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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended June 30, 2004

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2004

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PART I. FINANCIAL INFORMATION

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

SAFE HARBOR CAUTIONARY STATEMENT

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

These statements include declarations regarding 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:

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.

RESULTS OF OPERATIONS

Operating Revenues — Electric

Electric Operating Revenues - Electric Operating Revenues, which represent approximately 85% of Unitil’s total Operating Revenues, decreased by $0.5 million, or 1.1%, and by $5.1 million, or 5.3%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003, primarily due to a decrease in energy prices from last year. Electric Operating Revenues include the recovery of cost of electric sales, which are recorded as Purchased Electricity and Conservation & Load Management in Operating Expenses. Approximately 90% of the Conservation & Load Management expenses are related to electric operations. Electric operating revenues increase or decrease due to changes in Purchased Electricity expenses and Conservation & Load Management expenses. 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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The Purchased Electricity cost of sales component decreased $1.3 million, or 4.3%, and $6.3 million, or 9.1%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003, reflecting lower electric commodity prices. Purchased Electricity expenses include the cost of electric supply as well as the other energy supply related restructuring costs including power supply buyout costs.

Conservation & Load Management revenues related to electric operations increased $0.2 million, or 29.5%, and $0.6 million, or 54.7%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003, reflecting increased spending on energy efficiency programs that were implemented during those periods. The Company recovers the costs of Purchased Electricity and Conservation & Load Management in its rates at cost and therefore changes do not impact net income.

Electric sales margin was $13.3 million and $26.8 million in the three and six month periods ended June 30, 2004, respectively. This represents increases of $0.6 million and $0.6 million compared to the same periods in 2003, respectively. These increases are due to increased kilowatt (kWh) unit sales to both residential and commercial and industrial customer classes during these periods.

The following table details total Electric Operating Revenues and Sales Margin for the three and six month periods ended June 30, 2004 and 2003:

Electric Operating Revenues and Sales Margin (000’s)

Kilowatt-hour Sales – Unitil’s total electric kilowatt-hour (kWh) sales increased 5.3% and 3.1% in the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. This increase reflects growth in sales to residential and commercial and industrial customer classes driven by customer growth.

Sales to residential customers increased 3.7% and 2.5% in the three and six months ended June 30, 2004, respectively, compared to the same periods in 2003. Commercial and industrial sales of electricity increased 6.2% and 3.4%, respectively, during those periods, compared to the same periods in 2003.

The following table details total kWh sales for the three and six months ended June 30, 2004 and 2003 by major customer class:

kWh Sales (000’s)

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Operating Revenues - Gas

Gas Operating Revenues – Gas Operating Revenues, which represent approximately 15% of Unitil’s total Operating Revenues, decreased $0.6 million, or 11.7%, and $1.4 million, or 7.8%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003. Gas Operating Revenues include the recovery of cost of sales, which are recorded as Purchased Gas and Conservation & Load Management in Operating Expenses.

Purchased Gas decreased $0.3 million, or 10.5%, and $1.1 million, or 9.6%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003. For the three month and six month periods ended June 30, 2004, the decrease in Purchased Gas is primarily attributable to lower gas unit sales. Purchased Gas costs include the cost of gas supply as well as the other energy supply related costs.

Conservation & Load Management expenses related to gas operations increased less than $0.1 million in both the three and six month periods ended June 30, 2004 compared to the same periods in 2003. The Company recovers the costs of Purchased Gas and Conservation & Load Management in its rates at cost and therefore changes do not impact net income.

Gas sales margin was $1.9 million and $6.1 million in the three and six month periods ended June 30, 2004, respectively. This represents decreases of $0.3 million and $0.4 million compared to the same periods in 2003, respectively. These decreases are attributable to lower unit sales, reflecting milder weather through the first six months of 2004 compared to the same period in 2003.

The following table details total Gas Operating Revenues and Margin for the three and six months ended June 30, 2004 and 2003:

Gas Operating Revenues and Sales Margin (000’s)

Therm Sales – Unitil’s total firm therm sales of natural gas decreased (10.0%) and (7.2%) in the three and six months ended June 30,2004, respectively, compared to the same periods in 2003, due to a milder winter heating season in 2004 and the continued impact of a poor economy on commercial and industrial customers. Sales to residential customers decreased (11.7%) and (7.2%), respectively, and sales to commercial and industrial customers decreased (8.0%) and (7.2%), respectively, compared to the same periods in 2003.

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The following table details total firm therm sales for the three and six months ended June 30, 2004 and 2003, by major customer class:

Firm Therm Sales (000’s)

Operating Revenue - Other

Total Other Revenues increased $0.1 million, or 32.5%, and $0.2 million, or 26.3% in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003. These increases were the result of growth in revenues from the Company’s unregulated energy brokering business, Usource.

The following table details total Other Revenue for the three and six months ended June 30, 2004 and 2003:

Other Revenue (000’s)

Operating Expenses

Purchased Electricity – Purchased Electricity expenses include the cost of electric supply as well as the other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity expenses, recoverable from customers through periodic cost recovery adjustment mechanisms, decreased $1.3 million, or 4.3%, and $6.3 million, or 9.1%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003, reflecting lower electric commodity prices on higher sales volumes. The Company recovers the costs of Purchased Electricity in its rates at cost and therefore changes in these expenses do not impact net income.

Purchased Gas – Purchased Gas expenses include the cost of 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. Purchased Gas decreased $0.3 million, or 10.5%, and $1.1 million, or 9.6%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003. For the three month and six month periods ended June 30, 2004, the decrease in Purchased Gas is primarily attributable to lower gas unit sales. The Company recovers the costs of Purchased Gas in its rates at cost and therefore changes in these expenses do not impact net income.

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 $0.1 million, or 2.4%, and $0.2 million, or 2.0% in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003.

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The increase in the six month period reflects higher compensation and benefits expenses, $0.5 million, partially offset by lower collection costs, bad debts expenses and other net utility operating expenses, ($0.3 million).

Conservation & Load Management - Conservation and Load Management expenses are expenses associated with the development, management, and delivery of the Company’s Energy Efficiency programs. Energy Efficiency programs are designed, in conformity with 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 $0.2 million, or 29.5%, and $0.6 million, or 54.8%, in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003 reflecting increased spending on Energy Efficiency programs that were implemented in 2004. These costs are collected from customers on a fully reconciling basis and therefore, fluctuations in program costs have no impact on earnings. However, in the long run, Commercial and Industrial customers’ consumption of energy and peak demands may be lower.

Depreciation, Amortization and Taxes

Depreciation and Amortization - Depreciation and Amortization expense increased $0.1 million, or 1.8% for the three month period ended June 30, 2004 compared to the same period in 2003. The increase for the three month period was primarily due to increased depreciation and amortization on normal plant additions and regulatory assets, partially offset by lower amortization of corporate intangible assets compared to last year. For the six month period ended June 30, 2004, Depreciation and Amortization expense decreased $0.1 million, or 1.2%, compared to the same period in 2003. This decrease is mainly due to a reduction in amortization expense on intangible assets.

Local Property and Other Taxes - Local Property and Other Taxes increased by less than $0.1 million, or 4.6%, and $0.1 million, or 3.1%, the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003. These increases were due to increases in payroll and property taxes.

Federal and State Income Taxes - Federal and State Income Taxes increased $0.2 million, or 30.1%, and $0.3 million, or 13.3% in the three and six month periods ended June 30, 2004, respectively, compared to the same periods in 2003, reflecting higher pre-tax earnings.

Interest Expense, net

Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on short- and 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 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.

Interest Expense, net, decreased by $0.2 million and $0.5 million in the three and six month periods ended June 30, 2004, respectively, as compared to the same periods in 2003. The decrease in the six month period was the result of a reduction of $0.2 million in short-term interest expense due to lower levels of short-term borrowings, and increased interest income on regulatory assets of $0.5 million, offset by an increase in long-term interest expense of $0.2 million due to a higher level of long-term debt.

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CAPITAL REQUIREMENTS

Cash provided by operating activities was $20.8 million during the first six months of 2004, an increase of $12.0 million over the same period last year. A major source of cash in Working Capital is due to the collection of Accrued Revenues in 2004, which represents an increase of $9.3 million in cash flow compared to last year. This reflects the recovery of deferred energy costs, principally Unitil Energy System, Inc.’s energy costs incurred primarily in first half of 2003, which are scheduled for recovery over a 22-month period ending in April 2005. The other major increase in the sources of working capital cash flow is attributable to the 2003 funding of approximately $2.7 million for an environmental remediation project and the funding of $1.2 million in 2003 related to nonrecurring restructuring charges. Together these items contributed to the change in working capital cash flow from Other Current Liabilities of $5.1 million. These sources were offset by a decrease in sources of cash from taxes of $3.0 million compared to last year, and a net increase in sources of cash of $0.6 million from other working capital requirements.

Cash used in investing activities for the six months ended June 30, 2004 was $10.6 million compared with $11.4 million during the same period last year, a reduction of $0.8 million, reflecting normal electric and gas utility system additions. In total, 2004 capital expenditures are estimated to be $21.9 million, or equivalent to 2003 capital expenditures.

Cash flows used in financing activities were $10.5 million in the first half of 2004 compared with $0.3 million in the same period of 2003. Cash used for financing activities in the current period includes: a repayment of short-term debt of $3.6 million, repayment of long-term debt of $3.1 million, the payment of dividends to shareholders of $3.9 million, and other sources of $0.1 million. The repayment of long-term debt fully retired the FG&E 8.55% Notes.

At June 30, 2004 and December 31, 2003, Unitil had an aggregate of $34.0 and $52.0 million, respectively, in unsecured revolving lines of credit through three banks. On July 12, 2004, the Company reduced its aggregate unsecured short-term bank lines to $33.0 million. The revolving lines of credit were reduced due to the October 2003 receipt of approximately $16.9 million (after deducting underwriting discounts, commissions and the other expenses of the offering) through the sale of Common Stock and the issuance of $10.0 million of long-term Notes by the Company’s subsidiary, Fitchburg Gas and Electric Light Company. The Company renews its lines of credit annually on or about June 30, and anticipates that it will be able to secure, renew or replace its revolving lines of credit in the future in accordance with its projected requirements. Average daily short-term borrowings during the first six months of 2004 were approximately $25.7 million, a decrease of approximately $12.9 million over the comparable period in 2003. At June 30, 2004, the Company had available approximately $15.2 million of unused bank lines of credit and had short-term debt outstanding through bank borrowings of approximately $18.8 million. In addition, Unitil had $3.4 million in cash at June 30, 2004.

The Company provides limited guarantees on certain energy contracts entered into by its regulated subsidiary companies. The Company’s policy is to limit these guarantees to two years or less. As of June 30, 2004, there are $0.4 million of guarantees outstanding and these guarantees extend through October 21, 2005.

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 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 judgments, 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.

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Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas in the Company-owned retail distribution utilities: Fitchburg Gas and Electric Light Company (FG&E), and Unitil Energy Systems, Inc. (UES). Both FG&E and UES are subject to regulation by the Federal Energy Regulatory Commission (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 SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” 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 recognizes the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and specifies 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 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 SFAS 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.

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 recorded. 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 as a percent of revenues 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

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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 bad debts 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, 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 SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions”, (PBOP). 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. Approximately 40% of the Company’s net pension expense is capitalized as capital additions to utility plant.

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 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 SFAS No. 109, “Accounting for Income Taxes.” The Company does not currently have any valuation allowances against its recorded deferred tax amounts.

Depreciation - Depreciation expense is calculated based on an asset’s useful life, 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 SFAS No. 5, “Accounting for Contingencies.” 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.

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

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INTEREST RATE RISK

The Company meets its external financing needs by issuing short-term debt. The majority of the Company’s 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 long-term debt securities issued by the Company. In addition, the Company’s short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease the Company’s interest expense in future periods. For example, if the Company had an 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 (pre-tax). The average interest rates on the Company’s short-term borrowings for the three months ended June 30, 2004 and June 30, 2003 were 1.54% and 1.87%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2004 and June 30, 2003 were 1.55% and 1.87%, 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 power and gas 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, has further reduced its exposure to commodity risk.

REGULATORY MATTERS

PLEASE ALSO REFER TO NOTE 6 TO THE CONSOLIDATED FINANCIAL STATEMENTS IN PART I, ITEM 1 OF THIS REPORT FOR A DETAILED DISCUSSION OF REGULATORY MATTERS.

As a registered holding company under PUHCA, Unitil and its subsidiaries are regulated by the Securities and Exchange Commission (SEC) with respect to various matters, including: the issuance of securities, our capital structure and certain acquisitions and dispositions of assets. 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, with respect to their rates, issuance of securities and other accounting and operational matters. Certain aspects of the Company’s utility operations as they relate to wholesale and interstate business activities are also regulated by the Federal Energy Regulatory Commission (FERC). Over the past several years, the Company has completed the restructuring of its electric and natural gas operations in order to implement retail choice as mandated in New Hampshire and Massachusetts.

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. In 2002, the retail distribution utilities completed rate proceedings and were authorized by the NHPUC and MDTE to implement increased rates for electric and natural gas distribution operations beginning in December of that year. UES and FG&E also recover the actual cost of any electricity or natural gas they supply to their customers, as well as certain costs associated with industry restructuring, through periodically adjusted rates.

In recent years, there has been significant legislative and regulatory activity to restructure the utility industry in order to introduce greater competition in the supply and sale of electricity and natural gas, while continuing to regulate the distribution operations of Unitil’s retail distribution utilities. Unitil implemented the restructuring of its electric and gas operations in Massachusetts in 1998 and 2000, respectively, and implemented the final phase of a restructuring settlement for its New Hampshire electric operations on May 1, 2003. Following electric industry

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restructuring, 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.

In connection with industry restructuring and the implementation of retail choice for our customers in New Hampshire and Massachusetts, Unitil Power divested of its long-term power supply contracts and FG&E divested of its long-term power supply contracts and owned generation assets. Unitil Power divested its long-term power supply contracts to a subsidiary of Mirant Corporation (Mirant) and FG&E divested its owned generation assets and long-term power supply contracts to Select Energy, Inc. (Select Energy). 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 as a result of electric industry restructuring.

Unitil’s customers in both New Hampshire and Massachusetts now have the opportunity to purchase their electric supply from third party vendors, though most customers continue to purchase such supplies through Unitil as the provider of last resort. Accordingly, UES and FG&E contract with wholesale power suppliers for the electricity necessary to meet their regulated default (provider of last resort) service energy supply obligations. Similarly, FG&E’s natural gas customers have the option to contract for their natural gas supply with third-party suppliers and FG&E remains the default service provider for these natural gas customers. The costs associated with the acquisition of such wholesale electric and natural gas supplies for customers who do not contract with third-party suppliers are recovered from those customers through reconciling rate mechanisms.

UES and FG&E have secured regulatory approval from both New Hampshire and Massachusetts state regulators 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 6 to 8 years, is $188 million as of June 30, 2004 and is included in Regulatory Assets on the Company’s Consolidated Balance Sheet. Unitil’s retail distribution utilities have also implemented comprehensive customer and financial information systems to accommodate the transition to competitive energy markets and retail choice.

On March 17, 2004, UES filed its first annual reconciliation and rate filing with the NHPUC under its restructuring plan, seeking revised rates for the Transition Service Charge, Default Service Charge, Stranded Cost Charge, and External Delivery Charge. In this filing, UES also sought an accounting order to defer and amortize transaction and issuance costs associated with the merger of E&H with and into CECo to form UES. The NHPUC issued orders approving the deferal and proposed rates, as modified during the course of the proceeding, for effect on May 1, 2004. The net impact of the proposed rate changes (see discussion of UES’ March 15, 2004 rate filing regarding PBOP costs, in “Other Regulatory Procedings, below) was a retail rate decrease of 1.8 percent.

Between December 2002 and January 2003, FG&E and UES received approval from their respective state regulatory commissions for accounting orders to mitigate certain accounting requirements related to prepaid pension plan assets, which have been triggered by the substantial decline in the capital markets and a sharp decrease in interest rates. These approvals allowed FG&E and UES to offset the additional minimum pension liability obligation as a Regulatory Asset and avoid the reduction in equity that would otherwise have been required. These regulatory orders did not pre-approve the amount of pension expense to be recovered in future rates, which recovery will be determined in future proceedings. Based on these approvals, FG&E’s and UES’ additional minimum pension liability obligations are offset by amounts included in Regulatory Assets on the Company’s balance sheet.