10-K 1 form10k.txt 10K 2002 DRAFT SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-8858 UNITIL CORPORATION (Exact name of registrant as specified in its charter) New Hampshire 02-0381573 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 6 Liberty Lane West, Hampton, New Hampshire 03842-1720 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (603) 772-0775 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Exchange on Which Registered Common Stock, No Par Value American Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K [ X ] Based on the closing price of March 1, 2003, the aggregate market value of common stock held by non-affiliates of the registrant was $123,810,466. The number of common shares outstanding of the registrant was 4,743,696 as of March 1, 2003. Documents Incorporated by Reference: Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 17, 2003, are incorporated by reference into Part III of this Report. UNITIL CORPORATION FORM 10-K For the Fiscal Year Ended December 31, 2002 Table of Contents Item Description Page PART I 1. Business Unitil Corporation................................................ 2 Utility Operations................................................ 3 March 14, 2003 New Hampshire Public Utilities Commission Order.... 4 Regulatory Matters................................................ 4 Electric Power Supply............................................. 6 Gas Supply........................................................ 8 Environmental Matters............................................. 9 Employees......................................................... 10 Executive Officers of the Registrant.............................. 11 2. Properties............................................................. 12 3. Legal Proceedings...................................................... 12 4. Submission of Matters to a Vote of Securities Holders.................. 12 PART II 5. Market for Registrant's Common Equity and Related Shareholder Matters.. 13 6. Selected Financial Data................................................ 14 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................................. 15 7A. Quantitative and Qualitative Disclosures about Market Risk............. 27 8. Financial Statements and Supplementary Data............................ 28 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................................... 53 PART III 10. Directors and Executive Officers of the Registrant..................... 54 11. Executive Compensation................................................. 54 12. Security Ownership of Certain Beneficial Owners and Management......... 54 13. Certain Relationships and Related Transactions......................... 54 PART IV 14. Controls and Procedures................................................ 55 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K........ 55 Signatures............................................................. 59 Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002................................................................ 61 Schedule II Valuation and Qualifying Accounts and Reserves............. 64 Exhibit 4.1 Unitil Energy Systems, Inc. - Twelfth Supplemental Indenture Exhibit 10.16 Restricted Stock Plan Exhibit 10.17 Portfolio Sale and Assignment and Transition Service and Default Service Supply Agreement By and Among Unitil Power Corp., Unitil Energy Systems, Inc. and Mirant Americas Energy Marketing, LP Exhibit 11.1 Computation in Support of Earnings per Share Exhibit 12.1 Computation in Support of Ratio of Earnings to Fixed Charges Exhibit 21.1 Subsidiaries of Registrant Exhibit 23.1 Consent of Independent Certified Public Accountants Exhibit 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 1 PART I Item 1. Business UNITIL Corporation Unitil Corporation (Unitil or the Company) was incorporated under the laws of the State of New Hampshire in 1984. Unitil is a registered public utility holding company under the Public Utility Holding Company Act of 1935 (the 1935 Act), and is the parent company of the Unitil companies. The following companies are wholly-owned subsidiaries of Unitil:
State and Unitil Corporation Year of Principal Type Subsidiaries Organization of Business -------------------------------------------------- --------------- ------------------------------------------- Unitil Energy Systems, Inc. (UES) NH - 1901 Retail Electric Distribution Utility Fitchburg Gas and Electric Light Company (FG&E) MA - 1852 Retail Electric & Gas Distribution Utility Unitil Power Corp. (Unitil Power) NH - 1984 Wholesale Electric Power Utility Unitil Realty Corp. (Unitil Realty) NH - 1986 Real Estate Management Unitil Service Corp. (Unitil Service) NH - 1984 System Service Company Unitil Resources, Inc. (Unitil Resources) NH - 1993 Energy Brokering and Advisory Services Usource, Inc. NH - 2000 Energy Brokering and Advisory Services Usource L.L.C. (Usource) NH - 2000 Energy Brokering and Advisory Services
Unitil's principal business is the retail sale and distribution of electricity and related services in several cities and towns in the seacoast and capital city areas of New Hampshire, and both electricity and gas and related services in north central Massachusetts, through Unitil's two wholly-owned retail distribution utility subsidiaries (UES and FG&E, collectively referred to as the Retail Distribution Utilities). The Company's wholesale electric power utility subsidiary, Unitil Power Corp., currently provides all the electric power supply requirements to UES for resale at retail. In December 2002, Exeter & Hampton Electric Company (E&H), a wholly-owned subsidiary of Until, was merged with and into Concord Electric Company (CECo), also a wholly-owned subsidiary of Unitil. CECo changed its name to UES immediately following the merger. Unitil has three additional wholly owned subsidiaries: Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and Unitil Resources, Inc. (Unitil Resources). Unitil Realty owns and manages the Company's corporate office building and property located in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Service provides, at cost, centralized management, administrative, accounting, financial, engineering, information systems, regulatory, planning, procurement, and other services to the Unitil System companies. Unitil Resources is the Company's wholly owned non-utility subsidiary and has been authorized by the Securities and Exchange Commission, pursuant to the rules and regulations of the 1935 Act, to engage in business transactions as a competitive marketer of electricity, gas and other energy commodities in wholesale and retail markets, and to provide energy brokering, consulting and management related services within the United States. Usource, Inc. and Usource L.L.C. (Usource) are wholly-owned subsidiaries of Usource, Inc. Usource provides energy brokering services, as well as related energy consulting services. 2 UTILITY OPERATIONS UES serves customers in two distinct geographical territories in New Hampshire - one in the central region of the state and one in the seacoast region. UES is engaged principally in the retail distribution and sale of electricity to approximately 70,000 customers in New Hampshire in the cities of Concord, Exeter and Hampton, as well as 12 towns surrounding Concord and all or part of 16 towns surrounding Exeter and Hampton. UES's service area consists of approximately 408 square miles in the Merrimack River Valley of south central New Hampshire and in southeastern New Hampshire. The State of New Hampshire's government operations are located within UES's service area, including the executive, legislative, judicial branches and offices and facilities for all major state government services. In addition, UES's service area is a retail trading center for the north central and southeastern parts of the state. These areas serve diversified businesses relating to insurance, printing, electronics, granite, belting, plastic yarns, furniture, machinery, sportswear and lumber, shopping centers, motels, farms, restaurants, apple orchards and office buildings, as well as manufacturing firms engaged in the production of sportswear, automobile parts and electronic components. It is estimated that there are over 150,000 daily summer visitors to UES's service territory in southeastern New Hampshire, which includes several popular resort areas and beaches along the Atlantic Ocean. Of UES's 2002 retail electric revenues, approximately 42% were derived from residential sales, 34% from commercial, government and nonmanufacturing sales, 23% from industrial/manufacturing sales and 1% from other sales. FG&E is engaged principally in the retail distribution and sale of both electricity and natural gas in the City of Fitchburg and several surrounding communities. FG&E's service area encompasses approximately 170 square miles in north central Massachusetts. Electricity is supplied and distributed by FG&E to approximately 27,000 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. FG&E's industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and allied industries. Of FG&E's 2002 electric revenues, approximately 35% were derived from residential sales, 23% from commercial and nonmanufacturing sales, 25% from industrial/manufacturing sales and 17% from other sales. Natural gas is supplied and distributed by FG&E to approximately 15,000 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Of FG&E's 2002 gas operating revenues, approximately 51% were derived from residential sales, 11% from small general customers, 18% from medium general customers, 9% from large general customers, 8% from interruptible sales (which are sales to customers that have agreed to discontinue use of the Company-supplied gas service temporarily upon notice by the Company, and which customers usually have an alternate fuel capability, e.g., fuel oil, that they can employ during the interruption periods) and 3% from other sales. FG&E's industrial gas revenue is primarily derived from firm sales to chemical manufacturers, paper manufacturing and paper products companies, fabricated metal products manufacturers and plastics manufacturers. Natural gas sales in New England are seasonal, and the Company's results of operations reflect this seasonal nature. Accordingly, results of operations are typically positively impacted by gas operations during the five heating season months from November through March of the following year. Electric sales in New England are far less seasonal than natural gas sales; however, the highest usage typically occurs in the summer and winter months due to air conditioning and heating requirements, respectively. Unitil is not dependent on a single customer or a few customers for its electric and gas sales. (For details on Unitil's Results of Operations, see Part II, Item 7 herein.) (For segment information, see Part II, Item 8, Footnote 14 herein.) 3 MARCH 14, 2003 New Hampshire Public Utilities Commission Order On March 14, 2003 the New Hampshire Public Utilities Commission (NHPUC) approved the agreement between Unitil Power, UES and Mirant Americas Energy Marketing, LP. (Mirant), which was entered into on February 25, 2003, under which Mirant will purchase the entitlements to Unitil Power's Supply portfolio and provide Transition and Default Service to the customers of UES. The final amount of Unitil Power's recoverable stranded costs, calculated on the basis of the amounts agreed to be paid by the parties under such Agreement for the Unitil Power power supply portfolio, was determined to be $108.7 million, with a recovery period of 8 years. As of December 31, 2002, the Company had estimated these recoverable stranded costs and accordingly recorded on its balance sheet as of that date $94.5 million as Power Supply Buyout Obligations and Regulatory Assets. The approval of the Agreement by the NHPUC is subject to an appeal period of 30 days. The NHPUC Order completes the state approval process for Unitil's restructuring plan under which UES will implement customer choice for its customers on May 1, 2003. REGULATORY MATTERS 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 public utilities, 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 in order 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. Unitil implemented the restructuring of its electric operations in Massachusetts in 1998 and is implementing a restructuring settlement for its New Hampshire electric operations on May 1, 2003. Massachusetts Electric Operations Restructuring - Beginning March 1, 1998, FG&E implemented its Restructuring Plan under the Massachusetts Restructuring Act. FG&E completed the divestiture of its entire regulated power supply business in 2000 in accordance with the Restructuring Plan. All FG&E distribution customers must pay a transition charge that provides for the recovery of costs associated with FG&E's power portfolio which were stranded as a result of the divestiture of those assets. The plant and Regulatory Asset balances that will be recovered through the transition charge have been approved by the MDTE as part of FG&E's annual Reconciliation Filings. The Restructuring Act also requires FG&E to obtain power for retail customers who choose not to buy energy from a competitive supplier through either Standard Offer Service (SOS) or Default Service. FG&E must provide SOS through February 2005 at rate levels which guarantee rate reductions required by the Restructuring Act. New distribution customers and customers no longer eligible for SOS are eligible to receive Default Service at prices set periodically based on market solicitations as approved by regulators. As of December 31, 2002, competitive suppliers were serving approximately 20% of FG&E's load, mainly for large industrial customers. 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, a nuclear generating unit. FG&E earns an authorized rate of return on the unamortized balance of these Regulatory Assets. In addition, as a result of the rate reduction and rate cap requirements of the Restructuring Act, FG&E has been authorized to defer the recovery of a portion of its transition costs and SOS costs. These unrecovered amounts are also recorded as Regulatory Assets and earn authorized carrying charges until their subsequent recovery in future periods. In 2002, Unitil's earnings derived from these generation-related Regulatory Assets, including carrying charges earned on deferred transition costs and SOS costs, represented approximately 10% of net income. The value of FG&E's Regulatory Assets is approximately $128 million at December 31, 2002, and is expected to be amortized and recovered over the next three to nine years. Earnings from this segment of FG&E's utility business will continue to decline and ultimately cease. FG&E made a total of four Reconciliation Filings in 1999, 2000, 2001 and 2002. Rate adjustments were approved in each Filing for effect during the subsequent year, subject to further investigation. In October 2001, the MDTE issued a final Order on FG&E's 1999 Reconciliation Filing which determined the final treatment of Regulatory Assets attributable to stranded generation costs, purchased power costs, and related expenses for the 1999, and future, Reconciliation Filings. FG&E's 2001 Reconciliation Filing, submitted on December 2, 2001, recast its rates from 1998 through 2001 in compliance with the MDTE's final Order on its 1999 filing. On October 15, 2002, the MDTE issued an Order approving a settlement agreement regarding the Company's 2001 filing. Under the approved settlement, FG&E agreed to reduce the carrying charge on deferred transition costs that will be 4 recovered from customers in future years. This change does not affect current electric rates, but will reduce the total amount of transition costs, including carrying costs, in future years. The MDTE's October 2002 Order and associated settlement resolve many of the issues which otherwise might have been contested in future FG&E Reconciliation Filings. FG&E submitted its 2002 Reconciliation Filing on December 20, 2002. Rate adjustments were approved for effect on January 1, 2003, subject to investigation, resulting in a rate reduction of approximately 4.4% for residential SOS customers. The reduction is due to a decrease in the SOS fuel adjustment, which is not subject to the rate cap, and does not affect net income. Massachusetts Gas Operations Restructuring - Following a three year state-wide collaborative process on the unbundling, or separation, of discrete services offered by natural gas local distribution companies (LDCs), the MDTE approved regulations and tariffs for FG&E and other LDCs to provide full customer choice effective November 1, 2000. The MDTE ruled that LDCs would continue to have an obligation to provide gas supply and delivery services for a five-year transition period, with a review after three years. This review is expected to be initiated in late 2003. The MDTE also required mandatory assignment of LDCs' pipeline capacity to competitive marketers supplying customers during the transition period. This mandatory capacity assignment protects LDCs from exposure to certain stranded gas supply costs during the transition period. New Hampshire Restructuring - On January 25, 2002, the Company's New Hampshire electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with the New Hampshire Public Utilities Commission (NHPUC). This proposal included the introduction of customer choice consistent with New Hampshire's electric utility industry restructuring law, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the merger of CECo and E&H into one distribution company and new distribution rates for the combined company. On October 25, 2002, the NHPUC approved a multi-party settlement on all major issues in the proceeding, including stranded cost recovery for purchased power contracts. At December 31, 2002, the Company estimated a range for these divestiture obligations and recoverable stranded costs and recorded $94.5 million as Power Supply Buyout Obligations and Regulatory Assets at December 31, 2002. Under Unitil's restructuring plan, Unitil agreed to divest its existing power supply portfolio and conduct a solicitation for new power supplies from which to meet UES' ongoing Transition and Default Service obligations in 2003. On February 26, 2003, Unitil filed for final NHPUC approval of the Agreement among Unitil Power, UES and Mirant discussed above under the heading "March 14, 2003 NHPUC Oder," including final tariffs for UES for stranded cost recovery and Transition and Default Service. On March 14, 2003 the NHPUC approved the Agreement. The Agreement and Order of the NHPUC provide for stranded cost recovery in the amount of $108.7 million over a recovery period of eight years. The NHPUC Order is subject to a 30 day appeal period. Unitil's restructuring plan is also designed to resolve the pending litigation on this matter. In June 1997, Unitil and other New Hampshire utilities intervened as plaintiffs in a suit filed in U.S. District Court by Northeast Utilities' affiliate Public Service Company of New Hampshire for protection from the NHPUC's Final Plan to restructure the New Hampshire electric utility industry. Although the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery, the NHPUC also made certain legal rulings, that, if implemented, could affect UES's long-term ability to recover all of its stranded costs. The Unitil Settlement, approved in October 2002, otherwise resolves all of the issues in the federal court action. Upon the expiration of all periods of appeal with respect to the regulatory approvals for Unitil's New Hampshire restructuring, UES will implement retail choice and Unitil will withdraw its intervention in this federal court action, with prejudice. Unitil expects customer choice to be implemented on May 1, 2003. Wholesale Power Market Restructuring - Unitil has also been a participant in the restructuring of the wholesale power market and transmission system in New England, which is subject to FERC jurisdiction. New wholesale markets structured pursuant to FERC's Standard Market Design are expected to be implemented in the New England Power Pool during the first half of 2003 under the general supervision of an Independent System Operator (ISO) and the regulatory oversight of the FERC. Rate Proceedings - Prior to 2002, the last formal regulatory filings initiated by the Company to increase base rates for Unitil's retail electric operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. The last distribution base rate increase request for FG&E's retail gas operations occurred in 1998. In 2001, FG&E's electric base rates were investigated by the MDTE, which resulted in an electric base rate decrease. A majority of the Company's electric and gas operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, energy efficiency, and restructuring-related cost 5 recovery mechanisms. 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, FG&E continues to provide a multi-year refund through its Cost of Gas Adjustment Clause in compliance with the MDTE's May 2001 Order finding that FG&E had over-collected fuel inventory finance charges. At December 31, 2002, the unamortized balance of this refund was $1.3 million. FG&E believes a refund is not justified or warranted and has appealed the MDTE's ruling to the Massachusetts Supreme Judicial Court (SJC). On a preliminary motion, a single justice of the SJC declined to stay the MDTE's Order based on a finding that refunds made by FG&E may be recouped if FG&E prevails on the merits of its claims. The review of the MDTE Order by the SJC is pending. On October 25, 2002, as part of the electric restructuring settlement for Unitil's New Hampshire utility operations described above, the Company received approval from the NHPUC for an increase of approximately $2.0 million in annual distribution revenues for UES, effective December 1, 2002. On December 2, 2002, the MDTE issued an Order resulting in distribution rate increases of $2.0 million for FG&E's electric operations and $3.0 million for FG&E's gas operations. Increases for rising gas costs were incorporated into the final gas rates. FG&E's new rates became effective on December 2, 2002. On April 16, 2002, FG&E filed Performance Based Regulation (PBR) Plans with the MDTE for both electric and gas operations. PBR is a method of setting regulated distribution rates that provides incentives 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. FG&E's PBR Plans were filed in conjunction with FG&E's distribution rate filings, consistent with MDTE policy to implement PBR in the context of base rate cases. The MDTE did not initiate investigations of the filings. On January 6, 2003, the MDTE issued Orders closing the cases. Accordingly, FG&E's PBR plans have no scheduled date of implementation, and conventional cost-based regulation continues to apply. In December 2002, FG&E and UES filed requests with their respective state regulatory commissions for approval of an accounting Order to mitigate certain accounting requirements related to pension plan assets, which have been triggered by the substantial decline in the capital markets. These requests were granted by the respective state regulatory commissions in December 2002. These approvals allow FG&E and UES to treat the additional minimum pension liability and Prepaid Pension Costs as Regulatory Assets and avoid the reduction in equity that would otherwise be required. These regulatory Orders do not pre-approve the amount of pension expense to be recovered in future rates. Such recovery will be subject to review and approval in future rate proceedings. Based on these approvals, Unitil has included the amount of the additional minimum pension liabilities and Prepaid Pension Costs of $12.0 million in Regulatory Assets on its balance sheet. ELECTRIC POWER SUPPLY FG&E distributes electricity in the north central area of Massachusetts. UES distributes electricity in the central and seacoast regions of New Hampshire. FG&E contracts directly for its electric supply with various wholesale suppliers. UES contracts for all of its needs from its affiliate Unitil Power, which has acquired a portfolio of power contracts from other wholesale suppliers. Following retail choice restructuring in 2003, UES will contract directly with wholesale suppliers to meet the needs of its customers. The wholesale power markets are conducted under the auspices of the New England Power Pool (NEPOOL). FG&E, Unitil Power, and UES are members of NEPOOL. NEPOOL was formed in 1971 to assure reliable operation of the bulk power system in the most economic manner for the region. Under the NEPOOL Agreement and the Open Access Transmission Tariff (OATT), to which virtually all New England electric utilities are parties, substantially all operation and dispatching of electric generation and bulk transmission capacity in New England is performed on a regional basis. NEPOOL is governed by an agreement that is filed with the FERC and its provisions are subject to continuing FERC jurisdiction. The NEPOOL Agreement and the OATT imposes generating capacity and reserve obligations, provides for the use of major transmission facilities and payments associated therewith. The most notable benefits of NEPOOL are coordinated power system operation in a reliable manner and a supportive business environment for the development of a competitive electric marketplace. There are ongoing legislative and regulatory initiatives that are primarily focused on the deregulation of the generation and supply of electricity and the corresponding development of a competitive market place from which 6 customers could choose their electric energy supplier. As a result, the NEPOOL Agreement continues to be restructured. NEPOOL's membership provisions have been broadened to cover all entities engaged in the electricity business in New England, including power marketers and brokers, independent power producers, load aggregators and retail customers in states that have enacted retail access statutes. The regional bulk power system is operated by an independent corporate entity, ISO New England (ISO-NE), so that there is no opportunity for conflicting financial interests between the system operator and the market-driven participants. Various energy and capacity products are traded in open, competitive markets, with transmission access and pricing subject to a regional OATT designed to promote competition among power suppliers. On May 1, 1999, ISO-NE began dispatching generating units using a bid-based system and implemented bid-based markets for reserve products and automatic generation control. On March 1, 2003, ISO-NE implemented a Standard Market Design (SMD) that is intended to improve the ability to trade power between New England and other regions throughout the northeast. Energy Resources - Since April 1, 1998, each electric utility is required to carry an allocated share of the NEPOOL capability responsibility under the NEPOOL Agreement. These capacity requirements are determined each month based on regional reliability criteria. Unitil Power, the full requirements supplier to UES, had an annual peak capability responsibility in November 2002 of 309.33 MW and a corresponding monthly peak demand of 220.02 MW. Beginning December 1, 2000, FG&E no longer had a direct capability responsibility because it's Standard Offer Service supplier, Constellation Power Source, and its periodic Default Service supplier are responsible for the capability responsibility under the respective contracts. Effective December 1, 2000, FG&E began serving Default Service load through six-month contracts wherein the Default Service supplier had the load serving obligation, thus at the end of 2000, FG&E had no direct capability responsibility. Under MDTE regulations, FG&E has continued to procure Default Service through a bid process every six months. To meet the needs of UES, Unitil Power has contracted for generating capacity and energy and for associated transmission services as needed to meet NEPOOL requirements and to provide a diverse and economical energy supply. Unitil Power's purchases are from various utility and non-utility generating units using a variety of fuels and from several utility systems in the U.S. and Canada as well as purchases in the spot market. For the twelve months ended December 31,2002, Unitil Power's energy needs were provided by the following fuel sources: nuclear (10%), oil (6%), gas (8%), coal (5%), refuse (4%), and system (67%). On March 14, 2003 the New Hampshire Public Utilities Commission (NHPUC) approved the agreement between Unitil Power, UES and Mirant Americas Energy Marketing, LP. (Mirant), which was entered into on February 25, 2003, under which Mirant will purchase the entitlements to Unitil Power's Supply portfolio and provide Transition and Default Service to the customers of UES. The final amount of Unitil Power's recoverable stranded costs, calculated on the basis of the amounts agreed to be paid by the parties under such Agreement for the Unitil Power power supply portfolio, was determined to be $108.7 million, with a recovery period of 8 years. As of December 31, 2002, the Company had estimated a range for these recoverable stranded costs and accordingly recorded on its balance sheet as of that date $94.5 million as Power Supply Buyout Obligations and Regulatory Assets. The approval of the Agreement by the NHPUC is subject to an appeal period of 30 days. The NHPUC Order completes the state approval process for Unitil's restructuring plan under which UES will implement customer choice for its customers on May 1, 2003. Under Unitil's approved restructuring plan, Unitil agreed to divest its existing power supply portfolio and conduct a solicitation for new power supplies from which to meet UES' ongoing Transition and Default Service energy obligations. On February 26, 2003, Unitil filed for final NHPUC approval of the executed agreements resulting from these divestiture and solicitation processes, including final tariffs for UES for stranded cost recovery and Transition and Default Services. The filing proposed a recovery period of eight years for stranded costs. On January 25, 2002, the Company's New Hampshire electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with the New Hampshire Public Utilities Commission (NHPUC). This proposal included the introduction of customer choice consistent with New Hampshire's electric utility industry restructuring law, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the merger of CECo and E&H into one distribution company and new distribution rates for the combined company. On October 25, 2002, the NHPUC approved a multi-party settlement on all major issues in the proceeding, including stranded cost recovery for purchased power contracts. At December 31, 2002, the Company estimated these divestiture obligations and recoverable stranded costs and recorded $94.5 million as Power Supply Buyout Obligations and Regulatory Assets at December 31, 2002. 7 In 2002, FG&E met its capacity requirements through an all requirements Standard Offer contract with Constellation Power Source, and several all requirements Default Service contracts. FG&E's power supply portfolio, including the joint ownership generation output, was sold to Select Energy, Inc. effective February 1, 2000 as part of the power supply restructuring plan approved by the MDTE. For the twelve months ended December 31, 2002, FG&E's energy needs were supplied by system power from the Standard Offer and Default contracts. Fuel - Oil: Approximately 6% of Unitil Power's electric power in 2002 was provided by oil-fired units. Most fuel oil used by New England electric utilities is acquired from foreign sources and is subject to interruption and price increases by foreign governments. Coal: Approximately 5% of Unitil Power's 2002 requirements were from coal-burning facilities. The facilities generally purchase their coal under long-term supply agreements with prices tied to economic indices. Although coal is stored both on-site and by fuel suppliers, long-term interruptions of coal supply may result in limitations in the production of power or fuel switching to oil and thus result in higher energy prices. Pursuant to the Nuclear Waste Policy Act of 1982, the participants in Millstone Nuclear Generating Station Unit No. 3 (Millstone 3) were required to enter into contracts with the United States Department of Energy, prior to the operation of that Unit, for the transport and disposal of spent fuel at a nuclear waste repository. FG&E cannot predict whether the Federal government will be able to provide storage or permanent disposal repositories for spent fuel. FG&E's Millstone 3 ownership interest was sold in March 2001. The sales agreement and a separate settlement agreement with Northeast Utilities indemnifies FG&E from continuing liability associated with environmental, decommissioning and waste disposal associated with its former Millstone 3 ownership. GAS SUPPLY FG&E distributes gas purchased from domestic and Canadian suppliers under long-term contracts as well as gas purchased from producers and marketers on the spot market. The following tables summarize actual gas purchases by source of supply and the cost of gas sold for the years 2000 through 2002. Sources of Gas Supply (Expressed as percent of total MMBtu of gas purchased) Natural Gas: 2002 2001 2000 ------------------------------------ Domestic firm 73.9% 76.2% 78.6% Canadian firm 8.4% 8.0% 6.3% Domestic spot market 16.2% 14.5% 13.2% ------------------------------------ Total natural gas 98.5% 98.7% 98.1% Supplemental gas 1.5% 1.3% 1.9% ------------------------------------ Total gas purchases 100.0% 100.0% 100.0% Cost of Gas Sold 2002 2001 2000 -------------------------------- Cost of gas purchased and sold per MMBtu $ 4.49 $ 6.49 $ 5.19 Percent Increase (Decrease) from prior year (30.76%) 24.99% 52.01% As a supplement to pipeline natural gas, FG&E owns a propane air gas plant and a liquefied natural gas (LNG) storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas. 8 ENVIRONMENTAL MATTERS The Company's past and present operations include activities that are subject to extensive federal and state environmental regulations. Sawyer Passway MGP Site - The Company continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows the Company to work towards temporary remediation of the site. Work performed in 2002 was associated with the five-year review of the Temporary Solution submittal (Class C Response Action Outcome) under the Massachusetts Contingency Plan that was filed for the site in 1997. Completion of this work has confirmed the Temporary Solution status of the site for an additional five years. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed. Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement). The Agreement allows FG&E to amortize and recover from gas customers over succeeding seven-year periods the environmental response costs incurred each year. Environmental response costs are defined to include liabilities related to manufactured gas sites, waste disposal sites or other sites onto which hazardous material may have migrated as a result of the operation or decommissioning of Massachusetts gas manufacturing facilities from 1882 through 1978. In addition, any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers. The total annual charge for such costs assessed to gas customers cannot exceed five percent of FG&E's total revenue for firm gas sales during the preceding year. Costs in excess of five percent will be deferred for recovery in subsequent years. Former Electric Generating Station - The Company is remediating 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 the time of the sale of the structure to WRW. When Rockware and WRW encountered financial difficulties and failed to respond adequately to Orders of the environmental regulators to remedy the situation, FG&E agreed to take steps at that time and obtained DEP approval to temporarily enclose, secure and stabilize the facility. Based on that approval, between September and December 1989, contractors retained by FG&E 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. 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. Those surveys revealed continued deterioration of the asbestos-containing insulation materials in the building. By letter dated May 1, 2002, the EPA notified FG&E that it was a Potentially Responsible Party for planned remedial activities at the site and invited FG&E to perform or finance such activities. FG&E and the EPA have entered into an Agreement of Consent, whereby FG&E, without an admission of liability, will conduct environmental remedial action to abate and remove asbestos-containing and other hazardous materials. FG&E has awarded contracts for all aspects of the abatement work, which is presently ongoing. FG&E received significant coverage from its insurance carrier. The Company believes that these funds will be sufficient to complete this remediation and that resolution of this matter will not have a material adverse impact on the Company's financial position. The Company has recorded the estimated cost of the remediation action in Current Liabilities and an offsetting asset reflecting insurance proceeds in Current Assets. At the balance sheet date, net of amounts expended in 2002, the remaining project cost was $3.7 million. 9 EMPLOYEES As of December 31, 2002, the Company and its subsidiaries had 316 full-time and part-time employees. The Company considers its relationship with its employees to be good and has not experienced any major labor disruptions since the early 1960's. There are approximately 100 employees represented by labor unions. In 2000, E&H reached a new five-year pact with its employees covered by a collective bargaining agreement, which will expire effective May 31, 2005. In 2000, CECo reached a new five-year pact with its employees covered by a collective bargaining agreement, which will expire effective May 31, 2005. In 2000, FG&E reached a five-year pact with its employees covered by collective bargaining agreements, which will expire effective May 31, 2005. The agreements provided for discreet salary adjustments, established work practices and provided uniform benefit packages. The Company expects to successfully negotiate new agreements prior to the expiration dates of these contracts. 10 EXECUTIVE OFFICERS OF THE REGISTRANT The names, ages and positions of all of the executive officers of the Company as of March 1, 2003 are listed below, along with a brief account of their business experience during the past five years. All officers are elected annually by the Board of Directors at the Directors' first meeting following the annual meeting, which is held on the third Thursday in April, or at a special meeting held in lieu thereof. There are no family relationships among these officers, nor is there any arrangement or understanding between any officer and any other person pursuant to which the officer was elected. Officers of the Company also hold various Director and Officer positions with subsidiary companies. Name, Age Business Experience and Position During Past 5 years ---------------------------------- ------------------------------------------ Robert G. Schoenberger, 52, Mr. Schoenberger has been Chairman of the Chairman of the Board of Directors Board and Chief Executive Officer of and Chief Executive Officer Unitil since 1997. Prior to his employment with Unitil, Mr. Schoenberger was President and Chief Operating Officer at New York Power Authority (NYPA) from 1993 until 1997. Michael J. Dalton, 62*, Mr. Dalton has been a Director, President President and and Chief Operating Officer of the Chief Operating Officer Company since its incorporation in 1984. Mark H. Collin, 44, Mr. Collin was appointed Senior Vice Senior Vice President and Chief President and Chief Financial Officer of Financial Officer Unitil in February 2003. Mr. Collin has been Treasurer of Unitil since January 1998. Mr. Collin has been Treasurer of Unitil's principal subsidiaries and Vice President of Unitil Service Corp. since 1992. George R. Gantz, 51 Mr. Gantz has been Senior Vice President Senior Vice President - Customer of Unitil Service since 1994. Services and Communications * Mr. Dalton has submitted his resignation from the Company, effective April 1, 2003. 11 Item 2. Properties UES maintains Distribution Operations Centers in the city of Concord and the town of Kensington. These properties are owned by UES in fee. UES's thirty electric distribution substations, including a 5,000 kVA mobile substation, constitute 214,270 kVA of capacity for the transformation of electric energy from the 34.5 kV subtransmission voltage to other primary distribution voltage levels. The electric substations are, with one exception, located on land owned by UES in fee. The sole exception is located on land occupied pursuant to a perpetual easement. UES has a total of approximately 1,535 pole miles of overhead electric distribution lines and a total of approximately 194 conduit bank miles of underground electric distribution lines. The electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by UES without objection by the owners. In the case of certain distribution lines, UES owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone and telegraph companies. Additionally, UES owns in fee 137.7 acres of land located on the east bank of the Merrimack River in the City of Concord. Of the total acreage, 81.2 acres are located within an industrial park zone, as specified in the zoning ordinances of the City of Concord. The physical properties of UES (with certain exceptions) and its franchises are subject to the lien of its Indenture of Mortgage and Deed of Trust under which the respective series of First Mortgage Bonds of UES are outstanding. FG&E owns a liquid propane gas plant and a liquid natural gas plant, both of which are located on land owned in fee. FG&E is participating, on a tenancy-in-common basis with other New England utilities, in the ownership of the Wyman 4 generating unit. In accordance with Massachusetts Electric Restructuring Law, and pursuant to the power supply divestiture discussed in Note 10 of the Financial Statements, FG&E began selling the output from its electric contracts and generation units on February 1, 2000. As of December 31, 2002, the electric properties of the Company consisted principally of 62 miles of transmission lines, 480.8 miles of distribution lines, 14 distinct transmission and distribution substations, and two mobile substations totaling 18.75 MVA. The in-service and spare capacity of these substations totals 561,900 kVA. Electric transmission facilities (including substations) and steel, cast iron and plastic gas mains owned by the Company are, with minor exceptions, located on land owned by the Company in fee or occupied pursuant to perpetual easements. The Company leases its service building. Unitil Realty owns the Company's corporate headquarters building and 12 acres of land in fee, which is located in the town of Hampton, New Hampshire. The Company believes that its facilities are currently adequate for its intended uses. Item 3. Legal Proceedings The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. In the opinion of the Company's management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company's financial position. Item 4. Submission of Matters to a Vote of Security Holders None 12 PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters The Registrant's Common Stock is traded on the American Stock Exchange. As of December 31, 2002, there were 1,932 Common Shareholders of record. Common Stock Data Dividends per Common Share 2002 2001 ------------------------------------------------------------------------------ 1st Quarter $ 0.345 $ 0.345 2nd Quarter 0.345 0.345 3rd Quarter 0.345 0.345 4th Quarter 0.345 0.345 ------------------------------- Total for Year $ 1.38 $ 1.38 =============================== 2002 2001 ---------------------------------------------- Price Range of Common Stock High/Ask Low/Bid High/Ask Low/Bid ------------------------------- ---------------------------------------------- 1st Quarter 26.80 22.82 27.00 24.90 2nd Quarter 31.40 26.10 27.50 24.75 3rd Quarter 29.22 25.31 25.45 23.00 4th Quarter 26.99 24.80 25.15 22.95 Information regarding Securities Authorized for Issuance Under Equity Compensation Plans is set forth on pages 15 through 16 of the 2002 Proxy Statement as filed with the Securities and Exchange Commission on March 12, 2003. 13 Item 6. Selected Financial Data
2002 2001 2000 1999 1998 ------------------------------------------------------------ Consolidated Statements of Earnings (000's) Operating Income $13,248 $14,394 $14,280 $15,408 $15,306 (Gain) Loss on Non-Utility Investments, net of tax (82) 2,400 ---- ---- ---- Other Non-operating Expense 185 170 244 51 156 ------------------------------------------------------------ Income Before Interest Expense and Extraordinary Item 13,145 11,824 14,036 15,357 15,150 Interest Expense, net 7,057 6,797 6,820 6,919 6,901 ------------------------------------------------------------ Income before Extraordinary Item 6,088 5,027 7,216 8,438 8,249 Extraordinary Item, net of tax --- 3,937 ---- ---- ---- ------------------------------------------------------------ Net Income 6,088 1,090 7,216 8,438 8,249 Dividends on Preferred Stock 253 257 263 268 274 ------------------------------------------------------------ Earnings Applicable to Common Shareholders 5,835 $833 $6,953 $8,170 $7,975 ============================================================ Balance Sheet Data (000's) Utility Plant (Original Cost) $271,179 $255,498 $238,023 $219,838 $209,462 Total Assets $480,783 $376,762 $382,967 $363,527 $376,835 Capitalization: Common Stock Equity $74,350 $74,746 $79,935 $78,675 $75,351 Preferred Stock 3,322 3,609 3,690 3,757 3,843 Long-Term Debt 104,226 107,470 81,695 86,157 75,222 ------------------------------------------------------------ Total Capitalization $181,898 $185,825 $165,320 $168,589 $154,416 ============================================================ Short-term Debt $35,990 $13,800 $32,500 $10,500 $20,000 Capital Structure Ratios: Common Stock Equity 34% 37% 40% 44% 43% Preferred Stock 2% 2% 2% 2% 2% Long-Term Debt 48% 54% 41% 48% 43% Short-Term Debt 16% 7% 17% 6% 12% Earnings Per-Share Data Basic Earnings Per Average Share $1.23 $0.18 $1.47 $1.74 $1.77 Diluted Earnings Per Average Share $1.23 $0.18 $1.47 $1.74 $1.72 Common Stock Data Shares of Common Stock (Year-End) (000's) 4,744 4,744 4,735 4,712 4,575 Shares of Common Stock (Average) (000's) 4,744 4,744 4,723 4,682 4,506 Dividends Paid Per Share (Year-End) $1.38 $1.38 $1.38 $1.38 $1.36 Book Value Per Share (Year-End) $15.67 $15.76 $16.88 $16.70 $16.47 Electric and Gas Statistics Electric Distribution Sales (000's of kWh) 1,659,136 1,596,390 1,587,536 1,608,824 1,540,968 Electric Customers (Year-End) 96,985 95,116 94,050 92,505 91,729 Firm Gas Distribution Sales (000's of Therms) 22,480 23,067 23,992 22,136 22,027 Gas Customers (Year-End) 14,911 14,879 14,796 14,928 14,915
14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Overview Unitil Corporation (Unitil or the Company) is nearing the completion of an unprecedented restructuring process brought about by the deregulation of the natural gas and electric industries in New Hampshire and Massachusetts. As a result, by the middle of 2003, the Company expects to have divested its entire generation and power supply portfolio, thus transforming the Company's vertically integrated utility operations into principally a pipes-and-wires business providing gas and electric delivery services. In the process, Unitil's distribution subsidiaries secured regulatory approval for the recovery of approximately a quarter billion dollars for all power supply related stranded costs, implemented comprehensive customer and financial information systems to accommodate the transition to competitive energy markets, and adjusted all utility delivery rates to reflect the overall cost of service as a restructured gas and electric energy delivery company. During this restructuring process, management's focus has been to ensure fair and reasonable treatment of the investments made to meet the needs of Unitil's customers, while at the same time making sure that the Company is properly structured from both a financial and an operational perspective to continue to provide high-quality and competitively priced electric and gas delivery services. Highlights of Year 2002: |_| On January 25, 2002, the Company's New Hampshire electric utility subsidiaries Concord Electric Company (CECo), Exeter & Hampton Electric Company (E&H) and Unitil Power Corp. (Unitil Power) filed a comprehensive electric restructuring proposal with the New Hampshire Public Utilities Commission (NHPUC). This proposal included the introduction of customer choice, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the combination of CECo and E&H into a single electric distribution utility, and new distribution rates for the combined entity. On October 25, 2002, the NHPUC approved a multi-party settlement on all the major issues in the proceeding. A key result of the New Hampshire restructuring settlement was the formation of Unitil Energy Systems, Inc. (UES) on December 2, 2002. UES is the New Hampshire distribution electric utility formed by the combination of CECo and E&H, and is a wholly-owned subsidiary of Unitil. UES received an increase of approximately $2.0 million in annual distribution revenue to cover current operating costs, depreciation and amortization, and investments in utility plant. These rates became effective December 1, 2002. |_| On May 17, 2002, the Company's Massachusetts distribution utility subsidiary, Fitchburg Gas and Electric Light Company (FG&E), filed revised rates with the Massachusetts Department of Telecommunications and Energy (MDTE) designed to increase annual base distribution revenues for both electric and gas operations to cover increases in operating expenses, depreciation and the cost of invested capital. On December 2, 2002, the MDTE authorized base rate changes to increase annual distribution revenues by $2.0 million for electric operations and $3.0 million for gas operations. In addition, increases for rising gas supply costs were incorporated into the final gas rates, effective December 2, 2002. |_| On October 15, 2002, the MDTE issued an Order approving a settlement agreement that resolved and secured the recovery of FG&E's restructuring-related stranded costs. The settlement resolves issues concerning FG&E's compliance with the Massachusetts Electric Restructuring Act of 1997 and related MDTE Orders. Under the settlement, FG&E agreed to reduce the carrying charge on deferred transition costs and to pass along the benefit of lower interest costs to customers. 15 |_| Unitil eliminated a major environmental liability associated with a former electric generating station in Fitchburg, Massachusetts. Under a consent Order voluntarily initiated by Unitil with the U.S. Environmental Protection Agency (EPA), a remedial project to clean up and remove asbestos and related hazardous materials from a building formerly owned by the Company is underway. Site remediation is expected to be completed at the end of 2003. Funds from an insurance settlement related to this issue are believed to be sufficient to complete the remediation work, such that this matter will not have a material effect on the Company's financial position. |_| In December 2002, FG&E and UES received regulatory approval to account for certain pension obligations as regulatory assets, avoiding a reduction in equity that would have been triggered by the substantial decline in the capital markets. These regulatory Orders do not pre-approve the amount of pension expense to be recovered in future rates. Such recovery will be subject to review and approval in future rate proceedings. |_| Unitil's non-regulated business, Usource, nearly doubled its revenues in 2002, as its electric and gas energy brokerage business continues to expand into new regions where large commercial and industrial customers are able to choose their energy suppliers. |_| In December 2002, Unitil committed to a formal management transition and reorganization plan to streamline its management structure and to improve efficiency to meet ongoing business requirements. The Company estimates this reorganization will result in an annual cash savings of approximately $2.3 million in operating expenses and construction project overheads in future periods. Earnings per Share 2002 2001 2000 -------------------------------------------------------------------------- Earnings per Share $ 1.23 $ 0.18 $ 1.47 Non-recurring Items, net of tax: Restructuring Charge (0.20) --- --- Investment Write-down --- (0.50) --- Extraordinary Item --- (0.83) --- ---------------------------------- Earnings Before Non-recurring Items $ 1.43 $ 1.51 $ 1.47 ================================== Earnings in 2002 were $5.8 million, or $1.23 per common share on a diluted basis, compared to $0.8 million, or $0.18 in 2001. Results for both years included significant non-recurring charges that affected earnings. In the fourth quarter of 2002, Unitil recorded a non-recurring Restructuring Charge of $1.6 million, or ($0.20) per share, associated with the reorganization and reduction of 19 management and administrative positions. The Company estimates that the result of this management restructuring process will be an annual cash savings in future periods of approximately $2.3 million in operating expenses and construction project overheads. In 2001, as a result of industry restructuring-related regulatory Orders, Unitil recognized an Extraordinary Item to reduce Regulatory Assets by $3.9 million after tax, or ($0.83) per share. Unitil also recorded an Investment Write-down of $2.4 million after-tax, or ($0.50) per share, to recognize a decrease in the fair value of a non-utility energy technology investment. Unitil subsequently sold its remaining interest in this non-utility investment in 2002 and realized $1.5 million in cash. As a result of this sale, the Company will also realize approximately $1.3 million in current tax refunds from the carryback of this capital loss. This sale transaction did not have a material impact on Unitil's 2002 operating results. Excluding the effect of these 2002 and 2001 non-recurring items, comparable earnings per share were $1.43 in 2002 and $1.51 in 2001. This decrease in earnings was mainly the result of increases in certain operating expenses, including higher pension and health care costs, higher depreciation expense associated with increased investments in Utility Plant, and accelerated amortization of certain Regulatory Assets. These impacts were partially offset by higher distribution base revenues. 16 A year-to-year comparison of Unitil's financial condition, changes in financial condition and results of operations for the three-year period 2000 through 2002 follows. RESULTS OF OPERATIONS Operating Revenue -- Electric Kilowatt-hour Sales - Unitil's total electric kilowatt-hour (kWh) sales increased by 3.9% in 2002 compared to 2001. This increase reflects growth in sales to residential and commercial and industrial customer classes driven by hotter-than-normal summer weather. Sales to residential customers increased by 3.9% in 2002 compared to 2001. The increase in energy sales reflects an increase in the number of residential customers as well as higher usage per customer, due to weather. Commercial and industrial sales of electricity also increased by 3.9% in 2002 compared to 2001. In addition, warmer summer weather in 2002 as compared to 2001 contributed to the increase in energy sales. Unitil's total electric kWh sales increased by 0.6% in 2001 compared to 2000. This increase reflected growth in sales to residential and commercial customer classes, offset by reductions in kWh sales to industrial customers, due to the impact of the general economic downturn experienced in 2001. The following table details total kWh sales for the last three years by major customer class: kWh Sales (000's) ------------------------------------------------------------------ 2002 2001 2000 --------------------------------------- Residential 619,756 596,378 576,524 Commercial/Industrial 1,039,380 1,000,012 1,011,012 --------------------------------------- Total 1,659,136 1,596,390 1,587,536 ======================================= Electric Operating Revenue - Electric Operating Revenue decreased by $16.5 million, or 9.0%, in 2002 compared to 2001. This decrease in revenue is the result of a reduction in wholesale commodity fuel prices overall and lower distribution rates in the Massachusetts service territory, offset by the increase in kWh sales. 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 2001, Electric Operating Revenue increased by $23.8 million, or 14.8%, as compared to 2000. This increase in revenue was the result of increased wholesale commodity fuel prices. The following table details total Electric Operating Revenue for the last three years by major customer class: Electric Operating Revenue (000's) ------------------------------------------------------------------ 2002 2001 2000 --------------------------------------- Residential $ 65,746 $ 71,960 $ 61,506 Commercial/Industrial 101,571 111,820 98,517 --------------------------------------- Total $ 167,317 $ 183,780 $ 160,023 ======================================= Operating Revenues - Gas Therm Sales - Total firm therm sales decreased 2.5% in 2002 compared to 2001, due to a warmer winter in early 2002 and the impact of the general economic downturn, partially offset by colder weather in the latter stages of 2002 compared to the prior year. 17 In 2001, total firm therm sales decreased 3.9% compared to 2000, primarily due to a warmer winter compared to the prior year and the impact of the general economic downturn. The following table details total firm therm sales for the last three years, by major customer class: Firm Therm Sales (000's) ------------------------------------------------------------------ 2002 2001 2000 --------------------------------------- Residential 11,022 11,175 11,730 Commercial/Industrial 11,458 11,892 12,262 --------------------------------------- Total 22,480 23,067 23,992 ======================================= Gas Operating Revenue - Gas Operating Revenue, which represents approximately 11% of Unitil's total Operating Revenues, decreased by $2.5 million, or 11.1%, in 2002 compared to 2001. This was attributable to lower unit sales and decreased wholesale gas commodity prices. The energy commodity component of Gas Operating Revenue represents the recovery of energy commodity supply costs, which are collected from customers through periodic cost recovery adjustment mechanisms. Changes in energy commodity supply revenues do not affect net income, as they normally mirror corresponding changes in energy commodity supply costs. In 2001, total Gas Operating Revenue was flat, as compared to 2000. This was attributable to lower unit sales, offset by higher gas supply prices. The following table details total Gas Operating Revenue for the last three years by major customer class: Gas Operating Revenue (000's) ------------------------------------------------------------------ 2002 2001 2000 --------------------------------------- Residential $ 10,871 $ 12,779 $ 11,540 Commercial/Industrial 8,007 9,505 8,745 --------------------------------------- Total Firm Gas Revenue 18,878 22,284 20,285 Interruptible Gas Revenue 1,405 544 2,471 --------------------------------------- Total $ 20,283 $ 22,828 $ 22,756 ======================================= Operating Revenue - Other Total Other Revenue increased $0.4 million, or 89.9%, compared to 2001. This was the result of growth in revenues from the Company's non-regulated energy brokering business, Usource. In 2001, total Other Revenue increased $0.3 million, compared to 2000. This was also the result of increased Usource brokerage fees. The following table details total Other Revenue for the last three years: Other Revenue (000's) ------------------------------------------------------------------ 2002 2001 2000 --------------------------------------- Usource $ 756 $ 384 $ 131 Other 30 30 31 --------------------------------------- Total $ 786 $ 414 $ 162 ======================================= 18 Operating Expenses Fuel and Purchased Power - 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, decreased $18.3 million, or 13.8%, in 2002 compared to 2001. The change was driven by a decrease in wholesale power prices, compared to the volatile markets and rising energy prices that the nation experienced in early 2001. In 2001, Fuel and Purchased Power expenses increased $22.7 million, or 20.6%, compared to 2000. This change was mainly due to increased wholesale power prices. Gas Purchased for Resale - 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 decreased by $2.7 million, or 19.4% in 2002 compared to 2001, reflecting a decrease in wholesale gas prices. In 2001, Gas Purchased for Resale increased by $0.3 million, or 2.5%, compared to 2000, due to a decrease in therms purchased, offset by higher wholesale gas prices in early 2001. Operation and Maintenance (O&M) - O&M expense includes electric and gas utility operating costs, and the operating cost of the Company's non-regulated business activities. Total O&M expense increased $0.7 million, or 2.7%, in 2002 compared to 2001, primarily due to higher employee and retiree health and pension costs. In 2001, total O&M expense increased $0.5 million, or 1.9%, compared to 2000, mainly due to higher utility system maintenance costs. Depreciation, Amortization and Taxes Depreciation and Amortization - Depreciation and Amortization expense increased $2.1 million, or 16.8%, in 2002 compared to 2001, due to a higher level of Utility Plant investments and the accelerated amortization of restructuring-related Regulatory Assets. In 2001, Depreciation and Amortization expense increased $0.8 million, or 6.7%, compared to 2000, due to a higher level of Utility Plant investments. Federal and State Income Taxes - Federal and State Income Taxes decreased $0.9 million, or 27.2%, in 2002 compared to 2001, due to lower pre-tax operating income in 2002 and the amortization in 2002 of deferred tax liabilities related to the accelerated write-off of Regulatory Assets. In 2001, Federal and State Income Taxes remained level compared to 2000. Local Property and Other Taxes -Local Property and Other Taxes increased $0.1 million, or 1.4%, in 2002 compared to 2001. This increase was related to a higher level of Utility Plant and higher tax rates, partially offset by the repeal of the State of New Hampshire Utility Franchise Tax. In 2001, Local Property and Other Taxes decreased $0.3 million, or 6.1%, compared to 2000. This decrease was related to the repeal of the State of New Hampshire Utility Franchise Tax, partially offset by higher property taxes. Interest Expense, net Interest expense is presented in the financial statements net of interest income. In 2002, Interest Expense, net, increased primarily due to the refinancing of lower cost short-term debt with higher cost long-term debt and additional borrowings to support the Company's capital requirements. Total interest expense was $9.3 million, $9.1 million and $8.6 million in 2002, 2001 and 2000, respectively, due to higher debt outstanding in those years. Interest income was $2.3 million, $2.3 million and $1.8 million in 2002, 2001 and 2000, respectively, reflecting higher interest earned on recoverable deferred asset balances related to industry restructuring. 19 Non-recurring Items 2002 Restructuring Charge - In the fourth quarter of 2002, the Company recognized a pre-tax Restructuring Charge of $1.6 million. The after-tax effect of the Restructuring Charge was a reduction of $0.20 in Earnings Per Common Share, assuming full dilution. In December 2002, the Company undertook a strategic review of its business operations and committed to a formal transition and reorganization plan (the Reorganization Plan) to streamline its management structure, in order to improve operating efficiency and to align the organization to meet ongoing business requirements. The Reorganization Plan resulted in the elimination of 19 management and administrative positions. As a result of the elimination of these positions, and consistent with existing Company policy, certain benefits are extended to the employees whose positions were eliminated. On January 8, 2003, the Company implemented the remainder of the Reorganization Plan. The Company estimates that the result of this management restructuring process will be an annual cash savings of approximately $2.3 million in operating expenses and construction project overheads. The $1.6 million pre-tax Restructuring Charge established a liability at December 31, 2002, to cover the disbursement of severance and employee benefits and related costs committed to under the Reorganization Plan, substantially all of which will be paid in fiscal 2003. At December 31, 2002, the Restructuring Charge of $1.6 million is included in Other Current Liabilities. 2001 Investment Write-down, net of tax - Beginning in 1998, Unitil invested $5.5 million in Enermetrix, Inc. (Enermetrix), an energy technology start-up enterprise. In accordance with Statement of Financial Accounting Standards (SFAS) No. 115 "Accounting for Certain Investments in Debt and Equity Securities," the Company recorded a non-cash charge of $3.7 million, or $2.4 million, net of tax, in the fourth quarter of 2001 to recognize the decrease in fair value of its non-utility investment in Enermetrix. On April 11, 2002, the Company sold its equity ownership in Enermetrix for $1.5 million in cash and improved commercial terms for use of the Enermetrix Software Network. As a result of the sale, in 2002, the Company recognized the benefit of approximately $1.3 million of this capital loss as a carryback against capital gains in its 2002 tax return. 2001 Extraordinary Item, net of tax - In November 1997, the Massachusetts Legislature enacted the Massachusetts Electric Restructuring Act of 1997 (the Restructuring Act). The Restructuring Act required all electric utilities to file a restructuring plan with the MDTE by December 31, 1997. 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 Restructuring Plan (the 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 FG&E'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 and 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 FG&E'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. 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 taxes. 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 after reconciliation, including the above-market or 20 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. Capital Requirements and Liquidity Unitil requires capital to fund the addition of property, plant and equipment to improve, protect, maintain and expand its electric and gas distribution systems and for working capital and other timing differences related to the collection of revenues in rates. 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, 2002, the Company had unsecured bank lines for short-term debt in the aggregate amount of $38 million with three banks. 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 (1935 Act) or by state regulators. In 2001, the Company received SEC authorization 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. In addition to the significant contractual obligations listed in the table below, the Company also 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 December 31, 2002, there are $1.8 million of guarantees outstanding and these guarantees extend through October 15, 2004.
Significant Contractual Obligations (000's) Total 2003 2004- 2006- 2008 & as of December 31, 2002 2005 2007 Beyond --------------------------------------------------------------------------------------------------------- Long-term Debt $ 107,469 $ 3,244 $ 3,551 $ 646 $ 100,028 Capital Lease 4,534 1,131 1,464 584 1,355 Power Supply Buyout - MA 81,526 7,276 14,758 15,202 44,290 Purchased Power Contract 99,246 12,619 30,871 26,277 29,479 Gas Supply Contract 6,653 2,123 2,284 2,002 244 ---------------------------------------------------------- Total Contractual Cash Obligations $ 299,428 $ 26,393 $ 52,928 $ 44,711 $ 175,396 ==========================================================
Cash Flows from Operating Activities - Cash Flows from Operating Activities decreased by $13.6 million in 2002, compared to 2001, mainly due to changes in Accrued Revenues and Accounts Receivable and Accounts Payable related to energy costs. 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 2002, the Company's cash flow is negatively impacted and additional working capital-related short-term borrowings are necessary. The balance of the decrease in 2002 was due to higher working capital needs, principally resulting from year-end timing differences on energy supply contract payments. In 2001, Cash Flows from Operating Activities increased by $14.3 million compared to 2000, mainly due to decreased Accrued Revenues and Accounts Receivable related to energy costs. During 2001, the Company collected revenue from rate reconciling mechanisms for higher energy costs incurred in 2000, and used this cash, in part, to pay down short-term debt borrowings. 21 Operating Activities (000's) --------------------------------------------------------------- 2002 2001 2000 ------------------------------------ $ 9,568 $ 23,178 $ 8,864 ==================================== Cash Flows from Investing Activities - Cash Used in Investing Activities decreased $0.3 million in 2002, compared to the prior year, primarily reflecting a $0.9 million increase in capital expenditures on distribution system additions and improvements, offset by the receipt of $1.5 million of proceeds from the sale of the Company's ownership interest in its non-utility investment. In addition, in 2001, Unitil received $0.3 million in proceeds from the sale of its interest in Millstone Nuclear Generating Station Unit No. 3 (Millstone 3). 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 ownership interest in Millstone 3, and the reduction of unregulated investment activities. Capital expenditures are projected to increase in 2003 to approximately $21.8 million, primarily reflecting increased expenditures for utility distribution system improvements. Investing Activities (000's) --------------------------------------------------------------- 2002 2001 2000 ------------------------------------ $ (19,290) $ (19,548) $ (22,249) ==================================== Cash Flows from Financing Activities - Cash Flows from Financing Activities increased by $11.4 million in 2002 compared to 2001. This increase primarily reflects increased short-term borrowings used to fund a significant portion of the Company's additions to gas and electric plant and equipment, as well as increased working capital requirements associated with recoverable deferred charges relating to industry restructuring. Cash Flows from Financing Activities decreased by $14.2 million in 2001 compared to 2000. This decrease primarily reflects repayment of short- and long-term borrowings, offset by proceeds received from the issuance of long-term debt. 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. 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. The Company also negotiated with its banks to increase its lines of credit to meet its borrowing obligations. The Company periodically files rate adjustments to its reconciling cost recovery mechanisms to reflect changes in wholesale energy prices. During 2001 the Company raised $0.3 million of additional common equity capital through the issuance of 11,279 shares of Common Stock in connection with the Dividend Reinvestment and Stock Purchase Plan (DRP). During 2001, the Company moved to open-market purchases to meet its share issuance obligations under the DRP. As a result, the Company did not issue new original shares of Common Stock in connection with the DRP during 2002, and does not anticipate doing so in 2003. 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, in 2001, the Company repurchased, canceled and retired 2,500 shares of its outstanding Common Stock at a total cost of $58,500. 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 2002 was $1.38 per share. This annual dividend resulted in a payout ratio of 97% for the year, before the non-recurring Restructuring Charge. Excluding the loss from Non-regulated Operations, the payout ratio was 88% based on Utility Operations, before the Restructuring Charge. At its January 2003 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. 22 Financing Activities (000's) ------------------------------------------------------------------- 2002 2001 2000 ---------------------------------------- $ 10,806 $ (614) $ 13,598 ======================================== Interest Rate Risk As discussed above, the Company meets it external financing needs by issuing short-term and long-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. The average interest rate on the Company's short-term borrowings was 2.18% and 4.78% during 2002 and 2001, respectively. Market Risk Although Until'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 purchased power and gas costs in rates. Consequently, there is limited commodity price risk after consideration of the related rate-making. Regulatory Matters The Unitil Companies are regulated by various federal and state agencies, including the SEC, the Federal Energy Regulatory Commission (FERC), and state regulatory authorities with jurisdiction over public utilities, including the NHPUC and the MDTE. 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 gas, while continuing to regulate the distribution operations of Unitil's utility operating subsidiaries. Unitil implemented the restructuring of its electric operations in Massachusetts in 1998 and is implementing a restructuring settlement for its New Hampshire electric operations that is expected to be on May 1, 2003. Massachusetts Electric Operations Restructuring - Beginning March 1, 1998, FG&E implemented its Restructuring Plan under the Massachusetts Restructuring Act. FG&E completed the divestiture of its entire regulated power supply business in 2000 in accordance with the Restructuring Plan. All FG&E distribution customers must pay a transition charge that provides for the recovery of costs associated with FG&E's power portfolio which were stranded as a result of the divestiture of those assets. The plant and Regulatory Asset balances that will be recovered through the transition charge have been approved by the MDTE as part of FG&E's annual Reconciliation Filings. The Restructuring Act also requires FG&E to obtain power for retail customers who choose not to buy energy from a competitive supplier through either Standard Offer Service (SOS) or Default Service. FG&E must provide SOS through February 2005 at rate levels which guarantee rate reductions required by the Restructuring Act. New distribution customers and customers no longer eligible for SOS are eligible to receive Default Service at prices set periodically based on market solicitations as approved by regulators. As of December 31, 2002, competitive suppliers were serving approximately 20% of FG&E's load, mainly for large industrial customers. 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, a nuclear generating unit. FG&E earns an authorized rate of return on the unamortized balance of these Regulatory Assets. In addition, as a result of the rate reduction and rate cap requirements of the Restructuring Act, FG&E has been authorized to defer the recovery of a portion of its transition costs and SOS costs. These unrecovered amounts are also recorded as Regulatory Assets and earn authorized carrying charges until their subsequent recovery in future periods. In 2002, Unitil's earnings derived from these generation-related 23 Regulatory Assets, including carrying charges earned on deferred transition costs and SOS costs, represented approximately 10% of net income. The value of FG&E's Regulatory Assets is approximately $128 million at December 31, 2002, and is expected to be amortized and recovered over the next three to nine years. Earnings from this segment of FG&E's utility business will continue to decline and ultimately cease. FG&E made a total of four Reconciliation Filings in 1999, 2000, 2001 and 2002. Rate adjustments were approved for effect during the subsequent year, subject to further investigation. In October 2001, the MDTE issued a final Order on FG&E's 1999 Reconciliation Filing which determined the final treatment of Regulatory Assets attributable to stranded generation costs, purchased power costs, and related expenses for the 1999, and future, Reconciliation Filings. FG&E's 2001 Reconciliation Filing, submitted on December 2, 2001, recast its rates from 1998 through 2001 in compliance with the MDTE's final Order on its 1999 filing. On October 15, 2002, the MDTE issued an Order approving a settlement agreement regarding the Company's 2001 filing. Under the approved settlement, FG&E agreed to reduce the carrying charge on deferred transition costs that will be recovered from customers in future years. This change does not affect current electric rates, but will reduce the total amount of transition costs, including carrying costs, in future years. The MDTE's October 2002 Order and associated settlement resolve many of the issues which otherwise might have been contested in FG&E's future Reconciliation Filings. FG&E submitted its 2002 Reconciliation Filing on December 20, 2002. Rate adjustments were approved for effect on January 1, 2003, subject to investigation, resulting in a rate reduction of approximately 4.4% for residential SOS customers. The reduction is due to a decrease in the SOS fuel adjustment, which is not subject to the rate cap, and does not affect net income. Massachusetts Gas Operations Restructuring - Following a three year state-wide collaborative process on the unbundling, or separation, of discrete services offered by natural gas local distribution companies (LDCs), the MDTE approved regulations and tariffs for FG&E and other LDCs to provide full customer choice effective November 1, 2000. The MDTE ruled that LDCs would continue to have an obligation to provide gas supply and delivery services for a five-year transition period, with a review after three years. This review is expected to be initiated in late 2003. The MDTE also required mandatory assignment of LDCs' pipeline capacity to competitive marketers supplying customers during the transition period. This mandatory capacity assignment protects LDCs from exposure to certain stranded gas supply costs during the transition period. New Hampshire Restructuring - On January 25, 2002, the Company's New Hampshire electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with the NHPUC. This proposal included the introduction of customer choice consistent with New Hampshire's electric utility industry restructuring law, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the merger of CECo and E&H into one distribution company and new distribution rates for the combined company. On October 25, 2002, the NHPUC approved a multi-party settlement on all major issues in the proceeding, including stranded cost recovery for purchased power contracts. The Company estimates that these recoverable stranded costs are approximately $94.5 million and these were recorded as Power Supply Buyout Obligations and Regulatory Assets at December 31, 2002. Under Unitil's approved restructuring plan, Unitil agreed to divest its existing power supply portfolio and conduct a solicitation for new power supplies from which to meet its ongoing Transition and Default Service energy obligations. On February 26, 2003, Unitil filed for final NHPUC approval of the executed agreements resulting from these divestiture and solicitation processes, including final tariffs for stranded cost recovery and Transition and Default Services. The filing proposed a recovery period of approximately eight years for stranded costs. The implementation of customer choice for UES customers is targeted for May 1, 2003. Unitil's restructuring plan is also designed to resolve the pending litigation on this matter. In June 1997, Unitil and other New Hampshire utilities intervened as plaintiffs in a suit filed in U.S. District Court by Northeast Utilities' affiliate Public Service Company of New Hampshire for protection from the NHPUC's Final Plan to restructure the New Hampshire electric utility industry. Although the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery, the NHPUC also made certain legal rulings, that, if implemented, could affect UES's long-term ability to recover all of its stranded costs. The Unitil Settlement, approved in October 2002, otherwise resolves all of the issues in the federal court action. Upon the expiration of all periods of appeal with respect to the restructuring proceeding by the NHPUC thereto, UES will implement retail choice and Unitil will withdraw its intervention in this federal court action, with prejudice. 24 Wholesale Power Market Restructuring - Unitil has also been a participant in the restructuring of the wholesale power market and transmission system in New England, which is subject to FERC jurisdiction. New wholesale markets structured pursuant to FERC's Standard Market Design are expected to be implemented in the New England Power Pool during the first half of 2003 under the general supervision of an Independent System Operator and the regulatory oversight of the FERC. Rate Proceedings - Prior to 2002, the last formal regulatory filings initiated by the Company to increase base rates for Unitil's retail electric operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. The last distribution base rate increase request for FG&E's retail gas operations occurred in 1998. In 2001, FG&E's electric base rates were investigated by the MDTE, which resulted in an electric base rate decrease. A majority of the Company's electric and gas operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, energy efficiency, and restructuring-related cost recovery mechanisms. 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, FG&E continues to provide a multi-year refund through its Cost of Gas Adjustment Clause in compliance with the MDTE's May 2001 Order finding that FG&E had over-collected fuel inventory finance charges. At December 31, 2002, the unamortized balance of this refund was $1.3 million. FG&E believes a refund is not justified or warranted and has appealed the MDTE's ruling to the Massachusetts Supreme Judicial Court (SJC). On a preliminary motion, a single justice of the SJC declined to stay the MDTE's Order based on a finding that refunds made by FG&E may be recouped if FG&E prevails on the merits of its claims. The review of the MDTE Order by the SJC is pending. On October 25, 2002, as part of the electric restructuring settlement for Unitil's New Hampshire utility operations described above, the Company received approval from the NHPUC for an increase of approximately $2.0 million in annual distribution revenues for UES, effective December 1, 2002. On December 2, 2002, the MDTE issued an Order resulting in distribution rate increases of $2.0 million for FG&E's electric operations and $3.0 million for FG&E's gas operations. Increases for rising gas costs were incorporated into the final gas rates. FG&E's new rates became effective on December 2, 2002. On April 16, 2002, FG&E filed Performance Based Regulation (PBR) Plans with the MDTE for both electric and gas operations. PBR is a method of setting regulated distribution rates that provides incentives 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. FG&E's PBR Plans were filed in conjunction with FG&E's distribution rate filings, consistent with MDTE policy to implement PBR in the context of base rate cases. The MDTE did not initiate investigations of the filings. On January 6, 2003, the MDTE issued Orders closing the cases. Accordingly, FG&E's PBR plans have no scheduled date of implementation, and conventional cost-based regulation continues to apply. In December 2002, FG&E and UES filed requests with their respective state regulatory commissions for approval of an accounting Order to mitigate certain accounting requirements related to pension plan assets, which have been triggered by the substantial decline in the capital markets. These requests were granted by the respective state regulatory commissions in December 2002. These approvals allow FG&E and UES to treat the additional minimum pension liability and Prepaid Pension Costs as Regulatory Assets and avoid the reduction in equity that would otherwise be required. These regulatory Orders do not pre-approve the amount of pension expense to be recovered in future rates. Such recovery will be subject to review and approval in future rate proceedings. Based on these approvals, Unitil has included the amount of the additional minimum pension liabilities and Prepaid Pension Costs of $12.0 million in Regulatory Assets on its balance sheet. Environmental Matters The Company's past and present operations include activities that are subject to extensive federal and state environmental regulations. Sawyer Passway MGP Site - The Company continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows the Company to work towards temporary remediation of the site. Work performed in 2002 was associated with the five-year review of 25 the Temporary Solution submittal (Class C Response Action Outcome) under the Massachusetts Contingency Plan that was filed for the site in 1997. Completion of this work has confirmed the Temporary Solution status of the site for an additional five years. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed. Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement). The Agreement allows FG&E to amortize and recover from gas customers over succeeding seven-year periods the environmental response costs incurred each year. Environmental response costs are defined to include liabilities related to manufactured gas sites, waste disposal sites or other sites onto which hazardous material may have migrated as a result of the operation or decommissioning of Massachusetts gas manufacturing facilities from 1882 through 1978. In addition, any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers. The total annual charge for such costs assessed to gas customers cannot exceed five percent of FG&E's total revenue for firm gas sales during the preceding year. Costs in excess of five percent will be deferred for recovery in subsequent years. Former Electric Generating Station - The Company is remediating 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 the time of the sale of the structure to WRW. When Rockware and WRW encountered financial difficulties and failed to respond adequately to Orders of the environmental regulators to remedy the situation, FG&E agreed to take steps at that time and obtained DEP approval to temporarily enclose, secure and stabilize the facility. Based on that approval, between September and December 1989, contractors retained by FG&E 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. 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 EPA, conducted further testing and survey work during 2001 to ascertain the environmental status of the building. Those surveys revealed continued deterioration of the asbestos-containing insulation materials in the building. By letter dated May 1, 2002, the EPA notified FG&E that it was a Potentially Responsible Party for planned remedial activities at the site and invited FG&E to perform or finance such activities. FG&E and the EPA have entered into an Agreement of Consent, whereby FG&E, without an admission of liability, will conduct environmental remedial action to abate and remove asbestos-containing and other hazardous materials. FG&E has awarded contracts for all aspects of the abatement work, which is presently ongoing. FG&E received significant coverage from its insurance carrier. The Company believes that these funds will be sufficient to complete this remediation and that resolution of this matter will not have a material adverse impact on the Company's financial position. The Company has recorded the estimated cost of the remediation action in Current Liabilities and an offsetting asset reflecting insurance proceeds in Current Assets. At the balance sheet date, net of amounts expended in 2002, the remaining project cost was $3.7 million. Critical Accounting Policies The preparation of the Company's financial statements in conformity with generally accepted accounting principles 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. Actual results could differ from those estimates. The following is a summary of the Company's most critical accounting policies, which are defined as 26 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 attached financial statements and Note 1: Summary of Significant Accounting Policies. Regulatory Accounting - The Company is a regulated utility and its principal business is the distribution of electricity and natural gas. 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 in future electric and gas retail rates. 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 Fuel and Purchased Power and Gas Purchased for Resale in the Consolidated Statements of Earnings and these costs are recoverable in current and future rates under various orders issued by state and federal regulators. 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 are not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. 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." For example, in 2002 the Company resolved a long standing contingency related to an environmental matter by entering into a fixed price contract to remediate the site while also settling on the funding of the project to be provided by the Company's insurance carrier. As a result, management estimates that this matter will not have a material adverse effect on the Company's financial position. Forward-Looking Information This report contains forward-looking statements which are subject to 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, interest rates, 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. Item 7A. Quantitative and Qualitative Disclosures about Market Risk Reference is made to the "Market Risk section of Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" (above). 27 Item 8. Financial Statements and Supplemental Data Report of Independent Certified Public Accountants 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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. We have also audited Schedule II for each of the three years in the period ended December 31, 2002. In our opinion, this schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information therein. /s/ GRANT THORNTON LLP Boston, Massachusetts February 7, 2003 28 CONSOLIDATED STATEMENTS OF EARNINGS (000's, except common shares and per share data)
----------------------------------------- Year Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------------------------ Operating Revenues: Electric $ 167,317 $ 183,780 $ 160,023 Gas 20,283 22,828 22,756 Other 786 414 162 ------------------------------------------- Total Operating Revenues 188,386 207,022 182,941 ------------------------------------------- Operating Expenses: Fuel and Purchased Power 114,598 132,947 110,280 Gas Purchased for Resale 11,143 13,827 13,492 Operation and Maintenance 25,667 25,000 24,545 Restructuring Charge 1,598 ---- ---- Depreciation and Amortization 14,911 12,767 11,964 Provisions for Taxes: Local Property and Other 4,731 4,666 4,967 Federal and State Income 2,490 3,421 3,413 ----------------------------------------- Total Operating Expenses 175,138 192,628 168,661 ----------------------------------------- Operating Income 13,248 14,394 14,280 Non-Operating Expenses: (Gain) Loss on Non-Utility Investments, (82) 2,400 ---- net of tax Other Non-Operating Expenses 185 170 244 ----------------------------------------- Income Before Interest Expense and Extraordinary Item 13,145 11,824 14,036 Interest Expense, net 7,057 6,797 6,820 ----------------------------------------- Income before Extraordinary Item 6,088 5,027 7,216 Extraordinary Item, net of tax ---- 3,937 ---- ----------------------------------------- Net Income 6,088 1,090 7,216 Less Dividends on Preferred Stock 253 257 263 ----------------------------------------- Earnings Applicable to Common Shareholders $ 5,835 $ 833 $ 6,953 ========================================= Average Common Shares Outstanding - Basic 4,743,696 4,743,576 4,723,171 Average Common Shares Outstanding - Diluted 4,762,166 4,759,822 4,742,745 Earnings per Common Share ------------------------------------------------------------------------------------------ Income before Extraordinary Item $ 1.23 $ 1.01 $ 1.47 Extraordinary Item, net of tax ---- (0.83) ---- ----------------------------------------- Net Income $ 1.23 $ 0.18 $ 1.47 =========================================
(The accompanying Notes are an integral part of these financial statements.) 29 CONSOLIDATED BALANCE SHEETS (000'S) ASSETS ---------------------------- December 31, 2002 2001 -------------------------------------------------------------------------------- Utility Plant: Electric $ 193,152 $ 183,795 Gas 44,796 41,287 Common 27,573 28,529 Construction Work in Progress 5,658 1,887 ---------------------------- Utility Plant 271,179 255,498 Less: Accumulated Depreciation 82,587 77,210 ---------------------------- Net Utility Plant 188,592 178,288 ---------------------------- Other Property and Investments 651 2,286 ---------------------------- Current Assets: Cash 7,160 6,076 Accounts Receivable - Net of Allowance for Doubtful Accounts of $372 and $600 19,513 17,133 Refundable Taxes 4,851 2,432 Material and Supplies 2,323 2,804 Prepayments 1,735 1,889 Accrued Revenue 4,842 1,330 ---------------------------- Total Current Assets 40,424 31,664 ---------------------------- Noncurrent Assets: Regulatory Assets 244,011 146,042 Prepaid Pension Costs ---- 10,712 Debt Issuance Costs, net 1,755 1,826 Other Noncurrent Assets 5,350 5,944 ---------------------------- Total Noncurrent Assets 251,116 164,524 ---------------------------- TOTAL $ 480,783 $ 376,762 ============================ (The accompanying Notes are an integral part of these financial statements.) 30 CONSOLIDATED BALANCE SHEETS (Cont.) (000'S) CAPITALIZATION AND LIABILITIES ---------------------------- December 31, 2002 2001 -------------------------------------------------------------------------------- Capitalization: Common Stock Equity $ 74,350 $ 74,746 Preferred Stock, Non-Redeemable, Non-Cumulative 225 225 Preferred Stock, Redeemable, Cumulative 3,097 3,384 Long-Term Debt, Less Current Portion 104,226 107,470 ---------------------------- Total Capitalization 181,898 185,825 ---------------------------- Current Liabilities: Long-Term Debt, Current Portion 3,243 3,224 Capitalized Leases, Current Portion 800 988 Accounts Payable 14,221 20,084 Short-Term Debt 35,990 13,800 Dividends Declared and Payable 77 109 Refundable Customer Deposits 1,336 1,393 Interest Payable 1,311 1,375 Other Current Liabilities 9,062 6,328 ---------------------------- Total Current Liabilities 66,040 47,301 ---------------------------- Deferred Income Taxes 47,332 47,113 Noncurrent Liabilities: Power Supply Buyout Obligations 175,657 88,779 Capitalized Leases, Less Current Portion 2,534 2,945 Other Noncurrent Liabilities 7,322 4,799 ---------------------------- Total Noncurrent Liabilities 185,513 96,523 ---------------------------- TOTAL $ 480,783 $ 376,762 ============================ (The accompanying Notes are an integral part of these financial statements.) 31 CONSOLIDATED STATEMENTS OF CAPITALIZATION (000's except number of shares and par value) ---------------------------- December 31, 2002 2001 -------------------------------------------------------------------------------- Common Stock Equity Common Stock, No Par Value $ 41,220 $ 41,220 (Authorized - 8,000,000 shares; Outstanding - 4,743,696 and 4,743,696 shares) Stock Options 990 669 Retained Earnings 32,140 32,857 ---------------------------- Total Common Stock Equity 74,350 74,746 ---------------------------- Preferred Stock UES Preferred Stock, Non-Redeemable, Non-Cumulative: 6.00% Series, $100 Par Value 225 225 UES Preferred Stock, Redeemable, Cumulative: 8.70% Series, $100 Par Value 215 215 5.00% Series, $100 Par Value --- 91 6.00% Series, $100 Par Value --- 168 8.75% Series, $100 Par Value 333 333 8.25% Series, $100 Par Value 385 385 FG&E Preferred Stock, Redeemable, Cumulative: 5.125% Series, $100 Par Value 946 960 8.00% Series, $100 Par Value 1,218 1,232 ---------------------------- Total Preferred Stock 3,322 3,609 ---------------------------- Long-Term Debt UES First Mortgage Bonds: Series I, 8.49%, Due October 14, 2024 6,000 6,000 Series J, 6.96%, Due September 1, 2028 10,000 10,000 Series K, 8.00%, Due May 1, 2031 7,500 7,500 Series L, 8.49%, Due October 14, 2024 9,000 9,000 Series M, 6.96%, Due September 1, 2028 10,000 10,000 Series N, 8.00%, Due May 1, 2031 7,500 7,500 FG&E Long-Term Notes: 8.55% Notes, Due March 31, 2004 6,000 9,000 6.75% Notes, Due November 30, 2023 19,000 19,000 7.37% Notes, Due January 15, 2029 12,000 12,000 7.98% Notes, Due June 1, 2031 14,000 14,000 Unitil Realty Corp. Senior Secured Notes: 8.00% Notes, Due August 1, 2017 6,469 6,694 ---------------------------- Total Long-Term Debt 107,469 110,694 Less: Long-Term Debt, Current Portion 3,243 3,224 ---------------------------- Total Long-Term Debt, Less Current Portion 104,226 107,470 ---------------------------- Total Capitalization $ 181,898 $ 185,825 ============================ (The accompanying Notes are an integral part of these financial statements.) 32 CONSOLIDATED STATEMENTS OF CASH FLOWS (000's)
----------------------------------------- Year Ended December 31, 2002 2001 2000 ------------------------------------------------------------------------------------------ Cash Flows from Operating Activities: Net Income $ 6,088 $ 1,090 $ 7,216 Adjustments to Reconcile Net Income to Cash Provided by Operating Activities: Depreciation and Amortization 14,911 12,767 11,964 Deferred Tax Provision 856 (607) 3,523 Noncash Stock Option Compensation Expenses 321 293 182 (Gain) Loss on Non-Utility Investments, net (82) 2,400 ---- Changes in Current Assets and Liabilities: Accounts Receivable (2,380) 2,924 (3,427) Prepayments and other Current Assets (960) (1,690) (2,393) Accrued Revenue (3,512) 7,973 (6,340) Accounts Payable (5,863) 1,545 2,024 Interest Payable and other Current Liabilities 2,670 366 (145) Other, net (2,481) (3,883) (3,740) ----------------------------------------- Cash Provided by Operating Activities 9,568 23,178 8,864 ----------------------------------------- Cash Flows from Investing Activities: Acquisitions of Property, Plant and Equipment (20,825) (19,890) (21,092) Proceeds from Sale of Electric Generation Assets ---- 342 ---- Proceeds (Acquisitions) on Investments, net 1,535 ---- (1,157) ----------------------------------------- Cash Used in Investing Activities (19,290) (19,548) (22,249) ----------------------------------------- Cash Flows from Financing Activities: Proceeds from (Repayment of) Short-Term Debt, net 22,190 (18,700) 22,000 Proceeds from Issuance of Long-Term Debt ---- 29,000 ---- Repayment of Long-Term Debt (3,225) (3,208) (1,255) Dividends Paid (6,831) (6,902) (6,787) Issuance of Common Stock, net ---- 229 639 Retirement of Preferred Stock (293) (81) (68) Repayment of Capital Lease Obligations (1,035) (952) (931) ----------------------------------------- Cash Provided by (Used In) Financing Activities 10,806 (614) 13,598 ----------------------------------------- Net Increase in Cash 1,084 3,016 213 Cash at Beginning of Year 6,076 3,060 2,847 ----------------------------------------- Cash at End of Year $ 7,160 $ 6,076 $ 3,060 ========================================= Supplemental Cash Flow Information: Interest Paid $ 9,356 $ 8,988 $ 8,640 Income Taxes Paid $ 2,351 $ 4,265 $ 827 Supplemental Schedule of Noncash Activities: Capital Leases Incurred $ 436 $ 691 $ 363
(The accompanying Notes are an integral part of these financial statements.) 33 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (000's except number of shares)
Common Stock Option Retained Shares Plan Earnings Total ----------------------------------------------------- Balance at January 1, 2000 $ 40,352 $ 194 $ 38,129 $ 78,675 Net Income for 2000 7,216 7,216 Dividends on Preferred Shares (263) (263) Dividends on Common Shares - at $1.38 per Share (6,514) (6,514) Stock Option Plan 182 182 Issuance of 22,916 Common Shares (a) 639 639 ----------------------------------------------------- Balance at December 31, 2000 40,991 376 38,568 79,935 Net Income after Extraordinary Item for 2001 1,090 1,090 Dividends on Preferred Shares (257) (257) Dividends on Common Shares - at an Annual Rate of $1.38 per Share (6,544) (6,544) Stock Option Plan 293 293 Issuance of 11,279 Common Shares (a) 287 287 Re-acquired and retired Common Shares (b) (58) (58) ----------------------------------------------------- Balance at December 31, 2001 41,220 669 32,857 74,746 Net Income for 2002 6,088 6,088 Dividends on Preferred Shares (253) (253) Dividends on Common Shares - at $1.38 per Share (6,546) (6,546) Stock Option Plan 321 321 Premium paid for redemption of Preferred Shares (c) (6) (6) ----------------------------------------------------- Balance at December 31, 2002 $ 41,220 $ 990 $ 32,140 $ 74,350 =====================================================
(a) Shares sold and issued in connection with the Company's Dividend Reinvestment and Stock Purchase Plan and Employee 401(k) Tax Deferred Savings and Investment Plan. (b) Shares repurchased in conjunction with the Company's interim stock repurchase program. (c) Premium paid for the redemption of Exeter & Hampton Electric Company Preferred Shares. (The accompanying Notes are an integral part of these financial statements.) 34 Note 1: Summary of Significant Accounting Policies Nature of Operations - Unitil Corporation (Unitil or the Company) is registered with the Securities and Exchange Commission (SEC) as a public utility holding company under the Public Utility Holding Company Act of 1935 (1935 Act). The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (UES) (formed in 2002 by the combination and merger of Unitil's former utility subsidiaries Concord Electric Company (CECo) and Exeter & Hampton Electric Company (E&H)), Fitchburg Gas and Electric Light Company (FG&E), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource, Inc. and Usource L.L.C. are subsidiaries of Unitil Resources. Unitil's principal business is the retail sale and distribution of electricity and related services in several cities and towns in the seacoast and capital city areas of New Hampshire, and both electricity and gas and related services in north central Massachusetts, through Unitil's two wholly-owned retail distribution utility subsidiaries. The Company's wholesale electric power utility subsidiary, Unitil Power, principally provides all the electric power supply requirements to UES for resale at retail. Unitil Realty owns and manages the Company's corporate office building and property located in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Service provides, at cost, centralized management, administrative, accounting, financial, engineering, information systems, regulatory, planning, procurement and other services to its affiliated Unitil companies. Unitil Resources is the Company's wholly-owned non-utility subsidiary and has been authorized by the SEC, pursuant to the rules and regulations of the 1935 Act, to engage in competitive business transactions associated with electricity, gas and other energy commodities in wholesale and retail markets, and to provide energy brokering, consulting and management related services within the United States. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly owned subsidiaries of Unitil Resources. Usource provides competitive energy brokering services, as well as related energy consulting services. With respect to rates and other business and financial matters, UES is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC), FG&E is regulated by the Massachusetts Department of Telecommunications & Energy (MDTE), and Unitil Power, UES and FG&E are regulated by the Federal Energy Regulatory Commission (FERC). Basis of Presentation Principles of Consolidation - The consolidated financial statements include the accounts of Unitil and all of its wholly-owned subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation. Regulatory Accounting - Generally Accepted Accounting Principles for regulated entities in the United States allow Unitil to give accounting recognition to the actions of regulatory authorities in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In accordance with SFAS No. 71, the Company has recognized future cash inflows that will result from the ratemaking process (a Regulatory Asset) or has recognized obligations (a Regulatory Liability) if it is probable that such costs will be recovered or obligations relieved in the future through the ratemaking process. In addition to the Regulatory Assets and Liabilities separately identified on the Consolidated Balance Sheet, there are other regulatory assets and liabilities, such as accrued revenues associated with reconciling cost recovery mechanisms and certain deferred tax liabilities recovered through the ratemaking process. The Company also has obligations under long-term power contracts, the recovery of which is subject to regulation. 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 are not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. Massachusetts and New Hampshire have both passed utility industry restructuring legislation and the Company has filed and implemented its restructuring plans in both states. In Massachusetts, the Company is allowed to recover certain types of costs through ongoing assessments to be included in future regulated service rates. The Company is also deferring the recovery of certain restructuring related costs in order to meet the retail rate cap imposed under the Massachusetts restructuring legislation. Based on the recovery mechanism that allows 35 recovery of all of its stranded costs and deferred costs related to restructuring, the Company has recorded regulatory assets that it expects to fully recover in future periods. The Company expects to continue to meet the criteria for the application of SFAS No. 71 for the distribution portion of its assets and operations for the foreseeable future. If a change in accounting were to occur to the distribution portion of the Company's operations, it could have a material adverse effect on the Company's earnings and retained earnings in that year and could have a material adverse effect on the Company's ongoing financial condition as well. On January 25, 2002, the Company's New Hampshire electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with the NHPUC. This proposal included the introduction of customer choice consistent with the New Hampshire restructuring law, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the combination of CECo and E&H into a planned successor, UES, and new distribution rates for UES. On October 25, 2002, the NHPUC approved a multi-party settlement on all major issues in the proceeding. Under Unitil's approved restructuring plan, Unitil will divest its existing New Hampshire power supply portfolio and conduct a solicitation for new power supplies from which to meet its ongoing transition and default service energy obligations. In early 2003, Unitil will file for final NHPUC approval of the executed agreements resulting from these divestiture and solicitation processes, including final tariffs for stranded cost recovery and transition and default services. The implementation of customer choice is targeted for May 1, 2003. Upon receipt of all requested approvals in the proceeding by the NHPUC, and the expiration of all periods of appeal with respect thereto, UES will implement retail choice and Unitil will withdraw its intervention in a pending federal court action, with prejudice. In June 1997, Unitil and other utilities in NH intervened as plaintiffs in a suit filed in U.S. District Court by Northeast Utilities' affiliate Public Service Company of New Hampshire for protection from the NHPUC Final Plan to restructure the New Hampshire electric utility industry. Although the NHPUC found that CECo and E&H were entitled to full interim stranded costs recovery, the NHPUC also made certain legal rulings, that, if implemented, could affect the Company's long-term ability to recover all of their stranded costs. The Unitil Settlement approved in October 2002, provides for full stranded cost recovery by UES, and otherwise resolves all of the issues in the federal court action. Asset Balances at December 31, Regulatory Assets consist of the following (000's) 2002 2001 ----------------------------------------------------------------------- Power Supply Buyout Obligations $ 175,657 $ 88,779 Income Taxes 24,799 27,386 Recoverable Deferred Charges 22,253 18,103 Recoverable Generation-related Assets 9,327 11,774 Pension 11,975 ---- ------------------------ Total Regulatory Assets $ 244,011 $ 146,042 ======================== Use of Estimates - The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and requires disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Revenue Recognition - Unitil's operating subsidiaries record electric and gas operating revenues based upon the amount of electricity and gas delivered to customers through the end of the accounting period. Usource, Unitil's competitive energy brokering subsidiary, records energy brokering revenues based upon the estimated amount of electricity and gas delivered to customers through the end of the accounting period. Utility Plant - The cost of additions to Utility Plant and the cost of renewals and betterments are capitalized. Cost consists of labor, materials, services and certain indirect construction costs, including an allowance for funds used during construction (AFUDC). The costs of current repairs and minor replacements are charged to appropriate operating expense accounts. The original cost of utility plant retired or otherwise disposed of and the cost of removal, less salvage, are charged to the accumulated provision for depreciation. Depreciation and Amortization - Depreciation provisions for Unitil's utility operating subsidiaries are determined on a group straight-line basis. Provisions for depreciation were equivalent to the following composite rates, based 36 on the average depreciable property balances at the beginning and end of each year: 2002 - 3.79%, 2001 - 3.75% and 2000 - 3.74%. Amortization provisions include the recovery of a portion of FG&E's former investment in Seabrook Station, a nuclear generating unit, in rates to its customers through the Seabrook Amortization Surcharge as ordered by the MDTE. In addition, FG&E is amortizing the balance of its unrecovered electric generating related assets, which are recorded as Regulatory Assets, in accordance with its electric restructuring plan approved by the MDTE (See Note 15). Stock-based Employee Compensation - Unitil accounts for stock-based employee compensation currently using the fair value based method (See Note 5). Federal Income Taxes - Deferred tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and are measured by applying tax rates applicable to the taxable years in which those differences are expected to reverse. The Tax Reduction Act of 1986 eliminated investment tax credits. Investment tax credits generated prior to 1986 are being amortized, for financial reporting purposes, over the productive lives of the related assets. Newly Issued Pronouncements - On June 29, 2001, the Financial Accounting Standards Board (FASB) approved for issuance SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." Significant provisions of these statements are as follows: all business combinations initiated after June 30, 2001, must use the purchase method of accounting; goodwill and intangible assets with indefinite lives are not amortized but are tested for impairment annually using a fair value approach; other intangible assets will continue to be valued and amortized over their estimated lives. The Company has no goodwill recorded at December 31, 2002 and 2001. As a result, the adoption of these statements did not have any impact on the Company's financial position or results of operations. The merger of the Company's two New Hampshire utility subsidiaries, CECo and E&H, into UES in December 2002 was the combination of entities under the common control of Unitil Corporation and therefore all of the accounts of these businesses were combined at their historical cost. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which establishes new accounting and reporting standards for legal obligations associated with retiring tangible long-lived assets. The fair value of a liability for an asset retirement obligation must be recorded in the period in which it is incurred, with the cost capitalized as part of the related long-lived asset and depreciated over the asset's useful life. SFAS No.143 must be adopted by 2003. The Company currently accounts for all of the costs of its long lived-assets, including the cost of removal to replace these assets, in accordance with Generally Accepted Accounting Principles and guidelines published by the FERC for Utility plant accounting. The Company has no ownership interest in nuclear power plants, and no decommissioning obligations. The Company has determined that the adoption of this statement will not have a material adverse impact on the Company's financial position or results of operations. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that an impairment loss should be recognized if the carrying value of the asset is not recoverable from its undiscounted cash flows. The statement is effective for fiscal years beginning after December 15, 2001, with early adoption permitted. The Company has determined that the adoption of this statement will not have a material adverse impact on the Company's financial position or results of operations. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. The Company initiated a reorganization of management and administrative positions in the fourth quarter of 2002 and recognized a Restructuring Charge, discussed below, under the provisions of Emerging Issues Task Force (EITF) Issue No. 94-3, the predecessor standard to SFAS 146. In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure." SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value-based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method on reported results. The Company recognizes compensation cost at fair value at the date of grant. 37 Also in 2002, the FASB issued Interpretation 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Under FIN 45 guarantors are required to measure and recognize the fair value of guarantees at inception and provide new disclosures regarding the nature of any guarantees. FIN 45 is effective for financial statements of reporting periods ending after December 15, 2002. The Company has adopted the provisions of FIN 45. Reclassifications - Certain amounts previously reported have been reclassified to conform to current year presentation. Note 2: Restructuring Charge - 2002 In the fourth quarter of 2002, Unitil recognized a pre-tax Restructuring Charge of $1.6 million. The after-tax effect of the Restructuring Charge was a reduction of $0.20 in Earnings per Common Share, assuming full dilution. In December 2002, the Company undertook a strategic review of its business operations and committed to a formal transition and reorganization plan (the Reorganization Plan) to streamline its management structure, in order to improve operating efficiency and to align the organization to meet ongoing business requirements. The Reorganization Plan resulted in the elimination of 19 management and administrative positions. As a result of the elimination of these positions, and consistent with existing Company policy, certain benefits are extended to the employees whose positions were eliminated. On January 8, 2003, the Company implemented the Reorganization Plan. The $1.6 million pre-tax Restructuring Charge established a liability at December 31, 2002, to cover the disbursement of severance and employee benefits and related costs committed to under the Reorganization Plan, substantially all of which will be paid in fiscal 2003. At December 31, 2002, the Restructuring Charge of $1.6 million is included in Other Current Liabilities. Note 3: Extraordinary Item - 2001 In November 1997, the Massachusetts Legislature enacted the Massachusetts Electric Restructuring Act of 1997 (the Restructuring Act). The Restructuring Act required all electric utilities to file a restructuring plan with the MDTE by December 31, 1997. 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 Restructuring Plan (the 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 FG&E'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 and 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 FG&E'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. 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 taxes. The Company recognized the extraordinary charge of $0.83 per share, as of September 30, 2001. 38 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, after reconciliation, 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. Note 4: Investment Write-down and Sale of Equity Stake in Enermetrix - 2001 Beginning in 1998, Unitil invested $5.5 million in Enermetrix, Inc. (Enermetrix), an energy technology start-up enterprise. In accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," the Company recorded a non-cash charge of $3.7 million, or $2.4 million, net of tax, in the fourth quarter of 2001 to recognize the decrease in fair value of its non-utility investment in Enermetrix. On April 11, 2002, the Company sold its equity ownership in Enermetrix for $1.5 million in cash and improved commercial terms for use of the Enermetrix Software Network. As a result of the sale, in 2002, the Company recognized the benefit of approximately $1.3 million of this capital loss as a carryback against capital gains in its 2002 tax return. Note 5: Common Stock New Shares Issued - During 2002, Unitil did not issue any additional shares of its common stock. The Company raised $287,142 and $639,000 of additional common equity capital through the issuance of 11,279 and 22,916 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase Plan (DRP) during 2001 and 2000, respectively. The DRP provides participants in the plan a method for investing cash dividends on the Company's Common Stock and cash payments in additional shares of the Company's Common Stock. Shares Repurchased, Cancelled and Retired - During 2002, Unitil did not repurchase, cancel and retire any of its common stock. During 2001, in conjunction with the SEC's 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 used its cash on hand to repurchase, cancel and retire 2,500 shares of its outstanding Common Stock at a total cost of $58,500. 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. Stock-Based Compensation Plans - Unitil maintains two stock option plans, which provide for the granting of options to key employees. Details of the plan are as follows: Unitil Corporation Key Employee Stock Option Plan - The "Unitil Corporation Key Employee Stock Option Plan" was a 10-year plan which began in March 1989. The number of shares granted under this plan, as well as the terms and conditions of each grant, were determined by the Key Employee Stock Option Plan Committee of the Board of Directors, subject to plan limitations. All options granted under this plan vested upon grant. The 10-year period in which options could be granted under this plan expired in March 1999. The expiration date of the remaining outstanding options is November 3, 2007. The plan provides dividend equivalents on options granted, which are recorded at fair value as compensation expense. The total compensation expenses recorded by the Company with respect to this plan were $43,000, $42,000 and $38,000 for the years ended December 31, 2002, 2001 and 2000, respectively. 39 Share Option Activity of the "Unitil Corporation Key Employee Stock Option Plan" is presented in the following table:
2002 2001 2000 ------------------------------------------------ Beginning Options Outstanding and Exercisable 30,996 29,358 27,976 Dividend Equivalents Earned 1,649 1,638 1,382 Options Exercised ---- ---- ---- ------------------------------------------------ Ending Options Outstanding and Exercisable 32,645 30,996 29,358 ================================================ Range of Option Exercise Price per Share $12.11-$18.28 $12.11-$18.28 $12.11-$18.28 Weighted Average Remaining Contractual Life 4.9 years 5.9 years 6.9 years
Unitil Corporation 1998 Stock Option Plan - The "Unitil Corporation 1998 Stock Option Plan" became effective on December 11, 1998. The number of shares granted under this plan, as well as the terms and conditions of each grant, are determined by the Compensation Committee of the Board of Directors, subject to plan limitations. All options granted under this plan vest over a three-year period from the date of the grant, with 25% vesting on the first anniversary of the grant, 25% vesting on the second anniversary, and 50% vesting on the third anniversary. Under the terms of this plan, key employees may be granted options to purchase the Company's Common Stock at no less than 100% of the market price on the date the option is granted. All options must be exercised no later than 10 years after the date on which they were granted. The total compensation expenses recorded by the Company with respect to this plan were $278,000, $251,000 and $144,000 for the years ended December 31, 2002, 2001 and 2000, respectively.
2002 2001 2000 ------------------------------------------------------------------------- Average Average Average Number of Exercise Number of Exercise Number of Exercise Shares Price Shares Price Shares Price ------------------------------------------------------------------------- Beginning Options Outstanding 172,500 $ 26.99 113,500 $ 27.64 62,000 $ 23.38 Options Granted ---- ---- 60,000 $ 25.88 55,000 $ 32.18 Options Forfeited ---- ---- (1,000) $ 33.56 (3,500) $ 23.38 ------------------------------------------------------------------------- Ending Options Outstanding 172,500 $ 26.99 172,500 $ 26.99 113,500 $ 27.64 ========================================================================= Options Vested and Exercisable- end of year 100,500 $ 26.11
The Company has adopted SFAS No. 123, "Accounting for Stock Based Compensation," and recognizes compensation costs at fair value at the date of grant. The following summarizes certain data for options outstanding at December 31, 2002:
Weighted Options Weighted Range of Options Average Vested and Average Remaining Exercise Prices Outstanding Exercise Price Exercisable Exercise Price Contractual Life $20.00-$24.99 58,500 $23.38 58,500 $23.38 6.2 years $25.00-$29.99 60,000 $25.88 15,000 $25.88 8.1 years $30.00-$34.99 54,000 $32.15 27,000 $32.15 7.1 years ------------- ----------- 172,500 100,500 ============= ===========
40 There were no options granted during 2002. The weighted average fair value per share of options granted during 2001 and 2000 was $4.66 and $7.13, respectively. The fair value of options at the date of grant was estimated using the Black-Scholes model with the following weighted average assumptions: 2002 2001 2000 ------------------------------------- Expected Life (years) N/A 10.0 10.0 Interest Rate N/A 5.8% 6.0% Volatility N/A 23.6% 22.3% Dividend Yield N/A 5.3% 4.3% Restrictions on Retained Earnings - Unitil Corporation has no restriction on the payment of common dividends from retained earnings. Its two retail distribution subsidiaries, UES and FG&E, do have restrictions. Under the terms of the First Mortgage Bond Indentures, UES had $9,313,000 available for the payment of cash dividends on its Common Stock at December 31, 2002. Under the terms of long-term debt purchase agreements, FG&E had $5,144,000 of retained earnings available for the payment of cash dividends on its Common Stock at December 31, 2002. In addition, under the terms of the NHPUC's Order in Docket DE 01-247, UES' ability to issue dividends on its common stock is restricted to an annual maximum of $1,794,000. This restriction will remain in place until UES files its next base rate case with the NHPUC, which UES is required to file within the next five years. Note 6: Preferred Stock Unitil's two distribution operating subsidiaries, UES and FG&E, have redeemable Cumulative Preferred Stock outstanding and one subsidiary, UES, has a Non-Redeemable, Non-Cumulative Preferred Stock issue outstanding. These subsidiaries are required to offer to redeem annually a given number of shares of each series of Redeemable Cumulative Preferred Stock and to purchase such shares that shall have been tendered by holders of the respective stock. All such subsidiaries may redeem, at their option, the Redeemable Cumulative Preferred Stock at a given redemption price, plus accrued dividends. The aggregate purchases of Redeemable Cumulative Preferred Stock during 2002, 2001 and 2000 related to the annual redemption offer were $34,500, $81,000 and $67,500, respectively. The aggregate amount of sinking fund requirements of the Redeemable Cumulative Preferred Stock for each of the five years following 2002 are $192,000 per year. Also, during 2002, in conjunction with the merger of E&H into CECo to form UES, the 5% and 6% series of Redeemable Cumulative Preferred Stock were fully-redeemed at par plus premiums of 2% and 3%, respectively. These redemptions and related premiums resulted in an aggregate expenditure of $258,720. Note 7: Long-Term Debt and Interest Expense Substantially all the property and franchises of Unitil's utility operating subsidiaries are subject to liens of indenture under which First Mortgage bonds have been issued. Certain of the Company's long-term debt agreements contain provisions which, among other things, limit the incursion of additional long-term debt. Total aggregate amount of sinking fund payments relating to bond issues and normal scheduled long-term debt repayments amounted to $3,225,444, $3,208,000 and $1,254,946 in 2002, 2001 and 2000, respectively. The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 2002 is: 2003 - $3,244,156, 2004 - $3,264,421, 2005 - $286,368, 2006 - $310,136 and 2007 - $335,877. 41 The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. In management's opinion, the carrying value of the debt approximated its fair value at December 31, 2002 and 2001. The Company also 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 December 31, 2002, there are $1.8 million of guarantees outstanding and these guarantees extend through October 15, 2004. Interest Expense, net - Interest expense is presented in the financial statements, net of Interest Income. In 2002, Interest Expense, net, increased primarily due to the refinancing of lower cost short-term debt with higher cost long-term debt and additional borrowings to support the Company's capital requirements. Total interest expense was $9.3 million, $9.1 million and $8.6 million in 2002, 2001 and 2000, respectively, and increased due to higher debt outstanding in each of those years. Interest income was $2.3 million, $2.3 million and $1.8 million in 2002, 2001 and 2000, respectively, primarily reflecting interest earned on recoverable deferred charge balances related to industry restructuring. Note 8: Credit Arrangements At December 31, 2002, Unitil had unsecured committed bank lines for short-term debt in the aggregate amount of $38.0 million with three banks for which it pays commitment fees. The weighted average interest rates on all short-term borrowings were 2.18%, 4.78% and 6.57% during 2002, 2001 and 2000, respectively. Note 9: Leases Unitil's subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery and office equipment. FG&E had a 22-year facility lease in which the Primary Term was scheduled to end on January 31, 2003. On February 1, 2002, a 10-year Extended Term commenced extending the lease term through February 2012. Furthermore, the amended lease agreement allows for three additional five-year renewal periods at the option of FG&E. In addition, Unitil's subsidiaries lease some equipment under operating leases. The following is a schedule of the leased property under capital leases by major classes: Asset Balances at December 31, Classes of Utility Plant (000's) 2002 2001 -------------------------------------------------------------------- Common Plant $ 7,095 $ 7,146 Less: Accumulated Depreciation 3,761 3,213 ---------------------------- Net Plant $ 3,334 $ 3,933 ============================ The following is a schedule by years of future minimum lease payments and present value of net minimum lease payments under capital leases, as of December 31, 2002: Year Ending December 31, (000's) -------------------------------------------------------------------- 2003 $ 1,130 2004 862 2005 602 2006 310 2007 274 2008 - 2012 1,356 ------------ Total Minimum Lease Payments $ 4,534 Less: Amount Representing Interest 1,200 ------------ Present Value of Net Minimum Lease Payments $ 3,334 ============ Total rental expense charged to operations for the years ended December 31, 2002, 2001 and 2000 amounted to $4,000, $12,000 and $21,000, respectively. There are no material future operating lease payment obligations at December 31, 2002. 42 Note 10: Income Taxes Federal Income Taxes were provided for the following items for the years ended December 31, 2002 2001and 2000, respectively:
2002 2001 2000 --------------------------------------- Current Federal Tax Provision (Benefit) (000's): Operating Income $ 1,960 $ 3,566 $ (9) Amortization of Investment Tax Credits (51) (153) (256) --------------------------------------- Total Current Federal Tax Provision (Benefit) 1,909 3,413 (265) --------------------------------------- Deferred Federal Tax Provision (Benefit) (000's) Accelerated Tax Depreciation 68 (401) 183 Abandoned Properties (705) (767) (863) Accrued Revenue 1,118 691 3,604 Allowance for Funds Used During Construction (32) (42) (48) Post Retirement Benefits Other Than Pensions (38) (34) (29) Deferred Pensions 86 89 275 Regulatory Assets and Liabilities 70 37 (186) Deferred Gain on Sale of New Haven Harbor ---- ---- 125 Contributions in Aid of Construction (231) (251) (106) Difference in Prior Year Taxes as Filed 72 312 149 Other (119) (197) (38) --------------------------------------- Total Deferred Federal Tax Provision (Benefit) 289 563 3,066 --------------------------------------- Total Federal Tax Provision $ 2,198 $ 2,850 $ 2,801 =======================================
The components of the Federal and State income tax provisions reflected as operating expenses in the accompanying consolidated statements of earnings for the years ended December 31, 2002, 2001 and 2000 were as follows:
Federal and State Tax Provisions (000's) 2002 2001 2000 --------------------------------------------------------------------------------------------- Federal Current $ 1,960 $ 3,566 $ (9) Deferred 289 (563) 3,066 Amortization of Investment Tax Credits (51) (153) (256) --------------------------------------- Total Federal Tax Provision 2,198 2,850 2,801 --------------------------------------- State Current (275) 615 155 Deferred 567 (44) 457 --------------------------------------- Total State Tax Provision 292 571 612 --------------------------------------- Federal and State Income Taxes - Operating Expenses $ 2,490 $ 3,421 $ 3,413 =======================================
In 2001, the Company provided for a deferred tax benefit of $1.3 million on the capital loss from the write-down of its investment in Enermetrix. The Company recognized the benefit in 2002 of this capital loss as a carryback against capital gains in its tax return. Also in the third quarter of 2001, the Company recorded a deferred tax benefit of $1.4 million as adjustments to deferred taxes recognized when the Company recorded the extraordinary item. 43 The differences between the Company's provisions for Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below: 2002 2001 2000 ----------------------------------- Statutory Federal Income Tax Rate 34% 34% 34% Income Tax Effects of: State Income Taxes, Net 2 4 4 Investment Tax Credits (1) (1) (2) Abandoned Property (8) (6) (6) Other, Net 2 (1) 2 ----------------------------------- Effective Income Tax Rate 29% 30% 32% =================================== Temporary differences which gave rise to deferred tax assets and liabilities are shown below: Deferred Income Taxes (000's) 2002 2001 --------------------------------------------------------------------- Accelerated Depreciation $ 24,140 $ 24,020 Abandoned Property 2,547 4,845 Contributions in Aid of Construction (3,654) (3,360) Percentage Repair Allowance 2,038 2,165 Retirement Loss - Plant Assets 2,924 3,177 Employee Benefit Plans 3,624 3,551 Regulatory Assets and Liabilities 7,087 7,828 Deferred Charges 7,820 5,954 Investment Write-down ---- (1,236) Other 806 169 -------------------------- Total Deferred Income Tax $ 47,332 $ 47,113 ========================== Due to a change in New Hampshire State tax regulations and in accordance with SFAS No. 109, "Accounting for Income Taxes," the Company recorded an adjustment to Deferred Income Taxes and an offsetting adjustment to Regulatory Assets of $6.1 million in 2001. Note 11: Energy Supply Massachusetts: Joint Owned Units - FG&E is participating, on a tenancy-in-common basis, with other New England utilities, in the ownership of one generating unit. Wyman Unit No. 4 is an oil-fired station that has been in commercial operation since December 1978. FG&E's 0.217% interest in Millstone Nuclear Generating Station Unit No. 3 (Millstone 3), which has been in commercial operation since April 1986, was sold to Dominion Resources, Inc. effective April 1, 2001. Kilowatt-hour generation and operating expenses of the joint ownership unit is divided on the same basis as ownership. FG&E's proportionate costs are reflected in the Consolidated Statements of Earnings. In accordance with the Massachusetts Restructuring Act, and pursuant to the power supply divestiture discussed below, FG&E began selling the entire output from its joint ownership generating units on February 1, 2000. Revenues from this sale reflect collection of the costs associated with FG&E's ownership interest in these generation units. Accordingly, these expenses do not have an impact on net income. Information with respect to FG&E's ownership in Wyman Unit No. 4, at December 31, 2002, is shown below:
Company's Proportionate Share of Net Book Joint Ownership Unit State Ownership % Total MW Value (000's) --------------------------------------------------------------------------------------- Wyman Unit No. 4 ME 0.1822 1.13 $ 71
Purchased Power and Gas Supply Contracts - FG&E has commitments under long-term contracts for the purchase of electricity and gas from various suppliers. Generally, these contracts are for fixed periods and require payment of demand and energy charges. Total annual costs under these contracts are included in Fuel and 44 Purchased Power and Gas Purchased for Resale in the Consolidated Statements of Earnings. These costs are recoverable in revenues under various cost recovery mechanisms. In accordance with the Restructuring Act, and pursuant to the power supply divestiture discussed below, FG&E began selling the entire output from its power supply contracts on February 1, 2000. Under the Restructuring Act, customers not purchasing electric power from competitive suppliers are eligible either for Standard Offer Service (SOS) or for Default Service. Many of FG&E's customers are currently eligible for SOS service. On March 1, 1999, FG&E entered into a contract with Constellation Power Source to procure power needed to serve the SOS load. The contract will continue through February 28, 2005. The power required to meet Default Service is currently being procured through six-month contracts that expire May 31, 2003. In accordance with MDTE regulations, FG&E will conduct periodic Request for Proposals (RFP) to procure Default Service at market prices. The next RFP will be used to procure Default Service effective June 1, 2003. Power Supply Divestiture - In January 2000, the MDTE approved FG&E's agreement to sell the output from its remaining electric power supply portfolio to Select Energy Inc., a subsidiary of Northeast Utilities. FG&E initiated its electric restructuring process, including the divestiture and sale of its power supply portfolio, in 1998, in response to the Restructuring Act. Under the Select Energy contract, which went into effect February 1, 2000, FG&E began selling the entire output from its remaining power contracts and the output of its two joint ownership units to Select Energy. Upon the sale of FG&E's share of Millstone 3, this portion of the contract sale ceased. FG&E has been allowed recovery of its transition costs, including the above-market or stranded generation and power-supply related costs, via a non-bypassable uniform transition charge. The recoverable transition costs, which have been recorded on FG&E's balance sheet at December 31,2002, as Regulatory Assets, include $81.1 million of purchased power contracts and $12.3 million of recoverable generation-related assets. New Hampshire: Purchased Power Contracts - Unitil Power has commitments under long-term contracts for the purchase of electricity from various suppliers. These wholesale contracts are generally for fixed periods and require payment of demand and energy charges. The total costs under these contracts are included in Fuel and Purchased Power in the Consolidated Statements of Earnings and are normally recoverable in revenues under various cost recovery mechanisms. UES, upon the implementation of customer choice, will be required to acquire and provide transition service power supply to its customers for up to three years. All existing and new customers will be eligible to receive transition service. To the extent that UES customers choose a third party supplier for their power supply and then subsequently return to UES for service, UES will be obligated to provide default service power supply to these customers. Power Supply Divestiture - On January 25, 2002, Unitil Power, along with CECo and E&H, filed a comprehensive electric restructuring proposal under which its long-term power supply contracts would be sold and/or assigned through a competitive auction process to a third party and the remaining financial obligations recovered in their entirety through a retail stranded cost charge. This proposal included the introduction of customer choice consistent with the New Hampshire restructuring law, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the combination of CECo and E&H into a planned successor and new distribution rates for the combined company. On October 25, 2002, the NHPUC approved a multi-party settlement on all major issues in the proceeding. Under Unitil's approved restructuring plan, Unitil will divest its existing power supply portfolio and conduct a solicitation for new power supplies from which to meet its ongoing transition and default service energy obligations. On February 26, 2003, Unitil filed for final NHPUC approval of the executed agreements resulting from these divestiture and solicitation processes, including final tariffs for stranded cost recovery and transition and default services. The filing proposed a recovery period of approximately eight years for stranded costs. The implementation of customer choice is targeted for May 1, 2003. The Unitil Settlement approved in October 2002, provides for full stranded cost recovery by UES, and otherwise resolves all of the issues in the federal court action. The Company has estimated its recoverable stranded costs at $94.5 million, which have been recorded on UES' balance sheet as Regulatory Assets and Power Supply Buyout Obligations. 45 Note 12: Benefit Plans Pension Plans - Unitil has a defined benefit pension plan covering substantially all its employees. The retirement benefits are based upon the employee's level of compensation and length of service. The Company records annual expense and accounts for its pension plan in accordance with SFAS No. 87, "Employers' Accounting for Pensions." The following table provides the components of net periodic expense (income) for the plan for years 2002, 2001 and 2000:
Net Periodic Expense (Income) (000's) 2002 2001 2000 --------------------------------------------------------------------------------------------- Service Cost $ 1,116 $ 914 $ 850 Interest Cost 2,797 2,639 2,552 Expected Return on Plan Assets (4,181) (4,439) (4,356) Amortization of Transition Obligation ---- 84 85 Amortization of Prior-Service Cost 102 96 98 Recognized Net Actuarial (Gain) ---- (10) (105) ---------------------------------------------- Net Periodic Benefit Income $ (166) $ (716) $ (876) ---------------------------------------------- Reconciliation of Projected Benefit Obligations (000's): --------------------------------------------------------------------------------------------- Beginning of Year $ 38,922 $ 35,348 $ 33,371 Service Cost 1,116 914 850 Interest Cost 2,797 2,639 2,552 Amendments 78 ---- (80) Actuarial (Gain) Loss 1,997 2,173 749 Benefit Payments (2,165) (2,152) (2,094) ---------------------------------------------- End of Year $ 42,745 $ 38,922 $ 35,348 ---------------------------------------------- Reconciliation of Fair Value of Plan Assets (000's): --------------------------------------------------------------------------------------------- Beginning of Year $ 40,943 $ 45,422 $ 45,783 Actual Return of Plan Assets (4,534) (2,327) 1,733 Benefit Payments (2,165) (2,152) (2,094) ---------------------------------------------- End of Year $ 34,244 $ 40,943 $ 45,422 ---------------------------------------------- Funded Status (000's): --------------------------------------------------------------------------------------------- Funded Status at December 31 $ (8,501) $ 2,021 $ 10,074 Unrecognized Transition Obligation ---- ---- 84 Unrecognized Prior-Service Cost 919 942 1,038 Unrecognized Loss (Gain) 18,461 7,749 (1,200) ---------------------------------------------- Subtotal 10,879 10,712 9,996 Effect of Regulatory Order (10,879) ---- ---- ---------------------------------------------- Prepaid Pension Cost $ ---- $ 10,712 $ 9,996 ----------------------------------------------
Unitil had an Accumulated Benefit Obligation (ABO) of $35.3 million, $31.3 million and $29.5 million at December 31, 2002, 2001 and 2000, respectively. The Effect of Regulatory Order, noted in the table above, is discussed below. In December 2002, FG&E and UES filed requests with their respective state regulatory commissions for approval of an accounting order to mitigate certain accounting requirements related to pension plan assets which have been triggered by the substantial decline in the capital markets. Due to this decline, at December 31, 2002, the Company's ABO of $35.3 million exceeded its Fair Value of Plan Assets of $34.2 million, which created an additional minimum liability of $1.1 million to be recognized for pension accounting purposes under SFAS No. 87. The respective state regulatory commissions approved these requests in December 2002. These approvals allow FG&E and UES to treat its additional minimum pension liability and Prepaid Pension Costs as Regulatory Assets 46 under SFAS No. 71 and avoid the reduction in equity through comprehensive income that would otherwise be required by SFAS No. 87. These regulatory Orders do not pre-approve the amount of pension expense to be recovered in future rates. Such recovery will be subject to review and approval in future rate proceedings. Based on these approvals, the Company included the additional minimum pension liabilities of $1.1 million plus Prepaid Pension Costs of $10.9 million, or a total of $12.0 million, in Regulatory Assets on its balance sheet. Plan assets are primarily made up of 60% equity and 40% fixed income investments. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased pension benefit costs and cash funding requirements in future periods. Likewise, changes in assumptions regarding discount rates and expected rates of return on plan assets could also increase or decrease pension benefit costs and cash funding requirements in future periods. The weighted average discount rates used in determining the Projected Benefit Obligation in 2002, 2001 and 2000 were 7.00%, 7.25% and 7.75%, respectively. The rate of increase in future compensation levels was 4.00% and the expected long-term rate of return on assets was 9.25% in 2002, 2001 and 2000. Unitil Service has a Supplemental Executive Retirement Plan (SERP). The SERP is an unfunded retirement plan with participation limited to executives selected by the Board of Directors. The cost associated with the SERP amounted to approximately $137,000, $136,000 and $112,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Employee 401(k) Tax Deferred Savings Plan - Unitil sponsors a defined contribution plan under Section 401(k) of the Internal Revenue Code, covering substantially all of the Company's employees. Participants may elect to defer current compensation by contributing to the plan. The Company matches contributions, with a maximum matching contribution of 3% of current compensation. Employees may direct, at their sole discretion, the investment of their savings plan balances both the employer and employee portions into a variety of investment options, including a Company Common Stock fund. Participants are 100% vested in contributions made on their behalf, once they have completed three years of service. The Company's share of contributions to the plan were $483,000, $446,000 and $425,000 for the years ended December 31, 2002, 2001 and 2000, respectively. Post-Retirement Benefits - Unitil's subsidiaries provide health care benefits to retirees for a 12-month period following their retirement. The Company's subsidiaries continue to provide life insurance coverage to retirees. Life insurance and limited health care post-retirement benefits require the Company to accrue post-retirement benefits during the employee's years of service with the Company and the recognition of the actuarially determined total post-retirement benefit obligation earned by existing retirees. At December 31, 2002, 2001 and 2000, the accumulated post-retirement benefit obligation (transition obligation) was approximately $214,000, $235,000 and $257,000, respectively, and the period cost associated with these benefits for 2002, 2001 and 2000 was approximately $119,000, $107,000 and $90,000, respectively. This obligation is being recognized on a delayed basis over the average remaining service period of active participants, and such period will not exceed 20 years. In addition, the Company made payments of $1.2 million, $1.0 million and $0.9 million in 2002, 2001 and 2000 respectively, to the Unitil Retiree Trust (URT) in return for certain advisory services rendered to the Company in those years. URT is an organization of retirees, incorporated in 1993, to advise Unitil Corporation regarding customer service and retirement issues and to provide social, health and welfare benefits to its members, who are eligible former employees of the Company. URT is under the direction of an independent Board of Trustees whose voting members are comprised of former employees of the Company, elected by and from the membership of URT. URT is not a subsidiary of Unitil Corporation. 47 Note 13: Earnings Per Share The following table reconciles basic and diluted earnings per share, assuming all outstanding stock options were converted to common shares per SFAS No. 128, "Earnings per Share."
(000's except share and per share data) 2002 2001 2000 ------------------------------------------------------------------------------------------------------ Income before Extraordinary Item $ 5,835 $ 4,770 $ 6,953 Extraordinary Item, net of tax ---- (3,937) ---- --------------------------------------------- Earnings Available to Common Shareholders $ 5,835 $ 833 $ 6,953 ============================================= Weighted Average Common Shares Outstanding - Basic 4,743,696 4,743,576 4,723,171 Plus: Diluted Effect of Incremental Shares - from Assumed Conversion 18,470 16,246 19,574 Weighted Average Common Shares Outstanding - Diluted 4,762,166 4,759,822 4,742,745 Earnings per Share: Income before Extraordinary Item $ 1.23 $ 1.01 $ 1.47 Extraordinary Item, net of tax --- $ (0.83) $ --- --------------------------------------------- Earnings Available to Common Shareholders $ 1.23 $ 0.18 $ 1.47 =============================================
Weighted average options to purchase 54,000, 114,000 and 55,000 shares of Common Stock were outstanding during 2002, 2001 and 2000, respectively, but were not included in the computation of Weighted Average Common Shares Outstanding for purposes of computing diluted earnings per share, because the effect would have been antidilutive. Note 14: Segment Information Unitil reported four segments: utility electric operations, utility gas operations, other, and non-regulated. Unitil is engaged principally in the retail sale and distribution of electricity in New Hampshire and both electric and gas service in Massachusetts through its retail distribution subsidiaries UES and FG&E. The Company's wholesale electric power subsidiary, Unitil Power, principally provides all the electric power supply requirements to UES for resale at retail. Unitil Resources provides an energy brokering service, through Usource, as well as various energy consulting activities. Unitil Realty and Unitil Service provide centralized facilities, operations and administrative services to support the affiliated Unitil companies. Unitil Realty and Unitil Service are included in the "Other" column of the table below. Unitil Service provides centralized management and administrative services, including information systems management and financial record keeping. Unitil Realty owns certain real estate, principally the Company's corporate headquarters. Unitil Resources and Usource are included in the Non-Regulated column below. The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies. Intersegment sales take place at cost and the effects of all intersegment and/or intercompany transactions are eliminated in the consolidated financial statements. Segment profit or loss is based on profit or loss from operations after income taxes. Expenses used to determine operating income before taxes are charged directly to each segment or are allocated based on factors under the 1935 Act rules and contained in cost-of-service studies, which were included in rate applications approved by the NHPUC and MDTE. Assets allocated to each segment are based upon specific identification of such assets provided by Company records. 48 The following table provides significant segment financial data for the years ended December 31, 2002, 2001 and 2000:
Year Ended December 31, 2002 (000's) Non- Electric Gas Other Regulated Eliminations Total ----------------------------------------------------------------------------------------------------------------------- Revenues $ 167,317 $ 20,283 $ 30 $ 756 $ 188,386 Depreciation and Amortization 10,793 1,998 1,922 198 14,911 Interest, net 4,693 1,692 654 18 7,057 Income Taxes 3,519 (458) (46) (525) 2,490 Segment Profit 6,249 (206) 456 (664) 5,835 Identifiable Segment Assets 384,862 85,366 24,500 1,958 (15,903) 480,783 Capital Expenditures 16,676 3,859 290 ---- 20,825 Year Ended December 31, 2001 (000's) ----------------------------------------------------------------------------------------------------------------------- Revenues $ 183,780 $ 22,828 $ 30 $ 384 $ 207,022 Depreciation and Amortization 9,025 1,760 1,753 229 12,767 Interest, net 4,388 1,576 829 4 6,797 Income Taxes 4,527 (457) 2 (651) 3,421 Segment Profit 8,771 (771) 172 (1,002) 7,170 Investment Write-down, net of tax ---- ---- (2,400) ---- (2,400) Extraordinary Item, net of tax (3,937) ---- ---- ---- (3,937) Identifiable Segment Assets 288,013 87,851 23,679 834 (23,615) 376,762 Capital Expenditures 14,328 4,817 745 ---- 19,890 Year Ended December 31, 2000 (000's) ----------------------------------------------------------------------------------------------------------------------- Revenues $ 160,023 $ 22,756 $ 31 $ 131 $ 182,941 Depreciation and Amortization 8,815 1,575 1,344 230 11,964 Interest, net 4,797 1,370 627 26 6,820 Income Taxes 4,051 199 14 (851) 3,413 Segment Profit 7,923 662 46 (1,678) 6,953 Identifiable Segment Assets 286,437 89,917 24,079 994 (18,460) 382,967 Capital Expenditures 14,066 3,821 3,205 ---- 21,092
Note 15: Commitments and Contingencies Regulatory Matters - The Unitil Companies are regulated by various federal and state agencies, including the SEC, the FERC and state regulatory authorities with jurisdiction over public utilities, including the NHPUC and the MDTE. 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 gas, while continuing to regulate the distribution operations of Unitil's utility operating subsidiaries. Unitil implemented the restructuring of its electric operations in Massachusetts in 1998 and is implementing a restructuring settlement for its New Hampshire electric operations that is expected to be on May 1, 2003. Massachusetts Electric Operations Restructuring - Beginning March 1, 1998, FG&E implemented its Restructuring Plan under the Massachusetts Restructuring Act. FG&E completed the divestiture of its entire regulated power supply business in 2000 in accordance with the Restructuring Plan. All FG&E distribution customers must pay a transition charge that provides for the recovery of costs associated with FG&E's power portfolio which were stranded as a result of the divestiture of those assets. The plant and Regulatory Asset balances that will be recovered through the transition charge have been approved by the MDTE as part of FG&E's annual Reconciliation Filings. The Restructuring Act also requires FG&E to obtain power for retail customers who choose not to buy energy from a competitive supplier through either SOS or Default Service. FG&E must provide SOS through February 2005 at rate levels which guarantee rate reductions required by the Restructuring Act. New distribution customers and customers no longer eligible for SOS are eligible to receive Default Service at prices set periodically based on market solicitations as approved by regulators. As of December 31, 2002, competitive suppliers were serving approximately 20% of FG&E's load, mainly for large industrial customers. 49 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, a nuclear generating unit. FG&E earns an authorized rate of return on the unamortized balance of these Regulatory Assets. In addition, as a result of the rate reduction and rate cap requirements of the Restructuring Act, FG&E has been authorized to defer the recovery of a portion of its transition costs and SOS costs. These unrecovered amounts are also recorded as Regulatory Assets and earn authorized carrying charges until their subsequent recovery in future periods. In 2002, Unitil's earnings derived from these generation-related Regulatory Assets, including carrying charges earned on deferred transition costs and SOS costs, represented approximately 10% of net income. The value of FG&E's Regulatory Assets is approximately $128 million at December 31, 2002, and is expected to be amortized and recovered over the next three to nine years. Earnings from this segment of FG&E's utility business will continue to decline and ultimately cease. FG&E made a total of four Reconciliation Filings in 1999, 2000, 2001 and 2002. Rate adjustments were approved for effect during the subsequent year, subject to further investigation. In October 2001, the MDTE issued a final Order on FG&E's 1999 Reconciliation Filing which determined the final treatment of Regulatory Assets attributable to stranded generation costs, purchased power costs, and related expenses for the 1999, and future, Reconciliation Filings. FG&E's 2001 Reconciliation Filing, submitted on December 2, 2001, recast its rates from 1998 through 2001 in compliance with the MDTE's final Order on its 1999 filing. On October 15, 2002, the MDTE issued an Order approving a settlement agreement regarding the Company's 2001 filing. Under the approved settlement, FG&E agreed to reduce the carrying charge on deferred transition costs that will be recovered from customers in future years. This change does not affect current electric rates. The MDTE's October 2002 Order and associated settlement resolve many of the issues which otherwise might have been contested in FG&E's future Reconciliation Filings. FG&E submitted its 2002 Reconciliation Filing on December 20, 2002. Rate adjustments were approved for effect on January 1, 2003, subject to investigation, resulting in a rate reduction of approximately 4.4% for residential SOS customers. The reduction is due to a decrease in the SOS fuel adjustment, which is not subject to the rate cap, and does not affect net income. Massachusetts Gas Operations Restructuring - Following a three year state-wide collaborative process on the unbundling, or separation, of discrete services offered by natural gas local distribution companies (LDCs), the MDTE approved regulations and tariffs for FG&E and other LDCs to provide full customer choice effective November 1, 2000. The MDTE ruled that LDCs would continue to have an obligation to provide gas supply and delivery services for a five-year transition period, with a review after three years. This review is expected to be initiated in late 2003. The MDTE also required mandatory assignment of LDCs' pipeline capacity to competitive marketers supplying customers during the transition period. This mandatory capacity assignment protects LDCs from exposure to certain stranded gas supply costs during the transition period. New Hampshire Restructuring - On January 25, 2002, the Company's New Hampshire electric utility subsidiaries, CECo, E&H and Unitil Power, filed a comprehensive restructuring proposal with the NHPUC. This proposal included the introduction of customer choice consistent with New Hampshire's electric utility industry restructuring law, the divestiture of Unitil Power's power supply portfolio, the recovery of stranded costs, the merger of CECo and E&H into one distribution company and new distribution rates for the combined company. On October 25, 2002, the NHPUC approved a multi-party settlement on all major issues in the proceeding, including stranded cost recovery for purchased power contracts. The Company estimates that these recoverable stranded costs are approximately $94.5 million and these were recorded as Power Supply Buyout Obligations and Regulatory Assets at December 31, 2002. Under Unitil's approved restructuring plan, Unitil also agreed to divest its existing power supply portfolio and conduct a solicitation for new power supplies from which to meet its ongoing Transition and Default Service energy obligations. On February 26, 2003, Unitil filed for final NHPUC approval of the executed agreements resulting from these divestiture and solicitation processes, including final tariffs for stranded cost recovery and Transition and Default Services. The filing proposed a recovery period of approximately eight years for stranded costs. The implementation of customer choice for UES customers is targeted to begin May 1, 2003. Unitil's restructuring plan is also designed to resolve the pending litigation on this matter. In June 1997, Unitil and other New Hampshire utilities intervened as plaintiffs in a suit filed in U.S. District Court by Northeast Utilities' affiliate Public Service Company of New Hampshire for protection from the NHPUC's Final Plan to restructure the New Hampshire electric utility industry. Although the NHPUC found that CECo and E&H were entitled to full 50 interim stranded cost recovery, the NHPUC also made certain legal rulings, that, if implemented, could affect UES's long-term ability to recover all of its stranded costs. The Unitil Settlement, approved in October 2002, otherwise resolves all of the issues in the federal court action. Upon receipt the expiration of all periods of appeal with respect to the restructuring proceeding by the NHPUC thereto, UES will implement retail choice and Unitil will withdraw its intervention in this federal court action, with prejudice. Wholesale Power Market Restructuring - Unitil has also been a participant in the restructuring of the wholesale power market and transmission system in New England, which is subject to FERC jurisdiction. New wholesale markets structured pursuant to FERC's Standard Market Design are expected to be implemented in the New England Power Pool during the first half of 2003 under the general supervision of an Independent System Operator and the regulatory oversight of the FERC. Rate Proceedings - Prior to 2002, the last formal regulatory filings initiated by the Company to increase base rates for Unitil's retail electric operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. The last distribution base rate increase request for FG&E's retail gas operations occurred in 1998. In 2001, FG&E's electric base rates were investigated by the MDTE, which resulted in an electric base rate decrease. A majority of the Company's electric and gas operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, energy efficiency and restructuring-related cost recovery mechanisms. 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, FG&E continues to provide a multi-year refund through its Cost of Gas Adjustment Clause in compliance with the MDTE's May 2001 Order finding that FG&E had over-collected fuel inventory finance charges. At December 31, 2002, the unamortized balance of this refund was $1.3 million. FG&E believes a refund is not justified or warranted and has appealed the MDTE's ruling to the Massachusetts Supreme Judicial Court (SJC). On a preliminary motion, a single justice of the SJC declined to stay the MDTE's Order based on a finding that refunds made by FG&E may be recouped if FG&E prevails on the merits of its claims. The review of the MDTE Order by the SJC is pending. On October 25, 2002, as part of the electric restructuring settlement for Unitil's New Hampshire utility operations described above, the Company received approval from the NHPUC for an increase of approximately $2.0 million in annual distribution revenues for UES, effective December 1, 2002. On December 2, 2002, the MDTE issued an Order resulting in distribution rate increases of $2.0 million for FG&E's electric operations and $3.0 million for FG&E's gas operations. Increases for rising gas costs were incorporated into the final gas rates. FG&E's new rates became effective on December 2, 2002. On April 16, 2002, FG&E filed Performance Based Regulation (PBR) Plans with the MDTE for both electric and gas operations. PBR is a method of setting regulated distribution rates that provides incentives 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. FG&E's PBR Plans were filed in conjunction with FG&E's distribution rate filings, consistent with MDTE policy to implement PBR in the context of base rate cases. The MDTE did not initiate investigations of the filings. On January 6, 2003, the MDTE issued Orders closing the cases. Accordingly, FG&E's PBR plans have no scheduled date of implementation, and conventional cost-based regulation continues to apply. In December 2002, FG&E and UES filed requests with their respective state regulatory commissions for approval of an accounting Order to mitigate certain accounting requirements related to pension plan assets, which have been triggered by the substantial decline in the capital markets. These requests were granted by the respective state regulatory commissions in December 2002. These approvals allow FG&E and UES to treat the additional minimum pension liability and Prepaid Pension Costs as Regulatory Assets under SFAS No. 71 and avoid the reduction in equity that would otherwise be required by SFAS No. 87. These regulatory Orders do not pre-approve the amount of pension expense to be recovered in future rates. Such recovery will be subject to review and approval in future rate proceedings. Based on these approvals, Unitil has included the amount of the additional minimum pension liabilities and Prepaid Pension Costs of $12.0 million in Regulatory Assets on its balance sheet. 51 Environmental Matters - The Company's past and present operations include activities that are subject to extensive federal and state environmental regulations. Sawyer Passway MGP Site - The Company continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows the Company to work towards temporary remediation of the site. Work performed in 2002 was associated with the five-year review of the Temporary Solution submittal (Class C Response Action Outcome) under the Massachusetts Contingency Plan that was filed for the site in 1997. Completion of this work has confirmed the Temporary Solution status of the site for an additional five years. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed. Since 1991, FG&E has recovered the environmental response costs incurred at this former MGP site pursuant to a MDTE approved Settlement Agreement (Agreement). The Agreement allows FG&E to amortize and recover from gas customers over succeeding seven-year periods the environmental response costs incurred each year. Environmental response costs are defined to include liabilities related to manufactured gas sites, waste disposal sites or other sites onto which hazardous material may have migrated as a result of the operation or decommissioning of Massachusetts gas manufacturing facilities from 1882 through 1978. In addition, any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers. The total annual charge for such costs assessed to gas customers cannot exceed five percent of FG&E's total revenue for firm gas sales during the preceding year. Costs in excess of five percent will be deferred for recovery in subsequent years. Former Electric Generating Station - The Company is remediating 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 the time of the sale of the structure to WRW. When Rockware and WRW encountered financial difficulties and failed to respond adequately to Orders of the environmental regulators to remedy the situation, FG&E agreed to take steps at that time and obtained DEP approval to temporarily enclose, secure and stabilize the facility. Based on that approval, between September and December 1989, contractors retained by FG&E 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. 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. Those surveys revealed continued deterioration of the asbestos-containing insulation materials in the building. By letter dated May 1, 2002, the EPA notified FG&E that it was a Potentially Responsible Party for planned remedial activities at the site and invited FG&E to perform or finance such activities. FG&E and the EPA have entered into an Agreement on Consent, whereby FG&E, without an admission of liability, will conduct environmental remedial action to abate and remove asbestos-containing and other hazardous materials. FG&E has awarded contracts for all aspects of the abatement work, which is presently ongoing. FG&E received significant coverage from its insurance carrier. The Company believes that these funds will be sufficient to complete this remediation and that resolution of this matter will not have a material adverse impact on the Company's financial position. 52 The Company has recorded the estimated cost of the remediation action in Current Liabilities and an offsetting asset reflecting insurance proceeds in Current Assets. At the balance sheet date, net of amounts expended in 2002, the remaining project cost was $3.7 million. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None 53 PART III Item 10. Directors and Executive Officers of the Registrant Information required by this Item is set forth on pages 3 through 7 of the 2002 Proxy Statement as filed with the Securities and Exchange Commission on March 12, 2003. Item 11. Executive Compensation Information required by this Item is set forth on pages 12 through 23 of the 2002 Proxy Statement as filed with the Securities and Exchange Commission on March 12, 2003. Item 12. Security Ownership of Certain Beneficial Owners and Management Information required by this Item is set forth on pages 4 through 7 and pages 16 through 18 of the 2002 Proxy Statement as filed with the Securities and Exchange Commission on March 12, 2003. Item 13. Certain Relationships and Related Transactions None 54 PART IV Item 14. Controls and Procedures Within the 90 days prior to the date of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer, Chief Financial Officer and Controller, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer, Chief Financial Officer and Controller concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company's periodic SEC filings. There have been no significant changes in the Company's internal controls or in other factors, which could significantly affect internal controls subsequent to the date the Company carried out its evaluation. Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) (1) and (2) - LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES The following financial statements are included herein under Part II, Item 8, Financial Statements and Supplementary Data: o Report of Independent Certified Public Accountants o Consolidated Balance Sheets - December 31, 2002 and 2001 o Consolidated Statements of Earnings for the years ended December 31, 2002, 2001, and 2000 o Consolidated Statements of Capitalization - December 31, 2002 and 2001 o Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001, and 2000 o Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2002, 2001, and 2000 o Notes to Consolidated Financial Statements The following consolidated financial statement schedule of the Company and subsidiaries is included in Item 15(d): o Schedule II Valuation and Qualifying Accounts for December 31, 2002, 2001, and 2000 All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions, are not applicable, or information required is included in the financial statements or notes thereto and, therefore, have been omitted. 55 (3) - List of Exhibits
Exhibit Number Description of Exhibit Reference* -------------- ---------------------- ---------- 3.1 Articles of Incorporation Exhibit 3.1 to Form of the Company S-14 Registration Statement 2-93769 3.2 Articles of Amendment to the Articles of Incorporation Exhibit 3.2 to Form Filed on March 4, 1992 and April 30, 1992 10-K for 1992 3.3 By-laws of the Company. Exhibit 3.2 to Form S-14 Registration Statement 2-93769 3.4 Articles of Exchange of Concord Electric Company (CECo), Exhibit 3.3 to Exeter & Hampton Electric Company (E&H) and the Company. 10-K for 1984 3.5 Articles of Exchange of CECo, E&H, and the Company - Stipulation of Exhibit 3.4 to the Parties Relative to Recordation and Effective Date. Form 10-K for 1984 3.6 The Agreement and Plan of Merger dated March 1, 1989 among the Exhibit 25(b) to Company, Fitchburg Gas and Electric Light Company (FG&E) and UMC Form 8-K dated March 1, Electric Co., Inc. (UMC). 1989 3.7 Amendment No. 1 to The Agreement and Plan of Merger dated March 1, Exhibit 28(b) to 1989 among the Company, FG&E and UMC. Form 8-K dated December 14, 1989 4.1 Twelfth Supplemental Indenture of Unitil Energy Systems, Inc., Filed herewith successor to Concord Electric Company, dated as of December 2, 2002, amending and restating the Concord Electric Company Indenture of Mortgage and Deed of Trust dated as of July 15, 1958. 4.2 FG&E Purchase Agreement dated March 20, 1992 for the 8.55% Senior Exhibit 4.18 to Notes due March 31, 2004 Form 10-K for 1993 4.3 FG&E Note Agreement dated November 30, 1993 for the 6.75% Notes due Exhibit 4.18 to November 23, 2023. Form 10-K for 1993 4.4 FG&E Note Agreement dated January 26, 1999 for the 7.37% Notes due Exhibit 4.25 to January 15, 2028. Form 10-K for 1999 4.5 FG&E Note Agreement dated June 1, 2001 for the 7.98% Notes due June Exhibit 4.6 to 1, 2031. Form 10-Q for June 30, 2001 4.6 Unitil Realty Corp. Note Purchase Agreement dated July 1, 1997 for Exhibit 4.22 to the 8.00% Senior Secured Notes due August 1, 2017. Form 10-K for 1997 10.1 Unitil System Agreement dated June 19, 1986 providing that Unitil Exhibit 10.9 to Power will supply wholesale requirements electric service to CECo Form 10-K for 1986 and E&H. 56 Exhibit Number Description of Exhibit Reference* -------------- ---------------------- ---------- 10.2 Supplement No. 1 to Unitil System Agreement providing that Unitil Exhibit 10.8 to Power will supply wholesale requirements electric service to CECo Form 10-K for 1987 and E&H. 10.3 Transmission Agreement between Unitil Power Corp. and Public Exhibit 10.6 to Service Company of New Hampshire, effective November 11, 1992. Form 10-K for 1993 10.4 Form of Severance Agreement dated February 21, 1989, between the Exhibit 10.55 to Company and the persons named in the schedule attached thereto. Form 8 dated April 12, 1989 10.5 Key Employee Stock Option Plan effective January 17, 1989. Exhibit 10.56 to Form 8 dated April 12, 1989 10.6 Unitil Corporation Key Employee Stock Option Plan Award Agreement. Exhibit 10.63 to Form 10-K for 1989 10.7 Unitil Corporation Management Performance Compensation Plan. Exhibit 10.94 to Form 10-K/A for 1993 10.8 Unitil Corporation Supplemental Executive Retirement Plan effective Exhibit 10.95 to as of January 1, 1987. Form 10-K/A for 1993 10.9 Unitil Corporation 1998 Stock Option Plan. Exhibit 10.12 to Form 10-K for 1998 10.10 Unitil Corporation Management Incentive Plan. Exhibit 10.13 to Form 10-K for 1998 10.11 Entitlement Sale and Administrative Service Agreement with Select Exhibit 10.14 to Energy. Form 10-K for 1999 10.12 Purchase and Sale Agreement For New Haven Harbor. Exhibit 10.15 to Form 10-K for 1999 10.13 Labor Agreement effective June 1, 2000 between CECo and The Exhibit 10.13 to International Brotherhood of Electrical Workers, Local Union No. Form 10-K for 2000 1837. 10.14 Labor Agreement effective June 1, 2000 between E&H and The Exhibit 10.14 to International Brotherhood of Electrical Workers, Local Union No. Form 10-K for 2000 1837. 10.15 Labor Agreement effective June 1, 2000 between FG&E and The Utility Exhibit 10.15 to Workers of America, AFL-CIO., Local Union No. B340, The Brotherhood Form 10-K for 2000 of Utility Workers Council. 10.16 Unitil Corporation 2003 Restricted Stock Plan Filed herewith 10.17 Portfolio Sale and Assignment and Transition Service and Default Filed herewith Service Supply Agreement By and Among Unitil Power Corp., Unitil Energy Systems, Inc. and Mirant Americas Energy Marketing, LP 11.1 Statement Re: Computation in Support of Earnings per Share For the Filed herewith Company. 57 Exhibit Number Description of Exhibit Reference* -------------- ---------------------- ---------- 12.1 Statement Re: Computation in Support of Ratio of Earnings to Fixed Filed herewith Charges for the Company. 21.1 Statement Re: Subsidiaries of Registrant. Filed herewith 23.1 Consent of Independent Certified Public Accountants Filed herewith 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Filed herewith Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
* The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference. ** Copies of these debt instruments will be furnished to the Securities and Exchange Commission upon request. (b) Report on Form 8-K No reports on Form 8-K were filed during the fourth quarter of the year ended December 31, 2002. 58 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Unitil Corporation Date March 25, 2003 By /s/ Robert G. Schoenberger ------------------------------- Robert G. Schoenberger Chairman of the Board Directors, and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Capacity Date --------- -------- ---- /s/ Robert G. Schoenberger Principal Executive March 25, 2003 ------------------------------ Officer; Director Robert G. Schoenberger /s/ Michael J. Dalton Principal Operating March 25, 2003 ------------------------------ Officer; Director Michael J. Dalton /s/ Mark H. Collin Principal Financial March 25, 2003 ------------------------------ Officer Mark H. Collin /s/ Albert H. Elfner, III Director March 25, 2003 ------------------------------ Albert H. Elfner, III /s/ Ross B. George Director March 25, 2003 ------------------------------ Ross B. George /s/ M. Brian O'Shaughnessy Director March 25, 2003 ------------------------------ M. Brian O'Shaughnessy /s/ Charles H. Tenney III Director March 25, 2003 ------------------------------ Charles H. Tenney III /s/ Dr. Sarah P. Voll Director March 25, 2003 ------------------------------ Dr. Sarah P. Voll /s/ Eben S. Moulton Director March 25, 2003 ------------------------------ Eben S. Moulton 59 /s/ David P. Brownell Director March 25, 2003 ------------------------------ David P. Brownell /s/ Edward F. Godfrey Director March 25, 2003 ------------------------------ Edward F. Godfrey /s/ Michael B. Green Director March 25, 2003 ------------------------------ Michael B. Green 60 CERTIFICATIONS UNDER SECTION 302 OF THE SARBANES-OXLEY ACT I, Robert G. Schoenberger, certify that: 1) I have reviewed this annual report on Form 10-K of Unitil Corporation; 2) Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3) Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4) The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5) The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6) The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 25, 2003 /s/ Robert G. Schoenberger -------------------------- Robert G. Schoenberger Chief Executive Officer 61 I, Mark H. Collin, certify that: 1) I have reviewed this annual report on Form 10-K of Unitil Corporation; 2) Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3) Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4) The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5) The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6) The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 25, 2003 /s/ Mark H. Collin ------------------ Mark H. Collin Chief Financial Officer 62 I, Laurence M. Brock, certify that: 1) I have reviewed this annual report on Form 10-K of Unitil Corporation; 2) Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3) Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4) The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5) The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6) The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: March 25, 2003 /s/ Laurence M. Brock --------------------- Laurence M. Brock Controller, Unitil Service Corp. 63 SCHEDULE II UNITIL CORPORATION VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Additions -------------------------- Balance at Charged to Charged to Deductions Balance at Beginning Costs and Other from End of Description of Period Expenses Accounts Reserves Period (A) (B) -------------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2002 Reserves Deducted from A/R Electric $ 457,657 $ 323,401 $ 138,010 $ 646,869 $ 272,199 Gas 142,842 294,051 64,571 401,164 100,300 --------------------------------------------------------------------- $ 600,499 $ 617,452 $ 202,581 $ 1,048,033 $ 372,499 ===================================================================== Year Ended December 31, 2001 Reserves Deducted from A/R Electric $ 452,872 $ 940,590 $ 86,161 $ 1,021,080 $ 457,657 Gas 142,810 54,162 656,952 711,082 142,842 --------------------------------------------------------------------- $ 595,682 $ 994,752 $ 743,113 $ 1,732,162 $ 600,499 ===================================================================== Year Ended December 31, 2000 Reserves Deducted from A/R Electric $ 464,797 $ 455,353 $ 81,286 $ 548,564 $ 452,872 Gas 133,803 48,202 413,277 452,472 142,810 --------------------------------------------------------------------- $ 598,600 $ 503,555 $ 494,563 $ 1,001,036 $ 595,682 ===================================================================== $ 646,084 $ 807,059 $ 178,881 $ 1,033,424 $ 598,600 =====================================================================
(A) Collections on Accounts Previously Charged Off (B) Bad Debts Charged Off 64