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 company's are wholly owned subsidiaries of Unitil, which together make up the Unitil System: State and Year of Unitil Corporation Subsidiaries Organization Principal Type of Business Concord Electric Company (CECo) NH - 1901 Retail Electric Distribution Utility
Exeter & Hampton Electric NH - 1908 Retail Electric Distribution Company (E&H) Utility
Fitchburg Gas and Electric MA - 1852 Retail Electric & Gas Light Company(FG&E) Distribution Utility
Unitil Power Corp. NH - 1984 Wholesale Electric Power (Unitil Power) Utility
Unitil Realty Corp. NH - 1986 Real Estate Management (Unitil Realty)
Unitil Service Corp. NH - 1984 System Service Company (Unitil Service)
Unitil Resources, Inc. NH - 1993 Energy Marketing and Services (Unitil Resources) 	 	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.
Utility Operations 	CECo is engaged principally in the distribution and sale of electricity at retail to approximately 26,300 customers in the City of Concord, which is the state capitol, 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 1996 retail electric revenues, approximately 34% was derived from residential sales, 54% 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 37,300 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 1996 retail electric revenues, approximately 47% was 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 25,600 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. FG&E's industrial customers include paper manufacturing and allied products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and allied industries. Of FG&E's 1996 electric revenues, approximately 33% was derived from residential sales, 33% from commercial and nonmanufacturing sales, and 34% from industrial/ manufacturing sales.
	Natural gas is supplied and distributed by FG&E to approximately 14,800 customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts. Of FG&E's 1996 gas operating revenues, approximately 51% was derived from residential sales, 23% from commercial sales, 11% from firm sales to industrial customers, and 16% from interruptible sales (which are sales to duel-fuel customers who possess alternative competitive energy sources, such as fuel oil, and who typically use gas during the non-heating season on an as-available basis). FG&E's industrial gas revenue is primarily derived from firm sales to paper manufacturing and allied 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, Section 7 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 Public Utilities (MDPU) 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 MDPU 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 MDPU 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 rates for the Unitil's Retail Distribution Utilities were in 1985 for CECo, 1984 for FG&E, and 1982 for E&H. 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.
FG&E also files a quarterly electric fuel charge and a semiannual gas adjustment factor with the MDPU for approval to adjust its rates for changes in fuel and gas related costs. Although all of FG&E's electric fuel costs and the largest portion of its purchased power costs are fully recovered under the Department's Electric Fuel Charge regulations, FG&E's electric generation entitlements are subject to annual performance reviews. Performance targets are filed by FG&E in advance and approved by the Department, and in January of each year FG&E files data on actual unit performance for the prior November to October period. The Department will investigate reasons why units failed to meet target performance criteria, and has in some cases disallowed recovery of replacement power costs for unplanned outages which the Department deemed to be due to imprudent operations or actions.
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, 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 MDPU. 	 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 as a Category 2 facility, which calls for increased NRC inspection attention. In March 1996 the NRC requested additional information about the operation of the unit from Northeast Utilities companies (NU), which operate the unit. As a result of an engineering evaluation completed by NU, Millstone 3 was taken out of service on March 30, 1996. The NRC later informed NU, in a letter dated June 28, 1996, that it had reclassified Millstone 3 as a Category 3 facility. The NRC assigns this rating to plants which it deems to have significant weaknesses that warrant maintaining the plant in shutdown condition until the operator demonstrates that adequate programs have been established and implemented to ensure substantial improvement in the operation of the plant. The NRC's letter also informed NU that this designation would require the NRC staff to obtain NRC approval by vote prior to a restart of the unit. The other Millstone nuclear units are also out of service and listed as Category 3 facilities.
	The Company cannot predict when Millstone 3 will be allowed by the NRC to restart, but believes that the unit will remain shut down for a protracted period of time. During the period that Millstone 3 is out of service, FG&E will continue 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 will also incur costs to replace the power that was expected to be generated by the unit. During the outage, FG&E has been incurring approximately $35,000 per month in replacement power costs, and has been recovering these costs through its fuel adjustment clause, which will be subject to review and approval by the MDPU. 	 SFAS No. 71 --- The Company follows the provisions of Statement of Financial Accounting Standards (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. Future regulatory changes could result in the Company no longer meeting the provisions of SFAS 71 for all or part of its business; thereby requiring the elimination of the financial statement effect of regulation for the portion of the business. (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 Restructuring and Competition)
Electric Utility Industry Restructuring and Competition
	The electric utility industry is undergoing a period of rapid change. Most prominent among these changes is the introduction of retail competition and the congruous legislative and regulatory initiatives that are designed to give retail customers the ability to choose, for the first time, their own electric energy supplier. Unitil has been preparing for this 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 of energy suppliers for all customers. Simultaneous with this transition process for Unitil's regulated utilities, the Company is moving to position its competitive market subsidiary, Unitil Resources, to pursue growth areas both within and beyond the Company's traditional franchises in all energy-related sectors.
	Unitil's electric utility operations have sold and distributed electricity and related services at retail in New Hampshire and Massachusetts, within the respective franchise territories of the Retail Distribution Utilities. However, under current legislative and regulatory electric industry restructuring proposals and plans in both New Hampshire and Massachusetts, the energy supply function would be separated form the delivery of that energy to customers. Under this new industry structure, Unitil's Retail Distribution Utilities would no longer sell electricity to their customers. Instead, as early as January 1, 1998 retail customers could purchase electricity from a competitive supplier of their choice, with the Retail Distribution Utilities remaining responsible for providing electric distribution services only over their "wire and poles" at regulated rates. Electric power would be provided by competitive market power generators and energy marketers. The Retail Distribution Utilities may continue to have an obligation to provide and/or arrange for "default" energy supply services to customers who either elect not to choose a competitive power supplier or who are without a competitive energy supplier under certain circumstances. However, the role of the Retail Distribution Company as the sole supplier of their customers' electric power supply would no longer exist.
	Under this new competitive market structure, utilities that have power supply obligations and commitments face the risk that market prices may not be sufficient to recover the costs of these commitments which were incurred to supply customers under a regulated industry structure. The amount by which power supply related costs exceed market prices for this power is commonly referred to as "stranded costs". Unitil's New Hampshire based Retail Distribution Utilities, CECo and E&H, presently purchase all their electric energy requirements at cost under a wholesale power agreement with Unitil's wholesale power company, Unitil Power, and resell it to their customers. Under New Hampshire's restructuring plan, CECo and E&H are required to terminate the wholesale power agreement with Unitil Power and may seek authorization to fully recover their stranded costs which are related to their purchase power obligations through a wires access or transition charge to retail customers. FG&E, Unitil's Massachusetts based distribution subsidiary, has purchased power obligations with nonaffiliated companies and also has non operating ownership interest in three joint-owned generating units. Current legislative and regulatory industry restructuring proposals in Massachusetts also provide for the reasonable recovery of any stranded costs related to FG&E's power supply obligations.
	Regulatory activity in both New Hampshire and Massachusetts has focused on deregulating the retail sale of electric energy. In both states, January 1, 1998 has been targeted as the beginning of competition, or "Choice Date." Under these restructuring proposals, customers would be allowed to choose their supplier of electricity from the competitive market, and have their local utility deliver that electricity over its distribution systems at regulated rates.
New Hampshire --- In New Hampshire, House Bill 1392 (HB 1392) was signed into law by the Governor in May 1996. HB 1392 establishes principles, standards and a timetable for the NHPUC to implement full, open retail electric competition as early as January 1, 1998, but no later than July 1, 1998. The bill also directs the NHPUC to set interim access charges for the recovery of above market "stranded" power supply costs and to make a final determination on these access charges within two years of implementation of full competition.
	On February 28, 1997, the NHPUC issued its Final Plan for restructuring the electric utility industry in New Hampshire. Concurrently, the NHPUC issued five separate orders establishing interim stranded cost charges for each of the state's electric utilities, including Concord Electric Company (CECo) and Exeter & Hampton Electric Company (E&H), Unitil's New Hampshire based retail distribution utilities. The Final Plan and related orders include a number of complex regulatory and market restructuring issues. Among other things, the Final Plan and orders provide for the interim recovery of CECo's and E&H's stranded costs, as defined by the NHPUC; releases CECo and E&H from their obligation to provide electric service and prohibits them from making energy sales after Choice Date; and requires CECo and E&H to terminate the System Agreement under which they currently purchase all their power supply requirements from Unitil Power Corp. The provisions of the System Agreement permit termination by any party thereto on seven years prior written notice. The NHPUC Final Plan and orders establish a novel standard relative to stranded cost recovery. Under the Final Plan the NHPUC bases recovery on an electric utility's stranded cost, at least during the interim recovery period, on a utility's performance in maintaining rates at or below the regional average rate. CECo's and E&H's rates are currently among the lowest in the region and below the regional average. As a result, under this methodology, CECo and E&H are currently permitted to collect 100% of their stranded costs, as defined by the NHPUC.
	The NHPUC Final Plan and orders raised a number of issues on which Unitil will seek rehearing and clarification. These issues include whether Unitil's unregulated affiliates will be allowed to sell competitive services and use the Unitil name in the existing service territories; the methodology for the recovery of all of CECo's and E&H's above-market power supply obligations incurred under the System Agreement by Unitil Power through retail rates; and the limitations of the NHPUC's authority over transmission tariffs and wholesale arrangements which are in the exclusive jurisdiction of the FERC, including the recovery of FERC approved wholesale charges through retail rates.
Unitil is unable to predict at this time what the NHPUC's response will be to its request for rehearing and clarification or what the ultimate impact of these decisions may be. Until is pursuing the necessary administrative appeal and court actions to ensure full recovery of commitments and obligations incurred to serve customers in the Company's New Hampshire franchises, and to permit Unitil to freely pursue new opportunities in the competitive energy market.
	On March 3, 1997, Northeast Utilities, the parent company of the largest investor owned utility in New Hampshire, filed a suit in United States District Court in Concord, New Hampshire, to enjoin implementation of the Final Plan. On March 17, 1997, Unitil moved to intervene in the proceeding on common issues of law, including whether the NHPUC is preempted under federal law from denying full recovery of FERC- approved wholesale costs in retail rates. At this time the Company is unable to predict the ultimate impact that the Final Plan and related orders will have on the Company, or the likely result of the Northeast Utilities lawsuit.
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 electric consumers are allowed to choose from competing electric suppliers, and have this supply delivered across the local utility system. More than thirty electric suppliers, including Unitil Resources, are currently authorized to market electricity to Pilot Program participants. Unitil Resources began competitive marketing efforts in May, and began making sales in June.
	Under the Pilot Program, the NHPUC initially ordered CECo and E&H to file tariffs which included a 10% discount to encourage participation and a mechanism to protect non participants from any adverse cost consequences resulting from changes in power supply obligations. Both these tariff items would have had a significant impact on the ability of the Company to recover its power supply obligations. However, after filing for reconsideration of the NHPUC's Order, the Company entered into a settlement agreement with the NHPUC staff and the Office of the Consumer Advocate which provides the Company an opportunity to mitigate any losses which may result under the Pilot Program. The settlement was approved by the NHPUC on July 1, 1996. The Company also recorded in 1996, a one-time charge to earnings for estimated losses relating to Pilot Program operations.
Massachusetts --- In March 1996, the MDPU issued a Notice of Inquiry/ Rulemaking, opening a new phase in its investigation on the restructuring of the electric utility industry in Massachusetts. Throughout 1996 the MDPU conducted a comprehensive information gathering effort, including holding numerous legislative style public hearings. On December 30, 1996, the MDPU issued a document entitled Electric Utility Restructuring Plan: Model Rules and Legislative Proposal. In this document the MDPU presented its proposed framework, model rules and proposed legislation for a restructured electric utility industry. On February 24, 1997, the Governor of Massachusetts filed legislation for electric industry restructuring which was generally consistent with the MDPU's proposal.
	The MDPU's proposed rules provide transition measures to accomplish the change from a regulated industry to a competitive market, as early as January 1, 1998. These measures include consumer safety and reliability standards, environmental protection measures and a reasonable framework for the recovery of utilities' stranded costs related to prudent generation investments and purchased power obligations. Included in the proposed rules and regulations is the requirement that each electric utility file "unbundled rates," that is, separate rate components for distribution, transmission and generation services and for access to the competitive supplier market. The MDPU has identified the unbundling of rates as "critical to provide both customers and competitors with the information they need to make decisions in a more competitive environment." The MDPU has required that the unbundled rates be revenue neutral for the Company, for each rate class, and for each customer. The Company filed its unbundled rates on March 3, 1997 to become effective on or after July 1, 1997, after approval by the MDPU.
	The MDPU has been supportive of the settlement process as a way to expedite electric utility restructuring in Massachusetts. On February 26, 1997, the MDPU approved a restructuring plan filed by the New England Electric System, Massachusetts Attorney General (Mass AG), the Massachusetts Division of Energy Resources and numerous other parties. Under this settlement, consumers will be allowed to choose an electricity supplier as early as January 1, 1998, and will receive a 10% reduction on their electric bills. The settlement requires the utility to divest all its generation plant, and provides the utility with the opportunity to fully recover all of its stranded costs. Several other settlement agreements have been reached in principal with the Mass AG and other Massachusetts electric utilities. The Company is currently developing a transition plan for its Massachusetts utility subsidiary and exploring the use of the settlement process to expedite its restructuring process.
	Each of the settlements reached are subject to restructuring legislation that may be enacted by the Massachusetts Legislature. On March 20, 1997, the Special Joint Committee on Electric Industry Restructuring of the Massachusetts Legislature issued a lengthy report and proposed legislation recommending retail competition and the recovery of prudently incurred generation cost for a period of ten years. The Committee also recommended that in order to be allowed to recover stranded cost that companies had to provide for a ten percent (10%) reduction in customer bills.
FG&E cannot predict what legislation, if any, will be adopted by the legislature and whether that legislation will allow for full recovery of stranded costs. Fitchburg does believe it is legally entitled to such recovery and will take appropriate actions to provide for such recovery.
Gas Utility Industry Restructuring and Competition
	Unitil's retail distribution gas operations have historically been subject to competition from fuel oil suppliers, electric utilities and propane suppliers, and other fuel providers for heating, water heating, cooking, industrial processes and other purposes. However, over the past several years changes in both federal and state regulation of the natural gas industry have resulted in increased "gas on gas" competition for the retail sale of natural gas.
	In April, 1992 the FERC issued Order 636 (Order 636), which substantially revised the regulation of interstate pipelines. Order 636 mandated, among other things, the unbundling of interstate pipeline sales and transportation services and required pipelines to provide open-access transportation on an equal basis for all gas supplies. This unbundling of services at the interstate pipeline level has changed the historical relationships of the natural gas industry, whereby producers sold to pipelines, pipelines sold to local gas distribution companies, such as FG&E, and local distribution companies to end-use customers. Now local gas distribution companies or end-use customers may directly utilize pipeline services for purchases, or simply for the transportation of gas purchased from third parties.
	During 1996, the MDPU ordered all Massachusetts gas distribution utilities to offer "unbundled" gas services to interruptible and special contract customers, as a means of promoting greater retail sales competition. Unbundled service separates the supply and transportation of gas to the city-gate (i.e. the point where the local distribution utility takes gas from the interstate pipeline into its distribution system ) from the delivery of that gas to the customers facility through that distribution system.
	While Unitil's retail gas distribution operations have been, and continue to be, subject to competition from electricity, oil, propane, coal and other fuels, federal and state regulatory changes have created the potential for increased competition among existing and new suppliers or natural gas marketers for retail gas sales. In particular, gas marketers can be expected to seek to provide sales services to end-use customers within FG&E's retail service territory. The Company expects that any third- party sales that are made within its gas service territory, will continue to be delivered over FG&E's local distribution system to customers. Because the company earns its margin on its gas distribution services and not on gas sales, the level of margins for distribution services provided to third parties is currently the same to the Company as if it sold the gas supplies directly to the same end-users. Similar opportunities may exist for the Company to market gas to new or existing retail customers, whether or not located within FG&E's franchise territory. Several gas distribution companies in Massachusetts have proposed that they be allowed to exit the business of the regulated sales of gas to retail customers and remain responsible only for the delivery of gas over their distribution system. These proposals are similar to restructuring proposals on the electric side of the business in that customers will be allowed to choose there own gas supplier. Unitil believes that these proposals, if adopted by the MDPU, will not have a material adverse effect on the Company's gas operations.
Electric Power Supply
New England Power Pool --- CECo, E&H, FG&E and Unitil Power are electric utility members of the New England Power Pool (NEPOOL). In addition, Unitil Resources also became a member of NEPOOL on March 1, 1997. 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 and load aggregators. Operation of the regional bulk power system will be provided by a new independent corporate entity, so that there will be 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. The proposed restructuring changes have been filed with FERC as an amendment to the NEPOOL Agreement, and the resulting FERC proceedings are expected to take place in stages during 1997.
Energy Resources --- Each electric utility's capability responsibility under the current NEPOOL Agreement involves carrying an allocated share of New England capacity requirements which is determined for each six-month period based on regional reliability criteria. Unitil Power, as the full requirements supplier to CECo and E&H, had a capability responsibility as of December, 1996 of 231.34 MW and a corresponding peak demand of 189.14 MW that occurred on August 8, 1996. FG&E's capability responsibility as of December, 1996 was 93.77 MW, with a corresponding peak demand of 79.69 MW that occurred on June 12, 1996.
	To meet the needs of CECo and E&H, Unitil Power has contracted for generating capacity and energy and for associated transmission services as needed to meet NEPOOL requirements and to provide a diverse and economical energy supply. Unitil Power's purchases are from various utility and non- utility generating units using a variety of fuels and from several utility systems in the U.S. and Canada. For the twelve months ending December 31, 1996, Unitil Power's energy needs were provided by the following fuel sources: nuclear (30%), oil (20%), coal (14%), gas (18%), wood and refuse (4%) , hydro (1%), and system and other (13%).
	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 ending December 31, 1996, FG&E's energy needs, including generation from joint-owned units, were provided from the following fuel sources: nuclear (18%), oil (19%), wood (26%), hydro (3%), coal (10%) and gas, system and other (24%).
	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. 	 Fuel --- Oil: Approximately 19% of FG&E's and 20% of Unitil Power's electric power in 1996 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 10% of FG&E's and 14% of Unitil Power's 1996 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. Contracts for various segments of the fuel cycle will be required in the future, and their availability, prices and terms cannot now be predicted.
	 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. Under the Act, a national repository for nuclear waste was anticipated to be in operation by 1998. FG&E cannot predict whether the Federal government will be able to provide interim 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 1994 through 1996.
Sources of Gas Supply
(Expressed as percent of total MMBtu of gas purchased) Natural Gas: 1996 1995 1994
Domestic firm.................................. 80.8% 82.3% 81.9% Canadian firm.................................. 7.0% 5.6% 6.2% Domestic spot market........................... 10.7% 11.1% 9.0% Total natural gas.................................. 98.5% 99.0% 97.1% Supplemental gas................................... 1.5% 1.0% 2.9% Total gas purchases................................ 100.0% 100.0% 100.0%
Cost of Gas Sold 1996 1995 1994 			 Cost of gas purchased and sold per MMBtu.......... $3.95 $3.03 $3.47 Percent Increase (Decrease) from prior year....... 30.4% (12.7)% (8.2)%
	As a supplement to pipeline natural gas, FG&E owns a propane air gas plant and has under a financial lease 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 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.
	The Company continues to work with federal and state environmental agencies to identify and assess environmental issues at two former gas manufacturing sites, the Sawyer Passway ("Sawyer Passway") and Logan Street ("Logan Street") sites, operated by FG&E.
	In December 1994 the Company accepted a Tier 1B permit from the Massachusetts Department of Environmental Protection (DEP) to address the Sawyer Passway site in Fitchburg, Massachusetts pursuant to the requirements of the Massachusetts Contingency Plan. A supplemental Phase II field investigation was conducted at the Site in July and August of 1996. Results of the investigation confirm, in the Phase II Investigation Report (the "Report"), the presence of some contamination, however, the Report indicates the identified contamination does not present "an imminent hazard to health, safety or the environment." The Phase II Investigation Report and the Risk Characterization was submitted to the DEP on January 31, 1997. Phase III, the Identification and Selection of Comprehensive Remedial Action Alternatives, has been delayed until June 30, 1997 to permit investigation of redevelopment alternatives on this site.
	The Company also conducted a Phase I assessment of the Logan Street Site on April 12, 1995. Results of that investigation suggest that there is some evidence of both groundwater and soil contamination. The site was numerically ranked using the Massachusetts Contingency Plan Numerical Ranking System Scoresheet and was classified as a Tier II Site. Currently, site closeout options are being investigated.
	The costs of such assessments and any remedial action determined to be necessary will initially be funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the Massachuestts Department of Public Utilities. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site. Because these investigations are at an early stage management cannot, at this time, predict the costs of future analysis and remediation.
Capital Requirements
	Net capital expenditures increased approximately $5.8 million in 1996 compared to 1995, reflecting a $1.6 million increase in planned spending for utility system improvements as well as $2.7 million increase in expenditures for the construction of the Company's new corporate headquarters. The Company also received cash payments of $875,000 and $2 million from the State of New Hampshire in 1996 and 1995, respectively, related to the eminent domain taking of is former corporate headquarters for a highway expansion project.
	In 1997, total capital expenditures are expected to approximate $13.3 million. This projection reflects normal capital expenditures for system expansions, replacements and other improvements.
Financing Activities
	The change in Cash Flows from Financing Activities in 1996 compared to 1995 reflects an increase in short-term borrowing requirements. Higher short-term borrowings in 1996 were primarily due to funding of the timing difference 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 interim construction financing of the Company's new corporate headquarters.
	No long-term debt was issued by any of the Unitil System companies during 1996 or 1995. The Company anticipates that it will complete a permanent long-term financing of its headquarters building in the first half of 1997.
	The Company currently has unsecured committed bank lines for short- term debt aggregating $23,000,000 with four banks for which it pays commitment fees. At December 31, 1996, the unused portion of the committed credit lines outstanding was $1,600,000. The average interest rate on all short-term borrowings outstanding during 1996 was 5.79%.
Employees
	As of December 31, 1996, the Company and its subsidiaries had 326 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 118 employees represented by labor unions. In 1995, E&H reached a new three year pact with its employees covered by a collective bargaining agreement. In 1994, both CECo and FG&E reached new three year pacts with their respective employees covered by collective bargaining agreements. The agreements provide for discreet salary adjustments, established work practices and provided uniform benefit packages. The current FG&E collective bargaining agreement will expire effective April 30, 1997. The current CECo collective bargaining agreement will expire effective May 31, 1997. 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 effect 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).
Executive Officers of the Registrant
	The names, ages and positions of all of the executive officers of the Company as of March 1, 1997 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 Business Experience and Position During Past 5 years
Peter J. Stulgis, 46, Mr. Stulgis has been a Director of Chairman of the Board of Directors the Company since its incorporation and Chief Executive Officer in 1984, and Chairman of the Board and Chief Executive Officer since 1992. From 1987 - 1992, Mr. Stulgis was Executive Vice President and Chief Financial Officer of the Company. 		 Michael J. Dalton, 56, Mr. Dalton has been a Director, President and Chief Operating Officer President and Chief Operating Officer of the Company since its incorporation in 1984.
Gail A. Siart, 38, Ms. Siart was promoted to Chief Chief Financial Officer, Financial Officer in 1994. Ms. Siart Secretary and Treasurer has been Secretary of the Company since 1988 and Treasurer since 1992. Prior to being elected Treasurer in 1992, Ms. Siart was the System's Subsidiary Treasurer since 1988. 		 James G. Daly, 39 Mr. Daly was promoted to Senior Senior Vice President Vice President of Unitil Service Energy Resources in 1994. Mr. Daly was Vice Unitil Service President of Unitil Service from 1992 to 1994, and Asst. Vice President of Unitil Service from 1988 to 1992. 		 George R. Gantz, 45 Mr. Gantz was promoted to Senior Senior Vice President Vice President of Unitil Service Business Development in 1994. Mr. Gantz was Vice Unitil Service President of Unitil Service from 1989 to 1994, and Asst. Vice President of Unitil Service from 1986 to 1989.
Item 2.
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 110,100 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 39 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 617 pole miles of overhead electric distribution primary voltage lines and approximately 110 cable miles of underground primary voltage 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, together with 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 693 pole miles of overhead electric distribution primary voltage lines and approximately 77 cable miles of underground primary voltage 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 propane gas plant and leases an LNG plant, both of which are located on land owned by it in fee. The Company has entered into agreements for joint ownership with others of one nuclear and two fossil fuel generating facilities. At December 31, 1996, the electric properties of the Company consisted principally of 69 miles of transmission lines, 16 transmission and distribution substations with a total capacity of 499,160 KVA and 667 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, and its combustion turbine electric peaking generator and LNG facility. (See Business - Electric Operations and Energy Supply and Gas Operations and Supply above for additional information regarding the Company's plants, facilities and gas mains and services.)
	Unitil Realty owns the Company's new corporate headquarters building and 12 acres of land in fee, which is located in the Town of Hampton, New Hampshire. This facility was completed and occupied by the Company during the summer of 1996. The Company believes that its facilities are currently adequate for their intended uses.
	Unitil Realty was, until February 13, 1995, the owner of the Company's corporate headquarters and 36 acres of related land located in the Town of Exeter, New Hampshire. On that date, the State of New Hampshire (the "State") took title to and possession of the land and building through eminent domain. The building is to be demolished in connection with the State's Route 101 highway expansion. (See Capital Requirements under Item 1. of this Report). The State of New Hampshire rented this facility back to the Company, until the Company completed the construction of its new corporate headquarters building.
Item 3.
Item 3. Legal Proceedings 	The Company is involved in other 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.
Item 4. Submission of Matters to a Vote of Security Holders
None
PART II
Item 5.
Item 5. Market For Registrant's Common Equity and Related Stockholder Matters Common Stock Data
Dividends Paid Per Common Share 1996 1995 				 1st Quarter $0.33 $0.32 2nd Quarter 0.33 0.32 3rd Quarter 0.33 0.32 4th Quarter 0.33 0.32 The Year $1.32 $1.28 				 1996 1995 High/Ask Low/Bid High/Ask Low/Bid 1st Quarter 24 3/4 20 3/4 17 5/8 16 2nd Quarter 24 1/4 21 1/8 17 5/8 16 1/8 3rd Quarter 23 20 3/8 20 1/8 16 5/8 4th Quarter 21 1/2 18 1/4 21 3/8 19 1/8
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA 1996 1995 1994 1993 1992 Consolidated Statements of Earnings (000's) Operating Income $14,273 $14,225 $13,754 $14,073 $13,342 Non-operating Expenses 627 (217) (64) 50 22 Income Before Interest Expense 14,900 14,008 13,690 14,123 13,364 Interest Expense, Net 6,171 5,639 5,652 6,523 6,948 Expenses (Net of Taxes) ---- ---- ---- ---- (155) Net Income 8,729 8,369 8,038 7,600 6,571 Dividends on Preferred Stock 278 284 291 298 352 Net Income Applicable to 					 Common Stock $8,451 $8,085 $7,747 $7,302 $6,219 Balance Sheet Data (000's)					 Utility Plant (original cost) $207,544 $190,177 $178,777 $171,540 $165,880 Total Assets 232,108 211,702 204,521 201,509 172,348 Capitalization and Short-term Debt:					 Common Stock Equity 67,974 63,895 59,997 56,234 52,608 Preferred Stock 3,891 3,999 4,094 4,198 4,277 Long-Term Debt 62,211 63,505 65,580 57,378 62,041 Total Capitalization 134,076 131,399 129,671 117,810 118,926 Capitalization Ratios:					 Common Stock Equity 51% 49% 46% 48% 44% Preferred Stock 3% 3% 3% 3% 4% Long-Term & Short-Term Debt 46% 48% 51% 49% 52% 					 Common Stock Data (000's)					 Shares of Common Stock (Year-End) 4,384 4,330 4,268 4,205 4,152 Shares of Common Stock (Average) 4,354 4,299 4,234 4,181 4,133 					 Per Share Data					 Earnings Per Average Share $1.94 $1.88 $1.83 $1.75 $1.50 Dividends Paid Per Share $1.32 $1.28 $1.24 $1.15 $1.10 Book Value Per Share $15.50 $14.76 $14.06 $13.37 $12.67 					 Electric and Gas Statistics					 Electric Sales - (MWH) 1,523,788 1,401,292 1,358,165 1,303,326 1,260,747 Customers Served - Year End 89,865 88,316 86,782 85,383 85,131 Gas Sales - (000's of Therms) 24,508 22,303 23,057 22,763 23,281 Customers Served - Year End 14,848 14,846 15,012 15,340 15,514
Note: The above data have been combined and restated to reflect the merger of FG&E into the Unitil System and the two-for-one stock split that occurred in 1992.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Earnings and Dividends
Earnings were $1.94 per average common share outstanding for the year ending December 31, 1996, an increase over 1995 and 1994 earnings per share of $1.88 and $1.83, respectively. 1996 marked the fourth consecutive year that Unitil achieved record earnings. The average return on common equity in 1996 was 12.8%.
This earnings performance reflects an increase of 9% in Unitils electric and firm natural gas sales base as well as higher operating expenses in support of the Companys utility operations, regulatory activities and new energy related business initiatives, and a reduction in energy consulting related revenue in 1996 compared to 1995.
Also impacting 1996 earnings were two nonrecurring and offsetting items: 1) a one-time charge related to the implementation in New Hampshire of a state - -mandated retail pilot program on competitive energy sales, and 2) income related to a lump sum settlement payment received in the eminent domain taking of the Companys former corporate headquarters for a highway expansion project.
Unitils common stock dividends in 1996 were $1.32 per share, an increase of 3.1% over 1995s annual dividend of $1.28 per share. This annual dividend of $1.32 in 1996 resulted in a payout ratio of 68%. At its January 1997 meeting, the Unitil Board of Directors increased the quarterly dividend rate by an additional 1.5%, resulting in the current effective annualized dividend of $1.34 per share.
Year in Review
The Unitil Systems total electric kilowatt-hour sales increased by 8.7% in 1996 compared to 1995. Electricity sales were higher for all major customer classes.
Electric energy sales to large industrial and commercial customers were up substantially in 1996, as kilowatt-hour usage by this group increased 21%. A significant factor in this growth was the addition of major new customer loads under Unitils new competitive pricing initiatives, including the Energy Bank TM market pricing program. Energy BankTM introduced nationally competitive electricity prices to the New England region and was designed to attract new large commercial and industrial customers. In 1996 electricity sales were also higher to Unitils underlying customer sales base. Excluding sales made under special market-based pricing programs, electricity sales to the Systems largest commercial and industrial customers in 1996 increased 7.1%, followed by an increase of 3.5% in sales to residential customers.
Approximately one half of the increase in sales reflects the addition of a major new customer early in 1996 under a special competitive market pricing arrangement. In the fall of 1996, this customer curtailed its operations to make alterations and improvements to its facility, and has informed the Company that it does not expect to complete this work until mid-1997.
The following table details total kilowatt-hour sales in each of the last three years by major customer class:
KWH SALES (000s) 1996 1995 1995 Residential 524,810 507,233 507,071 Commercial 382,647 381,292 374,769 Large Commercial/Industrial 604,696 500,945 464,357 Other Sales 11,634 11,822 11,968 Total KWH Sales 1,523,788 1,401,292 1,358,165
			 	Unitils natural gas revenue comprises approximately 12% of the Systems total energy revenues. Firm therm sales were higher to all major customer classes in 1996. The following table details total firm therm sales in each of the last three years by major customer class:
FIRM THERM SALES (000s) 1996 1995 1994 Residential 13,835 12,523 13,345 Commercial 6,728 6,208 5,892 Industrial 3,945 3,572 3,820 Total Therm Sales 24,508 22,303 23,057
Total firm therm sales increased 9.9%, led by a 10.6% increase in gas sales to industrial customers and a 10.5% increase in firm therm sales to residential customers. This increase in gas sales was attributable to continued growth in the local and regional economy and the beneficial impact of weather conditions for gas sales relative to the prior year. The 1996 winter heating season in the first quarter of the year was 11% colder, as measured in heating degree days, compared to the extremely mild heating season in 1995.
	The System's operating costs (not including fuel, purchased power and conservation program costs, which are normally recovered from customers through periodic cost recovery adjustment mechanisms) increased approximately $1.2 million, or 6.4% in 1996 versus 1995. This increase reflects the impact of higher costs resulting from industry restructuring proceedings, development and marketing of new product offerings and expenditures on improvements to operating and customer service capabilities.
OPERATING REVENUES
The following table compares the major components of Operating Revenues for 1996, 1995 and 1994:
OPERATING REVENUE ($000s) 1996 1995 1994 Base Electric Revenue $48,588 $45,458 $44,381 Fuel & Purchased Power 100,007 90,558 88,103 Conservation Program Costs 1,101 2,083 1,613 Total Electric Revenue 149,696 138,099 134,097 			 Base Gas Revenue 7,676 7,105 7,348 Cost of Gas 10,439 8,202 9,935 Interruptible Revenue 2,990 2,323 1,412 Total Gas Revenue 21,105 17,630 18,695 			 Other Revenue 45 941 624 Total Operating Revenue $170,846 $156,670 $153,416
	Electric Operating Revenue increased by $11.6 million, or 8%, in 1996 compared to 1995. Total electric operating revenue is comprised of electric base revenue, fuel and purchased power revenue and conservation and load management program revenue. Fuel and purchased power revenue are collected from customers through the operation of periodic cost recovery adjustment mechanisms. Changes in this component of operating revenue do not affect net income as they normally mirror corresponding changes in fuel and purchased power costs. Conservation and load management program revenue is also collected from customers through periodic cost recovery mechanisms, reflecting underlying changes in conservation and load management program costs. Electric base revenue is that portion of electric operating revenue that has a direct impact on net income. In 1996, electric base revenue rose by approximately $2.7 million. This 6.1% increase in electric base revenue was due to the growth in the Systems total kilowatt-hour sales and kilowatt billing demands of 8.7% and 9.4%, respectively.
In 1995, the System's electric operating revenue increased by approxi- mately $4.0 million, or 3% with the electric base revenue portion increasing by approximately 2.5%. This increase in electric base revenue in 1995, compared to 1994, was due to the growth in the System's total electric kilowatt-hour sales and kilowatt billing demands of 3.2% and 4.4%, respectively.
Gas Operating Revenue increased by $3.5 million, or 19.7%, in 1996 compared to 1995. Gas operating revenue is comprised of three components: cost of gas revenue, interruptible revenue and gas base revenue. Cost of gas revenue is collected from customers through the operation of a cost of gas adjustment mechanism. Changes in this component of gas operating revenue does not affect net income as it reflects corresponding changes in gas supply costs.
Interruptible revenue increased by $700,000, an increase of almost 29% in 1996, due to competitive prices of natural gas relative to oil throughout most of 1996. Margins earned on interruptible gas sales are used to directly lower rates to firm customers through the cost of gas adjustment mechanism and do not directly impact the Company's net income. Gas base revenue is that portion of gas operating revenue that has a direct impact on net income. In 1996, gas base revenue increased $577,000, on an overall increase of 9.9% in firm therm sales, due to improving economic conditions and a colder-than- normal heating season in 1996 as compared to the extremely mild heating season in 1995.
	In 1995, total gas operating revenue decreased by about $1.1 million, or 5.7%, as compared to 1994. Interruptible revenue increased more than 64%, due to very favorable spot market prices for gas in 1995. Gas base revenue decreased in 1995 due to a 3.3% reduction in therm sales to firm customers which primarily reflected the extremely mild heating season in 1995.
	Other Revenue declined from $940,000 in 1995 to $45,000 in 1996. The primary factor for this decline was the termination of a service agreement at the end of 1995 between Unitil Resources and one of its principal customers to which it provided administrative, management and power brokering services.
OPERATING EXPENSES
	Fuel and Purchased Power reflects the cost of fuel used in electric generation and wholesale energy and capacity purchased to meet the Unitil System's electric energy requirements. Fuel and purchased power expenses (normally recoverable from customers through periodic cost recovery adjustment mechanisms) increased $8.4 million, or 9.1% in 1996 compared to 1995. The change reflects an increase in the System's total energy requirements in 1996, coupled with higher fossil fuel costs. The combined resource portfolio of the Unitil System is comprised of a variety of power supply sources, including owned generation, utility purchase power contracts and purchases from non-utility generators. The Unitil System's total energy supply resources for 1996 were comprised of: 17% from subsidiary-owned generation; 63% from various utility-purchased power contracts; and 20% representing purchases from non-utility generation units.
	In 1995 compared to 1994, fuel and purchase power expenses increased $2.0 million, or 2.2%.
Purchased Gas reflects gas purchased and made to supply the System's total gas energy requirements. Purchased Gas is normally recoverable from customers through the cost of gas adjustment mechanism. Purchased Gas costs increased by approximately $2.8 million or 26.6% in 1996 as compared to 1995, reflecting the higher cost of gas available in the marketplace and an increase in therms purchased.
Purchased Gas decreased by $617,000, or 5.5% in 1995 as compared to 1994, based on a lower cost of gas, partially offset by an increase in therms purchased for interruptible sales.
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. The Company's combination gas & electric utility operating subsidiary, has been incurring FERC-approved transition charges from its natural gas pipeline supplier since 1992. Through the end of 1996, the amount of transition costs incurred by the Company totaled approximately $2.7 million. These costs are being recovered directly from gas customers through the cost of gas adjustment mechanism. On the basis of estimates included in rate filings before the FERC and other publicly available information, the Company currently estimates that it may incur up to an additional $700,000 of transition costs in future years. The Company expects full recovery of these costs through billings to customers.
Operation and Maintenance expense, which include conservation and load management (C&LM) program and purchase power related expenditures, increased by approximately $1.3 million, or 5.6% in 1996 compared to 1995. The increase primarily reflects higher operating expenses in support of the companies utility operations, regulatory activities and new business initiatives.
	In 1995, Operation and Maintenance expense increased by approximately $900,000, or 4.2%. This increase primarily reflected higher conservation and load management program expenditures. In 1995, expenditures on this component of operation and maintenance expenses was over $2.1 million -- a 30% increase over 1994's conservation and load management program expenditure level. Excluding these costs, the System's total operating and maintenance costs were relatively unchanged in 1995 compared to 1994.
DEPRECIATION, AMORTIZATION AND TAXES
	Depreciation expense increased more than 10% for 1996 over the prior year due primarily to a higher level of plant in service.
	Amortization of the Cost of Abandoned Properties principally relates to the abandonment of an investment in the Seabrook Nuclear Power Plant by the Company's Massachusetts retail operating subsidiary. A portion of the former investment in this project is being recovered in rates to electric customers as allowed by the Massachusetts Department of Public Utilities.
	Federal and State Income Taxes increased in 1996 compared to 1995 by $478,000. This result reflects higher net income before taxes in 1996 and the absence of a nonrecurring tax benefit realized by the Company in 1995 from a donation of land to an economic development project in Fitchburg, Massachusetts. Despite an increase in net income before taxes, Federal and State Income Taxes remained relatively unchanged in 1995, primarily reflecting the impact of a nonrecurring tax benefit realized by the Company from the above mentioned land donation.
	Local Property Taxes increased $155,000, or 5.1%, in 1996. This increase mainly reflects the annual property tax increases set by local communities. Local Property taxes increased in 1995, compared to 1994 by 13.2%.
NON-OPERATING INCOME/EXPENSES
	Non-Operating Income/Expenses in 1996 represent income of approximately $627,000, primarily reflecting the additional funds received in settlement of an eminent domain taking by the State of New Hampshire of the Companys former corporate headquarters for a highway expansion project, offset by other non-operating expenses.
INTEREST EXPENSES
	Interest Expense, Net increased 9.4% in 1996 over 1995, due to an increase in short-term borrowings. This increase in short term borrowings reflects the timing difference between required payments for fuel, purchase power and purchase gas costs and the recovery of these cost from customers through periodic cost recovery mechanisms. Increased short-term borrowing in 1996 was also related to the interim construction financing of the Companys new corporate headquarters. The company anticipates that it will complete a permanent long-term financing of its headquarters in the first half of 1997.
	Interest Expense remained relatively unchanged in 1995 compared to 1994.
CAPITAL REQUIREMENTS AND LIQUIDITY
	The Unitil System requires capital for the acquisition of property, plant and equipment in order to improve, protect, maintain and expand its electric and gas distribution systems, to develop and market new energy related products 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 System's Dividend Reinvestment and Stock Purchase Plan. When internally-generated funds are not available, it is the Company's policy to borrow interim 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. The size and timing of such financings depend on developments in the securities markets, the ability to meet certain financing covenants and the receipt of appropriate regulatory approval. The Company attempts to maintain a conservative capitalization structure, which contributes to both the stability of Unitil and its ability to market new securities. The Company has been able to access the financial markets to meet its capital requirements and does not anticipate a change in its access to, or the availability of, capital in the coming year.
	Cash Flow from Operations decreased by $10.8 million in 1996 after increasing by $0.7 million in 1995. Over one-half of the change in cash provided by operating activities in 1996 compared to 1995 was the result of a $6.0 million increase in the timing difference 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 decrease reflects other changes in the Companys working capital requirements as detailed in the Consolidated Statements of Cash Flows.
Operating Activities ($000's): 1996 1995 1994 Net Cash Provided by Operating Activities $6,229 $17,018 $16,349
	Cash Flow from Investing Activities increased approximately $5.8 million in 1996 compared to 1995, reflecting a $1.6 million increase in planned spending for utility system improvements as well as $2.7 million increase in expenditures for the construction of the Companys new corporate headquarters. The Company also received cash payments of $875,000 and $2 million from the State of New Hampshire in 1996 and 1995, respectively, related to the eminent domain taking of is former corporate headquarters for a highway expansion project.
Investing Activities ($000's): 1996 1995 1994 Net Cash (Used in)Investing Activities ($18,484) ($12,645) ($8,943)
	In 1997, total capital expenditures are expected to approximate $13.3 million. This projection reflects normal capital expenditures for system expansions, replacements and other improvements.
	The change in Cash Flows from Financing Activities in 1996 compared to 1995 reflects an increase in short-term borrowing requirements. Higher short-term borrowings in 1996 were primarily due to funding of the timing difference 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 interim construction financing of the Companys new corporate headquarters. The Company anticipates that it will complete a permanent long-term financing of its headquarters building in the first half of 1997. Short term borrowing requirements are met through Unitil's short-term credit facilities with four different banks.
Financing Activities ($000's): 1996 1995 1994 Net Cash Provided by (Used In) Financing Activities $11,759 ($4,785) ($5,301)
	During 1996, the Company raised $1,111,261 of additional common equity capital through the issuance of 52,081 shares of common stock in connection with the Dividend Reinvestment and Tax Deferred Savings and Investment plans. The Company raised $1,009,499 of additional common equity capital in 1995 and $1,037,809 of additional equity capital in 1994, through the respective issuance of 58,457 and 58,229 shares of common stock in connection with these plans. The Company also issued shares during each of the years from 1994 through 1996 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 1996, 1995 and 1994 were 2,400 shares, 3,291 shares and 4,110 shares, respectively.
REGULATORY MATTERS
Competition and Restructuring - Regulatory activity in both New Hampshire and Massachusetts has focused on the restructuring of the electric industry and the process of deregulating the retail sale of electric energy. In both states, January 1, 1998 has been targeted as the beginning of competition, or "Choice Date." Under these restructuring proposals, customers would be allowed to choose their supplier of electricity from the competitive market, and have their local utility deliver that electricity over its distribution systems at regulated rates.
	Unitil has been preparing for this 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 Companys assets and obligations that are dedicated to the current regulated franchises and, at the same time, provide choice for all customers. Simultaneous with this transition process for Unitils regulated utilities, the Company is moving to position its competitive market subsidiary, Unitil Resources, Inc., to pursue growth areas both within and beyond the Companys traditional franchises in all energy-related sectors, including electricity, gas, oil and propane.
New Hampshire -- In New Hampshire, House Bill 1392 (HB 1392) was signed into law by the Governor in May 1996. HB 1392 establishes principles, standards and a timetable for the New Hampshire Public Utilities Commission (NHPUC) to implement full, open retail electric competition as early as January 1, 1998, but no later than July 1, 1998. The bill also directs the NHPUC to set interim access charges for the recovery of above market "stranded" power supply costs and to make a final determination on these access charges within two years of implementation of full competition.
	As required by HB 1392, the NHPUC has set a procedural schedule for opening up the state to retail competition. In connection with that procedural schedule, the Company has filed with the NHPUC its "Customer Choice" Plan a transition plan that guarantees electric consumers open access to the retail energy supply market in New Hampshire. Under this plan, all of the Companys New Hampshire customers will continue to enjoy Unitils very competitive electric rates, among the lowest in New England, and also may benefit from future market competition and the resulting energy savings. Unitils Customer Choice Plan guarantees all its customers competitive retail delivery prices, open and nondiscriminatory access to competitive electricity suppliers, reliable electric service and comprehensive consumer protection standards. The Companys Customer Choice Plan achieves these benefits and safeguards for consumers while providing for full recovery of Unitils obligations that are dedicated to serving customers in the Companys New Hampshire franchises.
	On February 28, 1997, the NHPUC issued its Final Plan for restructuring the electric utility industry in New Hampshire. Concurrently, the NHPUC issued five supplemental orders establishing interim stranded cost charges for each of the states electric utilities, including Concord Electric Company (CECo) and Exeter & Hampton Electric Company (E&H), Unitils New Hampshire based electric distribution operating companies. The Final Plan and related orders include a number of complex regulatory and market restructuring issues which the Company is currently evaluating. Among other things, the Final Plan and orders provide for the recovery of CECos and E&Hs stranded costs related to their purchase power obligations and requires them to terminate the System Agreement under which they currently purchase all their power supply requirements from Unitil Power Corp. The termination provisions of the System Agreement permit termination by any party thereto on seven years prior written notice. On March 3, 1997, Northeast Utilities, the Parent Company of Public Service Company of New Hampshire, filed a suit in United States District Court in Concord, New Hampshire, to enjoin implementation of the Final Plan. At this time the Company is unable to predict the ultimate impact that the Final Plan and related orders will have on the Company, or the likely result of the Northeast Utilities lawsuit.
	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 electric consumers are allowed to choose from competing electric suppliers, and have this supply delivered across the local utility system. More than thirty electric suppliers, including Unitil Resources, the Companys competitive market subsidiary, are currently authorized to market electricity to Pilot Program participants. Unitil Resources began competitive marketing efforts in May, and began making sales in June.
	Under the Pilot Program, the NHPUC initially ordered Concord Electric Company and Exeter & Hampton Electric Company, Unitils New Hampshire-based distribution companies, to file tariffs which included a 10% discount to encourage participation and a mechanism to protect nonparticipants from any adverse cost consequences resulting from changes in power supply obligations. Both these tariff items would have had a significant impact on the ability of the Company to recover its power supply obligations. However, after filing for reconsideration of the NHPUCs Order, the Company entered into a settlement agreement with the NHPUC staff and the Office of the Consumer Advocate which provides the Company an opportunity to mitigate any losses which may result under the Pilot Program. The settlement was approved by the NHPUC on July 1, 1996. The Company also recorded in 1996, a one-time charge to earnings for estimated losses relating to Pilot Program operations.
Massachusetts- In March 1996, the Massachusetts Department of Public Utilities (MDPU) issued a Notice of Inquiry/Rulemaking, opening a new phase in its investigation on the restructuring of the electric utility industry in Massachusetts. Throughout 1996 the MDPU conducted a comprehensive information gathering effort, including holding numerous legislative style public hearings. On December 30, 1996, the MDPU issued a document entitled Electric Utility Restructuring Plan: Model Rules and Legislative Proposal. In this document the MDPU presented its framework, model rules and proposed legislation for a restructured electric utility industry. On February 24, 1997, the Massachusetts Governor filed legislation for electric industry restructuring which is generally consistent with the MDPUs proposal.
	The MDPUs proposed rules provide transition measures to accomplish the change from a regulated industry to a competitive market, as early as January 1, 1998. These measures include consumer safety and reliability standards, environmental protection measures and a reasonable framework for the recovery of utilities stranded costs related to generation investments and purchased power obligations. Included in the proposed rules and regulations is the requirement that each electric utility file "unbundled rates," that is, separate rate components for distribution, transmission and generation services and for access to the competitive supplier market. The MDPU has identified the unbundling of rates as "critical to provide both customers and competitors with the information they need to make decisions in a more competitive environment." The MDPU has required that the unbundled rates be revenue neutral for the Company, for each rate class, and for each customer. The Company is required to submit unbundled rates by March 3, 1997 to become effective on or after July 1, 1997.
	The MDPU has been supportive of the settlement process as a way to expedite electric utility restructuring in Massachusetts. On February 26, 1997, the MDPU approved a restructuring plan filed by the Massachusetts Attorney General, the Massachusetts Division of Energy Resources and numerous other parties in the context of a settlement agreement with the states largest investor owned utility. Under this plan, consumers will be allowed to choose an electricity suppler beginning as early as January 1, 1998, and are guaranteed a 10% savings on their electric bills. The plan requires the utility to divest itself of ownership of all its generation plant, and provides the utility with the opportunity to fully recover its stranded costs. It is likely that several restructuring offers of settlement will be filed in the first half of 1997 by other Massachusetts electric utilities. The Company is currently developing a transition plan for its Massachusetts utility subsidiary and exploring the use of the settlement process to expedite the restructuring process.
Rate Cases 	 	The last formal regulatory hearings to increase base 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. A majority of the System's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas and conservation program cost recovery mechanisms.
Millstone Unit No. 3
	Unitils Massachusetts operating subsidiary, Fitchburg Gas and Electric Light Company (FG&E), has a 0.217% ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 MW of electric capacity. In January 1996 the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its watch list as a Category 2 facility, which calls for increased NRC inspection attention. In March 1996 the NRC requested additional information about the operation of the unit from Northeast Utilities (NU), the units managing owner. As a result of an engineering evaluation completed by NU, Millstone 3 was taken out of service on March 30, 1996. The NRC later informed NU, in a letter dated June 28, 1996, that it had reclassified Millstone 3 as a Category 3 facility. The NRC assigns this rating to plants which it deems to have significant weaknesses that warrant maintaining the plant in shutdown condition until the operator demonstrates that adequate programs have been established and implemented to ensure substantial improvement in the operation of the plant. The NRC's letter also informed NU that this designation would require the NRC staff to obtain NRC approval by vote prior to a restart of the unit.
	The Company cannot predict when Millstone 3 will be allowed by the NRC to restart, but believes that the unit will remain shut down for a protracted period of time. During the period that Millstone 3 is out of service, FG&E will continue to incur its proportionate share of the units ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E will also incur costs to replace the power that was expected to be generated by the unit. During the outage FG&E has been recovering approximately $35,000 per month in replacement power costs through its fuel adjustment clause, which is subject to periodic review by the MDPU.
ENVIRONMENTAL
	The Company continues to work with federal and state environmental agencies to identify and assess environmental issues at two former gas manufacturing sites, the Sawyer Passway ("Sawyer Passway") and Logan Street ("Logan Street") sites, operated by Fitchburg Gas and Electric Light Company, the Company's combination gas and electric operating subsidiary.
	In December 1994 the Company accepted a Tier 1B permit from the Massachusetts Department of Environmental Protection (DEP) to address the Sawyer Passway site in Fitchburg, Massachusetts pursuant to the requirements of the Massachusetts Contingency Plan. A supplemental Phase II field investigation was conducted at the Site in July and August of 1996. Results of the investigation confirm, in the Phase II Investigation Report (the "Report"), the presence of some contamination, however, the Report indicates the identified contamination does not present "an imminent hazard to health, safety or the environment." The Phase II Investigation Report and the Risk Characterization was submitted to the DEP on January 31, 1997. Phase III, the Identification and Selection of Comprehensive Remedial Action Alternatives, has been delayed until June 30, 1997 to permit investigation of redevelopment alternatives on this site.
	The Company also conducted a Phase I assessment of the Logan Street Site on April 12, 1995. Results of that investigation suggest that there is some evidence of both groundwater and soil contamination. The site was numerically ranked using the Massachusetts Contingency Plan Numerical Ranking System Scoresheet and was classified as a Tier II Site. Currently, site closeout options are being investigated.
	The costs of such assessments and any remedial action determined to be necessary will initially be funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the Massachuestts Department of Public Utilities. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site. Because these investigations are at an early stage management cannot, at this time, predict the costs of future analysis and remediation.
NEW ACCOUNTING STANDARDS
	During 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and For Long-Lived Assets to be Disposed of. " This Statement requires a review of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable from the estimated future undiscounted cash flows associated with the asset. The adoption of this standard did not have a material impact on the financial position of the Company.
ITEM 8
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, 1996 and 1995, 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, 1996. 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, 1996 and 1995, and the consolidated results of their operations and their consolidated cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
	We have also audited Schedule VIII of Unitil Corporation and subsidiaries as of December 31, 1996 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
Boston, Massachusetts February 7, 1997
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 1996 1995 			 Utility Plant:			 Electric $157,874,414 $148,458,414 Gas 28,729,277 27,220,705 Common 18,779,677 8,494,093 Construction Work in Progress 2,161,114 6,003,991 Utility Plant 207,544,482 190,177,203 Less: Accumulated Depreciation 63,786,756 60,682,742 Net Utility Plant 143,757,726 129,494,461 			 Other Property & Investments 42,448 42,448 			 			 Current Assets:			 Cash 2,902,842 3,397,931 Accounts Receivable - Less Allowance for Doubtful Accounts of $660,114 and $622,596 16,383,323 14,931,699 Materials and Supplies 2,478,932 2,275,865 Prepayments 480,453 434,727 Accrued Revenue 8,859,188 2,577,715 Total Current Assets 31,104,738 23,617,937 			 			 Deferred Assets:			 Debt Issuance Costs 828,689 885,258 Cost of Abandoned Properties 25,432,258 27,254,791 Prepaid Pension Costs 7,347,635 6,689,093 Other Deferred Assets 23,594,289 23,718,296 Total Deferred Assets 57,202,871 58,547,438 			 TOTAL $232,107,783 $211,702,284
(The accompanying Notes are an integral part of these statements.)
					
CAPITALIZATION AND LIABILITIES 			 December 31, 1996 1995 			 Capitalization:			 Common Stock Equity $67,974,260 $63,894,789 Preferred Stock, Non-Redeemable, Non-Cumulative 225,000 225,000 Preferred Stock, Redeemable, Cumulative 3,665,900 3,773,900 Long-Term Debt, Less Current Portion 60,917,000 62,211,000 Total Capitalization 132,782,160 130,104,689 			 Capitalized Leases, Less Current Portion 4,629,832 3,732,947 			 Current Liabilities:			 Long-Term Debt, Current Portion 1,294,000 1,294,000 Capitalized Leases, Current Portion 1,000,210 741,832 Accounts Payable 15,103,925 14,565,075 Short-Term Debt 21,400,000 2,700,000 Dividends Declared and Payable 191,246 170,796 Refundable Customer Deposits 1,585,116 3,214,502 Taxes Payable (Refundable) (147,938) 216,596 Interest Payable 1,484,166 1,425,876 Other Current Liabilities 2,043,846 1,225,445 Total Current Liabilities	43,954,571		25,554,122 			 Deferred Liabilities: 			 Investment Tax Credits 1,610,117 1,803,821 Other Deferred Liabilities 8,488,593 9,763,878 Total Deferred Liabilities	10,098,710		11,567,699 			 Deferred Income Taxes 40,642,510 40,742,827 			 			 TOTAL $232,107,783 $211,702,284
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF EARNINGS	
Year Ended December 31, 1996 1995 1994 					 Operating Revenues:					 Electric $149,696,296 $138,099,371 $134,096,627 Gas 21,104,498 17,629,879 18,694,703 Other 45,427 940,954 624,560 Total Operating Revenues 170,846,221 156,670,204 153,415,890 					 Operating Expenses:					 Fuel and Purchased Power 100,768,116 92,346,024 90,342,737 Gas Purchased for Resale 13,322,853 10,522,742 11,139,311 Operation and Maintenance 24,110,140 22,824,218 21,903,619 Depreciation 6,953,720 6,315,613 6,129,617 Amortization of Abandoned Properties 1,822,533 1,518,047 1,605,640 Provisions for Taxes:					 Local Property and Other 4,983,229 4,784,109 4,384,032 Federal and State Income 4,612,534 4,134,826 4,156,479 Total Operating Expenses 156,573,125 142,445,579 139,661,435 Operating Income 14,273,096 14,224,625 13,754,455 Non-Operating (Income) Expenses (627,201) 216,860 64,108 Income Before Interest Expense 14,900,297 14,007,765 13,690,347 Interest Expense, Net 6,171,254 5,638,969 5,652,148 Net Income 8,729,043 8,368,796 8,038,199 Less Dividends on Preferred Stock 277,758 283,749 291,543 Net Income Applicable to Common Stock $8,451,285 $8,085,047 $7,746,656 					 Average Common Shares Outstanding 4,354,297 4,298,752 4,234,062 					 Earnings Per Average Common Share $1.94 $1.88 $1.83 					
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CAPITALIZATION	
December 31, 1996 1995 			 Common Stock Equity			 Common Stock, No Par Value (Authorized - 8,000,000 shares; $33,984,409 $32,822,673 Outstanding - 4,384,065 and 4,329,585 Shares) Stock Options 1,505,666 1,299,177 Retained Earnings 32,484,185 29,772,939 Total Common Stock Equity 67,974,260 63,894,789 Preferred Stock			 CECo Preferred Stock, Non-Redeemable, N on-Cumulative: 225,000 225,000 6% Series, $100 Par Value			 CECo Preferred Stock, Redeemable, Cumulative: 215,000 215,000 8.70% Series, $100 Par Value			 E&H Preferred Stock, Redeemable, Cumulative:			 5% Series, $100 Par Value 91,000 98,000 6% Series, $100 Par Value 168,000 168,000 8.75% Series, $100 Par Value 344,300 344,300 8.25% Series, $100 Par Value 406,000 406,000 FG&E Preferred Stock, Redeemable, Cumulative:			 5.125% Series, $100 Par Value 1,034,600 1,076,600 8% Series, $100 Par Value 1,407,000 1,466,000 Total Preferred Stock 3,890,900 3,998,900 Long-Term Debt			 CECo First Mortgage Bonds:			 Series C, 6.75%, Due January 15, 1998 1,552,000 1,584,000 Series H, 9.43%, Due September 1, 2003 5,850,000 6,500,000 Series I, 8.49%, Due October 14, 2024 6,000,000 6,000,000 E&H First Mortgage Bonds:			 Series E, 6.75%, Due January 15, 1998 504,000 511,000 Series H, 8.50%, Due December 15, 2002 805,000 910,000 Series J, 9.43%, Due September 1, 2003 4,500,000 5,000,000 Series K, 8.49%, Due October 14, 2024 9,000,000 9,000,000 FG&E Long-term Notes:			 Twelve year Notes, 8.55%, Due March 31, 2004 15,000,000 15,000,000 Thirty year Notes, 6.75%, Due November 30, 2023 19,000,000 19,000,000 Total Long-Term Debt 62,211,000 63,505,000 Less: Long-Term Debt, Current Portion 1,294,000 1,294,000 Total Long-Term Debt, Less Current Portion 60,917,000 62,211,000 Total Capitalization $132,782,160 $130,104,689
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CASH FLOWS	
Year Ended December 31, 1996 1995 1994 Cash Flows From Operating Activities:					 Net Income $8,729,043 $8,368,796 $8,038,199 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation and Amortization 8,776,253 7,833,660 7,735,257 Deferred Taxes 457,712 (314,365) 257,630 Amortization of Investment Tax Credit (193,704) (202,347) (210,676) Amortization of Debt Issuance Costs 56,571 72,252 63,882 Provision for Doubtful Accounts 911,628 889,320 717,735 (Gain) Loss on Taking of Land and Bldg (875,000) 140,698 ----
Changes in Assets and Liabilities: (Increase) Decrease In: Accounts Receivable (2,363,251) (2,539,334) (281,549) Materials and Supplies (203,067) (185,886) 437,485 Prepayments and Prepaid Pension (704,268) (913,405) (704,790) Accrued Revenue (6,281,473) (285,418) 1,354,192 Increase (Decrease) In: Accounts Payable 538,850 2,074,034 (949,245) Refundable Customer Deposits (1,629,386) 731,723 744,325 Taxes and Interest Payable (306,244) 611,238 (396,700) Other, Net (684,418) 736,870 (456,528) Net Cash Provided by Operating Activities 6,229,246 17,017,836 16,349,217 					 Cash Flows From Investing Activities:					 Acq. of Property, Plant & Equipment (19,358,615) (14,644,963) (8,943,491) Proceeds from Taking of Land & Bldg 875,000 2,000,000 ---- Net Cash Used in Investing Activities (18,483,615) (12,644,963) (8,943,491) 					 Cash Flows from Financing Activities:					 Proceeds From (Repayment of) ST Debt 18,700,000 2,700,000 (8,400,000) Proceeds From Issuance of LT Debt ---- ---- 15,000,000 Repayment of Long-Term Debt (1,294,000) (2,075,321) (6,797,773) Dividends Paid (5,997,348) (5,760,286) 5,514,283) Issuance of Common Stock 1,161,735 1,070,689 1,108,976 Retirement of Preferred Stock (108,000) (94,700) (104,100) Repayment of Capital Lease Obligations (703,107) (625,447) (594,209) Net Cash Provided by (Used in) Financing 11,759,280 (4,785,065) (5,301,389) Net (Decrease) Increase in Cash (495,089) (412,192) 2,104,337 Cash at Beginning of Year 3,397,931 3,810,123 1,705,786 Cash at End of Year $2,902,842 $3,397,931 $3,810,123 					 Supplemental Cash Flow Information:					 Interest Paid $6,132,611 $5,942,933 $5,518,586 Federal Income Taxes Paid $3,982,000 $3,435,000 $4,141,527 Non-Cash Financing Activities:					 Capital Leases Incurred $1,858,370 $1,262,685 $237,243
(The accompanying Notes are an integral part of these statements.)
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY		
Deferred Stock Common Option Retained Shares Plan Earnings Total 							 Balance at January 1, 1994 $30,643,009 $910,892 $24,679,876 $56,233,777 Net Income for 1994 8,038,199 8,038,199 Dividends on preferred shares (291,543) (291,543) Dividends on common shares -							 at an annual rate of $1.24 per share (5,243,516) (5,243,516) Stock Option Plan 180,475 180,475 Exercised stock options-4,110 shares 71,166 (29,169) 41,997 Issuance of 58,229 common shares(a)1,037,809 1,037,809
Balance at December 31, 1994 31,751,984 1,062,198 27,183,016 59,997,198
Net Income for 1995 8,368,796 8,368,796 Dividends on preferred shares (283,749) (283,749) Dividends on common shares -							 at an annual rate of $1.28 per share (5,495,124) (5,495,124) Stock Option Plan 248,127 248,127 Exercised stock options-3,291 shares 61,190 (11,148) 50,042 Issuance of 58,457 common shares(a)1,009,499 1,009,499 							 Balance at December 31, 1995 32,822,673 1,299,177 29,772,939 63,894,789
Net Income for 1996 8,729,043 8,729,043 Dividends on preferred shares (277,758) (277,758) Dividends on common shares -							 at an annual rate of $1.32 per share (5,740,039) (5,740,039) Stock Option Plan 237,044 237,044 Exercised stock options-2,400 shares 50,475 (30,555) 19,920 Issuance of 52,081 common shares(a)1,111,261 1,111,261
Balance at December 31, 1996 $33,984,409 $1,505,666 $32,484,185 $67,974,260
(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 --- The Company is registered with the Securities and Exchange Commission (SEC) as a holding company (with subsidiaries providing electric service and electric power supply in New Hampshire, electric and gas service in Massachusetts and consulting and other services on energy related matters) under the Public Utility Holding Company Act of 1935 (1935 Act). In addition, the Company and several of its wholly-owned utility operating subsidiaries -- Concord Electric Company (CECo), Exeter & Hampton Electric Company (E&H), Fitchburg Gas and Electric Light Company (FG&E), and Unitil Power Corp. (Unitil Power) -- are subject to regulation by various other agencies. With respect to their rates and accounting practices, two of the retail subsidiaries, CECo and E&H, are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC), FG&E is subject to regulation by the Massachusetts Department of Public Utilities (MDPU), and Unitil Power is regulated by the Federal Energy Regulatory Commission (FERC). CECo, E&H, FG&E and Unitil Power conform with generally accepted accounting principles, as applied in the case of regulated public utilities, and conform with the accounting requirements and ratemaking practices of the regulatory authorities having jurisdiction.
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 Companys 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 --- Depreciation provisions for the Companys 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: 1996 - 3.45 percent; 1995 - 3.48 percent, and 1994 - 3.49 percent.
Amortization of Abandoned Properties --- FG&E is recovering a portion of its former investment in the Seabrook Nuclear Power Plant in rates to its customers through a Seabrook Amortization Surcharge as ordered by the MDPU.
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 Standard --- During 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and For Long-Lived Assets to be Disposed of." This Statement requires a review of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable from the estimated future undiscounted cash flows associated with the asset. The adoption of this standard did not have a material impact on the financial position of the Company.
Reclassifications --- Reclassifications are made periodically to amounts previously reported to conform with current year presentation.
Note 2: Common Stock
New Shares Issued --- During 1996, the Company raised $1,111,261 of additional common equity capital through the issuance of 52,081 shares of common stock in connection with the Dividend Reinvestment and Stock Purchase Plan and 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 1995, the Company raised $1,009,499 of additional common equity capital through the issuance of 58,457 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 and expire within ten years of the grant date. 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 $237,044, $248,127 and $180,475 for the years ended December 31, 1996, 1995 and 1994, respectively.
Share Option Activity of the KESOP is presented in the following table: 1996 1995 1994 Beginning Options Outstanding & Exercisable 173,362 147,981 142,354 Options Granted 1,000 17,000 --- Dividend Equivalents Earned 10,533 11,672 9,737 Options Exercised (2,400) (3,291) (4,110) Options Canceled --- --- --- Ending Options Outstanding & Exercisable 182,495 173,362 147,981 			 Range of Option Grant Price per Share $12.11-$18.28 $12.11-$14.93 $12.11-$17.74
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 Company has omitted certain disclosures relating to SFAS No. 123, as the recording of compensation expense did not materially differ from the way the Company had previously recorded this expense.
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 $5,513,077 and $8,093,982, respectively, available for the payment of cash dividends on their common stock at December 31, 1996. Under the terms of long-term debt Purchase Agreements, FG&E had $13,712,366 of retained earnings available for the payment of cash dividends on its common stock at December 31, 1996.
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 1996, 1995 and 1994 were: 1996 - $108,000; 1995 - $94,700; and 1994 - $104,100. The aggregate amount of sinking fund requirements of the Redeemable Cumulative Preferred Stock for each of the five years following 1996 are $206,000 per year.
Note 4: Long-Term Debt		
Under the terms of both CECos Indenture of Mortgage and Deed of Trust and the supplemental indenture thereto relating to long-term debt, the sinking fund requirements of CECo's Series C Bonds may be satisfied by certifying to the Mortgage Trustee net additional property in lieu of making cash redemptions. In 1996, total sinking fund payments for CECo and E&H relating to long-term debt amounted to $1,294,000. In 1995, CECo satisfied its requirements with respect to its Series C Bonds by certifying to the Mortgage Trustee net additional property.
Certain of the loan agreements contain provisions which, among other things, limit the incurring of additional long-term debt.
The aggregate amount of sinking fund requirements and normal scheduled redemptions for each of the five years following 1996 are: 1997 - $1,294,000; 1998 - $4,339,000; 1999 - $2,290,000; 2000 - $2,290,000, and 2001 - $4,940,000.
The fair value of the Companys 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, 1996 and 1995.
Note 5: Credit Arrangements
At December 31, 1996, the Company had unsecured committed bank lines for short-term debt aggregating $23,000,000 with four banks for which it pays commitment fees. At December 31, 1996, the unused portion of the committed credit lines outstanding was $1,600,000. The average interest rates on all short-term borrowings were 5.79% and 6.59% during 1996 and 1995, respectively.
Note 6: Leases
The Companys 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 include a twenty-five-year lease, which began on April 1, 1973, for a combustion turbine and a liquefied natural gas storage and vaporization facility. This lease provides for a ten-year renewal period at the option of FG&E. In addition, Unitils 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 1996 1995 Electric $2,054,025 $2,054,025 Gas 726,329 726,329 Common 5,822,813 5,061,846 Gross Plant 8,603,167 7,842,200 Less: Accumulated Depreciation 2,973,125 3,367,421 Net Plant $5,630,042 $4,474,779
The following is a schedule by years of future minimum lease payments and present value of net minimum lease payments under capital and operating leases as of December 31, 1996:
Year Ending December 31, Capital Operating 1997 $1,637,056 $63,902 1998 1,348,372 34,022 1999 1,222,057 652 2000 1,013,754 2001 824,253 2002 - 2006 1,899,428 Total Minimum Lease Payments $7,944,920 $98,576 Less: Amount Representing Interest 2,314,878 Present Value of Net Minimum Lease Payments $5,630,042
Total rental expense charged to operations for the years ended December 31, 1996, 1995 and 1994 amounted to $161,000; $447,000; and $320,000, respectively.
Note 7: Income Taxes
Federal Income Taxes were provided for the following items for the years ended December 31, 1996, 1995 and 1994, respectively:
1996 1995 1994 Current Federal Tax Provision:						 Operating Income $3,658,222 $3,959,976 $3,497,311 Amortization of Investment Tax Credits (193,704) (202,347) (210,676) Total Current Federal Tax Provision 3,464,518 3,757,629 3,286,635 Deferred Federal Tax Provision:						 Accelerated Tax Depreciation 602,761 545,233 590,655 Abandoned Properties (654,985) (578,255) (611,620) Allowance for Funds Used During Construction ("AFUDC") and Overheads (71,751) (73,191) (73,192) Post Retirement Benefits Other Than Pensions(20,279) (19,941) (27,162) Deferred Maintenance Cost and Other (174,549) (86,178) (122,382) Percentage Repair Allowance 123,871 106,630 145,927 Deferred Advances 303,699 (482,112) 26,967 Deferred Pensions 211,888 289,622 256,867 						 Total Deferred Federal Tax Provision 320,655 (298,192) 186,060 Total Federal Tax Provision $3,785,173 $3,459,437 $3,472,695
The components of the Federal and State income tax provisions reflected in the accompanying consolidated statements of earnings for the years ended December 31, 1996, 1995 and 1994 were as follows:
1996 1995 1994 Federal:			 Current $3,658,222 $3,959,976 $3,497,311 Deferred 320,655 (298,192) 186,060 Amortization of Investment Tax Credits (193,704) (202,347) (210,676) Total Federal Tax Provision 3,785,173 3,459,437 3,472,695 			 State:			 Current 690,303 691,563 612,214 Deferred 137,058 (16,174) 71,570 Total State Tax Provision 827,361 675,389 683,784 			 Total Provision for Federal and State 			 Income Taxes $4,612,534 $4,134,826 $4,156,479
	 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, 1996 1995 1994 Statutory Federal Income Tax Rate 34% 34% 34% Income Tax Effects of:			 Investment Tax Credits (2) (2) (2) Donation of Appreciated Land --- (1) --- Federal Income Tax - Prior (1) (1) --- Other, Net (1) (1) (2) Effective Federal Income Tax Rate 30% 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, 1996 1995 Accelerated Depreciation $24,374,031 $23,971,624 Abandoned Property 9,687,654 10,381,893 Contributions in Aid to Construction (2,810,811) (3,166,565) Percentage Repair Allowance 1,692,616 1,599,813 Cathodic Protection 349,384 294,978 Retirement Loss 1,526,116 1,288,346 Deferred Pensions 2,518,284 2,303,456 AFUDC 61,992 78,878 Overheads 301,093 360,470 KESOP (534,982) (451,009) Bad Debts (249,670) (235,785) Accumulated Deferred (SFAS 109) 3,884,726 4,442,755 Other (157,923) (126,027) Total Deferred Income Taxes $40,642,510 $40,742,827
Note 8: Joint Ownership 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 1996 Consolidated Statements of Earnings. Information with respect to these units as of December 31, 1996 is set forth in the table below:
Company's Share Joint Ownership Proportionate Share of Amount of Utility Accumulated Units State Ownership % Total MW Plant in Service Depreciation
Millstone Unit No.3 CT 0.2170 2.50 $11,469,857 $3,491,233 Wyman Unit No.4 ME 0.1822 1.13 408,141 273,023 New Haven Harbor CT 4.5000 20.12 7,065,274 5,057,037 23.75 $18,943,272 $8,821,293
Note 9: Benefit Plans
Pension Plans --- Four of the Companys subsidiaries have Retirement and Pension plans and related Trust Agreements to provide retirement annuities for participating employees at age 65. The entire cost of the plans is borne by the respective subsidiaries.
Net periodic pension (income) cost for 1996, 1995 and 1994 included the following components: 				 1996 1995 1994 Service Cost--Benefits Earned During the Period $703,148 $616,016 $693,340 Interest Cost on Projected Benefit Obligation 1,920,786 1,811,981 1,795,836 Expected Return on Plan Assets (4,836,448)(6,412,405)(2,714,751) Net Amortization and Deferral 2,016,445 3,652,029 (20,546) Net Periodic Pension (Income) Cost $(196,069) $(332,379) $(246,121)
The following table sets forth the plans funded status at December 31, 1996, 1995 and 1994:
Projected Benefit Obligation:			 1996 1995 1994 Vested $21,394,580 $24,250,626 $19,970,389 Non-Vested 1,137,183 148,106 331,910 Accumulated 22,531,763 24,398,732 20,302,299 Due to Recognition of Future Salary Increases 4,375,492 3,837,798 2,521,055 Total 26,907,255 28,236,530 22,823,354 Plan Assets at Fair Value 36,547,430 32,858,602 27,343,779 Funded Status 9,640,175 4,622,072 4,520,425 Unrecognized Net Loss (Gain) (2,625,660) 1,736,643 953,653 Unrecognized Prior Service Cost 111,232 124,718 138,204 Unrecognized Transition Obligation 221,888 205,660 189,432 Prepaid Pension Cost $7,347,635 $6,689,093 $5,801,714
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 1996, 1995 and 1994 were 7.75%, 7.75%, and 8.25%, respectively, while the rate of increase in future compensation levels was 4.50% for the last three years. The expected long-term rates of return on assets in 1996, 1995 and 1994 were 9.25%, 9.50%, and 9.50%, respectively.
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 $71,000; $60,000; and $53,000 for the years ended December 31, 1996, 1995 and 1994, 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 12% 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 $356,574; $301,486; and $284,248 for the years ended December 31, 1996, 1995 and 1994, respectively.
Post-Retirement Benefits --- The Companys subsidiaries provide health care benefits to retirees for a twelve-month period following their retirement. The Companys 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 employees 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, 1996 and 1995, the accumulated post retirement benefit obligation (transition obligation) was approximately $342,000 and $364,000, respectively, and the period cost associated with these benefits for 1996 and 1995 was $132,447 and $132,172, 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. 106, as the accumulated post-retirement benefit obligation (transition obligation) is not material.
Note 10: Commitments and Contingencies
Environmental Matters --- The Company continues to work with federal and state environmental agencies to identify and assess environmental issues at two former gas manufacturing sites, the Sawyer Passway ("Sawyer Passway") and Logan Street ("Logan Street") sites, operated by Fitchburg Gas and Electric Light Company, the Company's combination gas and electric operating subsidiary.
In December 1994 the Company accepted a Tier 1B permit from the Massachusetts Department of Environmental Protection (DEP) to address the Sawyer Passway site in Fitchburg, Massachusetts pursuant to the requirements of the Massachusetts Contingency Plan. A supplemental Phase II field investigation was conducted at the Site in July and August of 1996. Results of the investigation confirm, in the Phase II Investigation Report (the "Report"), the presence of some contamination, however, the Report indicates the identified contamination does not present "an imminent hazard to health, safety or the environment." The Phase II Investigation Report and the Risk Characterization was submitted to the DEP on January 31, 1997. Phase III, the Identification and Selection of Comprehensive Remedial Action Alternatives, has been delayed until June 30, 1997 to permit investigation of redevelopment alternatives on this site.
The Company also conducted a Phase I assessment of the Logan Street Site on April 12, 1995. Results of that investigation suggest that there is some evidence of both groundwater and soil contamination. The site was numerically ranked using the Massachusetts Contingency Plan Numerical Ranking System Scoresheet and was classified as a Tier II Site. Currently, site closeout options are being investigated.
The costs of such assessments and any remedial action determined to be necessary will initially be funded from traditional sources of capital and recovered from customers under a rate recovery mechanism approved by the Massachuestts Department of Public Utilities. The Company also has a number of liability insurance policies that may provide coverage for environmental remediation at this site. Because these investigations are at an early stage management cannot, at this time, predict the costs of future analysis and remediation.
Regulatory Matters
Competition and Restructuring - Regulatory activity in both New Hampshire and Massachusetts has focused on the restructuring of the electric industry and the process of deregulating the retail sale of electric energy. In both states, January 1, 1998 has been targeted as the beginning of competition, or "Choice Date." Under these restructuring proposals, customers would be allowed to choose their supplier of electricity from the competitive market, and have their local utility deliver that electricity over its distribution systems at regulated rates.
Unitil has been preparing for this 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 Companys assets and obligations that are dedicated to the current regulated franchises and, at the same time, provide choice for all customers. Simultaneous with this transition process for Unitils regulated utilities, the Company is moving to position its competitive market subsidiary, Unitil Resources, Inc., to pursue growth areas both within and beyond the Companys traditional franchises in all energy-related sectors, including electricity, gas, oil and propane. 	 New Hampshire In New Hampshire, House Bill 1392 (HB 1392) was signed into law by the Governor in May 1996. HB 1392 establishes principles, standards and a timetable for the New Hampshire Public Utilities Commission (NHPUC) to implement full, open retail electric competition as early as January 1, 1998, but no later than July 1, 1998. The bill also directs the NHPUC to set interim access charges for the recovery of above market "stranded" power supply costs and to make a final determination on these access charges within two years of implementation of full competition.
As required by HB 1392, the NHPUC has set a procedural schedule for opening up the state to retail competition. In connection with that procedural schedule, the Company has filed with the NHPUC its "Customer Choice" Plan a transition plan that guarantees electric consumers open access to the retail energy supply market in New Hampshire. Under this plan, all of the Companys New Hampshire customers will continue to enjoy Unitils very competitive electric rates, among the lowest in New England, and also may benefit from future market competition and the resulting energy savings. Unitils Customer Choice Plan guarantees all its customers competitive retail delivery prices, open and nondiscriminatory access to competitive electricity suppliers, reliable electric service and comprehensive consumer protection standards. The Companys Customer Choice Plan achieves these benefits and safeguards for consumers while providing for full recovery of Unitils obligations that are dedicated to serving customers in the Companys New Hampshire franchises.
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 electric consumers are allowed to choose from competing electric suppliers, and have this supply delivered across the local utility system. More than thirty electric suppliers, including Unitil Resources, the Companys competitive market subsidiary, are currently authorized to market electricity to Pilot Program participants. Unitil Resources began competitive marketing efforts in May, and began making sales in June.
Under the Pilot Program, the NHPUC initially ordered Concord Electric Company and Exeter & Hampton Electric Company, Unitils New Hampshire-based distribution companies, to file tariffs which included a 10% discount to encourage participation and a mechanism to protect nonparticipants from any adverse cost consequences resulting from changes in power supply obligations. Both these tariff items would have had a significant impact on the ability of the Company to recover its power supply obligations. However, after filing for reconsideration of the NHPUCs Order, the Company entered into a settlement agreement with the NHPUC staff and the Office of the Consumer Advocate which provides the Company an opportunity to mitigate any losses which may result under the Pilot Program. The settlement was approved by the NHPUC on July 1, 1996. The Company also recorded in 1996, a one-time charge to earnings for estimated losses relating to Pilot Program operations.
Massachusetts - In March 1996, the Massachusetts Department of Public Utilities (MDPU) issued a Notice of Inquiry/Rulemaking, opening a new phase in its investigation on the restructuring of the electric utility industry in Massachusetts. Throughout 1996 the MDPU conducted a comprehensive information gathering effort, including holding numerous legislative style public hearings. On December 30, 1996, the MDPU issued a document entitled Electric Utility Restructuring Plan: Model Rules and Legislative Proposal. In this document the MDPU presented its framework, model rules and proposed legislation for a restructured electric utility industry. On February 24, 1997, the Massachusetts Governor filed legislation for electric industry restructuring which is generally consistent with the MDPUs proposal.
The MDPUs proposed rules provide transition measures to accomplish the change from a regulated industry to a competitive market, as early as January 1, 1998. These measures include consumer safety and reliability standards, environmental protection measures and a reasonable framework for the recovery of utilities stranded costs related to generation investments and purchased power obligations. Included in the proposed rules and regulations is the requirement that each electric utility file "unbundled rates," that is, separate rate components for distribution, transmission and generation services and for access to the competitive supplier market. The MDPU has identified the unbundling of rates as "critical to provide both customers and competitors with the information they need to make decisions in a more competitive environment." The MDPU has required that the unbundled rates be revenue neutral for the Company, for each rate class, and for each customer. The Company is required to submit unbundled rates by March 3, 1997 to become effective on or after July 1, 1997.
The MDPU has been supportive of the settlement process as a way to expedite electric utility restructuring in Massachusetts. On February 26, 1997, the MDPU approved a restructuring plan filed by the Massachusetts Attorney General, the Massachusetts Division of Energy Resources and numerous other parties in the context of a settlement agreement with the states largest investor owned utility. Under this plan, consumers will be allowed to choose an electricity suppler beginning as early as January 1, 1998, and are guaranteed a 10% savings on their electric bills. The plan requires the utility to divest itself of ownership of all its generation plant, and provides the utility with the opportunity to fully recover its stranded costs. It is likely that several restructuring offers of settlement will be filed in the first half of 1997 by other Massachusetts electric utilities. The Company is currently developing a transition plan for its Massachusetts utility subsidiary and exploring the use of the settlement process to expedite the restructuring process.
Rate Cases
The last formal regulatory hearings to increase base 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. A majority of the System's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas and conservation program cost recovery mechanisms.
Millstone Unit No. 3
Unitils Massachusetts operating subsidiary, Fitchburg Gas and Electric Light Company (FG&E), has a 0.217% ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 MW of electric capacity. In January 1996 the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its watch list as a Category 2 facility, which calls for increased NRC inspection attention. In March 1996 the NRC requested additional information about the operation of the unit from Northeast Utilities (NU), the units managing owner. As a result of an engineering evaluation completed by NU, Millstone 3 was taken out of service on March 30, 1996. The NRC later informed NU, in a letter dated June 28, 1996, that it had reclassified Millstone 3 as a Category 3 facility. The NRC assigns this rating to plants which it deems to have significant weaknesses that warrant maintaining the plant in shutdown condition until the operator demonstrates that adequate programs have been established and implemented to ensure substantial improvement in the operation of the plant. The NRC's letter also informed NU that this designation would require the NRC staff to obtain NRC approval by vote prior to a restart of the unit.
The Company cannot predict when Millstone 3 will be allowed by the NRC to restart, but believes that the unit will remain shut down for a protracted period of time. During the period that Millstone 3 is out of service, FG&E will continue to incur its proportionate share of the units ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E will also incur costs to replace the power that was expected to be generated by the unit. During the outage FG&E has been recovering approximately $35,000 per month in replacement power costs through its fuel adjustment clause, which is subject to periodic review by the MDPU.
Litigation --- The Company is also involved in other 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.
Purchased Power and Gas Supply Contracts --- FG&E and Unitil Power have 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 the electric purchased power contracts at December 31, 1996, was as follows: Est. Annual Min. Payments Which Cover Unit 1996 Energy Purchased Contract Future Debt Service Fuel Type MW Entitlement (MWHs) End-Date Requirements ($000) 						 Unitil Power						 Oil 10.0 27,710 2005 None Gas 22.5 96,016 2010 $1,871 [1] Gas 1.5 8,097 2012 None Oil/Gas 25.0 76,265 1996 None Oil/Gas 23.0 28,532 1998 None Oil/Gas 15.0 15,253 2006 None Oil/Gas 10.0 8,125 2008 None Coal 20.0 39,049 2009 None [2] Coal/Oil 24.8 135,964 2005 None Nuclear 25.5 182,634 1998 None Nuclear 5.0 21,285 2005 None Nuclear 10.1 87,854 2010 None Nuclear 2.0 18,614 2013 None Hydro 8.9 2001 $1,103 [3] Refuse 6.0 44,746 2003 None System 8.0 3,944 1996 None System 18.3 402 2002 None Various 16.0 25,010 1999 None Various 229,673 Short-term None 						 FG&E						 Nuclear 10.0 59,135 1996 None Hydro 5.3 2001 $479 [3] Hydro 3.0 19,114 2012 None Wood 14.0 107,780 2012 None System 15.0 41,819 2001 None Various 233,998 Short-term None 						 Notes:						 [1] Total estimated 1996 annualized capacity payments, including debt service requirements. [2] Contract was terminated in 1996 and replaced with a purchase power option agreement. [3] Total support charges including debt service requirements.						
Note 11: Segment Information
The following additional information is presented about the electric and gas operations of the Company: 			 Electric Operations 1996 1995 1994 Operating Revenues $149,696,296 $138,099,371 $134,096,627 Operating Income Before Income Taxes $16,587,166 $16,781,348 $15,884,879 Identifiable Assets as of December 31 $179,999,328 $174,984,327 $172,350,572 Depreciation $6,098,187 $5,504,701 $5,359,212 Construction Expenditures $10,833,786 $9,158,920 $7,109,091 			 			 Gas Operations 1996 1995 1994 Operating Revenues $21,104,498 $17,629,879 $18,694,703 Operating Income Before Income Taxes $2,298,464 $1,578,103 $2,026,055 Identifiable Assets as of December 31 $33,472,548 $30,446,104 $29,065,750 Depreciation $855,533 $810,912 $770,405 Construction Expenditures $1,915,446 $2,007,922 $1,816,390 			 Total Company 1996 1995 1994 Electric and Gas Operating Revenues $170,800,794 $155,729,250 $152,791,330 Other Revenue 45,427 940,954 624,560 Total Operating Revenues $170,846,221 $156,670,204 $153,415,890 Operating Income Before Income Taxes $18,885,630 $18,359,451 $17,910,934 Income Tax Expense 4,612,534 4,134,826 4,156,479 Non-Operating Income (Expense) (627,201) 216,860 64,108 Net Interest and Other Expenses 6,171,254 5,638,969 5,652,148 Net Income $8,729,043 $8,368,796 $8,038,199 Dividend Requirements on Preferred Stock 277,758 283,749 291,543 Net Income Applicable to Common Stock $8,451,285 $8,085,047 $7,746,656 Identifiable Assets as of December 31 $213,471,876 $205,430,431 $201,416,322 Unallocated Assets 18,635,907 6,271,853 3,105,139 Total Assets as of December 31 $232,107,783 $211,702,284 $204,521,461 Depreciation $6,953,720 $6,315,613 $6,129,617 Construction Expenditures $19,358,615 $14,644,963 $8,943,491
	Expenses used to determine operating income before taxes are charged directly to either 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 MDPU. Assets allocated to each segment are based upon specific identification of such assets provided by Company records. Assets not so identified represent primarily working capital items and real property.
Item 9.
Item 9.	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure
	None
PART III
Item 10.
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 6 of the 1996 Proxy Statement.
Item 11.
Item 11. EXECUTIVE COMPENSATION Information required by this Item is set forth in Exhibit 99.1 on pages 7 through 11 of the 1996 Proxy Statement.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by this Item is set forth in Exhibit 99.1 on pages 2 through 4 of the 1996 Proxy Statement and is incorporated herein by reference. 	 Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 	 None
PART IV
Item 14.
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, 1996 and 1995 	
Consolidated Statements of Earnings - for the years ended December 31, 1996, 1995 and 1994		
Consolidated Statements of Capitalization - December 31, 1996 and 1995	
Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994	
Consolidated Statements of Changes in Common Stock Equity - for the years ended December 31, 1996, 1995 and 1994	
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, 		 1996; 1995 and 1994		
	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. ** 		 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 Form 10-K unless 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, 1952 of E&H Exhibit 4.5 to 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 		 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 		 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 with Unitil Realty Corp.'s Exhibit 4.16 to acquisition of the Company's Form 10-K facilities in Exeter, New Hampshire. for 1988 		 10.1 Labor Agreement effective June 1, 1994 between CECo and The International Brotherhood of Electrical Exhibit 10.1 to Form Workers, Local Union No. 1837 10-K for 1994 		 10.2 Labor Agreement effective June 25, 1995 between E&H and The International Brotherhood of Electrical Workers, Local Union No. 1837, Unit 1. Filed herewith 		 10.3 Labor Agreement effective May 1, 1994 between FG&E and The Brotherhood of Utility Workers of Exhibit 10.3 to Form New England, Inc., Local Union No. 340. 10-K for 1994 		 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 		 10.5 Supplement No. 1 to Unitil System Agreement providing that Unitil Power will supply wholesale Exhibit 10.8 to requirements electric service to Form 10-K CECo and E&H. for 1987 		 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 February 21, 1989, Exhibit 10.55 to between the Company and Form 8 the persons named in the dated schedule attached thereto. April 12, 1989 		 10.8 Key Employee Stock Option Exhibit 10.56 to Plan effective as of Form 8 dated January 17, 1989. 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 		 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 1996 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, 1996.
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We have issued our report dated February 7, 1997, 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, 1996. 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 28, 1997
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 20, 1997 By Peter J. Stulgis Peter J. Stulgis 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
Peter J. Stulgis Principal Executive March 20, 1997 Peter J. Stulgis Officer; Director (Chairman of the Board of Directors and Chief Executive Officer)
Michael J. Dalton Principal Operating March 20, 1997 Michael J. Dalton Officer; Director (President and Chief Operating Officer)
Gail A. Siart Principal Financial March 20, 1997 Gail A. Siart Officer (Treasurer and Chief Financial Officer)
G. Arnold Haynes Director March 20, 1997 G. Arnold Haynes
J. Parker Rice, Jr. Director March 20, 1997 J. Parker Rice, Jr.
Charles H. Tenney III Director March 20, 1997 Charles H. Tenney III
Franklin Wyman, Jr. Director March 20, 1997 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, 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 					 Year Ended December 31, 1995					 					 Reserves Deducted from A/R					 					 Electric 504,790 627,197 170,563 812,278 490,272 Gas 69,059 254,387 49,271 240,393 132,324 573,849 881,584 219,834 1,052,671 622,596 					 Year Ended December 31, 1994					 					 Reserves Deducted from A/R					 					 Electric 510,853 552,905 193,202 752,170 504,790 Gas 70,402 157,098 58,714 217,155 69,059 581,255 710,003 251,916 969,325 573,849 					 (A) Collections on Accounts Previously Charged Off					 (B) Bad Debts Charged Off