<PAGE 1> UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 Form 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Mark One) [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________________ to ________________ Commission file number 1-7316 COMMONWEALTH ENERGY SYSTEM (Exact name of registrant as specified in its Declaration of Trust) Massachusetts 04-1662010 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One Main Street, Cambridge, Massachusetts 02142-9150 (Address of principal executive offices) (Zip Code) (617) 225-4000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Shares of Beneficial New York Stock Exchange, Inc. Interest $2 par value Pacific Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: Title of Class None Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ x ] Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES [ x ] NO [ ] Aggregate market value of the voting stock held by non-affiliates of the registrant as of March 16, 1998: $789,947,326 Common Shares outstanding at March 16, 1998: 21,531,784 shares Document Incorporated by Reference Part in Form 10-K Notice of 1998 Annual Meeting and Proxy Statement, dated March 30, 1998 (pages as specified herein) Part III List of Exhibits begins on page 55 of this report. <PAGE 2> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES TABLE OF CONTENTS PART I PAGE Item 1. Business............................................... 3 General............................................. 3 Electric Power Supply............................... 4 Power Supply Commitments and Support Agreements..... 7 Electric Fuel Supply................................ 7 Nuclear Fuel Supply and Disposal.................... 8 Gas Supply.......................................... 8 Rates, Regulation and Legislation................... 9 Competition......................................... 14 Segment Information................................. 14 Environmental Matters............................... 14 Construction and Financing.......................... 15 Employees........................................... 15 Item 2. Properties............................................. 15 Item 3. Legal Proceedings...................................... 16 Item 4. Submission of Matters to a Vote of Security Holders.... 16 PART II Item 5. Market for the Registrant's Securities and Related Stockholder Matters.................................... 17 Item 6. Selected Financial Data................................ 18 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 19 Item 8. Financial Statements and Supplementary Data............ 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 28 PART III Item 10. Trustees and Executive Officers of the Registrant...... 52 Item 11. Executive Compensation................................. 53 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 53 Item 13. Certain Relationships and Related Transactions......... 54 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................................ 54 Signatures........................................................ 72 <PAGE 3> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES PART I. Item 1. Business General Commonwealth Energy System, a Massachusetts trust, is an unincorporated business organization with transferable shares. It is organized under a Declaration of Trust dated December 31, 1926, as amended, pursuant to the laws of Massachusetts. It is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935, holding all of the stock of four operating public utility companies. Commonwealth Energy System, the parent company, is referred to in this report as the "System" and, together with its subsidiaries, is collectively referred to as "the system." The operating utility subsidiaries of the System are engaged in the generation, transmission and distribution of electricity and the distribution of natural gas, all within Massachusetts. These subsidiaries are: Electric Gas Cambridge Electric Light Company Commonwealth Gas Company Canal Electric Company Commonwealth Electric Company In addition to the utility companies, the System also owns all of the stock of a steam distribution company (COM/Energy Steam Company), five real estate trusts, a liquefied natural gas (LNG) and vaporization facility (Hopkinton LNG Corp.) and three new subsidiaries that are pursuing energy- related business opportunities. Subsidiaries of the System receive technical assistance as well as financial, data processing, accounting, legal and other services from a wholly-owned services company subsidiary (COM/Energy Services Company). The five real estate subsidiaries are: Darvel Realty Trust, which is a joint-owner of the Riverfront Office Park complex in Cambridge; COM/Energy Acushnet Realty, which leases land to Hopkinton LNG Corp. (Hopkinton); COM/Energy Research Park Realty, which was organized to develop a research building in Cambridge; COM/Energy Cambridge Realty, which was organized to hold various properties; and COM/Energy Freetown Realty (Freetown), which holds 596 acres of land in Freetown, Massachusetts. Advanced Energy Systems, Inc. (formerly COM/Energy Enterprises, Inc.), together with two new subsidiaries formed during 1997, COM/Energy Marketing, Inc. and COM/Energy Technologies, Inc., were established to pursue business opportunities created by the restructuring of the electric and gas industries and the emergence of new energy technologies. Each of the operating utility subsidiaries serves retail customers except for Canal Electric Company (Canal) which operates an electric generating station located in Sandwich, Massachusetts. The station consists of Canal Unit 1, an oil-fired steam electric generating unit that is wholly- owned by Canal and has a rated capacity of 569 MW, and Canal Unit 2, a steam electric generating unit that was converted to dual-fuel capability (oil and natural gas) in 1996 that is jointly-owned by Canal and Montaup Electric Company (Montaup) (an unaffiliated company) and has a rated capacity of <PAGE 4> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 580 MW. Canal Unit 2 is operated under an agreement with Montaup which provides for the equal sharing of output, fixed charges and operating expenses. Electric service is furnished by Cambridge Electric Light Company (Cam- bridge Electric) and Commonwealth Electric Company (Commonwealth Electric) at retail to approximately 321,000 year-round and 46,100 seasonal customers in 41 communities in eastern and southeastern Massachusetts covering 1,112 square miles and having an aggregate population of 645,000. The territory served includes the communities of Cambridge, New Bedford and Plymouth and the geographic area comprising Cape Cod and Martha's Vineyard. In early 1997, Cambridge Electric and Commonwealth Electric received approval to participate as a broker in the purchase and sale of electricity. Cambridge Electric also sells power at wholesale to the Town of Belmont, Massachusetts. Natural gas is distributed by Commonwealth Gas Company (Commonwealth Gas) to approximately 237,000 customers in 49 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1,128,000. Twelve of these communities are also served by system companies with electricity. Some of the larger communities served by Commonwealth Gas include Cambridge, Somerville, New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of Boston. Steam, which is produced by Cambridge Electric in connection with the generation of electricity, is purchased by COM/Energy Steam and, together with its own production, is distributed to 19 customers in Cambridge and two customers (including Massachusetts General Hospital) in Boston. Steam is used for space heating and other purposes. Industry in the territories served by system companies is highly diversified. The larger industrial customers include high-technology firms and manufacturers of such products as photographic equipment and supplies, computer diskettes, rubber products, textiles, wire and other fastening devices, abrasives and grinding wheels, candy, copper and alloys, and chemicals. Electric Power Supply To satisfy demand requirements and provide required reserve capacity, the system supplements its generating capacity by purchasing power on a long and short-term basis through capacity entitlements under power contracts with other New England and Canadian utilities and with Qualifying Facilities and other non-utility generators through a competitive bidding process that is regulated by the Massachusetts Department of Telecommunications and Energy (DTE) (formerly the Massachusetts Department of Public Utilities (DPU)). System companies own generating facilities with a net capability at the time of peak load (974 MW on July 18, 1997) totaling 1,017.7 MW including 569 MW provided by Canal Unit 1, of which three-quarters (426.8 MW) is sold to neighboring utilities under long-term contracts, and 290 MW provided by Canal Unit 2. Another 126.3 MW is provided by various smaller system units. Of the 558.5 MW available to the system, 63.3 MW are used principally for peaking purposes. A 3.52% ownership interest in the Seabrook 1 nuclear power plant provides 40.5 MW of capability to the system and Central Maine Power Company's <PAGE 5> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Wyman Unit 4, an oil-fired facility in which the system has a 1.4% joint- ownership interest, provides 8.8 MW. Additionally, in 1993, Canal extended an agreement with New England Power Company (NEP) whereby 50 MW of Canal Unit 2 (previously 20 MW) is exchanged for 50 MW of Bear Swamp Unit Nos. 1 and 2 through April 1997. The Bear Swamp Units are pumped storage hydroelectric generating facilities. These contracts are designed to reduce the system's reliance on oil. In addition, through Canal's equity ownership in Hydro-Quebec Phase II, the system has an entitlement of 67.8 MW. Purchase power arrangements were also in place with four natural gas-fired cogenerating units in Massachusetts totaling 205.2 MW. The system also receives 67 MW from a waste-to-energy plant and has entitlements totaling 23.9 MW through contracts with four hydroelectric suppliers. Pursuant to a restructured Power Sale Agreement (PSA), effective January 1, 1995, a non-utility generator (NUG) ceased supplying capacity and energy to the system. The restructured PSA defers the system's obligation to purchase the NUG's capacity and energy for a maximum of six years. In addition, on January 27, 1995, the DTE approved the buy-out of a PSA between Commonwealth Electric and another NUG, effective April 12, 1995. This buy-out is expected to save Commonwealth Electric's customers approximately $37 million over the next 20 years. A purchased power obligation with another NUG was terminated in June 1996 and is expected to save Commonwealth Electric's customers an additional $34 million over the twenty-year life of the original agreement. The system also has available 84.4 MW from two operating nuclear units in which system distribution companies have life-of-the-unit contracts for power. Information with respect to these units is as follows: Vermont Yankee Pilgrim Year of Initial Operation 1972 1972 Contract Expiration Date 2012 2012 Equity Ownership (%) 2.50 - Plant Entitlement (%) 2.25 11.0 Plant Capability (MW) 496.0 664.7 System Entitlement (MW) 11.2 73.2 Information relative to nuclear units that are no longer operating in which the system has an equity ownership is as follows: Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands) Year of Shutdown 1996 1997 1992 Equity Ownership (%) 4.50 4.00 4.50 Equity Ownership Balance $5,007 $3,121 $405 For additional information, refer to Note 3(d) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. <PAGE 6> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The system's non-nuclear generating assets together with capacity entitlements associated with power contracts previously discussed and as further discussed later in this section are part of an ongoing auction process initiated during 1997 in response to electric industry restructuring legislation enacted in Massachusetts in November 1997. The auction process is expected to be completed in 1998. For further information refer to the "Industry Restructuring" section of Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 of this report. Cambridge Electric, Canal and Commonwealth Electric, together with other electric utility companies in the New England area, are members of Independent System Operator (ISO) - New England (formerly the New England Power Pool or NEPOOL), which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England. ISO - New England operates a centralized dispatching facility to ensure reliability of service and to dispatch the most economically available generating units of the member companies to fulfill the region's energy requirements. This concept is accomplished by use of computers to monitor and forecast load requirements. ISO - New England, on behalf of its members entered into an Interconnection Agreement with Hydro-Quebec, a Canadian utility operating in the Province of Quebec. The agreement provided for construction of an interconnection (referred to as the Hydro-Quebec Project-Phase I and Phase II) between the electrical systems of New England and Quebec. The parties have also entered into an Energy Contract and an Energy Banking Agreement; the former obligates Hydro-Quebec to offer ISO - New England participants up to 33 million MWH of surplus energy during an eleven-year term that began September 1, 1986 and the latter provides for energy transfers between the two systems. ISO - New England has also entered into Phase II agreements for an additional purchase from Hydro-Quebec of 7 million MWH per year for a twenty-five year period which began in late 1990. Canal is obligated to pay its share of operating and capital costs for Phase II over a 25 year period ending in 2015. Future minimum lease payments for Phase II have an estimated present value of $11.8 million at December 31, 1997. In addition, Canal has an equity interest in Phase II which amounted to $3.1 million in 1997 and $3.3 million in 1996. The System's electric subsidiaries are also members of the Northeast Power Coordinating Council (NPCC), an advisory organization that includes the major power systems in New England and New York plus the Provinces of Ontario and New Brunswick in Canada. NPCC establishes criteria and standards for reliability and serves as a vehicle for coordination in the planning and operation of these systems. The reserve requirements used by the ISO - New England participants in planning future additions are determined by ISO - New England to meet the reliability criteria recommended by the NPCC. The system estimates that, during the next ten years, reserve requirements so determined will be approximately 20% of peak load. <PAGE 7> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Power Supply Commitments and Support Agreements Cambridge Electric and Commonwealth Electric, through Canal, secure cost savings for their respective customers by planning for bulk power supply on a single system basis. Additionally, Cambridge Electric and Commonwealth Electric have long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. For additional information concerning system commitments under long-term power contracts, refer to Note 3(d) of Notes to Consolidated Financial Statements filed under Item 8 of this report. The system's 3.52% interest in the Seabrook nuclear power plant is owned by Canal to provide for a portion of the capacity and energy needs of Cambridge Electric and Commonwealth Electric. For additional information concerning Seabrook 1, refer to Note 3(b) of Notes to Consolidated Financial Statements filed under Item 8 of this report. Electric Fuel Supply (a) Oil and Natural Gas Of the system's total energy requirement for 1997, approximately 42% was generated using imported residual oil and approximately 32% was generated using natural gas. Effective March 15, 1998, Canal executed a one-year contract with Coastal Refining and Marketing, Inc. (Coastal) for the purchase of 1% sulfur residual fuel oil. The contract provides for delivery of a set percentage of Canal's fuel requirement, the balance (a maximum of 50%) to be met by spot purchases or by Coastal at the discretion of Canal. Energy Supply & Credit Corporation (ESCO Massachusetts, Inc.) operates Canal's fuel oil terminal and manages the receipt of and payment for fuel oil under assignment of Canal's supply contracts to ESCO Massachusetts, Inc. Residual fuel oil in the terminal's shore tanks is held in inventory by ESCO Massachusetts, Inc. and delivered upon demand to Canal's two day tanks. Fuel oil storage facilities at the Canal site have a capacity of 1,199,000 barrels, representing approximately 60 days of normal operation of the two units. During 1997, ESCO Massachusetts, Inc. maintained an average daily inventory of 395,000 barrels of fuel oil which represents 18 days of normal operation of the two units. This supply is maintained by tanker deliveries. During 1996, Unit 2 was converted to dual-fuel capability, residual fuel oil and natural gas. Unit 2 has burned approximately 2.5 million MMBTU's of natural gas since the conversion was completed during periods when the use of natural gas was the most economical choice. Canal anticipates that its dual-fuel capability will result in future savings as the least expensive fuel is utilized. <PAGE 8> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Canal has a gas supply contract with PGE Energy Trading Corporation to provide 100% of the natural gas requirements of Unit 2 through October 31, 1998. Canal's original gas supply contract with Duke/Louis Dreyfus, L.L.C. expired on December 31, 1997. (b) Nuclear Fuel Supply and Disposal Approximately 13% of the system's total energy requirement for 1997 was generated by nuclear plants. The nuclear fuel contract and inventory information for Seabrook 1 has been furnished to the system by North Atlantic Energy Services Corporation (NAESCO), the plant manager responsible for operation of the unit. Seabrook's requirement for nuclear fuel components are 100% covered through 1999 by existing contracts. There are no spent fuel reprocessing or disposal facilities currently operating in the United States. Instead, commercial nuclear electric gener- ating units operating in the United States are required to retain spent fuel on-site. As required by the Nuclear Waste Policy Act of 1982 (the Act), as amended, the joint-owners entered into a contract with the Department of Energy for the transportation and disposal of spent fuel and high level radioactive waste at a national nuclear waste repository or Monitored Retrievable Storage (MRS) facility. Owners or generators of spent nuclear fuel or its associated wastes are required to bear the costs for such transportation and disposal through payment of a fee of approximately 1 mill/KWH based on net electric generation to the Nuclear Waste Fund. Under the Act, a storage or disposal facility for nuclear waste was anticipated to be in operation by 1998; a reassessment of the project's schedule requires extending the completion date of the permanent facility until at least 2010. Seabrook 1 is currently licensed for enough on-site storage to accommodate spent fuel expected to be accumulated through at least the year 2010. Gas Supply Commonwealth Gas purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company (Tennessee) and Algonquin Gas Transmission Company (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines) and purchases all of its gas supplies from third-party vendors, utilizing firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil companies. In addition to firm transportation and gas supplies mentioned above, Commonwealth Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The underground storage contracts are a combination of existing and new agreements which are the result of Federal Energy Regulatory Commission (FERC) Order 636 service unbundling. The LNG facilities, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season. Commonwealth Gas entered into a multi-party agreement in 1992 to assume a portion of Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois Gas Transmission System and Tennessee pipelines. The ANE gas supply contract was filed with the DTE and hearings were completed in April 1993. The DTE approved the ANE gas supply contract in November 1995. Commonwealth Gas is <PAGE 9> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES presently in negotiations with the parties to allow for final execution of all pertinent agreements and contracts. Commonwealth Gas began transporting gas on its distribution system in 1990 for end-users. As of December 31, 1997, there were 218 customers using this transportation service, accounting for 8,462 BBTU or approximately 16% of total throughput. Hopkinton LNG Facility A portion of the gas supply for Commonwealth Gas during the heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of the System. The facility consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 million MCF of natural gas. In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG trucked from Hopkinton. Commonwealth Gas has contracts for LNG service with Hopkinton extending on a year to year basis with notice of termination required five years in advance of the anticipated termination date. Commonwealth Gas and Hopkinton are currently evaluating the contracts to determine if amendments to the contracts should be negotiated in light of the ongoing deregulation of the natural gas industry. Current contract payments include a demand charge sufficient to cover Hopkinton's fixed charges and an operating charge which covers liquefaction and vaporization expenses. Commonwealth Gas furnishes pipeline gas during the period April 15 to November 15 each year for liquefaction and storage. As the need arises, LNG is vaporized and placed in the distribution system of Commonwealth Gas. Based upon information presently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, Commonwealth Gas believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales. Rates, Regulation and Legislation Certain of the System's utility subsidiaries operate under the jurisdiction of the DTE which regulates retail rates, accounting, issuance of securities and other matters. In addition, Canal, Cambridge Electric and Commonwealth Electric file their respective wholesale rates with the FERC. (a) Restructuring Legislation As more fully discussed in the "Industry Restructuring" section of Management's Discussion and Analysis of Results of Operations in Item 7 of this report, the system began to implement the provisions of the Electric Industry Restructuring Act on March 1, 1998 as signed into law on November 25, 1997 following the Company's filing of its proposed restructuring plan with the DTE on November 19, 1997. A modified plan was approved by the DTE on February 27, 1998 prior to implementation on March 1, 1998. Also discussed is the movement initiated by the DTE in July 1997 to unbundle rates and services for all gas customers. <PAGE 10> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (b) Wholesale Rate Proceedings Cambridge Electric provides power supply and transmission services to its FERC-jurisdictional wholesale customers. Cambridge Electric requires FERC approval to change its wholesale rates, including those to the Municipal Light Department of the Town of Belmont, Massachusetts (Belmont), a "partial requirements" customer since 1986. Since February 1993, Belmont has taken power supply service pursuant to a FERC approved Net Requirements Power Supply Agreement. In 1993, Cambridge Electric and Belmont began negotiations for a new transmission service agreement. The negotiations were not successful. On June 29, 1994, Cambridge Electric filed for FERC approval of a new transmission service agreement with Belmont. The FERC accepted the rates effective January 25, 1995, subject to refund. At the same time, an investigation was opened by the FERC to determine the reasonableness of both the existing transmission tariff rates to Belmont and the proposed trans- mission service agreement with Belmont. Both Belmont and FERC staff intervened in the investigation. Cambridge Electric filed its case with the FERC on October 25, 1994 and evidentiary hearings were held in March 1995. An Initial Decision (ID) of the Presiding Administrative Law Judge was issued on September 14, 1995. In the ID, the Administrative Law Judge found that Cambridge Electric's existing transmission tariff rates were just and reasonable. The Administrative Law Judge identified a number of revisions to the filed transmission service agreement which effectively reduced the rates to Belmont. In October 1995, the parties filed briefs on exceptions to the Administrative Law Judge's ID. Cambridge Electric awaits final FERC action on this investigation. On March 29, 1995, the FERC issued two notices of proposed rulemaking concerning open access transmission and stranded costs. The FERC's notices proposed to remove impediments to competition in the wholesale bulk power marketplace and to bring more efficient, lower-cost power to electric consumers. On March 29, 1996, Cambridge Electric filed transmission tariffs that implemented the FERC's requirements for non-discriminatory open access transmission for both point-to-point and network service. The tariffs were accepted on May 17, 1996 to be effective on May 28, 1996, but the rates are subject to an investigation initiated by the FERC itself. A settlement with the FERC regarding this investigation was filed on February 6, 1997. On April 24, 1996, the FERC issued Order No. 888, a set of three interrelated rules resolving the above rulemakings. The FERC required all public utilities that own, control or operate transmission facilities in interstate commerce to have on file wholesale open access transmission tariffs that conform to the FERC pro-forma tariff contained in Order No. 888. On July 9, 1996, Cambridge Electric and Commonwealth Electric filed tariffs that conform to the FERC's pro-forma tariffs. On November 13, 1996, the FERC accepted the non-rate terms and conditions of these tariffs effective July 9, 1996, subject to a revision of one section dealing with the scheduling of services. On March 4, 1997, the FERC issued Order No. 888-A which required revisions to the tariffs filed in compliance with Order No. 888. Cambridge Electric and Commonwealth Electric both filed their revised tariffs on July 14, 1997. On November 25, 1997, the FERC issued Order No. 888-B requiring minor changes that did not require an additional filing. <PAGE 11> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES On December 31, 1996, Cambridge Electric and Commonwealth Electric filed market-based power sales tariffs with the FERC that received FERC approval on February 27, 1997. The Companies seek authorization to make wholesale power sales at fully negotiated rates. In addition, the Companies requested and received authorization to participate as brokers in the sale and purchase of electricity. (c) Unbundled Rates Electric Both Commonwealth Electric and Cambridge Electric have restructured their operations to provide customers with unbundled rates that provide a ten percent rate reduction as of March 1, 1998 and the opportunity to purchase generation supply on the competitive market pursuant to the electric industry restructuring legislation enacted in November 1997. Delivery rates are composed of distribution charges, transition charges (to collect stranded costs) and transmission charges. Electricity supply services include optional standard offer service and default service. Distribution charges consist of customer demand and energy charges as appropriate to recover distribution costs, including costs formerly recovered under the Conservation Charge, and is based on the separation of distribution and transmission facilities. Transmission charges are itemized separately and are subject to each company's Transmission Cost Adjustment. Transition charges are designed to recover on a reconciling basis all of each company's stranded costs. Prior to March 1, 1998, Commonwealth Electric and Cambridge Electric had Fuel Charge rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. These schedules required a quarterly computation and DTE approval of a Fuel Charge decimal based upon forecasts of fuel, purchased power, transmission costs and billed unit sales for each period. To the extent that collections under the rate schedules did not match actual costs for that period, an appropriate adjustment was reflected in the calculation of the next subsequent calendar quarter decimal. Also prior to March 1, 1998, Cambridge Electric and Commonwealth Electric collected a portion of capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The recovery mechanism for these costs used a per kilowatthour (KWH) factor that was calculated using historical (test-period) capacity costs and unit sales. This factor was then applied to current monthly KWH sales. When current period capacity costs and/or unit sales varied from test-period levels, Cambridge Electric and Commonwealth Electric experienced a revenue excess or shortfall that had a significant impact on net income. However, as part of the settlement agreements approved by the DTE in May 1995, Cambridge Electric and Commonwealth Electric were allowed to defer these costs (within certain limits) which neutralized their sometimes volatile effect on net income. Both Commonwealth Electric and Cambridge Electric also had separately stated Conservation Charge rate schedules that allowed for current recovery, from retail customers, of conservation and load management costs. <PAGE 12> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Gas Commonwealth Gas has a Standard Seasonal Cost of Gas Adjustment rate schedule (CGA) that provides for the recovery, from firm customers, of purchased gas and conservation and load management costs not recovered through base rates. These schedules, which require DTE approval, are estimated semi- annually and include credits for gas pipeline refunds and profit margins applicable to capacity release, off-system sales and interruptible sales. Actual gas costs are reconciled annually as of October 31, and any difference is included as an adjustment in the calculation of the decimals for the two subsequent six-month periods. Periodically, Commonwealth Gas is required to file a long-range forecast of the energy needs and requirements of its market area and annual supplements thereto with the DTE. To approve this long-range forecast and resource plans, the DTE must find, among other things, that Commonwealth Gas' projected firm load is reasonable and based on proven and verifiable forecasting methods and data, and that Commonwealth Gas assembles its supply portfolio based on a prudent resource planning process that can be reasonably expected to meet projected demands on a cost efficient basis. Commonwealth Gas filed its forecast, covering the period November 1996 through October 2001, with the DTE on December 20, 1996. (d) Gas Demand and Transition Costs Commonwealth Gas is obligated, as part of its pipeline transportation contracts, storage contracts and gas purchase contracts, to pay monthly demand charges which are recovered from customers through the CGA. As a direct result of implementation of FERC Order 636, most pipeline companies are incurring transition costs which include the cost of restructuring gas supply contracts, the value of facilities that were supporting the gas sales function and are no longer used and useful for transportation only services, the cost of contracts with upstream pipeline companies and various miscellaneous costs. These costs are billed to Commonwealth Gas and other local distribution companies. Commonwealth Gas is collecting all contract restructuring costs from its customers through the CGA as permitted by the DTE. (e) Retail Choice Pilot Program Prior to March 1, 1998, the date retail choice was available for all customers, Commonwealth Electric had designed a program to allow a limited number of customers the opportunity to possibly reduce their electric bills while Commonwealth Electric learned more about real-time pricing and the administrative requirements associated with open-market competition. Through the program, Commonwealth Electric developed internal procedures for billing and allocating the costs for providing an alternative supply to its retail customers, and developed methods for educating customers regarding retail choice. The program was available to 18 commercial and industrial customers of Commonwealth Electric that took service under one of Commonwealth Electric's economic development rates. This program was discontinued on February 28, 1998. <PAGE 13> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (f) Customer Transition Charge In September 1995, the DTE issued a ruling largely approving four rate tariffs, including a Customer Transition Charge (CTC), that were filed by Cambridge Electric on March 15, 1995. The CTC was intended to protect remaining customers from paying certain stranded costs that were incurred in the event that Cambridge Electric's largest customers discontinued full service, yet still remain connected for back-up and other services. These costs included long-term power contracts entered into to meet projected energy requirements, investments in substations, underground and overhead lines and current and future decommissioning costs associated with nuclear plants. This ruling is believed to be the first retail stranded cost charge approved nationally and follows the DTE restructuring order which endorsed, in principle, the recovery of stranded costs. Through the CTC, Cambridge Electric recovered 75% of net stranded costs as calculated in its proposal. Cambridge Electric's other rates include a Supplemental Service Rate, a Standby Service Rate and a Maintenance Service Rate each of which were approved with only minor changes. Pursuant to its terms, the CTC will terminate as of March 1, 1998, which is the retail access date established by the Massachusetts Legislature in its Electric Industry Restructuring Act. The Massachusetts Institute of Technology (MIT) appealed the DTE's ruling approving the CTC to the Massachusetts Supreme Judicial Court (the SJC), contending, in part, that the DTE lacked authority to approve the CTC, the DTE's ruling was not supported by subsidiary findings, imposition of the CTC on MIT constitutes inequitable retroactive ratemaking, and the CTC violates the Public Utility Regulatory Policies Act (PURPA). On September 18, 1997, the SJC announced its decision remanding the matter to the DTE for further consideration. The SJC did find that recovery of prudent and verifiable stranded costs by utility companies is in the public interest and consistent with PURPA. However, the SJC stated that the insufficiencies of the DTE's subsidiary findings precluded the SJC from undertaking a meaningful review of the DTE's calculations that formed the basis of the customer transition charge. Among the issues that the SJC directed the DTE to consider further are: the methodology for calculation of stranded costs, why 75% of stranded costs were allocated to MIT rather than 100%, the prudence of the stranded costs incurred by Cambridge Electric, and whether Cambridge Electric took the necessary mitigation efforts to reduce stranded costs. The DTE is in the process of determining whether to take additional evidence in the remand or to rely on the record and pleadings already filed. At this time, management is unable to predict the outcome of this proceeding. In an earlier legal proceeding involving the CTC, on August 27, 1996, the United States District Court for the District of Massachusetts (District Court) granted the motions for summary judgement of Cambridge Electric and the DTE and dismissed the May 1996 complaint filed by MIT. In its complaint, MIT had alleged that the CTC approved by the DTE and implemented by Cambridge Electric violated PURPA. In dismissing MIT's complaint, the District Court found that MIT's complaint involved an allegation relating to the DTE's application of PURPA, which is not within the District Court's jurisdiction. <PAGE 14> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Competition The system continues to develop and implement strategies that deal with the increasingly competitive environment facing the electric business. The system's actions in response to the competitive challenges brought on by electric and gas industry restructuring have been well received by regulators, business groups and customers. For a more detailed discussion of the DTE's restructuring order and gas service unbundling efforts, refer to the "Industry Restructuring" section of Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 of this report. On February 6, 1997, due to the dramatically changing nature of the electric and gas industries, the System announced the consolidation of management personnel of Commonwealth Electric, Commonwealth Gas and COM/Energy Services Company effective on that date. These companies will continue to operate under their existing company names. The consolidation process for these companies involved the merging of similar functions and activities to eliminate duplication in order to create the most efficient and cost-effective operation possible. In addition, the system initiated a voluntary personnel reduction program during the second quarter of 1997 which reduced the total number of regular employees by approximately 13%. Through this and prior work force reductions and attrition, the system has reduced its full-time work force approximately 33% since 1990. Also, the introduction of advanced technologies in the workplace continues to improve customer service and the system's competitive position. The system has yet to be significantly impacted by the increase in competition and believes that its current business strategy and entrance into unregulated markets will have a positive impact in the near-term. Segment Information System companies provide electric, gas and steam services to retail customers in service territories located in central, eastern and southeastern Massachusetts and, in addition, sell electricity at wholesale to Massachusetts customers. Other operations of the system include the pursuit of new business opportunities and the operation of rental properties and other investment activities which do not presently contribute significantly to either revenues or operating income. Reference is made to additional industry segment information in Note 11 of Notes to Consolidated Financial Statements filed under Item 8 of this re- port. Environmental Matters The system is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. System compliance with these laws and regulations will require capital expenditures of $68.2 million from 1998 through 2002 for the electric and gas divisions. For additional information concerning environmental issues, refer to the "Environmental Matters" section of "Management's Discussion and Analysis of Financial Condition and Results of Operations" filed under Item 7 of this report. <PAGE 15> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Construction and Financing For information concerning the system's financing and construction programs refer to Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 and Note 3(a) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. Employees The total number of full-time employees for the system declined by approximately 13% to 1,727 in 1997 from 1,991 employees at year-end 1996 due primarily to the initiation of a voluntary personnel reduction program during the second quarter of 1997. Of the current total, 1,037 (60%) are represented by various collective bargaining units. Agreements with three units representing approximately 12% of regular employees are scheduled to expire in 1998. Upon expiration of one of these contracts, representing 6% of regular employees, a new contract (already ratified) will become effective through March 1, 2001. Although a labor dispute with one collective bargaining unit occurred during 1996, employee relations have generally been satisfactory since the dispute was resolved in September 1996. Item 2. Properties The system's principal electric properties consist of Canal Unit 1, a 569 MW oil-fired steam electric generating unit, and its one-half ownership in Canal Unit 2, a 580 MW steam electric generating unit with the ability to burn both oil and natural gas, both located at Canal Electric's facility in Sandwich, Massachusetts. Cambridge Electric owns and operates two steam electric generating stations and two gas turbine units located in Cambridge, Massachusetts with a total capability of 112.5 MW and Commonwealth Electric has an interest in smaller generating units totaling 13.8 MW. Of these 126.3 MW, 63.3 MW is used primarily for peaking and emergency purposes. In addition, the system has a 3.52% interest (40.5 MW of capacity) in Seabrook 1 and a 1.4% (8.8 MW) joint- ownership interest in Central Maine Power Company's Wyman Unit 4. Other electric properties include an integrated system of distribution lines and substations. In addition, the system's other principal properties consist of an electric division office building in Wareham, Massachusetts and other structures such as garages and service buildings. At December 31, 1997, the electric transmission and distribution system consisted of 5,833 pole miles of overhead lines, 4,461 cable miles of underground line, 371 substations and 381,159 active customer meters. The principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 1997, the gas system included 2,811 miles of gas distribution lines, 167,777 services and 245,246 customer meters together with the necessary measuring and regulating equipment. In addition, the system owns a liquefaction and vaporization plant, a satellite vaporization plant and above- ground cryogenic storage tanks having an aggregate storage capacity equivalent <PAGE 16> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES to 3.5 million MCF of natural gas. The system's gas division owns a central headquarters and service building in Southborough, Massachusetts, five district office buildings and several natural gas receiving and take stations. Item 3. Legal Proceedings Cambridge Electric is an intervenor in an appeal at the Massachusetts Supreme Judicial Court (SJC) filed by MIT of a decision by the DTE approving a customer transition charge that allows Cambridge Electric to recover certain stranded costs. For additional information refer to the "Customer Transition Charge" section in Item 1 of this report. Item 4. Submission of Matters to a Vote of Security Holders None <PAGE 17> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES PART II. Item 5. Market for the Registrant's Securities and Related Stockholder Matters (a) Principal Markets The System's common shares are listed on the New York and Pacific stock exchanges. The table below sets forth the high and low closing prices as reported on the New York Stock Exchange composite transactions tape. 1997 by Quarter First Second Third Fourth High $24 1/2 $24 $27 $34 9/16 Low 20 7/8 19 23 3/4 25 11/16 1996 by Quarter First Second Third Fourth High $25 $25 3/4 $25 5/8 $24 7/8 Low 21 15/16 22 3/4 21 1/2 22 1/2 (b) Number of Shareholders at December 31, 1997 12,708 shareholders (c) Frequency and Amount of Dividends Declared in 1997 and 1996 1997 1996 Per Per Share Share Declaration Date Amount Declaration Date Amount March 27, 1997 $ .395 March 28, 1996 $ .385 June 26, 1997 .395 June 27, 1996 .385 September 25, 1997 .395 September 26, 1996 .385 December 18, 1997 .395 December 19, 1996 .385 $1.580 $1.540 (d) Future dividends may vary depending upon the System's earnings and capital requirements as well as financial and other conditions existing at that time. <PAGE 18> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 6. Selected Financial Data 1997 1996 1995 1994 1993 (Dollars In Thousands Except Common Share Data) Operating Revenues Electric $ 688,508 $ 649,678 $ 604,980 $ 638,150 $ 622,039 Gas 333,977 341,867 306,953 323,568 302,644 Steam and other 19,250 19,360 17,355 15,867 14,035 Total $1,041,744 $1,010,905 $ 929,288 $ 977,585 $ 938,718 Net Income $ 49,901 $ 59,175 $ 51,396 $ 48,968 $ 45,834 Common Share Data- Earnings per share $2.27 $2.70 $2.36 $2.29 $2.18 Dividends declared per share $1.58 $1.54 $1.50 $1.50 $1.46 Average shares outstanding 21,531,784 21,529,676 21,311,836 20,827,562 20,431,228 Total Assets $1,485,050 $1,428,955 $1,392,342 $1,345,032 $1,318,940 Long-term debt $ 364,311 $ 355,305 $ 377,181 $ 418,307 $ 448,893 Redeemable preferred share investment 12,200 13,020 13,840 14,660 15,480 Common share investment 430,770 415,694 390,785 362,997 337,070 Total Capitalization $ 807,281 $ 784,019 $ 781,806 $ 795,964 $ 801,443 1997 by Quarter 1st 2nd 3rd 4th (Dollars In Thousands Except Per Share Amounts) Operating Revenues $316,190 $221,944 $222,115 $281,495 Operating Income 35,892 7,793 16,887 27,078 Income Before Interest Charges 36,541 8,774 17,227 27,709 Net Income 26,400 (1,334) 7,147 17,688 Earnings per Common Share 1.21 (.07) .32 .81 Dividends Declared per Common Share .395 .395 .395 .395 Closing Price of Common Shares- High 24 1/2 24 27 34 9/16 Low 20 7/8 19 23 3/4 25 11/16 1996 by Quarter 1st 2nd 3rd 4th (Dollars In Thousands Except Per Share Amounts) Operating Revenues $298,614 $222,667 $226,909 $262,715 Operating Income 36,131 18,608 17,601 24,325 Income Before Interest Charges 38,622 19,863 18,838 24,220 Net Income 27,907 9,463 8,360 13,445 Earnings per Common Share 1.28 .43 .37 .62 Dividends Declared per Common Share .385 .385 .385 .385 Closing Price of Common Shares- High 25 25 3/4 25 5/8 24 7/8 Low 21 15/16 22 3/4 21 1/2 22 1/2 <PAGE 19> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Earnings and Dividends Earnings and earnings per common share by organizational element for the three-year period were as follows: 1997 1996 1995 Per Per Per Amount Share Amount Share Amount Share (Dollars in thousands except per share amounts) Electric........... $34,811 $1.62 $39,667 $1.85 $32,247 $1.52 Gas................ 14,681 .68 16,229 .75 15,352 .72 Other.............. (579) (.03) 2,229 .10 2,687 .12 Total.......... $48,913 $2.27 $58,125 $2.70 $50,286 $2.36 Parent company earnings and dividends on preferred shares were allocated among the electric, gas and other operations of the system based on the Parent's equity investment in each segment. 1997 versus 1996 Earnings per share for the year 1997 were $2.27 compared to the record level of $2.70 achieved last year. The decline for the year was due to a one- time after-tax charge of $10.7 million, or 50 cents per share, that related to a voluntary personnel reduction program (PRP). Factors that had a positive impact on earnings for the year were lower operating and maintenance expenses (25 cents) that resulted, in part, from the PRP, an increase in electric unit sales (11 cents) and the absence in 1997 of costs associated with a labor dispute in 1996 (13 cents). Earnings for 1997 were negatively affected by the absence of a 1996 refund associated with a power contract settlement agreement (11 cents), lower firm gas unit sales (8 cents), costs associated with new business development (12 cents), the absence of a 1996 recognition of the recoverability of costs associated with Canal Electric Company's postretire- ment benefits costs that were subsequently recovered in wholesale rates (5 cents) and a lower investment base on generation assets (6 cents). 1996 versus 1995 In 1996, earnings per share increased 34 cents to $2.70. Significant factors that contributed to the improved earnings included higher firm gas (18 cents) and retail electric (14 cents) unit sales, the refund associated with the power contract settlement agreement (11 cents), lower interest costs (9 cents), and the recognition of Canal's recovery of postretirement benefits costs (5 cents). Partially offsetting these factors were costs related to the labor dispute (13 cents), storm damage from Hurricane Edouard (6 cents), a customer refund (5 cents in 1996 versus 1 cent in 1995) pursuant to a 1995 settlement agreement with the Massachusetts Department of Telecommunications and Energy (DTE) (formerly the Massachusetts Department of Public Utilities) that limited Commonwealth Electric Company's return on equity, as defined in a settlement that expired in 1997, and the reversal in 1995 of a reserve (4 cents) related to a conservation program settlement in 1995. <PAGE 20> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES In March 1997, the System's Board of Trustees increased the quarterly dividend rate per share 2.6% from 38 1/2 cents to 39 1/2 cents ($1.58 on an annualized basis). This was the second consecutive year and the third time in four years that the Board had voted to increase the quarterly dividend rate. Dividends paid to common shareholders in 1997 were $34.1 million, representing a payout ratio of 69% of 1997 earnings per share. Electric Operations Electric operating revenues for 1997 increased $38.8 million (6%) due to greater wholesale sales reflecting the changing capacity needs of non-affili- ated utilities ($11.7 million) and the Independent System Operator (ISO) - New England (formerly the New England Power Pool that operates a centralized facility to ensure reliability of service and dispatch of economically available generating units throughout New England) ($11 million) and higher retail unit sales ($2.4 million). Offsetting these factors was the absence of a $4 million refund associated with the 1996 power contract settlement agree- ment and lower revenues ($2.1 million) due to the return allowed on Canal's declining investment base. In 1996, electric operating revenues increased $44.7 million (7.4%) due mainly to higher fuel costs of $33.9 million reflecting the increased avail- ability of Canal's Unit 1 generating facility that was out of service during the first seven months of 1995 for scheduled maintenance and repairs. The remainder of the change reflects the $4 million refund associated with the power contract settlement, the impact of higher retail unit sales ($3.9 million), and the recovery in rates of $1.8 million for Canal's previously deferred postretirement benefits costs. Unit sales (in Megawatthours or MWH) were as follows: % % 1997 Change 1996 Change 1995 Residential.......... 1,830,793 1.5 1,802,973 2.9 1,752,430 Commercial........... 2,506,215 3.1 2,430,188 (0.8) 2,450,390 Industrial and other. 459,104 2.1 449,844 1.1 445,020 Total retail..... 4,796,112 2.4 4,683,005 0.8 4,647,840 Wholesale............ 3,916,974 43.9 2,721,623 37.9 1,973,543 Total............ 8,713,086 17.7 7,404,628 11.8 6,621,383 In 1997 and 1996, retail unit sales increased due to approximately 4,200 (1.2%) and 3,700 (1.0%) additional customers, the significant majority of which are permanent year-round residential customers. The increase in the level of wholesale sales reflected the increased availability of Canal Unit 1 (by 53%) and greater sales to ISO - New England (by nearly 43%). The changes in wholesale unit sales have little, if any, impact on net income. The $38.1 million increase in fuel and purchased power costs in 1997 was due primarily to higher wholesale unit sales and higher costs for replacement power reflecting the permanent shutdown of both Connecticut Yankee during 1996 and Maine Yankee in 1997, the latter of which was taken out of service in December 1996. In 1996, the cost of fuel increased by $33.9 million due primarily to the availability of Canal Unit 1, while the cost of purchased power decreased by $9.8 million reflecting the availability of Canal Unit 1 and the reduced requirement for other more costly sources of capacity. <PAGE 21> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Gas Operations In 1997, gas operating revenues decreased $7.9 million (2.3%) primarily due to a 5.6% decline in firm unit sales ($11.1 million) and lower conserva- tion and load management (C&LM) costs ($1.8 million), offset by an increase in transportation revenues of $1.8 million and revenues from sales of gas to third parties of $3.9 million. In 1996, operating revenues increased approxi- mately $34.9 million or 11.4% due to higher gas costs of $28.7 million reflecting both higher prices from suppliers and increased unit sales to customers. The increased firm sales, including transportation, equated to $6.9 million due to colder weather during 1996. Commonwealth Gas Company also utilizes the off-system sales and capacity release markets as a means to sell excess resources. A margin-sharing agreement for these sales was approved by the DTE on January 15, 1997 that allowed Commonwealth Gas to retain 25% of the gross margins realized above a certain threshold amount as set from year to year with the remaining margins credited to firm customers through the Cost of Gas Adjustment clause. As a result of this margin-sharing agreement, Commonwealth Gas realized revenues of approximately $644,000 in 1997. Unit sales and transportation volume (in billions of British thermal units or BBTU) were as follows: % % 1997 Change 1996 Change 1995 Residential......... 22,043 (3.1) 22,759 6.7 21,336 Commercial.......... 11,077 (4.2) 11,558 7.9 10,710 Industrial and other 5,594 (16.2) 6,676 4.1 6,412 Total firm....... 38,714 (5.6) 40,993 6.6 38,458 Off-system.......... 2,673 10.5 2,420 (40.1) 4,043 Quasi-firm.......... 51 (95.2) 1,066 (44.1) 1,906 Interruptible....... 1,882 (0.1) 1,883 55.0 1,215 Total sales...... 43,320 (6.6) 46,362 1.6 45,622 Transportation...... 6,506 34.1 4,852 20.6 4,024 Total............ 49,826 (2.7) 51,214 3.2 49,646 The decline in firm unit sales in 1997 was due to decreases to all customer segments that reflected milder weather experienced in the region during the first quarter as compared to a colder period in 1996. Degree days for the current year totaled 6,463, 3.6% lower than last year and 1.2% below the normal level of 6,541. The significant fluctuations in non-firm sales reflected the competitive environment that exists in the natural gas industry. A portion of the margin realized on these sales reduced the cost of gas sold to firm customers. The increase in unit sales to firm customers during 1996 (6.6%) reflected significant improvements for all customer segments consistent with colder than normal weather experienced during the year, as compared to milder weather in 1995 that was 1.4% above normal. Heating degree days were nearly 3.8% higher during 1996 as compared to 1995 and 2.3% above normal. A growing customer base, including customers formerly receiving quasi-firm sales service, somewhat offset the decline in firm sales in 1997 and contributed to the increase in firm unit sales in 1996. <PAGE 22> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Other Operating Expenses Other operation in 1997 increased $10.3 million or 4.8% due to a one-time charge related to the PRP ($17.7 million) as further discussed below, costs associated with new business development ($3.6 million), and an increase in the provision for bad debts ($1.4 million) that reflected higher reserve requirements. The impact of these factors was offset, in part, by lower operating costs ($5 million) that resulted, in part, from the PRP, lower pension costs ($2.7 million) and the absence of costs related to the 1996 labor dispute ($4.6 million). The system initially announced the details of the system-wide voluntary PRP in May 1997. The goal of the PRP was to achieve a reduced, more efficient and more productive workforce in response to the significant regulatory changes facing the system. In 1997, approximately 13% of system employees voluntarily terminated employment as a result of the PRP. The one-time charge of $17.7 million referred to above excludes generation-related costs, the recovery of which is being addressed as part of the electric industry restruc- turing process. The payback period for the cost of the PRP is expected to be about one year. This action followed the consolidation of the system's electric and gas operations earlier in 1997. In furtherance of this consoli- dation effort, the system, in March 1998, reached agreement with IBM Global Services, Inc. to offer employment to 40 system employees and to provide all of the system's information technology, telecommunications and network services. In 1996, other operation increased approximately $9 million or 4.4% and reflected the impact of higher general liability insurance costs ($6.3 million), higher postretirement benefits costs ($4 million), and the net impact of the labor dispute. These expenses were offset somewhat by lower C&LM costs ($2.4 million), a $1.6 million decline in health benefits costs, a decline in the provision for bad debts ($1.1 million) that reflected improved collection experience, and the absence of legal fees ($800,000) associated with the cancellation of a power contract in 1995. Maintenance declined in 1997 by $4.1 million or 10% and resulted from a reduction in transmission and distribution-related projects and, to a lesser extent, the PRP. Maintenance increased in 1996 by $2.5 million or 6.5% primarily due to storm damage costs related to Hurricane Edouard ($2.1 million), partially offset by reductions primarily associated with Canal Unit 1 ($1.5 million). Depreciation increased $1.6 million and $3.6 million in 1997 and 1996, respectively, and reflected the system's additions to property, plant and equipment, that included the costs associated with the completed conversion of Canal Unit 2 in mid-1996 to burn natural gas as well as oil. Federal and state income taxes decreased by $5.1 million during 1997 due mainly to the lower level of pre-tax income. Local property and other taxes were higher during 1997 due to higher property tax rates and assessments within the system's service territory and an increase in payroll-related taxes due to the 1996 labor dispute. <PAGE 23> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Other Income In 1997, other income decreased $2.3 million due primarily to the absence of a 1996 recognition of the recoverability of costs associated with Canal's postretirement benefits ($1.8 million) following Federal Energy Regulatory Commission approval, and the absence of a 1996 gain that related to the sale of parcels of land ($700,000). These two factors were also the primary causes for the change for 1996 versus 1995. Interest Charges The $2 million decline in total interest charges for 1997 was due to maturing long-term debt and scheduled sinking fund payments partially offset by a slightly higher average level of short-term borrowings. The decline of $2.2 million, or 5%, in 1996 also reflected maturing debt and sinking fund payments. Liquidity and Capital Resources Financial Condition The system's cash requirements are essentially met through the generation of cash flows from the sale of electricity, natural gas (including liquefied natural gas) and steam. Cash requirements for current operations, construc- tion programs, debt service and other capital requirements are maintained through internal generation and short-term borrowings made available through the system's credit lines with banks. Long-term debt issues are used to permanently finance short-term debt when deemed appropriate by management. The system's 1997 net cash flow from operating activities exceeded funds required to support additions to property, plant and equipment by $50 million or 86.9%. Plant additions continued to be funded entirely with internally- generated funds. The year's cash requirements for the payment of preferred and common dividends ($35.1 million), the funding of maturing long-term debt and sinking fund requirements ($22.7 million) and the re-payment of short-term borrowings ($24.4 million) were provided from operations and proceeds from the issuance of long-term debt ($35 million). Other information on the sources and uses of cash for the past three years is included in the Consolidated Statements of Cash Flows. <PAGE 24> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Capitalization ------------------------------------------------------------------- Bar graph illustration of comparative five-year (1998-2002) forecast of capitalization components based on values listed in chart below. ------------------------------------------------------------------- Forecast 1998 1999 2000 2001 2002 (Dollars in Millions) Common Equity $ 459 42% $ 478 46% $ 512 48% $ 563 51% $ 620 54% Total Debt 621 57 551 53 539 51 520 48 507 45 Preferred Stock 11 1 10 1 10 1 9 1 8 1 $1,091 100% $1,039 100% $1,061 100% $1,092 100% $1,135 100% Capital Requirements and Resources The system's projected capital expenditures for the years 1998 through 2002 are $627.8 million, including $254.7 million for 1998 that consists of approximately $150 million for Advanced Energy Systems, Inc.'s pending purchase of a total energy plant that serves the Longwood Medical Area in Boston (as further discussed below), $60.3 million in construction expendi- tures, $28.8 million for debt and sinking fund payments, and $15.6 million related to new business development. These 1998 expenditures will be met primarily through a combination of long and short-term debt issues ($186.8 million) and internally-generated funds of $67.9 million. Advanced Energy has reached agreement to purchase the total energy plant that is owned and operated by Harvard University (MATEP) and provides the steam, cooling and electric requirements of Harvard's professional schools and five affiliated teaching hospitals in Boston. The closing for this transac- tion is expected to occur during the second quarter of 1998. It is projected that this new venture will increase system revenues by approximately $45 million in 1998 and, on average, by approximately $65 million in the years 1999 through 2002. The System could also raise capital through the issuance of additional Common Shares, a new series of Preferred Shares, or through its Dividend Reinvestment and Common Share Purchase Plan. The System's goal is to maintain a capital structure that preserves an appropriate balance between debt and equity. Management believes its capital resources and liquidity are suffi- cient to meet its current and projected requirements. <PAGE 25> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The system's capitalization structure is presented below: 1996 1997 (Dollars in thousands) Long-term debt.... $369,565 40.3% $383,311 41.7% Preferred shares.. 13,020 1.4 12,200 1.3 Common equity..... 415,694 45.4 430,770 46.8 Short-term debt... 118,475 12.9 94,075 10.2 Total capitalization $916,754 100.0% $920,356 100.0% Capital Requirements ------------------------------------------------------------------- Bar graph illustration of comparative two-year (1996-1997) actual and five-year (1998-2002) forecast of capital requirements based on values listed in chart below. ------------------------------------------------------------------- Forecast 1996 1997 1998 1999 2000 2001 2002 (Dollars in Millions) Construction- Electric $ 38 $ 34 $ 41 $ 29 $ 28 $ 25 $ 25 Gas 12 18 18 18 18 19 19 Other 3 5 1 1 1 1 1 Maturing Debt 42 23 29 115 10 11 39 Purchase of MATEP - - 150 - - - - New Business - - 16 3 3 3 3 $ 95 $ 80 $255 $166 $ 60 $ 59 $ 88 Forward-Looking Statements This discussion contains statements which, to the extent it is not a recitation of historical fact, constitute "forward-looking statements" and is intended to be subject to the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995. A number of important factors affecting the System's business and financial results could cause actual results to differ materially from those reflected in the forward-looking statements or projected amounts. Those factors include developments in the legislative, regulatory and competitive environment, certain environmental matters, demands for capital and new business development expenditures and the availability of cash from various sources. Industry Restructuring Electric On November 25, 1997, the Governor of Massachusetts signed into law the Electric Industry Restructuring Act (the Act). Provisions of this legislation include, among other things, a 10 percent discount on standard offer service <PAGE 26> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES and retail choice of energy supplier effective March 1, 1998, with a subse- quent increase in the discount on standard offer service of up to 15 percent upon completion of divestiture of non-nuclear generating assets and securiti- zation of net non-mitigable stranded costs (which, for the system, are primarily the result of above-market purchased power contracts with non- utility generators) and, recovery of stranded costs subject to review and an audit process. The system filed a comprehensive electric restructuring plan with the DTE on November 19, 1997 that was thoroughly reviewed in five separate hearings that solicited public comment, and seven days of evidentiary hearings that were completed in February 1998. Consistent with the Act, the system's plan provides, as of March 1, 1998, a rate reduction of 10 percent for customers choosing the standard service transition rate from the average of undiscounted rates in effect during August 1997, divestiture of non-nuclear generating assets and a restructured electric generation market that is able to offer retail access to all customers. The system's plan also includes the following provisions: 1) an estimate and detailed accounting of total transition costs eligible for recovery through a non-bypassable access or transition charge; 2) a description of the system's strategies to mitigate transition costs; 3) unbundled rates for generation, distribution, transmission and other services; 4) proposed charges for the recovery of transition costs through the non-bypassable transition charge; 5) proposed programs to provide universal service to all customers; 6) proposed programs and mandatory charges to promote energy conservation and demand-side management; 7) procedures for ensuring direct retail access to all electric generation suppliers; 8) discussions of the impact of the plan on the system's employees and the communities served by the system; and (9) a mandatory charge per kwh for all consumers to support the development and promotion of renewable energy projects. On February 27, 1998, the DTE approved the system's restructuring plan stating that the plan complies with the Act. While the system is encouraged with the treatment afforded stranded or transition cost recovery by the legislation and the DTE, the mandated customer discount could have a signifi- cant impact on future cash flows. Auction Process On March 31, 1997, the system submitted a report to the DTE that detailed the proposed auction process for selling its electric generation assets and entitlements. The process included a standard, sealed-bid auction for generation assets and purchased power contracts. The auction process provides a market-based approach to maximizing stranded cost mitigation and minimizing the access charges that ratepayers will have to pay for stranded cost recov- ery. A request for bids from interested parties was issued during August, and an Offering Memorandum was issued in October. Potential bidders examined all pertinent information related to the system's generating facilities and purchased power agreements in order to prepare and submit their first round of bids in mid-December. In January 1998, the system selected a short list of potential bidders, each of whom are expected to submit a final binding bid in the second quarter of 1998. The entire process, including regulatory approv- als, is expected to be completed in 1998. <PAGE 27> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Gas On July 18, 1997, the DTE directed the ten Massachusetts gas utilities, including Commonwealth Gas, to initiate a collaborative process that will establish guiding principles and specific procedures for unbundling rates and services for all customers. The DTE listed six principles that it considers important to the success of a competitive natural gas market that will provide safe and reliable service at the lowest possible cost to customers. The natural gas market would: (1) provide the broadest possible choice; (2) provide all customers with an opportunity to share in the benefits of increased competition; (3) ensure full and fair competition in the gas supply market; (4) functionally separate supply from local distribution services; (5) support and further the goals of environmental regulation; and lastly (6) rely on incentive regulation where a fully competitive market cannot or presently does not exist. In addition, the DTE outlined several specific issues that it expects the collaborative to address: (1) services that can be offered on a competitive basis; (2) terms and conditions of service; (3) consumer protections and social programs; (4) mitigation of gas related and non-gas related transition costs; (5) third-party supplier qualifications; and (6) curtailment princi- ples. The DTE also suggested that the collaborative reconsider the pricing and provision of interruptible transportation services. On August 18, 1997, the DTE noted that the development of unbundling principles and procedures constitutes only a part of the effort necessary to develop full customer choice for gas service. The DTE recognized that each local distribution company will be filing a comprehensive unbundling proposal at some later date. In the interim, the DTE directed those companies that do not currently have unbundled rates, including Commonwealth Gas, to have such rates in effect no later than November 1, 1998. Commonwealth Gas and eight other gas utilities initiated the Massachu- setts Gas Unbundling Collaborative (the Collaborative) on September 15, 1997, to explore and develop generic principles to achieve the goals set forth by the DTE. Collaborative participants represented a broad array of stakeholder interests including the utilities, natural gas marketers, interstate pipe- lines, producers, energy consultants, unions, consumer advocates and represen- tatives for the DTE, the Massachusetts Attorney General, and the Massachusetts Division of Energy Resources. On November 15, 1997, the Collaborative filed a status report with the DTE that outlined its progress in moving the gas industry to a more competitive structure that provides all customers with meaningful access to competitive markets consistent with public-policy objectives. The status report summa- rized the substantive issues that had been the subject of Collaborative discussion, including: (1) the disposition of interstate pipeline capacity; (2) the unbundling of rates; (3) customer enrollment, billing, termination, and information exchange procedures; and, (4) consumer protections, low-income discounts, and competitive supplier registration. The status report also established a schedule to implement a final unbundling plan by November 1, 1998. In accordance with that schedule, the Collaborative submitted with the DTE <PAGE 28> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES a Rate Unbundling Status Report on January 16, 1998. The report detailed an overall process for developing unbundled rates consistent with the DTE's rate structure goals of efficiency, fairness, simplicity, continuity and earnings stability. In response to the Collaborative's proposal, the DTE ordered Commonwealth Gas to submit, no later than April 15, 1998, a consensus-based settlement, or partial settlement, of unbundled rate tariffs designed accord- ing to the general concepts set forth in the report. Provisions of Statement of Financial Accounting Standards No. 71 As described in Note 2(b) of the Notes to Consolidated Financial State- ments, the system follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In the event the system is somehow unable to meet the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations in an amount that could be material. Conditions that could give rise to the discontinuance of SFAS No. 71 include: 1) increas- ing competition restricting the system's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators. The system monitors these criteria to ensure that the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, the system believes that its retail electric utility operations, excluding generation-related assets, remain subject to SFAS No. 71 and its regulatory assets, including those related to electric generation, remain probable of future recovery. As a result of electric industry restructuring, the system's retail electric companies discontinued application of accounting principles applied to their investment in electric generation facilities effective March 1, 1998. The system will not be required to write off any of its generation-related assets, including regulatory assets. These assets will be retained on the Consolidated Balance Sheets because the legislation and the DTE's plan for a restructured electric industry specifically provide for their recovery through the non-bypassable transition charge. Environmental Matters Commonwealth Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether Commonwealth Gas may be responsible for remedial actions. In April 1997, Commonwealth Gas recorded an additional liability and corresponding regulatory asset of $1.2 million due to an increase in the site clean-up cost estimate for an MGP site for which Commonwealth Gas was previously cited as a Poten- tially Responsible Party. The DTE has approved recovery of costs associated with MGP sites. Commonwealth Gas and certain other system subsidiaries are also involved in other known or potentially contaminated sites where the associated costs may not be recoverable in rates and have recorded in prior years an estimated liability (and a charge to operations) of $2 million to cover the expected costs associated with assessment and remediation activities. These estimates are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. The system is unable to estimate its ultimate <PAGE 29> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES liability for future environmental remediation costs. However, in view of the system's current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse effect on the system's results of operations or financial position. On January 1, 1997, the system adopted the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 pro- vides authoritative guidance for recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The system has recorded environmental remediation liabilities net of amounts paid of $2.3 million at December 31, 1997. The adoption of SOP 96-1 did not have a material adverse effect on the system's results of operations or financial position. Year 2000 The system has been involved in the Year 2000 compliancy since 1996. A complete inventory and review of software, information processing and delivery systems has been completed, and work continues on computer systems wherever necessary. While some computer systems have already been updated, tested and placed in production, the system expects to complete the balance of the modifications by early 1999. Expenditures incurred by the system through 1997 to review existing computer systems and to modify existing software and applications amounted to nearly $900,000, and it is estimated that approximately $2.6 million will be incurred in 1998 and 1999. Management believes that, with appropriate modifications, the system will be fully compliant regarding all Year 2000 issues and will continue to provide its products and services uninterrupted through the millennium change. Failure to become fully compliant could have a significant impact on the system's operations. New Accounting Principles During 1997, the Financial Accounting Standards Board issued two new accounting standards that the system will adopt in 1998. SFAS No. 130, "Reporting Comprehensive Income" will require disclosure on comprehensive income and its components. SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" will require disclosure of financial and descriptive information on reportable operating segments. The adoption of these standards is not expected to have a material impact on the system's results of operations or financial position. Item 8. Financial Statements and Supplementary Data The Company's financial statements required by this item are filed herewith on pages 30 through 52 of this report. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. <PAGE 30> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 8. Financial Statements and Supplementary Data MANAGEMENT'S REPORT The consolidated financial statements presented herein are representa- tions of the management of Commonwealth Energy System. Management recognizes its responsibility for the preparation and presentation of financial state- ments in conformity with generally accepted accounting principles. To fulfill this responsibility, management maintains a system of internal accounting controls, including established policies and procedures and a comprehensive internal auditing program to evaluate the adequacy and effectiveness of accounting and operating controls, compliance with system policies and procedures and the safeguarding of system assets. The responsibility of our independent auditors' examination is limited to the expression of an opinion as to the fairness of the consolidated financial statements presented. The independent auditors are selected by the Board of Trustees and report their findings thereto through the Audit Commit- tee, which is comprised of three outside Trustees. The Board of Trustees is responsible for ensuring that both the independent auditors and management fulfill their respective responsibilities as they pertain to these consolidat- ed financial statements. James D. Rappoli, Financial Vice President and Treasurer March 2, 1998. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Trustees of Commonwealth Energy System: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of COMMONWEALTH ENERGY SYSTEM (the System) (a Massachusetts trust) and subsidiary companies as of December 31, 1997 and 1996, and the related consolidated statements of income, cash flows, changes in common shareholders' investment and changes in redeemable preferred shares for each of the three years in the period ended December 31, 1997. These consolidated financial statements are the responsibility of the System and subsidiary companies' management. Our responsibility is to express an opinion on these consolidated 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 that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Common- wealth Energy System and subsidiary companies as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with general- ly accepted accounting principles. Arthur Andersen LLP Boston, Massachusetts February 19, 1998 (except with respect to certain matters discussed in Note 2, as to which the date is March 2, 1998). <PAGE 31> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INDEX TO FINANCIAL STATEMENTS AND SCHEDULES PART II. FINANCIAL STATEMENTS Consolidated Statements of Income for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Balance Sheets at December 31, 1997 and 1996 Consolidated Statements of Capitalization for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Changes in Common Shareholders' Investment for the Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Changes in Redeemable Preferred Shares for the Years Ended December 31, 1997, 1996 and 1995 Notes to Consolidated Financial Statements PART IV. SCHEDULES I Investments in, Equity in Earnings of, and Dividends Received from Related Parties for the Years Ended December 31, 1997, 1996 and 1995 II Valuation and Qualifying Accounts for the Years Ended December 31, 1997, 1996 and 1995 SCHEDULES OMITTED All other schedules are not submitted because they are not applicable or not required or because the required information is included in the financial statements or notes thereto. <PAGE 32> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (Dollars in thousands except per share amounts) 1997 1996 1995 Operating Revenues Electric $ 688,508 $ 649,678 $604,980 Gas 333,977 341,867 306,953 Steam and other 19,259 19,360 17,355 1,041,744 1,010,905 929,288 Operating Expenses Fuel used in electric production, principally oil 129,021 91,690 57,820 Electricity purchased for resale 265,805 265,019 274,795 Cost of gas sold 184,122 187,530 158,835 Other operation 225,658 215,319 206,280 Maintenance 36,838 40,913 38,414 Depreciation 53,405 51,782 48,170 Taxes- Local property 19,130 18,049 17,573 Income 31,040 36,099 24,574 Payroll and other 9,075 7,839 8,284 954,094 914,240 834,745 Operating Income 87,650 96,665 94,543 Other Income 2,601 4,878 1,461 Income Before Interest Charges 90,251 101,543 96,004 Interest Charges Long-term debt 33,572 35,586 38,581 Other interest charges 6,778 6,782 6,027 40,350 42,368 44,608 Net Income 49,901 59,175 51,396 Dividends on preferred shares 988 1,050 1,110 Earnings Applicable to Common Shares $ 48,913 $ 58,125 $ 50,286 Average Number of Common Shares Outstanding 21,531,433 21,529,676 21,311,836 Earnings Per Common Share $2.27 $2.70 $2.36 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 33> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1997 AND 1996 (Dollars in thousands) 1997 1996 Assets Property, Plant and Equipment, at original cost Electric $1,173,797 $1,150,818 Gas 373,541 357,403 Other 72,475 66,365 1,619,813 1,574,586 Less-Accumulated depreciation and amortization 577,962 536,041 1,041,851 1,038,545 Construction work in progress 7,864 5,485 Nuclear fuel in process 193 1,597 1,049,908 1,045,627 Equity in Corporate Joint Ventures Nuclear electric power companies (2.5% to 4.5%) 10,368 10,046 Other investments 3,399 3,349 13,767 13,395 Current Assets Cash 4,299 1,495 Accounts receivable, less reserves of $9,408 in 1997 and $8,324 in 1996 128,946 117,008 Unbilled revenues 32,029 31,698 Inventories, at average cost- Electric production fuel oil 1,902 2,221 Natural gas 23,301 23,084 Materials and supplies 7,441 6,220 Prepaid taxes 9,282 9,079 Other 5,786 5,686 212,986 196,491 Deferred Charges Regulatory assets 178,864 154,291 Other 29,525 19,151 208,389 173,442 $1,485,050 $1,428,955 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 34> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1997 AND 1996 (Dollars in thousands) 1997 1996 Capitalization and Liabilities Capitalization (See separate statement) Common share investment $ 430,770 $ 415,694 Redeemable preferred shares, less current sinking fund requirements 12,200 13,020 Long-term debt, less current sinking fund requirements and maturing debt 364,311 355,305 807,281 784,019 Capital Lease Obligations 12,272 12,346 Current Liabilities Interim Financing- Notes payable to banks 94,075 118,475 Maturing long-term debt 19,000 14,260 113,075 132,735 Other Current Liabilities- Current sinking fund requirements 8,473 8,473 Accounts payable 107,157 90,269 Accrued taxes- Local property and other 9,795 9,060 Income 14,410 7,910 Accrued interest 6,778 6,267 Dividends declared 8,517 8,289 Other 43,627 39,279 198,757 169,547 311,832 302,282 Deferred Credits Accumulated deferred income taxes 176,354 174,877 Nuclear units' purchased power contracts 69,659 43,677 Unamortized investment tax credits 25,340 26,618 Other 82,312 85,136 353,665 330,308 Commitments and Contingencies $1,485,050 $1,428,955 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 35> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (Dollars in thousands) 1997 1996 1995 Operating Activities Net income $ 49,901 $ 59,175 $ 51,396 Effects of noncash items- Depreciation and amortization 65,646 63,331 60,555 Deferred income taxes, net 2,542 3,515 4,182 Investment tax credits, net (1,278) (1,285) (1,401) Earnings from corporate joint ventures (1,348) (1,557) (1,633) Dividends from corporate joint ventures 1,272 1,376 2,067 Change in working capital, exclusive of cash- Accounts receivable and unbilled revenues (12,269) (9,446) (13,626) Prepaid (accrued) income taxes 6,500 (14,097) 14,353 Prepaid (accrued) local property and other taxes 532 (555) (950) Accounts payable and other 20,756 (33,956) 25,199 Power contract buy-out - - (25,500) Fuel charge stabilization deferral, net (5,543) 2,372 (3,447) Deferred postretirement benefits costs (2,126) (2,157) (4,479) FERC Order 636 transition costs, net - - 11,390 All other operating items (17,034) (3,391) 6,565 Net cash provided by operating activities 107,551 63,325 124,671 Investing Activities Additions to property, plant and equipment (inclusive of AFUDC)- Electric (34,524) (38,844) (61,643) Gas (18,230) (11,611) (16,198) Other (4,804) (2,730) (3,659) Net cash used for investing activities (57,558) (53,185) (81,500) Financing Activities Sale of common shares - 32 9,534 Payment of dividends (35,056) (34,205) (33,142) Proceeds from (payment of) short-term borrowings, net (24,400) 62,875 10,750 Long-term debt issues 35,000 - - Retirement of long-term debt and preferred shares through sinking funds (8,473) (8,436) (8,716) Long-term debt issues refunded (14,260) (33,230) (25,000) Net cash used for financing activities (47,189) (12,964) (46,574) Net increase (decrease) in cash 2,804 (2,824) (3,403) Cash at beginning of period 1,495 4,319 7,722 Cash at end of period $ 4,299 $ 1,495 $ 4,319 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of capitalized amounts) $ 38,201 $ 41,294 $ 42,051 Income taxes $ 24,436 $ 46,563 $ 12,918 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 36> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CAPITALIZATION DECEMBER 31, 1997 AND 1996 (Dollars in thousands) 1997 1996 Common Share Investment Common shares, $2 par value- Authorized-50,000,000 shares Outstanding-21,531,784 shares in 1997 and 21,529,676 shares in 1996 $ 43,063 $ 43,059 Amounts paid in excess of par value 111,912 111,685 Retained earnings 275,795 260,950 Total common share investment 430,770 415,694 Redeemable Preferred Shares, Cumulative, $100 Par Value Series A, 4.80% 2,520 2,640 Series B, 8.10% 3,840 4,000 Series C, 7.75% 6,660 7,200 Less-Current sinking fund requirements (820) (820) Total redeemable preferred shares 12,200 13,020 Long-term Debt System Senior Notes due- 1997, 10.48% - 10,000 1998, 10.45% 10,000 10,000 1999, 10.58% 10,000 10,000 Less-Maturing long-term debt (10,000) (10,000) Total System long-term debt 10,000 20,000 Subsidiary companies Mortgage Bonds, collateralized by property of operating subsidiaries, due- 2001, 8.99% 14,450 18,100 2006, 8.85% 34,300 34,650 2007, 6.54% 10,000 - 2017, 7.04% 25,000 - 2020, 7 3/8% 10,000 10,000 2020, 9 7/8% 40,000 40,000 2020, 9.95% 25,000 25,000 2033, 7.11% 35,000 35,000 Notes due- 1997, 6 1/4% - 4,260 1998, variable rate (6.391% in 1997 and 6.125% in 1996) 9,000 9,000 1999, 8.04% 10,000 10,000 2002, 7 3/4% 2,500 2,600 2002, 9.30% 30,000 30,000 2003, 7.43% 15,000 15,000 2004, 9.50% 10,000 12,500 2007, 8.70% 5,000 5,000 2007, 9.55% 10,000 10,000 2008, 7.70% 10,000 10,000 2012, 9.37% 15,789 16,842 2013, 7.98% 25,000 25,000 2014, 9.53% 10,000 10,000 2019, 9.60% 10,000 10,000 2023, 8.47% 15,000 15,000 Less-Maturing long-term debt (9,000) (4,260) Current sinking fund requirements (7,653) (7,653) Unamortized discount, net (75) (734) Total subsidiary companies' long-term debt 354,311 335,305 Total long-term debt 364,311 355,305 Total capitalization $807,281 $784,019 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 37> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' INVESTMENT FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 Amounts Par Paid in Value Excess $2 Per of Par Retained Shares Share Value Earnings Total (Dollars in thousands) Balance December 31, 1994 21,051,794 $42,103 $103,168 $217,726 $362,997 Add (Deduct)- Net income - - - 51,396 51,396 Sale of shares 476,474 953 8,581 - 9,534 Cash dividends declared- Common shares-$1.50 per share - - - (32,032) (32,032) Preferred shares - - - (1,110) (1,110) Balance December 31, 1995 21,528,268 43,056 111,749 235,980 390,785 Add (Deduct)- Net income - - - 59,175 59,175 Sale of shares 1,408 3 29 - 32 Cost of stock split - - (93) - (93) Cash dividends declared- Common shares-$1.54 per share - - - (33,155) (33,155) Preferred shares - - - (1,050) (1,050) Balance December 31, 1996 21,529,676 43,059 111,685 260,950 415,694 Add (Deduct)- Net income - - - 49,901 49,901 Shares issued pursuant to Long-Term Incentive Compensation Plan 2,108 4 43 - 47 Amortization of deferred compensation - - 184 - 184 Cash dividends declared- Common shares-$1.58 per share - - - (34,068) (34,068) Preferred shares - - - (988) (988) Balance December 31, 1997 21,531,784 $43,063 $111,912 $275,795 $430,770 Consolidated Statements of Changes in Redeemable Preferred Shares Commonwealth Energy System and Subsidiary Companies For the Years Ended December 31, 1997, 1996 and 1995 Authorized and Outstanding Cumulative Preferred Shares-$100 Par Value Series A Series B Series C Total 4.80% 8.10% 7.75% Shares Balance December 31, 1994 28,800 43,200 82,800 154,800 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1995 27,600 41,600 77,400 146,600 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1996 26,400 40,000 72,000 138,400 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1997 25,200 38,400 66,600 130,200 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 38> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) General Information Commonwealth Energy System (the System) is an exempt public utility holding company with investments in four operating public utility companies located in central, eastern and southeastern Massachusetts. The System is the parent company and, together with its subsidiaries, is collectively referred to as "the system." System electric operations are involved in the produc- tion, distribution and sale of electricity to 367,000 customers in 41 communi- ties including New Bedford, Plymouth, Cambridge and the geographic area comprising Cape Cod. Gas operations serve 237,000 customers in 49 communities including New Bedford, Cambridge, Plymouth and Worcester. In addition to the utility companies, the system includes a steam distribution company, five real estate trusts, a company engaged in the operation of LNG facilities and three new subsidiaries that are pursuing energy-related business opportunities. The system has 1,727 regular employees including 1,037 (60%) represented by various collective bargaining units. A contract with a collective bargain- ing unit representing approximately 5% of regular employees that was scheduled to expire in May 1997 was ratified in April 1997 and is effective through May 31, 2001. In April 1998, a collective bargaining contract representing approximately 5% of regular employees is scheduled to expire and two addition- al contracts (together representing approximately 7% of regular employees) are scheduled to expire in September 1998. During the second quarter of 1997, the system initiated a voluntary personnel reduction program. As a result of this program, the total number of regular employees has declined by approximately 13% in 1997. (2) Significant Accounting Policies (a) Principles of Consolidation and Accounting The consolidated financial statements include the accounts of the System and all of its subsidiary companies. All significant intercompany accounts and transactions have been eliminated in consolidation. 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 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. Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements. (b) Regulatory Assets and Liabilities The system's operating utility companies are regulated as to rates, accounting and other matters by various authorities, including the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Massachusetts Department of Public Utilities. Based on the current regulatory framework, the system accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulated subsidiaries of the System have established various regulatory assets in cases where the DTE and/or the FERC have permitted or are expected to permit recovery of specific costs over time. Similarly, the regulatory liabilities established by the system are required to be refunded to customers over time. In the event the criteria for applying SFAS No. 71 are no longer met, the accounting impact would be an extra- ordinary, non-cash charge to operations of an amount that could be material. <PAGE 39> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Criteria that give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts the system's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators from cost based regulation to another form of regulation. These criteria are reviewed on a regular basis to ensure the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, the system believes that its regulatory assets, including those related to generation, are probable of future recovery. As a result of electric industry restructuring, the system's retail electric companies discontinued application of accounting principles applied to their investment in electric generation facilities effective March 1, 1998. The system will not be required to write off any of its generation-related assets, including regulatory assets. These assets will be retained on the Consolidated Balance Sheets because the legislation and the DTE's plan for a restructured electric industry specifically provide for their recovery through a non-bypassable transition charge. Effective January 1, 1996, the system adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. SFAS No. 121 did not have an impact on the system's financial position or results of operations upon adoption. The principal regulatory assets included in deferred charges at December 31, 1997 and 1996 were as follows: 1997 1996 (Dollars in thousands) Postretirement benefit costs $ 25,475 $ 25,051 Power contract buy-out 17,609 20,794 Fuel charge stabilization 29,655 21,504 Deferred income taxes 13,089 13,597 FERC Order 636 transition costs 7,336 9,680 Maine Yankee unrecovered plant and decommissioning costs 34,908 - Connecticut Yankee unrecovered plant and decommissioning costs 28,566 35,879 Yankee Atomic unrecovered plant and decommissioning costs 6,184 7,798 Seabrook related costs 4,324 6,262 Other 11,718 13,726 $178,864 $154,291 The regulatory liabilities, reflected in the accompanying Consolidated Balance Sheets and related primarily to deferred income taxes, were $14.1 million and $17.7 million at December 31, 1997 and 1996, respectively. As of December 31, 1997, $143.1 million of the system's regulatory assets, including the costs associated with existing power contracts with three Yankee nuclear power plants that have shut down permanently (see Note 3(d)), and all of its regulatory liabilities are reflected in rates charged to customers. Regulatory assets are currently being recovered over a weighted average period of approximately 11 years. The fuel charge stabilization deferral was expected to be recovered over a six-year period beginning in April 1998, pursuant to a yet to be determined recovery schedule and subject to final DTE approval. In November 1997, the Commonwealth of Massachusetts enacted a comprehen- sive electric utility industry restructuring bill. On November 19, 1997, the System's electric subsidiaries filed a restructuring plan with the DTE. The plan, approved by the DTE on February 27, 1998, describes the process by which the System's retail electric subsidiaries will, beginning March 1, 1998, initiate a ten percent rate reduction for all customer classes and allow <PAGE 40> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES customers to choose their energy supplier. As part of the plan, the DTE authorized the recovery of certain strandable costs. The legislation gives the DTE the authority to determine the amount of strandable costs that will be eligible for recovery. Costs that will qualify as strandable costs and be eligible for recovery include, but are not limited to, certain above market costs associated with generating facilities, costs associated with long-term commitments to purchase power at above market prices from independent power producers and regulatory assets and associated liabilities related to the generation portion of the electric business. The cost of transitioning to competition will be mitigated, in part, through the divestiture of the system's non-nuclear generating assets in an auction process that is expected to be completed in 1998. Any net proceeds in excess of book value received from the divestiture of these assets will be used to mitigate stranded costs. The system's ability to recover its stranded costs will depend on several factors, including the aggregate amount of stranded costs the system will be allowed to recover and the market price of electricity. Management believes that the system will recover its stranded costs. A change in any of the above listed factors or in the current legislation could affect the recovery of stranded costs and may result in a loss to the system. For additional information relating to industry restructuring, see the "Industry Restructuring - Electric" section under Management's Discussion and Analysis of Financial Condition and Results of Operations. (c) Equity Method of Accounting The system uses the equity method of accounting for investments in corporate joint ventures due, in part, to its ability to exercise significant influence over operating and financial policies of these entities. Under this method, it records as income the proportionate share of the net earnings of the joint ventures with a corresponding increase in the carrying value of the investment. The investment is reduced as cash dividends are received. The system conducts business with the corporate joint ventures in which it has investments, principally four nuclear generating facilities located in New England and a 3.8% interest in Hydro-Quebec Phase II. (d) Operating Revenues Customers are billed for their use of electricity and gas on a cycle basis throughout the month. To reflect revenues in the proper period, the estimated amount of unbilled sales revenue is recorded each month. System utility companies are generally permitted to bill customers for costs associated with purchased power and transmission, fuel used in electric production, gas, conservation and load management and environmental costs. The amount of such costs incurred but not yet reflected in customers' bills is recorded as unbilled revenues. (e) Depreciation Depreciation is provided using the straight-line method at rates intended to amortize the original cost and the estimated cost of removal less salvage of properties over their estimated economic lives. The average composite depreciation rates were as follows: 1997 1996 1995 Electric 3.66% 3.65% 3.52% Gas 2.95 2.94 2.90 Steam 3.80 3.89 3.91 LNG 3.65 3.59 3.20 <PAGE 41> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (f) Allowance for Funds Used During Construction Under applicable rate-making practices, system companies are permitted to include an allowance for funds used during construction (AFUDC) as an element of their depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which utility companies earn a return. An amount equal to the AFUDC capitalized in the current period is reflected in other interest charges in the accompanying Consolidated Statements of Income and amounted to $368,000, $257,000 and $857,000 in 1997, 1996 and 1995, respectively. While AFUDC does not provide funds currently, these amounts are recover- able in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 6.1% in 1997, 6.2% in 1996 and 7.1% in 1995. (g) Earnings Per Share The System adopted SFAS No. 128 "Earnings Per Share" for the year ended December 31, 1997. SFAS No. 128 requires the presentation of both basic and diluted earnings per share (EPS). Diluted EPS reflect the possible impact on EPS that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. The System granted potential awards in the form of common shares to certain key employees pursuant to its Long Term Incentive Compensation Plan (see Note 5(d)) during the first quarter of 1997. The adoption of SFAS No. 128 did not have a material impact on the System's EPS. (3) Commitments and Contingencies (a) Capital Expenditures The system is engaged in a continuous construction program presently estimated at $248.6 million for the five-year period 1998 through 2002. Of that amount, $60.7 million is estimated for 1998. The program is subject to periodic review and revision. The system, through its Advanced Energy Systems, Inc. subsidiary, tentatively agreed to purchase a total energy plant located in the Longwood Medical Area of Boston for $146.3 million. This transaction is expected to be closed in the second quarter of 1998. Revenues for fiscal years ended June 30, 1997 and 1996 were $58 million and $53.9 million, respectively. (b) Seabrook Nuclear Power Plant The system's 3.52% interest in the Seabrook nuclear power plant is owned by Canal Electric Company (Canal Electric), a wholesale electric generating subsidiary, to provide for a portion of the capacity and energy needs of affiliates Cambridge Electric Light Company (Cambridge Electric) and Common- wealth Electric Company (Commonwealth Electric). Canal Electric is recovering 100% of its Seabrook 1 investment through a power contract with Cambridge Electric and Commonwealth Electric pursuant to FERC and DTE approval. <PAGE 42> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Pertinent information with respect to Canal Electric's joint-ownership interest in Seabrook 1 and information relating to operating expenses that are included in the accompanying financial statements are as follows: 1997 1996 (Dollars in thousands) Utility plant-in- service $232,471 $232,183 Plant capacity (MW) 1,150 Nuclear fuel 22,207 21,613 Canal Electric's share: Accumulated depreciation Percent interest 3.52% and amortization (64,379) (57,359) Entitlement (MW) 40.5 Construction work in In-service date 1990 progress 1,036 844 Operating license $191,335 $197,281 expiration date 2026 1997 1996 1995 (Dollars in thousands) Operating expenses: Fuel $ 1,471 $ 1,727 $ 2,353 Other operation 4,206 4,091 4,292 Maintenance 2,364 990 1,376 Depreciation 6,314 6,544 6,542 Amortization 1,319 1,319 1,319 $15,674 $14,671 $15,882 Canal Electric and the other joint owners have established a decommis- sioning fund to cover decommissioning costs. The estimated cost to decommis- sion the plant is $469.1 million in current dollars. Canal Electric's share of this liability (approximately $16.5 million), less its share of the market value of the assets held in a decommissioning trust (approximately $2.5 million), is approximately $14 million at December 31, 1997. (c) Price-Anderson Act Under the Price-Anderson Act (the Act), owners of nuclear power plants have the benefit of approximately $8.9 billion of public liability coverage which would compensate the public for valid bodily injury and property loss on a no fault basis in the event of an accident at a commercial nuclear power plant. Under the provisions of the Act, each nuclear reactor with an operat- ing license can be assessed up to $79.3 million per nuclear incident with a maximum assessment of $10 million per incident within one calendar year. Nuclear plant owners have initiated insurance programs designed to help cover liability claims relating to property damage, decontamination, replacement power and business interruption costs for participating utilities arising from a nuclear incident. The system has an equity ownership interest in four nuclear generating facilities as well as a 3.52% joint-ownership interest in Seabrook 1. The operators of these units maintain nuclear insurance coverage (on behalf of the owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II) and the combined American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI). NEIL II provides $2.25 billion of property, boiler, machinery and decontamination insurance coverage, including accidental premature decommissioning insurance in the amount of the shortfall in the Decommissioning Trust Fund, in excess of the underlying $500 million policy. All companies insured with NEIL II are subject to retroactive assessments if losses exceed the accumulated funds available. ANI provides $500 million of "all risk" property damage, boiler, machinery and decontamination insurance. An additional $200 million of primary financial protection coverage is provided for off-site bodily injury or property damage caused by a nuclear incident. ANI also provides secondary financial protection liability insur- ance which currently provides $8.7 billion of retrospective insurance premium benefits in accordance with the provisions of the Act. Additional coverage ($200 million) provided by ANI includes tort liability protection arising out <PAGE 43> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES of radiation injury claims by nuclear workers and injury or property damage caused by the transportation or shipment of nuclear materials or waste. Based on its various ownership interests in the five nuclear generating facilities, the system's retrospective premium could be as high as $1.9 million annually or a cumulative total of $15.1 million, exclusive of the effect of inflation indexing (at five-year intervals) and a 5% surcharge ($4 million) in the event that total public liability claims from a nuclear incident exceed the funds available to pay such claims. (d) Power Contracts The system has long-term contracts to purchase capacity from various generating facilities. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. Information relative to these contracts is as follows: Range of Contract Expiration Entitlement Cost Dates % MW 1997 1996 1995 (Dollars in thousands) Type of Unit Natural gas 2008-2017 (a) 208.6 $127,580 $120,842 $121,636 Nuclear 2012 (b) 85.1 41,058 41,280 44,379 Waste-to-energy 2015 100.0 67.0 43,038 39,622 37,526 Hydro 2014-2023 100.0 23.9 10,952 12,537 9,933 Total 384.6 $222,628 $214,281 $213,474 (a) Includes contracts to purchase power from various non-utility generators with capacity entitlements ranging from 11.1% to 100%. (b) The system has an 11% entitlement in the Pilgrim nuclear power plant and a 2.5% ownership interest in the Vermont Yankee nuclear power plant. The estimated cost to decommission this plant is $385.9 million in current dollars. The system's share of this liability (approximately $8.7 million), less its share of the market value of the assets held in a decommissioning trust (approximately $4.4 million), is approximately $4.3 million at December 31, 1997. Pertinent information with respect to life-of-the-unit contracts with nuclear units that are no longer operating in which the system has an equity ownership is as follows: Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands) Equity Ownership (%) 4.50 4.00 4.50 Plant Entitlement (%) 4.50 3.59 4.50 Contract Expiration Date 2007 2008 2000 Year of Shutdown 1996 1997 1992 1995 Actual Cost ($) 9,498 7,376 2,023 1996 Actual Cost ($) 9,259 6,511 2,260 1997 Actual Cost ($) 5,760 8,928 2,238 Decommissioning cost estimate (100%) ($) 437,270 386,046 137,428 System's decommissioning cost ($) 19,677 13,859 6,184 Market value of assets (100%) ($) 209,448 199,457 134,143 System's market value of assets ($) 9,425 7,161 6,036 Based upon regulatory precedent, the operators of the Yankee units believe they will be permitted to continue to collect from power purchasers (including system companies) decommissioning costs, unrecovered plant invest- ment and other costs associated with the permanent closure of these plants over the remaining period of each plant's operating license. The system does <PAGE 44> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES not believe that the ultimate outcome of the early closing of these plants will have a material adverse effect on its operations and believes that recovery of these FERC-approved costs would continue to be allowed in its rates at the retail level. Costs pursuant to these power contracts are included in electricity purchased for resale in the accompanying Consolidated Statements of Income and are recoverable in revenues. The estimated aggregate obligations for capacity under the long-term purchased power contracts and a life-of-the-unit contract from the one remaining operating Yankee nuclear unit (Vermont Yankee) in effect for the five years subsequent to 1997 is as follows: Long-Term Purchased Equity Owned Power Nuclear Unit Total (Dollars in thousands) 1998 $219,909 $4,957 $224,866 1999 223,490 5,001 228,491 2000 225,513 4,311 229,824 2001 233,576 4,806 238,382 2002 235,228 4,996 240,224 Due to changing conditions within the nuclear industry, it is possible that the remaining operating nuclear plant in which the system has an equity ownership interest could be shut down prior to the expiration of that unit's operating license. The costs associated with these power contract obligations are a significant component of the system's stranded costs that are included in the system's restructuring plan approved by the DTE. (e) Environmental Matters The system is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installa- tion of expensive air and water pollution control equipment. These regula- tions have had an impact on the system's operations in the past and would continue to have an impact on future operations, capital costs and construc- tion schedules of major facilities; however, the electric generating facili- ties are likely to be sold at auction in 1998 pursuant to the restructuring plan filed with the DTE. For additional environmental information, see "Environmental Matters" in Management's Discussion and Analysis of Financial Condition and Results of Operations. (4) Income Taxes The system files a consolidated federal income tax return. For finan- cial reporting purposes, the System and its subsidiaries provide taxes on a separate return basis. <PAGE 45> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The following is a summary of the consolidated provisions for income taxes for the years ended December 31, 1997, 1996 and 1995: 1997 1996 1995 (Dollars in thousands) Federal Current $24,396 $28,375 $15,954 Deferred 2,612 2,784 8,231 Investment tax credits, net (1,278) (1,285) (1,401) 25,730 29,874 22,784 State Current 5,389 5,542 4,176 Deferred 316 890 1,115 5,705 6,432 5,291 31,435 36,306 28,075 Amortization of regulatory liability relating to deferred income taxes (386) (159) (5,164) $31,049 $36,147 $22,911 Federal and state income taxes charged to: Operating expense $31,040 $36,099 $24,574 Other (income) expense 9 48 (1,663) $31,049 $36,147 $22,911 Deferred tax liabilities and assets are determined based on the differ- ence between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse. In May 1995, Canal Electric refunded certain unprotected excess deferred taxes to Commonwealth Electric and Cambridge Electric resulting in a reduction to the 1995 tax provision. Accumulated deferred income taxes consisted of the following in 1997 and 1996: 1997 1996 (Dollars in thousands) Liabilities Property-related $198,183 $195,810 Power contract buy-out 6,853 10,002 Fuel charge stabilization 12,241 8,124 Postretirement benefits plan 7,742 7,442 Seabrook nonconstruction 707 1,183 All other 16,140 20,018 241,866 242,579 Assets Investment tax credits 16,058 17,205 Pension plan 6,409 8,528 Regulatory liability 6,103 6,352 Personnel reduction program 1,540 - All other 20,960 22,239 51,070 54,324 Accumulated deferred income taxes, net $190,796 $188,255 The net year-end deferred income tax liability above includes a current deferred tax liability of $14,442,000 and $13,378,000 in 1997 and 1996, respectively, which are included in accrued income taxes in the accompanying Consolidated Balance Sheets. The total income tax provision set forth previously represents 38% in 1997 and 1996 and 31% in 1995 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages: <PAGE 46> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 1997 1996 1995 (Dollars in thousands) Federal statutory rate 35% 35% 35% Federal income tax expense at statutory levels $28,332 $33,363 $26,007 Increase (Decrease) from statutory levels: State tax net of federal tax benefit 3,708 4,181 3,439 Tax versus book depreciation 1,714 1,553 1,369 Amortization of investment tax credits (1,278) (1,285) (1,368) Reversals of capitalized expenses (654) (654) (652) Dividend received deduction (366) (381) (389) Amortization of excess deferred reserves (386) (159) (5,164) Other (21) (471) (331) $31,049 $36,147 $22,911 Effective federal income tax rate 38% 38% 31% (5) Employee Benefit Plans (a) Pension The system has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. The system makes monthly contributions to the plan consistent with the funding requirements of the Employee Retirement Income Security Act of 1974. Components of pension expense and related assumptions to develop pension expense were as follows: 1997 1996 1995 (Dollars in thousands) Service cost $ 7,565 $ 7,663 $ 6,386 Interest cost 24,824 24,462 23,949 Return on plan assets-(gain)/loss (61,094) (45,961) (62,933) Net amortization and deferral 37,540 24,520 42,928 Total pension expense 8,835 10,684 10,330 Less: Amounts capitalized and deferred 3,017 2,203 1,842 Net pension expense $ 5,818 $ 8,481 $ 8,488 Discount rate 7.50% 7.25% 8.50% Assumed rate of return 8.75 8.75 9.00 Rate of increase in future compensation 4.25 4.25 5.00 Pension expense reflects the use of the projected unit credit method which is also the actuarial cost method used in determining future funding of the plan. Commonwealth Electric and Cambridge Electric, in accordance with current ratemaking, are deferring the difference between pension contribution which is reflected in base rates, and pension expense. The funded status of the system's pension plan (using a measurement date of December 31) is as follows: <PAGE 47> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 1997 1996 (Dollars in thousands) Accumulated benefit obligation: Vested $(331,170) $(254,888) Nonvested (40,822) (30,604) $(371,992) $(285,492) Projected benefit obligation $(409,039) $(340,850) Plan assets at fair market value 390,625 343,884 Projected benefit obligation less or (greater) than plan assets (18,414) 3,034 Unamortized transition obligation 6,429 8,036 Unrecognized prior service cost 11,922 13,357 Unrecognized gain (20,480) (43,918) Accrued pension liability $ (20,543) $ (19,491) The following actuarial assumptions were used in determining the plan's year-end funded status: 1997 1996 Discount rate 7.00% 7.50% Rate of increase in future compensation 3.75 4.25 Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect pension expense in future years. (b) Other Postretirement Benefits Certain employees are eligible for postretirement benefits if they meet specific requirements. These benefits could include health and life insurance coverage and reimbursement of Medicare Part B premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits. To fund its postretirement benefits, the system makes contributions to various voluntary employees' beneficiary association trusts that were estab- lished pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). The system also makes contributions to a subaccount of its pension plan pursuant to section 401(h) of the Code to fund a portion of its postretirement benefit obligation. The system contributed approximately $12.2 million, $13.7 million and $14 million to these trusts during 1997, 1996 and 1995, respec- tively. The net periodic postretirement benefit cost for the years ended December 31, 1997, 1996 and 1995 includes the following components and related assumptions: 1997 1996 1995 (Dollars in thousands) Service cost $ 1,919 $ 2,211 $ 1,774 Interest cost 9,223 9,352 9,022 Return on plan assets (9,483) (5,176) (5,796) Amortization of transition obligation over 20 years 5,336 5,336 5,336 Net amortization and deferral 5,236 2,038 3,692 Total postretirement benefit cost 12,231 13,761 14,028 Less: Amounts capitalized and deferred 466 1,614 5,898 Net postretirement benefit cost $11,765 $12,147 $ 8,130 Discount rate 7.50% 7.25% 8.50% Assumed rate of return 8.75 8.75 9.00 Rate of increase in future compensation 4.25 4.25 5.00 <PAGE 48> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The funded status of the system's postretirement benefit plan using a measurement date of December 31, 1997 and 1996 is as follows: 1997 1996 (Dollars in thousands) Accumulated postretirement benefit obligation: Retirees $(102,485) $ (72,827) Fully eligible active plan participants (18,123) (11,468) Other active plan participants (28,756) (41,352) (149,364) (125,647) Plan assets at fair market value 61,632 45,967 Accumulated postretirement benefit obligation greater than plan assets (87,732) (79,680) Unamortized transition obligation 80,033 85,368 Unrecognized (gain) loss 7,699 (5,688) $ - $ - The following actuarial assumptions were used in determining the plan's estimated accumulated postretirement benefit obligation (APBO) and funded status for 1997 and 1996: 1997 1996 Discount rate 7.00% 7.50% Rate of increase in future compensation 3.75 4.25 Medicare Part B premiums 3.10 9.50 Medical care 6.75 7.00 Dental care 4.50 5.00 The above dental rate remains constant through the year 2007. Rates for Medicare Part B premiums and medical care decrease to 3.1% and 4.5%, respec- tively, by 2007 and remain at that level thereafter. A one percent change in the medical trend rate would have a $1.5 million impact on the system's annual expense and would change the APBO by approximately $18.2 million. Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect postretire- ment benefit expense in future years. Effective May 1, 1995 the DTE approved a settlement proposal sponsored jointly by Commonwealth Electric and the Attorney General of Massachusetts that allows Commonwealth Electric to fully recover costs relating to postreti- rement benefits and to amortize its $8.6 million deferred balance over a ten- year period. In February 1996, FERC accepted for filing rate schedules that provided for the recovery of Canal Electric's expense effective with its March 1996 contract billings including the recovery of previously deferred costs over a six-month period. On April 15, 1997, the DTE issued an accounting ruling allowing Commonwealth Gas Company to include postretirement benefits costs in cost-of-service and to amortize the deferred balance of $10.5 million at March 31, 1997 associated with these costs over a period not to exceed ten years that began in April 1997. (c) Savings Plan The system has an Employees Savings Plan that provides for system contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate and up to five percent for those employees no longer eligible for postretirement health benefits. The total system contribution was $4,173,000 in 1997, $4,053,000 in 1996 and $4,393,000 in 1995. <PAGE 49> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (d) Long-Term Incentive Compensation Plan The Long-Term Incentive Compensation Plan (the Plan), approved by shareholders in 1994, was established to advance the interests of the System by providing long-term financial incentives, primarily common shares of the System, to selected key employees of the system for achieving specified objectives. The System, in encouraging such share ownership, seeks to attract, retain and motivate employees who hold positions of significant responsibility. Eligible employees are chosen by the Executive Compensation Committee of the Board of Trustees and are presented grant share awards which mature after a three-year vesting period. Shares are issued to participants in March following the close of the third plan year. All shares are subject to forfeiture if specified performance measures are not met. During the applicable vesting period, participants have all the voting, dividend and other related rights of a record holder except that the shares are nontrans- ferable. Common shares granted under the Plan can not exceed 1% of the total shares issued and outstanding. In 1997, 31,606 common shares, valued at approximately $707,000, were granted to system officers. Compensation costs of approximately $231,000 were recorded in 1997 with the remainder to be recognized over the remaining vesting period of 26 months. Common shares granted pursuant to the Plan had no material impact on earnings per share. (6) Interim Financing and Long-Term Debt (a) Notes Payable to Banks System companies maintain both committed and uncommitted lines of credit for the short-term financing of their construction programs and other cor- porate purposes. As of December 31, 1997, system companies had $145 million of committed lines of credit that will expire at varying intervals in 1998. These lines are normally renewed upon expiration and require annual fees of up to .1875% of the individual line. At December 31, 1997, the uncommitted lines of credit totaled $10 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 5.8% and 5.6% in 1997 and 1996, respectively. Notes payable to banks totaled $94,075,000 and $118,475,000 at December 31, 1997 and 1996, respectively. (b) Long-term Debt Maturities and Retirements Under terms of various indentures and loan agreements, the System and certain subsidiary companies are required to make periodic sinking fund payments for retirement of outstanding long-term debt. These payments and balances of maturing debt issues for the five years subsequent to December 31, 1997 are as follows: Sinking Funds Maturing Debt Issues Year Subsidiaries System Subsidiaries Total (Dollars in thousands) 1998 $7,653 $10,000 $ 9,000 $26,653 1999 7,653 10,000 10,000 27,653 2000 7,653 - - 7,653 2001 9,010 - 3,500 12,510 2002 5,360 - 32,000 37,360 (7) Redeemable Preferred Shares Each series of the System's preferred shares was issued at par value, $100 per share, and is subject to periodic, mandatory sinking fund payments. The System can make additional voluntary redemptions, not exceeding the requi- red redemption, at par, on a non-cumulative basis, on each sinking fund date. <PAGE 50> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Preferred shares may also be called for redemption, in whole or in part, in excess of the required and voluntary sinking fund redemptions. The obligation to make mandatory redemptions is cumulative and the System is not allowed to pay dividends to common shareholders or make optional sinking fund payments if mandatory redemptions are in arrears. Details of redemptions for each series are contained in the following table: Sinking Funds Optional Dividend 1998-2002 Redemption Rate Mandatory Optional Call Prices (Dollars in thousands) Series A 4.80% $120 $120 $102 Series B 8.10 160 160 101 Series C 7.75 540 540 101 Preferred shareholders have no voting rights except in the event that six full quarterly dividends have not been paid. In this circumstance, the preferred shareholders are entitled, voting as a class, to elect two of the nine Trustees of the System. The preference of these shares in involuntary liquidation is equal to par value. The shares are of equal rank and are entitled to cumulative dividends at the annual rate established for each series. No dividend can be declared on any series unless proportionate dividends are concurrently declared on the other outstanding series and in the event that dividend payments are in arrears, the System may not redeem any shares unless all shares of all preferred series are redeemed. (8) Disclosures About Fair Value of Financial Instruments The fair value of certain financial instruments included in the accom- panying Consolidated Balance Sheets as of December 31, 1997 and 1996 are as follows: 1997 1996 Carrying Fair Carrying Fair Value Value Value Value (Dollars in thousands) Long-term debt $390,964 $444,970 $377,218 $417,411 Preferred shares 13,020 14,708 13,840 14,601 The carrying amount of cash and notes payable to banks approximates the fair value because of the short maturity of these financial instruments. The estimated fair value of long-term debt and preferred stock are based on quoted market prices of the same or similar issues or on the current rates offered for debt or preferred shares with the same remaining maturity. The fair values shown above do not purport to represent the amounts at which those obligations would be settled. (9) Lease Obligations System companies lease property, transmission facilities and equipment under agreements, some of which are capital leases. Several subsidiaries renegotiate certain lease agreements annually. These new agreements are for a term of one year and are renewable monthly thereafter. COM/Energy Services Company has agreements in effect for office furniture, computer and transpor- tation equipment. Generally, these agreements require the lessee to pay related taxes, maintenance and other costs of operation. Leases currently in effect contain no provisions which prohibit system companies from entering into future lease agreements or obligations. <PAGE 51> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The following is a breakdown, by major class, of property under capital lease at December 31, 1997 and 1996: 1997 1996 (Dollars in thousands) Transmission facilities $11,801 $12,454 Office furniture, computer equipment and other 1,753 1,500 13,554 13,954 Less: Accumulated amortization 53 77 $13,501 $13,877 Future minimum lease payments, by period and in the aggregate, of capital leases and non cancelable operating leases consisted of the following at December 31, 1997: Capital Operating Leases Leases (Dollars in thousands) 1998 $ 2,603 $11,000 1999 2,456 9,218 2000 2,159 5,012 2001 1,660 3,581 2002 1,598 3,581 Beyond 2002 17,128 11,672 Total future minimum lease payments 27,604 $44,064 Less: Estimated interest element included therein 14,103 Estimated present value of future minimum lease payments $13,501 Total rent expense for all operating leases, except those with terms of a month or less, amounted to $11,181,000 in 1997, $12,922,000 in 1996 and $13,867,000 in 1995. There were no contingent rentals and no sublease rentals for the years 1997, 1996 and 1995. (10) Dividend Restriction At December 31, 1997, approximately $111,729,000 of consolidated retained earnings was restricted against the payment of cash dividends by terms of indentures and note agreements securing long-term debt. (11) Segment Information System companies provide electric, gas and steam services to retail customers in communities located in central, eastern and southeastern Massa- chusetts and, in addition, sell electricity at wholesale to Massachusetts customers. Other operations of the system include the development and operation of rental properties and other activities which do not presently contribute significantly to either revenues or operating income. Operating income of the various industry segments includes income from transactions with affiliates and is exclusive of interest expense, income taxes and equity in earnings of unconsolidated corporate joint ventures. The amount of identifiable assets represented by the system's investment in corporate joint ventures consists principally of a percentage ownership in the assets of four regional electric generating plants and a 3.8% interest in Hydro-Quebec Phase II. <PAGE 52> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 1997 1996 1995 (Dollars in thousands) Revenues from Unaffiliated Customers Electric $ 688,508 $ 649,678 $ 604,980 Gas 333,977 341,867 306,953 Steam and other 19,259 19,360 17,355 Total Revenues $1,041,744 $1,010,905 $ 929,288 Capital Expenditures (including AFUDC) Electric $ 34,524 $ 38,844 $ 61,643 Gas 18,230 11,611 16,198 Other 4,804 2,730 3,659 $ 57,558 $ 53,185 $ 81,500 Operating Income Before Income Taxes Electric $ 84,828 $ 92,374 $ 78,817 Gas 34,918 36,984 36,611 Steam and other (1,056) 3,406 3,689 Total Operating Income Before Income Taxes $ 118,690 $ 132,764 $ 119,117 Identifiable Assets Electric $1,049,094 $1,011,306 $ 982,384 Gas 395,966 388,930 374,615 Steam and other 74,298 58,081 57,269 1,519,358 1,458,317 1,414,268 Intercompany eliminations (48,075) (42,757) (35,140) Investment in corporate joint ventures 13,767 13,395 13,214 Total Identifiable Assets $1,485,050 $1,428,955 $1,392,342 Depreciation Expense Electric $ 41,103 $ 39,977 $ 36,977 Gas 10,482 10,061 9,656 Steam and other 1,820 1,744 1,537 Total Depreciation $ 53,405 $ 51,782 $ 48,170 <PAGE 53> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES PART III. Item 10. Trustees and Executive Officers of the Registrant a. Trustees of the Registrant: Information required by this item is incorporated herein by reference to the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998, pages 3-4. b. Executive Officers of the Registrant: Age at December Name of Officer Position and Business Experience 31, 1997 William G. Poist President, Chief Executive Officer and 64 Trustee of the System and Chairman and Chief Executive Officer of its principal subsidiary companies since January 1, 1992; Vice President of the System and COM/Energy Services Company* effective September 1, 1991; President and Chief Operating Officer of Commonwealth Gas Company* from 1983 to 1991 and Hopkinton LNG Corp.* from 1985 to 1991. Russell D. Wright Vice Chairman and Chief Executive Officer of 51 Utility Operations effective March 1, 1998; President and Chief Operating Officer of Commonwealth Gas Company* effective February 6, 1997 and President and Chief Operating Officer of Cambridge Electric Light Company*, Canal Electric Company*, COM/Energy Steam Company*, and Commonwealth Electric Company* effective March 1, 1993; Financial Vice President and Treasurer of the System and Financial Vice President of its subsidiary companies from 1987 to 1993. Deborah A. McLaughlin President and Chief Operating Officer of 39 Utility Operations effective March 1, 1998; Vice President of Customer Service for Utility Operations from 1997 to 1998; Vice President of Customer Service for Cambridge Electric Light Company*, Canal Electric Company*, COM/Energy Steam Company*, and Commonwealth Electric Company* from 1993 to 1997; Audit Manager for COM/Energy Services Company* from 1987 to 1993. * Subsidiary of the System. <PAGE 54> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES b. Executive officers of the Registrant (Continued): Age at December Name of Officer Position and Business Experience 31, 1997 James D. Rappoli Financial Vice President and Treasurer of 46 the System and its subsidiary companies effective March 1, 1993; Treasurer of System subsidiary companies from 1990 to 1993; Assistant Treasurer of System subsidiary companies from 1989 to 1990. Michael P. Sullivan Vice President, Secretary, and 49 General Counsel of the System and subsidiary companies (effective June 1993); Vice President, Secretary, and General Attorney of the System and subsidiary companies since 1981. John R. Williams Vice President of Corporate Services of 54 COM/Energy Services Company* (effective December 2, 1996); Vice President of Operations at Commonwealth Electric* from 1993 to 1996; Vice President of Human Resources and Communications at COM/Energy Services Company* from 1990 to 1993; Vice President of Corporate Human Resources at COM/Energy Services Company* from 1987 to 1990. * Subsidiary of the System. The term of office for System officers expires May 7, 1998, the date of the next Annual Organizational Meeting. There are no family relationships between any trustee and executive officer and any other trustee or executive of the System. There were no arrangements or understandings between any officer or trustee and any other person pursuant to which he was or is to be selected as an officer, trustee or nominee. There have been no events under any bankruptcy act, no criminal pro- ceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any trustee or executive officer during the past five years. Item 11. Executive Compensation Information required by this item is incorporated herein by reference to the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998, pages 5-9. Item 12. Security Ownership of Certain Beneficial Owners and Management Information required by this item is incorporated herein by reference to the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998, pages 2-4. <PAGE 55> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 13. Certain Relationships and Related Transactions Information required by this item is incorporated herein by reference to the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998, pages 2-4. PART IV. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. Index to Financial Statements Consolidated financial statements and notes thereto of Commonwealth Energy System and Subsidiary Companies, together with the Report of Independent Public Accountants, are filed under Item 8 of this Form 10-K and listed on the Index to Financial Statements (page 31). (a) 2. Index to Financial Statement Schedules Commonwealth Energy System and Subsidiary Companies Filed herewith at page(s) indicated - Report of Independent Public Accountants on Schedules (page 68). Schedule I - Investments in, Equity in Earnings of, and Dividends Re- ceived from Related Parties - Years Ended December 31, 1997, 1996 and 1995 (pages 69-71). Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1997, 1996 and 1995 (page 72). All other schedules have been omitted because they are not applicable, not required or because the required information is included in the financial statements or notes thereto. Subsidiaries not Consolidated and Fifty-Percent or Less Owned Persons Financial statements of 50% or less owned persons accounted for by the equity method have been omitted because they do not, considered individ- ually or in the aggregate, constitute a significant subsidiary. Form 11-K, Annual Reports of Employee Stock Purchases, Savings and Similar Plans Pursuant to Rule 15(d)-21 of the Securities and Exchange Act of 1934, the information, financial statements and exhibits required by Form 11-K with respect to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies will be filed as an amendment to this report under cover of Form 10-K/A no later than April 30, 1998. <PAGE 56> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (a) 3. Exhibits: Notes to Exhibits - a. Unless otherwise designated, the exhibits listed below are incorporated by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses. b. During 1981, New Bedford Gas and Edison Light Company sold its gas business and properties to Commonwealth Gas Company and changed its corporate name to Commonwealth Electric Company. c. The following is a glossary of Commonwealth Energy System and subsid- iary companies' acronyms that are used throughout the following Exhibit Index: CES ...................... Commonwealth Energy System CE ....................... Commonwealth Electric Company CEL ...................... Cambridge Electric Light Company CEC ...................... Canal Electric Company CG ....................... Commonwealth Gas Company NBGEL .................... New Bedford Gas and Edison Light Company HOPCO .................... Hopkinton LNG Corp. Exhibit Index Exhibit 3. Declaration of Trust Commonwealth Energy System (Registrant) 3.1.1 Declaration of Trust of CES dated December 31, 1926, as amended by vote of the shareholders and trustees May 4, 1995 (Exhibit 1 to the CES Form 10-Q (September 1995), File No. 1-7316). Exhibit 4. Instruments defining the rights of security holders, including indentures Commonwealth Energy System (Registrant) Debt Securities - 4.1.1 CES Note Agreement ($40 Million Privately Placed Senior Notes) dated June 28, 1989 (Exhibit 1 to the CES Form 10-Q (September 1989), File No. 1-7316). Cambridge Electric Light Company Indenture of Trust or Supplemental Indenture of Trust - 4.2.1 Original Indenture on Form S-1 (April, 1949) (Exhibit 7(a), File No. 2-7909). 4.2.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2- 7909). <PAGE 57> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 4.2.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2- 7909). 4.2.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No. 2- 7909). Subsidiary Companies of the Registrant 4.2.5 Seventh Supplemental on Form 10-Q (June 1992), (Exhibit 1, File No 2-7909). Canal Electric Company Indenture of Trust and First Mortgage or Supplemental Indenture of Trust and First Mortgage - 4.3.1 Indenture of Trust and First Mortgage with State Street Bank and Trust Company, Trustee, dated October 1, 1968 (Exhibit 4(b) to Form S-1, File No. 2-30057). 4.3.2 First and General Mortgage Indenture with Citibank, N.A., Trustee, dated September 1, 1976 (Exhibit 4(b)2 to Form S-1, File No. 2- 56915). 4.3.3 First Supplemental dated October 1, 1968 with State Street Bank and Trust Company, Trustee, dated September 1, 1976 (Exhibit 4(b)3 to Form S-1, File No. 2-56915). 4.3.4 Third Supplemental dated September 1, 1976 with Citibank, N.A., New York, NY, Trustee, dated December 1, 1990 (Exhibit 3 to 1990 Form 10-K, File No. 2-30057). 4.3.5 Fourth Supplemental dated September 1, 1976 with Citibank, N.A., New York, NY, Trustee, dated December 1, 1990 (Exhibit 4 to 1990 Form 10-K, File No. 2-30057). Commonwealth Gas Company Indenture of Trust or Supplemental Indenture of Trust - 4.4.1 Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No. 2-7820). 4.4.2 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2- 1647). 4.4.3 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No. 2-1647). 4.4.4 Eighteenth Supplemental on Form 10-Q (March 1994) (Exhibit 1, File No. 2-1647). 4.4.5 Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No. 2- 1647). <PAGE 58> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Exhibit 10. Material Contracts 10.1 Power contracts. 10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No. 2-30057). 10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and CEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 1 to the 1991 CEL Form 10-K, File No. 2-7909). 10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the CEL Form 10-Q (June 1988), File No. 2-7909). 10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (Septem- ber 1989), File No. 2-7909). 10.1.3 Power Contract between YAEC and NBGEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to the 1991 CE Form 10-K, File No. 2-7749). 10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE Form 10-Q (June 1988), File No. 2-7749). 10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989), File No. 2-7749). 10.1.4 Power Contract between Connecticut Yankee Atomic Power Company (CYAPC) and CEL dated July 1, 1964 (Exhibit 13-K1 to the System's Form S-1, (April 1967) File No. 2-25597). 10.1.4.1 Additional Power Contract providing for extension on contract term between CYAPC and CEL dated April 30, 1984 (Exhibit 5 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.4.2 Second Supplementary Power Contract providing for decommissioning financing between CYAPC and CEL dated April 30, 1984 (Exhibit 6 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.5 Power contract between Vermont Yankee Nuclear Power Corporation (VYNPC) and CEL dated February 1, 1968 (Exhibit 3 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and Second Amendment dated April 15, 1983 (decommissioning financing) to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1984), File No. 2- 7909). <PAGE 59> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.5.2 Third Amendment dated April 1, 1985 and Fourth Amendment dated June 1, 1985 to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1986), File No. 2-7909). 10.1.5.3 Fifth and Sixth Amendments to 10.1.5 dated February 1, 1968, both as amended May 6, 1988 (Exhibit 1 to the CEL Form 10-Q (June 1988), File No. 2-7909). 10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as amended June 15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No. 2-7909). 10.1.5.5 Additional Power Contract dated February 1, 1984 between CEL and VYNPC providing for decommissioning financing and contract extension (Refiled as Exhibit 1 to CEL 1993 Form 10-K, File No. 2-7909). 10.1.6 Power contract between Maine Yankee Atomic Power Company (MYAPC) and CEL dated May 20, 1968 (Exhibit 5 to the System's Form S-7, File No. 2-38372). 10.1.6.1 First Amendment dated March 1, 1984 (decommissioning financing) and Second Amendment dated January 1, 1984 (supplementary payments) to 10.1.6 (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit 1 to the CEL Form 10-Q (September 1984), File No. 2-7909). 10.1.7 Agreement between NBGEL and Boston Edison Company (BECO) for the purchase of electricity from BECO's Pilgrim Unit No. 1 dated Au- gust 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.7.1 Service Agreement between NBGEL and BECO for purchase of stand-by power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.7.2 System Power Sales Agreement by and between CE and BECO dated July 12, 1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No. 2-7749). 10.1.7.3 Power Exchange Agreement by and between BECO and CE dated December 1, 1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.7.4 Service Agreement for Non-Firm Transmission Service between BECO and CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.8 Agreement for Joint-Ownership, Construction and Operation of New Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to the NBGEL Form S-1 dated October 1973, File No. 2-49013 and as amended below: 10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974 and January 31, 1975, respectively (Exhibit 13(m) to the NBGEL Form S-1 (November 7, 1975), File No. 2-54995). 10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979 and December 15, 1979, respectively (Refiled as Exhibit 1 to the CEC 1989 Form 10-K, File No. 2-30057). <PAGE 60> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as amended May 16, 1980, December 31, 1980 and June 1, 1982, respectively (Filed as Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended April 27, 1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10- Q (June 1984), File No. 2-30057). 10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985 (Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2-30057). 10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986 (Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2-30057). 10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2-30057). 10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19, 1986 (Exhib- it 1 to the CEC 1986 Form 10-K, File No. 2-30057). 10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12, 1987 (Exhibit 1 to the CEC 1987 Form 10-K, File No. 2-30057). 10.1.8.10 Settlement Agreement and Twenty-Second Amendment to 10.1.8, both dated January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.9 Purchase and Sale Agreement together with an implementing Addendum dated December 31, 1981, between CE and CEC, for the purchase and sale of the CE 3.52% joint-ownership interest in the Seabrook units, dated January 2, 1981 (Refiled as Exhibit 4 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.10 Agreement to transfer ownership, construction and operational interest in the Seabrook Units 1 and 2 from CE to CEC dated January 2, 1981 (Refiled as Exhibit 3 to the 1991 CE Form 10-K, File No. 2- 7749). 10.1.11 Power Contract, as amended to February 28, 1990, superseding the Power Contract dated September 1, 1986 and amendment dated June 1, 1988, between CEC (seller) and CE and CEL (purchasers) for seller's entire share of the Net Unit Capability of Seabrook 1 and related energy (Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2- 30057). 10.1.12 Agreement between NBGEL and Central Maine Power Company (CMP), for the joint-ownership, construction and operation of William F. Wyman Unit No. 4 dated November 1, 1974 together with Amendment No. 1 dated June 30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No. 2-54955). <PAGE 61> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.12.1 Amendments No. 2 and 3 to 10.1.12 as amended August 16, 1976 and December 31, 1978 (Exhibit 5(a) 14 to the System's Form S-16 (June 1979), File No. 2-64731). 10.1.13 Agreement between the registrant and Montaup Electric Company (MEC) for use of common facilities at Canal Units I and II and for allocation of related costs, executed October 14, 1975 (Exhibit 1 to the CEC 1985 Form 10-K, File No. 2-30057). 10.1.13.1 Agreement between the registrant and MEC for joint-ownership of Canal Unit II, executed October 14, 1975 (Exhibit 2 to the CEC 1985 Form 10-K, File No. 2-30057). 10.1.13.2 Agreement between the registrant and MEC for lease relating to Canal Unit II, executed October 14, 1975 (Exhibit 3 to the CEC 1985 Form 10-K, File No. 2-30057). 10.1.14 Contract between CEC and NBGEL and CEL, affiliated companies, for the sale of specified amounts of electricity from Canal Unit 2 dated January 12, 1976 (Exhibit 7 to the System's 1985 Form 10-K, File No. 1-7316). 10.1.15 Capacity Acquisition Agreement between CEC,CEL and CE dated Septem- ber 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File No. 2-30057). 10.1.15.1 Amendment to 10.1.15 as amended and restated June 1, 1993, hence- forth referred to as the Capacity Acquisition and Disposition Agreement, whereby Canal Electric Company, as agent, in addition to acquiring power may also sell bulk electric power which Cambridge Electric Light Company and/or Commonwealth Electric Company owns or otherwise has the right to sell (Exhibit 1 to Canal Electric's Form 10-Q (September 1993), File No. 2-30057). 10.1.16 Phase 1 Vermont Transmission Line Support Agreement and Amendment No. 1 thereto between Vermont Electric Transmission Company, Inc. and certain other New England utilities, dated December 1, 1981 and June 1, 1982, respectively (Exhibits 5 and 6 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.16.1 Amendment No. 2 to 10.1.16 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.16.2 Amendment No. 3 to 10.1.16 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749). 10.1.17 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for the purchase of available hydro-electric energy produced by a facility located in Ware, Massachusetts, dated September 1, 1983 (Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749). <PAGE 62> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.18 Power Purchase Agreement between Corporation Investments, Inc. (CI), and CE for the purchase of available hydro-electric energy produced by a facility located in Lowell, Massachusetts, dated January 10, 1983 (Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No. 2-7749). 10.1.18.1 Amendment to 10.1.18 between CI and Boott Hydropower, Inc., an assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.19 Phase 1 Terminal Facility Support Agreement dated December 1, 1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November 1, 1982, between New England Electric Transmission Corpo- ration (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.19.1 Amendment No. 3 to 10.1.19 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749). 10.1.20 Preliminary Quebec Interconnection Support Agreement dated May 1, 1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amend- ment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.21 Agreement with Respect to Use of Quebec Interconnection dated December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated November 1, 1982 among certain NEPOOL utilities (Exhib- it 3 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.21.1 Amendatory Agreement No. 3 to 10.1.21 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.22 Phase I New Hampshire Transmission Line Support Agreement between NEET and certain other New England Utilities dated December 1, 1981 (Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.23 Agreement, dated September 1, 1985, with Respect To Amendment of Agreement With Respect To Use Of Quebec Interconnection, dated December 1, 1981, among certain NEPOOL utilities to include Phase II facilities in the definition of "Project" (Exhibit 1 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.24 Agreement to Preliminary Quebec Interconnection Support Agreement - Phase II among Public Service Company of New Hampshire (PSNH), New England Power Co. (NEP), BECO and CEC whereby PSNH assigns a portion of its interests under the original Agreement to the other three parties, dated October 1, 1987 (Exhibit 2 to the CEC 1987 Form 10-K, File No. 2-30057). <PAGE 63> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.25 Preliminary Quebec Interconnection Support Agreement - Phase II among certain New England electric utilities dated June 1, 1984 (Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.25.1 First, Second and Third Amendments to 10.1.25 as amended March 1, 1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.25.2 Fifth, Sixth and Seventh Amendments to 10.1.25 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhib- it 1 to the CEC Form 10-Q (June 1988), File No. 2-30057). 10.1.25.3 Fourth and Eighth Amendments to 10.1.25 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057). 10.1.25.4 Ninth and Tenth Amendments to 10.1.25 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.25.5 Eleventh Amendment to 10.1.25 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057). 10.1.25.6 Twelfth Amendment to 10.1.25 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057). 10.1.26 Phase II Equity Funding Agreement for New England Hydro-Transmis- sion Electric Company, Inc. (New England Hydro) (Massachusetts), dated June 1, 1985, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.27 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro and certain NEPOOL utili- ties (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2- 30057). 10.1.28 Phase II New Hampshire Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 8 dated May 1, 1986 through January 1, 1990, respectively, between New England Hydro-Transmission Corporation (New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.29 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June 1, 1985, between New Hampshire Hydro and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.29.1 Amendment No. 1 to 10.1.29 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057). <PAGE 64> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.29.2 Amendment No. 2 to 10.1.29 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.30 Phase II New England Power AC Facilities Support Agreement, dated June 1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.30.1 Amendments Nos. 1 and 2 to 10.1.30 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.30.2 Amendments Nos. 3 and 4 to 10.1.30 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.31 Agreement Authorizing Execution of Phase II Firm Energy Contract, dated September 1, 1985, among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro-Quebec (Exhib- it 8 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.32 Agreements by and between Swift River Company and CE for the purchase of available hydro-electric energy to be produced by units located in Chicopee and North Willbraham, Massachusetts, both dated September 1, 1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.33 Power Purchase Agreement by and between SEMASS Partnership, as seller, to construct, operate and own a solid waste disposal facility at its site in Rochester, Massachusetts and CE, as buyer of electric energy and capacity, dated September 8, 1981 (Exhibit 17 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.33.1 Power Sales Agreement to 10.1.33 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749). 10.1.33.2 Amendment to 10.1.33 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated March 14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2-7749). 10.1.33.3 Amendment to 10.1.33 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated May 24, 1991 (Exhibit 1 to CE Form 10-Q (June 1991), File No. 2-7749). 10.1.34 Power Sale Agreement by and between CE (buyer) and Northeast Energy Associated, Ltd. (NEA) (seller) of electric energy and capacity, dated November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March 1987), File No. 2-7749). 10.1.34.1 First Amendment to 10.1.34 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749). <PAGE 65> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.34.2 Second Amendment to 10.1.34 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.34.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for the purchase of 21 MW of electricity (Exhibit 2 to the CE Form 10-Q (September 1988), File No. 2-7749). 10.1.34.4 Amendment to 10.1.34.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.35 Power Purchase Agreement and First Amendment, dated September 5, 1989 and August 3, 1990, respectively, by and between Commonwealth Electric (buyer) and Dartmouth Power Associates Limited Partnership (seller), whereby buyer will purchase all of the energy (67.6 MW) produced by a single gas turbine unit (Exhibit 1 to the CE Form 10- Q (June 1992), File No. 2-7749). 10.1.35.1 Second Amendment, dated June 23, 1994, to 10.1.50 by and between Commonwealth Electric Company and Dartmouth Power Associates, L.P. dated September 5, 1989 (Exhibit 4 to the CE Form 10-Q (June 1995), File No. 2-7749). 10.1.36 Power Purchase Agreement by and between Masspower (seller) and Com- monwealth Electric Company (buyer) for a 11.11% entitlement to the electric capacity and related energy of a 240 MW gas-fired cogen- eration facility, dated February 14, 1992 (Exhibit 1 to Common- wealth Electric's Form 10-Q (September 1993), File No. 2-7749). 10.1.37 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller) and Commonwealth Electric Company (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 2 to Commonwealth Electric's Form 10-Q (September 1993), File No. 2- 7749). 10.1.37.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., Cambridge Electric Light Company, Commonwealth Electric Company and New England Power Company, dated July 2, 1993 (Exhibit 3 to Common- wealth Electric's Form 10-Q (September 1993), File No 2-7749). 10.1.37.2 Power Sale Agreement by and between Altresco Pittsfield, L. P. (seller) and Cambridge Electric Light Company (Cambridge Electric) (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 1 to Cambridge Electric's Form 10-Q (September 1993), File No. 2-7909). 10.1.37.3 First Amendment, dated November 7, 1994, to 10.1.37 by and between Commonwealth Electric Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed as Exhibit 3 to Commonwealth Electric Company's Form 10-Q (June 1995), File 2-7749). <PAGE 66> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.37.4 First Amendment, dated November 7, 1994, to 10.1.37.2 by and between Cambridge Electric Light Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed as Exhibit 2 to Cambridge Electric Light Company's Form 10-Q (June 1995), File 2-7909). 10.2 Natural gas purchase contracts. 10.2.1 Transportation Agreement between CNG and CG to provide for trans- portation of natural gas on a daily basis from Steuben Gas Storage Company to TGP (Exhibit 10 to the CG 1991 Form 10-K, File No. 2- 1647). 10.3 Other agreements. 10.3.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 1 to CES Form 10-Q (September 1993), File No. 1-7316). 10.3.2 Employees Savings Plan of Commonwealth Energy System and Subsid- iary Companies as amended and restated January 1, 1993.(Exhibit 2 to CES Form 10-Q (September 1993), File No. 1-7316). 10.3.2.1 First Amendment to 10.3.2, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), File No. 1-7316). 10.3.2.2 Second Amendment to 10.3.2, effective April 1, 1996 (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316). 10.3.2.3 Third Amendment to 10.3.2, effective January 1, 1997 (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316). 10.3.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corpora- tion, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731). 10.3.3.1 Thirteenth Amendment to 10.3.3 as amended September 1, 1981 (Re- filed as Exhibit 3 to the System's 1991 Form 10-K, File No. 1-7316). 10.3.3.2 Fourteenth through Twentieth Amendments to 10.3.3 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316). 10.3.3.3 Twenty-first Amendment to 10.3.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316). 10.3.3.4 Twenty-second Amendment to 10.3.3 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316). <PAGE 67> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.3.3.5 Twenty-third Amendment to 10.3.3 as amended to April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316). 10.3.3.6 Twenty-fourth Amendment to 10.3.3 as amended March 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.3.3.7 Twenty-fifth Amendment to 10.3.3. as amended to May 1, 1988 (Exhib- it 1 to the CES Form 10-Q (March 1988), File No. 1-7316). 10.3.3.8 Twenty-sixth Agreement to 10.3.3 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.3.3.9 Twenty-seventh Agreement to 10.3.3 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316). 10.3.3.10 Twenty-eighth Agreement to 10.3.3 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316). 10.3.3.11 Twenty-ninth Agreement to 10.3.3 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316). 10.3.4 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as initial lender) covering the unconditional guarantee of a portion of the payment obligations of Maine Yankee Atomic Power Company under a loan agreement and note initially between Maine Yankee and MYA Fuel Company (Exhibit 3 to the CEL Form 10-K for 1985, File No. 2-7909). Exhibit 21. Subsidiaries of the Registrant Filed herewith as Exhibit 1 is a list of subsidiaries of Common- wealth Energy System, all of which are wholly-owned, as of Decem- ber 31, 1997. Exhibit 22. Published Report Regarding Matters Submitted to Vote of Security Holders. Filed herewith as Exhibit 2 is the Notice of 1998 Annual Meeting and Proxy Statement dated March 30, 1998. Exhibit 27. Financial Data Schedule Filed herewith as Exhibit 3 is the Financial Data Schedule for the twelve months ended December 31, 1997. (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended December 31, 1997. <PAGE 68> REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Trustees of Commonwealth Energy System: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements of Commonwealth Energy System included in this Form 10-K and have issued our report thereon dated February 19, 1998 (except with respect to certain matters discussed in Note 2, as to which the date is March 2, 1998). Our audits were made for the purpose of forming an opinion on those consolidated financial statements taken as a whole. The schedules listed in Part IV, Item 14 of this Form 10-K are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Boston, Massachusetts February 19, 1998. <PAGE 69> SCHEDULE I COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1997 (Dollars in Thousands) Balance at Balance at Beginning of Year Additions Deductions End of Year Notes Number Equity Number Receive- of in Other Distribution Other of able Shares Investment Earnings (A) of Earnings (B) Shares Investment (C) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Co. 346,600 $ 45,851 $ 5,216 $ - $ 2,842 $ - 346,600 $ 48,225 $ 7,500 COM/Energy Steam Co. 25,500 3,194 1,265 - 951 - 25,500 3,508 375 Canal Electric Co. 1,523,200 99,021 14,828 - 14,318 - 1,523,200 99,531 - Commonwealth Gas Co. 2,857,000 110,020 15,443 - 9,428 - 2,857,000 116,035 - Darvel Realty Trust 26 1,001 52 - - - 26 1,053 - COM/Energy Freetown Rlty. 1 5,031 (347) - - - 1 4,684 1,730 COM/Energy Research Park Rlty. 1 877 582 - 528 - 1 931 - COM/Energy Cambridge Rlty. 1 43 (5) - - - 1 38 - COM/Energy Acushnet Rlty. 1 694 62 - 55 - 1 701 - COM/Energy Services Co. 3,250 262 22 - - - 3,250 284 - Commonwealth Electric Co. 2,043,972 175,545 16,923 - 12,264 - 2,043,972 180,204 - Hopkinton LNG Corp. 5,000 3,881 549 - 548 - 5,000 3,882 650 Advanced Energy Systems, Inc. - - (904) 1,921 - - 100 1,017 - COM/Energy Resources, Inc. - - (60) 101 - - 100 41 - COM/Energy Marketing, Inc. - - (758) 1,200 - - 100 442 - COM/Energy Technologies, Inc. - - (916) 3,300 - - 100 2,384 - $445,420 $51,952 $6,522 $40,934 $ - $462,960 $ 9,795 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $10,046 $ 1,045 - $ 723 $ - 52,454 $ 10,368 Hydro-Quebec Phase II 137,329 3,321 233 - 248 231 127,034 3,075 Other Investments - 28 - 296 - - - 324 <FN> $ 13,395 $ 1,278 296 $ 971 $231 $ 13,767 NOTES: (A) Additional investment. (B) In 1997, New England Hydro-Transmission Company, Inc. repurchased 7.5% (10.249.2 shares) of its outstanding shares. Canal Electric Company received proceeds of $145,539 ($14.20 per share) and has included this amount with dividends. Also in 1997, New England Hydro-Transmission Corporation repurchased 6.85% (46.124 shares) of its outstanding shares. Canal Electric Company received proceeds of $85,207 (41,847.46 per share) and has included this amount with dividends. (C) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. <PAGE 70> SCHEDULE I COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1996 (Dollars in Thousands) Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Distribution Other of Receivable Shares Investment Earnings of Earnings (B) Shares Investment (A) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 346,600 $ 44,179 $ 5,120 $ 3,448 $ - 346,600 $ 45,851 $ 4,665 COM/Energy Steam Company 25,500 3,539 1,583 1,928 - 25,500 3,194 2,155 Canal Electric Company 1,523,200 98,471 16,574 16,024 - 1,523,200 99,021 5,620 Commonwealth Gas Company 2,857,000 109,659 16,789 16,428 - 2,857,000 110,020 5,495 Darvel Realty Trust 26 1,055 75 129 - 26 1,001 - COM/Energy Freetown Realty 1 5,477 (446) - - 1 5,031 1,305 COM/Energy Research Park Realty 1 739 461 323 - 1 877 - COM/Energy Cambridge Realty 1 48 (5) - - 1 43 - COM/Energy Acushnet Realty 1 575 119 - - 1 694 - COM/Energy Services Company 3,250 337 (27) 48 - 3,250 262 - Commonwealth Electric Company 2,043,972 168,919 19,605 12,979 - 2,043,972 175,545 2,240 Hopkinton LNG Corp. 5,000 3,893 548 560 - 5,000 3,881 1,015 $436,891 $60,396 $51,867 $ - $445,420 $22,495 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $ 9,814 $ 1,059 $ 827 $ - 52,454 $ 10,046 Hydro-Quebec Phase II 137,391 3,372 498 436 113 137,329 3,321 Other Investments - 28 - - - - 28 $ 13,214 $ 1,557 $ 1,263 $113 $ 13,395 <FN> NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. (B) In 1996, New England Hydro-Transmission Corporation repurchased 6.52% of their outstanding shares at $1,831.30 per share. Canal Electric Company received $112,616 for the repurchase of 61.495 shares, and has included this amount with dividends. <PAGE 71> SCHEDULE I COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1995 (Dollars in Thousands) Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Distribution Other of Receivable Shares Investment Earnings of Earnings (B) Shares Investment (A) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 346,600 $ 43,784 $ 5,438 $ 5,043 $- 346,600 $ 44,179 $ 2,425 COM/Energy Steam Company 25,500 4,110 2,093 2,664 - 25,500 3,539 500 Canal Electric Company 1,523,200 98,048 14,132 13,709 - 1,523,200 98,471 555 Commonwealth Gas Company 2,857,000 106,001 16,229 12,571 - 2,857,000 109,659 1,425 Darvel Realty Trust 26 870 185 - - 26 1,055 - COM/Energy Freetown Realty 1 5,833 (356) - - 1 5,477 1,085 COM/Energy Research Park Realty 1 886 239 386 - 1 739 - COM/Energy Cambridge Realty 1 57 (9) - - 1 48 - COM/Energy Acushnet Realty 1 524 67 16 - 1 575 - COM/Energy Services Company 3,250 337 49 49 - 3,250 337 - Commonwealth Electric Company 2,043,972 163,561 15,169 9,811 - 2,043,972 168,919 - Hopkinton LNG Corp. 5,000 3,893 548 548 - 5,000 3,893 - $427,904 $53,784 $44,797 $- $436,891 $6,610 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $ 9,818 $ 1,093 $ 1,097 $- 52,454 $ 9,814 Hydro-Quebec Phase II 137,442 3,802 540 876 94 137,391 3,372 Other Investments - 28 - - - - 28 $ 13,648 $ 1,633 $ 1,973 $94 $ 13,214 <FN> NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. (B) In 1995, New England Hydro-Transmission Corporation repurchased 6.52% of their outstanding shares at $1,834.62 per share. Canal Electric Company received $94,017 for the repurchase of 51.246 shares, and has included this amount with dividends. <PAGE 72> SCHEDULE II COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (Dollars in Thousands) Additions Balance at Provision Deductions Balance Beginning Charged to Accounts at End Description of Year Operations Recoveries Written Off of Year Year Ended December 31, 1997 Allowance for Doubtful Accounts $8,324 $8,638 $2,085 $ 9,639 $9,408 Year Ended December 31, 1996 Allowance for Doubtful Accounts $8,040 $7,152 $1,866 $ 8,734 $8,324 Year Ended December 31, 1995 Allowance for Doubtful Accounts $7,956 $8,089 $2,180 $10,185 $8,040 <PAGE 73> COMMONWEALTH ENERGY SYSTEM FORM 10-K DECEMBER 31, 1997 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. COMMONWEALTH ENERGY SYSTEM (Registrant) By: WILLIAM G. POIST William G. Poist, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. Principal Executive Officer: WILLIAM G. POIST March 26, 1998 William G. Poist, President and Chief Executive Officer Principal Financial and Accounting Officer: JAMES D. RAPPOLI March 26, 1998 James D. Rappoli, Financial Vice President and Treasurer A majority of the Board of Trustees: SHELDON A. BUCKLER March 26, 1998 Sheldon A. Buckler, Chairman of the Board KEVIN C. BRYANT March 26, 1998 Kevin C. Bryant, Trustee PETER H. CRESSY March 26, 1998 Peter H. Cressy, Trustee B. L. FRANCIS March 26, 1998 Betty L. Francis, Trustee FRANKLIN M. HUNDLEY March 26, 1998 Franklin M. Hundley, Trustee <PAGE 74> COMMONWEALTH ENERGY SYSTEM FORM 10-K DECEMBER 31, 1997 SIGNATURES (Continued) WILLIAM J. O'BRIEN March 26, 1998 William J. O'Brien, Trustee WILLIAM G. POIST March 26, 1998 William G. Poist, Trustee MICHAEL C. RUETTGERS March 26, 1998 Michael C. Ruettgers, Trustee G. L. WILSON March 26, 1998 Gerald L. Wilson, Trustee <PAGE 75> CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports included in this Form 10-K into the System's previously filed Registration Statements on Form S-8 File No. 33-57467 and on Form S-3 File No. 33-55593. It should be noted that we have not audited any financial statements of the System subsequent to December 31, 1997 or per- formed any audit procedures subsequent to the date of our report. ARTHUR ANDERSEN LLP Boston, Massachusetts March 31, 1998.