<PAGE 1> UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 Form 10-K/A Amendment No. 2 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Mark One) [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________________ to ________________ Commission file number 1-7316 COMMONWEALTH ENERGY SYSTEM (Exact name of registrant as specified in its Declaration of Trust) Massachusetts 04-1662010 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One Main Street, Cambridge, Massachusetts 02142-9150 (Address of principal executive offices) (Zip Code) (617) 225-4000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Shares of Beneficial New York Stock Exchange, Inc. Interest $2 par value Pacific Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: Title of Class None Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ x ] Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES [ x ] NO [ ] Aggregate market value of the voting stock held by non-affiliates of the registrant as of March 16, 1998: $801,039,203 Common Shares outstanding at March 16, 1999: 21,540,550 shares Document Incorporated by Reference Part in Form 10-K None Not applicable <PAGE 2> COMMONWEALTH ENERGY SYSTEM 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 "Parent" and, together with its subsidiaries, is collectively referred to as "COM/Energy." The operating utility subsidiaries of the Parent have been engaged in the generation, transmission and distribution of electricity and the dis-tribution 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 Parent also owns all of the stock of a company that operates a total energy plant serving the Longwood Medical Area of Boston (Advanced Energy Systems, Inc.), a steam distribution company (COM/Energy Steam Company), a liquefied natural gas (LNG) and vaporization facility (Hopkinton LNG Corp.), a subsidiary that is pursuing energy-related business opportunities (COM/Energy Technologies, Inc.), and five real estate trusts. An energy marketing subsidiary, COM/Energy Marketing, Inc., sold its assets to Reliant Energy in February 1999. Subsidiaries of the Parent 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. Each of the operating utility subsidiaries serves retail customers except for Canal Electric Company (Canal Electric). Canal Electric operated an electric generating station located in Sandwich, Massachusetts until December 30, 1998 when it was sold pursuant to COM/Energy's electric industry restructuring plan that was approved by the Massachusetts Department of Telecommunications and Energy (DTE) and is consistent with the Electric Industry Restructuring Act passed by the Massachusetts legislature in 1997. The station consisted of Canal Unit 1, an oil-fired steam electric generating unit that was wholly-owned by Canal Electric with a rated capacity of 569 megawatts (MW), and Canal Unit 2, a steam electric generating unit with dual- fuel capability (oil and natural gas) that was jointly-owned by Canal Electric <PAGE 3> COMMONWEALTH ENERGY SYSTEM and Montaup Electric Company (Montaup) (an unaffiliated company) with a rated capacity of 580 MW. Canal Unit 2 was 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 327,000 year-round and 45,500 seasonal customers in 41 communities in eastern and southeastern Massachusetts covering 1,112 square miles and having an aggregate population of 645,000. The territory served includes the communities of Cambridge, New Bedford and Plymouth and the geographic area comprising Cape Cod and Martha's Vineyard. 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 239,000 customers in 51 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 Cambridge Electric or Commonwealth Electric 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. Advanced Energy Systems, Inc.'s principal assets include a total energy plant (MATEP) and related contracts that were acquired on June 1, 1998 from Harvard University. MATEP provides steam, electricity and chilled water services to several hospitals and professional schools in the Longwood Medical Area of Boston under long-term contracts that will remain in place until at least September 2015. Its major customers are Brigham and Women's Hospital, Beth Israel Deaconess Hospital, Dana-Farber Cancer Institute, the Joslin Diabetes Center, Children's Hospital and Harvard's medical, dental and public health schools. For additional information concerning MATEP, refer to Note 3(e) of Notes to Consolidated Financial Statements filed under Item 8 of this report. Steam, which was produced by Cambridge Electric in connection with the generation of electricity, was 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 COM/Energy companies is highly diversified. The larger industrial customers include high-technology firms and manufacturers of such products as photographic equipment and supplies, computer diskettes, rubber products, textiles, wire and other fastening devices, abrasives and grinding wheels, candy, copper and alloys, and chemicals. In December 1998, the Parent signed an Agreement and Plan of Merger with BEC Energy, the parent company of Boston Edison Company, that will create NSTAR, an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities. The merger is expected to occur shortly after the satisfaction of certain conditions, including receipt of certain regulatory approvals. The regulatory <PAGE 4> COMMONWEALTH ENERGY SYSTEM approval process is expected to be completed during the second half of 1999. Electric Power Supply On May 27, 1998, COM/Energy agreed to sell substantially all of its non- nuclear generating assets (984 MW) to affiliates of The Southern Company of Atlanta, Georgia. The sale was conducted through an auction process that was outlined in a restructuring plan filed with the DTE in November 1997 in conjunction with the state's industry restructuring legislation enacted in 1997. The sale was approved by the DTE on October 30, 1998 and by the FERC on November 12, 1998. Proceeds from the sale of these assets, after construction-related adjustments at the closing that occurred on December 30, 1998, amounted to approximately $453.9 million or 6.1 times their book value of approximately $74.2 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments, amounted to $358.6 million and will be used to reduce transition costs related to electric industry restructuring that otherwise would have been collected through a non- bypassable transition charge. Prior to December 30, 1998, COM/Energy owned generating facilities with a net capability at the time of peak load (1,004.7 MW on July 23, 1998) totaling 1,010.6 MW including 559.2 MW provided by Canal Electric Unit 1, of which three-quarters (419.4 MW) was sold to neighboring utilities under long- term contracts, and 275.7 MW was provided by Canal Unit 2. Another 126.1 MW was provided by various smaller units. Of the 541.6 MW available to COM/Energy, 63.1 MW was used principally for peaking purposes. Central Maine Power Company's Wyman Unit 4, an oil-fired facility in which COM/Energy had a 1.4% joint-ownership interest, provided 8.8 MW. A 3.52% ownership interest in the Seabrook 1 nuclear power plant provides 40.9 MW of capability to COM/Energy. In addition, through Canal Electric's equity ownership in Hydro-Quebec Phase II, COM/Energy 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. COM/Energy also receives 67 MW from a waste-to-energy plant and has entitlements totaling 23.4 MW through contracts with four hydroelectric sup- pliers. To satisfy demand requirements and provide required reserve capacity, COM/Energy supplemented 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 DTE. Pursuant to a restructured Power Sale Agreement (PSA), effective January 1, 1995, a non-utility generator (NUG) ceased supplying capacity and energy to Commonwealth Electric. The restructured PSA defers Commonwealth Electric's obligation to purchase the NUG's capacity and energy for a maximum of six years. COM/Energy also has available 84.8 MW from two operating nuclear units in which its distribution companies have life-of-the-unit contracts for power. Information with respect to these units is as follows: <PAGE 5> COMMONWEALTH ENERGY SYSTEM Vermont Yankee Pilgrim Year of Initial Operation 1972 1972 Contract Expiration Date 2012 2004 Equity Ownership (%) 2.50 - Plant Entitlement (%) 2.25 11.0 Plant Capability (MW) 531.0 668.9 COM/Energy Entitlement (MW) 11.2 73.6 Commonwealth Electric has an 11% contract entitlement in the output of the Pilgrim nuclear power plant, which is expected to be sold by Boston Edison Company (Boston Edison) in 1999 to Entergy Nuclear Generating Company (Entergy). In conjunction with this sale, Commonwealth Electric has reached an agreement with Boston Edison to buy out of this life-of-the-unit contract, terminating Commonwealth Electric's rights and obligations under the contract regarding the power output of the plant. Pursuant to the buy out agreement, Commonwealth Electric will pay between $100 million and $115 million to terminate this contract with Boston Edison, subject to adjustment at closing. The buy out is expected to be completed in the second quarter of 1999. In a transaction related to the sale of the Pilgrim plant, Commonwealth Electric will buy power generated by the Pilgrim plant from Entergy on a declining basis through 2004. Cambridge Electric has a 2.5% equity ownership in the Vermont Yankee nuclear power plant. Vermont Yankee has granted AmerGen Energy Co. an exclusive right to negotiate an agreement to buy the plant. Information relative to nuclear units that are no longer operating in which COM/Energy has an equity ownership is as follows: Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands) Year of Shutdown 1996 1997 1992 Equity Ownership (%) 4.50 4.00 4.50 Equity Ownership Balance $4,713 $3,476 $395 For additional information, refer to Note 3(d) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. Cambridge Electric, Canal Electric and Commonwealth Electric, together with other electric utility companies in the New England area, are members of Independent System Operator (ISO) - New England (formerly the New England Power Pool or NEPOOL), which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England. ISO - New England operates a centralized dispatching facility to ensure reliability of service and to dispatch the most economically available generating units of the member companies to fulfill the region's energy requirements. This concept is accomplished by use of computers to monitor and forecast load requirements. ISO - New England, on behalf of its members entered into an Interconnection Agreement with Hydro-Quebec, a Canadian utility operating in the Province of Quebec. The agreement provided for construction of an interconnection (referred to as the Hydro-Quebec Project-Phase I and Phase II) <PAGE 6> COMMONWEALTH ENERGY SYSTEM between the electrical systems of New England and Quebec. The parties also entered into an Energy Contract and an Energy Banking Agreement; the former which obligated Hydro-Quebec to offer ISO - New England participants up to 33 million MWH of surplus energy during an eleven-year term that began September 1, 1986 has since expired, and the latter provided for energy transfers between the two systems. ISO - New England 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 that began in late 1990. Canal Electric is obligated to pay its share of operating and capital costs for Phase II over a 25 year period ending in 2015. Future minimum lease payments for Phase II have an estimated present value of $11.1 million at December 31, 1998. In addition, Canal has an equity interest in Phase II which amounted to $2.8 million in 1998 and $3.1 million in 1997. COM/Energy's electric subsidiaries are also members of the Northeast Power Coordinating Council (NPCC), an advisory organization that includes the major power systems in New England and New York plus the Provinces of Ontario and New Brunswick in Canada. NPCC establishes criteria and standards for reliability and serves as a vehicle for coordination in the planning and operation of these systems. The reserve requirements used by the ISO - New England participants in planning future additions are determined by ISO - New England to meet the reliability criteria recommended by the NPCC. COM/Energy 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 Electric, 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 commitments under long-term power contracts, refer to Note 3(d) of Notes to Consolidated Financial Statements filed under Item 8 of this report. COM/Energy's 3.52% interest in the Seabrook nuclear power plant is owned by Canal Electric to provide for a portion of the capacity and energy needs of Cambridge Electric and Commonwealth Electric. For additional information concerning Seabrook 1, refer to Note 3(b) of Notes to Consolidated Financial Statements filed under Item 8 of this report. Commonwealth Electric and Cambridge Electric continue to evaluate bids related to capacity entitlements associated with power contracts in response to electric industry restructuring legislation enacted in Massachusetts in November 1997. <PAGE 7> COMMONWEALTH ENERGY SYSTEM Electric Fuel Supply (a) Oil and Natural Gas Of COM/Energy's total energy requirement for 1998, approximately 48% was generated using imported residual oil and approximately 30% was generated using natural gas. Effective March 15, 1998, Canal Electric executed a one-year contract with Coastal Refining and Marketing, Inc. (Coastal) for the purchase of 1% sulfur residual fuel oil. The contract provided for delivery of a set percentage of Canal Electric's fuel requirement, the balance (a maximum of 50%) to be met by spot purchases or by Coastal at the discretion of Canal Electric. Energy Supply & Credit Corporation (ESCO Massachusetts, Inc.) operated Canal's fuel oil terminal and managed the receipt of and payment for fuel oil under assignment of Canal Electric's supply contracts to ESCO Massachusetts, Inc. Residual fuel oil in the terminal's shore tanks was held in inventory by ESCO Massachusetts, Inc. and delivered upon demand to Canal Electric's two day tanks. During 1996, Unit 2 was converted to dual-fuel capability, residual fuel oil and natural gas. Canal Electric anticipated that dual-fuel capability would result in future savings as the least expensive fuel was utilized. (b) Nuclear Fuel Supply and Disposal Approximately 13% of COM/Energy's total energy requirement for 1998 was generated by nuclear plants. The nuclear fuel contract and inventory information for Seabrook 1 has been furnished to COM/Energy by North Atlantic Energy Services Corporation (NAESCO), the managing agent responsible for operation of the unit. Seabrook's requirement for nuclear fuel components are 100% covered through 2002 by existing contracts. There are no spent fuel reprocessing or disposal facilities currently operating in the United States. Instead, commercial nuclear electric gener- ating units operating in the United States are required to retain spent fuel on-site. As required by the Nuclear Waste Policy Act of 1982 (the Act), as amended, the joint-owners entered into a contract with the Department of Energy for the transportation and disposal of spent fuel and high level radioactive waste at a national nuclear waste repository or Monitored Retrievable Storage (MRS) facility. Owners or generators of spent nuclear fuel or its associated wastes are required to bear the costs for such transportation and disposal through payment of a fee of approximately 1 mill/KWH based on net electric generation to the Nuclear Waste Fund. Under the Act, a storage or disposal facility for nuclear waste was anticipated to be in operation by 1998; a reassessment of the project's schedule requires extending the completion date of the permanent facility until at least 2010. Seabrook 1 is currently licensed for enough on-site storage to accommodate spent fuel expected to be accumulated through at least the year 2010. <PAGE 8> COMMONWEALTH ENERGY SYSTEM Gas Supply Commonwealth Gas purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company (Tennessee) and Algonquin Gas Transmission Company (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines) and purchases all of its gas supplies from third-party vendors, utilizing firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil companies. In addition to firm transportation and gas supplies mentioned above, Commonwealth Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The underground storage contracts are a combination of existing and new agreements which are the result of Federal Energy Regulatory Commission (FERC) Order 636 service unbundling. The LNG facilities, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season. Commonwealth Gas entered into a multi-party agreement in 1992 to assume a portion of Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois Gas Transmission System and Tennessee pipelines. The ANE gas supply contract was filed with the DTE and hearings were completed in April 1993. The DTE approved the ANE gas supply contract in November 1995. Commonwealth Gas is 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, 1998, there were 593 customers using this transportation service, accounting for 11,146 BBTU or approximately 24% of total throughput. Hopkinton LNG Facility A portion of the gas supply for Commonwealth Gas during the heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of the Parent. The facility consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 million MCF of natural gas. In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG trucked from Hopkinton. Commonwealth Gas has contracts for LNG service with Hopkinton extending on a year to year basis with notice of termination required five years in advance of the anticipated termination date. Current contract payments include a demand charge sufficient to cover Hopkinton's fixed charges and an operating charge which covers liquefaction and vaporization expenses. Commonwealth Gas furnishes pipeline gas during the period April 15 to November 15 each year for liquefaction and storage. As the need arises, LNG is vaporized and placed in the distribution system of Commonwealth Gas. <PAGE 9> COMMONWEALTH ENERGY SYSTEM Based upon information presently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, Commonwealth Gas believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales. Rates, Regulation and Legislation Certain of COM/Energy's utility subsidiaries operate under the jurisdiction of the DTE which regulates retail rates, accounting, issuance of securities and other matters. In addition, Canal, Cambridge Electric and Commonwealth Electric file their respective wholesale rates with the FERC. Electric Industry (a) Restructuring Legislation On November 25, 1997, the Governor of Massachusetts signed into law the Electric Industry Restructuring Act (the Act). This legislation provided, among other things, that customers of retail electric utility companies who take standard offer service receive a 10 percent rate reduction and be allowed to choose their energy supplier, effective March 1, 1998. The Act also provides that utilities be allowed full recovery of transition costs subject to review and an audit process. The rate reduction mandated by the legisla- tion increases to 15 percent effective September 1, 1999 for customers who continue to take standard offer service. A statewide ballot referendum that sought to repeal the legislation was defeated by a wide margin on November 3, 1998. COM/Energy had filed a comprehensive electric restructuring plan with the DTE in November 1997, that was substantially approved by the DTE in February 1998. The divestiture of COM/Energy's non-nuclear generation assets and the entitlements associated with its purchased power contracts through an auction process was an integral part of COM/Energy's restructuring plan and is consistent with the Act. While COM/Energy is encouraged with the treatment afforded transition costs (which, for COM/Energy, are primarily the result of above-market purchased power contracts with NUGs that have not yet been sold) by the legislation and the DTE, the mandated rate reduction has had a significant impact on cash flows of COM/Energy. However, the successful sale of the generating assets, as discussed below, will reduce the negative impact that the rate reductions will have on future cash flows. On May 27, 1998, COM/Energy selected affiliates of Southern Energy New England, L.L.C. (Southern Energy), an affiliate of The Southern Company of Atlanta, Georgia, to buy substantially all of its non-nuclear electric generating assets. As a result of construction-related adjustments at the closing on December 30, 1998, the final amount of proceeds from the sale was approximately $454 million. COM/Energy did not agree to retain any material liabilities related to pre-closing occurrences. Southern Energy has assumed all material future liabilities associated with the generating assets that were sold. These facilities represented 984 megawatts (MW) of electric capacity and had a book value of $74 million. The plants sold include: Canal Unit 1 (566 mw) and a one-half interest in Canal Unit 2 (282.5 MW) located in Sandwich, MA and owned by Canal Electric; the Kendall Station facility (67 MW) and the adjacent Kendall Jets (46 MW), located in Cambridge, MA and owned by Cambridge Electric; five diesel generators (13.8 MW) in Oak Bluffs and West <PAGE 10> COMMONWEALTH ENERGY SYSTEM Tisbury on the island of Martha's Vineyard that are owned by Commonwealth Electric, and a 1.4 percent joint-ownership interest (8.9 MW) in Wyman Unit No. 4 located in Yarmouth, ME, also owned by Commonwealth Electric. COM/Energy continues to evaluate bids related to its purchased power contracts with NUGs. COM/Energy is also evaluating the disposition of the Blackstone Station generating unit (15.3 MW) owned by Cambridge Electric and located in Cambridge, MA that is subject to a right of first offer held by Harvard University on any divestiture of the facility. On July 31, 1998, a divestiture filing was submitted to the FERC and the DTE that requested approval of the sale of the generating assets to Southern Energy and further proposed (subject to completion of the sale) that the current 10 percent rate reduction increase, effective January 1, 1999. On October 30, 1998, the DTE approved COM/Energy's sale of assets to Southern Energy. However, at that time, the DTE deferred ruling on the allocation of the net proceeds from the sale of Canal Units 1 and 2 between Cambridge Electric and Commonwealth Electric and on the rate of return to be paid to customers on the net proceeds from the sale over an eleven-year period. The FERC approved the sale on November 12, 1998. On December 23, 1998, the DTE approved COM/Energy's proposal to establish a special purpose affiliate, Energy Investment Services, Inc. (EIS), that will administer the above-book value net proceeds from the sale of the Canal units with the goal of preserving capital and maximizing earnings for the benefit of retail customers. EIS will credit the proceeds and any return earned to the accounts of Commonwealth Electric and Cambridge Electric, resulting in a reduction in the transition costs to be billed to customers. In addition, COM/Energy agreed to pursue the buyout of above-market purchased power contracts, including the Pilgrim nuclear unit in which Commonwealth Electric has an 11% entitlement. This transaction is expected to occur in the second quarter of 1999. On December 23, 1998, the DTE approved the divestiture filing that was submitted to the FERC and the DTE on July 31, 1998 that requested approval of the sale of the generating assets to Southern Energy and further proposed (subject to completion of the sale which occurred December 30, 1998) that the 10 percent rate reduction increase, effective January 1, 1999, to approximately 12 percent for Commonwealth Electric and to approximately 16 percent for Cambridge Electric. In addition, the companies proposed to increase the retail price of standard offer service, starting January 1, 1999, from 2.8 cents per kilowatthour (kwh) to 3.5 cents. At the same time, the transition charge for Commonwealth Electric's customers declined from 4.08 cents per kwh to 3.159 cents and for Cambridge Electric's customers from 2.73 cents per kwh to 1.447 cents. These changes are intended to further reduce the cost of electricity to customers, to make the market increasingly more attractive for independent power suppliers to sell electricity directly to consumers, and to reduce cost deferrals associated with the pricing of standard offer service. No gain was recorded on the sale of the generating assets on a consoli- dated basis as COM/Energy is obligated to reduce Cambridge Electric's and Commonwealth Electric's transition costs by the net proceeds of the sale. <PAGE 11> COMMONWEALTH ENERGY SYSTEM (b) Unbundled Rates As a result of electric industry restructuring, both Commonwealth Electric and Cambridge Electric have unbundled their rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and have afforded custom- ers the opportunity to purchase generation supply in the competitive market. Unbundled delivery rates are composed of a customer charge (to collect metering and billing costs), a distribution charge (to collect the costs of delivering electricity), a transition charge (to collect past costs for investments in generating plants and costs related to power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant), an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Electricity supply services provided by COM/Energy include optional standard offer service and default service. Standard offer service is the electricity that is supplied by the local distribution company (such as Cambridge Electric and Commonwealth Electric) until a competitive power supplier is chosen by the customer. It is designed as a seven-year transitional service to give the customer time to learn about competitive power suppliers. The price of standard offer service will increase over time. Default service is the electricity that is supplied by the local distribution company when a customer is not receiving power from either standard offer service or a competitive power supplier. The market price for default service will fluctuate based on the average market price for power. Amounts collected through these various charges will be reconciled to actual expenditures on an on-going basis. As of December 31, 1998, approximately 90% of retail customers received standard offer service and approximately 10% of retail customers received default service. No retail customers received electricity supply services from competitive power suppliers during 1998. Prior to the implementation of industry restructuring on March 1, 1998, Commonwealth Electric and Cambridge Electric had Fuel Charge rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. These schedules required a quarterly computation and DTE approval of a Fuel Charge decimal based upon forecasts of fuel, purchased power, transmission costs and billed unit sales for each period. To the extent that collections under the rate schedules did not match actual costs for that period, an appropriate adjustment was reflected in the calculation of the next subsequent calendar quarter decimal. These rate schedules are no longer in effect. Also prior to March 1, 1998, Cambridge Electric and Commonwealth Elec- tric collected a portion of capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The recovery mechanism for these costs used a per kwh factor that was calculated using historical (test-period) capacity costs and unit sales. This factor was then applied to current monthly kwh sales. When current period capacity costs and/or unit sales varied from test-period levels, Cambridge Electric and Commonwealth Electric experienced a revenue excess or shortfall that had a significant impact on net income. However, as part of the settlement agree- ments approved by the DTE in May 1995, Cambridge Electric and Commonwealth Electric were allowed to defer these costs (within certain limits) which neutralized their sometimes volatile effect on net income. Both companies <PAGE 12> COMMONWEALTH ENERGY SYSTEM also had separately stated Conservation Charge rate schedules that allowed for current recovery, from retail customers, of conservation and load management costs. These rate schedules are no longer in effect. (c) Retail Choice Pilot Program Prior to March 1, 1998, the date retail choice was available for all customers, Commonwealth Electric had designed a program to allow a limited number of customers the opportunity to possibly reduce their electric bills while Commonwealth Electric learned more about real-time pricing and the administrative requirements associated with open-market competition. Through the program, Commonwealth Electric developed internal procedures for billing and allocating the costs for providing an alternative supply to its retail customers, and developed methods for educating customers regarding retail choice. The program was available to 18 commercial and industrial customers of Commonwealth Electric that took service under one of Commonwealth Electric's economic development rates. This program was discontinued on February 28, 1998. (d) Customer Transition Charge In September 1995, the DTE issued a ruling largely approving four rate tariffs, including a Customer Transition Charge (CTC), that were filed by Cambridge Electric on March 15, 1995. The CTC was intended to protect remaining customers from paying certain stranded costs that were incurred in the event that Cambridge Electric's largest customers discontinued full service, yet still remain connected for back-up and other services. These costs included long-term power contracts entered into to meet projected energy requirements, investments in substations, underground and overhead lines and current and future decommissioning costs associated with nuclear plants. This ruling is believed to be the first retail stranded cost charge approved nationally and follows the DTE's initial restructuring order which endorsed, in principle, the recovery of stranded costs. Through the CTC, Cambridge Electric recovered 75% of net stranded costs as calculated in its proposal. Cambridge Electric's other rates include a Supplemental Service Rate, a Standby Service Rate and a Maintenance Service Rate each of which were approved with only minor changes. Cambridge Electric was an intervenor in an appeal at the Massachusetts Supreme Judicial Court (SJC) filed by the Massachusetts Institute of Technology (MIT) involving this DTE decision approving the CTC for the recovery of stranded investment costs. By its terms, the CTC was terminated on March 1, 1998, coincident with the retail access date established by the Massachusetts Legislature in the Electric Industry Restructuring Act. On September 18, 1997, the SJC remanded the CTC matter to the DTE for further consideration. The SJC stated that, although recovery of prudent and verifiable stranded costs by utility companies is in the public interest and consistent with the Public Utility Regulatory Policies Act, the insufficiencies of the DTE's subsidiary findings precluded the SJC from undertaking a meaningful review of the DTE's calculations that formed the basis of the CTC. The DTE is in the process of determining whether to hear additional evidence in the remand or to rely on the record and pleadings already filed. <PAGE 13> COMMONWEALTH ENERGY SYSTEM (e) Wholesale Rate Proceedings The Town of Belmont Massachusetts Municipal Light Department (Belmont) is a municipally-owned utility that provides electric service to approximately 25,000 residential customers as well as commercial customers. Belmont purchases approximately 80 percent of its electric requirements from Cambridge Electric under a Net Requirements Power Supply Agreement (NRA). The balance of its electric requirements are currently purchased from the New York Power Authority (NYPA) and Boston Edison Company and transmitted to Belmont under a Transmission Services Agreement with Cambridge Electric. Belmont provides approximately 1% of consolidated electric revenue. Net Requirements Power Supply Agreement Cambridge Electric has provided electric service to Belmont for nearly a century. Historically, Belmont was a full-requirements customer of Cambridge Electric, purchasing a "bundled" power supply and transmission service. In 1985, however, when Belmont received an allocation of approximately two megawatts of low-cost "preference" power from NYPA, Cambridge Electric agreed to provide transmission service for Belmont's NYPA power under its firm transmission tariff, and to provide "bundled" power supply and transmission service for the remainder of Belmont's power needs under a "partial requirements" tariff. On March 8, 1993, Cambridge Electric filed, with the concurrence of Belmont, the NRA which was approved by FERC's June 18, 1993 letter order. Prior to approving the NRA however, FERC Staff advised Cambridge Electric that the cost-of-service formula in the NRA needed to be clarified and that Cambridge Electric should file such clarification at least sixty days prior to the April 1, 1998 date upon which the formula rate would become applicable under the NRA. In compliance with this requirement, on January 21, 1998, Cambridge Electric submitted a supplemental filing containing the clarification to the formula rate set forth in the NRA. On February 19, 1998, Belmont filed with the FERC a protest claiming that Cambridge Electric's November 1997 announcement of its intention to leave the power supply business would have profound implications for Belmont as they were served from Cambridge Electric's general mix of electric power and that the divestiture will result in unjust and unreasonable charges. On March 30, 1998, the FERC issued its order approving Cambridge Electric's filing to become effective April 1, 1998 subject to the outcome of the pending proceeding. On April 29, 1998 Belmont filed a request for rehearing alleging the FERC erred in its March 30 Order by accepting Cambridge Electric's proposed modifications to the NRA without hearing or suspension, and without requiring that Cambridge Electric explain the basis for its deletion of certain protective standards. On May 29, 1998, the FERC issued its order denying rehearing. Subsequently, Cambridge Electric and Belmont entered into negotiations to settle certain outstanding issues. An amendment to the NRA has been signed by both parties and a joint offer of settlement (Joint Offer) was filed January 15, 1999. Material terms of the settlement include: (i) a new fixed <PAGE 14> COMMONWEALTH ENERGY SYSTEM monthly Customer Charge and an Energy Charge that varies by calendar year to replace the existing rates and charges section of the NRA; (ii) resolution of a billing reconciliation issue under the NRA; (iii) satisfaction of the "hold harmless" commitment Cambridge Electric made to Belmont in the divestiture proceeding related to the sale of its generating assets; and (iv) a termination date of March 31, 2003. Cambridge Electric awaits FERC action on the Joint Offer. Transmission Services Agreement Cambridge Electric and Belmont entered into discussions in early 1993 to negotiate a transmission services agreement (TSA). However, there were significant differences between the parties and final negotiations were held in late February 1994. As Cambridge Electric and Belmont were unable to agree on the terms of a TSA, Cambridge Electric filed a proposed TSA with the FERC on June 29, 1994. Belmont intervened in the proceeding. The FERC set the TSA for hearing to determine whether or not it was consistent with a previous memorandum of understanding (MOU) and whether the transmission rates were just and reasonable. Cambridge Electric and Belmont settled on the rate of return before hearings started. After the hearing and filing of initial and reply briefs, on September 14, 1995, the presiding administrative law judge (ALJ) issued an initial decision. The ALJ found that: (i) the proposed transmission agreement rates were not just and reasonable and directed Cambridge Electric to revise the rates based on directly assigned facilities and further that use rights should be based on the same direct assigned facilities; (ii) the proposed transmission agreement, revised in accordance with the findings made in the decision, are consistent with the parties' MOU and; (iii) that Cambridge Electric's pre- existing firm transmission tariff rate is just and reasonable. On October 16, 1995, Belmont filed a motion for expedited review and issuance of decision. On July 2, 1998, Belmont renewed its motion for issuance of a decision. On July 20, 1998, the FERC issued its opinion and order and affirmed certain parts and reversed other parts of the initial decision. On August 19, 1998, both Cambridge Electric and Belmont filed requests for rehearing of the July 20, 1998 order each citing issues on which they felt the FERC had erred. On November 4, 1998, the FERC issued its opinion and order by granting a rehearing for certain issues and denying a rehearing for others. In the order on rehearing the FERC granted Cambridge Electric's rehearing request on the limited rate issue regarding the method for allocating operating and maintenance costs. The rehearing order resulted in Cambridge Electric being able to increase its transmission rate to Belmont. In addition to Cambridge Electric receiving increased transmission revenues in the future, the decision substantially reduced Cambridge Electric's refund obligation to Belmont. The FERC's rehearing order denied all of Belmont's <PAGE 15> COMMONWEALTH ENERGY SYSTEM rehearing requests including when Belmont has the ability to purchase rights- of-use from Cambridge Electric. The Order obligated Cambridge Electric to make a compliance filing to include the necessary revisions to the TSA. Once the FERC approved and accepted the compliance filing, Cambridge Electric would have 30 days to make refunds to Belmont, with interest, back to the refund effective date of January 29, 1995. On December 4, 1998, Cambridge Electric made its compliance filing. On December 28, 1998, Belmont filed its protest claiming Cambridge Electric's compliance filing contains proposed revisions to the TSA which were not directed by the FERC and therefore should be rejected. On January 4, 1999, Belmont filed with the United States Court of Appeals for the District of Columbia Circuit a petition for review of the July 20, 1998 and November 4, 1998 FERC orders. On January 12, 1999, Cambridge Electric filed its response to Belmont's December 28, 1998 protest. Cambridge Electric awaits FERC action on Belmont's protest. The uncontested material terms of the TSA provide that Cambridge Electric will offer both firm and non-firm transmission service over a defined contract period on its system to Belmont. Cambridge Electric will charge Belmont a FERC-approved rate for these services. Belmont also has the option to purchase rights-of-use under the TSA. The charges for these rights-of-use will be determined through the application of a FERC-approved methodology. Belmont is also responsible for monthly operation and maintenance expenses with respect to these rights-of-use. Billing under the TSA will occur monthly. The initial term of the TSA is through March 31, 2007. Belmont may terminate within this initial term upon three-years' notice. The initial term may be extended for up to five years if Belmont exercises its right to purchase rights-of-use over Cambridge Electric's system on or after April 1, 2003. Upon three-years' notice either party shall have the right to terminate the TSA after expiration of the initial term. The only remaining contested provisions of the TSA are those provisions at issue in a pending appeal filed by Belmont on January 4, 1999 before the United States Court of Appeals for the D.C. Circuit and those at issue in a pending request for rehearing filed by Cambridge Electric before the FERC. Belmont's appeal to the Court of Appeals for the D.C. Circuit involves the FERC's ruling that Cambridge Electric has the right to terminate any rights- of-use purchased by Belmont on three-years' notice. The FERC held that Cambridge Electric has the right to terminate the TSA, and with it the rights- of-use, on three-years' notice, finding that any rights-of-use purchased by Belmont are not property rights of Belmont. This appeal has not yet reached the briefing stage. Cambridge Electric has requested rehearing by the FERC of its decision that certain operating and maintenance expenses associated with a particular plant may not be directly assigned to Belmont but instead must be allocated using a plant ratio methodology. Different assignment methodologies result in different rates charged to Belmont. The request for rehearing is currently pending. <PAGE 16> COMMONWEALTH ENERGY SYSTEM (f) Transmission Rate Matters On March 29, 1995, the FERC issued two notices of proposed rulemaking concerning open access transmission and stranded costs. The FERC's notices proposed to remove impediments to competition in the wholesale bulk power marketplace and to bring more efficient, lower-cost power to electric consumers. On March 29, 1996, Cambridge Electric filed transmission tariffs that implemented the FERC's requirements for non-discriminatory open access transmission for both point-to-point and network service. The tariffs were accepted on May 17, 1996 to be effective on May 28, 1996, but the rates are subject to an investigation initiated by the FERC itself. A settlement with the FERC regarding this investigation was filed on February 6, 1997. On April 24, 1996, the FERC issued Order No. 888, a set of three inter- related 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 (OATTs) that conform to the FERC pro-forma tariff contained in Order No. 888. On July 9, 1996, Cambridge Electric and Commonwealth Electric filed OATTs 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 January 21, 1997, Cambridge Electric and Commonwealth Electric filed revised OATTs to be consistent with the recently filed NEPOOL OATT. On March 4, 1997, the FERC issued Order No. 888-A which required revisions to the tariffs filed in compliance with Order No. 888. Cambridge Electric and Commonwealth Electric filed their revised OATTs on July 14, 1997. On July 31, 1997, the FERC issued an order on the July 9, 1996 filings, approving the rates, pending the outcome of any outstanding proceedings. On November 25, 1997, the FERC issued Order No. 888-B requiring minor changes that did not require an additional filing. On July 31, 1998, Cambridge Electric filed a Settlement Agreement with FERC regarding the outstanding proceeding referred to in the Order. On September 31, 1998, following the filing of ISO - New England's revised OATT, Cambridge Electric and Commonwealth Electric filed revised OATTs for consistency with ISO - New England. On January 28, 1999. FERC approved the July 31, 1998 Settlement Agreement which applied to Cambridge Electric's July 9, 1996 OATT. Currently, Cambridge Electric and Commonwealth Electric are awaiting decisions by FERC on the OATTs filed after 1996. Gas Industry (a) Industry Restructuring Commonwealth Gas and eight other gas utilities initiated the Massachu- setts Gas Unbundling Collaborative (the Collaborative) on September 15, 1997, to explore and develop generic principles to achieve the goals set forth by the DTE. Collaborative participants represented a broad array of stakeholder interests including the utilities, natural gas marketers, interstate pipe- lines, producers, energy consultants, labor unions, consumer advocates and representatives for the DTE, the Massachusetts Attorney General's Office, and <PAGE 17> COMMONWEALTH ENERGY SYSTEM the Massachusetts Division of Energy Resources. On March 18, 1998, the Collaborative filed a report to the DTE that summarized its progress. The Collaborative reported that it had made substan- tial progress in the areas of rate unbundling and terms and conditions for unbundled services. The report also described at least two policy issues, capacity disposition and cost responsibility, on which the Collaborative's participants require specific regulatory guidance before completing a compre- hensive framework for the transition to a more competitive market structure. In response to this report, the DTE issued a Notice of Inquiry (NOI) to address the Collaborative's unresolved issues. On May 1, 1998, Commonwealth Gas filed initial written comments in the proceeding arguing in favor of a mandatory capacity assignment proposal. On June 8, 1998, the DTE, as part of the aforementioned NOI, received final comments regarding the feasibility of implementing comprehensive unbundling for all local distribution companies (LDCs) by November 1, 1998. On June 29, 1998, Commonwealth Gas and three other Massachusetts LDCs submitted unbundled rate settlements to the DTE for consideration. The DTE issued a procedural order regarding the NOI on July 2, 1998 which stated that the introduction of comprehensive unbundling for all classes of customers for all LDCs is not feasible by November 1, 1998. The DTE stated that unbundled rates for the four LDCs that filed settlements on June 29, 1998 (including Commonwealth Gas) shall be in place by November 1, 1998 and that comprehensive unbundling shall be implemented no later than April 1, 1999. Also, as part of the July 2, 1998 procedural order, the DTE ordered that a set of proposed Model Terms and Conditions be submitted by the Collaborative no later than July 15, 1998. A partial set of Model Terms and Conditions were submitted on July 10, 1998 that excluded provisions for capacity assignment as well as those related sections of the terms and conditions that required further development by the Collaborative once the issues being addressed in the NOI were resolved by the DTE. On August 15, 1998, the DTE approved the unbundled rate settlement submitted by Commonwealth Gas. Commonwealth Gas submitted compliance rates consistent with the settlement agreement on September 11, 1998, and unbundled rates became effective on November 1, 1998. On November 30, 1998 the DTE issued an order approving the partial set of Model Terms and Conditions that were submitted by the Collaborative on July 10, 1998. In response to that order, however, the ten gas companies partici- pating in the Collaborative informed the DTE that an April 1, 1999 implementa- tion date for comprehensive gas unbundling was no longer feasible due to the significant time required by the Collaborative to complete the Model Terms and Conditions once the unresolved issues in the aforementioned NOI were answered by the DTE, as well as the additional time required by the gas companies to develop the systems necessary to implement unbundling consistent with these provisions. On February 1, 1999, the DTE issued an order in the NOI with regard to capacity assignment and cost responsibility. The DTE found in favor of mandatory capacity assignment, where gas marketers would be required to accept the full cost and contractual obligations of the capacity that the gas companies had historically procured to serve their common customers. In <PAGE 18> COMMONWEALTH ENERGY SYSTEM support of its decision, the DTE determined that the capacity market in Massachusetts was not yet workably competitive to allow it to remove tradi- tional regulatory controls that were designed to ensure the reliability of gas service to customers. The DTE further reaffirmed that the LDCs must continue with their obligation to plan for and procure sufficient upstream capacity. Finally, the DTE found that alternative approaches to mandatory capacity assignment would result in transition costs that would conflict with the well-established policy on cost allocation. On February 17, 1999, the Collaborative reconvened to continue its work in completing the Model Terms and Conditions consistent with the DTE's order on capacity assignment with a goal to begin the implementation of comprehen- sive unbundling for all LDCs beginning in 1999. (b) Unbundled Rates New unbundled rates for Commonwealth Gas went into effect on November 1, 1998. The unbundled rates were developed in accordance with a Settlement Agreement reached by participants in the Massachusetts Gas Unbundling Collaborative (MGUC) that was filed with the Massachusetts Department of Telecommunications and Energy on June 29, 1998 and approved on August 15, 1998. The new unbundled rates reflect the separation of the Company's gas supply function from its local distribution function. Commencing with the billing month of November 1998, Commonwealth Gas has a Seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC) that provide for the recovery, from firm customers or Default Service customers, of certain costs previously recovered through base rates. The CGAC provides for rates that must be approved semi-annually by the DTE. The LDAC provides for rates that require annual approval. As part of its new unbundled rates, Commonwealth Gas modified its existing CGAC to allow for the following changes: (a) the addition of provisions that allow for the recovery of certain bad-debt expenses; (b) new formulas that no longer adjust the Gas Adjustment Factors for the seasonal embedded gas costs that were in existing sales rates; (c) updated language reflecting the ratemaking requirements for non-core revenue margins; and (d) the removal of provisions for the recovery of environmental remediation costs and FERC Order 636 transition costs, which will instead be recovered through the LDAC. Commonwealth Gas' new LDAC recovers conservation charges, environmental remediation costs, balancing penalty revenue credits, and costs associated with the its participation in the MGUC. Competition COM/Energy continues to develop and implement strategies that deal with the restructured utility industry. The planned merger with BEC Energy, the sale of substantially all its non-nuclear generating assets and the purchase of MATEP are actions that are indicative of COM/Energy's commitment to seeking competitive advantages and other benefits by taking advantage of its strengths. For a more detailed discussion of the pending merger with BEC Energy, refer to the "Merger with BEC Energy" section of Management's Discussion and Analysis of Financial Condition and Results of Operations filed <PAGE 19> COMMONWEALTH ENERGY SYSTEM under Item 7 of this report. For additional information concerning the purchase of MATEP, refer to Note 3(e) of Notes to Consolidated Financial Statements filed under Item 8 of this report. On February 6, 1997, due to the dramatically changing nature of the electric and gas industries, COM/Energy announced the consolidation of management personnel of Commonwealth Electric, Commonwealth Gas and COM/Energy Services Company effective on that date. The companies continue to operate under their existing company names. The consolidation process for these companies involved the merging of similar functions and activities to eliminate duplication in order to create the most efficient and cost-effective operation possible. In addition, COM/Energy initiated a voluntary personnel reduction program during the second quarter of 1997 which reduced the total number of regular employees by approximately 13%. COM/Energy has reduced its full-time work force approximately 37% since 1990. Also, the introduction of advanced technologies in the workplace continues to improve customer service and COM/Energy's competitive position. Segment Information COM/Energy 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 and own and operate a cogeneration plant that provides the Longwood Medical Area of Boston with heating, chilled water service and electricity. Other operations of COM/Energy include the pursuit of new business opportunities and the operation of rental properties and other investment activities which do not presently contribute significantly to either revenues or operating income. Reference is made to additional industry segment information in Note 11 of Notes to Consolidated Financial Statements filed under Item 8 of this re- port. Environmental Matters COM/Energy is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. COM/Energy's compliance with these laws and regulations will require capital expenditures of $585,000 from 1999 through 2003 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 COM/Energy's financing and construction programs refer to Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 and Note 3(a) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. <PAGE 20> COMMONWEALTH ENERGY SYSTEM Employees The total number of full-time employees for COM/Energy declined by approximately 5% to 1,638 in 1998 from 1,727 employees at year-end 1997. Of the current total, 1,029 (63%) are represented by various collective bargaining units covered by separate contracts with expiration dates ranging from March 2001 through April 2003. Although a labor dispute with one collective bargaining unit occurred during 1996, employee relations have generally been satisfactory since the dispute was resolved in September 1996. <PAGE 21> COMMONWEALTH ENERGY SYSTEM 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: 1998 1997 1996 Per Per Per Amount Share Amount Share Amount Share (Dollars in thousands except per share amounts) Electric........... $34,234 $1.59 $34,811 $1.62 $39,667 $1.85 Gas................ 12,214 .57 14,681 .68 16,229 .75 Other.............. 7,026 .32 (579) (.03) 2,229 .10 Total.......... $53,474 $2.48 $48,913 $2.27 $58,125 $2.70 Parent company earnings and dividends on preferred shares were allocated among the electric, gas and other operations of COM/Energy based on the Parent's equity investment in each segment. 1998 versus 1997 Earnings per share for the year 1998 were $2.48 compared to the $2.27 achieved in 1997 and include a one-time gain of 50 cents per share from the sale of real estate. Earnings for 1997 include a one-time after-tax charge of 50 cents per share that related to a voluntary Personnel Reduction Program (PRP). Excluding these one-time items, the decline in earnings for the year was due to an increase in other operation expense (19 cents) reflecting costs associated with outsourcing the information technology, telecommunications and network services function (including costs related to Year 2000 compliance) net of PRP savings. Other factors that negatively impacted earnings were a 17% decline in firm gas sales (27 cents), a revenue shortfall related to demand-side management activity (25 cents), higher interest costs (10 cents), costs associated with new business development (4 cents) and costs related to supporting the industry restructuring referendum question on the November 1998 ballot (2 cents). Factors that had a positive impact on earnings were the labor savings realized from the PRP, a decline in the provision for bad debts (6 cents) and an increase in retail electric sales (2 cents). 1997 versus 1996 Earnings per share for the year 1997 were $2.27 compared to the record level of $2.70 achieved in 1996. Excluding the aforementioned PRP, factors that had a positive impact on earnings for the year were lower operating and maintenance expenses (25 cents) that resulted, in part, from the PRP, an increase in electric unit sales (11 cents) and the absence in 1997 of costs associated with a labor dispute in 1996 (13 cents). Earnings for 1997 were negatively affected by the absence of a 1996 refund associated with a power contract settlement agreement (11 cents), lower firm gas unit sales (8 cents), costs associated with new business development (12 cents), the absence of a 1996 recognition of the recoverability of costs associated with Canal Electric Company's postretirement benefits costs that were subsequently recovered in <PAGE 22> COMMONWEALTH ENERGY SYSTEM wholesale rates (5 cents) and a lower investment base on generation assets (6 cents). In March 1998, the Parent's Board of Trustees increased the quarterly dividend rate per share 2.5% from 39 1/2 cents to 40 1/2 cents ($1.62 on an annualized basis). This was the third consecutive year and the fourth time in five years that the Board had voted to increase the quarterly dividend rate. Dividends paid to common shareholders in 1998 were $34.9 million, representing a payout ratio of 65% of 1998 earnings per share. Electric Operations Operating revenues from regulated operations for 1998 were $75.7 million (11%) lower than in 1997 due primarily to a 10 percent rate reduction (further discussed below) and decreases in electricity purchased for resale and fuel charges ($58.8 million). The decline in these costs reflects a cost deferral of $42.5 million in conjunction with COM/Energy's restructuring plan as approved by the Massachusetts Department of Telecommunications and Energy (DTE). As a result of electric industry restructuring, COM/Energy has unbun- dled its rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and has afforded customers the opportunity to purchase genera- tion supply in the competitive market. Delivery rates are composed of a customer charge (to collect metering and billing costs), a distribution charge, a transition charge (to collect stranded costs), a transmission charge, an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge. Electricity supply services provided by COM/Energy include optional standard offer service and default service. Amounts collected through these various charges will be reconciled to actual expenditures on an on-going basis. For additional information concerning electric industry restructuring, refer to the Rates, Regulation and Legislation section filed under Item 1 of this report. Operating revenues from two non-regulated subsidiaries increased $23.8 million. Electric operating revenues from regulated operations for 1997 increased $38.8 million (6%) due to greater wholesale sales reflecting the changing capacity needs of non-affiliated utilities ($11.7 million) and the Independent System Operator (ISO) - New England (the agency that operates a centralized facility to ensure reliability of service and dispatch of economically available generating units throughout New England) ($11 million) and higher retail unit sales ($2.4 million). Offsetting these factors was the absence of a $4 million refund associated with a 1996 power contract settlement agreement and lower revenues ($2.1 million) due to the return allowed on Canal Electric's declining investment base. Unit sales (in Megawatthours or MWH) were as follows: % % 1998 Change 1997 Change 1996 Residential.......... 1,814,258 (0.9) 1,830,793 1.5 1,802,973 Commercial........... 2,560,433 2.2 2,506,215 3.1 2,430,188 Industrial and other. 458,877 (0.5) 459,104 2.1 449,844 Total retail..... 4,833,568 0.8 4,796,112 2.4 4,683,005 Wholesale............ 4,030,454 2.9 3,916,974 43.9 2,721,623 Total............ 8,864,022 1.7 8,713,086 17.7 7,404,628 <PAGE 23> COMMONWEALTH ENERGY SYSTEM In 1998 and 1997, retail unit sales increased due to strong commercial sector sales and approximately 5,700 (1.5%) and 4,200 (1.2%) additional customers, respectively, most of which are permanent year-round residential and commercial customers. In 1998, the increase in the level of wholesale sales primarily reflected increased sales to non-associated utilities, and to a lesser extent, increased sales to the Town of Belmont and to ISO - New England. The change in wholesale sales in 1997 reflected the increased availability of Canal Unit 1 and greater sales to ISO - New England. The changes in wholesale unit sales have little, if any, impact on net income. The $38.1 million increase (10.7%) in fuel and purchased power costs in 1997 was due primarily to higher wholesale unit sales and higher costs for replacement power due to the shutdown for repairs of both Connecticut Yankee and Maine Yankee in mid- and late-1996, respectively. These units remained out of service until their permanent shutdown in December 1996 and August 1997, respectively. Gas Operations Operating revenues from regulated operations decreased $41.9 million (12.7%) during 1998 due primarily to the considerable decline in firm unit sales. Operating revenues from an unregulated subsidiary increased $14.1 million. Also affecting revenues in both periods was a lower average cost of gas. In 1997, operating revenues from regulated operations decreased $11 million (3.2%) primarily due to a 5.6% decline in firm unit sales ($11.1 million) and lower conservation and load management (C&LM) costs ($1.8 million), offset by an increase in transportation revenues of $1.8 million and revenues from sales of gas to third parties of $3.9 million. Operating revenues from an unregulated subsidiary increased $3.1 million. Unit sales and transportation volume (in billions of British thermal units or BBTU) were as follows: % % 1998 Change 1997 Change 1996 Residential......... 19,514 (11.5) 22,043 (3.1) 22,759 Commercial.......... 8,965 (19.1) 11,077 (4.2) 11,558 Industrial and other 3,524 (37.0) 5,594 (16.2) 6,676 Total firm....... 32,003 (17.3) 38,714 (5.6) 40,993 Off-system.......... 4,429 65.7 2,673 10.5 2,420 Interruptible and other 1,658 (14.2) 1,933 (34.5) 2,949 Total sales...... 38,090 (12.1) 43,320 (6.6) 46,362 Transportation...... 9,230 41.9 6,506 34.1 4,852 Total............ 47,320 (5.0) 49,826 (2.7) 51,214 The decrease in unit sales to firm customers in 1998 reflects the impact of the milder weather conditions experienced during the year on all customer segments. The fluctuation in interruptible and other sales reflects the competitive market that exists today in the natural gas industry. A portion of the margin realized on these sales reduced the cost of gas sold to firm customers. Degree days for the current year totaled 5,754, 11% lower than last year and 12.1% below the normal level of 6,541. <PAGE 24> COMMONWEALTH ENERGY SYSTEM The decline in firm unit sales in 1997 was due to decreases to all customer segments that reflected milder weather experienced in the region during the first quarter as compared to a colder period in 1996. Degree days for 1997 totaled 6,463, 3.6% lower than 1996 and 1.2% below normal. Other Operating Expenses In 1998, other operation increased $9.8 million (4.3%), despite reflecting the absence of a one-time charge ($17.7 million) related to the aforementioned PRP, due to higher costs related to the outsourcing of the information tech- nology, telecommunications and network services function ($13.3 million) that includes costs associated with Year 2000 compliance, costs associated with new business development ($13.3 million), increased C&LM costs ($5 million) and higher costs associated with real estate operations ($1.3 million). These increases were offset, in part, by a decline in insurance and employee benefits costs ($1.1 million) and labor savings from the PRP, the absence of storm damage costs related to an April 1997 blizzard ($2 million) and a decline in the provision for bad debts ($2.1 million). Other operation in 1997 increased $10.3 million (4.8%) due to a one-time charge related to the aforementioned PRP, costs associated with new business development ($3.6 million), and an increase in the provision for bad debts ($1.4 million) that reflected higher reserve requirements. The impact of these factors was offset, in part, by lower operating costs ($5 million) that resulted, in part, from the PRP, lower pension costs ($2.7 million) and the absence of costs related to the 1996 labor dispute ($4.6 million). Maintenance increased $3 million (8.2%) in 1998 due to the addition of the Medical Area Total Energy Plant (MATEP) facility ($1.9 million) and greater expenses related to Canal Unit 1 boiler plant and related equipment. In 1997, maintenance declined $4.1 million (10%) and resulted from a reduction in transmission and distribution-related projects and, to a lesser extent, the PRP. Depreciation increased $7.6 million (14.2%) during 1998 and reflects the treatment allowed for certain production plant pursuant to the electric industry restructuring legislation as well as a higher level of depreciable plant including the newly acquired MATEP facility. Depreciation increased $1.6 million (3.1%) in 1997 due to additions to property, plant and equipment, that included the costs associated with the conversion of Canal Unit 2 in mid- 1996 to burn natural gas as well as oil. Federal and state income taxes decreased $4.8 million (15.4%) during 1998 reflecting the level of pre-tax income related to normal operations. The tax impact from the sale of real estate ($6.3 million) was reflected as an offset to the gain from the sale in Other Income on the Consolidated Statements of Income. Federal and state income taxes decreased $4.8 million (13.4%) during 1997 due mainly to the lower level of pre-tax income. The increase of $823,000 (2.9%) in local property and other taxes for 1998 was due primarily to real estate taxes associated with MATEP and higher real estate tax rates and assessments offset, in part, by a decline in payroll taxes attributable to savings realized from the aforementioned PRP. Local property and other taxes were higher during 1997 due to higher property tax <PAGE 25> COMMONWEALTH ENERGY SYSTEM rates and assessments within COM/Energy's service territory and an increase in payroll-related taxes due to a 1996 labor dispute. Other Income In 1998, other income increased $9.9 million due to the gain from the aforementioned sale of real estate ($10.8 million net of taxes). In 1997, other income decreased $2 million due primarily to the absence of a 1996 recognition of the recoverability of costs associated with Canal Electric's postretirement benefits ($1.8 million) following Federal Energy Regulatory Commission (FERC) approval, and the absence of a gain from the sale of real estate ($402,000 net of taxes) in 1996. Interest Charges The $6.6 million (16.3%) increase in total interest charges for 1998 resulted from higher levels of short-term borrowings, the full impact from the issuance of two series of long-term debt in September 1997 and the issuance of new long-term debt in the third quarter of 1998, partially offset by maturing long-term debt and scheduled sinking fund payments. The $2 million decline in total interest charges for 1997 was due to maturing long-term debt and scheduled sinking fund payments partially offset by a slightly higher average level of short-term borrowings. Liquidity and Capital Resources Financial Condition COM/Energy's cash requirements are essentially met through the generation of cash flows from the sale of electricity, natural gas (including liquefied natural gas), steam and chilled water. Cash requirements for current opera- tions, construction programs, debt service and other capital requirements are maintained through internal generation and short-term borrowings made avail- able through COM/Energy's credit lines with banks which totaled $132 million at December 31, 1998. Interest rates on short-term borrowings generally are at an adjusted money market rate. (See Note 6(a) of Notes to Consolidated Financial Statements for additional information.) Long-term debt issues are used to permanently finance short-term debt when deemed appropriate by management. The Parent, through its Advanced Energy Systems, Inc. subsidiary (AES), purchased the MATEP total energy plant, that was formerly owned and operated by Harvard University and is located in the Longwood Medical Area of Boston, and related contracts, for $146.3 million on June 1, 1998. This acquisition was ultimately financed with a $40 million equity contribution from the Parent to AES (financed with a 2-year variable rate term note issued by the Parent) and $112.5 million in 23-year term notes at a rate of 6.924% with quarterly sinking fund payments scheduled to begin September 30, 2003 that escalate from $790,000 to $2.7 million at the end of the term. The 2-year term note will be repaid in two installments of $20 million each on July 1, 1999 and July 1, 2000. The variable interest rate averaged 5.673% for 1998. The 23-year term notes are secured by long-term contracts between MATEP and its customers. This new venture increased revenues by approximately $34 million in 1998 and it is projected that annual revenues from this facility will average approxi- mately $60 million in the years 1999 through 2003. <PAGE 26> COMMONWEALTH ENERGY SYSTEM COM/Energy's 1998 net cash flow from operating activities ($81.9 million) exceeded funds required to support normal additions to property, plant and equipment. The improved cash flow position also reflects proceeds from the sale of COM/Energy's generating assets and real estate ($466.6 million). No gain was recorded on the sale of the generating assets on a consolidated basis as COM/Energy is obligated to reduce Cambridge Electric's and Commonwealth Electric's transition costs by the net proceeds of the sale. The year's cash requirements for the payment of preferred and common divi- dends ($35.9 million), the payment of maturing long-term debt and sinking fund requirements ($102.1 million) and the repayment of short-term borrowings ($92.1 million) were provided from operations and proceeds from the issuance of long-term debt ($152.5 million) and the sale of assets. Other information on the sources and uses of cash for the past three years is included in the Consolidated Statements of Cash Flows. On February 12, 1999, the holders of the Parent's Cumulative Preferred Shares (Series A 4.80%, Series B 8.10% and Series C 7.75%) were notified that each series will be redeemed in full effective April 1, 1999. The redemption price of $102 for Series A and $101 for each of Series B and C, plus accrued dividends will be paid upon redemption. Capital Requirements ------------------------------------------------------------------- Bar graph illustration of comparative two-year (1997-1998) actual and five-year (1999-2003) forecast of capital requirements based on values listed in chart below. ------------------------------------------------------------------- Forecast 1997 1998 1999 2000 2001 2002 2003 (Dollars in millions) Construction- Electric $ 35 $ 38 $ 38 $ 38 $ 41 $ 41 $ 44 Gas 18 19 19 18 19 19 19 Other 4 3 6 10 5 5 5 Maturing Debt 23 102 48 27 5 37 20 Purchase of MATEP - 146 - - - - - Retirement of Preferred Shares - - 11 - - - - $ 80 $308 $122 $ 93 $ 70 $102 $ 88 Capital Requirements and Resources COM/Energy's projected capital expenditures for the years 1999 through 2003 are $475.8 million, including $122.1 million for 1999 that consists of $63.4 million for construction expenditures and $58.7 million for maturing debt, sinking fund payments and the redemption of the preferred shares. These 1999 expenditures will be met through a combination of long and short-term debt issues and internally-generated funds. COM/Energy's goal is to maintain a capital structure that preserves an <PAGE 27> COMMONWEALTH ENERGY SYSTEM appropriate balance between debt and equity. Management believes its capital resources and liquidity are sufficient to meet its current and projected requirements. COM/Energy's capitalization structure is presented below: 1998 1997 (Dollars in thousands) Long-term debt $434,602 48.4% $383,311 41.7% Preferred shares 11,380 1.3 12,200 1.3 Common equity 449,592 50.1 430,770 46.8 Short-term debt 2,000 0.2 94,075 10.2 Total capitalization $897,574 100.0% $920,356 100.0% Capitalization ------------------------------------------------------------------- Bar graph illustration of comparative five-year (1999-2003) forecast of capitalization components based on values listed in chart below. ------------------------------------------------------------------- Forecast 1999 2000 2001 2002 2003 (Dollars in millions) Common Equity $ 474 45% $ 488 46% $ 509 47% $ 537 49% $ 566 51% Long-term Debt 480 46 454 43 447 42 435 40 540 48 Short-term Debt 92 9 120 11 121 11 114 11 7 1 $1,046 100% $1,062 100% $1,077 100% $1,086 100% $1,113 100% Forward-Looking Statements This discussion contains statements which, to the extent it is not a recitation of historical fact, constitute "forward-looking statements" and is intended to be subject to the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995. A number of important factors affecting the Parent's business and financial results could cause actual results to differ materially from those reflected in the forward-looking statements or projected amounts. Those factors include developments in the legislative, regulatory and competitive environment, certain environmental matters, demands for capital and new business development expenditures and the availability of cash from various sources. <PAGE 28> COMMONWEALTH ENERGY SYSTEM Merger with BEC Energy The electric utility industry has continued to change in response to legislative and regulatory mandates that are aimed at lowering prices for energy by creating a more competitive marketplace. These pressures have resulted in an increasing trend in the electric industry to seek competitive advantages and other benefits through business combinations. On December 5, 1998, the Parent and BEC Energy (BEC), headquartered in Boston, Massachusetts, entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, the Parent and BEC will be merged into a new holding company to be known as NSTAR. Holders of Parent common shares will receive 1.05 shares of NSTAR common stock for each share held while BEC common shareholders will receive one share of NSTAR common stock for each share held. In addition, current Parent and BEC common shareholders have the right to receive cash rather than NSTAR common stock in the amount of $44.10 for each share held, up to an aggregate maximum of $300 million. At the close of the merger, Parent shareholders will own approximately 32% of NSTAR common stock and BEC shareholders will own approximately 68%. The merger is expected to occur shortly after the satisfaction of certain conditions, including the receipt of certain regulatory approvals including that of the DTE. The regulatory approval process is expected to be completed during the second half of 1999. The merger will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts, including more than one million electric customers in 81 communities and 240,000 gas custom- ers in 51 communities. Shareholder votes on the merger will be held as part of each of the Parent's and BEC's annual shareholder meetings scheduled for the second quarter of 1999. The Merger Agreement may be terminated under certain circumstances, including by any party if the merger is not consummated by December 5, 1999, subject to an automatic extension of six months if the requisite regulatory approvals have not yet been obtained by such date. The merger will be accounted for using the purchase method of accounting. Upon effectiveness of the merger, Thomas J. May, BEC's current Chairman, President and Chief Executive Officer (CEO), will become the Chairman and CEO of NSTAR. Russell D. Wright, the Parent's current President and CEO, will become the President and Chief Operating Officer of NSTAR and will serve on NSTAR's board of directors. Also, upon effectiveness of the merger, NSTAR's board of directors will consist of the Parent's and BEC's current trustees. Provisions of Statement of Financial Accounting Standards No. 71 As described in Note 2(b) of the Notes to Consolidated Financial State- ments, COM/Energy follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In the event COM/Energy is somehow unable to meet the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations in an amount that could be material. Conditions that could give rise to the discontinuance of SFAS No. 71 include: 1) increas- ing competition restricting COM/Energy's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in <PAGE 29> COMMONWEALTH ENERGY SYSTEM which rates are set by regulators. COM/Energy monitors these criteria to ensure that the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, COM/Energy believes that its retail electric utility operations, excluding generation-related assets, remain subject to SFAS No. 71 and its regulatory assets, including those related to electric generation, remain probable of future recovery. As a result of electric industry restructuring, COM/Energy's retail electric companies discontinued application of accounting principles applied to their investment in electric generation facilities effective March 1, 1998. COM/Energy will not be required to write off any of its generation-related assets, including regulatory assets. These assets have been retained on the Consolidated Balance Sheets because the legislation and the DTE's plan for a restructured electric industry specifically provide for their recovery through the non-bypassable transition charge. Year 2000 The Year 2000 issue is the result of computer programs being written using two digits rather than four to define the applicable year. Any computer program that has date sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a temporary inability to process transactions or engage in normal business activities. COM/Energy has been involved in Year 2000 compliancy since 1996. COM/Energy, on a coordinated basis and with the assistance of RCG Informa- tion Technologies and other consultants, is addressing the Year 2000 issue. COM/Energy has followed a five-phase process in its Year 2000 compliance efforts, as follows: Awareness (through a series of internal announcements to employees and through contacts with vendors); Inventory (all computers, applications and embedded systems that could potentially be affected by the Year 2000 problem); Assessment (all applications or components and the impact on overall business operations and a plan to correct deficiencies and the cost to do so); Remediation (the modification, upgrade or replacement of deficient hardware and software applications and infrastructure modifications); and Testing (a detailed, comprehensive testing program for the modified critical component, system or software that involves the planning, execution and analysis of results). COM/Energy's inventory phase required an assessment of all date sensitive information and transaction processing computer systems and determined that approximately 90% of its software systems needed some modifications or replacement. Plans were developed and are being implemented to correct and test all affected systems, with priorities assigned based on the importance of the activity. COM/Energy has identified the software and hardware installa- tions that are necessary. All installations are expected to be completed and tested by mid-1999. COM/Energy has also inventoried its non-information technology systems that may be date sensitive (facilities, electric and gas operations, energy supply/production and distribution) that use embedded technology such as micro-controllers and micro-processors. COM/Energy has completed its assess- ment of these non-information technology systems and determined that 20% of <PAGE 30> COMMONWEALTH ENERGY SYSTEM these systems required remediation or replacement. COM/Energy is approxi- mately 86% complete in its efforts to resolve non-compliance with Year 2000 requirements related to these systems and anticipates that these systems will be updated or replaced as necessary and tested by mid-1999. At present, the remediation phase for information technology as it applies to hardware and non-technology issues is scheduled for completion by June 1, 1999. The testing phase for Year 2000 compliance is approximately 70% complete and is scheduled to be concluded by June 30, 1999. All other phases are complete. Modifying and testing COM/Energy's information and transaction processing systems from 1996 through 2000 is currently expected to cost approximately $7 million, including approximately $900,000 incurred through 1997 and $3.1 million spent in 1998. Approximately $3 million is expected to be spent in 1999 and 2000. Year 2000 costs have been expensed as incurred and will continue to be funded from operations. In addition to its internal efforts, COM/Energy has initiated formal communications with its significant suppliers to determine the extent to which COM/Energy may be vulnerable to its suppliers' failure to correct their own Year 2000 issues. As of February 1, 1999, COM/Energy has received responses from approximately 75% of those entities contacted, and nearly all have indicated that they are or will be Year 2000 compliant. Failure of COM/Energy's significant suppliers to address Year 2000 issues could have a material adverse effect on COM/Energy's operations, although it is not possible at this time to quantify the amount of business that might be lost or the costs that could be incurred by COM/Energy. Contact with significant vendors is continuing and inadequate or marginal responses are being pursued by COM/Energy. COM/Energy is prepared to replace certain suppliers or to initiate other contingency plans should these vendors not respond to COM/Energy's satisfaction by July 1, 1999. In addition, parts of the global infrastructure, including national banking systems, electrical power grids, gas pipelines, transportation facilities, communications and governmental activities, may not be fully functional after 1999. Infrastructure failures could significantly reduce COM/Energy's ability to acquire energy and its ability to serve its customers as effectively as they are now being served. COM/Energy is identifying elements of the infrastructure that are critical to its operations and is obtaining information as to the expected Year 2000 readiness of these ele- ments. COM/Energy has started its contingency planning for critical operational areas that might be effected by the Year 2000 issue if compliance by COM/Energy is delayed. COM/Energy gas and electric operations currently have emergency operating plans as well as information technology disaster recovery plans as components of its standard operating procedures. These plans will be enhanced to identify potential Year 2000 risks to normal operations and the appropriate reaction to these potential failures including contingency plans that may be required for any third parties that fail to achieve Year 2000 compliance. All necessary contingency plans are expected to be completed by June 30, 1999, although in certain cases, especially infrastructure failures, <PAGE 31> COMMONWEALTH ENERGY SYSTEM there may be no practical alternative course of action available to COM/Energy. COM/Energy is working with other energy industry entities, both regionally and nationally with respect to Year 2000 readiness and is cooperating in the development of local and wide-scale contingency planning. While COM/Energy believes its efforts to address the Year 2000 issue will allow it to be successful in avoiding any material adverse effect on COM/Energy's operations or financial condition, it recognizes that failing to resolve Year 2000 issues on a timely basis would, in a "most reasonably likely worst case scenario," significantly limit its ability to acquire and distrib- ute energy and process its daily business transactions for a period of time, especially if such failure is coupled with third party or infrastructure failures. Similarly, COM/Energy could be significantly effected by the failure of one or more significant suppliers, customers or components of the infrastructure to conduct their respective operations after 1999. Adverse affects on COM/Energy could include, among other things, business disruption, increased costs, loss of business and other similar risks. The foregoing discussion regarding Year 2000 project timing, effective- ness, implementation and costs includes forward-looking statements that are based on management's current evaluation using available information. Factors that might cause material changes include, but are not limited to, the availability of key Year 2000 personnel, the readiness of third parties, and COM/Energy's ability to respond to unforeseen Year 2000 complications. Environmental Matters Commonwealth Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether Commonwealth Gas may be responsible for remedial actions. In April 1998, Commonwealth Gas recorded an additional liability and corresponding regulatory asset of $500,000 due to an increase in the site clean-up cost estimate for an MGP site for which Commonwealth Gas was previously cited as a Potentially Responsible Party. The DTE has approved recovery of costs associated with MGP sites. Commonwealth Gas and certain other COM/Energy subsidiaries are also involved in other known or potentially contaminated sites where the associated costs may not be recoverable in rates and have recorded in prior years an estimated liability (and a charge to operations) of $1.8 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. COM/Energy is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of COM/Energy'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 COM/Energy's results of operations or financial position. On January 1, 1997, COM/Energy adopted the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 pro- vides authoritative guidance for recognition, measurement, display and <PAGE 32> COMMONWEALTH ENERGY SYSTEM disclosure of environmental remediation liabilities in financial statements. COM/Energy has recorded environmental remediation liabilities net of amounts paid of $2.9 million at December 31, 1998. The adoption of SOP 96-1 did not have a material adverse effect on COM/Energy's results of operations or financial position. New Accounting Principles In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts possibly including fixed-price fuel supply and power con- tracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 is effective for fiscal years beginning after June 15, 1999 and may be implemented as of the beginning of any fiscal quarter after issuance but cannot be applied retroactively. SFAS No. 133 must be applied to derivative instruments and certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1997 and, at the company's election, before January 1, 1998. In April 1998, the American Institute of Certified Public Accountants issued SOP 98-5, "Reporting on the Costs of Start-Up Activities" (SOP 98-5). SOP 98-5 provides guidance on the financial reporting of start-up and organi- zation costs and requires that these costs be expensed as incurred. The adoption of SFAS No. 133 and SOP 98-5 is not expected to have a material impact on COM/Energy's results of operations or financial condition. <PAGE 33> COMMONWEALTH ENERGY SYSTEM SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized. COMMONWEALTH ENERGY SYSTEM (Registrant) By JAMES D. RAPPOLI James D. Rappoli, Financial Vice President and Treasurer Date: May 12, 1999