<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 [FEE REQUIRED] For the fiscal year ended December 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] 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 Stock 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 17, 1997: $473,652,872 Common Shares outstanding at March 17, 1997: 21,529,676 shares Document Incorporated by Reference Part in Form 10-K Notice of 1997 Annual Meeting and Proxy Statement, dated March 28, 1997 (pages as specified herein) Part III List of Exhibits begins on page 53 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.......................................... 9 Rates, Regulation and Legislation................... 10 Competition......................................... 14 Segment Information................................. 15 Environmental Matters............................... 15 Construction and Financing.......................... 15 Employees........................................... 15 Item 2. Properties............................................. 16 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............ 27 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 27 PART III Item 10. Trustees and Executive Officers of the Registrant...... 50 Item 11. Executive Compensation................................. 51 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 51 Item 13. Certain Relationships and Related Transactions......... 52 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................................ 52 Signatures........................................................ 76 <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 two new subsidiaries that are pursuing energy- related business opportunities. Subsidiaries of the System have common executive and financial management and 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. Two new subsidiaries, COM/Energy Enterprises, Inc. and COM/Energy Resources, 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 566 MW, and Canal Unit 2, a steam <PAGE 4> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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 575.8 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 316,000 year-round and 46,900 seasonal customers in 41 communities in eastern 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. 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 234,000 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, rubber products, textiles, wire and other fastening devices, abrasives and grinding wheels, candy, copper and alloys, and chemicals. Among customers served is a major educational institution, Harvard University (Harvard). In March 1994, Cambridge Electric was successful in negotiating a seven-year service agreement with Harvard whose sales in 1996, 1995 and 1994 accounted for approximately 2.0%, 2.1% and 1.6%, respectively, of the system's total unit sales. 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 Public Utilities (DPU). System companies own generating facilities with a net capability at the time of peak load totaling 1,029.8 MW including 566 MW provided by Canal Unit 1, of which three-quarters (424.5 MW) is sold to neighboring utilities under long-term contracts, and 287.9 MW provided by Canal Unit 2. Another 126.3 MW is provided by various smaller system units. Of the 555.7 MW available to the <PAGE 5> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES system, 63.3 MW are used principally for peaking purposes. A 3.52% ownership interest in the Seabrook 1 nuclear power plant provides 40.8 MW of capability to the system and Central Maine Power Company's 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 204.7 MW. The system also receives 67 MW from a waste-to-energy plant and has entitlements totaling 23.8 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 DPU 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. The system anticipates providing for future peak load plus reserve requirements through existing system generation, including purchasing available capacity from neighboring utilities, non-utility generators, power marketers and power brokers. The system also has available 115.6 MW from three 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: Maine Vermont Yankee Yankee Pilgrim Year of Initial Operation 1972 1972 1972 Contract Expiration Date 2008 2012 2012 Equity Ownership (%) 4.00 2.50 - Plant Entitlement (%) 3.59 2.25 11.0 Plant Capability (MW) 870.0 496.0 664.7 System Entitlement (MW) 31.2 11.2 73.2 In July 1996, Connecticut Yankee Atomic Power Company (Connecticut Yankee), which operates the Connecticut Yankee nuclear power plant, took the unit out of service in connection with certain safety-related issues and refueling. On December 4, 1996, the plant's Board of Directors, following an economic evaluation of continuing to operate the plant over the remaining ten years of its current license life compared to closing the plant and incurring replacement power for the same period, voted to permanently shutdown the plant. In 1992, Yankee Atomic Electric Company (Yankee Atomic) permanently <PAGE 6> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES discontinued power operation and began decommissioning the Yankee Nuclear Power Station located in Rowe, Massachusetts. For additional information, refer to Note 4(e) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. One of the operating nuclear generating facilities, located in Wiscasset, Maine and operated by Maine Yankee Atomic Power Company (Maine Yankee), experienced two outages due to design and regulatory issues during 1996. On July 20, 1996 the unit came off line to address a design issue on the primary component cooling system. The unit remained off-line until September 2, 1996 to also address issues related to compliance with the Nuclear Regulatory Commissions (NRC) General Letter 96-01 that addresses surveillance testing of safety system components. The second outage for Maine Yankee began on December 5, 1996 to correct technical issues associated with a Confirmatory Action Letter issued by the NRC. Maine Yankee used this outage as an opportunity to breach the reactor and identify the specific fuel assemblies which were detected leaking earlier in the operating cycle. They identified eight assemblies with a total of seventy-five fuel rods leaking, and found the most recent load of fuel unacceptable for continued operation of the plant. Additional cable separation issues were also identified and the NRC has expanded the requirements of the Confirmatory Action Letter that Maine Yankee must meet prior to restart. The restart date of the unit has not yet been determined. Cambridge Electric, Canal and Commonwealth Electric, together with other electric utility companies in the New England area, are members of NEPOOL, which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England. NEPOOL 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. NEPOOL, on behalf of its members entered into an Interconnection Agree- ment 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 NEPOOL 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. NEPOOL 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 $12.5 million at December 31, 1996. In addition, Canal has an equity interest in Phase II which amounted to $3.3 million in 1996 and $3.4 million in 1995. <PAGE 7> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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 NEPOOL participants in planning future additions are determined by NEPOOL 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. 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 4(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 Cam- bridge Electric and Commonwealth Electric. For additional information concerning Seabrook 1, refer to Note 4(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 1996, approximately 21% was generated using imported residual oil and approximately 38% was generated using natural gas. Effective October 1, 1996, Canal executed a fifteen-month contract with Enron Liquid Fuels, Inc. (Enron) 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 35%) to be met by spot purchases or by Enron at the discretion of Canal. Through December 31, 1996, 17.6% of Canal's total requirements have been met by lower-cost, spot purchases resulting in savings to its customers. 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. <PAGE 8> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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 1996, ESCO Massachusetts, Inc. maintained an average daily inventory of 421,000 barrels of fuel oil, which represents approximately thirty-four 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. During September and October 1996, Unit 2 burned approximately 1.6 million MMBTU's of natural gas, saving customers approximately $1.1 million. Natural gas was not burned at Unit 2 during November and December as the cost of residual fuel oil was more economical during that period. Canal anticipates that its dual fuel capability will result in future savings as the least expensive fuel is utilized. Canal has entered into a contract with Duke/Louis Dreyfus, L.L.C. to provide 100% of the natural gas requirements of Unit 2 through December 31, 1997. (b) Nuclear Fuel Supply and Disposal Approximately 24% of the system's total energy requirement for 1996 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 high level wastes and 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 all of 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 temporary storage 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 all spent fuel expected to be accumulated through at least the year 2010. <PAGE 9> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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 ranging from less than one year to three or more years. The vendors vary from 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 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 DPU and hearings were completed in April 1993. The DPU approved the ANE gas supply contract in November 1995. Commonwealth Gas is 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, 1996, there were 66 customers using this transportation service, accounting for 6,192 BBTU or approximately 11.8% of system throughput. Hopkinton LNG Facility A portion of Commonwealth Gas' supply 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 and 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 <PAGE 10> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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 and Regulation and Legislation Certain of the System's utility subsidiaries operate under the jurisdiction of the DPU, 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. However, on August 16, 1995, the DPU issued an order calling for the restructuring of the electric utility industry in Massachusetts. For further information pertaining to the effects of this restructuring order on the System's utility companies' rates, regulation and legislation, refer to the "Electric Industry Restructuring" section of Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 of this report. (a) 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 under 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. <PAGE 11> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES On March 29, 1995, the FERC issued two notices of proposed rulemaking concerning open access transmission (RM95-8-000) and stranded costs (RM94-7- 001). 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 a Section 206 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 December 31, 1996, Cambridge Electric and Commonwealth Electric filed market-based power sales tariffs with the FERC which 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 authorization to participate as brokers in the sale and purchase of electricity. (b) Automatic Adjustment Clauses Electric Both Commonwealth Electric and Cambridge Electric have Fuel Charge rate schedules which generally allow for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. These schedules require a quarterly computation and DPU 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 do not match actual costs for that period, an appropriate adjustment is reflected in the calculation of the next subsequent calendar quarter decimal. Cambridge Electric and Commonwealth Electric collect a portion of capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The recovery mechanism for these costs uses a per kilowatthour (KWH) factor that is calculated using historical (test- period) capacity costs and unit sales. This factor is then applied to current monthly KWH sales. When current period capacity costs and/or unit sales vary from test-period levels, Cambridge Electric and Commonwealth Electric have experienced a revenue excess or shortfall that has had a significant impact on net income. However, as part of the settlement agreements approved by the DPU in May 1995, Cambridge Electric and Commonwealth Electric can now defer these <PAGE 12> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES costs (within certain limits) which neutralizes their sometimes volatile effect on net income. Both Commonwealth Electric and Cambridge Electric have separately stated Conservation Charge rate schedules which allow for current recovery, from retail customers, of conservation and load management costs. Gas Commonwealth Gas has a Standard Seasonal Cost of Gas Adjustment rate schedule (CGA) which provides for the recovery, from firm customers, of purchased gas and conservation and load management costs not collected through base rates. These schedules, which require DPU approval, are estimated semi- annually and include credits for gas pipeline refunds and profit margins applicable to interruptible and other non-firm 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 DPU. To approve this long-range forecast and resource plan, the DPU 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 DPU on December 20, 1996. (c) Gas Demand and Transition Costs Commonwealth Gas is obligated, as part of its pipeline transportation and supplier gas purchase contracts, to pay monthly demand charges which are recovered through the CGA. As a direct result of implementation of 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 DPU. (d) Retail Choice Pilot Program On September 3, 1996, the DPU approved Commonwealth Electric's retail choice pilot program. The program is comprised of two components: under Subscription A, eligible customers have the opportunity to buy their power <PAGE 13> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES from a supplier other than Commonwealth Electric (an alternative supplier); under Subscription B, eligible customers continue to buy their power from Commonwealth Electric, but at prices posted by Commonwealth Electric one day ahead. All participating customers will pay Commonwealth Electric a customer charge, transmission and distribution charges, and an access charge. The program is available to Commonwealth Electric's 18 commercial and industrial customers taking service under one of Commonwealth Electric's economic development rates. Subscription A has been filled by 5 customers having an aggregate load of approximately 15 megawatts. However, because this portion of the program is temporarily suspended pending re-bidding of the power supply, Commonwealth Electric is assisting these customers to qualify them on Subscription B. The remaining customers are eligible to participate in Subscription B. The program is designed to allow a limited number of customers the opportunity to possibly reduce their electric bills while Commonwealth Electric learns more about real-time pricing and the administrative require- ments associated with open-market competition. Through the program, Commonwealth Electric expects to develop internal procedures for billing and allocating the costs for providing an alternative supply to its retail customers, and to develop methods for educating customers regarding retail choice. The program is scheduled to continue until December 31, 1997. Those customers that find that their selection is not right for them will be able to return to Commonwealth Electric service at their prior rate. (e) Customer Transition Charge In September 1995, the DPU 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 will protect remaining customers from paying certain costs, often referred to as stranded investment costs, that were incurred in the event that Cambridge Electric's largest customers discontinue full service, yet still remain connected for back-up and other services. These costs include 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 DPU restructuring order which endorsed, in principle, the recovery of stranded investment costs. Through the CTC, Cambridge Electric will initially recover 75% of net stranded investment 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. Cambridge Electric is encouraged by the DPU's position on recovery of stranded investment costs and expects to address recovery of the remaining 25% in its restructuring filing. <PAGE 14> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The Massachusetts Institute of Technology (MIT) appealed the DPU's deci- sion to the Massachusetts Supreme Judicial Court (the SJC). Cambridge Electric is an intervenor in this proceeding. While no schedule is set for a decision from the SJC, Cambridge Electric anticipates a decision sometime in the second quarter of 1997. At this time, Cambridge Electric is unable to predict the outcome of this proceeding. In addition, on February 29, 1996, the FERC denied a petition filed in January 1996 by MIT, which sought relief from paying the CTC, on the premise that stranded costs are to be resolved at the state level. Cambridge Electric believes that the FERC's action will be an important factor that the SJC will consider in the appeal process. In a previous legal proceeding, 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 DPU and dismissed the May 1996 complaint filed by MIT. In its complaint, MIT had alleged that the CTC approved by the DPU and implemented by Cambridge Electric violated the Public Utility Regulatory Policies Act of 1978 (PURPA). In dismissing MIT's complaint, the District Court found that MIT's complaint involved an allegation relating to the DPU's application of PURPA, which is not within the District Court's jurisdiction. Competition The system continues to develop and implement strategies that deal with the increasingly competitive environment facing the electric business. The inherently high cost of providing energy services in the Northeast has placed the region at a competitive disadvantage as more customers begin to explore alternative energy supply options. Pursuant to its aforementioned Model Rules, the DPU is proposing to implement programs under which utility and non- utility generators can sell electricity to customers of other utilities without regard to previously closed franchise service areas. In 1994, the DPU began an inquiry into incentive ratemaking. The system's actions in response to the new competitive challenges have been well received by regulators, business groups and customers. The system has developed and will continue to develop innovative pricing mechanisms designed to retain existing customers, add new retail and wholesale customers and expand beyond current markets. For a more detailed discussion of the DPU's restructuring order, refer to the "Electric 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. COM/Electric and COM/Gas will continue to operate under their existing company names. The consolidation process for these companies will involve the merging of similar functions and activities to eliminate duplication in order to create the most efficient and cost-effective operation possible and will ultimately result in the reduction of up to 300 positions (15%) system-wide. Through prior work force reductions and attrition, the system has reduced its full-time work force approximately 23.1% since 1990. Also, the introduction of advanced technologies in the <PAGE 15> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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, absent a major shift in regulation at the state level, believes its current business strategy 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 development and management of new real estate ventures, the operation of rental properties and other investment activities and the pursuit of new business opportunities which do not presently contribute significantly to either revenues or operating income. Reference is made to additional industry segment information in Note 12 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 $68.8 million from 1997 through 2001 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. 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 4(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 5% to 1,991 in 1996 from 2,096 employees at year-end 1995. Of the current total, 1,182 (59%) are represented by various collective bargaining units. Agreements with two units representing approximately 5% of regular employees are scheduled to expire in 1997. Refer to Note 1 of Notes to Consolidated Financial Statements filed under Item 8 of this report for additional information regarding employee relations. <PAGE 16> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 2. Properties The system's principal electric properties consist of Canal Unit 1, a 566 MW oil-fired steam electric generating unit, and its one-half ownership in Canal Unit 2, a 575.8 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. In addition, the system has a 3.52% interest (40.5 MW of capacity) in Seabrook 1 and a 1.4% or 8.8 MW joint-ownership interest in Central Maine Power Company's Wyman Unit 4. The system also has an interest in smaller generating units totaling 77.6 MW used primarily for peaking and emergency purposes. 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, 1996, the electric transmission and distribution system consisted of 5,803 pole miles of overhead lines, 4,371 cable miles of underground line, 355 substations and 378,088 active customer meters. The principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At the end of 1996, the gas system included 2,791 miles of gas distribution lines, 165,926 services and 243,083 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 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 DPU approving a customer transition charge that allows Cambridge Electric to recover certain stranded investment 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. 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 1995 by Quarter First Second Third Fourth High $20 15/16 $20 3/4 $21 11/16 $23 9/16 Low 17 13/16 18 7/8 17 11/16 20 1/2 (b) Number of Shareholders at December 31, 1996 13,676 shareholders (c) Frequency and Amount of Dividends Declared in 1996 and 1995 1996 1995 Per Per Share Share Declaration Date Amount Declaration Date Amount March 28, 1996 $ .385 March 23, 1995 $ .375 June 27, 1996 .385 June 22, 1995 .375 September 26, 1996 .385 September 28, 1995 .375 December 19, 1996 .385 December 14, 1995 .375 $1.540 $1.500 (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 1996 1995 1994 1993 1992 (Dollars In Thousands Except Common Share Data) Operating Revenues Electric $ 649,678 $ 604,980 $ 638,150 $ 622,039 $ 595,112 Gas 341,867 306,953 323,568 302,644 294,874 Steam and other 19,360 17,355 15,867 14,035 14,307 Total $1,010,905 $ 929,288 $ 977,585 $ 938,718 $ 904,293 Net Income $ 59,175 $ 51,396 $ 48,968 $ 45,834 $ 39,897 Common Share Data- Earnings per share $2.70 $2.36 $2.29 $2.18 $1.91 Dividends declared per share $1.54 $1.50 $1.50 $1.46 $1.46 Average shares outstanding 21,529,676 21,311,836 20,827,562 20,431,228 20,163,736 Total Assets $1,428,955 $1,392,342 $1,345,032 $1,318,940 $1,273,475 Long-term debt $ 355,305 $ 377,181 $ 418,307 $ 448,893 $ 361,092 Redeemable preferred share investment 13,020 13,840 14,660 15,480 16,300 Common share investment 415,694 390,785 362,997 337,070 315,219 Total Capitalization $ 784,019 $ 781,806 $ 795,964 $ 801,443 $ 692,611 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 1995 by Quarter 1st 2nd 3rd 4th (Dollars In Thousands Except Per Share Amounts) Operating Revenues $265,225 $208,776 $206,542 $248,745 Operating Income 30,011 17,237 17,253 30,042 Income Before Interest Charges 31,913 17,738 17,945 28,408 Net Income 20,933 6,430 7,116 16,917 Earnings per Common Share .98 .29 .32 .77 Dividends Declared per Common Share .375 .375 .375 .375 Closing Price of Common Shares- High 20 15/16 20 3/4 21 11/16 23 9/16 Low 17 13/16 18 7/8 17 11/16 20 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: 1996 1995 1994 Per Per Per Amount Share Amount Share Amount Share (Dollars in Thousands Except Per Share Amounts) Electric........... $39,667 $1.85 $32,247 $1.52 $32,952 $1.58 Gas................ 16,229 .75 15,352 .72 12,346 .59 Other.............. 2,229 .10 2,687 .12 2,500 .12 Total.......... $58,125 $2.70 $50,286 $2.36 $47,798 $2.29 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. Common share data for 1995 and 1994 has been restated throughout this discussion to reflect the two-for-one stock split that became effective June 5, 1996. 1996 versus 1995 In 1996, earnings applicable to common shares increased $7.8 million (15.6%) to $58.1 million. Earnings per share increased $.34 to $2.70. Return on average common equity, among the highest in the utility industry, improved to 14.4% from 13.3% in 1995. Significant factors that contributed to the improved earnings included higher firm gas ($.18) and retail electric ($.14) unit sales, a refund ($.11) associated with a power contract settlement agreement, lower interest costs ($.09), and the reversal of a reserve for Canal Electric Company's (Canal) recovery of postretirement benefits costs ($.07). Partially offsetting these factors were costs related to a five and one-half month labor dispute ($.11) resolved in September, storm damage from Hurricane Edouard ($.06), a customer refund ($.05 in 1996 versus $.01 in 1995) pursuant to a 1995 settlement agreement with the Massachusetts Department of Public Utilities (DPU) that limits Commonwealth Electric Company's (Commonwealth Electric) return on equity, as defined in a settlement that expires in 1997, and the reversal in 1995 of a reserve ($.04) related to a conservation program settlement in 1995. In March 1996, the System's Board of Trustees increased the quarterly dividend rate per share 2.7% from $.375 to $.385, an annual rate of $1.54. Dividends paid to common shareholders in 1996 were $33.2 million, representing a payout ratio of 57% of 1996 earnings. <PAGE 20> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 1995 versus 1994 In 1995, earnings applicable to common shares increased $2.5 million or 5.2% to $50.3 million. Earnings per share increased $.07 to $2.36. Factors that contributed to the improved earnings were a $3.8 million reduction ($.11) in other operation expense, the reversal of a reserve related to the system's energy conservation programs ($.04), and higher steam unit sales ($.01). Partially offsetting these factors was an increase in interest charges ($.07) primarily related to deferred gas costs and, to a lesser extent, higher short- term interest rates. Electric Operations In 1996, electric operating revenues increased $44.7 million or 7.4% due mainly to higher fuel costs of $33.9 million reflecting the increased availability 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 a $4 million refund associated with a power contract settlement approved by the Federal Energy Regulatory Commission (FERC) relative to billing issues in prior years, 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. Electric operating revenues in 1995 decreased $32.8 million (5.1%) due mainly to lower fuel oil costs ($32.6 million) caused by a combination of scheduled maintenance and other repairs to Canal's Unit 1. Also contributing to the decline in revenues were lower conservation and load management (C&LM) costs ($3.3 million). Offsetting these declines were increases related to the recovery of costs associated with a power contract buyout ($3.9 million including $1.9 million in carrying charges) and the recognition in revenues of $2 million in carrying charges associated with Commonwealth Electric's fuel charge stabilization deferral. Unit sales (in Megawatthours or MWH) were as follows: % % 1996 Change 1995 Change 1994 Residential.......... 1,802,973 2.9 1,752,430 (1.0) 1,770,095 Commercial........... 2,430,188 (0.8) 2,450,390 1.8 2,406,077 Industrial and Other. 449,844 1.1 445,020 - 445,037 Total Retail..... 4,683,005 0.8 4,647,840 0.6 4,621,209 Wholesale............ 2,721,623 37.9 1,973,543 (48.1) 3,803,786 Total............ 7,404,628 11.8 6,621,383 (21.4) 8,424,995 In 1996 retail unit sales increased slightly due to approximately 3,700 (1.0%) additional customers, the 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 as explained above. The changes in wholesale unit sales have little, if any, impact on net income. Retail unit sales increased in 1995 due to a modest growth in customers (approximately 2,500 or 0.6%) mainly in the residential and commercial sectors and, to a <PAGE 21> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES lesser extent, additional weather-related load attributable to greater air- conditioning and heating use. The decrease in total unit sales in 1995 was mainly due to a lower level of wholesale sales reflecting the decreased availability of Canal Unit 1. The cost of fuel increased in 1996 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 power. In 1995, the 36% decline in fuel costs was due to reduced consumption at Canal Unit 1. The cost of purchased power increased just 2% in 1995. Gas Operations In 1996, gas operating revenues increased approximately $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 higher degree days during 1996. Gas operating revenues decreased in 1995 by $16.6 million or 5.1% due mainly to an $18.3 million (10.3%) decline in the cost of gas sold that reflects a 3.7% reduction in total sales. Quasi-firm sales are designed for customers who receive interruptible service in peak months as negotiated in each contract and firm service in all other months. Fluctuations in quasi-firm sales had minimal impact on net income in 1996 and 1995. On January 17, 1997, the DPU approved a margin- sharing proposal filed by Commonwealth Gas Company (COM/Gas) for sales and transportation to quasi-firm customers. This proposal allows COM/Gas to retain 25% of the margins on these sales over a certain threshold amount as set from year to year. The remaining margins reduce the cost of gas sold to firm customers. Unit sales and transportation volume (in billions of British thermal units or BBTU) were as follows: % % 1996 Change 1995 Change 1994 Residential......... 22,759 6.7 21,336 (0.8) 21,515 Commercial.......... 11,558 7.9 10,710 (0.2) 10,728 Industrial and other 6,676 4.1 6,412 1.8 6,296 Total firm....... 40,993 6.6 38,458 (0.2) 38,539 Off-system.......... 2,420 (40.1) 4,043 (36.8) 6,401 Quasi-firm.......... 1,066 (44.1) 1,906 291.4 487 Interruptible....... 1,883 55.0 1,215 (36.9) 1,927 Total sales...... 46,362 1.6 45,622 (3.7) 47,354 Transportation...... 4,852 20.6 4,024 82.2 2,208 Total............ 51,214 3.2 49,646 0.2 49,562 The increase in unit sales to firm customers during 1996 (6.6%) reflects significant improvements for all customer classes consistent with colder than <PAGE 22> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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, also contributed to the increase in firm unit sales in 1996. During 1995 firm unit sales were virtually unchanged compared to 1994. Other Operating Expenses In 1996, other operation increased approximately $9 million or 4.4% reflecting the net impact of higher general liability insurance costs ($6.3 million), higher postretirement benefits costs ($4 million), and the net impact of COM/Gas' labor dispute ($3.8 million). These expenses were offset somewhat by lower C&LM costs ($2.4 million), a $1.6 million decline in medical costs, a decline in the provision for bad debts ($1.1 million) reflecting improved collection experience, and the absence of legal fees ($.8 million) associated with the cancellation of a power contract in 1995. Other operation in 1995 declined $7.1 million or 3.3% due primarily to a decline in liability insurance ($5.4 million) caused by accrual adjustments that reflected better than anticipated experience, lower C&LM costs ($3.3 million) and a decline in the provision for bad debts ($1 million). This was offset, in part, by higher labor costs ($3.5 million) and postretirement benefits costs ($2.6 million). Maintenance increased in 1996 by $2.5 million or 6.5% primarily due to storm damage costs related to Hurricane Edouard ($2.1 million). These increases were partially offset by reductions in maintenance costs, primarily associated with Canal Unit 1 ($1.5 million). During 1995, maintenance increased $1.9 million (5.2%) reflecting scheduled maintenance and other repair costs to several system generating units ($1.5 million). Depreciation expense increased $3.6 million and $4 million in 1996 and 1995, respectively, consistent with the System's additions to and upgrading of its property, plant and equipment. Other Income The $3.4 million increase in 1996 was due mainly to the recording of a regulatory asset by Canal for costs associated with postretirement benefits that were recovered in 1996 wholesale rates ($1.8 million) and a gain recognized on the sale of a parcel of non-utility land by Cambridge Electric ($.7 million). The increase in 1995 was due to a decline in the expense component of other income due primarily to the reversal of a reserve ($1.4 million) that had been established by Commonwealth Electric that related to certain costs associated with its conservation program, offset by the recognition of a reserve ($2.7 million, net of tax) related to a system generating station that discontinued operations and, to a lesser extent, the absence of the equity component of allowance for funds used during construction (AFUDC) ($.3 million). <PAGE 23> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Interest Charges Total interest charges declined $2.2 million, or 5%, in 1996 reflecting maturing long-term debt and scheduled sinking fund payments. Interest charges for 1995 increased $1.1 million or 2.6% due primarily to a higher level of interest on deferred gas costs ($2 million) and higher short-term interest rates, offset, in part, by lower long-term interest costs ($.9 million) that reflected maturing long-term debt and scheduled 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. Daily cash requirements for current operations, construction 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 financings are used to refinance short-term debt when deemed appropriate by management. The system's 1996 net cash flow from operating activities exceeded funds used for investing activities for additions to property, plant and equipment by $10.2 million or 19.2%. These types of investing activities continue to be funded entirely with internally-generated funds. Cash required in 1996 for financing activities was primarily for the payment of preferred and common dividends ($34.2 million) and the funding of maturing long-term debt and sinking fund requirements ($41.7 million). Proceeds from short-term borrow- ings ($62.9 million) helped to meet the year's cash requirements. Other information on the sources and uses of cash for the past three years is included in the Consolidated Statements of Cash Flows in this report. Capital Requirements ------------------------------------------------------------------- Bar graph illustration of comparative two-year (1995-1996) actual and five-year (1997-2001) forecast of capital requirements based on values listed in chart below. ------------------------------------------------------------------- Forecast 1995 1996 1997 1998 1999 2000 2001 (Dollars in Millions) Construction- Electric $ 61 $ 39 $ 49 $ 60 $ 34 $ 31 $ 27 Gas 16 11 18 18 19 19 19 Other 3 3 1 1 1 1 1 Maturing Debt 34 42 23 28 28 7 8 $114 $ 95 $ 91 $107 $ 82 $ 58 $ 55 <PAGE 24> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Capital Requirements and Resources The system's projected capital expenditures for the years 1997 through 2001 are $392.2 million, including $90.9 million for 1997 that consists of $68.2 million in construction expenditures and $22.7 million for debt and sinking fund payments. These 1997 requirements will be met primarily through internally-generated funds of $78.8 million with the balance of $12.1 million supplemented by long and short-term debt financings. The System could also raise capital through the issuance of additional series of preferred shares or additional Common Shares or through changing its Dividend Reinvestment and Common Share Purchase Plan from a market purchase plan to direct issue of shares. 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 sufficient to meet its current and projected requirements. The system's capitalization structure, including short-term debt, is presented below: 1995 1996 (Dollars in Thousands) Long-term debt.... $410,411 47.1% $369,565 40.3% Preferred shares.. 13,840 1.6 13,020 1.4 Common equity..... 390,785 44.9 415,694 45.4 Short-term debt... 55,600 6.4 118,475 12.9 Total capitalization $870,636 100.0% $916,754 100.0% Capitalization ------------------------------------------------------------------- Bar graph illustration of comparative five-year (1997-2001) forecast of capitalization components based on values listed in chart below. ------------------------------------------------------------------- Forecast 1997 1998 1999 2000 2001 (Dollars in Millions) Common Equity $438 46% $458 48% $477 51% $495 54% $515 58% Total Debt 493 53 480 51 444 48 407 45 368 41 Preferred Stock 12 1 11 1 11 1 10 1 9 1 $943 100% $949 100% $932 100% $912 100% $892 100% Forward-Looking Statements This report contains statements which, to the extent they are not recita- tions of historical fact, constitute "forward-looking statements" and are intended to be subject to the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995. A number of important factors <PAGE 25> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES affecting the System's business and financial results could cause actual results to differ materially from those stated in the forward-looking state- ments. Those factors include developments in the legislative, regulatory and competitive environment, certain environmental matters, demands for capital expenditures and the availability of cash from various sources, and uncertain- ty as to regulatory approval of the full recovery of regulatory assets and other stranded costs. Electric Industry Restructuring In August 1995, the DPU issued an order calling for the restructuring of the electric utility industry in Massachusetts. On May 1, 1996, the DPU issued a second order containing proposed rules for implementing electric industry restructuring that were the subject of public comment and hearings during June and July 1996. Subsequently, on December 30, 1996, the DPU issued another order announcing its "Model Rules and Legislative Proposal" as a guide in the creation of a competitive market for electric generation in Massachusetts that would provide customers with the opportunity to achieve lower electric bills beginning January 1, 1998. The order also required electric utilities to file by March 3, 1997, revenue-neutral, unbundled rates and model bills showing a breakdown of the bill into generation, transmission, distribution and access charge categories. In its "Model Rules," the DPU has proposed that the minimum structural reorganization needed to create a competitive market is the functional separation of generation, transmission and distribution within one integrated company, and the establishment of a separate marketing affiliate if a company retains generation assets. The Massachusetts Legislature, which will render the final passage of any restructuring law, is now considering the DPU's proposed legislation. Other elements of the DPU's Model Rules provide that electric customers will be able to buy their power on the open market; distribution services will remain a monopoly service offered exclusively by the existing local distribution companies in clearly defined service territories; and customers will have three types of electric generation choices. First, customers may enter into unregulated agreements with a competitive supplier for the provision of generation. Second, customers may continue to buy power directly from their electric distribution company at a price regulated by the DPU. Third, customers who have received generation from a competitive supplier but who, for any reason, have stopped receiving such generation will be able to receive default generation service, provided by distribution companies at spot market price. Changes in the electric industry may reduce the opportunity that currently exists for electric companies to recover their investment in generating plant and other expenditures previously approved by the DPU and included in current rates. The potential losses, which may result from subjecting electric company generation to the pressures of a competitive market, are typically referred to as "stranded costs." The single largest component of stranded costs which are significant to the system relates to above market purchased power contracts that Commonwealth Electric and Cambridge Electric have with non-utility generators. However, the DPU has concluded that it is in the public interest to provide electric companies a reasonable opportunity to <PAGE 26> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES collect net, non-mitigable stranded costs. The DPU has proposed that stranded costs associated with owned generation facilities, regulatory assets, and minimum purchased power obligations be collected over the expected economic life of the generating facility, the current amortization schedule of the regulatory asset, or the contractual term of the purchased power obligation, respectively. The DPU's proposal requires that any stranded cost recovery for an electric utility be subject to mitigation efforts to reduce embedded costs over time. The Model Rules specify that mitigation should include such measures as sales of capacity and energy from owned generation, renegotiation or buy-out of purchased power contracts, and sales and voluntary writedowns of assets. Further, the DPU will conduct stranded cost charge reconciliations at years two, five and ten following the date of retail access. During the last several months, three Massachusetts electric utilities have announced negotiated settlement agreements with the Massachusetts Attorney General's Office (Attorney General) that include divestiture of generating assets, provision for a ten percent reduction in customers' charges and recovery of stranded costs through a non-bypassable access charge. One settlement agreement has already been approved by the DPU. Implementation of any restructuring settlement may be affected by actions of the Massachusetts Legislature. The system is engaged in preliminary settlement discussions with the Attorney General, and expects to reach a comprehensive settlement during the first half of 1997. In the unlikely event it is unable to complete a settlement, the system would file a full restructuring plan with the DPU. As described in Note 2(b) to the Consolidated Financial Statements, the system complies with 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 determined that it no longer met 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. Criteria that give rise to the discontinuance of SFAS No. 71 include: 1) increasing 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 periodically reviews 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 regulatory assets, including those related to generation, are probable of future recovery. 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. The costs associated with the assessment and clean-up of these sites are recoverable in rates through the cost of gas adjustment clause over a seven- year amortization period without carrying costs pursuant to a 1990 DPU order. Commonwealth Gas has recorded an estimated $2.5 million liability that <PAGE 27> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES reflects its best estimate (based on current information) of the costs to be incurred in connection with assessment and remediation activities identified to this point. Commonwealth Gas has also recorded a regulatory asset in anticipation of recovery of these costs. Commonwealth Gas is unable to predict the total cost to ultimately resolve these matters, due to significant uncertainty as to the actual site conditions and the extent of any associated remediation activities and the assignment of responsibility. However, it is expected that all such costs will continue to be recovered in rates as described above. 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 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 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. Effective January 1, 1997, the system will adopt the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." This Statement provides 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 $4.2 million at December 31, 1996. Upon adoption of SOP 96-1, the system's estimated liability will not incrementally change and further, management does not believe that SOP 96-1 will have a material adverse effect 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 28 through 49 of this report. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. <PAGE 28> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 8. Financial Statements and Supplementary Data MANAGEMENT'S REPORT The consolidated financial statements presented herein are representations of the management of Commonwealth Energy System. Management recognizes its responsibility for the preparation and presentation of financial statements 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 Committee, 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 consolidated financial statements. James D. Rappoli, Financial Vice President February 19, 1997. 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 (a Massachusetts trust) and subsidiary companies as of December 31, 1996 and 1995, 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, 1996. 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 Commonwealth Energy System and subsidiary companies as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Boston, Massachusetts February 19, 1997. <PAGE 29> 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, 1996, 1995 and 1994 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Balance Sheets at December 31, 1996 and 1995 Consolidated Statements of Capitalization for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Changes in Common Shareholders' Investment for the Years Ended December 31, 1996, 1995 and 1994 Consolidated Statements of Changes in Redeemable Preferred Shares for the Years Ended December 31, 1996, 1995 and 1994 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, 1996, 1995 and 1994 II Valuation and Qualifying Accounts for the Years Ended December 31, 1996, 1995 and 1994 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 30> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994 (Dollars in Thousands - Except Per Share Amounts) 1996 1995 1994 Operating Revenues Electric $ 649,678 $604,980 $638,150 Gas 341,867 306,953 323,568 Steam and other 19,360 17,355 15,867 1,010,905 929,288 977,585 Operating Expenses Fuel used in electric production, principally oil 91,690 57,820 90,414 Electricity purchased for resale 265,019 274,795 269,418 Cost of gas sold 187,530 158,835 177,150 Other operation 215,319 206,280 213,370 Maintenance 40,913 38,414 36,522 Depreciation 51,782 48,170 44,188 Taxes- Local property 18,049 17,573 17,467 Income 36,099 24,574 29,154 Payroll and other 7,839 8,284 8,087 914,240 834,745 885,770 Operating Income 96,665 94,543 91,815 Other Income 4,878 1,461 627 Income Before Interest Charges 101,543 96,004 92,442 Interest Charges Long-term debt 35,586 38,581 39,442 Other interest charges 7,039 6,884 4,475 Allowance for borrowed funds used during construction (257) (857) (443) 42,368 44,608 43,474 Net Income 59,175 51,396 48,968 Dividends on preferred shares 1,050 1,110 1,170 Earnings Applicable to Common Shares $ 58,125 $ 50,286 $ 47,798 Average Number of Common Shares Outstanding 21,529,676 21,311,836 20,827,562 Earnings Per Common Share $2.70 $2.36 $2.29 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 31> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994 (Dollars in Thousands) 1996 1995 1994 Operating Activities Net income $ 59,175 $ 51,396 $ 48,968 Effects of noncash items- Depreciation and amortization 63,331 60,555 53,727 Deferred income taxes, net 3,515 4,182 14,846 Investment tax credits, net (1,285) (1,401) (1,470) Earnings from corporate joint ventures (1,557) (1,633) (1,750) Dividends from corporate joint ventures 1,376 2,067 1,651 Change in working capital, exclusive of cash- Accounts receivable and unbilled revenues (9,446) (13,626) 15,085 Income taxes (14,097) 14,353 8,016 Local property and other taxes (555) (950) 616 Accounts payable and other (33,956) 25,199 28,976 Power contract buy-out - (25,500) - Fuel charge stabilization deferral, net 2,372 (3,447) (15,964) Deferred postretirement benefits and pension costs (2,157) (4,479) (8,536) FERC Order 636 transition costs, net - 11,390 (2,585) All other operating items (3,391) 6,565 (15,017) Net cash provided by operating activities 63,325 124,671 126,563 Investing Activities Additions to property, plant and equipment (exclusive of AFUDC)- Electric (38,607) (60,841) (37,997) Gas (11,591) (16,143) (17,993) Other (2,730) (3,659) (1,843) Allowance for borrowed funds used during construction (257) (857) (443) Net cash used for investing activities (53,185) (81,500) (58,276) Financing Activities Sale of common shares 32 9,534 9,434 Payment of dividends (34,205) (33,142) (32,475) Proceeds from (payment of) short-term borrowings, net 62,875 10,750 (27,125) Retirement of long-term debt and preferred shares through sinking funds (8,436) (8,716) (6,406) Long-term debt issues refunded (33,230) (25,000) (10,000) Net cash used for financing activities (12,964) (46,574) (66,572) Net increase (decrease) in cash (2,824) (3,403) 1,715 Cash at beginning of period 4,319 7,722 6,007 Cash at end of period $ 1,495 $ 4,319 $ 7,722 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of capitalized amounts) $ 41,294 $ 42,051 $ 41,022 Income taxes $ 46,563 $ 12,918 $ 17,563 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 32> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1996 and 1995 (Dollars in Thousands) 1996 1995 Assets Property, Plant and Equipment, at original cost Electric $1,150,818 $1,118,630 Gas 357,403 346,990 Other 66,365 65,020 1,574,586 1,530,640 Less-Accumulated depreciation and amortization 536,041 497,712 1,038,545 1,032,928 Construction work in progress 5,485 10,154 Nuclear fuel in process 1,597 122 1,045,627 1,043,204 Equity in Corporate Joint Ventures Nuclear electric power companies (2.5% to 4.5%) 10,046 9,814 Other investments 3,349 3,400 13,395 13,214 Current Assets Cash 1,495 4,319 Accounts receivable, less reserves of $8,324,000 in 1996 and $8,040,000 in 1995 117,008 105,377 Unbilled revenues 31,698 33,883 Inventories, at average cost- Electric production fuel oil 2,221 1,683 Natural gas 23,084 17,339 Materials and supplies 6,220 6,516 Prepaid taxes 9,079 9,044 Other 5,686 6,799 196,491 184,960 Deferred Charges Regulatory assets 154,291 130,672 Other 19,151 20,292 173,442 150,964 $1,428,955 $1,392,342 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, 1996 and 1995 (Dollars in Thousands) 1996 1995 Capitalization and Liabilities Capitalization (See separate statement) Common share investment $ 415,694 $ 390,785 Redeemable preferred shares, less current sinking fund requirements 13,020 13,840 Long-term debt, less current sinking fund requirements and maturing debt 355,305 377,181 784,019 781,806 Capital Lease Obligations 12,346 13,291 Current Liabilities Interim Financing- Notes payable to banks 118,475 55,600 Maturing long-term debt 14,260 33,230 132,735 88,830 Other Current Liabilities- Current sinking fund requirements 8,473 9,103 Accounts payable 90,269 100,715 Accrued taxes- Local property and other 9,060 9,580 Income 7,910 22,007 Accrued interest 6,267 8,389 Dividends declared 8,289 8,073 Other 39,279 55,379 169,547 213,246 302,282 302,076 Deferred Credits Accumulated deferred income taxes 174,877 170,182 Unamortized investment tax credits 26,618 27,903 Other 128,813 97,084 330,308 295,169 Commitments and Contingencies $1,428,955 $1,392,342 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 34> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CAPITALIZATION DECEMBER 31, 1996 and 1995 (Dollars in Thousands) 1996 1995 Common Share Investment Common shares, $2 par value- Authorized-50,000,000 shares Outstanding-21,529,676 shares in 1996 and 21,528,268 shares in 1995 $ 43,059 $ 43,056 Amounts paid in excess of par value 111,685 111,749 Retained earnings 260,950 235,980 Total common share investment 415,694 390,785 Redeemable Preferred Shares, Cumulative, $100 Par Value Series A, 4.80% 2,640 2,760 Series B, 8.10% 4,000 4,160 Series C, 7.75% 7,200 7,740 Less-Current sinking fund requirements (820) (820) Total redeemable preferred shares 13,020 13,840 Long-term Debt System Senior Notes due- 1997, 10.48% 10,000 10,000 1998, 10.45% 10,000 10,000 1999, 10.58% 10,000 10,000 Less-Maturing long-term debt (10,000) - Total System long-term debt 20,000 30,000 Subsidiary companies Mortgage Bonds, collateralized by property of operating subsidiaries, due- 1996, 7% - 3,800 1996, 8.99% - 10,000 2001, 8.99% 18,100 21,750 2006, 8.85% 34,650 35,000 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- 1996, 9.97% - 20,000 1997, 6 1/4% 4,260 4,320 1998, variable rate (6.125% in 1996 and 6.5625% in 1995) 9,000 9,000 1999, 8.04% 10,000 10,000 2002, 7 3/4% 2,600 2,700 2002, 9.30% 30,000 30,000 2003, 7.43% 15,000 15,000 2004, 9.50% 12,500 15,000 2007, 8.70% 5,000 5,000 2007, 9.55% 10,000 10,000 2008, 7.70% 10,000 10,000 2012, 9.37% 16,842 17,895 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 (4,260) (33,230) Current sinking fund requirements (7,653) (8,283) Unamortized discount, net (734) (771) Total subsidiary companies' long-term debt 335,305 347,181 Total long-term debt 355,305 377,181 Total capitalization $784,019 $781,806 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 35> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' INVESTMENT FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994 Amounts Par Paid in Value Excess $2 Per of Par Retained Shares Share Value Earnings Total (Dollars in Thousands) Balance December 31, 1993 20,590,154 $41,180 $ 94,657 $201,233 $337,070 Add (Deduct)- Net income - - - 48,968 48,968 Sale of shares 461,640 923 8,511 - 9,434 Cash dividends declared- Common shares-$1.50 per share - - - (31,305) (31,305) Preferred shares - - - (1,170) (1,170) 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 CONSOLIDATED STATEMENTS OF CHANGES IN REDEEMABLE PREFERRED SHARES FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 and 1994 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, 1993 30,000 44,800 88,200 163,000 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 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 The accompanying notes are an integral part of these consolidated financial statements. <PAGE 36> 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 production and sale of electricity to 363,000 customers in 41 communities including New Bedford, Plymouth, Cambridge and the geographic area comprising Cape Cod. Gas operations serve 234,000 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 two new subsidiaries that are pursuing energy-related business opportunities. The system has 1,991 regular employees including 1,182 (59%) represented by various collective bargaining units. On September 8, 1996, a contract was ratified, following a five and one-half month labor dispute, with a collective bargaining unit that represents approximately 17% of regular employees. The new six-year agreement will remain in effect through March 31, 2002. New agreements were reached earlier this year with two other bargaining units (representing approximately 23% of regular employees) that were scheduled to expire on October 1, 1996 and November 1, 1997. These new agreements will remain in effect until 2002 and 2001, respectively. Additional contracts with two bargaining units representing approximately 5% of regular employees are scheduled to expire 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 Public Utilities (DPU). 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 DPU 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. 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 <PAGE 37> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES impact on the system's financial position or results of operations upon adoption. This result may change as modifications are made to the current regulatory framework due to ongoing electric industry restructuring efforts in Massachusetts. If all or a separable portion of the system's operations becomes no longer subject to the provisions of SFAS No. 71, a write-off of related regulatory assets and liabilities would be required, unless some form of transition cost recovery continues through rates established and collected for the system's remaining regulated operations. In addition, the system would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. However, on December 30, 1996, the DPU issued an order containing "model rules" for industry restructuring that management believes would essentially allow full recovery of stranded costs. For additional information relating to industry restructuring, see the "Electric Industry Restructuring" section under Management's Discussion and Analysis of Financial Condition and Results of Operations. The principal regulatory assets included in deferred charges at December 31, 1996 and 1995 were as follows: 1996 1995 (Dollars in Thousands) Postretirement benefit costs including pensions $ 25,051 $ 24,608 Power contract buy-out 20,794 23,838 Fuel charge stabilization 21,504 22,063 Deferred income taxes 13,597 14,106 FERC Order 636 transition costs 9,680 11,711 Connecticut Yankee unrecovered plant and decommissioning costs 35,879 - Yankee Atomic unrecovered plant and decommissioning costs 7,798 10,135 Seabrook related costs 6,262 9,511 Other 13,726 14,700 $154,291 $130,672 The regulatory liabilities, reflected in the accompanying Consolidated Balance Sheets and related primarily to deferred income taxes, were $17.7 million and $14 million at December 31, 1996 and 1995, respectively. As of December 31, 1996, $120.5 million of the system's regulatory assets, including the Connecticut Yankee costs associated with an existing power contract (see Note 4(e)), and all of its regulatory liabilities are reflected in rates charged to customers. Regulatory assets are being recovered over a weighted average period of approximately 11 years. The fuel charge stabilization deferral is 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 DPU approval. Requests for recovery of the remaining regulatory assets (primarily postretirement benefits costs) are in process and DPU approval is expected during 1997. (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. <PAGE 38> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (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: 1996 1995 1994 Electric 3.65% 3.52% 3.30% Gas 2.94 2.90 2.98 Steam 3.89 3.91 3.94 LNG 3.59 3.20 3.12 (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 the accompanying Consolidated Statements of Income. While AFUDC does not provide funds currently, these amounts are recoverable in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 6.2% in 1996, 7.1% in 1995 and 9.1% in 1994. (3) Common Shares Outstanding On June 5, 1996, the System effected a two-for-one stock split of its outstanding common shares as proposed by the System's Board of Trustees on March 28, 1996 and subsequently approved by the System's shareholders on May 2, 1996. The record date for the stock split was May 15, 1996. The split resulted in the issuance of an additional 10.8 million common shares and accompanied an increase in the number of authorized common shares from 18 million to 50 million and included a change in the par value from four dollars to two dollars per common share. Prior year amounts for the average number of common shares outstanding, earnings per common share, dividends declared per common share and common share investment information in the accompanying consolidated financial statements and in the table of selected financial data have been restated to reflect the stock split. (4) Commitments and Contingencies (a) Construction The system is engaged in a continuous construction program presently estimated at $302 million for the five-year period 1997 through 2001. Of that <PAGE 39> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES amount, $68.7 million is estimated for 1997. The program is subject to periodic review and revision. (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 Commonwealth 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 DPU approval. Pertinent information with respect to Canal Electric's joint-ownership interest in Seabrook 1 and information relating to operating expenses which are included in the accompanying financial statements are as follows: 1996 1995 (Dollars in Thousands) Utility plant-in- service $232,183 $232,547 Plant capacity (MW) 1,150 Nuclear fuel 21,613 20,138 Canal Electric's share: Accumulated depreciation Percent interest 3.52% and amortization (57,359) (50,230) Entitlement (MW) 40.5 Construction work in In-service date 1990 progress 844 946 Operating license $197,281 $203,401 expiration date 2026 1996 1995 1994 (Dollars in Thousands) Operating expenses: Fuel $ 1,727 $ 2,353 $ 1,939 Other operation 4,091 4,292 4,340 Maintenance 990 1,376 1,688 Depreciation 6,544 6,542 6,531 Amortization 1,319 1,319 1,320 $14,671 $15,882 $15,818 Canal Electric and the other joint owners have established a decommissioning fund to cover decommissioning costs. The estimated cost to decommission the plant is $449.9 million in current dollars. Canal Electric's share of this liability (approximately $15.8 million), less its share of the market value of the assets held in a decommissioning trust (approximately $1.9 million), is approximately $13.9 million at December 31, 1996. (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 operating 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 <PAGE 40> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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 insurance 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 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 yearly or a cumulative total of $15.1 million, exclusive of the effect of inflation indexing (at five-year intervals) and a 5% surcharge ($4 million) in the event that total public liability claims from a nuclear incident exceed the funds available to pay such claims. (d) Power Contracts Cambridge Electric and Commonwealth Electric have long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. Pertinent information with respect to life-of-the-unit contracts for power from nuclear units that operated in 1996 in which the system has an equity ownership (Yankee Nuclear Units) is as follows: Connecticut Maine Vermont Yankee* Yankee Yankee (Dollars in Thousands) Equity Ownership (%) 4.50 4.00 2.50 Plant Entitlement (%) 4.50 3.59 2.25 Plant Capability (MW) 560.0 870.0 496.0 System Entitlement (MW) 25.2 31.2 11.2 Contract Expiration Date 2007 2008 2012 1994 Actual Cost ($) 8,902 6,250 3,660 1995 Actual Cost ($) 9,498 7,376 4,003 1996 Actual Cost ($) 9,259 6,511 4,208 Decommissioning cost estimate (100%) ($) 410,582 380,718 366,142 System's decommissioning cost ($) 18,476 13,668 8,238 Market value of assets (100%) ($) 209,448 163,536 159,613 System's market value of assets ($) 9,425 5,871 3,591 * Refer to section (e) for further information on Connecticut Yankee. Cambridge Electric pays its share of the decommissioning expense to each of the operators of these nuclear facilities as a cost of electricity purchased for resale. <PAGE 41> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The system also has long-term contracts to purchase capacity from other generating facilities. Information relative to these contracts is as follows: Range of Contract Expiration Entitlement 1996 1995 1994 Dates % MW Cost Cost Cost (Dollars in Thousands) Type of Unit Natural gas 2008-2017 * 204.7$120,842 $121,636 $137,304 Nuclear 2012 11 73.6 37,072 40,376 41,475 Waste-to-energy 2015 100 67.0 39,622 37,526 38,107 Hydro 2014-2023 100 23.7 12,537 9,933 7,521 Total 369.0 $210,073 $209,471 $224,407 * Includes contracts to purchase power from various non-utility generators with capacity entitlements ranging from 11.1% to 100%. Costs pursuant to these 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 life-of-the- unit contracts from the operating Yankee Nuclear Units and other long-term purchased power contracts in effect for the five years subsequent to 1996 are as follows: Long-Term Equity Owned Purchased Nuclear Units Power Total (Dollars in Thousands) 1997 $11,474 $216,032 $227,506 1998 11,003 219,702 230,705 1999 12,768 224,508 237,276 2000 12,779 229,992 242,771 2001 11,908 239,253 251,161 (e) Yankee Nuclear Power Plants On July 22, 1996, Connecticut Yankee Atomic Power Company (Connecticut Yankee), which operates the Connecticut Yankee nuclear power plant (the Connecticut plant), took the unit out of service in connection with certain safety-related issues and refueling. During the outage, Connecticut Yankee's owners evaluated the economics of continuing to operate the plant over the remaining ten years of its current license life, compared to the costs of closing the plant and incurring replacement power for the same period. As a result of this evaluation, on December 4, 1996, Connecticut Yankee's Board of Directors voted to permanently shut down the plant. Cambridge Electric has an equity ownership interest in Connecticut Yankee of 4.5% which, at December 31, 1996, amounted to approximately $4.7 million. Cambridge Electric, through its ownership interest, has a corresponding capacity entitlement and power purchase obligation. The preliminary estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in the plant is approximately $797 million. Cambridge Electric's share of these remaining estimated costs is approximately $36 million. Based upon regulatory precedent, Connecticut Yankee believes that it would continue to collect from its power purchasers (including Cambridge Electric) its decommissioning costs, unrecovered plant investment and other costs associated with the permanent closure of the plant over the remaining period of the plant's operating license that expires in 2007. Cambridge Electric does not believe the <PAGE 42> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES ultimate outcome of the early closing of this plant will have a material adverse effect on its operations and believes that recovery of these FERC- approved costs will continue to be allowed in its rates at the retail level. This action follows the permanent shutdown of the Yankee Atomic plant in Rowe, Massachusetts in 1992. Due to changing conditions within the nuclear industry, it is possible that the remaining two operating nuclear plants in which the system has an equity ownership interest could be shut down sometime in the future prior to the expiration of each unit's operating license. (f) 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 installation of expensive air and water pollution control equipment. These regulations have had an impact on the system's operations in the past and will continue to have an impact on future operations, capital costs and construction schedules of major facilities. For additional information, see "Environmental Matters" in Management's Discussion and Analysis of Financial Condition and Results of Operations. (5) Income Taxes The system files a consolidated federal income tax return. For financial reporting purposes, the System and its subsidiaries provide taxes on a separate return basis. The following is a summary of the consolidated provisions for income taxes for the years ended December 31, 1996, 1995 and 1994: 1996 1995 1994 (Dollars in Thousands) Federal Current $28,375 $15,954 $12,789 Deferred 2,784 8,231 12,617 Investment tax credits, net (1,285) (1,401) (1,470) 29,874 22,784 23,936 State Current 5,542 4,176 3,171 Deferred 890 1,115 2,403 6,432 5,291 5,574 36,306 28,075 29,510 Amortization of regulatory liability relating to deferred income taxes (159) (5,164) (174) $36,147 $22,911 $29,336 Federal and state income taxes charged to: Operating expense $36,099 $24,574 $29,154 Other (income) expense 48 (1,663) 182 $36,147 $22,911 $29,336 Deferred tax liabilities and assets are determined based on the difference 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. <PAGE 43> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Accumulated deferred income taxes consisted of the following in 1996 and 1995: 1996 1995 (Dollars in Thousands) Liabilities Property-related $195,810 $190,763 Power contract buy-out 10,002 10,002 Fuel charge stabilization 8,124 8,149 Postretirement benefits plan 7,442 6,767 Seabrook nonconstruction 1,183 3,089 All other 20,018 20,006 242,579 238,776 Assets Investment tax credits 17,205 18,035 Pension plan 8,528 7,457 Regulatory liability 6,352 6,455 All other 22,239 21,570 54,324 53,517 Accumulated deferred income taxes, net $188,255 $185,259 The net year-end deferred income tax liability above includes a current deferred tax liability of $13,378,000 and $15,077,000 in 1996 and 1995, 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 1996, 31% in 1995 and 37% in 1994 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages: 1996 1995 1994 (Dollars in Thousands) Federal statutory rate 35% 35% 35% Federal income tax expense at statutory levels $33,363 $26,007 $27,406 Increase (Decrease) from statutory levels: State tax net of federal tax benefit 4,181 3,439 3,623 Tax versus book depreciation 1,553 1,369 1,471 Amortization of investment tax credits (1,285) (1,368) (1,457) Reversals of capitalized expenses (654) (652) (654) Dividend received deduction (381) (389) (428) Amortization of excess deferred reserves (159) (5,164) (174) Other (471) (331) (451) $36,147 $22,911 $29,336 Effective federal income tax rate 38% 31% 37% (6) 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. <PAGE 44> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Components of pension expense and related assumptions to develop pension expense were as follows: 1996 1995 1994 (Dollars in Thousands) Service cost $ 7,663 $ 6,386 $ 7,316 Interest cost 24,462 23,949 21,452 Return on plan assets-(gain)/loss (45,961) (62,933) 4,544 Net amortization and deferral 24,520 42,928 (21,990) Total pension expense 10,684 10,330 11,322 Less: Amounts capitalized and deferred 2,203 1,842 2,823 Net pension expense $ 8,481 $ 8,488 $ 8,499 Discount rate 7.25% 8.50% 7.25% Assumed rate of return 8.75 9.00 8.50 Rate of increase in future compensation 4.25 5.00 4.50 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: 1996 1995 (Dollars in Thousands) Accumulated benefit obligation: Vested $(254,888) $(240,585) Nonvested (30,604) (26,772) $(285,492) $(267,357) Projected benefit obligation $(340,850) $(323,652) Plan assets at fair market value 343,884 308,969 Projected benefit obligation less or (greater) than plan assets 3,034 (14,683) Unamortized transition obligation 8,036 9,643 Unrecognized prior service cost 13,357 14,792 Unrecognized gain (43,918) (27,349) Accrued pension liability $ (19,491) $ (17,597) The following actuarial assumptions were used in determining the plan's year-end funded status: 1996 1995 Discount rate 7.50% 7.25% Rate of increase in future compensation 4.25 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. <PAGE 45> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES To fund its postretirement benefits, the system makes contributions to various voluntary employees' beneficiary association trusts that were established 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 $13.7 million, $14 million and $14.5 million to these trusts during 1996, 1995 and 1994, respectively. The net periodic postretirement benefit cost for the years ended December 31, 1996, 1995 and 1994 include the following components and related assumptions: 1996 1995 1994 (Dollars in Thousands) Service cost $ 2,211 $ 1,774 $ 2,198 Interest cost 9,352 9,022 8,299 Return on plan assets (5,176) (5,796) (186) Amortization of transition obligation over 20 years 5,336 5,336 5,336 Net amortization and deferral 2,038 3,692 (1,118) Total postretirement benefit cost 13,761 14,028 14,529 Less: Amounts capitalized and deferred 1,614 5,898 8,811 Net postretirement benefit cost $12,147 $ 8,130 $ 5,718 Discount rate 7.25% 8.50% 7.25% Assumed rate of return 8.75 9.00 8.50 Rate of increase in future compensation 4.25 5.00 4.50 The funded status of the system's postretirement benefit plan using a measurement date of December 31, 1996 and 1995 is as follows: 1996 1995 (Dollars in Thousands) Accumulated postretirement benefit obligation: Retirees $ (72,827) $ (71,270) Fully eligible active plan participants (11,468) (12,860) Other active plan participants (41,352) (41,814) (125,647) (125,944) Plan assets at fair market value 45,967 33,324 Accumulated postretirement benefit obligation greater than plan assets (79,680) (92,620) Unamortized transition obligation 85,368 90,703 Unrecognized (gain) loss (5,688) 1,917 $ - $ - The following actuarial assumptions were used in determining the plan's estimated accumulated postretirement benefit obligation (APBO) and funded status for 1996 and 1995: 1996 1995 Discount rate 7.50% 7.25% Rate of increase in future compensation 4.25 4.25 Medicare Part B premiums 9.50 12.20 Medical care 7.00 8.00 Dental care 5.00 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 5%, respectively, by 2007 and remain at that level thereafter. A one percent <PAGE 46> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES change in the medical trend rate would have a $1.7 million impact on the system's annual expense and would change the APBO by approximately $16.1 million. Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect postretirement benefit expense in future years. Effective May 1, 1995 the DPU approved a settlement proposal sponsored jointly by Commonwealth Electric and the Attorney General of Massachusetts which allows Commonwealth Electric to fully recover costs relating to postretirement 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. Commonwealth Gas has recently requested a ruling from the DPU as it seeks to fully recover its costs. In addition, Commonwealth Gas has requested to amortize its deferred balance of $10 million over a period not to exceed ten years. While the system is unable to predict the ultimate outcome of its request, it believes that the DPU will authorize similar treatment as provided to Commonwealth Electric. (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 $4,053,000 in 1996, $4,393,000 in 1995 and $4,302,000 in 1994. (7) 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, 1996, system companies had $135 million of committed lines of credit that will expire at varying intervals in 1997. These lines are normally renewed upon expiration and require annual fees of up to .1875% of the individual line. At December 31, 1996, the uncommitted lines of credit totaled $20 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 5.6% and 6.1% in 1996 and 1995, respectively. Notes payable to banks totaled $118,475,000 and $55,600,000 at December 31, 1996 and 1995, 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, 1996 are as follows: Sinking Funds Maturing Debt Issues Year Subsidiaries System Subsidiaries Total (Dollars in Thousands) 1997 $7,653 $10,000 $ 4,260 $21,913 1998 7,653 10,000 9,000 26,653 1999 7,653 10,000 10,000 27,653 2000 6,153 - - 6,153 2001 7,581 - 3,500 11,081 <PAGE 47> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (8) 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 required redemption, at par, on a non-cumulative basis, on each sinking fund date. 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 1997-2001 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. (9) Disclosures About Fair Value of Financial Instruments The fair value of certain financial instruments included in the accompanying Consolidated Balance Sheets as of December 31, 1996 and 1995 is as follows: 1996 1995 (Dollars in Thousands) Carrying Fair Carrying Fair Value Value Value Value Long-term debt $377,218 $417,411 $418,694 $475,661 Preferred stock 13,840 14,601 14,660 16,847 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. <PAGE 48> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (10) 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 transportation 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. The following is a breakdown, by major class, of property under capital lease at December 31, 1996 and 1995: 1996 1995 (Dollars in Thousands) Transmission facilities $12,454 $13,128 Office furniture, computer equipment and other 1,500 1,888 13,954 15,016 Less: Accumulated amortization 77 85 $13,877 $14,931 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, 1996: Capital Operating Leases Leases (Dollars in Thousands) 1997 $ 2,941 $13,791 1998 2,319 12,182 1999 1,810 11,369 2000 1,732 5,032 2001 1,669 3,058 Beyond 2001 18,845 12,159 Total future minimum lease payments 29,316 $57,591 Less: Estimated interest element included therein 15,439 Estimated present value of future minimum lease payments $13,877 Total rent expense for all operating leases, except those with terms of a month or less, amounted to $12,922,000 in 1996, $13,867,000 in 1995 and $13,052,000 in 1994. There were no contingent rentals and no sublease rentals for the years 1996, 1995 and 1994. (11) Dividend Restriction At December 31, 1996, approximately $112,717,000 of consolidated retained earnings was restricted against the payment of cash dividends by terms of indentures and note agreements securing long-term debt. (12) Segment Information System companies provide electric, gas and steam services to retail customers in communities located in central, eastern and southeastern Massachusetts 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. <PAGE 49> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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. 1996 1995 1994 (Dollars in Thousands) Revenues from Unaffiliated Customers Electric $ 649,678 $ 604,980 $ 638,150 Gas 341,867 306,953 323,568 Steam and other 19,360 17,355 15,867 Total Revenues $1,010,905 $ 929,288 $ 977,585 Capital Expenditures (including AFUDC) Electric $ 38,844 $ 61,643 $ 38,754 Gas 11,611 16,198 18,020 Other 2,730 3,659 1,843 $ 53,185 $ 81,500 $ 58,617 Operating Income Before Income Taxes Electric $ 92,374 $ 78,817 $ 85,823 Gas 36,984 36,611 31,664 Steam and other 3,406 3,689 3,482 Total Operating Income Before Income Taxes $ 132,764 $ 119,117 $ 120,969 Identifiable Assets Electric $1,011,306 $ 982,384 $ 931,168 Gas 388,930 374,615 380,805 Steam and other 58,081 57,269 53,914 1,458,317 1,414,268 1,365,887 Intercompany eliminations (42,757) (35,140) (34,503) Investment in corporate joint ventures 13,395 13,214 13,648 Total Identifiable Assets $1,428,955 $1,392,342 $1,345,032 Depreciation Expense Electric $ 39,977 $ 36,977 $ 33,188 Gas 10,061 9,656 9,559 Steam and other 1,744 1,537 1,441 Total Depreciation $ 51,782 $ 48,170 $ 44,188 <PAGE 50> 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 1997 Annual Meeting and Proxy Statement dated March 28, 1997, pages 3-4. b. Executive Officers of the Registrant: Age at December Name of Officer Position and Business Experience 31, 1996 William G. Poist President, Chief Executive Officer and 63 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. James D. Rappoli Financial Vice President and Treasurer of 45 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. Russell D. Wright President and Chief Operating Officer of 50 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 (July 1987 to March 1993); Treasurer of System subsidiary companies (December 1989 to December 1990); Assistant Vice President- Finance of System subsidiary companies 1986. * Subsidiary of the System. <PAGE 51> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES b. Executive officers of the Registrant (Continued): Age at December Name of Officer Position and Business Experience 31, 1996 Michael P. Sullivan Vice President, Secretary, and 48 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. Robert A. Paul Senior Vice President of Corporate 52 Planning of COM/Energy Services Company* (effective February 10, 1997); Vice President of Commonwealth Edison Co. (a subsidiary of Unicom Corp.) from 1994 to 1997; senior manager at Digital Equipment Corp. from 1977 to 1994. John R. Williams Vice President of Corporate Services of 53 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 1, 1997, 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 1997 Annual Meeting and Proxy Statement dated March 28, 1997, 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 1997 Annual Meeting of Shareholders dated March 28, 1997, pages 2-4. <PAGE 52> 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 1997 Annual Meeting and Proxy Statement dated March 28, 1997, 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 29). (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 71). Schedule I - Investments in, Equity in Earnings of, and Dividends Received from Related Parties - Years Ended December 31, 1996, 1995 and 1994 (pages 72-74). Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1996, 1995 and 1994 (page 75). 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, 1997. <PAGE 53> 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 54> 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). <PAGE 55> 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 (September 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 56> 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 August 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 Power Exchange Agreement by and between BECO and CEL dated December 1, 1984 (Exhibit 5 to the CEL 1984 Form 10-K, File No. 2- 7909). 10.1.7.5 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). <PAGE 57> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 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). 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 (Exhibit 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 Agreement to Share Certain Costs Associated with the Tewksbury- Seabrook Transmission Line dated May 8, 1986 (Exhibit 2 to the CEC 1986 Form 10-K, File No. 2-30057). 10.1.10 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). 10.1.11 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). 10.1.12 Termination Supplement between CEC, CE and CEL for Seabrook Unit 2, dated December 8, 1986 (Exhibit 3 to the CEC 1986 Form 10-K, File No. 2-30057). <PAGE 58> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.13 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). 10.1.14 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). 10.1.14.1 Amendments No. 2 and 3 to 10.1.17 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). 10.1.15 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). 10.1.15.1 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). 10.1.15.2 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). 10.1.16 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). 10.1.17 Capacity Acquisition Agreement between CEC,CEL and CE dated September 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File No. 2-30057). 10.1.17.1 Supplement to 10.1.20 consisting of three Capacity Acquisition Commitments each dated May 7, 1987, concerning Phases I and II of the Hydro-Quebec Project and electricity acquired from Connecticut Light and Power Company (CL&P) (Exhibit 1 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.17.2 Supplements to 10.1.20 consisting of two Capacity Acquisition Commitments each dated October 31, 1988, concerning electricity acquired from Western Massachusetts Electric Company and/or CL&P for periods ranging from November 1, 1988 to October 31, 1994 (Exhibit 2 to the CEC Form 10-Q (September 1989), File No. 2- 30057). <PAGE 59> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.17.3 Amendment to 10.1.20 as amended and restated June 1, 1993, henceforth 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). 10.1.17.4 Capacity Disposition Commitment dated June 25, 1993 by and between Canal Electric Company (Unit 2) and Commonwealth Electric Company for the sale of a portion of Commonwealth Electric's entitlement in Unit 2 to Green Mountain Power Corporation (Exhibit 2 to Canal Electric's Form 10-Q (September 1993), File No. 2-30057). 10.1.18 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). 10.1.18.1 Amendment No. 2 to 10.1.21 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.18.2 Amendment No. 3 to 10.1.21 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749). 10.1.19 Participation Agreement between MEPCO and CEL and/or NBGEL dated June 20, 1969 for construction of a 345 KV transmission line between Wiscasset, Maine and Mactaquac, New Brunswick, Canada and for the purchase of base and peaking capacity from the NBEPC (Exhibit 13 to the CES 1984 Form 10-K, File No. 1-7316). 10.1.19.1 Supplement Amending 10.1.22 as amended June 24, 1970 (Exhibit 8 to the CES Form S-7, Amendment No. 1, File No. 2-38372). 10.1.20 Power Purchase Agreement between Weweantic Hydro Associates and CE for the purchase of available hydro-electric energy produced by a facility located in Wareham, Massachusetts, dated December 13, 1982 (Exhibit 1 to the CE 1983 Form 10-K, File No. 2-7749). 10.1.20.1 Power Purchase Agreement (Revised) between Weweantic Hydro Associ- ates and Commonwealth Electric Company for the purchase of available hydro-electric energy produced by a facility located in Wareham, MA, originally dated December 13, 1982, revised and dated March 12, 1993 (Exhibit 1 to the CE Form 10-Q (June 1993), File No. 2-7749). 10.1.21 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 60> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.22 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). 10.1.22.1 Amendment to 10.1.25 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). 10.1.23 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 Corporation (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.23.1 Amendment No. 3 to 10.1.26 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749). 10.1.24 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, Amendment 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). 10.1.25 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 (Exhibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.25.1 Amendatory Agreement No. 3 to 10.1.28 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.26 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). 10.1.27 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). 10.1.28 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 61> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.29 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). 10.1.29.1 First, Second and Third Amendments to 10.1.32 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). 10.1.29.2 Fifth, Sixth and Seventh Amendments to 10.1.32 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057). 10.1.29.3 Fourth and Eighth Amendments to 10.1.32 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057). 10.1.29.4 Ninth and Tenth Amendments to 10.1.32 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.29.5 Eleventh Amendment to 10.1.32 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057). 10.1.29.6 Twelfth Amendment to 10.1.32 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057). 10.1.30 Phase II Equity Funding Agreement for New England Hydro- Transmission 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). 10.1.31 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 utilities (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.32 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). 10.1.33 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). 10.1.33.1 Amendment No. 1 to 10.1.36 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057). <PAGE 62> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.33.2 Amendment No. 2 to 10.1.36 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.34 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). 10.1.34.1 Amendments Nos. 1 and 2 to 10.1.37 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.34.2 Amendments Nos. 3 and 4 to 10.1.37 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.35 Phase II Boston Edison AC Facilities Support Agreement, dated June 1, 1985, between BECO and certain NEPOOL utilities (Exhibit 7 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.35.1 Amendments Nos. 1 and 2 to 10.1.38 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.35.2 Amendments Nos. 3 and 4 to 10.1.38 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.36 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 (Exhibit 8 to the CEC Form 10-Q (September 1985), File No. 2- 30057). 10.1.37 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). 10.1.37.1 Transmission Service Agreement between Northeast Utilities' companies (NU) - The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO), and CE for NU companies to transmit power purchased from Swift River Company's Chicopee Units to CE, dated October 1, 1984 (Exhibit 14 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.37.2 Transformation Agreement between WMECO and CE whereby WMECO is to transform power to CE from the Chicopee Units, dated December 1, 1984 (Exhibit 15 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.38 System Power Sales Agreement by and between CL&P and WMECO, as buyers, and CE, as seller, dated January 13, 1984 (Exhibit 13 to the CE 1984 Form 10-K, File No. 2-7749). <PAGE 63> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.39 System Power Sales Agreement by and between CL&P, WMECO, as sellers, and CEL, as buyer, of power in excess of firm power customer requirements from the electric systems of the NU Companies, dated June 1, 1984, as effective October 25, 1985 (Exhibit 1 to CEL 1985 Form 10-K, File No. 2-7909). 10.1.39.1 System Power Sales Agreement by and between CL&P, WMECO, and PSNH, as sellers, and Commonwealth Electric Company, as buyer, of power for peaking capacity and related energy, dated January 13, 1995, as effective June 1, 1995 and extending to October 31, 2000 (Exhibit 2 to the CE Form 10-Q (June 1995), File No. 2-7749). 10.1.40 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). 10.1.40.1 Power Sales Agreement to 10.1.44 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749). 10.1.40.2 Amendment to 10.1.44 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). 10.1.40.3 Amendment to 10.1.44 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). 10.1.41 System Power Sales Agreement by and between CE (seller) and NEP (buyer), dated January 6, 1984 (Exhibit 1 to the CE Form 10-Q (June 1985), File No. 2-7749). 10.1.42 Service Agreement by and between CE and NEP dated March 24, 1984, whereas CE agrees to purchase short-term power applicable to NEP'S FERC Electric Tariff Number 5 (Exhibit 1 to the CE Form 10-Q (June 1987), File No. 2-7749). 10.1.43 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). 10.1.43.1 First Amendment to 10.1.47 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749). 10.1.43.2 Second Amendment to 10.1.47 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749). <PAGE 64> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.43.3 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). 10.1.43.4 Amendment to 10.1.47.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.44 Exchange of Power Agreement between Montaup Electric Company and CE dated January 17, 1991 (Exhibit 2 to CE Form 10-Q (September 1991) File No. 2-7749). 10.1.44.1 First Amendment, dated November 24, 1992, to Exchange of Power Agreement between Montaup Electric Company and Commonwealth Electric Company dated January 17, 1991 (Exhibit 1 to CE Form 10-Q (March 1993) File No. 2-7749). 10.1.45 System Power Exchange Agreement by and between Commonwealth Electric Company and New England Power Company dated January 16, 1992 (Exhibit 1 to CE Form 10-Q (March 1992), File No. 2-7749). 10.1.45.1 First Amendment, dated September 8, 1992, to 10.1.49 by and between Commonwealth Electric Company and New England Power Company dated January 16, 1992 (Exhibit 1 to CE Form 10-Q (September 1992), File No. 2-7749). 10.1.45.2 Second Amendment, dated March 2, 1993, to 10.1.49 by and between CE and New England Power Company (NEP) dated January 16, 1992 (Exhibit 2 to CE Form 10-Q (March 1993) File No. 2-7749). 10.1.46 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). 10.1.46.1 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). 10.1.47 Power Exchange Contract, dated March 24, 1993, between NEP and Canal Electric Company (Canal) for an exchange of unit capacity in which NEP will purchase 20 MW of Canal Unit 2 capacity in exchange for Canal's purchase of 20 MW of NEP's Bear Swamp Units 1 and 2 (10 MW per unit) commencing May 31, 1993 through April 28, 1997 and NEP will purchase 50 MW of Canal's Unit 2 capacity in exchange for Canal's purchase of 50 MW of NEP's Bear Swamp Units 1 and 2 (25 MW per unit) commencing November 1, 1993 through April 28, 1997 (Exhibit 1 to Canal's Form 10-Q (March 1993) File No. 2-30057). <PAGE 65> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.1.48 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). 10.1.49 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). 10.1.49.1 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 Commonwealth Electric's Form 10-Q (September 1993), File No 2- 7749). 10.1.49.2 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). 10.1.49.3 First Amendment, dated November 7, 1994, to 10.1.53 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). 10.1.49.4 First Amendment, dated November 7, 1994, to 10.1.53.2 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 Service Agreement Applicable to Rate Schedule F-1 between AGT and CG for Firm natural gas services, dated January 28, 1981 (Exhibit 1 to the CG Form 10-Q (March 1987), File No. 2-1647). 10.2.2 Gas Service Contract between HOPCO and NBGEL for the performance of liquefaction, storage and vaporization service and the operation and maintenance of an LNG facility located at Acushnet, MA dated September 1, 1971 (Exhibit 8 to the CG 1984 Form 10-K, File No. 2- 1647). 10.2.2.1 Gas Service Contract between HOPCO and CG for the performance of liquefaction, storage and vaporization services and the operation of LNG facilities located in Hopkinton, MA dated September 1, 1971 (Exhibit 9 to the CG 1984 Form 10-K, File No. 2-1647). <PAGE 66> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.2.2.2 Amendments to 10.2.2 and 10.2.2.1 as amended December 1, 1976 (Exhibits 2 and 3 to the CG 1986 Form 10-K, File No. 2-1647). 10.2.2.3 Supplement 1 to Gas Service Contract between HOPCO and NBGEL dated September 1, 1973 and September 14, 1977 (Exhibit 5(c)5 to the CES Form S-16 (June 1979), File No. 2-64731). 10.2.2.4 Supplement 1 to 10.2.2.1 dated September 14, 1977 (Exhibit 5(c)6 to the CG Form S-16 (June 1979), File No. 2-64731). 10.2.2.5 Supplement 2 to 10.2.2.1 dated September 30, 1982 (Refiled as Exhibit 2 to the CG 1992 Form 10-K, File No. 2-1647). 10.2.2.6 1986 Consolidating Supplement to CG Service Contract and NBGEL Service Contract by and between CG and HOPCO dated December 31, 1986 amending and consolidating the CG Service Contract and the NBGEL Service Contract both as amended December 1, 1976 and supplemented September 14, 1977 (Exhibit 2 to CG Form 10-Q (March 1988), File No. 2-1647). 10.2.3 Operating Agreement between Air Products and Chemicals, Inc., (APC) and HOPCO, dated as of September 1, 1971, as supplemented by Supplements No. 1, No. 2 and No. 3 dated as of July 1, 1974, August 1, 1975 and January 1, 1985, respectively, with respect to the operation and maintenance by APC of HOPCO's liquefied natural gas facilities located at Hopkinton, MA (Exhibit 11 to the CES 1984 Form 10-K, File No. 1-7316). 10.2.3.1 Engineering and Prime Contracting Agreement between APC and HOPCO for performance of engineering services and capital project construction at LNG facility in Hopkinton, MA (Exhibit 12 to the CES 1984 Form 10-K, File No. 1-7316). 10.2.4 Firm Storage Service Transportation Contract by and between TGP and CG providing for firm transportation of natural gas from CGT, dated December 15, 1985 (Exhibit 1 to the CG 1985 Form 10-K, File No. 2- 1647). 10.2.5 Gas Sales Agreement by and between Enron Gas Marketing, Inc. and CG relating to the sale and purchase of natural gas on an interruptible basis, dated June 17, 1986 (Exhibit 3 to the CG Form 10-Q (June 1986), File No. 2-1647). 10.2.6 Service Agreement dated December 14, 1985 and an amendment thereto dated May 15, 1986 by and between Texas Eastern Transmission Corporation (TET) and CG to receive, transport and deliver to points of delivery natural gas for the account of CG, dated December 14, 1985 (Exhibit 5 to the CG Form 10-Q (June 1986), File No. 2-1647). 10.2.7 Gas Transportation Agreement by and between TET and CG to receive, transport and deliver on an interruptible basis, certain quantities of natural gas for the account of CG, dated January 31, 1986 (Exhibit 6 to the CG Form 10-Q (June 1986), File No. 2-1647). <PAGE 67> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.2.8 Service Agreement dated May 19, 1988, by and between TET and CG, whereby TET agrees to receive, transport and deliver natural gas to CG (Exhibit 1 to the CG Form 10-Q (September 1988), File No. 2- 1647). 10.2.9 Gas Transportation Agreement by and between AGT and CG to receive, transport and deliver certain quantities of natural gas on a firm basis for the account of CG dated December 1, 1988 (Exhibit 2 to the CG 1988 Form 10-K, File No. 2-1647). 10.2.10 Gas Sales Agreement between Tejas Power Corporation (seller) and CG (purchaser) for the purchase of spot market gas, dated February 21, 1989 with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (March 1989), File No. 2-1647). 10.2.11 Gas Sales Agreement between Vitol (seller) and CG (purchaser) for the purchase of spot market gas, dated April 5, 1988, with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (June 1989), File No. 2-1647). 10.2.12 Gas Sales Agreement between Fina Oil and Chemical Company (seller) and CG (purchaser) for the purchase of spot market gas, dated July 10, 1989, with a contract term of at least one year (Exhibit 3 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.13 Gas Sales Agreement between Panenergy (seller) and CG (purchaser) for the purchase of spot market gas, dated August 14, 1989, with a contract term of at least one year (Exhibit 4 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.14 Gas Storage Agreement between Steuben Gas Storage Company (Steuben) and CG (customer) for the storage and delivery of customer's natural gas to and from underground gas storage facilities, dated May 23, 1989, with a contract term of at least one year (Exhibit 4 to the CG Form 10-Q (June 1989), File No. 2-1647). 10.2.14.1 Amendment, dated August 28, 1989, to 10.2.14 dated May 23, 1989 (Exhibit 5 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.15 Gas Sales Agreement between LGN&E (seller) and CG (purchaser) for the purchase of firm gas, dated August 15, 1990, with a contract term of at least six years (Exhibit 1 to the CG Form 10-Q (September 1990), File No. 2-1647). 10.2.16 Transportation Agreement between AGT and CG to provide for firm transportation of natural gas on a daily basis, dated December 1, 1988 (Exhibit 3 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.17 Gas Sales Agreement between AFT and CG to reduce the volume of Rate Schedule F-1, dated October 15, 1990 (Exhibit 5 to the CG 1991 Form 10-K, File No. 2-1647). <PAGE 68> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES 10.2.18 Transportation Agreement between AFT and CG for Rate Schedule AFT- 1, dated November 1, Agreement No. 90103, 1990 (Exhibit 6 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.19 Transportation Agreement between TGP and CG dated September 1, 1991 (Exhibit 9 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.20 Transportation Agreement between CNG and CG to provide for transportation 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). 10.2.21 Service Line Agreement by and between Commonwealth Gas Company (CG) and Milford Power Limited Partnership dated March 12, 1992 for a term ending January 1, 2013. (Exhibit 1 to the CG Form 10-Q (March 1992), 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 the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), 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 Corporation, 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 (Refiled 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 69> 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 (Exhibit 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 Fuel Supply, Facilities Lease and Operating Contract by and between, on the one side, ESCO (Massachusetts), Inc. and Energy Supply and Credit Corporation, and on the other side, CEC, dated as of February 1, 1985 (Exhibit 1 to the CEC 1984 Form 10-K, File No. 2-30057. 10.3.4.1 Amendments Nos. 1 and 2 to 10.3.5 as amended July 1, 1986 and November 15, 1989, respectively (Exhibit 3 to the CEC 1989 Form 10- K, File No. 2-30057). 10.3.5 Assignment and Sublease Agreement and Canal's Consent of Assignment thereto whereby ESCO-Mass assigns its rights and obligations under Part II of the Resupply Agreement dated February 1, 1985 to ESCO Terminals Inc., dated June 4, 1985 (Exhibit 4 to CEC Form 10-Q (June 1985), File No. 2-30057). 10.3.6 Oil Supply Contract by and between CEC (buyer) and Coastal Oil New England, Inc. (seller) for a portion of CEC's requirements of No. 6 residual fuel oil, dated July 1, 1991 (Exhibit 3 to CEC Form 10-Q (June 1991), File No. 2-30057). 10.3.6.1 Assignment Agreement between CEC and ESCO (Massachusetts), Inc. (ESCO-Mass) and Energy Supply and Credit Corporation whereby CEC assigns to ESCO-Mass rights and obligations under 10.3.7 (above) dated July 1, 1991 (Exhibit 4 to CEC Form 10-Q (June 1991), File No. 2-30057). 10.3.7 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). <PAGE 70> COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Exhibit 21. Subsidiaries of the Registrant Filed herewith as Exhibit 1 is a list of subsidiaries of Commonwealth Energy System, all of which are wholly-owned, as of December 31, 1996. Exhibit 22. Published Report Regarding Matters Submitted to Vote of Security Holders. Filed herewith as Exhibit 2 is the Notice of 1997 Annual Meeting and Proxy Statement dated March 28, 1997. Exhibit 27. Financial Data Schedule Filed herewith as Exhibit 3 is the Financial Data Schedule for the twelve months ended December 31, 1996. Filed herewith as Exhibit 4 is the restated Financial Data Sched- ule for the twelve months ended December 31, 1995. Filed herewith as Exhibit 5 is the restated Financial Data Sched- ule for the twelve months ended December 31, 1994. (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended December 31, 1996. <PAGE 71> 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, 1997. 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, 1997. <PAGE 72> 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 73> 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 3,893 620 $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 74> 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, 1994 (Dollars in Thousands) Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Other Distribution of Receivable Shares Investment Earnings (B) of Earnings Shares Investment (A) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 346,600 $ 43,674 $ 6,242 $ - $ 6,132 346,600 $ 43,784 $ 410 COM/Energy Steam Company 25,500 3,321 1,976 - 1,187 25,500 4,110 105 Canal Electric Company 1,523,200 94,552 14,158 - 10,662 1,523,200 98,048 9,350 Commonwealth Gas Company 2,857,000 107,004 13,568 - 14,571 2,857,000 106,001 2,935 Darvel Realty Trust 26 759 111 - - 26 870 - COM/Energy Freetown Realty 1 (18,832) (335) 25,000 - 1 5,833 360 COM/Energy Research Park Realty 1 1,045 296 - 455 1 886 - COM/Energy Cambridge Realty 1 74 (17) - - 1 57 - COM/Energy Acushnet Realty 1 558 66 - 100 1 524 - COM/Energy Services Company 3,250 337 49 - 49 3,250 337 - Commonwealth Electric Company 2,043,972 163,329 16,073 - 15,841 2,043,972 163,561 200 Hopkinton LNG Corp. 5,000 4,019 548 - 674 5,000 3,893 - $399,840 $52,735 $25,000 $49,671 $427,904 $13,360 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $ 9,660 $ 1,242 $ - $ 1,084 52,454 $ 9,818 Hydro-Quebec Phase II 137,442 3,861 508 - 567 137,442 3,802 Other Investments - 28 - - - - 28 $ 13,549 $ 1,750 $ - $ 1,651 $ 13,648 <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) Additional investment. <PAGE 75> SCHEDULE II COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (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, 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 Year Ended December 31, 1994 Allowance for Doubtful Accounts $7,761 $9,396 $2,138 $11,339 $7,956 <PAGE 76> COMMONWEALTH ENERGY SYSTEM FORM 10-K DECEMBER 31, 1996 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 27, 1997 William G. Poist, President and Chief Executive Officer Principal Financial and Accounting Officer: JAMES D. RAPPOLI March 27, 1997 James D. Rappoli, Financial Vice President and Treasurer A majority of the Board of Trustees: SHELDON A. BUCKLER March 27, 1997 Sheldon A. Buckler, Chairman of the Board PETER H. CRESSY March 27, 1997 Peter H. Cressy, Trustee March , 1997 Henry Dormitzer, Trustee B. L. FRANCIS March 27, 1997 Betty L. Francis, Trustee FRANKLIN M. HUNDLEY March 27, 1997 Franklin M. Hundley, Trustee <PAGE 77> COMMONWEALTH ENERGY SYSTEM FORM 10-K DECEMBER 31, 1996 SIGNATURES (Continued) WILLIAM J. O'BRIEN March 27, 1997 William J. O'Brien, Trustee WILLIAM G. POIST March 27, 1997 William G. Poist, Trustee MICHAEL C. RUETTGERS March 27, 1997 Michael C. Ruettgers, Trustee G. L. WILSON March 27, 1997 Gerald L. Wilson, Trustee <PAGE 78> 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, 1996 or performed any audit procedures subsequent to the date of our report. ARTHUR ANDERSEN LLP Boston, Massachusetts March 28, 1997.