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, 1998 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 incorporation or organization) Identification No.) 6 Liberty Lane West, Hampton, New Hampshire 03842-1720 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (603) 772-0775 Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Exchange on Which Registered Common Stock, No Par Value American Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark 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, 1999, the aggregate market value of common stock held by non-affiliates of the registrant was $106,027,649. The number of common shares outstanding of the registrant was 4,660,556 as of March 1, 1999. Documents Incorporated by Reference: Portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held April 15, 1999, are incorporated by reference into Part III of this Report. UNITIL CORPORATION FORM 10-K For the Fiscal Year Ended December 31, 1998 Table of Contents Item Description Page PART I 1. Business The Unitil System ................................. 2 Utility Operations ............................... 2 Rates and Regulation ................................. 3 Electric Utility Industry Restructuring and Competition.. 5 Gas Utility Industry Restructuring and Competition..... 6 Electric Power Supply ............................... 6 Gas Supply ............................................. 8 Environmental Matters ................................ 8 Capital Requirements ................................. 9 Financing Activities............................... 9 Employees................................................ 10 Executive Officers of the Registrant............... 11 2. Properties ................................................ 12 3. Legal Proceedings.............................................. 13 4. Submission of Matters to a Vote of Securities Holders.......... 13 PART II 5.	Market for Registrant's Common Equity and Related Stockholder Matters ...................................... 14 6. Selected Financial Data ................................. 15 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations .................................. 16 8. Financial Statements and Supplementary Data................ 26 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................................. 48 PART III 10. Directors and Executive Officers of the Registrant .. . 49 11. Executive Compensation ................................. 49 12. Security Ownership of Certain Beneficial Owners and Management .............................................. 49 13. Certain Relationships and Related Transactions ............. 49 PART IV1 14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K ........................................... 50 Consent of Independent Certified Public Accountants.......... 56 Signatures .................................................. 57 Schedule VIII Valuation and Qualifying Accounts and Reserves ......... 59 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 27		Financial Data Schedule Exhibit 99.1		1998 Proxy Statement Exhibit 4.23 Eleventh Supplemental Indenture relating to Exeter & Hampton First Mortgage Bonds Exhibit 4.24 Ninth Supplemental Indenture relating to Concord Electric Company First Mortgage Bonds Exhibit 10.2 Exeter & Hampton Company Labor Agreement Exhibit 10.3 Fitchburg Gas and Electric Company Labor Agreement Exhibit 10.12 Unitil Corporation 1998 Stock Option Plan Exhibit 10.13 Unitil Corporation Management Incentive Plan PART I Item 1. Business. THE UNITIL SYSTEM	 	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 System. The following companies are wholly owned subsidiaries of Unitil, which together make up the Unitil System: Unitil Corporation Subsidiaries State and Principal Type Year of of Business Organization Concord Electric Company (CECo) NH-1901 Retail Electric Distribution Utility Exeter & Hampton Electric Company (E&H) NH-1908 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 Marketing and Services 	 	The Unitil System'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 three wholly owned retail distribution utility subsidiaries (CECo, E&H and FG&E, collectively referred to as the Retail Distribution Utilities). The Company's wholesale electric power utility subsidiary, Unitil Power Corp., principally provides all the electric power supply requirements to CECo and E&H for resale at retail, and also engages in various other wholesale electric power services with affiliates and non-affiliates throughout the New England region. 	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 at cost 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. 	On March 25, 1999 Unitil acquired a minority interest in North American Power Brokers, Inc., a privately held company providing Internet technology solutions to the energy industry. Unitil, through Unitil Resources, has licensed and deployed North American Power's innovative Internet-based technology for electricity and natural gas energy transactions between retail consumers and energy suppliers. Unitil will offer the retail energy electronic commerce system developed and owned by North American Power to medium and large commercial and industrial customers, co-branded under the name "Usource", powered by North American Power's World Wide Retail Energy Exchange. UTILITY OPERATIONS 	CECo is engaged principally in the distribution and sale of electricity at retail to approximately 26,700 customers in the City of Concord, which is the state capital, and twelve surrounding towns, all in New Hampshire. CECo's service area consists of approximately 240 square miles in the Merrimack River Valley of south central New Hampshire. The service area includes the City of Concord and major portions of the surrounding towns of Bow, Boscawen, Canterbury, Chichester, Epsom, Salisbury and Webster, and limited areas in the towns of Allenstown, Dunbarton, Hopkinton, Loudon and Pembroke. 	 The State of New Hampshire's government operations are located within CECo's service area, including the executive, legislative, judicial branches and offices and facilities for all major state government services. In addition, CECo's service area is a retail trading center for the north central part of the state and has over sixty diversified businesses relating to insurance, printing, electronics, granite, belting, plastic yarns, furniture, machinery, sportswear and lumber. Of CECo's 1998 retail electric revenues, approximately 33% were derived from residential sales, 55% from commercial, government and nonmanufacturing sales, and 12% from industrial/ manufacturing sales. 	E&H is engaged principally in the distribution and sale of electricity at retail to approximately 39,200 customers in the towns of Exeter and Hampton and in all or part of sixteen surrounding towns, all in New Hampshire. E&H's service area consists of approximately 168 square miles in southeastern New Hampshire. The service area includes all of the towns of Atkinson, Danville, East Kingston, Exeter, Hampton, Hampton Falls, Kensington, Kingston, Newton, Plaistow, Seabrook, South Hampton and Stratham, and portions of the towns of Derry, Brentwood, Greenland, Hampstead and North Hampton. 	 Commercial and industrial customers served by E&H are quite diversified and include retail stores, 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 E&H's territory, which includes several popular resort areas and beaches along the Atlantic Ocean. Of E&H's 1998 retail electric revenues, approximately 47% were derived from residential sales, 43% from commercial and nonmanufacturing sales, 10% from industrial/manufacturing sales. 	FG&E is engaged principally in the 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 25,900 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 1998 electric revenues, approximately 34% were derived from residential sales, 33% from commercial and nonmanufacturing sales, and 33% from industrial/ manufacturing sales. 	Natural gas is supplied and distributed by FG&E to approximately 14,900 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Of FG&E's 1998 gas operating revenues, approximately 52% were derived from residential sales, 23% from commercial sales, 13% from firm sales to industrial customers, and 12% from interruptible sales (which are sales to customers that have agreed to discontinue use of the Company-supplied 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). FG&E's industrial gas revenue is primarily derived from firm sales to paper manufacturing and paper products companies, fabricated metal products manufacturers, rubber and plastics manufacturers, primary iron manufacturers and other miscellaneous industries. 	Natural gas sales in New England are seasonal, and the Company's results of operations reflect this seasonality. 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. The Unitil System is not dependent on a single customer or a few customers for its electric and gas sales. 	(For details on the Unitil System's Results of Operations see Part II, Item 7 herein.) (For segment information see Part II, Item 8, Footnote 11 herein.) RATES AND REGULATION 	The Company is registered with the Securities and Exchange Commission (SEC) as a holding company under the 1935 Act, and it and its subsidiaries are subject to the provisions of the 1935 Act. Accordingly, the Securities and Exchange Commission (SEC) has jurisdiction over Unitil and its subsidiaries with respect to, among other things, securities issues, sales and acquisitions of securities and utility assets, intercompany loans, services performed by and for affiliated companies, certain accounts and records, and involvement in non utility operations. The Company and its subsidiaries, where applicable, are subject to regulation by the Federal Energy Regulatory Commission (FERC), the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE) with respect to rates, adequacy of service, issuance of securities, accounting and other matters. Unitil Power, as a wholesale utility, is subject to rate regulation by the FERC. Both CECo and E&H, as retail electric utilities in New Hampshire, are subject to rate regulation by the NHPUC, and FG&E is subject to MDTE regulation with respect to gas and electric retail rates, and FERC regulation with respect to New England Power Pool (NEPOOL) interchanges and other wholesale sales of electricity. 	Current Rate Regulation--- The revenues of Unitil's Retail Distribution Utilities are collected pursuant to rates on file with the NHPUC, the MDTE and, to a minor extent, the FERC. In general, the Retail Distribution Companies current retail rates are comprised of a base rate component, established during comprehensive base rate cases, and various periodic rate adjustment mechanisms, which track and reconcile particular expense elements with associated collected revenues. The last comprehensive regulatory proceedings to increase base electric rates for Unitil's Retail Distribution Utilities were in 1985 for CECo, 1984 for FG&E, and 1982 for E&H. FG&E was granted its first Gas Base Rate adjustment in 14 years effective December 1, 1998. The majority of the Unitil System's utility operating revenues are presently collected under various rate adjustment mechanisms, including revenues collected from customers for fuel, purchased power, cost of gas, and demand-side management program costs. 	The Unitil System Agreement (System Agreement), as approved by the FERC, governs wholesale sales by Unitil Power to its New Hampshire retail distribution affiliates, CECo and E&H, and provides for recovery by Unitil Power of all costs incurred in the provision of service. Unitil Power has continued to adjust its wholesale rates every six months in accordance with the System Agreement, and CECo and E&H have continued to file corresponding semiannual changes in their retail fuel and purchased power adjustment clauses with the NHPUC which have been routinely approved. 	Recent changes in legislation and regulation in Massachusetts has changed the way FG&E provides service to its electric customers. Instead of supplying energy on demand to all its customers, FG&E will deliver energy to its customers on behalf of competitive suppliers and will supply energy to customers who do not choose Standard Offer Service, and to customers whose supplier fails to deliver Default Service. The result of these changes will be the replacement of FG&E's quarterly filed electric fuel charge with: a) an annually determined Standard Offer Service charge and reconciliation adjustment mechanism; and b) a monthly determined Default Service charge and reconciliation adjustment mechanism both of which are designed to allow FG&E to recover all its power supply costs. In addition FG&E has implemented a Transition Cost Charge and reconciliation adjustment mechanism enabling it to recover all its stranded costs (See Electric Utility Industry Restructuring and Competition). 	FG&E's gas costs are recovered through a cost of gas adjustment (CGA) mechanism, through which firm gas customers pay the costs incurred for procuring and transporting gas to FG&E's local distribution system for delivery to customers. FG&E gas operations have been incurring FERC-approved transition charges from interstate pipeline suppliers since 1992, resulting from the transition to a comprehensive set of new regulations under FERC Order 636. These costs have been recovered directly from FG&E's gas customers through the CGA mechanism, as authorized by the MDTE. FG&E does not expect to incur any additional transition costs in 1999. 	 	Millstone Unit No. 3- FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. On March 30, 1996, as a result of an engineering evaluation completed by the operator, Northeast Utilities, Millstone 3 was taken out of service. NRC authorization for restart was given on June 29, 1998. Millstone 3 began producing electric power in early July, 1998 and reached full output on July 15, 1998. The unit remains on the NRC's Watch List. 	During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E had been incurring approximately $35,000 per month in replacement power costs, and had been recovering those costs through its fuel adjustment clause, which will be subject to review and approval by the MDTE. 	In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. The arbitration and legal cases are proceeding. 		 	SFAS No. 71 --- The Company accounts for all its regulated operations in accordance with Statement of Financial Accounting Standard ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring the Company to record the financial statement effects of the rate regulation to which the Company is currently subject. If a separable portion of the Company's business no longer meets SFAS No. 71, the Company is required to eliminate the financial statement effects of regulation for that portion. (See "Impact of Electric Restructuring" in Note 8 of the financial statements contained herein.) 	(For a discussion of utility rates and regulation under a more competitive environment, see the following sections on Electric Utility Industry Restructuring and Competition, and Gas Utility Industry Restructuring and Competition) ELECTRIC UTILITY INDUSTRY RESTRUCTURING AND COMPETITION 	 		Restructuring and Competition -Regulatory activity surrounding restructuring and competition continues in both Massachusetts and New Hampshire. March 1, 1998 was "Choice Date" or the beginning of competition for all electric consumers in Massachusetts, while New Hampshire's "Choice Date" slipped past both the proposed date of January 1, 1998, and the legislature's mandated July 1, 1998. Currently, approximately 10% of New Hampshire electric consumers can choose their electric supplier. The ability to choose for the remaining 90% is currently the subject of a federal court preliminary injunction (see below). 	 Massachusetts gas industry restructuring plans continue to be under development. The MDTE, gas utilities and other stakeholders began a collaborative effort in late 1997 to develop solutions to the many issues that surround restructuring the local natural gas distribution business. 	Unitil has been preparing for electric and gas industry restructuring by developing transition plans that will move its utility subsidiaries into this new market structure in a way that will ensure fairness in the treatment of the Company's assets and obligations that are dedicated to the current regulated franchises and, at the same time, provide choice for all customers. 		New Hampshire - On February 28, 1997, the New Hampshire Public Utilities Commission (NHPUC) issued its Final Plan for transition to a competitive electric market in New Hampshire. The order allowed CECo and E&H, Unitil's New Hampshire retail distribution utilities, to recover 100% of "stranded" costs for a two-year period, but excluded recovery of certain administrative-related charges. 	Northeast Utilities' affiliate, Public Service Company of New Hampshire, appealed the NHPUC order in Federal District Court. A temporary restraining order was issued on March 10, 1997. In June 1997, Unitil was admitted as a Plaintiff Intervenor in the Federal Court proceeding. On June 9, 1998, the Federal Court issued an injunction continuing the freeze on NHPUC efforts to implement restructuring. Several parties have filed interlocutory appeals, and no date has been scheduled for a trial in the federal court. The Company will vigorously pursue its action in the federal court and simultaneously look for ways to resolve issues and bring forth choice to its retail customers. 	In September of 1998, the Company reached a comprehensive restructuring settlement with key parties and filed this voluntary Agreement with the NHPUC. The Agreement was modified on October 20, 1998. In oral deliberations on November 2 and November 18, 1998, the NHPUC imposed conditions to approval of the Settlement which were unacceptable to the Company, and the Settlement was subsequently withdrawn. The component of the Agreement dealing with wholesale rates was filed with the FERC in September 1998, and approved by the FERC in early November. However, implementation will not occur, as the changes were conditioned upon approval by the NHPUC. Unitil continues to participate actively in all proceedings and in several NHPUC-established working groups which will define details of the transition to competition and customer choice. 		NH Pilot Program -- In June 1996, the New Hampshire Retail Competition Pilot Program (Pilot Program), mandated by legislation enacted a year earlier, became operational. During the two-year term of the Pilot Program, up to 3% or some 17,000 New Hampshire electric consumers were allowed to choose from competing electric suppliers, and have this supply delivered across the local utility system. The Company's subsidiary, Unitil Resources, Inc., began competitive marketing efforts in May 1996, and began making sales in June, 1996. The State of New Hampshire recently extended this program beyond the original 24 month period. As of March 1, 1999, Unitil Resources, Inc. is marketing energy competitively to over 700 customers outside the Unitil companies' traditional franchise territories under the Pilot Program. 		Massachusetts (Electric)- On January 15, 1999, the MDTE gave final approval to FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) a choice of energy supplier; b) an option to purchase Standard Offer Service (i.e. state-mandated energy service) provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction. The Plan also provides for FG&E to divest of its generation assets and its portfolio of purchased power contracts. The Company will be afforded full recovery of any transition costs through a non-bypassable retail Transition Charge. 	Pursuant to the Plan, on October 30, 1998, the Company filed with the MDTE a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. The MDTE's January 15, 1999 Order approves the FG&E/Constellation contract, and service thereunder is scheduled to commence on March 1, 1999, and is scheduled to continue through February 28, 2005. This contract is the result of the first successful Standard Offer auction conducted in Massachusetts. 	The January 15 Order also approved the Company's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts. A contract for the sale of FG&E's interest in the New Haven Harbor plant was filed with the MDTE on November 20, 1998. The MDTE's decision is pending. Contracts for the sale of the Company's remaining generating assets and purchased power contracts are expected to be filed with the MDTE in the near future. All such contracts are subject to MDTE approval. GAS UTILITY INDUSTRY RESTRUCTURING AND COMPETITION 	In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were approved by the MDTE and implemented in November of 1998. 	On July 2, 1998 the MDTE established April 1, 1999 as the date by which unbundled gas service would begin to be implemented by all LDCs. On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. That order also set forth the MDTE's decision regarding release by LDCs of their pipeline capacity contracts to competitive marketers. In January of 1999, the LDCs reported to the MDTE that they were continuing to work to develop systems and practices to implement unbundling. The MDTE has not yet responded to the LDCs' report, and it appears unlikely that full implementation will be achieved by the April 1, 1999 target date. 	 ELECTRIC POWER SUPPLY 	New England Power Pool --- FG&E, UPC, CECo, E&H and URI are members of the New England Power Pool (NEPOOL). NEPOOL was formed to assure reliable operation of the bulk power system in the most economic manner for the region. Under the NEPOOL Agreement, 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 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 providing a supportive business environment for the development of a competitive electric marketplace. 	As a result of ongoing legislative and regulatory initiatives which are primarily focused on the deregulation of the generation and supply of electricity and the corresponding development of a competitive market place from which customers could choose their electric energy supplier, the NEPOOL Agreement is being 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 will be traded in open, competitive markets, with transmission access and pricing subject to a regional tariff designed to promote competition among power suppliers. A new capacity market was implemented last year, and the other markets are expected to begin on April 1, 1999. Furthermore, on April 1, 1999 or shortly thereafter, the ISO-NE is scheduled to begin dispatching generating units using a bid-based system rather than the current system of dispatching units based on fuel costs. 	Energy Resources --- Effective April 1, 1998, each electric utility's capability responsibility under the NEPOOL Agreement involves carrying an allocated share of New England capacity requirements which is determined for each month based on regional reliability criteria. Unitil Power Corp., the full requirements supplier to CECo and E&H, had a capability responsibility for December, 1998 of 232.16 MW and a corresponding monthly peak demand of 180.13 MW. FG&E's capability responsibility for December, 1998 was 110.62 MW, with a corresponding monthly peak demand of 85.72 MW. 	To meet the needs of CECo and E&H, Unitil Power Corp. 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. For the twelve months ended December 31,1998, Unitil Power's energy needs were provided by the following fuel sources: nuclear (27%), oil (18%), coal (11%), gas (21%), wood and refuse (4%) , hydro (1%), and system and other (18%). 	FG&E meets its capacity requirements through purchase power contracts and ownership interests in three generating units in which FG&E participates on a tenancy-in-common basis as a nonoperating owner. FG&E'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. For the twelve months ended December 31, 1998, FG&E's energy needs, including generation from joint-owned units, were provided from the following fuel sources: oil (25%), wood (26%), hydro (4%), coal (19%) and nuclear, system and other (26%). 	FG&E has a 4.5% ownership interest, or 20.12 MW, in an oil and natural gas-fired generating plant in New Haven, Connecticut, which is operated by The United Illuminating Company, the plant's majority owner. FG&E also has a 0.1822% ownership interest, or 1.13 MW, in an oil-fired generating plant in Yarmouth, Maine, which is operated by Central Maine Power Company as the majority owner, and a 0.217% ownership interest, or 2.5 MW, in the Millstone 3 nuclear unit operated by Northeast Utilities, parent of the principal owners of that unit. In addition, FG&E operates an oil-fired combustion turbine with a current capability of 26.6 MW under a long-term financing lease. As a result of the aforementioned FG&E Electric Restructuring Plan approved by the MDTE, FG&E will divest of its electric generating assets. (See Management Discussion and Analysis for further discussion of the FG&E Electric Restructuring Plan). 	 Fuel --- Oil: Approximately 25% of FG&E's and 18% of UPC's electric power in 1998 was provided by oil-fired units, some of which are owned by FG&E. 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 19% of FG&E's and 11% of UPC's 1998 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. 	Nuclear: FG&E has a 0.217% ownership interest in Millstone Unit No. 3 (the Unit). The Unit has contracted for certain segments of the nuclear fuel production cycle through various dates. This cycle includes, among other things, mining, enrichment and disposal of used fuel. 	 Pursuant to the Nuclear Waste Policy Act of 1982, the participants in 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. 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 1996 through 1998. Sources of Gas Supply (Expressed as percent of total MMBtu of gas purchased) Natural Gas: 1998 1997 1996 			 Domestic firm............................ 78.4% 82.7% 80.8% Canadian firm............................... 6.4% 5.7% 7.0% Domestic spot market....................... 14.5% 10.5% 10.7% Total natural gas............................. 99.3% 98.9% 98.5% Supplemental gas............................. 0.7% 1.1% 1.5% Total gas purchases........................... 100.0% 100.0% 100.0% Cost of Gas Sold 1998 1997 1996 			 Cost of gas purchased and sold per MMBtu.... $3.30 $3.55 $3.95 Percent Increase (Decrease) from prior year...(7.0)% (10.1)% 30.4% 	As a supplement to pipeline natural gas, FG&E owns a propane air gas plant and a liquefied natural gas (LNG) storage and vaporization facility. These plants are used principally during peak load periods to augment the supply of pipeline natural gas. ENVIRONMENTAL MATTERS 	The Company does not expect that compliance with environmental laws or regulations will have a material effect on its business, or the businesses of its subsidiaries. The Company does not know whether, or to what extent, such regulations may affect it or its subsidiaries by impinging on the operations of other electric and gas utilities in New England. 	Unitil Power Corp. and FG&E purchase wholesale capacity and energy from a diverse group of suppliers using various fuel sources and FG&E has ownership interests in certain generating plants. Some of the purchase power contracts contain cost adjustment provisions that may allow the supplier to pass through environmental remediation costs. The Company has not been informed whether any of these suppliers are likely to incur significant environmental remediation costs and, if so, which if any such costs may be passed through. 	In September 1998, the FG&E signed a memorandum of understanding with the Massachusetts Highway Department and the Massachusetts Department of Environmental Protection that accommodates the construction of a new highway bridge across Sawyer Passway, the Company's former manufactured gas plant (MGP) site. This memorandum satisfies the requirements of the Massachusetts Contingency Plan for temporary closure at this last remaining portion of the site. Specifically, this agreement allows for current FG&E efforts to perform remediation work required as result of bridge construction. Upon completion of site remediation associated with the bridge construction, this last remaining portion of the Sawyer Passway MGP site is expected be closed out and attain the status of temporary closure in late 1999. This temporary closure allows FG&E to monitor the site every five years to determine if a more feasible remediation alternative can be developed and achieved. 	The costs of remedial action at this site are initially funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the MDTE. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site. CAPITAL REQUIREMENTS 	Net capital expenditures increased approximately $0.6 million in 1998 compared to 1997, reflecting higher planned spending for utility customer and distribution system additions and improvements. The decrease of $4.6 million in 1997 compared to 1996 reflected spending, in 1996, for the construction of the Company's new corporate headquarters. The Company also received cash payments of $0.9 million from the State of New Hampshire in 1996, related to the eminent domain taking of is former corporate headquarters for a highway expansion project . 	In 1999, total capital expenditures are expected to approximate $15.7 million. This projection reflects normal capital expenditures for system expansions, replacements and other improvements. FINANCING ACTIVITIES The increase in cash flows in 1998 compared to 1997 reflects higher net borrowings of $6.1 million and increased common stock issued of $0.3 million, net of other items. 	During the year ended December 31, 1998, Concord Electric Company (CECo) sold $10,000,000 of 30-year Series J First Mortgage Bonds at par to an institutional investor, bearing an interest rate of 6.96%. Proceeds were used to repay short-term indebtedness, incurred to fund CECo's ongoing construction programs, and to redeem a higher coupon long-term debt issue prior to its maturity. The redemption of $4,550,000 was on the 9.43% Series H First Mortgage Bonds. 	During the year ended December 31, 1998, Exeter & Hampton Electric Company (E&H) sold $10,000,000 of 30-year Series L First Mortgage Bonds at par to an institutional investor, bearing an interest rate of 6.96%. Proceeds were used to repay short-term indebtedness, incurred to fund E&H's ongoing construction programs, and to redeem two higher coupon long-term debt issues prior to their maturity. The redemptions, which totaled $4,200,000, included $700,000 of 8.5% Series H First Mortgage Bonds, and $3,500,000 of 9.43% Series J First Mortgage Bonds. Additional short-term borrowings were incurred, primarily to fund 1998 costs related to electric industry restructuring in Massachusetts that will be collected in future periods. 	The change in Cash Flows from Financing Activities in 1997 compared to 1996 reflects a decrease in borrowings due to the repayment of short-term debt. Higher short-term borrowings in 1996 were primarily due to funding of the timing difference (under collection) between payments on fuel, purchased power and purchased gas costs and the corresponding recovery of these costs in revenue billed under periodic cost recovery mechanisms as well as the construction financing of the Company's new corporate headquarters. 	The Company currently has unsecured committed bank lines for short-term debt aggregating $25,000,000 with four banks for which it pays commitment fees. At December 31, 1998, the unused portion of the committed credit lines outstanding was $5,000,000. The average interest rate on all short-term borrowings were 5.95% and 5.98% during 1998 and 1997, respectively. EMPLOYEES 	As of December 31, 1998, the Company and its subsidiaries had 324 full-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 101 employees represented by labor unions. In 1998, E&H reached a new three year pact with its employees covered by a collective bargaining agreement which will expire effective May 31, 2000. In 1997, CECo reached a new three year pact with its employees covered by a collective bargaining agreement which will expire effective May 31, 2000. In 1998, FG&E reached a one year pact with its employees covered by collective bargaining agreements which will expire effective May 31, 2000. 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. 	The Company and its subsidiaries, where applicable, have in force funded Retirement Plans and related Trust Agreements providing retirement annuities for participating employees at age 65. The Company's policy is to fund the pension cost accrued (see Note 9 of Notes to Consolidated Financial Statements contained in Part II, Item 8). 	The Company established a new Key Employee Stock Option Plan (KESOP) scheduled to begin in 1999, which provides for the granting of options to key employees. The number of shares granted under this plan, as well as the terms and conditions of each grant, are determined by the Board of Directors, subject to plan limitations. All options granted under the KESOP vest upon grant (See Exhibit 10.12). 	The original KESOP plan that began in 1989 included a provision that no options could be issued after March, 1999. All of the options that were granted under the original plan were exercised as of March 31, 1999 except for 25,000 which remain outstanding. 	The Company established a the "Unitil Corporate Management Incentive Plan" which provides key management employees of Unitil Corporation and its subsidiaries with incentives related to the performance of the Corporation (See Exhibit 10.13). EXECUTIVE OFFICERS OF THE REGISTRANT 	The names, ages and positions of all of the executive officers of the Company as of March 1, 1999 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 selected. Officers of the Company also hold various Director and Officer positions with subsidiary companies. Name, Age and Position Business Experience During Past 5 years 		 Robert G. Schoenberger, 48, Chairman of the Board of Directors and Chief Executive Officer		Mr. Schoenberger has been Chairman of the Board and Chief Executive Office of 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. Prior to 1993, he was Executive Vice President - Finance and Administration, also at NYPA (state owned public power enterprise). 		 Michael J. Dalton, 58, President and Chief Operating Officer Mr. Dalton has been a Director, President and Chief Operating Officer of the Company since its incorporation in 1984. 		 Anthony J. Baratta, Jr., 55, Senior Vice President and Chief Financial Officer Mr. Baratta has been Senior Vice President and Chief Financial Officer of Unitil since 1998. Prior to his employment with Unitil, Mr. Baratta was Executive Vice President and Chief Financial Officer at New World Power Corporation. From 1990 to 1995, Mr. Baratta was President, Chief Executive Officer and Director at HYDRA-CO Enterprises, Inc., a wholly-owned subsidiary of Niagara Mohawk Power Corp., and prior to that held several senior management positions within Niagara Mohawk. 		 Mark H. Collin, 40, Treasurer and Secretary and Vice President, Unitil Service		Mr. Collin was appointed Treasurer and Secretary in January, 1998. Mr. Collin has been the System subsidiary Treasurer and Vice President of Unitil Service Corp. since 1992. 		 James G. Daly, 41 Senior Vice President Energy Resources Unitil Service 		Mr. Daly has been Senior Vice President of Unitil Service since 1994. Mr. Daly was Vice President of Unitil Service Corp. from 1992 to 1994. 		 George R. Gantz, 47 Senior Vice President Business Development Unitil Service		Mr. Gantz has been Senior Vice President of Unitil Service since 1994. Mr. Gantz was Vice President of Unitil Service from 1989 to 1994. Item 2. Properties 	CECo's distribution service center building and adjoining administration building, totaling 37,560 square feet of office, warehouse and garage area, are located on land in the City of Concord owned by CECo in fee. CECo's sixteen electric distribution substations constitute 100,790 kVA of capacity for the transformation of electric energy from the 34.5 kV transmission voltage to primary distribution voltage levels. The electric substations are, with one exception, located on land owned by CECo in fee. The sole exception is located on land occupied pursuant to a perpetual easement. 	CECo has in excess of 34 pole miles of 34.5 kV electric transmission facilities located, with minor exceptions, either on land owned by CECo in fee or on land occupied pursuant to perpetual easements. CECo also has a total of approximately 632 pole miles of overhead electric distribution lines and a total of approximately 44 conduit bank miles (118 cable 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 CECo without objection by the owners. In the case of certain distribution lines, CECo 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, CECo 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 CECo (with certain exceptions) and its franchises are subject to the lien of its Indenture of Mortgage and Deed of Trust, as supplemented, under which the respective series of First Mortgage Bonds of CECo are outstanding. 	E&H's distribution and engineering service center building is located on land owned by E&H in fee. E&H's fourteen electric distribution substations, including a 5,000 kVA mobile substation, constitute 91,400 kVA of capacity for the transformation of electric energy from the 34.5 kV transmission voltage to primary distribution voltage levels. The electric substations are located on land owned by E&H in fee. 	E&H has in excess of 68 pole miles of 34.5 kV electric transmission facilities located on land either owned or occupied pursuant to perpetual easements. E&H also has a total of approximately 713 pole miles of overhead electric distribution lines and a total of approximately 87 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 E&H without objection by the owners. In the case of certain distribution lines, E&H owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone and telegraph companies. 	Certain physical properties of E&H and its franchises are subject to the lien of its Indenture of Mortgage and Deed of Trust, as supplemented, under which the respective series of First Mortgage Bonds of E&H 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. The Company has entered into agreements for joint ownership with others of one nuclear and two fossil fuel generating facilities. As a result of the aforementioned FG&E electric restructuring plan that was approved by the MDTE, FG&E will divest its electric generating assets. At December 31, 1998, the electric properties of the Company consisted principally of 69 miles of transmission lines, 16 transmission and distribution substations with a total capacity of 562,900 kVA and 467 miles of distribution lines. 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. (See Business - Electric Power Supply and Gas Supply above for additional information regarding the Company's plants, facilities and gas mains and services.) 	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 their intended uses. Item 3. Legal Proceedings 	The Company is involved in legal and administrative proceedings and claims of various types which arise in the ordinary course of business. 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 PART II Item 5. Market For Registrant's Common Equity and Related Stockholder Matters Common Stock Data Dividends Paid Per Common Share 1998 1997 				 1st Quarter $0.34 $0.335 2nd Quarter $0.34 $0.335 3rd Quarter $0.34 $0.335 4th Quarter $0.34 $0.335 The Year $1.36 $1.34 				 1998 1997 High/Ask Low/Bid High/Ask Low/Bid 1st Quarter 27 1/4 23 5/8 21 1/8 18 5/8 2nd Quarter 25 5/8 22 1/4 21 3/8 18 3/4 3rd Quarter 24 3/8 21 1/8 23 3/8 20 3/8 4th Quarter 28 13/16 22 3/4 24 5/16 21 1/8 Item 6. Selected Financial Data 1998 1997 1996 1995 1994 					 Consolidated Statements of Earnings (000's) Operating Income $15,306 $15,562 $14,273 $14,225 $13,754 Non-operating Expense (Income) 156 160 (627) 217 64 Income Before Interest Expense 15,150 15,402 14,900 14,008 13,690 Interest Expense, Net 6,901 7,167 6,171 5,639 5,652 Net Income 8,249 8,235 8,729 8,369 8,038 Dividends on Preferred Stock 274 276 278 284 291 Net Income Applicable to Common Stock $7,975 $7,959 $8,451 $8,085 $7,747 					 Balance Sheet Data (000's)					 Utility Plant (Original Cost) $209,462 $219,475 $207,545 $190,177$178,777 Total Assets 376,835 238,531 232,108 211,702 204,521 Capitalization and Short-term Debt:					 Common Stock Equity $75,351 $71,644 $67,974 $63,895 $59,997 Preferred Stock 3,843 3,891 3,891 3,999 4,094 Long-Term Debt 75,222 68,366 62,211 63,505 65,580 Total Capitalization $154,416 $143,901 $134,076 $131,399$129,671 					 Capitalization Ratios:					 Common Stock Equity 49% 50% 51% 49% 46% Preferred Stock 2% 3% 3% 3% 3% Long-Term Debt 49% 47% 46% 48% 51% Short-Term Notes Payable $20,000 $18,000 $21,400 $2,700 --- 					 Common Stock Data (000's)					 Shares of Common Stock (Year-End) 4,575 4,464 4,384 4,330 4,268 Shares of Common Stock (Average) 4,506 4,413 4,354 4,299 4,234 Per Share Data					 Basic Earnings Per Average Share $1.77 $1.80 $1.94 $1.88 $1.83 Diluted Earnings per Average Share $1.72 $1.76 $1.89 $1.85 $1.80 Dividends Paid Per Share (Year-End) $1.36 $1.34 $1.32 $1.28 $1.24 Book Value Per Share (Year-End) $16.47 $16.05 $15.50 $14.76 $14.06 					 Electric and Gas Statistics 1998 1997 1996 1995 1994 Electric Sales - (MWH) 1,540,96 1,491,103 1,532,015 1,401,292 1,358,165 Customers Served - Year End 92,495 91,492 89,865 88,316 86,782 Gas Sales - (000's of Firm Therms) 22,027 23,716 24,508 22,303 23,057 Customers Served - Year End 14,915 14,943 14,848 14,846 15,012 	 	 Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations FINANCIAL HIGHLIGHTS - 1998 	 	1998 was a year of significant changes for the electric and gas utility operations of Unitil Corporation ("Unitil" or the "Company") in the state of Massachusetts. Changes in the Massachusetts regulatory environment had a major impact on the Company's financial position at December 31, 1998, and those regulatory changes have created a new definition of utility operations at Unitil's Massachusetts subsidiary, Fitchburg Gas and Electric Light Company (FG&E), on a going-forward basis. 	As discussed below, several major events shaped our financial position and results of operations in 1998. Electric utility industry restructuring was implemented in Massachusetts with a 10% rate reduction effective March 1, 1998. Under FG&E's restructuring plan (the "Plan"), which received final approval on January 15, 1999, FG&E will complete the auction of its electric generation and power supply portfolio and will receive 100% recovery of its stranded costs. 	FG&E also was granted its first Gas Base Rate adjustment in 14 years, an annual increase of approximately $1 million or 7%, effective December 1, 1998. Even after the increase, the FG&E's gas rates are among the lowest in Massachusetts. Also, on November 1, 1998, Gas utility industry bills were "unbundled" in Massachusetts, and, based on an order issued by the Massachusetts Department of Telecommunications and Energy (MDTE) on February 1, 1999, FG&E expects to begin transitioning out of the gas merchant function for gas supply under a multi-year phase-in of a restructured natural gas industry in Massachusetts. 	 Finally, the early 1998 record-setting weather conditions (the warmest winter in at least 103 years) had a negative impact on the Company's financial results, due to lower gas and electric sales in the first quarter of 1998. UNITIL RECEIVES FINAL ORDER ON FG&E'S ELECTRIC RESTRUCTURING PLAN IN MASSACHUSETTS (SUBSEQUENT EVENT) 	On January 15, 1999, the MDTE issued an order (the "Order") approving FG&E's Electric Restructuring Plan with certain modifications. Electric utility industry restructuring in Massachusetts became effective on March 1, 1998, ("Choice Date"). On that date, FG&E implemented open retail access, under its Plan, and all of FG&E's customers gained the right to choose their electricity supplier. Regardless of the supplier chosen, FG&E will continue to deliver electricity to all of its customers within its distribution system, which remains a regulated business. On Choice Date, FG&E's customers received a 10% rate discount. Since Choice Date, FG&E has been authorized to earn a lower return on its generation-related investments. FG&E is required to provide an additional 5% discount upon the earlier of completion of its divestiture of generation investments or September 1, 1999. 	FG&E has been allowed recovery of its restructuring transition costs, estimated at $140 million, including its above-market or stranded generation and power supply-related costs, via a non-bypassable uniform Transition Charge. Estimated Regulatory Assets, based upon the Transition Charges to be collected according to the Plan, have been recorded together with the recognition of certain liabilities related to power supply contracts and generation assets. The Company's estimate, based on the competitive bidding process, of the above-market portion of its power supply contract obligations is approximately $129 million. The net book value of its investment in other generation assets, principally investments in Joint Owned generation facilities, is approximately $11 million. Also, as a result of the competitive bidding process, FG&E expects to receive approximately $5 million in proceeds from the disposition of its investment in a Joint Owned generation facility. Deferred Tax Assets and Liabilities related to the adjustments above, are reflected in the Company's Balance Sheet. EARNINGS AND DIVIDENDS Net income for 1998 was $8.0 million, slightly above 1997 earnings. Lower interest expense, lower operating expenses, and a lower effective income tax rate contributed positively to the Company's earnings performance. Sales revenues in 1998 were comparable to 1997, as system growth was offset by a mild winter heating season. 	Basic earnings per average common share were $1.77 for the year ended December 31, 1998, compared to $1.80 and $1.94 for 1997 and 1996, respectively. The decrease in 1998 from 1997, on a per share basis, is attributable to higher common shares outstanding in 1998 which were issued through the Company's Dividend Reinvestment and Stock Purchase Plans (see Capital Requirements and Liquidity and Note 2). Diluted earnings per share were $1.72, $1.76 and $1.89 for 1998, 1997 and 1996, respectively. The average return on common equity was 10.9%, 11.4%, and 12.8% in 1998, 1997, and 1996, respectively. 	Unitil's common stock dividends in 1998 were $1.36 per share, an increase of 1.5% over 1997's annual dividend of $1.34 per share. This annual dividend of $1.36 in 1998 resulted in a payout ratio of 77%. At its January 1999 meeting, the Unitil Board of Directors increased the quarterly dividend rate by an additional 1.5%, resulting in the current effective annualized dividend of $1.38 per share. OPERATING REVENUES-ELECTRIC 	Unit (KWH) Sales - Unitil's total electric kilowatt-hour sales increased by 3.3% in 1998 compared to 1997, primarily due to system growth and increased activity of a major industrial customer, offset by the milder winter weather in early 1998. The 1998 winter heating season was 16% warmer than normal and 7% warmer than the same period in 1997. 		 	Sales to residential customers increased by 1.4% in 1998 compared to 1997, and were 2.7% higher than 1996 sales. These energy sales increases are due to the expansion of our residential customer base within our service territories and overall healthy regional economic conditions. 	Commercial and industrial sales of electricity in 1998 were boosted by the resumption of operations of a major industrial customer which had been curtailed through the first quarter of 1998. Electric energy sales to all commercial and industrial customers were up 4.4% in 1998, due to a strong economy and the fact that the major customer mentioned above had curtailed operations for all of 1997. 1998 sales are lower by 0.6% compared to 1996, as the major customer mentioned above was in full operation for most of 1996. 	 	The following table details total kilowatt-hour sales for the last three years by major customer class: KWH Sales (000's) 1998 1997 1996 					 Residential 541,492 533,907 527,107 Commercial 415,482 400,760 396,475 Industrial 583,994 556,436 608,433 Total KWH Sales 1,540,968 1,491,103 1,532,015 	 	Electric utility rates before and after industry restructuring in Massachusetts show the significant change in the way the Company's combined electric and gas utility, FG&E, provides electric utility service to its customers. Prior to March 1, 1998, FG&E provided all of its customers with "bundled" electric service that reflected its obligation to provide energy supply and the delivery of that energy to and across its system. 	After March 1, 1998, FG&E "unbundled" its prices for energy supply, transmission and distribution (or delivery services), and for the first time allowed customers to choose an alternative energy supplier from the competitive market. FG&E will continue to provide for the delivery of all energy supply across its system. Customers' monthly bills, after March 1, reflect these unbundled prices and individually display energy supply, Transition Charges, delivery, and other related services. 	As part of the transition to the new market structure, FG&E will offer Standard Offer Service ("SOS") to its customers who elect not to choose a competitive energy supplier, for up to 7 years. FG&E has contracted with an energy supplier to provide SOS to its customers at no profit to FG&E. One of the purposes of this service is to give customers a power supply price from which they can measure competitive offers before they are ready to enter the competitive market. 	Two other important features of FG&E's unbundled rates are: 1) the Transition Charge component of the bill, which is designed to recover FG&E's transition costs resulting from restructuring over approximately 12 years, and 2) the provision of a total rate discount of 10%. FG&E will provide an additional 5% discount upon the earlier of completion of its divestiture of generation investments or September 1, 1999. 	Electric Operating Revenue decreased by $0.3 million, or 0.2%, in 1998 compared to 1997. The impact of higher sales volume across all customer classes was offset by lower electric rates, due to the 10% discount mandated in Massachusetts, and overall lower energy supply prices. Energy supply costs are normally collected from customers through periodic cost recovery adjustment mechanisms. Changes in energy supply prices do not affect net income, as they normally mirror corresponding changes in energy supply costs. Electric Operating Revenue (000's) 1998 1997 1996 				 Residential $57,242 $57,947 $57,124 Commercial 44,122 44,170 44,076 Industrial 48,275 47,856 48,496 Total Operating Revenue $149,639 $149,973 $149,696 OPERATING REVENUES-GAS 	Unit (Therm) Sales - Total firm therm gas sales decreased 7.1% in 1998 when compared to 1997. The decrease in sales is primarily attributable to the mild winter heating season, which was the warmest in the 103 years such data has been kept. Sales to residential and commercial customers, which are most sensitive to weather, decreased by 10.6% and 7.0%, respectively, while sales to industrial customers were up by 3.9%. Total firm therm sales decreased 10.1% in the two-year period from 1996 to 1998, as the winter heating season in 1996 was significantly colder than in 1998. 	The following table details total firm therm gas sales for the last three years by major customer class: Firm Therm Gas Sales (000's) 1998 1997 1996 			 Residential 11,656 13,038 13,835 Commercial 6,162 6,628 6,728 Industrial 4,209 4,050 3,945 Total Therm Sales 22,027 23,716 24,508 	Gas Operating Revenues, which represent approximately 10% of Unitil's total operating revenues, decreased by $2.7 million, or 13.8%, in 1998 compared to 1997. This decrease is primarily attributable to the decrease in firm therm gas sales related to weather, as discussed above. In December 1998, FG&E concluded its gas base rate case, which resulted in a rate increase of approximately 7.0%. Concurrent with the rate increase, FG&E "unbundled" its gas bills, showing a separate itemization of all delivery service charges, as well as supplier service charges. This will allow customers to compare their current gas supply rates against offers they receive from competitive suppliers, once competition begins in 1999 (see Regulatory Matters). Gas Operating Revenue (000's) 1998 1997 1996 				 Residential $8,581 $10,179 $10,654 Commercial 4,140 4,784 4,781 Industrial 4,288 4,766 5,670 Total Operating Revenue $17,009 $19,729 $21,105 OPERATING REVENUES-OTHER 	Other Revenue declined from $36,000 in 1997 to $30,000 in 1998. The decrease in Other Revenue from $45,000 in 1996 is the result of the termination of an administrative services agreement between Unitil Resources, Inc. and a principal customer. OPERATING EXPENSES 	Fuel and Purchased Power expense is the cost of power supply, including fuel used in electric generation and the price of wholesale energy and capacity, that meets the Unitil's electric energy requirements. Fuel and purchased power expenses (normally recoverable from customers through periodic cost recovery adjustment mechanisms) decreased $1.4 million, or 1.4% in 1998 compared to 1997. The change reflects a decrease in wholesale power prices offset by an increase in the Company's total energy requirements in 1998. The combined power supply portfolio of the Unitil is comprised of a variety of resources. For 1998, the portfolio was comprised of: 14% owned generation; 75% purchased power from utilities; and 11% purchased power from non-utility generators. 	The Company anticipates that power supply-related costs and corresponding revenues will decline in future years, as customers choose alternate competitive energy suppliers under a restructured electric utility industry. 	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. Purchased Gas costs decreased by approximately $2.2 million or 18.0% in 1998 as compared to 1997, reflecting a decrease in therms purchased in 1998 and lower wholesale gas prices in 1998. Gas purchased for resale decreased by $3.4 million, or 25.9% in the two-year period from 1996 to 1998, based on lower wholesale prices and a decrease in therms purchased due to warmer weather. 		Under Order 636, the Federal Energy Regulatory Commission (FERC) has allowed gas pipeline suppliers to recover prudently incurred costs resulting from the transition into a deregulated environment. FG&E has been incurring FERC-approved transition charges from its natural gas pipeline supplier since 1992. Through the end of 1998, the amount of transition costs incurred by the Company totaled approximately $3.4 million. These costs are being recovered directly from gas customers through the Cost of Gas Adjustment mechanism. The Company does not expect to incur any additional transition costs in 1999. 	Operation and Maintenance expense, which includes utility operating costs, Conservation and Load Management program expenditures and the Company's share of operating costs related to power production at the generation facilities in which the Company has a partial ownership interest, increased by approximately $0.1 million, or 0.4% in 1998 compared to 1997. The increase in Operation and Maintenance expenses compared to last year reflects higher administrative costs associated with filing and implementation of FG&E's restructuring plan and energy supply divestiture efforts. These additional expenses related to industry restructuring in Massachusetts are partially offset by revenues accrued to be recovered, in the future, upon divestiture of the energy supply portfolio, or through other rate cost reconciliation mechanisms. 	In 1997, Operation and Maintenance expense decreased from 1996 by approximately $0.6 million, or 2.3%, due to lower distribution operating expenses partially offset by the higher costs of power production. DEPRECIATION, AMORTIZATION AND TAXES 	Depreciation and Amortization expense increased $0.8 million, or 9.0%, for 1998 over the prior year due to the accelerated write-off of electric generating assets, in accordance with FG&E's restructuring plan. 	Federal and State Income Taxes decreased in 1998 compared to 1997 by $0.5 million. This result reflects lower net income before taxes, as well as higher amortization of flow-through Investment Tax Credits in 1998. 	Local Property and Other Taxes increased $0.3 million, or 5.0%, in 1998. This increase mainly reflects higher payroll taxes slightly offset by lower local property taxes. Local property and other taxes increased in 1997, compared to 1996, by 5.9%. NON-OPERATING INCOME/EXPENSES 	Non-Operating Expenses/Income in 1998 were relatively unchanged from 1997, as there was a continuation of community service programs throughout the Unitil,s service territory. In 1996, Non-Operating Income of $0.6 million reflects the one-time gain on the sale of the Company's former corporate headquarters. INTEREST EXPENSE 	Interest Expense, Net decreased $0.3 million or 3.7% in 1998 from 1997, primarily reflecting an increase in accrued interest income associated with deferred rate recovery mechanisms and interest on refunds received from suppliers. Interest expense remained flat, as increased borrowing levels were offset by lower interest rates. The increase in interest expense for 1997 over 1996 was a result of higher interest rates and the construction financing of the Company's new corporate headquarters. CAPITAL REQUIREMENTS AND LIQUIDITY 	Unitil requires capital for the acquisition of property, plant and equipment in order to improve, protect, maintain and expand its electric and gas distribution systems, and to improve customer service operations and capabilities. The capital necessary to meet these requirements is derived primarily from the Company's retained earnings and through the sale of shares of common stock through the Company's Dividend Reinvestment and Stock Purchase Plans. When internally-generated funds are not available, it is the Company's policy to borrow funds on a short-term basis to meet the capital requirements of its subsidiaries and, when necessary, to repay short-term debt through the issuance of permanent financing. 	Cash Flows from Operating Activities decreased by $3.3 million in 1998, after increasing by $10.3 million in 1997. 	The decrease in 1998 compared to 1997 was primarily due to higher working capital needs at the year-end Balance Sheet date, as a result of timing differences of payments on energy supply contracts, as well as increased refunds of customer deposits. 	In 1997 compared to 1996, $8.3 million of the increase in operating cash flow was the result of a decrease in the timing difference (undercollection) between the payment on fuel, purchased power and purchased gas costs, and the corresponding recovery of these costs in revenue billed under periodic cost recovery mechanisms. The balance of the increase reflects other changes in the Company's working capital requirements as detailed in the Consolidated Statements of Cash Flows. Operating Activities (000's) 1998 1997 1996 Cash Provided by Operating Activities $13,215 $16,555 $6,260 	Cash Flows Used in Investing Activities increased approximately $0.6 million in 1998 reflecting higher planned spending for utility customer and distribution system additions and improvements. The decrease of $4.6 million in 1997 compared to 1996, reflected spending, in 1996, for the construction of the Company's new corporate headquarters. The Company also received cash payments of $0.9 million from the State of New Hampshire in 1996, related to the eminent domain taking of is former corporate headquarters for a highway expansion project. Investing Activities (000's) 1998 1997 1996 Cash Used in Investing Activities $(14,463) $(13,887 $(18,484) 	 	 	Cash Flows from Financing Activities increased by $6.2 million in 1998 compared to 1997. This increase reflects higher net borrowings of $6.1 million and increased common stock issued of $0.3 million, net of other items. 	On September 3, 1998, Concord Electric Company (CECo) sold $10,000,000 of 30-year Series J First Mortgage Bonds at par to an institutional investor, bearing an interest rate of 6.96%. Proceeds were used to repay short-term indebtedness, incurred to fund CECo's ongoing construction program, and to redeem a higher coupon long-term debt issue prior to its maturity. The redemption of $4,550,000 was on the 9.43% Series H First Mortgage Bonds. 	On September 3, 1998, Exeter & Hampton Electric Company (E&H) sold $10,000,000 of 30-year Series L First Mortgage Bonds at par to an institutional investor, bearing an interest rate of 6.96%. Proceeds were used to repay short-term indebtedness, incurred to fund E&H's ongoing construction program, and to redeem two higher coupon long-term debt issues prior to their maturity. The redemptions, which totaled $4,200,000, included $700,000 of 8.5% Series H First Mortgage Bonds, and $3,500,000 of 9.43% Series J First Mortgage Bonds. 	Additional short-term borrowings were incurred, primarily to fund 1998 costs related to electric industry restructuring in Massachusetts that will be collected in future periods. 	During 1998, the Company raised $1.0 million of additional common equity capital through the issuance of 43,862 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase plans. The Company raised $1.0 million of additional common equity capital in 1997 and $1.1 million of additional equity capital in 1996, through the issuance of 51,529 and 52,081 shares, respectively of common stock in connection with these plans. The Company also raised $566,000, $242,000, and $20,000 of additional common equity capital in 1998, 1997, and 1996, respectively, through the issuance of shares, as a result of the exercise of options granted under the Company's Key Employee Stock Option Plan (KESOP). The total number of shares issued under the KESOP plan in 1998, 1997 and 1996 were 66,951 shares, 28,222 shares and 2,400 shares, respectively. 	The change from 1996 to 1997 reflects a decrease in borrowings, due to the repayment of short-term debt. Higher short-term borrowings in 1996 were primarily due to funding of the timing difference (undercollection) between payments on fuel, purchased power and purchased gas costs and the corresponding recovery of these costs in revenue billed under periodic cost recovery mechanisms, as well as the construction financing of the Company's new corporate headquarters. Financing Activities (000's) 1998 1997 1996 Cash From Financing Activities $2,994 $(3,234) $11,729 	 Subsequent Event - FG&E Financing On January 26, 1999, FG&E sold $12,000,000 of long-term notes at par to institutional investors, bearing an interest rate of 7.37%. Proceeds were used to repay short-term indebtedness, incurred to fund FG&E's ongoing construction programs. REGULATORY MATTERS 	Restructuring and Competition -Regulatory activity surrounding restructuring and competition continues in both Massachusetts and New Hampshire. March 1, 1998 was "Choice Date" or the beginning of competition for all electric consumers in Massachusetts, while New Hampshire's "Choice Date" slipped past both the proposed date of January 1, 1998, and the legislature's mandated July 1, 1998. Currently, approximately 10% of New Hampshire electric consumers can choose their electric supplier. The ability to choose for the remaining 90% is currently the subject of a federal court preliminary injunction (see below). 	 Massachusetts gas industry restructuring plans continue to be under development. The MDTE, gas utilities and other stakeholders began a collaborative effort in late 1997 to develop solutions to the many issues that surround restructuring the local natural gas distribution business. 	Unitil has been preparing for electric and gas industry restructuring by developing transition plans that will move its utility subsidiaries into this new market structure in a way that will ensure fairness in the treatment of the Company's assets and obligations that are dedicated to the current regulated franchises and, at the same time, provide choice for all customers. 	Massachusetts (Electric)- On January 15, 1999, the MDTE gave final approval to FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) a choice of energy supplier; b) an option to purchase Standard Offer Service (i.e. state-mandated energy service) provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction. The Plan also provides for FG&E to divest generation assets and its portfolio of purchased power contracts. The Company will be afforded full recovery of any transition costs through a non-bypassable retail Transition Charge. 	Pursuant to the Plan, on October 30, 1998, the Company filed with the MDTE a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. The MDTE's January 15, 1999 Order approves the FG&E/Constellation contract, and service thereunder is scheduled to commence on March 1, 1999, and is scheduled to continue through February 28, 2005. This contract is the result of the first successful Standard Offer auction conducted in Massachusetts. 	The January 15 Order also approved the Company's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts. A contract for the sale of FG&E's interest in the New Haven Harbor plant was filed with the MDTE on November 20, 1998. The MDTE's decision is pending. Contracts for the sale of the Company's remaining generating assets and purchased power contracts are expected to be filed with the MDTE in the near future. All such contracts are subject to MDTE approval. 	Massachusetts (Gas) -In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were approved by the MDTE and implemented in November of 1998. 	On July 2, 1998 the MDTE established April 1, 1999 as the date by which unbundled gas service would begin to be implemented by all LDCs. On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. That order also set forth the MDTE's decision regarding release by LDCs of their pipeline capacity contracts to competitive marketers. In January of 1999, the LDCs reported to the MDTE that they were continuing to work to develop systems and practices to implement unbundling. The MDTE has not yet responded to the LDCs' report, and it appears unlikely that full implementation will be achieved by the April 1, 1999 target date. 	New Hampshire - On February 28, 1997, the New Hampshire Public Utilities Commission (NHPUC) issued its Final Plan for transition to a competitive electric market in New Hampshire. The order allowed CECo and E&H, Unitil's New Hampshire retail distribution utilities, to recover 100% of "stranded" costs for a two-year period, but excluded recovery of certain administrative-related charges. 	Northeast Utilities' affiliate, Public Service Company of New Hampshire, appealed the NHPUC order in Federal District Court. A temporary restraining order was issued on March 10, 1997. In June 1997, Unitil was admitted as a Plaintiff Intervenor in the Federal Court proceeding. On June 9, 1998, the Federal Court issued an injunction continuing the freeze on NHPUC efforts to implement restructuring. Several parties have filed interlocutory appeals, and no date has been scheduled for a trial in the federal court. The Company will vigorously pursue its action in the federal court and simultaneously look for ways to resolve issues and bring forth choice to its retail customers. 	In September of 1998, the Company reached a comprehensive restructuring settlement with key parties and filed this voluntary Agreement with the NHPUC. The Agreement was modified on October 20, 1998. In oral deliberations on November 2 and November 18, 1998, the NHPUC imposed conditions to approval of the Settlement which were unacceptable to the Company, and the Settlement was subsequently withdrawn. The component of the Agreement dealing with wholesale rates was filed with the FERC in September 1998, and approved by the FERC in early November. However, implementation will not occur, as the changes were conditioned upon approval by the NHPUC. Unitil continues to participate actively in all proceedings and in several NHPUC-established working groups which will define details of the transition to competition and customer choice. 	Rate Cases -The last formal regulatory hearings to increase base electric rates for Unitil's three retail operating subsidiaries occurred in 1985 for Concord Electric Company, 1984 for Fitchburg Gas and Electric Light Company and 1981 for Exeter & Hampton Electric Company. 	On May 15, 1998, FG&E filed a gas base rate case with the MDTE. After evidentiary hearings, the MDTE issued an Order allowing FG&E to establish new rates, effective November 30, 1998, that would produce an annual increase of approximately $1.0 million in gas revenues. However, as part of the proceeding, the Attorney General of the Commonwealth of Massachusetts alleged that FG&E had double-collected fuel inventory finance charges, since 1987, and requested that the MDTE require FG&E to refund approximately $1.6 million to its customers. The Company believes that the Attorney General's claim is without merit and that a refund is not justified or warranted. The MDTE stated its intent to open a separate proceeding to investigate the Attorney General's claim. 	A majority of the Company's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas and energy efficiency program cost recovery mechanisms. Restructuring will continue to change the methods of how certain costs are recovered from customers and from suppliers. Transition costs, Standard Offer Service and Default Service power supply costs, internal and external transmission service costs and energy efficiency and renewable energy program costs for FG&E are being recovered via fully reconciling rate adjustment mechanisms in Massachusetts. 	Millstone Unit No. - FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. On March 30, 1996, as a result of an engineering evaluation completed by the operator, Northeast Utilities, Millstone 3 was taken out of service. NRC authorization for restart was given on June 29, 1998. Millstone 3 began producing electric power in early July, 1998 and reached full output on July 15, 1998. The unit remains on the NRC's Watch List. During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E had been incurring approximately $35,000 per month in replacement power costs, and had been recovering those costs through its fuel adjustment clause, which will be subject to review and approval by the MDTE. 	In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. The arbitration and legal cases are proceeding. 	Environmental Matters - In September 1998, the FG&E signed a memorandum of understanding with the Massachusetts Highway Department and the Massachusetts Department of Environmental Protection that accommodates the construction of a new highway bridge across Sawyer Passway, the Company's former manufactured gas plant (MGP) site. This memorandum satisfies the requirements of the Massachusetts Contingency Plan for temporary closure at this last remaining portion of the site. Specifically, this agreement allows for current FG&E efforts to perform remediation work required as result of bridge construction. Upon completion of site remediation associated with the bridge construction, this last remaining portion of the Sawyer Passway MGP site is expected to be closed out and attain the status of temporary closure in late 1999. This temporary closure allows FG&E to monitor the site every five years to determine if a more feasible remediation alternative can be developed and achieved. 	The costs of remedial action at this site are initially funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the MDTE. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site. 	Market Risk - Although Unitil's utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of fuel and gas costs in rates. Consequently, there is limited commodity price risk after consideration of the related rate-making. As the utility industry deregulates, the Company will be divesting its commodity-related energy businesses and therefore will be further reducing its exposure to commodity-related risk. YEAR 2000 SOFTWARE COMPLIANCE DISCUSSION 	The Company recognizes the need to ensure its operations are not adversely affected by software or device failures related to the Year 2000 date recognition problem, (the "Y2K Issues"). Specifically, Y2K Issues would arise when software applications, or devices with embedded chips, fail to correctly recognize and process the year 2000 and beyond. Certain software applications and devices are certified to recognize and process date references to the year 2000 and beyond and they are deemed to be Year 2000 compliant, ("Year 2000 Compliance"). Potential software failures could create incorrect calculations, among other errors, and they present a risk to the integrity of our Company's financial systems and the reliability of our operating systems. In order to minimize the risk of disruption to our business operations, the Company is taking the actions described below, including communicating with suppliers, dealers, financial institutions and others with which it does business, to coordinate the identification, evaluation, remediation and testing of possible Y2K Issues which may affect the Company 	The Company has established a centralized task force to identify and implement necessary changes to the Company's internal computer systems, controlling hardware devices and software applications in order to achieve Year 2000 Compliance for those systems. The remediation of Y2K Issues and testing of all critical components of the Company's internal systems is scheduled to be completed by June 30, 1999. 	The Company has also established processes for evaluating and managing the risks and possible costs associated with Y2K Issues which may exist in systems external to the Company's operations, but could affect the Company's operations indirectly. The Company has already directed efforts to notify our critical vendors and suppliers about Y2K Issues which may affect our operations, and most are already providing important information about the Year 2000 readiness of their organizations. Testing of certain critical systems has already begun, in conjunction with our key suppliers and vendors, and the Company is planning to develop contingency plans in circumstances where assurance of Year 2000 Compliance cannot be obtained. 	The Company currently estimates it will invest in the range of $250,000 to $500,000 plus internal costs, over the cost of normal software upgrades and replacements to achieve Year 2000 Compliance. These additional capital outlays include costs to replace certain devices and software, and the costs for consultants to assist us with software programming and testing. 	Unitil relies on the proper operation of a regional network of systems and devices to transport and distribute electricity and gas to its customers. Any disruption in those systems caused by Y2K Issues could interrupt the reliable delivery of electric and gas service through our Distribution Operating Companies. Some of these software systems and devices belong to other companies and are beyond the control of Unitil to ensure that they are properly remediated for Year 2000. However, several agencies, including the Department of Energy, The New England ISO, and The National Electricity Reliability Council, have active Year 2000 programs in place. These programs will ensure that member companies are actively and comprehensively dealing with any Year 2000 Issues in their supply, generation, transportation and distribution facilities and systems. Unitil participates in these groups and currently believes that satisfactory progress is being made and will continue to be made to ensure a reliable supply and delivery of energy. Furthermore, these groups plan to establish contingency plans to cover delivery difficulties during key Year 2000 dates. The Company also plans to work with local, state and regional agencies and other utility companies to ensure that appropriate contingency plans are in place for energy supply and delivery systems which could be affected by Year 2000 difficulties. 	In addition, while the Company currently anticipates that its own mission-critical systems will be Year 2000 Compliant in a timely fashion, it cannot guarantee the compliance of other systems operated by other companies upon which it depends. For example, the Company's ability to provide electricity to its customers depends upon the regional electric transmission grid which connects the systems of neighboring utilities to provide electric power for the region. If one company's system is not Year 2000 Compliant, then a failure could impact all providers within the grid, including Unitil. Similarly, the Company's gas operations depend upon natural gas pipelines that it does not own or control, and any Year 2000 noncompliance associated with these pipelines may affect the Company's ability to provide natural gas to its customers. Failure to achieve Year 2000 readiness could have a material effect on the Company's results of operations, financial position and cash flows. NEW ACCOUNTING STANDARDS 	During 1998, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures about Segments of an Enterprise and Related Information." This Statement supersedes all previous accounting pronouncements regarding the reporting of segment information and requires companies to report financial and descriptive information about reportable operating segments in annual and interim financial statements. 	Also in 1998, the Company adopted SFAS No. 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits" (an amendment of FASB Statements No. 87, 88, and 106). This Statement standardizes the disclosure requirements for pensions and other postretirement benefits, requires additional information on changes in the benefit obligations and fair values of plan assets, and eliminates certain disclosures that are no longer useful. 	During 1997, the Company adopted SFAS No. 128, "Earnings per Share." This Statement supersedes all previous accounting pronouncements regarding the reporting of Earnings per Share data and requires the presentation of basic and diluted Earnings per Share information by all publicly traded entities. The adoption of this reporting standard by the Company is effective with the reporting years presented in the financial statements. FORWARD-LOOKING INFORMATION 	This report contains forward-looking statements which are subject to the inherent uncertainties in predicting future results and conditions. Certain factors that could cause the actual results to differ materially from those projected in these forward-looking statements include, but are not limited to; variations in weather, changes in the regulatory environment, customers' preferences on energy sources, general economic conditions, increased competition and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company. 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, 1998 and 1997, 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, 1998. 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 generally accepted auditing standards. 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 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, 1998 and 1997, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. 	We have also audited Schedule VIII of Unitil Corporation and subsidiaries as of December 31, 1998 and for the three years then ended included in Part IV Item 14(a)(2). In our opinion, the schedule presents fairly, in all material respects, the information required to be set forth therein. 	 GRANT THORNTON LLP CONSOLIDATED STATEMENTS OF EARNINGS 	 (000's, except common shares and per share data) 					 Year Ended December 31, 1998 1997 1996 					 Operating Revenues:					 Electric $149,639 $149,973 $149,696 Gas 17,009 19,729 21,105 Other 30 36 45 Total Operating Revenues 166,678 169,738 170,846 					 Operating Expenses:					 Fuel and Purchased Power 98,589 99,974 100,768 Gas Purchased for Resale 9,874 12,032 13,323 Operation and Maintenance 23,652 23,550 24,110 Depreciation and Amortization 10,007 9,178 8,776 Provisions for Taxes:					 Local Property and Other 5,540 5,276 4,983 Federal and State Income 3,710 4,166 4,613 Total Operating Expenses 151,372 154,176 156,573 Operating Income 15,306 15,562 14,273 Non-Operating Expenses (Income) 156 160 (627) Income Before Interest Expense 15,150 15,402 14,900 Interest Expense, Net 6,901 7,167 6,171 Net Income 8,249 8,235 8,729 Less Dividends on Preferred Stock 274 276 278 Net Income Applicable to Common Stock $7,975 $7,959 $8,451 					 Average Common Shares Outstanding 4,505,784 4,412,869 4,354,297 					 Basic Earnings Per Share $1.77 $1.80 $1.94 					 Diluted Earnings Per Share $1.72 $1.76 $1.89 					 (The accompanying Notes are an integral part of these statements.) CONSOLIDATED BALANCE SHEETS (000's) ASSETS 			 December 31, 1998 1997 			 Utility Plant:			 Electric $152,940 $166,636 Gas 32,622 30,473 Common 20,876 19,689 Construction Work in Progress 3,024 2,677 Utility Plant 209,462 219,475 Less: Accumulated Depreciation 63,428 68,360 Net Utility Plant 146,034 151,115 			 			 Current Assets:			 Cash 4,083 2,337 Accounts Receivable - Less Allowance for			 Doubtful Accounts of $646 and $653 15,999 16,890 Taxes Refundable 1,056 554 Materials and Supplies 2,962 2,663 Prepayments 1,147 434 Accrued Revenue 5,322 6,796 Total Current Assets 30,569 29,674 			 			 Deferred Tax Assets			 			 Noncurrent Assets:			 Regulatory Assets 163,034 23,885 			 Prepaid Pension Costs 8,591 8,120 Debt Issuance Costs 1,320 918 Other Noncurrent Assets 27,287 24,819 Total Noncurrent Assets 200,232 57,742 			 TOTAL $376,835 $238,531 (The accompanying Notes are an integral part of these statements.) CONSOLIDATED BALANCE SHEETS (Cont.) (000's) 		 CAPITALIZATION AND LIABILITIES 			 December 31, 1998 1997 			 Capitalization:			 Common Stock Equity $75,351 $71,644 Preferred Stock, Non-Redeemable, Non-Cumulative 225 225 Preferred Stock, Redeemable, Cumulative 3,618 3,666 Long-Term Debt, Less Current Portion 74,047 63,896 Total Capitalization 153,241 139,431 			 			 Current Liabilities:			 Long-Term Debt, Current Portion 1,175 4,470 Capitalized Leases, Current Portion 907 883 Accounts Payable 11,382 14,734 Short-Term Debt 20,000 18,000 Dividends Declared and Payable 232 212 Refundable Customer Deposits 1,293 2,187 Interest Payable 841 1,087 Other Current Liabilities 2,776 2,635 Total Current Liabilities 38,606 44,208 			 			 Deferred Income Taxes 43,027 42,295 			 Noncurrent Liabilities: 			 Power Supply Contract Obligations 129,688 -- 			 Capitalized Leases, Less Current Portion 4,287 4,733 Other Noncurrent Liabilities 7,986 7,864 Total Noncurrent Liabilities 141,961 12,597 			 			 TOTAL $376,835 $238,531 (The accompanying Notes are an integral part of these statements.) CONSOLIDATED STATEMENTS OF CAPITALIZATION 	 (000's except number of shares) 			 December 31, 1998 1997 			 Common Stock Equity			 Common Stock, No Par Value (Authorized - 8,000,000 shares; $38,407 $35,653 Outstanding - 4,574,629 and 4,463,816 Shares)			 Stock Options 543 1,452 Retained Earnings 36,401 34,539 Total Common Stock Equity 75,351 71,644 			 Preferred Stock			 CECo Preferred Stock, Non-Redeemable, Non-Cumulative: 225 225 6% Series, $100 Par Value			 CECo Preferred Stock, Redeemable, Cumulative: 215 215 8.70% Series, $100 Par Value			 E&H Preferred Stock, Redeemable, Cumulative:			 5% Series, $100 Par Value 91 91 6% Series, $100 Par Value 168 168 8.75% Series, $100 Par Value 333 344 8.25% Series, $100 Par Value 406 406 FG&E Preferred Stock, Redeemable, Cumulative:			 5.125% Series, $100 Par Value 998 1,035 8% Series, $100 Par Value 1,407 1,407 Total Preferred Stock 3,843 3,891 			 Long-Term Debt			 CECo First Mortgage Bonds:			 Series C, 6.75%, Due January 15, 1998 --- 1,520 Series H, 9.43%, Due September 1, 2003 --- 5,200 Series I, 8.49%, Due October 14, 2024 6,000 6,000 Series J, 6.96%, Due September 1, 2028 10,000 E&H First Mortgage Bonds:			 Series E, 6.75%, Due January 15, 1998 --- 498 Series H, 8.50%, Due December 15, 2002 --- 700 Series J, 9.43%, Due September 1, 2003 --- 4,000 Series K, 8.49%, Due October 14, 2024 9,000 9,000 Series L, 6.96%, Due September 1, 2028 10,000 FG&E Long-term Notes:			 Twelve year Notes, 8.55%, Due March 31, 2004 14,000 15,000 Thirty year Notes, 6.75%, Due November 30, 2023 19,000 19,000 Unitil Realty Corp. Senior Secured Notes:			 8.00% Notes Due August 1, 2017 7,222 7,448 Total Long-Term Debt 75,222 68,366 Less: Long-Term Debt, Current Portion 1,175 4,470 Total Long-Term Debt, Less Current Portion 74,047 63,896 			 Total Capitalization $153,241 $139,431 (The accompanying Notes are an integral part of these statements.) CONSOLIDATED STATEMENTS OF CASH FLOWS (000's) 	 Year Ended December 31, 1998 1997 1996 			 Operating Activities:			 Net Income $8,249 $8,235 $8,729 Adjustments to Reconcile Net Income to			 Cash Provided by Operating Activities:			 Depreciation and Amortization 10,068 9,238 8,832 Deferred Tax Provision 1,515 660 458 Amortization of Investment Tax Credit (402) (172) (194) Gain on Taking of Land and Building ---- ---- (875) Changes in Working Capital:			 Accounts Receivable 891 (506) (1,451) Materials and Supplies (299) (184) (203) Prepayments (713) (725) (705) Accrued Revenue 1,474 2,063 (6,281) Accounts Payable (3,352) (370) 539 Refundable Customer Deposits (894) 602 (1,629) Taxes and Interest Payable (748) (804) (306) Other, Net (2,574) (1,482) (654) Cash Provided by Operation Activities 13,215 16,555 6,260 			 Cash Flows Used In Investing Activities:			 Acquisition of Property, Plant & Equipment (14,463) (13,887) (19,359) Proceeds from Taking of Land & Building ---- ---- 875 Cash Used in Investing Activities (14,463) (13,887) (18,484) 			 Cash Flows From Financing Activities:			 Proceeds From (Repayment of) Short-Term Debt, net 2,000 (3,400) 18,700 Proceeds From Issuance of Long-Term Debt 20,000 7,500 ---- Repayment of Long-Term Debt (13,144) (1,345) (1,294) Dividends Paid (6,368) (6,159) (5,998) Issuance of Common Stock 1,600 1,285 1,132 Retirement of Preferred Stock (48) ---- (108) Repayment of Capital Lease Obligations (1,046) (1,115) (703) Cash Provided by (Used In) Financing Activities 2,994 (3,234) 11,729 			 Net Increase (Decrease) in Cash 1,746 (566) (495) 			 Cash at Beginning of Year 2,337 2,903 3,398 Cash at End of Year $4,083 $2,337 $2,903 			 Supplemental Cash Flow Information:			 Interest Paid $7,445 $7,531 $6,133 Federal Income Taxes Paid $2,490 $3,340 $3,982 			 Supplemental Schedule of Noncash Activities:			 Capital Leases Incurred $624 $1,057 $1,858 			 The Company recorded the estimated impact of the Order from the Massachusetts Department of Telecommunications and Energy related to its Electric Utility Restructuring Plan on its December 31, 1998 balance sheet as follows: 			 Net Decrease in Utility Plant-Electric $(11,302) --- --- Increase in Regulatory Assets 140,871 --- --- Decrease in Investment Tax Credits 119 --- --- Increase in Power Supply Contract Obligations (129,688) --- --- (The accompanying Notes are an integral part of these statements.) CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (000's)		 Deferred Stock Common Option Retained Shares Plan Earnings Total Balance at January 1, 1996 $32,822 $1,299 $29,773 $63,894 Net Income for 1996 8,729 8,729 Dividends on preferred shares (278) (278) Dividends on common shares -				 at an annual rate of $1.32 per share (5,740) (5,740) Stock Option Plan 237 237 Exercised stock options - 2,400 shares 50 (30) 20 Issuance of 52,081 common shares (a) 1,112 1,112 				 Balance at December 31, 1996 33,984 1,506 32,484 67,974 Net Income for 1997 8,235 8,235 Dividends on preferred shares (276) (276) Dividends on common shares -				 at an annual rate of $1.34 per share (5,904) (5,904) Stock Option Plan 330 330 Exercised stock options - 28,222 shares 626 (384) 242 Issuance of 51,529 common shares (a) 1,043 1,043 				 Balance at December 31, 1997 35,653 1,452 34,539 71,644 Net Income for 1998 8,249 8,249 Dividends on preferred shares (274) (274) Dividends on common shares -				 at an annual rate of $1.36 per share (6,113) (6,113) Stock Option Plan 245 245 Exercised stock options-66,951 shares 1,720 (1,154) 566 Issuance of 43,862 common shares (a) 1,034 1,034 Balance at December 31, 1998 $38,407 $543 $36,401 $75,351 	(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 (See Note 2). (The accompanying Notes are an integral part of these statements.) 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 (the 1935 Act), and is the parent of the Unitil System. The following companies are wholly owned subsidiaries of Unitil: Concord Electric Company (CECo), Exeter & Hampton Electric Company (E&H), Fitchburg Gas and Electric Light Company (FG&E), Unitil Power Corp. (UPC), Unitil Realty Corp. (URC), Unitil Service Corp. (USC), and Unitil Resources, Inc. (URI). 	Unitil's principal business is the retail sale and distribution of electricity in New Hampshire and both electric and gas services in Massachusetts through its retail distribution subsidiaries CECo, E&H, and FG&E. The Company's wholesale electric power subsidiary, UPC, principally provides all the electric power supply requirements to CECo and E&H for resale at retail, and also engages in various other wholesale electric power services with affiliates and non-affiliates throughout the New England region. URI is engaged in business transactions as a competitive marketer of electricity. Finally, URC and USC provide centralized operations to support the Unitil System. 	With respect to rates and accounting practices, CECo and E&H are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC), FG&E is regulated by the Massachusetts Department of Telecommunications & Energy (MDTE), and UPC is regulated by the Federal Energy Regulatory Commission (FERC). 	The Company accounts for all its regulated operations in accordance with Statement of Financial Accounting Standard ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation," requiring the Company to record the financial statement effects of the rate regulation to which the Company is currently subject. If a separable portion of the Company's business no longer meets SFAS No. 71, the Company is required to eliminate the financial statement effects of regulation for that portion. Basis of Presentation 	Principles of Consolidation --- Unitil Corporation (the Company) is the parent company of the Unitil System (the System). The consolidated financial statements include the accounts of the Company and all of its wholly-owned subsidiaries. All material intercompany balances and transactions have been eliminated in consolidation. 	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 --- The Company'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. 	Depreciation and Amortization --- Depreciation provisions for the Company's utility operating subsidiaries are determined on a group straight-line basis. Provisions for depreciation were equivalent to the following composite rates, based on the average depreciable property balances at the beginning and end of each year: 1998 - 3.21 percent; 1997 - 3.45 percent; and 1996 - 3.45 percent. 	Amortization provisions include the recovery of a portion of FG&E's former investment in the Seabrook Nuclear Power Plant in rates to its customers through a Seabrook Amortization Surcharge as ordered by the MDTE. In addition, FG&E is amortizing electric generating assets, in accordance with its electric restructuring plan approved by the MDTE (See Note 12). 	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. 	New Accounting Standards --- During 1998, the Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information. " This Statement supersedes all previous accounting pronouncements regarding the reporting of segment information and requires companies to report financial and descriptive information about reportable operating segments in annual and interim financial statements (See Note 11). 	Also in 1998, the Company adopted SFAS No. 132, "Employer's Disclosures about Pensions and Other Postretirement Benefits" (an amendment of FASB Statements No. 87, 88, and 106). This Statement standardizes the disclosure requirements for pensions and other postretirement benefits, requires additional information on changes in the benefit obligations and fair values of plan assets and eliminates certain disclosures that are no longer useful (See Note 9). 	 During 1997, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share." This Statement supersedes all previous accounting pronouncements regarding the reporting of earnings per share data and requires the presentation of basic and diluted earnings per share information by all publicly traded entities. The adoption of this reporting standard by the Company is effective with the reporting years presented in the financial statements (See Note 10). 	Reclassifications --- Certain amounts previously reported have been reclassified to conform with current year presentation. Note 2: Common Stock 	New Shares Issued --- During 1998, the Company raised $1,034,195 of additional common equity capital through the issuance of 43,862 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase Plan and the Employee 401(k) Tax Deferred Savings and Investment Plan. The Dividend Reinvestment and Stock Purchase Plan 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. The Employee 401(k) Tax Deferred Savings and Investment Plan is described in Note 9 below. In 1997, the Company raised $1,042,974 of additional common equity capital through the issuance of 51,529 shares of common stock in connection with these plans. 	The Company maintains a Key Employee Stock Option Plan (KESOP), which provides for the granting of options to key employees. The number of shares granted under this plan, as well as the terms and conditions of each grant, are determined by the Board of Directors, subject to plan limitations. All options granted under the KESOP vest upon grant. No option can be issued under the current plan after 1999. The plan provides options and 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 $244,903, $330,098 and $237,044 for the years ended December 31, 1998, 1997 and 1996, respectively. 	 Share Option Activity of the KESOP is presented in the following table: 1998 1997 1996 Beginning Options Outstanding & Exercisable 191,365 182,495 173,362 Options Granted --- 25,000 1,000 Dividend Equivalents Earned 10,327 12,092 10,533 Options Exercised (66,951) (28,222) (2,400) Options Canceled --- --- --- Ending Options Outstanding & Exercisable 134,741 191,365 182,495 			 Range of Option Exercise Price per Share $12.11-$18.28 $12.11-$18.28 $12.11-$18.28 The Company has adopted Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock Based Compensation," and recognizes compensation costs at fair value. 	 	The weighted average fair value per share of options granted during 1997 and 1996 was $3.21 and $3.23, respectively. No options were granted in 1998. The weighted average exercise price of options and dividend equivalents exercised in 1998 was $8.38 per share. The fair value of options at the date of grant was estimated using the Black-Scholes model with the following weighted average assumptions: 1998 1997 1996 Expected Life (Years) None Granted 2 3 Interest Rate 6.0% 6.0% Volatility 19.5% 19.4% Dividend Yield 5.5% 6.6% 	 	Restrictions on Retained Earnings ---Unitil Corporation has no restriction on the payment of common dividends from retained earnings. Its three retail distribution subsidiaries do have restrictions. Under the terms of the First Mortgage Bond Indentures, CECo and E&H had $3,336,986 and $3,366,816, respectively, available for the payment of cash dividends on their common stock at December 31, 1998. Under the terms of long-term debt Purchase Agreements, FG&E had $16,421,494 of retained earnings available for the payment of cash dividends on its common stock at December 31, 1998. Note 3: Preferred Stock 	Certain of the Unitil subsidiaries have redeemable Cumulative Preferred Stock outstanding and one subsidiary, CECo, has a Non-Redeemable, Non-Cumulative Preferred Stock issue outstanding. All such 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 1998, 1997 and 1996 were: 1998 - $47,300; 1997 - $0; and 1996 - $108,000. The aggregate amount of sinking fund requirements of the Redeemable Cumulative Preferred Stock for each of the five years following 1998 are $206,000 per year. Note 4: Long-Term Debt		 	Certain of the Company's long-term debt agreements contain provisions which, among other things, limit the incursion additional long-term debt. 	 	Total aggregate amount of sinking fund payments relating to bond issues and normal scheduled long-term debt repayments amounted to $4,394,000 and $1,294,000 in 1998 and 1997, respectively. 	 	The aggregate amount of bond sinking fund requirements and normal scheduled long-term debt repayments for each of the five years following 1998 are: 1999 - $1,176,307; 2000 - $1,190,940; 2001 - $3,206,788; 2002 - $3,223,951 and 2003 - $3,242,539. 	 	On September 3, 1998, Concord Electric Company sold $10,000,000 of 30-year Series J First Mortgage Bonds at par to an institutional investor, bearing an interest rate of 6.96%. Proceeds were used to repay short-term indebtedness, incurred to fund CECo's ongoing construction program, and to redeem a higher coupon long-term debt issue prior to its maturity. The redemption of $4,550,000 was on the 9.43% Series H First Mortgage Bonds. 	On September 3, 1998, Exeter & Hampton Electric Company sold $10,000,000 of 30-year Series L First Mortgage Bonds at par to an institutional investor, bearing an interest rate of 6.96%. Proceeds were used to repay short-term indebtedness, incurred to fund E&H's ongoing construction program, and to redeem two higher coupon long-term debt issues prior to their maturity. The redemptions, which totaled $4,200,000, included $700,000 of 8.5% Series H First Mortgage Bonds, and $3,500,000 of 9.43% Series J First Mortgage Bonds. 	On January 26, 1999, FG&E sold $12,000,000 of Long-term Notes at par to institutional investors, bearing an interest rate of 7.37%. Proceeds were used to repay short-term indebtedness, incurred to fund FG&E's ongoing construction program. 	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, 1998 and 1997. Note 5: Credit Arrangements 	At December 31, 1997, the Company had unsecured committed bank lines for short-term debt aggregating $25,000,000 with four banks for which it pays commitment fees. At December 31, 1998, the unused portion of the committed credit lines outstanding was $5,000,000. The average interest rates on all short-term borrowings were 5.95% and 5.98% during 1998 and 1997, respectively. Note 6: Leases 	The Company's subsidiaries conduct a portion of their operations in leased facilities and also lease some of their machinery and office equipment. FG&E has a facility lease for twenty-two years which began in February 1981. The lease allows five, five-year renewal periods at the option of FG&E. The equipment leases, which expired in 1998, included a twenty-five-year lease, which began on April 1, 1973, for a combustion turbine and a liquefied natural gas storage and vaporization facility. 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)	 1998	 1997 Electric --- $2,054 Gas --- 726 Common $6,899 6,420 Gross Plant 6,899 9,200 Less: Accumulated Depreciation 1,705 3,584 Net Plant $5,194 $5,616 	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, 1998: Year Ending December 31, (000's) 1999 $1,920 2000 1,362 2001 1,214 2002 1,123 2003 810 2004 - 2008 1,532 Total Minimum Lease Payments $7,961 Less: Amount Representing Interest 2,767 Present Value of Net Minimum Lease Payments $5,194 	Total rental expense charged to operations for the years ended December 31, 1998, 1997 and 1996 amounted to $88,000, $110,000; and $161,000, respectively. There are no material future operating lease payment obligations at December 31, 1998. Note 7: Income Taxes Federal Income Taxes were provided for the following items for the years ended December 31, 1998, 1997 and 1996, respectively: 1998 1997 1996 Current Federal Tax Provision (000's):						 Operating Income $2,221 $2,999 $3,658 Amortization of Investment Tax Credits (402) (172) (194) 		 Total Current Federal Tax Provision 1,819 2,827 3,464 Deferred Federal Tax Provision (000's):						 Accelerated Tax Depreciation 488 500 603 Abandoned Properties (656) (589) (655) 	Allowance for Funds Used During Construction					 ("AFUDC") and Overheads (58) (65) (72) 	Post Retirement Benefits Other Than Pensions (32) (33) (20) Environmental Remediation 45 112 --- Deferred Maintenance Cost and Other (76) 251 (175) Accrued Revenue 1,042 --- --- Deferred Gas Rate Case Expense 283 --- --- Percentage Repair Allowance 115 108 124 Deferred Advances (72) 52 304 Deferred Pensions 146 237 212 Total Deferred Federal Tax Provision 1,225 573 321 Total Federal Tax Provision $3,044 $3,400 $3,785 	 	The components of the Federal and State income tax provisions reflected in the accompanying consolidated statements of earnings for the years ended December 31, 1998, 1997 and 1996 were as follows: (000's) 1998 1997 1996 Federal 			 Current $2,221 $2,999 $3,658 Deferred 1,225 573 321 Amortization of Investment Tax Credits (402) (172) (194) Total Federal Tax Provision 3,044 3,400 3,785 			 State 			 Current 377 679 691 Deferred 289 87 137 Total State Tax Provision 666 766 828 			 Total Provision for Federal and State 			 Income Taxes $3,710 $4,166 $4,613 	The differences between the Company's provisions for Federal Income Taxes and the provisions calculated at the statutory federal tax rate, expressed in percentages, are shown below: Year Ended December 31, 1998 1997 1996 Statutory Federal Income Tax Rate 34% 34% 34% Income Tax Effects of:			 Investment Tax Credits (3) (1) (1) Abandoned Property (6) (5) (5) Other, Net 2 1 2 Effective Federal Income Tax Rate 27% 29% 30% Temporary differences which gave rise to deferred tax assets and liabilities are shown below: 	Deferred Income Taxes for the Year Ended December 31, 		 (000's) 1998 1997 Accelerated Depreciation $24,658 $24,625 Abandoned Property 8,442 9,098 Contributions in Aid to Construction (2,819) (2,750) Percentage Repair Allowance 1,924 1,792 Cathodic Protection 369 372 Retirement Loss 2,348 1,823 Deferred Pensions 2,870 2,758 AFUDC 31 45 Overheads 202 249 KESOP (442) (544) Bad Debts (225) (246) Accumulated Deferred 3,179 3,441 Environmental Remediation 186 132 Accrued Revenue 1,199 --- Deferred Gas Rate Case Expense 337 --- Investment Tax Credit 916 1,437 Other (148) 63 Total Deferred Income Taxes $43,027 $42,295 Note 8: 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 three generating units. New Haven Harbor is a dual-fired oil-and-gas station, and Wyman Unit No. 4 is an oil-fired station. They have been in commercial operation since August 1975 and December 1978, respectively. Millstone Unit No. 3, a nuclear generating unit, has been in commercial operation since April 1986. Kilowatt-hour generation and operating expenses of the joint ownership units are divided on the same basis as ownership. FG&E's proportionate costs are reflected in the 1998 Consolidated Statements of Earnings. Information with respect to these units as of December 31, 1998 is shown below: Joint Ownership Proportionate Share Company's Net Units State Ownership % of Total MW Book Value Millstone Unit No.3 CT 0.2170 2.50 $7,581 Wyman Unit No.4 ME 0.1822 1.13 117 New Haven Harbor CT 4.5000 20.12 2,000 23.75 $9,698 	 		 	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 costs under these contracts are included in Electricity and Gas Purchased for Resale in the Consolidated Statements of Earnings. These costs are normally recoverable in revenues under various cost recovery mechanisms. The status of FG&E's electric purchased power contracts at December 31, 1998, is as shown below: 			 Unit Fuel Energy Contract Type Entitlements End Date 			 			 			 Hydro 8 MW 2001 Hydro 3 MW 2012 Wood 17 MW 2012 System 15 MW 2001 	Impact of Electric Restructuring --- On January 15, 1999 the MDTE issued an order (the Order) approving FG&E's Electric Restructuring Plan (the Plan) with certain modifications. The January 15 Order included approval of the Company's power supply divestiture plan for its interest in the three generating units and four long-term power supply contracts outlined, above. 	FG&E has been allowed recovery of its transition costs, estimated at $140 million, including the above-market or stranded generation and power-supply related costs via a non-bypassable uniform Transition Charge. Estimated Regulatory Assets, based upon the Transition Charges to be collected, have been recorded together with the recognition of certain adjustments related to power supply contract liabilities and generation assets. 	FG&E recorded, based on the competitive bidding process, the estimated above-market portion of its power supply contracts obligations of $129 million. The net book value of its investment in generation assets, principally investments in Joint Owned facilities and inventories, is approximately $11 million and has been reclassified to Regulatory Assets. Also, as a result of the competitive bidding process, FG&E expects to receive approximately $5 million in proceeds from the disposition of its investment in Joint Owned facilities in 1999, which has been recorded in Regulatory Assets at December 31, 1998. Also, Deferred Tax Assets and Liabilities related to the adjustments above, are reflected in the Company's Balance Sheet at December 31, 1998. 	As a result of the Order by the MDTE related to Electric Industry Restructuring in Massachusetts (See Note 12), the Company is required to discontinue the provisions of Statement of Financial Accounting Standards 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), to the generation and power supply portion of FG&E's business. FG&E's electric distribution business and gas supply and distribution business, as well as the power supply and distribution business of CECo, E&H and UPC will continue to apply SFAS No. 71. New Hampshire: Purchased Power Contracts --- UPC also 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 Electricity Purchased for Resale in the Consolidated Statements of Earnings and are normally recoverable in revenues under various cost recovery mechanisms. 	The status of UPC's electric purchased power contracts at December 31, 1998, is as shown below: Est. Annual Min Payments Which Unit 1998 Energy Cover Future Fuel MW Winter Purchased Contract Debt Service Type Entitlements (MWH's) End Date Requirements (000's) 						 Unitil Power Corp.						 Gas 24 127,221 2010 $5,047 [1] Gas 2 4,631 2008 None Oil/Gas 2 5,768 2003 None Oil/Gas 16 75,889 2006 None Oil/Gas 10 17,820 2008 None Oil 4 8,472 1999 None Oil 11 52,598 2005 None Coal 25 137,183 2005 None Nuclear 29 197,146 2005 None Nuclear 10 86,408 2010 None Nuclear 2 13,458 2013 None Hydro 5 --- 2001 $989 [2] Refuse 6 47,113 2003 None System 18 1,242 2002 None System 30 11,317 Variable None Various 5 4,236 1999 None Various 178,055 Short-term None 						 						 Notes:						 [1] Total estimated 1998 annualized capacity payments, including debt service requirements. [2] Total support charges including debt service requirements.						 	In New Hampshire, Electric Industry Restructuring is not yet complete. The Company expects that, upon completion of industry restructuring, the above-market portion of the contracts listed above would be classified as stranded costs. Note 9: Benefit Plans 	Pension Plans --- Prior to May 1, 1998 four of the Company's subsidiaries had defined benefit Retirement and Pension plans and related Trust Agreements to provide retirement annuities for participating employees at age 65. On May 1, 1998, the plans of each employer were merged into one plan with uniform plan provisions to be known as the "Unitil Corporation Retirement Plan." The entire cost of the plan is borne by the respective subsidiaries. 	The following table provides the components of net periodic expense (income) for the plans for years 1998, 1997, and 1996: (000's) 1998 1997 1996 Service Cost $827 $767 $703 Interest Cost 2,207 2,023 1,921 Expected Return on Plan Assets (3,562) (3,094) (2,817) Amortization of Transition Obligation (16) (16) (16) Amortization of Prior-service Cost 74 13 13 Net Periodic Benefit Income $(470) $(307) $(196) Reconciliation of Projected Benefit Obligation (000's): 1998 1997 1996 Beginning of Year $29,853 $26,907 $28,236 Service Cost 827 767 703 Interest Cost 2,207 2,023 1,921 Amendments (Note A) 1,292 --- --- Actuarial Loss/(Gain) 4,290 1,836 (2,373) Benefit Payments (1,848) (1,680) (1,580) End of Year $36,621 $29,853 $26,907 	 Reconciliation of Fair Value of Plan Assets (000's):	 	 	 Beginning of Year $42,304 $36,547 $32,858 Actual Return on Plan Assets 8,171 6,971 4,807 Employer Contributions --- 466 462 Benefit Payments (1,848) (1,680) (1,580) End of Year $48,627 $42,304 $36,547 			 Funded Status (000's)			 Funded Status at December 31 (Note B) $12,006 $12,451 $9,640 Unrecognized Transition Obligation 254 238 222 Unrecognized Prior-service Cost 1,317 98 111 Unrecognized Net Actuarial (Gain)/Loss (4,986) (4,667) (2,625) Prepaid Pension Cost $8,591 $8,120 $7,348 			 (A)Generally effective May 1, 1998, the plans of each employer were merged into one plan with uniform plan provisions to be known as the "Unitil Corporation Retirement Plan." (B)From Fair Value of Plan Assets less End of Year Projected Benefit Obligation 			 	 	Plan assets are invested in common stock, short-term investments and various other fixed income security funds. The weighted-average discount rates used in determining the projected benefit obligation in 1998, 1997 and 1996 were 7.00%, 7.25%, and 7.75%, respectively, while the rate of increase in future compensation levels for 1998, 1997 and 1996 were 4.00%, 4.50% and 4.50%, respectively. The expected long-term rates of return on assets in 1998, 1997 and 1996 were 9.25% in each year. 	Unitil Service Corp. 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 $114,000; $112,000; and $71,000 for the years ended December 31, 1998, 1997 and 1996, respectively. 	Employee 401(k) Tax Deferred Savings Plan --- The Company 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 from 1% to 15% of current compensation to the plan. The Company matches contributions, with a maximum matching contribution of 3% of current compensation. Employees may direct the investment of their savings plan balances 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 $384,142; $389,888; and $356,574 for the years ended December 31, 1998, 1997 and 1996, respectively. 	Post-Retirement Benefits --- The Company's subsidiaries provide health care benefits to retirees for a twelve-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, 1998, 1997 and 1996, the accumulated post retirement benefit obligation (transition obligation) was approximately $299,000, $321,000 and $342,000, respectively, and the period cost associated with these benefits for 1998, 1997 and 1996 was approximately $76,000, $75,000 and $132,000, 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. The Company has omitted certain disclosures relating to SFAS No.132, as the accumulated post-retirement benefit obligation (transition obligation) is not material. Note 10: Earnings Per Share 	The following table reconciles basic and diluted earnings per share assuming all stock options were converted to common shares per SFAS 128. (000's except share and per share data) 1998 1997 1996 Basic Income Available to Common Stock $7,975 $7,959 $8,451 			 Weighted Average Common Shares Outstanding-Basic 4,505,784 4,412,869 4,354,297 Plus: Diluted Effect of Incremental Shares from Assumed Conversion 128,324 107,512 106,366 			 Weighted Average Common Shares Outstanding-Diluted 4,634,108 4,520,381 4,460,663 Basic Earnings per Share $1.77 $1.80 $1.94 Diluted Earnings per Share $1.72 $1.76 $1.89 			 Note 11: Segment Information 	The Company has two reportable segments: Electric (CECo, E&H, UPC, URI, and the electric portion of FG&E's business) and Gas (the gas portion of FG&E's business). 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 CECo, E&H, and FG&E. The Company's wholesale electric power subsidiary, UPC, provides all the electric power supply requirements to CECo and E&H for resale at retail, and also engages in various other wholesale electric power services with affiliates and non-affiliates throughout the New England Region. URI is engaged in business transactions as a competitive marketer of electricity. URC and USC provide centralized operations to support the Unitil System. 	 	 URC and USC are included in the "Other" column of the table below. USC provides centralized management and admininstrative services, including information systems management and financial record-keeping. URC owns certain real estate, principally the Company's corporate headquarters. 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 in accordance with factors 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. The table below provides significant segment financial data for the years ended December 31, 1998, 1997 and 1996: 						 Year Ended December 31, 1998 (000's) Electric Gas Other Eliminations Total Revenues External Customers $149,639 $17,009 $30 $166,678 Intersegment --- --- 18,483 (18,483) --- Depreciation and Amortization 7,917 893 1,197 10,007 Interest, net 4,842 1,097 962 6,901 Income Taxes 3,609 (145) 246 3,710 Segment Profit 7,428 176 371 7,975 Identifiable Segment Assets 316,568 36,354 44,932 (21,019) 376,835 Regulatory Assets 163,034 --- --- 163,034 Capital Expenditures 10,644 3,171 648 14,463 					 					 Year Ended December 31, 1997 (000's) Revenues 					 External Customers $149,973 $19,729 $36 $169,738 Intersegment --- --- 14,295 (14,295) --- Depreciation and Amortization 7,246 892 1,040 9,178 Interest, net 5,715 1,034 418 7,167 Income Taxes 3,563 414 189 4,166 Segment Profit 6,772 916 271 7,959 Identifiable Segment Assets 177,684 36,045 47,488 (22,686) 238,531 Regulatory Assets 23,885 --- --- 23,885 Capital Expenditures 10,475 2,182 1,230 13,887 					 					 Year Ended December 31, 1996 (000's) Revenues 					 External Customers $149,696 $21,105 $45 $170,846 Intersegment --- --- 10,738 (10,738) --- Depreciation and Amortization 7,243 856 677 8,776 Interest, net 5,206 979 (14) 6,171 Income Taxes 3,831 417 365 4,613 Segment Profit 6,982 900 569 8,451 Identifiable Segment Assets 175,178 33,473 41,952 (18,495) 232,108 Regulatory Assets 25,432 --- --- 25,432 Capital Expenditures 10,834 1,915 6,610 19,359 					 	 		 Note 12: Commitments and Contingencies Environmental Matters 	In September 1998, the FG&E signed a memorandum of understanding with the Massachusetts Highway Department and the Massachusetts Department of Environmental Protection that accommodates the construction of a new highway bridge across Sawyer Passway, the Company's former manufactured gas plant (MGP) site. This memorandum satisfies the requirements of the Massachusetts Contingency Plan for temporary closure at this last remaining portion of the site. Specifically, this agreement allows for current FG&E efforts to perform remediation work required as result of bridge construction. Upon completion of site remediation associated with the bridge construction, this last remaining portion of the Sawyer Passway MGP site is expected be closed out and attain the status of temporary closure in late 1999. This temporary closure allows FG&E to monitor the site every five years to determine if a more feasible remediation alternative can be developed and achieved. 	The costs of remedial action at this site are initially funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the MDTE. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site. Regulatory Matters 	 	Restructuring and Competition -Regulatory activity surrounding restructuring and competition continues in both Massachusetts and New Hampshire. March 1, 1998 was "Choice Date" or the beginning of competition for all electric consumers in Massachusetts, while New Hampshire's "Choice Date" slipped past both the proposed date of January 1, 1998, and the legislature's mandated July 1, 1998. Currently, approximately 10% of New Hampshire electric consumers can choose their electric supplier. The ability to choose for the remaining 90% is currently the subject of a federal court preliminary injunction (see below). 	 Massachusetts gas industry restructuring plans continue to be under development. The MDTE, gas utilities and other stakeholders began a collaborative effort in late 1997 to develop solutions to the many issues that surround restructuring the local natural gas distribution business. 	Unitil has been preparing for electric and gas industry restructuring by developing transition plans that will move its utility subsidiaries into this new market structure in a way that will ensure fairness in the treatment of the Company's assets and obligations that are dedicated to the current regulated franchises and, at the same time, provide choice for all customers. 	Massachusetts (Electric)- On January 15, 1999, the MDTE gave final approval to FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) a choice of energy supplier; b) an option to purchase Standard Offer Service (i.e. state-mandated energy service) provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction. The Plan also provides for FG&E to divest generation assets and its portfolio of purchased power contracts. The Company will be afforded full recovery of any transition costs through a non-bypassable retail Transition Charge. 	Pursuant to the Plan, on October 30, 1998, the Company filed with the MDTE a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. The MDTE's January 15, 1999 Order approves the FG&E/Constellation contract, and service thereunder is scheduled to commence on March 1, 1999, and is scheduled to continue through February 28, 2005. This contract is the result of the first successful Standard Offer auction conducted in Massachusetts. 	The January 15 Order also approved the Company's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts. A contract for the sale of FG&E's interest in the New Haven Harbor plant was filed with the MDTE on November 20, 1998. The MDTE's decision is pending. Contracts for the sale of the Company's remaining generating assets and purchased power contracts are expected to be filed with the MDTE in the near future. All such contracts are subject to MDTE approval. 	Massachusetts (Gas) -In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were approved by the MDTE and implemented in November of 1998. 	On July 2, 1998 the MDTE established April 1, 1999 as the date by which unbundled gas service would begin to be implemented by all LDCs. On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. That order also set forth the MDTE's decision regarding release by LDCs of their pipeline capacity contracts to competitive marketers. In January of 1999, the LDCs reported to the MDTE that they were continuing to work to develop systems and practices to implement unbundling. The MDTE has not yet responded to the LDCs' report, and it appears unlikely that full implementation will be achieved by the April 1, 1999 target date. 	New Hampshire - On February 28, 1997, the New Hampshire Public Utilities Commission (NHPUC) issued its Final Plan for transition to a competitive electric market in New Hampshire. The order allowed CECo and E&H, Unitil's New Hampshire retail distribution utilities, to recover 100% of "stranded" costs for a two-year period, but excluded recovery of certain administrative-related charges. 	Northeast Utilities' affiliate, Public Service Company of New Hampshire, appealed the NHPUC order in Federal District Court. A temporary restraining order was issued on March 10, 1997. In June 1997, Unitil was admitted as a Plaintiff Intervenor in the Federal Court proceeding. On June 9, 1998, the Federal Court issued an injunction continuing the freeze on NHPUC efforts to implement restructuring. Several parties have filed interlocutory appeals, and no date has been scheduled for a trial in the federal court. The Company will vigorously pursue its action in the federal court and simultaneously look for ways to resolve issues and bring forth choice to its retail customers. 	In September of 1998, the Company reached a comprehensive restructuring settlement with key parties and filed this voluntary Agreement with the NHPUC. The Agreement was modified on October 20, 1998. In oral deliberations on November 2 and November 18, 1998, the NHPUC imposed conditions to approval of the Settlement which were unacceptable to the Company, and the Settlement was subsequently withdrawn. The component of the Agreement dealing with wholesale rates was filed with the FERC in September 1998, and approved by the FERC in early November. However, implementation will not occur, as the changes were conditioned upon approval by the NHPUC. Unitil continues to participate actively in all proceedings and in several NHPUC-established working groups which will define details of the transition to competition and customer choice. 	Rate Cases -The last formal regulatory hearings to increase base electric rates for Unitil's three retail operating subsidiaries occurred in 1985 for Concord Electric Company, 1984 for Fitchburg Gas and Electric Light Company and 1981 for Exeter & Hampton Electric Company. 	On May 15, 1998, FG&E filed a gas base rate case with the MDTE. After evidentiary hearings, the MDTE issued an Order allowing FG&E to establish new rates, effective November 30, 1998, that would produce an annual increase of approximately $1.0 million in gas revenues. However, as part of the proceeding, the Attorney General of the Commonwealth of Massachusetts alleged that FG&E had double-collected fuel inventory finance charges, since 1987, and requested that the MDTE require FG&E to refund approximately $1.6 million to its customers. The Company believes that the Attorney General's claim is without merit and that a refund is not justified or warranted. The MDTE stated its intent to open a separate proceeding to investigate the Attorney General's claim. 	A majority of the Company's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas and energy efficiency program cost recovery mechanisms. Restructuring will continue to change the methods of how certain costs are recovered from customers and from suppliers. Transition costs, Standard Offer Service and Default Service power supply costs, internal and external transmission service costs and energy efficiency and renewable energy program costs for FG&E are being recovered via fully reconciling rate adjustment mechanisms in Massachusetts. 	Millstone Unit No. - FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. On March 30, 1996, as a result of an engineering evaluation completed by the operator, Northeast Utilities, Millstone 3 was taken out of service. NRC authorization for restart was given on June 29, 1998. Millstone 3 began producing electric power in early July, 1998 and reached full output on July 15, 1998. The unit remains on the NRC's Watch List. 	During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E had been incurring approximately $35,000 per month in replacement power costs, and had been recovering those costs through its fuel adjustment clause, which will be subject to review and approval by the MDTE. 	In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. The arbitration and legal cases are proceeding. Item 9. 	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure None PART III Item 10. Directors and Executive Officers of the Registrant 	Information required by this Item is set forth in Exhibit 99.1 on pages 2 through 8 of the 1998 Proxy Statement. Item 11. Executive Compensation 	Information required by this Item is set forth in Exhibit 99.1 on pages 9 through 13 of the 1998 Proxy Statement. Item 12. Security Ownership of Certain Beneficial Owners and Management 		Information required by this Item is set forth in Exhibit 99.1 on pages 3 through 5 of the 1998 Proxy Statement and is incorporated herein by reference. 	 Item 13. Certain Relationships and Related Transactions 		None PART IV Item 14. 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. Report of Independent Certified Public Accountants 					 Consolidated Balance Sheets - December 31, 1998 and 1997 	 Consolidated Statements of Earnings - for the years ended December 31, 1998, 1997 and 1996		 Consolidated Statements of Capitalization - December 31, 1998 and 1997	 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996	 Consolidated Statements of Changes in Common Stock Equity - for the years ended December 31, 1998, 1997 and 1996	 Notes to Consolidated Financial Statements		 The following consolidated financial statement schedules of the Company and subsidiaries are included in Item 14(d): 					 	Report of Independent Certified Public Accountants		 	Schedule VIII Valuation and Qualifying Accounts for December 31, 		 1998, 1997 and 1996		 	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 inappropriate, or information required is included in the financial statements or notes thereto and, therefore, have been omitted. 		(3) - List of Exhibits Exhibit No. 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	 filed on March 4, 1992 and Exhibit 3.2 to Form 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),	 Exeter & Hampton Exhibit 3.3 to Electric Company (E&H) 10-K and the Company for 1984 		 3.5	Articles of Exchange of CECo,	 	 E&H, and the Company -	 Stipulation of the Parties Exhibit 3.4 to Relative to Recordation and Form 10-K Effective Date. 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	Form 8-K Light Company (FG&E) and dated UMC Electric Co., Inc. (UMC). March 1, 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 Form 8-K, dated and UMC December 14, 1989 		 4.1	Indenture of Mortgage and Deed of	 	 Trust dated July 15, 1958 of	 	 CECo relating to First	 	 Mortgage Bonds, Series B, 4 3/8%	 	 due September 15, 1988 and all	 series unless supplemented. ** 		 4.2	First Supplemental Indenture	 	 dated January 15, 1968 relating	 	 to CECo's First Mortgage	 	 Bonds, Series C, 6 3/4% due January	 	 5, 1998 and all additional series 	 unless supplemented. ** 		 Exhibit No.	Description of Exhibit	Reference* 		 4.3	Second Supplemental Indenture	 	 dated November 15, 1971 relating	 	 to CECo's First Mortgage	 	 Bonds, Series D, 8.70% due November	 	 15, 2001 and all additional series	 unless supplemented. ** 		 4.4	Fourth Supplemental Indenture	 	 dated March 28, 1984 amending	 	 CECo's Original First Mortgage	 	 Bonds Indenture, and First, Second and	 	 Third Supplemental Indentures	 	 and all additional series unless supplemented.	** 		 4.5	Fifth Supplemental Indenture	 	 dated June 1, 1984 relating	 	 to CECo's First Mortgage	 	 Bonds, Series F, 14 7/8% due June 1,	 	 1999 and all additional series	 unless supplemented. ** 		 4.6	Sixth Supplemental Indenture	 	 dated October 29, 1987 relating	 	 to CECo's First Mortgage	 Bonds, Series G, 9.85% due October Exhibit 4.6 to 	 15, 1997 and all additional series unless	Form 10-K supplemented. for 1987 		 4.7	Seventh Supplemental Indenture	 	 dated August 29, 1991 relating	 	 to CECo's First Mortgage	 Bonds, Series H, 9.43% due September Exhibit 4.7 to 1, 2003 and all additional series Form 10-K unless supplemented. for 1991 		 4.8	Eighth Supplemental Indenture	 	 dated October 14, 1994 relating	 to CECo's First Mortgage Bonds, Exhibit 4.8 to Series I, 8.49% due October 14, 2024 Form 10-K and all additional series unless for 1994 supplemented. 		 4.9	Indenture of Mortgage and Deed	 of Trust dated December 1, Exhibit 4.5 to 	 1952 of E&H relating to all series unless	Registration supplemented. Statement 2-49218 4.10	Third Supplemental Indenture	 	 dated June 1, 1964 relating	 	 to E&H's First Mortgage Bonds, Series D,	Exhibit 4.5 to 4 3/4% due June 1, 1994 and all Registration 	 additional series unless supplemented.	Statement 2-49218 		 Exhibit No.	Description of Exhibit	Reference* 		 4.11	Fourth Supplemental Indenture	 	 dated January 15, 1968 relating to	 E&H's First Mortgage Bonds, Series E, Exhibit 4.6 to 6 3/4% due January 15, 1998 and Registration 	 all additional series unless supplemented.	Statement 2-49218 		 4.12	Fifth Supplemental Indenture	 	 dated November 15, 1971 relating	 	 to E&H's First Mortgage Bonds, Series F,	Exhibit 4.7 to 8.70% due November 15, 2001 and Registration 	 all additional series unless supplemented.	Statement 2-49218 		 4.13	Sixth Supplemental Indenture 	 	 dated April 1, 1974 relating to 	 	 E&H's First Mortgage Bonds, Series G, 8 7/8%	 	 due April 1, 2004 and all additional	 series unless supplemented. ** 		 4.14	Seventh Supplemental Indenture	 	 dated December 15, 1977 relating	 to E&H's Exhibit 4 to First Mortgage Bonds, Series H, Form 10-K 8.50% due December 15, 2002 and for 1977 	 all additional series unless supplemented.	(File No. 0-7751) 		 4.15	Eighth Supplemental Indenture	 	 dated October 29, 1987 relating	 	 to E&H's First Mortgage Bonds, Series I,	Exhibit 4.15 to 9.85% due October 15, 1997 and Form 10-K 	 all additional series unless supplemented.	for 1987 		 4.16	Ninth Supplemental Indenture	 	 dated August 29, 1991 relating	 	 to E&H's	 First Mortgage Bonds, Series J, Exhibit 4.18 to 9.43% due September 1, 2003 and Form 10-K 	 all additional series unless supplemented.	for 1991 		 4.17	Tenth Supplemental Indenture	 	 dated October 14, 1994 relating	 	 to E&H's First Mortgage Bonds, Series K	Exhibit 4.17 to 8.49% due October 14, 2024 and all Form 10-K 	 additional series unless supplemented.	for 1994 		 4.18	Bond Purchase Agreement dated	 	 August 29, 1991 relating to	 E&H's Exhibit 4.19 to First Mortgage Bonds, Series J Form 10-K 9.43% due September 1, 2003 for 1991 		 		 Exhibit No.	Description of Exhibit	Reference* 		 4.19	Purchase Agreement dated March 20,	 1992 for the 8.55% Senior Notes Exhibit 4.18 to Form due March 31, 2004 10-K for 1993 		 4.20	Note Agreement dated November 30,	 1993 for the 6.75% Notes due Exhibit 4.18 to Form November 30, 2023 10-K for 1993 		 4.21	First Mortgage Loan Agreement dated October 24,	 	 1988 with an Institutional Investor in connection Exhibit 4.16 to with Unitil Realty Corp.'s Form 10-K acquisition of the Company's facilities in for 1998 Exeter, New Hampshire. 	 	 4.22	 Note Purchase Agreement dated July 1, 1997 	Exhibit 4.22 to for the 8.00% Senior Secured Notes Form 10-K due August 1, 2017 for 1997 		 4.23 Eleventh Supplemental Indenture dated Filed Herewith 	 September 1, 1998 relating to E&H's First	 	 Mortgage Bonds Series L 6.96% due September 1,	 	 2028.	 	 	 4.24 Ninth Supplemental Indenture dated Filed Herewith 	 September 1, 1998 relating to CECo's First	 	 Mortgage Bonds Series J 6.96% due September 1,	 	 2028.	 		 10.1 Labor Agreement effective June 1, 1997 Exhibit 10.1 to between CECo and The Form 10-K International Brotherhood of Electrical for 1997 	 Workers, Local Union No. 1837	 		 10.2 Labor Agreement effective May 31, Filed herewith 	 1998 between E&H and The International	 	 Brotherhood of Electrical Workers, Local Union	 	 No. 1837, Unit 1.	 		 10.3 Labor Agreement effective May 1, Filed herewith 	 1998 between FG&E and The	 	 Brotherhood of Utility Workers of	 	 New England, Inc., Local Union No. 340.	 	 	 10.4	Unitil System Agreement dated	 	 June 19, 1986 providing that Unitil Power	Exhibit 10.9 to 	 will supply wholesale requirements electric	Form 10-K service to CECo and E&H for 1986 		 		 		 Exhibit No.	Description of Exhibit	Reference* 10.5	Supplement No. 1 to Unitil System	 Agreement providing that Unitil Power Exhibit 10.8 to will supply wholesale requirements Form 10-K electric service to CECo and E&H. for 1987 	 CECo and E&H.	 		 10.6	Transmission Agreement Between	 Unitil Power Corp. and Public Exhibit 10.6 to Service Company of New Hampshire, Form 10-K Effective November 11, 1992 for 1993 		 10.7 Form of Severance Agreement dated Exhibit 10.55 to 	 February 21, 1989, between the Company 	Form 8 and the persons named in the schedule dated attached thereto. April 12, 1989 	 	 10.8 Key Employee Stock Option Exhibit 10.56 to Plan effective as of January 17, 1989. Form 8 dated April 12, 1989 	 	 10.9 Unitil Corporation Key Employee Exhibit 10.63 to Stock Option Plan Award Form 10-K Agreement. for 1989 	 	 10.10 Unitil Corporation Management Exhibit 10.94 to Performance Compensation Program. Form 10-K/A for 1993 	 	 10.11	Unitil Corporation Supplemental	 Executive Retirement Plan Exhibit 10.95 to effective as of January 1, 1987. Form 10-K/A for 1993 	 	 10.12	Unitil Corporation 1998 Stock Option Plan 	Filed herewith 		 10.13 Unitil Corporation Management Filed herewith 	 Incentive Plan	 		 11.1	Statement Re Computation in Support	 of Earnings Per Share for the Company Filed herewith 		 12.1	Statement Re Computation in	 	 Support of Ratio of Earnings	 to Fixed Charges for the Company. Filed herewith 		 21.1 Statement Re Subsidiaries of Registrant Filed herewith 		 27 Financial Data Schedule Filed herewith 		 99.1 1998 Proxy Statement Filed herewith * The exhibits referred to in this column by specific designations and dates have heretofore been filed with the Securities and Exchange Commission under such designations and are hereby incorporated by reference. **	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, 1998. 		On January 29, 1999 Unitil Corporation filed Form 8-K related to the approval of Fitchburg Gas and Electric Light Compay's Electric Restructuring Plan (the Plan) by the Massachusetts Department of Telecommunications and Energy. See Item 7 - Management's Discussion and Analysis for further discussion of the Plan. CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS 	We have issued our report dated February 9, 1999, accompanying the consolidated financial statements and schedule included in the Annual Report of Unitil Corporation and subsidiaries on Form 10-K for the year ended December 31, 1998. We hereby consent to the incorporation by reference of said report in the Registration Statements of Unitil Corporation and subsidiaries on Form S-3 and on Form S-8. 	GRANT THORNTON LLP Boston, Massachusetts March 23, 1999 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 31, 1999 By Robert G. Schoenberger Robert G. Schoenberger Chairman of the Board of 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 Robert G. Schoenberger Principal Executive March 31, 1999 Robert G. Schoenberger Officer; Director (Chairman of the Board of Directors and Chief Executive Officer) Michael J. Dalton Principal Operating March 31, 1999 Michael J. Dalton Officer; Director (President and Chief Operating Officer) 					 Anthony J. Baratta, Jr. Principal Financial March 31, 1999 Anthony J. Baratta, Jr. Officer (Executive Vice President and Chief Financial Officer) Bruce W. Keough Director March 31, 1999 Bruce W. Keough Douglas K. Macdonald Director March 31, 1999 Douglas K. Macdonald 	 M. Brian O'Shaughnessy Director March 31, 1999 M. Brian O'Shaughnessy J. Parker Rice, Jr. Director March 31, 1999 J. Parker Rice, Jr. Charles H. Tenney II Director March 31, 1999 Charles H. Tenney II Charles H. Tenney III Director March 31, 1999 Charles H. Tenney III William W. Treat Director March 31, 1999 William W. Treat W. William VanderWolk, Jr. Director March 31, 1999 W. William VanderWolk, Jr. Joan D. Wheeler Director March 31, 1999 Joan D. Wheeler Franklin Wyman, Jr. Director March 31, 1999 Franklin Wyman, Jr. SCHEDULE VIII UNITIL CORPORATION					 VALUATION AND QUALIFYING ACCOUNTS AND RESERVES					 					 Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Deductions Balance at Beginning Costs and Other from End of Description of Period Expenses Accounts(A) Reserves(B)Period 					 Year Ended December 31, 1998 					 Reserves Deducted from A/R					 					 Electric 544,224 459,942 146,387 582,528 568,025 Gas 108,899 288,214 31,189 350,243 78,059 653,123 748,156 177,576 932,771 646,084 Year Ended December 31, 1997 					 Reserves Deducted from A/R					 					 Electric 518,606 670,548 262,523 907,453 544,224 Gas 141,508 177,733 41,284 251,626 108,899 660,114 848,281 303,807 1,159,079 653,123 					 Year Ended December 31, 1996 					 Reserves Deducted from A/R					 					 Electric 490,272 691,880 155,853 819,399 518,606 Gas 132,324 213,258 44,949 249,023 141,508 622,596 905,138 200,802 1,068,422 660,114 					 (A) Collections on Accounts Previously Charged Off					 (B) Bad Debts Charged Off 					 Exhibit 11.1 UNITIL CORPORATION			 			 Computation in Support of Earnings per Share			 			 			 			 Year Ended December 31, 1998 1997 1996 (000's Omitted) BASIC EARNINGS PER SHARE			 Net Income $8,249 $8,235 $8,729 Less: Dividend Requirements on Preferred Stock 274 276 Net Income Applicable to Common Stock $7,959 $7,959 $8,451 			 Average Number of Common Shares Outstanding 4,506 4,413 4,354 			 Basic Earnings per Average Common Share Outstanding $1.77 $1.80 $1.94 			 			 DILUTED EARNINGS PER SHARE			 Net Income $8,249 $8,235 $8,729 Less: Dividend Requirements on Preferred Stock 274 276 278 Net Income Applicable to Common Stock $7,959 $7,959 $8,451 			 Average Number of Common Shares Outstanding plus Assumed Options converted* 4,634 4,520 4,461 			 Diluted Earnings per Average Common Share Outstanding $1.72 $1.76 $1.89 * Assumes all options were converted to common shares per SFAS 128. 							Exhibit 12.1 UNITIL CORPORATION Computation in Support of Ratio of Earnings to Fixed Charges Year Ended December 31, 1998 1997 1996 1995 1994 		(000's Omitted Except Ratio)				 						 Earnings:						 Net Income, per Consolidated						 Statements of Earnings		$8,249	$8,235	$8,729	$8,369	$8,038 Federal Income Tax 2,191 3,025 3,699 3,924 3,480 Deferred Federal Income Tax 1,225 573 321 (298) (186) State Income Tax 368 682 688 690 610 Deferred State Income Tax 289 87 137 (16) 72 Amortization of Tax Credit (402) (172) (194) (202) (211) Interest on Long-term Debt 5,412 5,242 5,142 5,193 4,825 Amortization of Debt 						 Discount and Expense 61 60 57 72 64 Rents (annual interest component) 671 667 595 572 561 Other Interest 1,787 1,889 1,049 799 909 Total $19,851 $20,288 $20,223 $19,103 $18,162 						 Fixed Charges:						 Interest on Long-term Debt		$5,412	$5,242	$5,142	$5,193	$4,825 Amortization of Debt 						 Discount and Expense 61 60 57 72 64 Rents (annual interest component) 671 667 595 572 561 Other Interest 1,889 1,889 1,049 799 909 Total $8,033 $7,858 $6,843 $6,636 $6,359 						 Ratio of Earnings to Fixed Charges 2.47 2.58 2.96 2.88 2.86 Exhibit 21.1 Subsidiaries of Registrant 	The Company or the registrant has seven wholly-owned subsidiaries, six of which are corporations organized under the laws of The State of New Hampshire: Concord Electric Company, Exeter & Hampton Electric Company, Unitil Power Corp., Unitil Realty Corp., Unitil Resources, Inc., and Unitil Service Corp. The seventh, Fitchburg Gas and Electric Light Company, is organized under the laws of The State of Massachusetts. Exhibit 27