<PAGE 1> UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 Form 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Mark One) [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 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 2-7909 CAMBRIDGE ELECTRIC LIGHT COMPANY (Exact name of registrant as specified in its charter) Massachusetts 04-1144610 (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 None None Securities registered pursuant to Section 12(g) of the Act: Title of Class None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [ x ] NO [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Outstanding at Class of Common Stock March 16, 1999 Common Stock, $25 par value 346,600 shares The Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this Form with the reduced disclosure format. Documents Incorporated by Reference Part in Form 10-K None Not Applicable List of Exhibits begins on page 47 of this report. <PAGE 2> CAMBRIDGE ELECTRIC LIGHT COMPANY FORM 10-K DECEMBER 31, 1998 TABLE OF CONTENTS PART I PAGE Item 1. Business........................................... 3 General......................................... 3 Electric Power Supply........................... 4 ISO - New England............................... 5 Energy Mix...................................... 6 Rates, Regulation and Legislation............... 6 (a) Restructuring Legislation............... 6 (b) Unbundled Rates......................... 8 (c) Customer Transition Charge.............. 9 (d) Wholesale Rate Proceedings.............. 9 Net Requirements Power Supply Agreement 9 Transmission Services Agreement 10 (e) Conservation and Load Management........ 11 (f) Transmission Rate Matters............... 12 (g) Energy Rate Matters..................... 12 Competition................................... 12 Construction and Financing.................... 13 Employees..................................... 13 Item 2. Properties...................................... 13 Item 3. Legal Proceedings............................... 13 PART II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters..................... 14 Item 7. Management's Discussion and Analysis of Results of Operations........................... 15 Item 7A. Quantitative and Qualitative Disclosures About Market Risk..................................... 23 Item 8. Financial Statements and Supplementary Data..... 23 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 23 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 47 Signatures.................................................. 59 <PAGE 3> CAMBRIDGE ELECTRIC LIGHT COMPANY PART I. Item 1. Business General Cambridge Electric Light Company (the Company) has been engaged in the generation, transmission and distribution and sale of electricity to approxi- mately 45,900 retail customers in the city of Cambridge, Massachusetts. The service territory encompasses a seven square mile area with a population of approximately 96,000. In addition, the Company sells power for resale to the Independent System Operator (ISO) - New England (the agency that operates a centralized facility to ensure reliability of service and dispatch of economi- cally available generating units throughout New England), the Town of Belmont, Massachusetts (Belmont), and sold steam from its electric generating stations at wholesale to an affiliated company for distribution to customers for space heating and other purposes. In early 1997, the Company received approval to participate as a broker in the purchase and sale of electricity. The Company, which was organized on January 28, 1886 pursuant to a special act of the legislature of the Commonwealth of Massachusetts, operates under the jurisdiction of the Massachusetts Department of Telecommunications and Energy (DTE), which regulates retail rates, accounting, issuance of securities and other matters. In addition, the Company files its wholesale rates with the Federal Energy Regulatory Commission (FERC). The Company is a wholly- owned subsidiary of Commonwealth Energy System (the Parent), which, together with its subsidiaries, is collectively referred to as "COM/Energy." In response to the significant changes that have taken place in the electric utility industry, the Company sold substantially all of its generat- ing assets in late 1998 to focus on the transmission and distribution of energy and related services. For additional information, refer to the "Restructuring Legislation" section under the "Rates, Regulation and Legisla- tion" section of this Item 1. 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 an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts including more than one million electric cus- tomers in 81 communities and 240,000 gas customers in 51 communities. The merger is expected to occur shortly after the satisfaction of certain con- ditions, including receipt of certain regulatory approvals. The regulatory approval process is expected to be completed during the second half of 1999. By virtue of its charter, which is unlimited in time, the Company has been involved in the production, purchase, distribution and sale of electricity without direct competition in kind from any privately or municipally-owned utility. Alternate sources of energy are available to customers within the service territory, but competition from these sources has not been signifi- cant. However, on November 25, 1997, the Governor of Massachusetts signed into law the Electric Industry Restructuring Act that subjects the generation element of electric utility operations to competition, effective March 1, 1998, and further allows consumers for the first time to choose their electric energy supplier. While competition to provide electric supply has not yet achieved the starting point for residential customers in Massachusetts, <PAGE 4> CAMBRIDGE ELECTRIC LIGHT COMPANY several of the Company's commercial and industrial customers (as of March 1999) are already buying power in the competitive market. For additional information, refer to the "Unbundled Rates" section under the "Rates, Regula- tion and Legislation" section of this Item 1. In early 1995, the Massachu- setts Institute of Technology, one of the Company's largest customers, completed and placed into service a natural gas cogeneration facility which will meet approximately 94% of its power needs. For further information on this facility refer to the "Customer Transition Charge" section discussion included in the "Rates, Regulation and Legislation" section. Of the Company's 1998 retail electric unit sales (86% of total sales), 12% was sold to residen- tial customers, 82% to commercial customers, 5% to industrial and 1% to streetlighting and similar types of customers. Electric Power Supply The Company sold its generating assets that consisted of the Kendall Station facility (67 megawatts (MW)) and the adjacent Kendall Jets (46 MW), located in Cambridge, MA to an affiliate of The Southern Company of Atlanta, Georgia effective December 30, 1998. The sale was the result of an auction process initiated during 1997 in response to electric industry restructuring legislation enacted in Massachusetts in November 1997. The Company will now rely on purchased power to meet its energy requirements. For further informa- tion refer to the "Restructuring Legislation" section under the "Rates, Regulation and Legislation" section of this Item 1. Power purchases for the Company and Commonwealth Electric Company (Common- wealth Electric), the other wholly-owned electric distribution subsidiary of the Parent, are arranged in accordance with their requirements. These arrangements have included purchases from Canal Electric Company (Canal Electric), another wholly-owned subsidiary of the Parent. These purchases included power generated at Canal Electric's generating facilities located in Sandwich, MA which were also part of the aforementioned auction and sale. However, the Company and Commonwealth Electric continue to purchase energy and capacity under a series of long-term contracts, and these entitlements include one-quarter (139.8 MW) of the capacity and energy of Canal Unit 1, which is now purchased from the new plant owner, Southern Energy Canal, L.L.C. (Southern). The Company's entitlement in Unit 1 is 28.7 MW. The Company's and Commonwealth Electric's cost of service agreements with Canal Electric for one-half (275.7 MW) of the capacity and energy purchased from Canal Unit 2 were terminated as part of the generating asset sale on December 30, 1998. The Company's entitlement in this unit was 55 MW. The former Unit 2 agreement was replaced by a new agreement under which Southern sells energy and capacity to the Company in order to support its customer load obligation, at fixed rates that are equivalent to the Company's standard offer (wholesale) rates. The Company also has an equity ownership interest of 2 1/2% in the Vermont Yankeee nuclear unit, with a power entitlement of 11.3 MW. Vermont Yankee has granted AmerGen Energy Co. an exclusive right to negotiate an agreement to buy the plant. Pursuant to a Capacity Acquisition and Disposition Agreement (CADA), Canal Electric seeks to secure bulk electric power on a single system basis to provide cost savings for the customers of the Company and Commonwealth Electric. The CADA has been accepted for filing as an amendment to Canal Electric's FERC rate schedule and allows Canal Electric to act on behalf of the Company and Commonwealth Electric in the procurement of additional <PAGE 5> CAMBRIDGE ELECTRIC LIGHT COMPANY capacity for one or both companies. The CADA is in effect for Seabrook 1 and Phases I and II of Hydro-Quebec. Exchange agreements are in place with these utilities whereby, in certain circumstances, it is possible to exchange capacity so that the mix of power improves the pricing for dispatch for both the seller and the purchaser. Power contracts are in place whereby Canal Electric bills or credits the Company and Commonwealth Electric for the costs or revenues associated with these facilities. The Company and Commonwealth Electric, in turn, have billed or are billing these charges (net of revenues from sales) to their customers through rates subject to DTE approval. Information relevant to life-of-the-unit contracts with nuclear units that are no longer operating in which the Company has an equity ownership is as follows: Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands) Equity Ownership (%) 4.50 4.00 2.00 Equity Ownership Balance $4,713 $3,476 $395 Year of Shutdown 1996 1997 1992 For further information on Maine Yankee, Connecticut Yankee and Yankee Atomic, refer to Note 3(b)in the Company's Notes to Financial Statements filed under Item 8 of this report. In addition, the Company has entitlements of 19.7 MW and 8.1 MW through Canal Electric's equity ownership in Hydro-Quebec Phase II and joint-ownership in the Seabrook nuclear unit, respectively. ISO - New England The Company, together with other electric utility companies in the New England area, is a member of ISO - New England, 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 member companies to fulfill the region's energy require- ments. This concept is accomplished through the use of computers to monitor and forecast load requirements. The Company and the Parent's other electric subsidiaries are also members of the Northeast Power Coordinating Council (NPCC), an advisory organization, which includes the major power systems in New England and New York plus the provinces of Ontario and New Brunswick in Canada. The NPCC establishes criteria and standards for reliability and serves as a vehicle for coordina- tion in the planning and operation of these systems. The reserve requirements used by 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 approxi- mately 20% of peak load. <PAGE 6> CAMBRIDGE ELECTRIC LIGHT COMPANY Energy Mix The Company's energy mix, including purchased power, was as follows: 1998 1997 1996 Oil 60% 55% 21% Nuclear 10 11 39 Natural gas 30 30 33 Hydro - 4 7 Total 100% 100% 100% The Company's energy mix in 1998 and 1997 reflects the greater availabili- ty of the oil-fired Canal Units 1 and 2 as compared to 1996 when significant scheduled and unscheduled maintenance resulted in reduced output. The significantly reduced nuclear fuel component in 1997 reflects the permanent shutdown of the Maine and Connecticut Yankee plants. Rates, Regulation and Legislation The Company operates under the jurisdiction of the DTE, which regulates retail rates, accounting, issuance of securities and other matters. In addition, the Company files its wholesale rates with the FERC. (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 pro- vides that utilities be allowed full recovery of transition costs subject to review and an audit process. The rate reduction mandated by the legislation 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. The Company, together with Commonwealth Electric and Canal Electric, 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 generation assets and the entitlements associated with purchased power contracts through an auction process was an integral part of the restructuring plan and is consistent with the Act. While the Company is encouraged with the treatment afforded net non-mitigable transition costs (which, for the Company, are primarily the result of above-market purchased power contracts with non-utility generators) by the legislation and the DTE, the mandated rate reduction has had a significant impact on cash flows of the Company. 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., an affiliate of The Southern Company of Atlanta, Georgia, to buy substantially all of its non-nuclear electric generating assets including the Company's Kendall Station facility and the adjacent Kendall Jets. As a <PAGE 7> CAMBRIDGE ELECTRIC LIGHT COMPANY result of construction-related adjustments at the closing on December 30, 1998, the final amount of proceeds from the sale was approximately $454 million. These facilities represented 984 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 the Company; five diesel generators (13.8 MW) in Oak Bluffs and West 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. The final amount of the proceeds from the sale of the Company's generating assets was approximately $58.2 million. These facilities, which represented 113 MW, had a book value of $7.1 million. No gain was recorded on the sale of the Company's generating assets because the Company is obligated to reduce its transition costs by the net proceeds of the sale. The Company continues to evaluate bids related to its purchased power contracts and is also evaluating the disposition of the Blackstone Station generating unit (15.3 MW) located in Cambridge, MA that is subject to a right of first offer 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 the Company 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 the Company and Commonwealth Electric, resulting in a reduction in the transition costs to be billed to customers. 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 on December 30, 1998) that the 10 percent rate reduction increase, effective January 1, 1999, to approxi- mately 16 percent. In addition, the Company 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 the Company's customers declined 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 the Company's cost deferrals associated with the pricing of standard offer service. <PAGE 8> CAMBRIDGE ELECTRIC LIGHT COMPANY (b) Unbundled Rates As a result of electric industry restructuring, the Company has unbundled its rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and has afforded customers 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 the Company include optional standard offer service and default service. Standard offer service is the electricity that is supplied by the local distribution company (such as the Company) 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 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. Prior to the implementation of industry restructuring on March 1, 1998, the Company had a Fuel Charge rate schedule that generally allowed for current recovery, from retail customers, of fuel used in electric production, pur- chased power and transmission costs. This schedule 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 schedule did not match actual costs for that period, an appropriate adjustment was reflected in the calculation of the next subsequent calendar quarter decimal. This rate schedule is no longer in effect. Also prior to March 1, 1998, the Company collected a portion of capacity- related purchased power costs associated with certain long-term power arrange- ments through base rates as approved by the DTE. Also, prior to March 1, 1998, revenues collected through base rates were generally designed to reimburse the Company for all costs of operation other than fuel, the energy portion of purchased power, transmission and C&LM costs while providing a fair return on capital invested in the business. However, as a result of a DTE-mandated recovery mechanism for these costs (described above), the Company experienced a revenue excess or shortfall when unit sales and/or the costs recoverable in base rates varied from test-period levels. The issue, which had a significant impact on the Company's net income, was addressed in a settlement agreement approved by the DTE in May 1995 that permitted deferral of up to $2 million annually for these capacity-related purchased power costs. <PAGE 9> CAMBRIDGE ELECTRIC LIGHT COMPANY (c) 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 the Company on March 15, 1995. The CTC was intended to protect remaining customers from paying certain stranded costs that were incurred in the event that the Company's largest customers discontinued full service, yet still remain connected for back-up and other services. These costs included long- term power contracts entered into to meet projected energy requirements, investments in substations, underground and overhead lines and current and future decommissioning costs associated with nuclear plants. This ruling is believed to be the first retail stranded cost charge approved nationally and follows the DTE restructuring order which endorsed, in principle, the recovery of stranded costs. Through the CTC, the Company recovered 75% of net stranded costs as calculated in its proposal. The Company'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. The Company 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. (d) 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 the Company 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 the Company. Net Requirements Power Supply Agreement The Company has provided electric service to Belmont for nearly a century. Historically, Belmont was a full-requirements customer of the Company, 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, the Company agreed to provide transmission service for Belmont's NYPA power under its firm transmission <PAGE 10> CAMBRIDGE ELECTRIC LIGHT COMPANY 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, the Company 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 the Company that the cost-of-service formula in the NRA needed to be clarified and that the Company 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, the Company 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 the Company's announcement of its intention to leave the power supply business would have profound implications for Belmont as they were served from the Company'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 the Company'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 the Company's proposed modifications to the NRA without hearing or suspension, and without requiring that the Company explain the basis for its deletion of certain protective standards. On May 29, 1998, the FERC issued its order denying rehearing. Subsequently, the Company and Belmont entered into negotiations to settle certain outstanding issues. An amendment to the Order has been signed by both parties and a joint offer of settlement (Joint Offer) was filed January 15, 1999. The Company awaits FERC action on the Joint Offer. Transmission Services Agreement The Company 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 the Company and Belmont were unable to agree on the terms of a TSA, the Company 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. The Company 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 the Company 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 <PAGE 11> CAMBRIDGE ELECTRIC LIGHT COMPANY with the parties' MOU and; (iii) that the Company'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 the Company 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 the Company's rehearing request on the limited rate issue regarding the method for allocating certain costs. The rehearing order resulted in the Company being able to increase its transmission rate to Belmont. In addition to the Company receiving increased transmission revenues in the future, the decision substantially reduced the Company's refund obligation to Belmont. The FERC's rehearing order denied all of Belmont's rehearing requests including when Belmont has the ability to purchase rights of use from the Company. The Order obligated the Company to make a compliance filing to include the necessary revisions to the TSA. Once the FERC approved and accepted the compliance filing, the Company 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, the Company made its compliance filing. On December 28, 1998, Belmont filed its protest claiming the Company'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, the Company filed its response to Belmont's December 28, 1998 protest. The Company awaits FERC action on Belmont's protest. (e) Conservation and Load Management Programs The Company has implemented a variety of cost-effective C&LM programs that are designed to reduce future energy use by its customers. In 1993, the DTE began allowing the recovery by the Company of its "lost base revenues" from customers as a rate component employed by the DTE to encourage effective implementation of C&LM programs. These and other C&LM costs were recovered through a Conservation Charge decimal. The KWH savings that were realized as a result of the successful implementation of C&LM programs served as the basis for determining lost base revenues. Pursuant to the Restructuring Act, the Company has agreed to mandatory charges per KWH to fund energy efficiency and demand-side management activities. <PAGE 12> CAMBRIDGE ELECTRIC LIGHT COMPANY (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, the Company filed transmission tariffs that implemented the FERC's requirements for non-discriminatory open access transmission for both point-to-point and network service. The tariffs were accepted on May 17, 1996 to be effective on May 28, 1996, but the rates are subject to an investigation initiated by the FERC itself. A settlement with the FERC regarding this investigation was filed on February 6, 1997. On April 24, 1996, the FERC issued Order No. 888, a set of three interrelated rules resolving the above rulemakings. The FERC required all public utilities that own, control or operate transmission facilities in interstate commerce to have on file wholesale Open Access Transmission Tariffs (OATTs) that conform to the FERC tariff contained in Order No. 888. On July 9, 1996, the Company filed OATTs that conform to the FERC's 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, the Company filed revised OATTs to be consistent with the recently filed ISO - New England 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. The Company filed 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, the Company filed a Settlement Agreement at FERC regarding the outstanding proceeding referred to in the Order. On September 30, 1998, following the filing of ISO - New England's revised OATT, the Company filed revised OATTs for consistency with ISO - New England. On January 28, 1999. FERC approved the July 31, 1998 Settlement Agreement which applied to the Company's July 9, 1996 OATT. Currently, the Company is awaiting decisions by FERC on the OATTs filed after 1996. (g) Energy Rate Matters On December 31, 1996, the Company and Commonwealth Electric filed market based power sales tariffs with the FERC with the intent to make wholesale power sales at fully negotiated rates. FERC approved the tariffs on February 27, 1997. In addition, the Company requested and received authorization to participate as brokers in the sale and purchase of electricity. Competition Prior to March 1, 1998, the Company developed and implemented strategies that dealt with the increasingly competitive environment facing the electric utility business. The inherently high cost of providing energy services in the Northeast had placed the region at a competitive disadvantage as more <PAGE 13> CAMBRIDGE ELECTRIC LIGHT COMPANY customers began to explore alternative energy supply options. Pursuant to preliminary electric industry restructuring rules issued in late 1996, the DTE proposed to implement programs under which utility and non-utility generators could sell electricity to customers of other utilities without regard to previously closed franchise service areas. The DTE initially began an inquiry into incentive ratemaking in 1994. The Company had developed innovative pricing mechanisms designed to retain existing customers, add new retail and wholesale customers and expand beyond current markets. 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 the Company and affiliates Commonwealth Electric, Commonwealth Gas, COM/Energy Services Company effective on that date. The Company and these affiliates 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. Construction and Financing Information concerning the Company's construction and financing programs is contained in Note 3(a) of the Notes to Financial Statements filed under Item 8 of this report. Employees The Company has 103 regular employees, 77 employees (75%) are represented by the Utility Workers' Union of America, A.F.L.-C.I.O. The existing collec- tive bargaining agreement is in effect through March 1, 2001. Employee relations have generally been satisfactory. Item 2. Properties The Company owns and operates one steam generating plant located in Cambridge with a total capability of 15.3 MW together with an integrated system of distribution lines and substations. At December 31, 1998, the Company's electric transmission and distribution system consisted of 93 pole miles of overhead lines, 737 cable miles of underground line, 246 substations and 46,316 active customer meters. Item 3. Legal Proceedings The Company is an intervenor in an appeal at the Massachusetts Supreme Judicial Court (SJC) filed by MIT of a decision by the DTE approving a customer transition charge that allows the Company to recover certain stranded costs. For additional information refer to "Rates, Regulation and Legislation" section in Item 1 of this report. <PAGE 14> CAMBRIDGE ELECTRIC LIGHT COMPANY PART II. Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters (a) Principal Market Not applicable. The Company is a wholly-owned subsidiary of Common- wealth Energy System. (b) Number of Stockholders at December 31, 1998 One (c) Frequency and Amount of Dividends Declared in 1998 and 1997 1998 1997 Per Share Per Share Declaration Date Amount Declaration Date Amount May 8, 1998 $ 7.50 April 25, 1997 $1.70 July 23, 1998 2.00 October 27, 1997 2.50 October 23, 1998 2.75 December 22, 1997 4.00 $12.25 $8.20 Reference is made to Note 7 of the Notes to Financial Statements filed under Item 8 of this report for the restriction against the payment of cash dividends. (d) Future dividends may vary depending on the Company's earnings and capital requirements as well as financial and other conditions existing at that time. <PAGE 15> CAMBRIDGE ELECTRIC LIGHT COMPANY Item 7. Management's Discussion and Analysis of Results of Operations The following is a discussion of certain significant factors which have affected operating revenues, expenses and net income during the periods included in the accompanying Statements of Income and is presented to facili- tate an understanding of the results of operations. This discussion should be read in conjunction with the Notes to Financial Statements filed under Item 8 of this report. A summary of the period to period changes in the principal items included in the accompanying Statements of Income for the years ended December 31, 1998 and 1997 and unit sales for these periods is shown below: Years Ended Years Ended December 31, December 31, 1998 and 1997 1997 and 1996 Increase (Decrease) (Dollars in thousands) Electric Operating Revenues $(12,620) (39.8)% $12,222 10.3% Operating Expenses: Fuel used in electric production (1,720) (21.7) 895 26.1 Electricity purchased for resale (18,492) (23.7) 9,206 13.4 Transmission 951 18.6 (1,056) (17.1) Other operation and maintenance (567) (2.2) 2,527 10.6 Depreciation 3,536 81.6 81 1.9 Taxes - Federal and state income 832 32.1 167 6.9 Local property and other (342) (8.7) 82 2.1 (15,802) (12.7) 11,902 10.6 Operating Income 3,182 46.9 320 4.9 Other Income 462 26.0 (209) (10.5) Income Before Interest Charges 3,644 42.5 111 1.3 Interest Charges 39 1.2 15 0.5 Net Income $ 3,605 69.1 $ 96 1.9 Unit Sales (MWH) Retail 53,738 4.2 21,983 1.7 Wholesale (38,255) (14.9) 43,628 20.5 Total unit sales 15,483 1.0 65,611 4.4 <PAGE 16> CAMBRIDGE ELECTRIC LIGHT COMPANY Unit Sales The following is a summary of unit sales and customers for the periods indicated: Years Ended December 31, 1998 1997 1996 % % Change Change Unit Sales (MWH): Residential 163,928 1.8 161,054 2.1 157,803 Commercial 1,099,867 4.6 1,051,170 2.2 1,028,896 Industrial 67,925 3.0 65,948 (5.4) 69,680 Municipal and other 8,423 2.3 8,233 2.4 8,043 Total retail 1,340,143 4.2 1,286,405 1.7 1,264,422 Wholesale 218,039 (14.9) 256,294 20.5 212,666 Total 1,558,182 1.0 1,542,699 4.4 1,477,088 Customers: Residential 38,724 2.1 37,914 1.1 37,503 Commercial 6,802 2.5 6,636 1.7 6,523 Industrial 37 (17.8) 45 (13.5) 52 Municipal and other 321 1.9 315 3.6 304 Total 45,884 2.2 44,910 1.2 44,382 During 1998, the Company's total unit sales increased reflecting higher retail sales to all classes of customers. The increase in retail sales was offset somewhat by a decrease in wholesale sales reflecting lower sales to ISO - - New England due to changes in the Company's capacity needs. For 1997, the Company's total unit sales increase reflects higher retail unit sales as sales to all classes of customers except industrial increased. Also included in the increase in unit sales are higher wholesale sales reflecting an increase in sales to ISO - New England due to changes in the Company's capacity needs. Operating Revenues Operating revenues for 1998 decreased approximately $12.6 million or 39.8% due to the 10 percent rate reduction (further discussed below) and decreases in electricity purchased for resale ($18.5 million) and fuel used ($1.7 million), offset in part by an increase in transmission ($951,000). The decrease in electricity purchased for resale of approximately $18.5 million or 23.7% reflects lower fuel costs and a $7.2 million deferral of costs in conjunction with the Company's restructuring plan as approved by the Massachusetts Department of Telecommunications and Energy (DTE). As a result of industry restructuring, the Company has unbundled its rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and has afforded customers the opportunity to purchase generation supply in the competitive market consistent with the electric industry restructuring legislation further discussed below. 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 <PAGE 17> CAMBRIDGE ELECTRIC LIGHT COMPANY services provided by the Company 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 for 1997 increased $12.2 million (10.3%) primarily due to higher electricity purchased for resale costs ($9.2 million), fuel costs ($895,000), retail sales ($753,000) and a higher level of wholesale sales, offset, in part by lower transmission charges ($1,056,000). As a result of a DTE-mandated recovery mechanism implemented in 1993 for capacity-related costs associated with certain long-term purchased power contracts, the Company experienced a revenue excess or shortfall when unit sales and/or the costs recoverable in base rates varied from test-period levels. This issue, which had a significant impact on net income, was addressed in a settlement agreement approved by the DPU in May 1995 (refer to the "Unbundled Rates" section in Item 1 of this report for additional details). During 1998, 1997 and 1996, the Company over-recovered approximately $1.4 million, $1.7 million and $290,000, respectively, resulting in an increase to net income of approximately $850,000, $1 million and $177,000, respectively. Electricity Purchased For Resale, Transmission and Fuel To satisfy demand requirements and provide required reserve capacity, the Company has purchased power on a long and short-term basis through entitlements pursuant to power contracts with other New England and Canadian utilities, Qualifying Facilities and other non-utility generators through a competitive bidding process that is regulated by the DTE. The Company has supplemented these sources with its own generating capacity. During 1998, electricity purchased for resale, transmission and fuel costs decreased in total by approximately $19.3 million (22.1%) in 1998 primarily due to lower fuel costs and the aforementioned deferral, offset in part by an increase in transmission costs. Electricity purchased for resale, transmission and fuel costs increased in total by approximately $9 million (11.6%) in 1997 due to higher fuel costs and higher costs for replacement power reflecting the permanent shutdown of Connecticut Yankee during 1996 and the absence of power from Maine Yankee which did not operate in 1997 and has since been permanently shut down. Also reflected in the increase in purchased power is the greater availability of affiliate Canal Electric Company's Units 1 and 2. Other Operation and Maintenance Other operation expense decreased 5.3% ($1.3 million) primarily due to the absence of a one-time charge ($2.5 million) related to a Personnel Reduction Program during 1997. Also contributing to the decrease were labor savings realized from the aforementioned personnel reduction program ($1.2 million) and lower insurance and benefits costs. The impact of these factors was somewhat offset by higher costs related to the outsourcing of the information technology, telecommunications and network services function ($1 million), including costs associated with Year 2000 compliance, and increases in costs <PAGE 18> CAMBRIDGE ELECTRIC LIGHT COMPANY associated with conservation and load management programs ($2 million). The increase in maintenance expense during 1998 of 25.1% ($690,000) was due primarily to a greater level of repairs at the Kendall generating unit. During 1997, other operation expense increased 13.7% ($2.8 million) due primarily to the one-time charge ($2.5 million) related to the personnel reduction program. Also contributing to the increase in other operation were higher costs related to automated meter reading ($346,000). The decline in maintenance costs of 10.3% ($315,000) during 1997 was due primarily to a lower level of repairs at the Company's Kendall generating unit. Depreciation and Taxes The significant increase in depreciation expense reflects the treatment allowed for production plant pursuant to the electric industry restructuring legislation. Depreciation expense increased 1.9% in 1997 due to a higher level of depreciable property, plant and equipment. The increase in federal and state income taxes in 1998 reflects the higher level of pre-tax income related to normal operations. During 1998, the 8.7% decrease in local property and other taxes reflects lower property taxes due to the sale of real estate and lower payroll taxes reflecting the impact of the aforementioned personnel reduction program. Other Income and Interest Charges The increase in other income during 1998 reflects the gains related to the sale of real estate ($1.3 million), offset in part by a lower rate of return relative to steam production for an affiliate steam company ($120,000) and lower rental income resulting from the sale of real estate. The decrease in other income during 1997 was due primarily to the absence of a gain recognized in 1996 relating to the sale of a real estate ($402,000). Interest charges for 1998 increased slightly (1.2%) as long-term interest decreased ($118,000) reflecting the retirement of a $6 million (6.25%) debt issue during the second quarter of 1997, offset by an increase in short-term interest ($182,000) reflecting a higher average level of short-term borrowings. Total interest charges for 1997 were virtually unchanged as long- term interest decreased ($678,000) reflecting the repayment of a $20 million (9.97%) debt issue during the second quarter of 1996 and the retirement of the $6 million debt issue during the second quarter of 1997. The impact of these maturing debt issues was offset by an increase in short-term interest ($659,000) reflecting a higher level of short-term borrowings. 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 Company's business and financial results could cause actual results to differ materially from those stated in the forward-looking state- ments. Those factors include developments in the legislative, regulatory and competitive environment, certain environmental matters, demands for capital expenditures and the availability of cash from various sources. <PAGE 19> CAMBRIDGE ELECTRIC LIGHT COMPANY 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, COM/Energy and BEC will be merged into a new holding company to be known as NSTAR. 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 COM/Energy'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, COM/Energy'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 COM/Energy'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 Financial Statements, the Company follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In the event the Company 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) increasing competition restricting the Company's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators. The Company monitors these criteria to ensure that the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its 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. <PAGE 20> CAMBRIDGE ELECTRIC LIGHT COMPANY As a result of electric industry restructuring, the Company discontinued application of accounting principles applied to its electric generation facilities effective March 1, 1998. The Company will not be required to write off any of its generation-related assets, including regulatory assets. These assets will be retained on the Company's Balance Sheets because the legisla- tion 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 is approximately 86% complete in its efforts to resolve non-compliance with Year 2000 requirements related to its non-information technology systems. COM/Energy 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. <PAGE 21> CAMBRIDGE ELECTRIC LIGHT COMPANY 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, 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, <PAGE 22> CAMBRIDGE ELECTRIC LIGHT COMPANY 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 The Company is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installa- tion of expensive air and water pollution control equipment. These regula- tions have had an impact on the Company's operations in the past and will continue to have an impact on future operations, capital costs and construc- tion schedules of major facilities. On January 1, 1997, the Company adopted the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 provides authoritative guidance for recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The Company has recorded environmental remediation liabilities net of amounts paid of $114,000 at December 31, 1998. The adoption of SOP 96-1 did not have a material adverse effect on the Company'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 deri- vative instrument (including certain derivative instruments embedded in other contracts possibly including fixed-price fuel supply and power contracts) 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. <PAGE 23> CAMBRIDGE ELECTRIC LIGHT COMPANY The adoption of SFAS No. 133 is not expected to have a material impact on the Company's results of operations or financial condition. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Although the Company has material commodity purchase contracts and financial instruments (debt), these instruments are not subject to market risk. The Company has a rate making mechanism which allows for the recovery of fuel costs from customers. The fuel adjustment mechanism allows the Company to pass all costs related to the purchase of commodities to the customer, thereby insulating the Company from market risk. Similarly, any change in the fair market value of the Company's prudently incurred debt obligations realized by the Company would be borne by customers through future rates. Item 8. Financial Statements and Supplementary Data The Company's financial statements required by this item are filed herewith on pages 24 through 46 of this report. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. <PAGE 24> CAMBRIDGE ELECTRIC LIGHT COMPANY Item 8. Financial Statements and Supplementary Data REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Cambridge Electric Light Company: We have audited the accompanying balance sheets of CAMBRIDGE ELECTRIC LIGHT COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Commonwealth Energy System) as of December 31, 1998 and 1997, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1998. These financial statements and schedules referred to below are the responsibility of the Company's manage- ment. Our responsibility is to express an opinion on these financial state- ments and schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cambridge Electric Light Company as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting princi- ples. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Boston, Massachusetts February 18, 1999 <PAGE 25> CAMBRIDGE ELECTRIC LIGHT COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULES PART II. FINANCIAL STATEMENTS Balance Sheets at December 31, 1998 and 1997 Statements of Income for the Years Ended December 31, 1998, 1997 and 1996 Statements of Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996 Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996 Notes to Financial Statements PART IV. SCHEDULES I Investments in, Equity in Earnings of, and Dividends Received From Related Parties for the Years Ended December 31, 1998, 1997 and 1996 II Valuation and Qualifying Accounts for the Years Ended December 31, 1998, 1997 and 1996 SCHEDULES OMITTED All other schedules are not submitted because they are not applicable or not required or because the required information is included in the financial statements or notes thereto. Financial statements of 50% or less owned companies accounted for by the equity method have been omitted because they do not, considered individ- ually, constitute a significant subsidiary. <PAGE 26> CAMBRIDGE ELECTRIC LIGHT COMPANY BALANCE SHEETS DECEMBER 31, 1998 AND 1997 ASSETS 1998 1997 (Dollars in thousands) PROPERTY, PLANT AND EQUIPMENT, at original cost $140,642 $163,914 Less - Accumulated depreciation 47,179 63,706 93,463 100,208 Add - Construction work in progress 937 757 94,400 100,965 INVESTMENTS Equity in nuclear electric power companies 9,906 9,849 Other 5 5 9,911 9,854 LONG-TERM RECEIVABLE - AFFILIATE 8,990 - CURRENT ASSETS Cash 28,228 521 Accounts receivable - Affiliated companies 1,729 2,743 Customers, less reserves of $465 in 1998 and $297 in 1997 10,774 12,483 Unbilled revenues 3,489 3,047 Inventories, at average cost - Materials and supplies 717 540 Electric production fuel oil 35 936 Prepaid taxes - Income - 1,192 Property 1,410 1,697 Other 324 501 46,706 23,660 DEFERRED CHARGES Regulatory assets 70,372 70,466 Deferred tax asset 10,687 - Other 536 2,176 81,595 72,642 $241,602 $207,121 The accompanying notes are an integral part of these financial statements. <PAGE 27> CAMBRIDGE ELECTRIC LIGHT COMPANY BALANCE SHEETS DECEMBER 31, 1998 AND 1997 CAPITALIZATION AND LIABILITIES 1998 1997 (Dollars in thousands) CAPITALIZATION Common Equity - Common stock, $25 par value - Authorized and outstanding - 346,600 shares in 1998 and 1997, wholly-owned by Commonwealth Energy System (Parent) $ 8,665 $ 8,665 Amounts paid in excess of par value 27,953 27,953 Retained earnings 16,182 11,607 52,800 48,225 Long-term debt, including premiums, less current sinking fund requirements and maturing debt 7,301 17,402 60,101 65,627 CURRENT LIABILITIES Interim Financing - Notes payable to banks - 19,000 Advances from affiliates - 11,290 Maturing long-term debt 10,000 - 10,000 30,290 Other Current Liabilities - Current sinking fund requirements 100 100 Accounts payable - Affiliated companies 2,818 4,144 Other 8,328 8,076 Accrued local property and other taxes 1,468 1,706 Accrued income taxes 20,514 - Accrued interest 463 460 Other 4,704 3,830 38,395 18,316 48,395 48,606 DEFERRED CREDITS Regulatory liabilities 69,502 2,984 Accumulated deferred income taxes - 15,135 Connecticut Yankee purchased power contract 25,185 28,566 Maine Yankee purchased power contract 30,646 34,908 Yankee Atomic purchased power contract 1,634 2,749 Unamortized investment tax credits and other 6,139 8,546 133,106 92,888 COMMITMENTS AND CONTINGENCIES $241,602 $207,121 The accompanying notes are an integral part of these financial statements. <PAGE 28> CAMBRIDGE ELECTRIC LIGHT COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 1998 1997 1996 (Dollars in thousands) ELECTRIC OPERATING REVENUES $118,707 $131,327 $119,105 OPERATING EXPENSES Fuel used in electric production 2,602 4,322 3,427 Electricity purchased for resale 59,387 77,879 68,673 Transmission 6,072 5,121 6,177 Other operation 22,342 23,599 20,757 Maintenance 3,439 2,749 3,064 Depreciation 7,871 4,335 4,254 Taxes - Income 3,423 2,591 2,424 Local property 2,828 3,060 3,041 Payroll and other 775 885 822 108,739 124,541 112,639 OPERATING INCOME 9,968 6,786 6,466 OTHER INCOME 2,236 1,774 1,983 INCOME BEFORE INTEREST CHARGES 12,204 8,560 8,449 INTEREST CHARGES Long-term debt 1,442 1,560 2,238 Other interest charges 1,997 1,815 1,157 Allowance for borrowed funds used during construction (56) (31) (66) 3,383 3,344 3,329 NET INCOME $ 8,821 $ 5,216 $ 5,120 The accompanying notes are an integral part of these financial statements. <PAGE 29> CAMBRIDGE ELECTRIC LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 1998 1997 1996 (Dollars in thousands) Balance at beginning of year $11,607 $ 9,233 $ 7,561 Add (Deduct): Net income 8,821 5,216 5,120 Cash dividends on common stock (4,246) (2,842) (3,448) Balance at end of year $16,182 $11,607 $ 9,233 The accompanying notes are an integral part of these financial statements. <PAGE 30> CAMBRIDGE ELECTRIC LIGHT COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 1998 1997 1996 (Dollars in thousands) OPERATING ACTIVITIES Net income $ 8,821 $ 5,216 $ 5,120 Effects of noncash items - Depreciation and amortization 8,502 4,335 4,254 Deferred income taxes (19,391) (448) (628) Investment tax credits (484) (91) (93) Earnings from corporate joint ventures (1,041) (1,119) (1,006) Dividends from corporate joint ventures 984 673 827 Change in working capital, exclusive of cash and interim financing - Accounts receivable and unbilled revenues 2,281 (2,785) 178 Income taxes 21,706 (224) (1,698) Accounts payable and other 753 (294) 829 Transition costs deferral (7,244) - - All other operating items (3,680) 722 2,131 Net cash provided by operating activities 11,207 5,985 9,914 INVESTING ACTIVITIES Proceeds from sale of generating assets 58,992 - - Additions to property, plant and equipment (exclusive of AFUDC) (7,799) (4,873) (5,024) Allowance for borrowed funds used during construction (56) (31) (66) Net cash from (used for) investing activities 51,137 (4,904) (5,090) FINANCING ACTIVITIES Payment of dividends (4,246) (2,842) (3,448) Proceeds from (payments of) short-term borrowings, net (19,000) 275 16,050 Proceeds from (payments to) affiliates (11,290) 6,225 2,640 Long-term debt issues refunded - (4,260) (20,000) Retirement of long-term debt through sinking funds (101) (101) (162) Net cash used for financing activities (34,637) (703) (4,920) Change in cash 27,707 378 (96) Cash at beginning of period 521 143 239 Cash at end of period $28,228 $ 521 $ 143 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the period for: Interest (net of capitalized amounts) $ 3,080 $ 3,371 $ 3,796 Income taxes $ 3,871 $ 2,319 $ 4,015 The accompanying notes are an integral part of these financial statements. <PAGE 31> CAMBRIDGE ELECTRIC LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS (1) General Information Cambridge Electric Light Company (the Company) is a wholly-owned subsid- iary of Commonwealth Energy System (the Parent). The Parent, together with its subsidiaries, is collectively referred to as "COM/Energy." The Parent is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935 with investments in four operating public utility companies located in central, eastern and southeastern Massachusetts and several non-regulated companies. The Company's operations are involved in the production, distribution and sale of electricity to approximately 44,500 customers in the city of Cam- bridge, Massachusetts. The service territory encompasses a seven square-mile area with a population of approximately 96,000. In addition, the Company sells power for resale to the New England Power Pool (NEPOOL) and the Town of Belmont, Massachusetts (Belmont), and sells steam from its electric generating stations at wholesale to an affiliated company for distribution to customers for space heating and other purposes. 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 an energy delivery company, that includes the 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. On December 30, 1998, in response to the significant changes that have taken place in the utility industry, COM/Energy sold substantially all of its non-nuclear generating assets including the Company's Kendall Station facility (67 MW) and the adjacent Kendall Jets (46 MW), to affiliates of The Southern Company of Atlanta, Georgia. The Company has 103 regular employees, 77 (75%) of whom are represented by a single collective bargaining unit with a contract that expires on March 1, 2001. Employee relations have generally been satisfactory. (2) Significant Accounting Policies (a) Principles of Accounting The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements. (b) Regulatory Assets and Liabilities The Company is regulated as to rates, accounting and other matters by various authorities including the Federal Energy Regulatory Commission (FERC) <PAGE 32> CAMBRIDGE ELECTRIC LIGHT COMPANY and the Massachusetts Department of Telecommunications and Energy (DTE). Based on the current regulatory framework, the Company accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." The Company has established various regula- tory assets in cases where the DTE and/or the FERC have permitted or are expected to permit recovery of specific costs over time. Similarly, the regulatory liabilities established by the Company are required to be refunded to customers over time. In the event the criteria for applying SFAS No. 71 are no longer met, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS No. 71 include: 1) increasing competition that restricts the Company's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators from cost based regulation to another form of regulation. These criteria are reviewed on a regular basis to ensure the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its regulatory assets including those related to generation, are probable of future recovery. As a result of electric industry restructuring, the Company discontinued application of accounting principles applied to its investment in electric generation facilities effective March 1, 1998. The Company will not be required to write-off any of its generation-related assets including regula- tory assets. These assets will be retained on the Company's Balance Sheets because the legislation and DTE's plan for a restructured electric industry specifically provide for their recovery through a non-bypassable transition charge. The principal regulatory assets included in deferred charges were as follows: 1998 1997 (Dollars in thousands) Yankee Atomic unrecovered plant and decommissioning costs $ 1,634 $ 2,749 Connecticut Yankee unrecovered plant and decommissioning costs 25,185 28,566 Maine Yankee unrecovered plant and decommissioning costs 30,646 34,908 Transition costs 9,149 - Postretirement benefits costs 3,120 3,596 Other 638 647 $70,372 $70,466 <PAGE 33> CAMBRIDGE ELECTRIC LIGHT COMPANY The regulatory liabilities, reflected in the accompanying Balance Sheets were as follows: 1998 1997 (Dollars in thousands) Regulatory liability related to sale of generating assets $65,418 $ - Deferred income taxes 2,402 2,984 Demand-side management deferral 1,682 - $69,502 $ 2,984 The regulatory liability of $65.4 million was established pursuant to the Company's divestiture filing that was approved by the DTE in which the Company agreed to use its share of the net proceeds from affiliate Canal Electric Company's (Canal Electric) sale of generating assets and the sale of its own generating assets to reduce transition costs that are billed to its retail electric customers over the next several years as a result of electric industry restructuring. The Company's share of the net proceeds from the sale of Canal Electric's generating assets has been classified as a long-term receivable - affiliate on the accompanying Balance Sheets. As of December 31, 1998, the Company's regulatory assets, including the costs associated with existing power contracts with three Yankee nuclear power plants that have shut down permanently, and all of its regulatory liabilities are reflected in rates charged to customers. Regulatory assets are to be recovered over the next 11 years pursuant to the legislation discussed below. In November 1997, the Commonwealth of Massachusetts enacted a comprehen- sive electric utility industry restructuring bill. On November 19, 1997, the Company, together with Commonwealth Electric Company (Commonwealth Electric) and Canal Electric, filed a restructuring plan with the DTE. The plan, approved by the DTE on February 27, 1998, provides that the Company and Commonwealth Electric, beginning March 1, 1998, initiate a ten percent rate reduction for all customer classes and allow customers to choose their energy supplier. As part of the plan, the DTE authorized the recovery of certain strandable costs and provides that certain future costs may be deferred to achieve or maintain the rate reduction that the restructuring bill mandates. The legislation gives the DTE the authority to determine the amount of strandable costs that will be eligible for recovery. Costs that will qualify as strandable costs and be eligible for recovery include, but are not limited to, certain above market costs associated with generating facilities, costs associated with long-term commitments to purchase power at above market prices from independent power producers and regulatory assets and associated liabilities related to the generation portion of the electric business. (c) Divestiture of Generation Assets The cost of transitioning to competition will be mitigated, in part, by the sale of COM/Energy's non-nuclear generating assets. 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 <PAGE 34> CAMBRIDGE ELECTRIC LIGHT COMPANY 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 the Company's Kendall Station generating assets, after construction-related adjustments at the closing that occurred on December 30, 1998, amounted to approximately $58.2 million or 8.2 times their book value of approximately $7.1 million. The proceeds from the sale, net of book value and transaction costs amounted to $49.3 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. No gain was recorded on the sale of these generating assets because the Company is obligated to reduce its transition costs by the net proceeds of the sale. COM/Energy established Energy Investment Services, Inc. as the vehicle to invest the net proceeds from the sale of Canal Electric's generating assets. These proceeds will be invested in a conservative portfolio of securities that is designed to maintain principal and earn a reasonable return. Both the principal amount and income earned will be used to reduce the transition costs that would otherwise be billed to customers of the Company and Commonwealth Electric. (d) Transactions with Affiliates Transactions between the Company and other COM/Energy companies include purchases and sales of electricity, including purchases from Canal Electric, an affiliate wholesale electric generating company. Other Canal transactions include costs relating to the abandonment of Seabrook 2 and the recovery of a portion of Seabrook 1 pre-commercial operation costs. In addition, payments for management, accounting, data processing and other services are made to an affiliate, COM/Energy Services Company. Transactions with other COM/Energy companies are subject to review by the DTE. The Company's operating expenses include the following major intercompany transactions for the periods indicated: Purchased Power Purchased Power and Transmission Period Ended Purchased Power and Transmission From Canal December 31, Canal Units Seabrook 1 as Agent (Dollars in thousands) 1998 $14,014 $ 7,323 $ 1,062 1997 15,772 7,825 2,358 1996 11,302 7,932 2,786 The costs for the Canal Electric and Seabrook 1 units are included in the long-term obligation table listed in Note 3(b). In addition, the Company purchased natural gas from an affiliate, Commonwealth Gas Company, totaling $133,000, $245,000 and $621,000 in 1998, 1997 and 1996, respectively. (e) Operating Revenues Customers are billed for their use of electricity on a cycle basis throughout the month. To reflect revenues in the proper period, the estimated amount of unbilled sales revenue is recorded each month. <PAGE 35> CAMBRIDGE ELECTRIC LIGHT COMPANY The Company is generally permitted to bill customers currently for costs associated with purchased power and transmission, fuel used in electric production, conservation and load management (C&LM) and environmental costs. The amount of such costs incurred by the Company but not yet reflected in customers' bills is recorded as unbilled revenues. (f) Depreciation Depreciation is provided using the straight-line method at rates intended to amortize the original cost and the estimated cost of removal less salvage of properties over their estimated economic lives. The average composite depreciation rate was 2.88% in 1998, 2.68% in 1997 and 2.69% in 1996. (g) Maintenance Expenditures for repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expense. Additions, replacements and renewals of property considered to be units of property are charged to the appropriate plant accounts. Upon retirement, accumulated depreciation is charged with the original cost of property units and the cost of removal less salvage. (h) Allowance for Funds Used During Construction Under applicable rate-making practices, the Company is permitted to include an allowance for funds used during construction (AFUDC) as an element of its depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which the Company earns a return. An amount equal to the AFUDC capitalized in the current period is reflected in the accompanying Statements of Income. While AFUDC does not provide funds currently, these amounts are recover- able in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 5.75% in 1998, 6% in 1997 and 6.25% in 1996. (3) Commitments and Contingencies (a) Financing and Construction Programs The Company is engaged in a continuous construction program presently estimated at $59.2 million for the five-year period 1999 through 2003. Of that amount, $7.8 million is estimated for 1998. The program is subject to periodic review and revision because of factors such as changes in business conditions, rates of customer growth, effects of inflation, maintenance of reliable and safe service, equipment delivery schedules, licensing delays, availability and cost of capital and environmental factors. The Company expects to finance these expenditures on an interim basis with internally generated funds and short-term borrowings which are ultimately expected to be repaid with the proceeds from sales of long-term debt and equity securities. (b) Power Contracts The Company has long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require <PAGE 36> CAMBRIDGE ELECTRIC LIGHT COMPANY payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. Information relative to these contracts is as follows: Range of Contract Expiration Entitlement Cost Dates % MW 1998 1997 1996 (Dollars in thousands) Type of Unit Cogenerating 2011 17.2 24.5 $15,134 $15,804 $14,589 Oil 2002 (a) 85.6 14,018 15,794 11,301 Nuclear 2012-2026 (b) 8.1 11,665 11,670 12,089 Total 118.2 $40,817 $43,268 $37,979 (a) Includes entitlements in Canal Unit 1 (5%) and Canal Unit 2 (10%). On May 27, 1998, COM/Energy selected affiliates of Southern Energy New England, L.L.C., an affiliate of The Southern Company of Atlanta, Georgia, to buy substantially all of its non-nuclear electric generating assets, including Canal Units 1 and 2. Under long-term contracts, the Company's entitlement in Unit 1 was 28.2 MW. However, the Company and Commonwealth Electric continue to purchase energy and capacity under a series of long-term contracts and these entitlements include one-quarter of the capacity and energy of Canal Unit 1, which is now purchased from the new plant owner, Southern Energy Canal, L.L.C. (Southern). The Company's cost of service agreement with Canal Electric for its share of the capacity and energy purchased from Canal Unit 2 was terminated as part of the generating asset sale on December 30, 1998. The former Unit 2 agreement was replaced by a new agreement under which Southern sells energy and capacity to the Company to support its customer load obligation, at fixed rates that are equiva- lent to the Company's standard offer (wholesale) rates. (b) Includes entitlements in Seabrook 1 (0.7%) and Vermont Yankee (2.5%) nuclear power plants. The estimated cost to decommission Vermont Yankee is $406.7 million in current dollars. The Company's share of this liability (approximately $9.2 million), less its share of the market value of assets held in a decommissioning trust (approximately $5.1 million), is approximately $4 million at December 31, 1998. Pertinent information with respect to life-of-the-unit contracts with nuclear units no longer operating in which the Company has an equity ownership is as follows: Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands) Equity Ownership (%) 4.50 4.00 4.50 Plant Entitlement (%) 4.50 3.59 2.50 Contract Expiration Date 2007 2008 2000 Year of Shutdown 1996 1997 1992 1996 Actual Cost ($) 9,259 6,511 2,260 1997 Actual Cost ($) 5,760 8,928 2,238 1998 Actual Cost ($) 3,553 4,705 2,184 Decommissioning cost estimate (100%) ($) 465,693 403,418 81,699 Company's decommissioning cost ($) 20,956 14,483 3,676 Market value of assets (100%) ($) 260,641 212,664 148,464 Company's market value of assets ($) 11,729 7,635 6,681 <PAGE 37> CAMBRIDGE ELECTRIC LIGHT COMPANY Based upon regulatory precedent, the operators of the Yankee units believe they will be permitted to continue to collect from power purchasers (including the Company) decommissioning costs, unrecovered plant investment and other costs associated with the permanent closure of these plants over the remaining period of each plant's operating license. The Company does not believe that the ultimate outcome of the early closing of these plants will have a material adverse effect on its operations and believes that recovery of these FERC- approved costs would continue to be allowed in its rates at the retail level. Costs pursuant to these contracts are included in electricity purchased for resale in the accompanying Statements of Income and are recoverable in revenue. The Company pays its share of decommissioning expense to each of the operators of the nuclear facilities as a cost of electricity purchased for resale. The estimated aggregate obligations under the life-of-the-unit contracts for capacity from the operating Yankee Nuclear Unit and other long-term purchased power obligations, including and Seabrook 1, in effect for the five years subsequent to 1998 are as follows: Long-Term Equity-Owned Purchased Nuclear Unit Power Total (Dollars in thousands) 1999 $5,704 $45,171 $50,875 2000 5,318 45,423 50,741 2001 5,710 41,689 47,399 2002 5,876 39,634 45,510 2003 5,621 34,690 40,311 Due to changing conditions within the nuclear industry, it is possible that the remaining operating nuclear plant in which the Company has an equity ownership interest could be shut down prior to the expiration of that unit's operating license. In addition, the Company incurred costs for purchases from ISO - New England of $13,491,000, $15,143,000 and $10,973,000 in 1998, 1997 and 1996, respectively. The costs associated with these power contract obligations are a signifi- cant component of the Company's stranded costs that are being recovered through a transition charge pursuant to DTE approval. (c) Price-Anderson Act Under the Price-Anderson Act (the Act), owners of nuclear power plants have the benefit of approximately $9.7 billion of public liability coverage which would compensate the public for valid bodily injury and property loss on a no fault basis in the event of an accident at a commercial nuclear power plant. Under the provisions of the Act, each nuclear reactor with an operat- ing license can be assessed up to $88.1 million per nuclear incident with a maximum assessment of $10 million per incident within one calendar year. Nuclear plant owners have initiated insurance programs designed to help cover liability claims relating to property damage, decontamination, replacement power and business interruption costs for participating utilities arising from a nuclear incident. <PAGE 38> CAMBRIDGE ELECTRIC LIGHT COMPANY The Company has an equity ownership interest in four nuclear generating facilities. The operators of these units maintain nuclear insurance coverage (on behalf of the owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II) and the American Nuclear Insurers (ANI). NEIL II provides $2.25 billion of property, boiler, machinery and decontamination insurance coverage, including accidental premature decommissioning insurance in the amount of the shortfall in the Decommissioning Trust Fund, in excess of the underlying $500 million policy. All companies insured with NEIL II are subject to retroactive assessments if losses exceed the accumulated funds available. ANI provides $500 million of "all risk" property damage, boiler, machinery and decontamination insurance. An additional $200 million of primary financial protection coverage is provided for off-site bodily injury or property damage caused by a nuclear incident. ANI also provides secondary financial protection liability insurance which currently provides $9.5 billion of retrospective insurance premium benefits in accordance with the provisions of the Act. Three of the four units in which the Company has an equity ownership interest have been permanently shut down. The Nuclear Regulatory Commission has approved each of the units' requests to withdraw from participation in the secondary insurance program. Additional coverage ($200 million) provided by ANI includes tort liability protection arising out of radiation injury claims by nuclear workers and injury or property damage caused by the transportation or shipment of nuclear materials or waste. Based on its various ownership interests in the four nuclear generating facilities, the Company's retrospective premium could be $250,000 annually or a cumulative total of $2.2 million, exclusive of the effect of inflation indexing (at five-year intervals) and a 5% surcharge ($4 million) in the event that total public liability claims from a nuclear incident exceed the funds available to pay such claims. (d) Environmental Matters The Company is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installa- tion of expensive air and water pollution control equipment. These regula- tions have had an impact on the Company's operations in the past and will continue to have an impact on future operations, capital costs and construction schedules of major facilities with the exception of electric generating facilities since substantially all of the Company's non-nuclear generating assets were sold in 1998. (4) Income Taxes For financial reporting purposes, the Company provides federal and state income taxes on a separate-return basis. However, for federal income tax purposes, the Company's taxable income and deductions are included in the consolidated income tax return of the Parent and it makes tax payments or receives refunds on the basis of its tax attributes in the tax return in accordance with applicable regulations. <PAGE 39> CAMBRIDGE ELECTRIC LIGHT COMPANY The following is a summary of the Company's provisions for income taxes for the years ended December 31, 1998, 1997 and 1996: 1998 1997 1996 (Dollars in thousands) Federal Current $ 20,117 $ 2,574 $ 2,861 Deferred (16,050) (287) (582) Investment tax credits (484) (91) (93) 3,583 2,196 2,186 State Current 4,013 556 543 Deferred (3,155) (48) (21) 858 508 522 4,441 2,704 2,708 Amortization of regulatory liability relating to deferred income taxes (186) (113) (25) $ 4,255 $ 2,591 $ 2,683 Federal and state income taxes charged to: Operating expense $ 3,423 $ - $ 2,424 Other income 832 - 259 $ 4,255 $ - $ 2,683 The significant increase in the current provision for income taxes in 1998 reflects the current tax related to the sale of the generating assets. Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse. Accumulated deferred income taxes consisted of the following: 1998 1997 (Dollars in thousands) Liabilities Property-related $ 15,099 $17,309 Transition charges 3,189 - All other 1,453 1,710 19,741 19,019 Assets Sale of generation assets 25,572 - Investment tax credits 764 1,134 Pension plan 733 810 Regulatory liability 784 1,039 All other 2,575 2,339 30,428 5,322 Accumulated deferred income taxes (deferred tax asset), net $(10,687) $13,697 The net year-end deferred tax asset included a current deferred tax asset of $18,847,000 in 1998 which is included in accrued income taxes in the accompanying Balance Sheets. The net year-end deferred income tax liability <PAGE 40> CAMBRIDGE ELECTRIC LIGHT COMPANY above includes a current deferred tax liability of $1,438,000 in 1997 which is included in accrued income taxes in the accompanying Balance Sheets. The total income tax provision set forth previously represents 33% in 1998, 33% in 1997 and 34% in 1996 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages: 1998 1997 1996 (Dollars in thousands) Federal statutory rate 35% 35% 35% Federal income tax expense at statutory levels $4,576 $2,732 $2,731 Increase (Decrease) from statutory levels: State tax net of federal tax benefit 558 331 339 Tax versus book depreciation 69 66 83 Amortization of excess deferred reserves (113) (113) (25) Amortization of investment tax credits (484) (91) (93) Reversals of capitalized expenses (15) (13) (13) Dividend received deduction (255) (274) (246) Other (81) (47) (93) $4,255 $2,591 $ 2,683 Effective federal income tax rate 33% 33% 34% (5) Employee Benefit Plans (a) Pension The Company has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed one year of service. Pension benefits are based on an employee's years of service and compensation. The company makes monthly contributions to the plan consistent with the funding requirements of the Employee Retirement Income Security Act of 1974. The following tables set forth the change in the pension benefit obligation and plan assets as well as the plan's funded status reconciled to the amount included in the financial statements: 1998 1997 (Dollars in thousands) Change in benefit obligation Obligation at beginning of year $ 31,860 $ 26,690 Service cost 566 534 Interest cost 2,199 1,871 Actuarial loss 2,684 4,570 Benefits paid (2,094) (1,805) Obligation at end of year $ 35,215 $ 31,860 <PAGE 41> CAMBRIDGE ELECTRIC LIGHT COMPANY 1998 1997 (Dollars in thousands) Change in plan assets Fair value of plan assets at beginning of year $ 32,325 $ 29,027 Actual return on plan assets 2,494 5,103 Employer contributions 300 - Benefits paid (2,094) (1,805) Fair value of plan assets at end of year $ 33,025 $ 32,325 1998 1997 (Dollars in thousands) Funded status $ (2,190) $ 465 Unrecognized transition obligation 414 551 Unrecognized prior service cost 834 954 Unrecognized net actuarial (gain) loss (1,631) (4,289) Prepaid(accrued) benefit cost $ (2,573) $ (2,319) Weighted-average assumptions as of December 31 were as follows: 1998 1997 Discount rate 6.50% 7.00% Expected return on plan assets 9.00 8.75 Rate of increase in future compensation 3.75 3.75 Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect pension expense in future years. Components of net periodic pension cost were as follows: 1998 1997 1996 (Dollars in thousands) Service cost $ 566 $ 534 $ 538 Interest cost 2,199 1,871 1,921 Expected return on plan assets (2,468) (2,215) (2,076) Amortization of transition obligation 137 137 137 Amortization of prior service cost 120 120 120 Total 554 447 640 Transfers from affiliates, net 390 503 441 Less: Amounts capitalized and deferred 37 723 299 Net periodic pension cost $ 907 $ 227 $ 782 The net periodic pension cost reflects the use of the projected unit credit method which is also the actuarial cost method used in determining future funding of the plan. The Company, in accordance with current ratemaking, are deferring the difference between the pension contribution which is reflected in base rates, and pension expense. <PAGE 42> CAMBRIDGE ELECTRIC LIGHT COMPANY (b) Other Postretirement Benefits Certain employees are eligible for postretirement benefits if they meet specific requirements. These benefits could include health and life insurance coverage and reimbursement of Medicare Part B premiums. Under certain circumstances, eligible employees are required to make contributions for postretirement benefits. To fund its postretirement benefits, the Company makes contributions to various voluntary employees' beneficiary association (VEBA) trusts that were established pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). The Company also makes contributions to a subaccount of its pension plan pursuant to section 401(h) of the Code to fund a portion of its postretirement benefit obligation. The following tables set forth the change in the postretirement benefit obligation and plan assets as well as the plan's funded status reconciled to the amount included in the financial statements: 1998 1997 (Dollars in thousands) Change in benefit obligation Obligation at beginning of year $ 12,875 $ 10,839 Service cost 217 189 Interest cost 889 777 Actuarial loss 352 1,806 Participant contributions 10 4 Benefits paid (836) (740) Obligation at end of year $ 13,507 $ 12,875 1998 1997 (Dollars in thousands) Change in plan assets Fair value of plan assets at beginning of year $ 5,195 $ 4,076 Actual return on plan assets 319 768 Employer contributions 1,121 1,087 Participant contributions 10 4 Benefits paid (836) (740) Fair value of plan assets at end of year $ 5,809 $ 5,195 Funded status $ (7,698) $ (7,680) Unrecognized transition obligation 6,965 7,463 Unrecognized net actuarial loss 733 217 Prepaid (accrued) benefit cost $ - $ - Weighted-average assumptions as of December 31 were as follows: 1998 1997 Discount rate 6.50% 7.00% Expected return on plan assets 9.00 8.75 Rate of increase in future compensation 3.75 3.75 <PAGE 43> CAMBRIDGE ELECTRIC LIGHT COMPANY For measurement purposes, a 6.50% annual rate of increase in the per capita cost of covered medical claims was assumed for 1999. The rates were assumed to decrease gradually to 4.5% for 2007 and remain at that level thereafter. Dental claims and Medicare Part B premiums are expected to increase at 4.5% and 3.1%, respectively. Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect the periodic postretirement benefit cost in future years. Components of net periodic postretirement benefit cost were as follows: 1998 1997 1996 (Dollars in thousands) Service cost $ 217 $ 189 $ 205 Interest cost 889 777 809 Expected return on plan assets (483) (376) (279) Amortization of transition obligation 498 497 498 Total 1,121 1,087 1,233 Transfers from affiliates, net 401 591 555 Add: Net amortization of deferrals 1,248 131 116 Less: Amounts capitalized and deferred 151 133 184 Net periodic postretirement benefit cost $ 2,619 $ 1,676 $ 1,720 Assumed healthcare cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage point change in assumed healthcare cost trend rates would have the following effects: One-Percentage-Point Increase Decrease (Dollars in thousands) Effect on total of service and interest cost components $ 146 $ (117) Effect on postretirement benefit obligation $ 1,571 $(1,481) Effective with its June 1, 1993 rate order from the DPU, the Company was allowed to recover its SFAS No. 106 expense in base rates over a four-year phase-in period with carrying costs on the deferred balance. At December 31, 1998 and 1997, the Company's deferral amounted to approximately $1.6 million and $2 million, respectively. (c) Savings Plan The Company has an Employees Savings Plan that provides for Company contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate and up to five percent for those employees no longer eligible for postretirement health benefits. The Com- pany's contribution was $294,000 in 1998, $302,000 in 1997 and $310,000 in 1996. <PAGE 44> CAMBRIDGE ELECTRIC LIGHT COMPANY (6) Interim Financing and Long-Term Debt (a) Notes Payable to Banks The Company and other COM/Energy companies maintain both committed and uncommitted lines of credit for the short-term financing of their construction programs and other corporate purposes. As of December 31, 1998, COM/Energy companies had $122 million of committed lines of credit that will expire at varying intervals in 1999. These lines are normally renewed upon expiration and require annual fees of up to .1875% of the individual line. At December 31, 1998, COM/Energy's uncommitted lines of credit totaled $10 million. Interest rates on the Company's outstanding borrowings generally are at an adjusted money market rate and averaged 5.7% and 5.8% in 1998 and 1997, respectively. The Company had no notes payable to banks at December 31, 1998 while notes payable to banks totaled $19,000,000 at December 31, 1997. (b) Advances from Affiliates The Company had no notes payable to the Parent at December 31, 1998 and $7,500,000 at December 31, 1997. These notes are written for a term of up to 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in that rate during the term of the notes. The rate averaged 8.3% and 8.5% in 1998 and 1997, respectively. The Company is a member of the COM/Energy Money Pool (the Pool), an arrangement among the subsidiaries of the Parent, whereby short-term cash surpluses are used to help meet the short-term borrowing needs of the utility subsidiaries. In general, lenders to the Pool receive a higher rate of return than they otherwise would on such investments, while borrowers pay a lower interest rate than those available from banks. Interest rates on the out- standing borrowings are based on the monthly average rate the Company would otherwise have to pay banks, less one-half the difference between that rate and the monthly average U.S. Treasury Bill weekly auction rate. The borrow- ings are for a period of less than one year and are payable upon demand. Rates on these borrowings averaged 5.3% and 5.4% in 1998 and 1997, respectively. The Company had no borrowings from the Pool at December 31, 1998, and borrowings totaled $3,790,000 at December 31, 1997. (c) Long-Term Debt Maturities and Retirements Long-term debt outstanding, exclusive of current maturities, current sinking fund requirements and related premiums, is as follows: Original Balance December 31, Issue 1998 1997 (Dollars in thousands) 7-Year Notes - 8.04%, due 1999 $10 000 $ - $10,000 15-Year Notes - 8.7%, due 2007 5 000 5,000 5,000 30-Year Notes - 7 3/4%, due 2002 5 000 2,300 2,400 $ 7,300 $17,400 Under the terms of its Indenture of Trust, the Company is required to make periodic sinking fund payments for retirement of outstanding long-term debt. <PAGE 45> CAMBRIDGE ELECTRIC LIGHT COMPANY The payments and balances of maturing debt issues for the five years subse- quent to December 31, 1998 are as follows: Sinking Fund Maturing Year Payments Debt Issues Total (Dollars in thousands) 1999 $100 $10,000 $10,100 2000 100 - 100 2001 100 - 100 2002 100 2,000 2,100 2003 - - - (d) Disclosures About Fair Value of Financial Instruments The fair value of certain financial instruments included in the accompany- ing Balance Sheets as of December 31, 1998 and 1997 is as follows: 1998 1997 (Dollars in thousands) Carrying Fair Carrying Fair Value Value Value Value Long-Term Debt $17,401 $18,362 $17,502 $18,498 The carrying amount of cash, notes payable to banks and advances to/from affiliates approximates the fair value because of the short maturity of these financial instruments. The estimated fair value of long-term debt is based on quoted market prices of the same or similar issues or on the current rates offered for debt with the same remaining maturity. The fair values shown above do not purport to represent the amounts at which those obligations would be settled. (7) Dividend Restriction At December 31, 1998, none of retained earnings was restricted against the payment of cash dividends by terms of term loans and note agreements securing long-term debt. As of the same date, retained earnings also included approxi- mately $4,909,000 representing the Company's equity in undistributed earnings of the nuclear companies. (8) Lease Obligations The Company leases equipment and office space under arrangements that are classified as operating leases. These lease agreements are for terms of one year or longer. Leases currently in effect contain no provisions that prohibit the Company from entering into future lease agreements or obliga- tions. <PAGE 46> CAMBRIDGE ELECTRIC LIGHT COMPANY Future minimum lease payments, by period and in the aggregate, of noncanc- elable operating leases consisted of the following at December 31, 1998: Operating Leases (Dollars in thousands) 1999 $ 1,420 2000 1,166 2001 998 2002 998 2003 998 Beyond 2003 3,013 Total future minimum lease payments $ 8,593 Total rent expense for all operating leases, except those with terms of a month or less, amounted to $1,307,000 in 1998, $1,683,000 in 1997 and $1,348,000 in 1996. There were no contingent rentals and no sublease rentals for the years 1998, 1997 and 1996. <PAGE 47> CAMBRIDGE ELECTRIC LIGHT COMPANY PART V. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. Index to Financial Statements Financial statements and notes thereto of the Company together with the Report of Independent Public Accountants, are filed under Item 8 of this report and listed on the Index to Financial Statements and Schedules (page 25). (a) 2. Index to Financial Statement Schedules Filed herewith at page(s) indicated - Schedule I - Investments in, Equity in Earnings of, and Dividends Received From Related Parties - Years Ended December 31, 1998, 1997 and 1996 (pages 55-57). Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1998, 1997 and 1996 (page 58). (a) 3. Exhibits: Notes to Exhibits - a. Unless otherwise designated, the exhibits listed below are incorporat- ed by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses. b. The following is a glossary of Commonwealth Energy System and subsid- iary companies' acronyms that are used throughout the following Exhibit Index: CES.....................Commonwealth Energy System CE......................Commonwealth Electric Company CEL.....................Cambridge Electric Light Company CEC.....................Canal Electric Company CG......................Commonwealth Gas Company NBGEL...................New Bedford Gas and Edison Light Company Exhibit Index Exhibit 3. Articles of incorporation and by-laws. 3.1 Articles of incorporation of CEL (Exhibit 1 to the CEL Form 10-K for 1990, File No.2-7909). 3.2 By-laws of CEL, as amended (Exhibit 2 to the CEL Form 10-K for 1990, File No.2-7909). Exhibit 4. Instruments defining the rights of security holders; including indentures. Indenture of Trust or Supplemental Indenture of Trust. 4.1.1 Original Indenture on Form S-1 (April 1949) (Exhibit 7(a), File No. 2-7909). <PAGE 48> CAMBRIDGE ELECTRIC LIGHT COMPANY 4.1.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2- 7909). 4.1.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2- 7909). 4.1.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No. 2-7909). 4.1.5 Seventh Supplemental on Form 10-Q (June 1992) (Exhibit 1, File No. 2-7909). Exhibit 10. Material Contracts. 10.1 Power Contracts. 10.1.1 Power Contract between CEC and CEL dated December 1, 1965 (Exhibit 13(a)(1) to the CEC Form S-1, File No. 2-30057). 10.1.2 Power Contract, as amended to February 28, 1990, superseding the Power Contract dated September 1, 1986 and amendment dated June 1, 1988, between CEC (seller) and CE and CEL (purchasers) for seller's entire share of the Net Unit Capability of Seabrook 1 and related energy produced and other provisions (Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2-30057). 10.1.3 Agreement for Joint-Ownership, Construction and Operation of the New Hampshire Nuclear Units (Seabrook) between CE, Public Service Company of New Hampshire (PSNH) and others dated May 1, 1973 and filed by CE as Exhibit 13(N) on Form S-1 dated October 1973, File No. 2-49013, and as amended below: 10.1.3.1 First through Fifth Amendments to 10.1.3 dated May 24, 1974, June 21, 1974, September 25, 1975, October 25, 1974 and January 31, 1975, respectively (Exhibit 13(m) to CE's Form S-1, (November 7, 1975), File No. 2-54995). 10.1.3.2 Sixth through Eleventh Amendments to 10.1.3 dated April 18, 1979, April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979 and December 15, 1979, respectively (Refiled as Exhibit 1 to the CEC Form 10-K for 1989, File No. 2-30057). 10.1.3.3 Twelfth through Fourteenth Amendments to 10.1.3 dated May 16, 1980, December 31, 1980 and June 1, 1982, respectively (Refiled as Exhibits 1, 2 and 3 to the CE 1992 Form 10-K), File No. 2-7749). 10.1.3.4 Fifteenth and Sixteenth Amendment to 10.1.3 dated April 27, 1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10-Q (June 1984), File No. 2-30057). 10.1.3.5 Seventeenth Amendment to 10.1.3 dated March 8, 1985 (Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2-30057). 10.1.3.6 Eighteenth Amendment to 10.1.3 dated March 14, 1986 (Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2-30057). 10.1.3.7 Nineteenth Amendment to 10.1.3 dated May 1, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2-30057). 10.1.3.8 Twentieth Amendment to 10.1.3 dated September 19, 1986 (Exhibit 1 to the CEC Form 10-K for 1986, File No. 2-30057). <PAGE 49> CAMBRIDGE ELECTRIC LIGHT COMPANY 10.1.3.9 Twenty-First Amendment to 10.1.3 dated November 12, 1987 (Exhibit 1 to the CEC Form 10-K for 1989, File No. 2-30057). 10.1.3.10 Twenty-Second Amendment and Settlement Agreement to 10.1.3 both dated January 13, 1989, (Exhibit 4 to the CEC Form 10-K for 1988, File No. 2-30057). 10.1.4 Capacity Acquisition Agreement between CEC, CEL and CE dated September 25, 1980 (Exhibit 1 to the 1991 CEC Form 10-K, File No. 2-30057). 10.1.4.1 Amendment to 10.1.4 as amended and restated June 1, 1993, hence- forth referred to as the Capacity Acquisition and Disposition Agreement, whereby CEC, as agent, in addition to acquiring power may also sell bulk electric power which the Company and/or CE owns or otherwise has the right to sell (Exhibit 1 to CE's Form 10-Q (September 1993), File No. 2-30057). 10.1.5 Power Contract between Yankee Atomic Electric Company and CEL, dated June 30, 1959, as amended April 1, 1975 (Exhibit 1 to the CEL Form 10-K, File No. 2-7909). 10.1.5.1 Second, Third and Fourth Amendments to 10.1.5 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the CEL Form 10-Q (June 1988), File No. 2-7909). 10.1.5.2 Fifth and Sixth Amendments to 10.1.5 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (Septem- ber 1989), File No. 2-7909). 10.1.6 Power Contract between Connecticut Yankee Atomic Power Company and CEL dated July 1, 1964 (Exhibit 13-K1 to the CES Form S-1, (April 1967) File No. 2-25597). 10.1.6.1 Additional Power Contract to 10.1.6 providing for extension on the contract term dated April 30, 1984 (Exhibit 5 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.6.2 Second Supplementary Power Contract to 10.1.6 providing for decom- missioning financing dated April 30, 1984 (Exhibit 6 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.7 Power Contract between CEL and Vermont Yankee Nuclear Power Corpo- ration dated February 1, 1968 (Exhibit 3 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.7.1 First Amendment (Section 7) and Second Amendment (decommissioning financing) to 10.1.7 as amended June 1, 1972 and April 15, 1983, respectively (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.7.2 Third and Fourth Amendments to 10.1.7 as amended April 1, 1985 and June 1, 1985, respectively (Exhibit 1 and 2 to the CEL Form 10-Q (June 1986) File No. 2-7909). 10.1.7.3 Fifth and Sixth Amendments to 10.1.7 both as amended May 6, 1988 (Exhibit 1 to the CEL Form 10-Q (June 1988), File No. 2-7909). <PAGE 50> CAMBRIDGE ELECTRIC LIGHT COMPANY 10.1.7.4 Seventh Amendment to 10.1.7 as amended June 15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No. 2-7909). 10.1.7.5 Additional Power Contract between CEL and Vermont Yankee Nuclear Power Corporation providing for decommissioning financing and contract extension dated February 1, 1984 (Refiled as Exhibit 1 to the 1993 CEL Form 10-K, File No. 2-7909). 10.1.8 Power Contract between Maine Yankee Atomic Power Company and CEL dated May 20, 1968 (Exhibit 5 to the CES Form S-7, File No. 2- 38372). 10.1.8.1 First Amendment (decommissioning financing) and Second Amendment (supplementary payments) to 10.1.9 as amended March 1, 1984 and January 1, 1984, respectively (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.8.2 Third Amendment to 10.1.8 as amended October 1, 1984 (Exhibit 1 to the CEL Form 10-Q (September 1984), File No. 2-7909). 10.1.9 Participation Agreement between Maine Electric Power Company and CEL and/or NBGEL for the construction of a 345 KV transmission line between Wiscasset, Maine and Mactaquac, New Brunswick, Canada and for the purchase of base and peaking capacity from the New Bruns- wick Electric Power Commission, dated June 20, 1969 (Exhibit 13 to the CES Form 10-K for 1984, File No. 1-7316). 10.1.9.1 Supplement Amending 10.1.9, as amended June 24, 1970 (Exhibit 8 to the CES Form S-7, Amendment No. 1, File No. 2-38372). 10.1.10 Service Agreement for Non-Firm Transmission Service between Boston Edison Company and CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.11 Agreement, dated September 1, 1985, With Respect To Amendment of Agreement With Respect To Use Of Quebec Interconnection, dated December 1, 1981, among certain New England Power Pool (NEPOOL) utilities to include Phase II facilities in the definition of "Project" (Exhibit 1 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.11.1 Amendatory Agreement No. 3 to 10.1.11, as amended June 1, 1990 (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2- 30057). 10.1.12 Preliminary Quebec Interconnection Support Agreement - Phase II among certain NEPOOL utilities, dated June 1,1984 (Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.12.1 First, Second and Third Amendments to 10.1.12 as amended March 1, 1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.12.2 Fourth and Eighth Amendments to 10.1.12 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057). <PAGE 51> CAMBRIDGE ELECTRIC LIGHT COMPANY 10.1.12.3 Fifth, Sixth and Seventh Amendments to 10.1.12 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhib- it 1 to the CEC Form 10-Q (June 1988), File No. 2-30057). 10.1.12.4 Ninth and Tenth Amendments to 10.1.12 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC Form 10-K for 1988, File No. 2-30057). 10.1.12.5 Eleventh Amendment to 10.1.12 as amended November 1, 1989 (Exhibit 4 to the CEC Form 10-K for 1989, File No. 2-30057). 10.1.12.6 Twelfth Amendment to 10.1.12 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057). 10.1.13 Agreement to Preliminary Quebec Interconnection Support Agreement - Phase II among PSNH, New England Power Company, Boston Edison Company and CEC whereby PSNH assigns a portion of its interests under the original Agreement to the other three parties, dated October 1, 1987 (Exhibit 2 to the CEC 1987 Form 10-K, File No. 2-30057). 10.1.14 Phase II Equity Funding Agreement for New England Hydro-Transmis- sion Electric Company, Inc. (New England Hydro (Massachusetts) between New England Hydro and certain NEPOOL utilities, dated June 1, 1985 (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.15 Phase II Equity Funding Agreement for New England Hydro-Transmis- sion Corporation (New Hampshire Hydro) between New Hampshire Hydro and certain NEPOOL utilities, dated June 1, 1985 (Exhibit 3 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.15.1 Amendment No. 1 to 10.1.15 as amended May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.15.2 Amendment No. 2 to 10.1.15 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.16 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro-Transmission Electric Company, Inc. (New England Hydro) and certain NEPOOL utilities (Exhibit 2 the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.17 Phase II New Hampshire Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 8 dated May 1, 1986 through January 1, 1990, respectively, between New England Hydro-Transmission Corporation (New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.18 Phase II New England Power AC Facilities Support Agreement between New England Power and certain NEPOOL utilities, dated June 1, 1985 (Exhibit 6 to the CEC Form 10-Q (September 1985), File No. 2-30057). <PAGE 52> CAMBRIDGE ELECTRIC LIGHT COMPANY 10.1.18.1 Amendments Nos. 1 and 2 to 10.1.18 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.18.2 Amendments Nos. 3 and 4 to 10.1.18 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.19 Phase II Boston Edison AC Facilities Support Agreement between Boston Edison Company and certain NEPOOL utilities, dated June 1, 1985 (Exhibit 7 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.19.1 Amendments Nos. 1 and 2 to 10.1.19 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.19.2 Amendments Nos. 3 and 4 to 10.1.19 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.20 Agreement Authorizing Execution of Phase II Firm Energy Contract among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro Quebec, dated September 1, 1985 (Exhibit 8 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.21 System Power Sales Agreement by and between Connecticut Light and Power (CL&P), Western Massachusetts Electric Company (Northeast Utilities companies), as sellers, and CEL, as buyer, of power in excess of firm power customer requirements from the electric systems of the Northeast Utilities companies, dated June 1, 1984, as effective October 25, 1985 (Exhibit 1 to the CEL 1985 Form 10-K, File No. 2-7909). 10.1.22 Power Sale Agreement by and between Altresco Pittsfield, L. P. and the Company for entitlement to the electric capacity and related energy to be produced by a cogeneration facility located in Pitts- field, Massachusetts, dated February 20, 1992 (Exhibit 1 to the CEL Form 10-Q (September 1993), File No. 2-7909). 10.1.22.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., the Company, CE and New England Power Company, dated July 2, 1993 (Exhibit 3 to the CE Form 10-Q (September 1993), File No. 2-7749). 10.2 Other Agreements. 10.2.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 1 to the CES Form 10-Q (September 1993), File No. 1-7316). 10.2.2 Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1993), File No. 1-7316). <PAGE 53> CAMBRIDGE ELECTRIC LIGHT COMPANY 10.2.2.1 First Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective October 1, 1994. (Exhibit 1 to the CES Form S-8 (January 1995), File No. 1-7316). 10.2.2.2 Second Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective April 1, 1996. (Exhibit 1 to the CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316). 10.2.2.3 Third Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective January 1, 1997. (Exhibit 1 to the CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316). 10.2.2.4 Fourth Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective January 1, 1998. (Exhibit 1 to the CES Form 10-K/A Amendment No. 1 (April 29, 1998), File No. 1-7316). 10.2.3 NEPOOL Agreement dated September 1, 1971 as amended through August 1, 1977 between NEGEA Service Corporation, as agent for CEL, CEC, NBGEL and various other electric utilities operating in New Eng- land, together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980 (Exhibit 5(c)13 to the CES Form S-16 (April 1980), File No. 2-64731). 10.2.3.1 Thirteenth Amendment to 10.2.3 dated September 1, 1981 (Exhibit 3 to the CES 1991 Form 10-K, File No. 1-7316). 10.2.3.2 Fourteenth through Twentieth Amendments to 10.2.3 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316). 10.2.3.3 Twenty-first Amendment to 10.2.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316). 10.2.3.4 Twenty-second Amendment to 10.2.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316). 10.2.3.5 Twenty-third Amendment to 10.2.3 as amended April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316). 10.2.3.6 Twenty-fourth Amendment to 10.2.3 as amended March 1, 1988 (Exhibit 1 to the CES 1987 Form 10-K, File No. 1-7316). 10.2.3.7 Twenty-fifth Amendment to 10.2.3 as amended May 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1988), File No. 1-7316). 10.2.3.8 Twenty-sixth Amendment to 10.2.3 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.2.3.9 Twenty-seventh Amendment to 10.2.3 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316). 10.2.3.10 Twenty-Eighth Amendment to 10.2.3 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316). <PAGE 54> CAMBRIDGE ELECTRIC LIGHT COMPANY 10.2.3.11 Twenty-Ninth Amendment to 10.2.3 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316). 10.2.4 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as initial lender) covering the unconditional guarantee of a portion of the payment obligations of Maine Yankee Atomic Power Company under a loan agreement and note initially between Maine Yankee and MYA Fuel Company (Exhibit 3 to the CEL 1985 Form 10-K, File No. 2-7909). Exhibit 27. Financial Data Schedule Filed herewith as Exhibit 1 is the Financial Data Schedule for the twelve months ended December 31, 1998 (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended Decem- ber 31, 1998. <PAGE 55> SCHEDULE I CAMBRIDGE ELECTRIC LIGHT COMPANY INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1998 (Dollars in Thousands) 1998 Balance Balance December 31, Equity December 31, Name of Issuer and 1997 in Dividends 1998 Description of Investment Shares Amount Earnings Received Amount Common Stock Connecticut Yankee Atomic Power Company 15,750 $5,007 $ 381 $ 675 $4,713 Maine Yankee Atomic Power Company 20,000 3,122 354 - 3,476 Vermont Yankee Nuclear Power Corporation 9,801 1,315 176 169 1,322 Yankee Atomic Electric Company 3,068 405 130 140 395 Total $9,849 $1,041 $ 984 $9,906 Other Investments Massachusetts Business Development Corporation 500 $ 5 $ 5 Total $ 5 $ 5 <FN> Under terms of the capital funds agreements and power contracts, no stock may be sold or transferred except to another stockholder; however, no market exists for these securities. See Note 3(b) of the Notes to Financial Statements included in Item 8 of this report for a information pertaining to the permanent closing of the nuclear plants owned by Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company and Yankee Atomic Electric Company. <PAGE 56> SCHEDULE I CAMBRIDGE ELECTRIC LIGHT COMPANY INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1997 (Dollars in Thousands) 1997 Balance Balance December 31, Equity December 31, Name of Issuer and 1996 in Dividends 1997 Description of Investment Shares Amount Earnings Received Amount Common Stock Connecticut Yankee Atomic Power Company 15,750 $4,747 $ 710 $ 450 $5,007 Maine Yankee Atomic Power Company 20,000 2,829 293 - 3,122 Vermont Yankee Nuclear Power Corporation 9,801 1,324 174 183 1,315 Yankee Atomic Electric Company 3,068 503 (58) 40 405 Total $9,403 $1,119 $ 673 $9,849 Other Investments Massachusetts Business Development Corporation 500 $ 5 $ 5 Total $ 5 $ 5 <FN> Under terms of the capital funds agreements and power contracts, no stock may be sold or transferred except to another stockholder; however, no market exists for these securities. See Note 3(b) of the Notes to Financial Statements included in Item 8 of this report for a information pertaining to the permanent closing of the nuclear plants owned by Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company and Yankee Atomic Electric Company. <PAGE 57> SCHEDULE I CAMBRIDGE ELECTRIC LIGHT COMPANY INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1996 (Dollars in Thousands) 1996 Balance Balance December 31, Equity December 31, Name of Issuer and 1995 in Dividends 1996 Description of Investment Shares Amount Earnings Received Amount Common Stock Connecticut Yankee Atomic Power Company 15,750 $4,564 $ 529 $ 346 $4,747 Maine Yankee Atomic Power Company 20,000 2,891 266 328 2,829 Vermont Yankee Nuclear Power Corporation 9,801 1,305 172 153 1,324 Yankee Atomic Electric Company 3,068 464 39 - 503 Total $9,224 $1,006 $ 827 $9,403 Other Investments Massachusetts Business Development Corporation 500 $ 5 $ 5 Total $ 5 $ 5 <FN> Under terms of the capital funds agreements and power contracts, no stock may be sold or transferred except to another stockholder; however, no market exists for these securities. See Note 3(b) of the Notes to Financial Statements included in Item 8 of this report for information pertaining to the permanent closing of the nuclear plants owned by Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company. <PAGE 58> SCHEDULE II CAMBRIDGE ELECTRIC LIGHT COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (Dollars in Thousands) Additions Balance at Provision Deductions Balance Beginning Charged to Accounts End Description of Year Operations Recoveries Written Off of Year Year Ended December 31, 1998 Allowance for Doubtful Accounts $297 $560 $ 101 $493 $465 Year Ended December 31, 1997 Allowance for Doubtful Accounts $482 $343 $ 49 $577 $297 Year Ended December 31, 1996 Allowance for Doubtful Accounts $490 $279 $ 51 $338 $482 <PAGE 59> CAMBRIDGE ELECTRIC LIGHT COMPANY FORM 10-K DECEMBER 31, 1998 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CAMBRIDGE ELECTRIC LIGHT COMPANY (Registrant) By: R. D. WRIGHT Russell D. Wright, Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Principal Executive Officers: R. D. WRIGHT March 31, 1999 Russell D. Wright, Chairman of the Board and Chief Executive Officer DEBORAH A. McLAUGHLIN March 31, 1999 Deborah A. McLaughlin President and Chief Operating Officer Principal Financial and Accounting Officer: JAMES D. RAPPOLI March 31, 1999 James D. Rappoli, Financial Vice President and Treasurer A majority of the Board of Directors: DEBORAH A. McLAUGHLIN March 31, 1999 Deborah A. McLaughlin, Director JAMES D. RAPPOLI March 31, 1999 James D. Rappoli, Director R. D. WRIGHT March 31, 1999 Russell D. Wright, Director