. Usource will continue to optimize value for its customers by seeking the best terms available for the purchase of their energy needs. As the volume of energy brokering grows further, Usource will continue to use the Enermetrix exchange and other available energy trading platforms to execute transactions.

In November 1997, the Massachusetts Legislature enacted landmark electric industry restructuring legislation (the Restructuring Act). The Restructuring Act required all electric utilities to file a restructuring plan with the Massachusetts Department of Telecommunications and Energy (MDTE) by December 31, 1997. The filing of its Restructuring Plan (the Plan) by Unitil's Massachusetts operating subsidiary, FG&E marked an unprecedented turning point in FG&E's 150 year history. Among other things, the Restructuring Act required all Massachusetts electric utilities to sell all of their electric generation assets and to restructure their Utility Operations to provide direct retail access to their customers by all qualified generation suppliers.

The MDTE conditionally approved FG&E's Plan in February 1998, and started an investigation and evidentiary hearings into FG&E's proposed recovery of Regulatory Assets related to stranded generation asset costs and expenses related to the formulation and implementation of its Plan. In January 1999, the MDTE approved FG&E's Plan, which included provisions for the recovery of stranded costs through a transition charge in the Company's electric rates. In September 1999, FG&E filed its first annual reconciliation of stranded generation asset costs and expenses and associated transition charge revenues, and the MDTE initiated a lengthy investigation and hearing process.

On October 18, 2001 and October 19, 2001, the MDTE issued a series of regulatory Orders in several pending cases involving FG&E, including a final Order on FG&E's initial reconciliation filing. Those Orders included the review and disposition of issues related to the Company's recovery of transition costs due to the restructuring of the electric industry in Massachusetts, as well as certain costs associated with gas industry restructuring and preparation and litigation of performance based rate proceedings initiated by the MDTE. The Orders determined the final treatment of Regulatory Assets that FG&E had sought to recover from its Massachusetts electric customers over a multi-year transition period that began in 1998. FG&E has now determined that it is authorized to recover approximately $150 million of Regulatory Assets attributable to stranded generation assets, purchased power costs and related expenses.

As a result of the industry restructuring-related Orders, FG&E recorded a non-cash adjustment to Regulatory Assets of $5.3 million, which resulted in the recognition of an extraordinary charge of $3.9 million, net of tax. The Company recognized the extraordinary charge of $0.83 per share as of September 30, 2001.

As a result of all of these Orders, the Company has been allowed recovery of its Massachusetts industry restructuring transition costs, estimated at $150 million, including the above-market or stranded generation and power supply related costs, via a non-bypassable uniform transition charge. FG&E has been and will continue to be subject to annual MDTE investigation and review in order to reconcile the costs and revenues associated with the collection of transition charges from its customers over the next eight to ten years.

Statement of Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities" addresses the accounting and reporting for investments in equity securities and requires companies to determine whether a decline in the fair value of the investment in equity securities is other than temporary.

The Company had invested $5.5 million in Enermetrix, Inc. (Enermetrix), an energy technology start-up enterprise, over the past several years. In accordance with SFAS No. 115, the Company recorded a non-cash charge of $3.7 million, or $2.4 million, net of tax, in the fourth quarter to recognize the decrease in fair value of its non-utility investment in Enermetrix. The Company has recorded a tax benefit of $1.3 million for this capital loss that it expects to realize in 2002. The Company recognized this valuation adjustment in 2001 to reflect significantly lower private equity valuation metrics for companies like Enermetrix and changes in the business outlook of Enermetrix. Enermetrix is a closely held, privately owned company and, as such, has no published market value. Unitil is a non-controlling, minority investor in Enermetrix. Among the contributing factors to management's decision for the reduction in fair value were the general economic downturn in the technology sector, the slower development of c ompetitive markets for energy supply and generally lower market valuations for companies like Enermetrix.

The Company's management considered various sources of information in determining its estimate of the fair value of its Enermetrix investment at December 31, 2001, including previous valuations of Enermetrix performed by independent investment banking firms and the Enermetrix operating forecast. Where those valuations were based upon the value of comparable companies that are publicly traded, and the operating forecast of Enermetrix, those statistics were updated and analyzed.

The Company has valued its investment in Enermetrix at December 31, 2001, at $1.8 million. Future market value risk is inherent in this investment in Enermetrix, which is an energy technology start-up enterprise. The Company will continue to monitor the value of its investment and periodically assess the impact, if any, on future period reported earnings.

The following graph shows Total Operating Revenues from 1999 to 2001:

Unit (kWh) Sales - Unitil's total electric kilowatt-hour (kWh) sales increased by 0.6% in 2001 compared to 2000. This increase reflects growth in sales to residential and commercial customer classes, offset by reductions in kWh sales to industrial customers, resulting from the economic downturn experienced in 2001.

Sales to residential customers increased by 3.4% in 2001 compared to 2000, and were 4.3% higher than 1999 sales. The increase in energy sales in 2001, as compared to 2000, was due in part to a 1.2% increase in the number of residential customers. The 4.3% increase in 2001 as compared to 1999 was due in part to a 2.6% increase in residential customers over this two-year period.

Commercial/Industrial sales of electricity were flat in 2001 compared to 2000. Commercial sales increased 3.1% due to customer growth and a warmer summer in 2001 compared to the prior year. Industrial sales decreased 3.7% compared to the prior year, primarily related to the downturn in economic conditions.

Unitil's total electric kWh sales decreased by 1.3% in 2000 compared to 1999. This decrease reflects the loss of a major customer that ceased operations in the second quarter of 2000, and a cooler-than-normal summer in 2000. Absent the loss of this major customer, total kWh sales in 2000 were flat compared to 1999. This primarily reflects continued growth in the number of customers served by the Company, offset by a cooler-than-normal summer season in 2000.

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

Electric Operating Revenue increased by $23.8 million, or 14.8%, in 2001 compared to 2000. This increase in revenue is a result of increased fuel and energy supply prices. The energy component of Electric Operating Revenue represents the recovery of energy supply costs, which are collected from customers through periodic cost recovery adjustment mechanisms. Changes in energy supply revenues do not affect net income, as they normally mirror corresponding changes in energy supply costs.

In 2000, Electric Operating Revenue increased by $5.9 million, or 3.9%, as compared to 1999. This increase in revenue is a result of increased fuel and energy supply prices, offset by decreased sales volume.

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

Unit (Therm) Sales - Total Firm Therm Sales decreased 3.9% in 2001 when compared to 2000, due to a warmer winter heating season compared to the prior year and the impact of an economic downturn.

In 2000, total Firm Therm Sales increased 8.4% compared to 1999, due to a colder winter heating season compared to the prior year, coupled with higher sales volume due to the Company's gas marketing initiatives.

The following table details total Firm Therm Sales for the last three years, by major customer class:

Gas Operating Revenue, which represents approximately 11% of Unitil's total Operating Revenues, were flat in 2001 compared to 2000. This was attributable to lower unit sales, offset by higher gas supply prices.

In 2000, total Gas Operating Revenue increased by $4.6 million, or 25.6%, as compared to 1999. This increase was attributable to higher unit sales, as well as increased gas supply prices.

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

Other Revenue increased $0.3 million, or 155.6%, compared to 2000. This was the result of growth in the amount of Usource energy brokerage fees.

In 2000, total Other Revenue was flat, as compared to 1999. This was the result of a decrease in revenue generated from consulting activities, offset by an increase in revenues from the Company's non-regulated energy brokering business, Usource.

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

Fuel and Purchased Power expense is the cost of purchased power, including fuel used in electric generation and the cost of wholesale energy and capacity purchased to meet Unitil's electric energy requirements. Fuel and Purchased Power expenses, recoverable from customers through periodic cost recovery adjustment mechanisms, increased $22.7 million, or 20.6%, in 2001 compared to 2000. The change was driven by an increase in wholesale power prices, as the nation experienced volatile markets and rising energy prices in 2000 and early 2001.

In 2000, Fuel and Purchased Power expenses increased $8.1 million, or 7.9%, as compared to 1999. This change was driven by an increase in wholesale power prices.

Gas Purchased for Resale reflects gas purchased and manufactured to supply the Company's total gas energy requirements. Gas supply costs are recoverable from customers through the Cost of Gas Adjustment mechanism. Gas Purchased for Resale increased by $0.3 million, or 2.5% in 2001 compared to 2000, reflecting a decrease in therms purchased, offset by higher wholesale gas prices in early 2001.

In 2000, Gas Purchased for Resale increased by $3.6 million, or 36.9%, as compared to 1999, reflecting an increase in therms purchased and significantly higher wholesale gas prices in 2000.

Operation and Maintenance expense includes electric and gas utility operating costs, and the operating cost of the Company's non-regulated business activities. Total Operating and Maintenance expense increased $0.5 million, or 1.9%, in 2001 compared to 2000. Utility Operations accounted for a net increase of $1.1 million, reflecting higher utility system maintenance costs and an increase in uncollectable account write-offs. Usource operating expenses decreased by $0.6 million in 2001 compared to 2000, reflecting the Company's refocused operating plan.

In 2000, Operation and Maintenance expense was relatively flat, as compared to 1999. Utility Operations accounted for a net decrease of $0.4 million, reflecting effective cost management and business process improvements. Usource operating and maintenance expense increased by $0.6 million in 2000 compared to 1999, reflecting planned sales, marketing, and product development expenditures.

Depreciation and Amortization expense increased $0.8 million, or 6.7%, in 2001 compared to 2000, due to a higher level of Plant in Service.

In 2000, Depreciation and Amortization expense increased $0.6 million, or 4.8%, as compared to 1999, due to a higher level of Plant in Service and accelerated write-off of electric generating assets, due to electric utility industry restructuring in Massachusetts. In addition, the Company incurred higher depreciation and amortization expenses related to Usource in 2000, compared to 1999.

Federal and State Income Taxes remained level, reflecting the fact that the Company's effective tax rate remained the same for 2001 and 2000.

In 2000, taxes decreased by $0.6 million, or 15.7%, compared to 1999, as a result of lower net income before taxes.

Local Property and Other Taxes decreased $0.3 million, or 6.1%, in 2001 compared to 2000. This decrease was related to the repeal of the State of New Hampshire Utility Franchise Tax and implementation of the Business Profits Tax, partially offset by higher property taxes.

In 2000, Local Property and Other Taxes decreased $0.1 million, or 2.2%, as compared to 1999. This decrease was related to local property tax changes.

Interest Expense is presented in the Financial Statements, net of Interest Income. In 2001, Interest Expense, net, reflects higher interest expense, offset by an increase in accrued interest income associated with deferred rate recovery mechanisms for Regulatory Assets. Total interest expense was $9.1 million, $8.6 million and $7.6 million in 2001, 2000 and 1999, respectively, due to higher debt outstanding in those years. Interest income was $2.3 million, $1.8 million and $0.7 million in 2001, 2000 and 1999, respectively, reflecting increased deferred restructuring-related costs.

In 2000, Interest Expense, net, decreased $0.1 million, or 1.4%, as compared to the prior year. An increase in accrued interest income associated with deferred rate recovery mechanisms was offset by higher short-term borrowing rates and a higher level of debt outstanding.

For the year ended December 31, 2001, Usource recorded a net loss of $1.0 million compared to a net loss of $1.7 million for 2000. The earnings per share impact of the Usource loss was $0.21 compared to a loss of $0.35 for 2000. The reduction in Usource losses reflects the Company's refocused operating plan and increased brokerage sales and fees in the Northeast.

Unitil requires capital primarily for the addition of property, plant, and equipment in order to improve, protect, maintain, and expand its electric and gas distribution systems. The capital necessary to meet these requirements is derived primarily from internally generated funds, which consist of cash flows from operating activities, excluding payments of dividends. The Company supplements internally generated funds, as needed, primarily through bank borrowings under unsecured short-term bank lines. As of December 31, 2001, the Company had unsecured bank lines for short-term debt aggregating $30 million with three banks. At December 31, 2001, the unused portion of these bank lines was $16.2 million. The amount of short-term borrowings that may be incurred by Unitil and its subsidiaries is subject to periodic approval either by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 or by the respective state regulators. In 2001, the Company received SEC authoriza tion to allow Unitil to incur total short-term borrowings up to a maximum of $45 million.

The Company periodically repays its short-term debt borrowings through the issuance of permanent long-term debt financing. The Company expects to continue to be able to satisfy its external financing needs by issuing additional short-term and long-term debt. The continued availability of these methods of financing will be dependent on many factors, including security market conditions, economic conditions, regulatory approvals and the level of the Company's income and cash flow.

The SEC recently issued a statement (Release Nos. 33-8056; 34-45321; FR-61) which discussed certain disclosures for inclusion in the financial reporting of public companies, specifically with respect to Management's Discussion and Analysis of Financial Condition and Results of Operations. In line with this statement, the Company has provided the following table, which summarizes the Significant Contractual Obligations of the Company going forward.

In addition to the significant contractual obligations listed in the above table, the Company also provides limited guarantees on certain energy contracts entered into by its regulated subsidiary companies. The term of these guarantees cannot exceed two years. Currently, there are $1.1 million of guarantees outstanding and these guarantees expire within the next eighteen months.

Cash Flows from Operating Activities increased by $14.3 million in 2001, after decreasing by $9.4 million in 2000. The decrease in 2000 and the corresponding increase in 2001 was primarily a result of changes in Accrued Revenues and Accounts Receivable, due to the impact of the volatile and rising energy markets in 2000 and early 2001. There is an inherent ratemaking lag between the period when energy costs increase and the period when the Company collects those higher energy costs from customers. This timing difference is recorded as Accrued Revenue. During the collection lag period, as occurred in 2000, the Company's cash flow is negatively impacted and additional working capital-related short-term borrowings is necessary. Once the Company begins to collect these higher costs through reconciling rate mechanisms, as it did in 2001, cash flow increases and short-term borrowings are repaid.

Cash Flows Used in Investing Activities decreased approximately $2.7 million in 2001, primarily reflecting a $1.2 million reduction in capital expenditures on distribution system additions and improvements, the receipt of $0.3 million of proceeds from the sale of the Company's interest in Millstone 3 and reduction of unregulated investment activities. Cash Flows Used in Investment Activities increased approximately $7.1 million in 2000, primarily reflecting cash proceeds of $5.3 million for the sale of the Company's 4.5% interest in New Haven Harbor Station, which was received in 1999.

Capital expenditures are projected to decrease in 2002 to approximately $19.2 million, primarily reflecting lower planned expenditures on the Company's non-regulated business activities offset by increased expenditures for utility distribution system improvements.

Cash Flows from Financing Activities decreased by $14.2 million in 2001 compared to 2000. This decrease primarily reflects proceeds received from the issuance of long-term debt, offset by a repayment of short- and long-term borrowings. During 2001, three of the Company's utility subsidiaries issued long-term debt totaling $29.0 million. The proceeds were used to reduce short-term debt aggregating $18.7 million and to provide long-term funding for a portion of its additions to gas and electric distribution plant and equipment (See Note 6). Cash Flows from Financing Activities increased by $18.0 million in 2000 compared to 1999. This increase reflected a higher level of borrowing in 2000 versus 1999 to fund the Company's capital expenditure program and working capital requirements. In particular, as previously discussed, the time lag between increases in energy costs and corresponding recovery from customers resulted in the Company incurring short-term debt to fund the interim working capital needs of the Company's energy cost obligations.

As a result of rising and volatile wholesale gas and electric energy prices in 2000 and early 2001, the Company filed and obtained authorization from the SEC under the 1935 Act to increase its maximum short-term borrowing level to $45 million. Further, the Company negotiated with its banks to increase its lines of credit to meet its borrowing obligations. On several occasions, the Company filed rate adjustments to its reconciling cost recovery mechanisms to reflect changes in wholesale energy prices during 2001. In 2001, as wholesale energy prices declined significantly, the Company obtained regulatory approval to reduce rates correspondingly to reflect lower energy costs.

During 2000 and 2001, respectively, the Company raised $0.6 and $0.3 million of additional common equity capital through the issuance of 22,916 and 11,279 shares of Common Stock in connection with the Dividend Reinvestment and Stock Purchase plans. During 2001, the Company moved to open-market purchases to meet its share issuance obligations under these plans. As a result, the Company does not anticipate issuing new original issue shares of Common Stock in connection with these plans in the next year. In conjunction with the SEC Emergency Orders of September 14 and 21, 2001, which suspended the applicability of certain of the conditions contained in its Rule 10b-18, the Company implemented an interim Common Stock repurchase program. Under this program, the Company repurchased, canceled and retired 2,500 of its outstanding Common shares at a total cost of $58,000. The SEC has since lifted its suspension of the aforementioned conditions and accordingly, the Company's interim Common Stock repurchase program is no longer in effect.

Unitil's annual Common Stock dividend in 2001 was $1.38 per share. This annual dividend resulted in a payout ratio of 91%, for the year, before the Investment Write-down and Extraordinary Item. Excluding the loss from Non-regulated Operations, the payout ratio was 80% based on Utility Operations, before the Investment Write-down and Extraordinary Item. At its January 2002 meeting, the Unitil Board of Directors declared a regular quarterly dividend on the Company's Common Stock of $0.345 per share. This quarterly dividend reflects the current annual dividend rate of $1.38 per share.

The Unitil Companies are regulated by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), and state regulatory authorities with jurisdiction over the utility industry, including the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In recent years, there has been significant legislative and regulatory activity to restructure the utility industry to introduce greater competition in the supply and sale of electricity and gas, while continuing to regulate the distribution operations of Unitil's utility operating subsidiaries.

Massachusetts enacted the Electric Restructuring Act of 1997 (the Restructuring Act) requiring the comprehensive restructuring of the electric utility industry in the State. Since March 1, 1998, all electric consumers in Massachusetts served by investor-owned utilities have had the ability to choose their electric energy supplier. FG&E, the Company's Massachusetts based combination gas and electric utility, has continued to implement its comprehensive electric Restructuring Plan, and has completed the divestiture of its entire regulated power supply business, including its nuclear investment in Millstone 3.

At the direction of the MDTE, in 1997, FG&E and other Massachusetts gas distribution utilities initiated an industry-wide collaborative process to develop a common set of principles to restructure their gas service and implement the necessary infrastructure to offer gas customers choice of their competitive gas energy supplier. FG&E filed new gas tariffs with the MDTE to implement natural gas unbundling in accordance with the principles resulting from this collaborative effort. The MDTE approved these tariffs and regulations governing the unbundling of gas services effective November 1, 2000.

In New Hampshire, Concord Electric Company (CECo) and Exeter & Hampton Electric Company (E&H), the Company's electric distribution operating subsidiaries, and Unitil Power Corp. (UPC), the Company's wholesale power supply company, continue to prepare for the transition to a new market structure. As discussed further below, on January 25, 2002, the Companies filed a comprehensive restructuring proposal with the NHPUC to comply with the State's restructuring law and provide retail choice to its customers. Unitil has also been an active participant in the restructuring of the wholesale power market and transmission system in New England. New wholesale markets have been implemented in the New England Power Pool (NEPOOL) under the general supervision of an Independent System Operator (ISO) and the regulatory oversight of the FERC.

Massachusetts Electric Operations Restructuring - On January 15, 1999, the MDTE approved the provisions of FG&E's Electric Restructuring Plan with certain modifications. Under the Restructuring Plan, FG&E must provide its customers with: a) the ability to choose a competitive energy supplier; b) an option to purchase standard offer service or default service provided by FG&E; and c) a cumulative 15% rate reduction adjusted for inflation.

As a result of the restructuring and divestiture of FG&E's entire generation and purchased power portfolio, FG&E has accelerated the amortization of its stranded electric generation assets and its abandoned investment in Seabrook Station. FG&E continues to earn an authorized rate of return on the unamortized balance of these Regulatory Assets. In addition, as a result of the rate reduction requirement of the Restructuring Act, FG&E has been authorized to defer the recovery of a portion of its transition costs and standard offer service costs. These unrecovered amounts are also recorded as Regulatory Assets and earn authorized carrying charges until their subsequent recovery in future periods. As the value of FG&E's Regulatory Assets are amortized and/or recovered over the next eight to ten years, income from this segment of FG&E's utility business will continue to decline and ultimately cease.

In accordance with its Restructuring Plan, each year FG&E adjusts its unbundled rate components, including the component that recovers its transition costs, to reconcile any differences between its estimated and actual costs from the prior year. These rate adjustments are subject to the required inflation-adjusted 15% rate discount. FG&E has made three such filings - in 1999, 2000, and 2001. Rate adjustments were approved for effect during the subsequent year, subject to further investigation.

The investigation of FG&E's initial reconciliation filing was initiated in 2000. On October 18, 2001 and October 19, 2001, the MDTE issued a series of regulatory Orders in several pending cases involving FG&E, including a final Order on FG&E's initial reconciliation filing. Those Orders included the review and disposition of issues related to the Company's recovery of transition costs due to the restructuring of the electric industry in Massachusetts, as well as certain costs associated with gas industry restructuring and preparation and litigation of performance based rate proceedings initiated by the MDTE. The Orders determined the final treatment of Regulatory Assets that FG&E had sought to recover from its Massachusetts electric customers over a multi-year transition period that began in 1998. FG&E has now determined that it is authorized to recover approximately $150 million of Regulatory Assets attributable to stranded generation assets, purchased power costs and related expenses . As a result of these Orders, FG&E recorded a non-cash adjustment to Regulatory Assets of $5.3 million in the third quarter of 2001, which resulted in the recognition of an extraordinary charge of $3.9 million after taxes. FG&E will continue to be subject to annual MDTE investigation and review in order to reconcile its restructuring-related costs and revenues, including its transition charge and standard offer service charge.

FG&E's third annual reconciliation and rate adjustment filing, filed on December 2, 2001, included a recast of its rates from 1998 through 2001 in compliance with the MDTE's final Order on its initial reconciliation filing. The investigation of the initial reconciliation filing specifically covered the period March 1998 through October 1999, however most of the MDTE's cost recovery findings apply after October 1999 as well. As part of this filing, FG&E also reduced its standard offer service fuel adjustment (SOSFA) reflecting lower fuel oil and natural gas costs. The SOSFA is a rate mechanism approved as part of restructuring plans in Massachusetts that provides for the recovery of excessive fuel costs based on a fuel trigger. Revenues collected under the trigger are passed on to standard offer service suppliers. Under the proposed SOSFA, FG&E estimates that all of its SOSFA-related costs, including deferred amounts of about $4.5 million, will be recovered by the end of November 2002.

On December 27, 2001, the MDTE approved FG&E's SOSFA and base rates for effect January 1, 2002, subject to further investigation. With the MDTE's resolution of cost recovery issues in its October 2001 Orders and anticipated final approval of FG&E's compliance filing, FG&E's financial risk associated with its unbundled cost recovery mechanisms is significantly reduced. The MDTE also allowed FG&E to implement the SOSFA for 2002. FG&E is required to notify the MDTE 45 days in advance of when all SOSFA-related costs are projected to be recovered.

Massachusetts Gas Operations Restructuring - As indicated above, in 1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service. In November 1999, the LDCs petitioned the MDTE for approval of regulations governing the unbundling of gas services that were developed with the input of participants of the collaborative. Effective November 1, 2000, the MDTE adopted these regulations and LDC tariffs, including those of FG&E, filed in accordance with the principles developed in the collaborative process. Retail customers are now free to choose a competitive gas supplier, if they wish.

As part of this proceeding, in February 1999, the MDTE issued an Order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. This Order also set forth the MDTE's decision requiring mandatory assignment by LDCs of their pipeline capacity contracts to competitive marketers.

New Hampshire Electric Operations Restructuring - On February 28, 1997, the NHPUC issued its Final Plan in response to the New Hampshire Electric Restructuring Law RSA 374-F, passed into law in 1996, for New Hampshire electric utilities to transition to a competitive electric market in the State. The Final Plan linked the interim recovery of stranded cost by the State's utilities to a comparison of their existing rates with the regional average utility rates. CECo's and E&H's rates are below the regional average; thus, the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery. However, the NHPUC also made certain legal rulings that could affect CECo's and E&H's long-term ability to recover all of their stranded costs. The Company cannot predict the final outcome of the restructuring of its Utility Operations in New Hampshire but believes that final resolution of this restructuring process will result in recovery of substantially all its stranded and restruct uring-related costs.

Northeast Utilities' affiliate, Public Service Company of New Hampshire (PSNH), filed suit in U.S. District Court for protection from the Final Plan and related orders and was granted an indefinite stay. In June 1997, Unitil, and other utilities in New Hampshire, intervened as plaintiffs in the federal court proceeding. In June 1998, the federal court clarified that the injunctions issued by the court in 1997 had effectively frozen the NHPUC's efforts to implement restructuring. This amended injunction has been challenged by the NHPUC, and affirmed by the First Circuit Court of Appeals. Unitil continues to be a plaintiff-intervenor in federal district court. In October 2000, the NHPUC approved a settlement for the restructuring of PSNH, which was implemented on May 1, 2001.

The Company has continued to work actively to explore settlement options and to seek a fair and reasonable resolution of key restructuring policies and issues in New Hampshire. The Company is also monitoring the regulatory and legislative proceedings dealing with electric restructuring in the State. As indicated above, the Company filed a comprehensive restructuring proposal with the NHPUC on January 25, 2002. If approved, the Company would withdraw its complaint from the federal court proceeding. The restructuring proposal, if approved, will go into effect on or before November 1, 2002. Under the restructuring proposal, the Company's customers will be allowed to choose a competitive energy supplier, while electricity delivery services will continue to be provided by Unitil. Unitil will sell its portfolio of electricity supply contracts and recover the residual stranded costs over a period of years. Unitil will offer customers a three-year transition service at specified prices and a permanent default ser vice. These services will be procured from the competitive wholesale market.

As part of the restructuring, Unitil is also proposing to combine CECo, E&H, and the remaining functions of UPC into a single distribution utility, Unitil Energy Systems, Inc. As part of the filing, Unitil filed new, consolidated tariff and rate schedules for distribution service in NH and is seeking an increase in base rates for distribution service. Rate levels and rate components applicable to all Unitil customers will change as a result, but overall rate levels are expected to be below rate levels in effect at the time of filing.

Rate Proceedings - Aside from Unitil's NH restructuring proposal discussed above, the last formal regulatory filings initiated by the Company to increase base rates for Unitil's three retail electric operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. A majority of the Company's electric operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas, energy efficiency, and restructuring-related cost recovery mechanisms. Electric industry restructuring will continue to change the methods of how certain costs are recovered through the Company's regulated rates and tariffs.

On the gas side, during FG&E's 1998 gas base rate case proceeding, the Massachusetts Attorney General alleged that FG&E had over-collected fuel inventory finance charges, and requested that the MDTE require FG&E to refund approximately $1.6 million of charges collected since 1987. The Company believes that the Attorney General's claim is without merit and that a refund was not justified or warranted. Following the MDTE's November 1, 1999 Order initiating an investigation, the MDTE held hearings in 2000. On May 31, 2001, the MDTE issued an Order in this proceeding, finding that FG&E had over-collected the costs in its Cost of Gas Adjustment Clause (CGAC) mechanism and ordered FG&E to return these costs, in the approximate amount of $0.7 million plus accumulated and future interest, to customers over the same number of years they were collected. On October 10, 2001, FG&E filed a Motion for Stay pending appeal and Memorandum of Law in Support with the Supreme Judicial Court (SJC). On November 16, 2001, the SJC denied the Motion for Stay, stating that any refunds made by FG&E may be recouped if FG&E prevails before the SJC on the merits of its claims. FG&E has begun to implement a multi-year refund of approximately $0.2 million per year through its CGAC mechanism in compliance with the MDTE's Order. The review of the MDTE Order by the SJC is currently pending. FG&E continues to assert that no refund is justified or warranted as a matter of fact or law; however, management cannot predict the outcome of this litigation.

On December 31, 1999, the Massachusetts Attorney General filed a complaint under G.L. c. 164, sec. 93, against FG&E requesting that the MDTE investigate the distribution rates, rate of return, and depreciation accrual rates for FG&E's electric operations in calendar year 1999. The MDTE opened a proceeding in November 2000 and investigated the matter in 2001. On October 18, 2001, the MDTE issued an Order, finding that FG&E's electric distribution base rates would annually generate an excess of approximately $1.2 million in revenue and ordered FG&E to reduce its electric base rates, effective that same day. FG&E submitted its compliance filing on October 19, 2001, and received approval of its filing on October 24, 2001.

Performance Based Ratemaking - On October 29, 1999, the MDTE initiated a proceeding to establish guidelines for service quality standards to be included in Performance Based Ratemaking (PBR) plans for all electric and gas distribution utilities in Massachusetts. PBR is a method of setting regulated distribution rates that provides incentives for utilities to control costs while maintaining a high level of service quality. Under PBR, a company's earnings are tied to performance targets and penalties can be imposed for deterioration of service quality. The MDTE issued an Order on June 29, 2001, establishing guidelines for implementation of service-quality measurement programs by gas and electric companies operating under PBR. On October 29, 2001, FG&E filed its Service Quality Plan for its Gas and Electric Divisions as required by the MDTE. On December 5, 2001, FG&E received approval of its Service Quality Plan for its Electric Division, subject to modification pending the conclusion of the s ervice quality proceeding. Approval of the plan for the Gas Division is pending. FG&E's Gas Division will be filing a PBR plan in April 2002. The requirement to file a PBR plan for the Gas Division stems from FG&E's 1998 gas rate case. FG&E is required to file a PBR plan for its Electric Division in its next electric rate case. The Company is preparing to file such a plan in April 2002. The PBR plan will establish new distribution rates through a traditional cost of service rate proceeding, service quality standards and penalties, and procedures for adjusting retail rates to reflect cost inflation and other factors over the term of the PBR plan.

Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement) between FG&E, certain other Massachusetts gas utilities and the Massachusetts Attorney General. 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 1882 through 1978. FG&E does not recover carrying charges associated with these costs and any tax benefits related to the payment of such costs are credited to customers in the year they are realized. 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 customers. The total annual charge for such cost assessed to customers cannot exceed five percent of FG&E's total revenue for firm gas sales during the preceding year. Cost in excess of five percent will be deferred for recovery in subsequent years.

Former Electric Generating Station - The Company is investigating environmental conditions at a former electric generating station located at Sawyer Passway, which FG&E sold to WRW, a general partnership, in 1983. Rockware International Corporation (Rockware), an affiliate of WRW, acquired rights to the electric equipment in the building and intended to remove, recondition and sell this equipment. During 1985, Rockware demolished several exterior walls of the generating station in order to facilitate removal of certain equipment. The demolition of the walls and the removal of generating equipment resulted in damage to asbestos containing insulation materials inside the building, which had been intact and encapsulated at time of the sale of the structure to WRW.

When Rockware and WRW encountered financial difficulties and ignored orders of the environmental regulators to remedy the situation, FG&E agreed to take steps and obtained DEP approval to temporarily enclose, secure and stabilize the facility. Based on that approval, between September and December 1989, contractors retained by the Company stabilized the facility and secured the building. This work did not permanently resolve the asbestos problems caused by Rockware, but was deemed sufficient for the then foreseeable future.

FG&E, working closely with the DEP and the Massachusetts Attorney General, brought an action in 1986 in the Worcester Superior Court, against Rockware. On July 16, 1990, FG&E filed an amended complaint and obtained a preliminary injunction barring Rockware from removing anything of value from the Fitchburg facility and barring it from further encumbering the property. It also obtained an attachment encumbering all of Rockware's goods, equipment and property, located in Fitchburg, Massachusetts. On June 3, 1993, FG&E, Rockware and WRW entered into an agreement for judgement in favor of the Company in the amount of $1.6 million and the preliminary injunctions became permanent. FG&E has been unable to collect any amounts from WRW and/or Rockware due to their bankruptcies.

In addition to its efforts to obtain reimbursement and indemnification from WRW and Rockware, FG&E entered into negotiations with its insurers. FG&E reached an interim settlement with its excess insurer and a final settlement with its primary insurer, which provided reimbursement for most of the costs that had been incurred to secure and stabilize the facility at that time.

Due to the continuing deterioration of this former electric generating station and Rockware's continued lack of performance, FG&E, in concert with the DEP and the U.S. Environmental Protection Agency (EPA), conducted further testing and survey work during 2001 to ascertain the environmental status of the building. These recent surveys have revealed continued deterioration of the asbestos containing insulation materials in the building. During an informal meeting on February 8, 2002, the EPA and DEP indicated to the Company that remedial actions are necessary. The Company anticipates receiving a Notice of Responsibility from the EPA by the end of the first quarter of 2002. The Company anticipates that this Notice will require specific remedial action, including abatement and removal of asbestos containing materials. At this time, the Company is uncertain as to the cost of the further remedial action that may be required by environmental regulators or for what portion of the cost the Company will be hel d responsible. However, the Company believes that its liability insurance policies will provide significant coverage for the costs of any clean-up effort and that the ultimate resolution of these matters will not have a material adverse impact on the Company's financial position.

Market Risk - Although Unitil's utility operating companies are active in markets which are subject to commodity price risk, the current regulatory framework within which these companies operate allows for full collection of fuel and gas costs in rates. Consequently, there is limited commodity price risk exposure after consideration of the related rate-making. As the utility industry continues to deregulate, the Company will be divesting its commodity-related energy businesses and therefore will be further reducing its exposure to commodity-related risk.

This report contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Certain factors that could cause the actual results to differ materially from those projected in these forward-looking statements include, but are not limited to: variations in weather, changes in the regulatory environment, customers' preferences on energy sources, general economic conditions, increased competition and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company.

Reference is made to the "Market Risk section of Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" (above).

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, 2001 and 2000, and the related consolidated statements of earnings, cash flows and changes in common stock equity for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the United States of America. 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 consolidated financial position of Unitil Corporation and subsidiaries as of December 31, 2001 and 2000, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.

/s/  GRANT THORNTON LLP   

Boston, Massachusetts

February 5, 2002