Item 1. Business
General
Commonwealth Energy System, a Massachusetts trust, is an unincorporated business organization with transferable shares. It is organized under a Declaration of Trust dated December 31, 1926, as amended, pursuant to the laws of Massachusetts. It is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935, holding all of the stock of four operating public utility companies. Commonwealth Energy System, the parent company, is referred to in this report as the "Parent" and, together with its subsidiaries, is collectively referred to as "COM/Energy."
The operating utility subsidiaries of the Parent have been engaged in the generation, transmission and distribution of electricity and the dis- tribution of natural gas, all within Massachusetts. These subsidiaries are:
Electric Gas
Cambridge Electric Light Company Commonwealth Gas Company Canal Electric Company Commonwealth Electric Company
In addition to the utility companies, the Parent also owns all of the stock of a company that operates a total energy plant serving the Longwood Medical Area of Boston (Advanced Energy Systems, Inc.), a steam distribution company (COM/Energy Steam Company), a liquefied natural gas (LNG) and vaporization facility (Hopkinton LNG Corp.), a subsidiary that is pursuing energy-related business opportunities (COM/Energy Technologies, Inc.), and five real estate trusts. An energy marketing subsidiary, COM/Energy Marketing, Inc., sold its assets to Reliant Energy in February 1999. Subsidiaries of the Parent receive technical assistance as well as financial, data processing, accounting, legal and other services from a wholly-owned services company subsidiary (COM/Energy Services Company).
The five real estate subsidiaries are: Darvel Realty Trust, which is a joint-owner of the Riverfront Office Park complex in Cambridge; COM/Energy Acushnet Realty, which leases land to Hopkinton LNG Corp. (Hopkinton); COM/Energy Research Park Realty, which was organized to develop a research building in Cambridge; COM/Energy Cambridge Realty, which was organized to hold various properties; and COM/Energy Freetown Realty (Freetown), which holds 596 acres of land in Freetown, Massachusetts.
Each of the operating utility subsidiaries serves retail customers except for Canal Electric Company (Canal Electric). Canal Electric operated an electric generating station located in Sandwich, Massachusetts until December 30, 1998 when it was sold pursuant to COM/Energy's electric industry restructuring plan that was approved by the Massachusetts Department of Telecommunications and Energy (DTE) and is consistent with the Electric Industry Restructuring Act passed by the Massachusetts legislature in 1997. The station consisted of Canal Unit 1, an oil-fired steam electric generating unit that was wholly-owned by Canal Electric with a rated capacity of 569 megawatts (MW), and Canal Unit 2, a steam electric generating unit with dual- fuel capability (oil and natural gas) that was jointly-owned by Canal Electric
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and Montaup Electric Company (Montaup) (an unaffiliated company) with a rated capacity of 580 MW. Canal Unit 2 was operated under an agreement with Montaup which provides for the equal sharing of output, fixed charges and operating expenses.
Electric service is furnished by Cambridge Electric Light Company (Cam- bridge Electric) and Commonwealth Electric Company (Commonwealth Electric) at retail to approximately 327,000 year-round and 45,500 seasonal customers in 41 communities in eastern and southeastern Massachusetts covering 1,112 square miles and having an aggregate population of 645,000. The territory served includes the communities of Cambridge, New Bedford and Plymouth and the geographic area comprising Cape Cod and Martha's Vineyard. Cambridge Electric also sells power at wholesale to the Town of Belmont, Massachusetts.
Natural gas is distributed by Commonwealth Gas Company (Commonwealth Gas) to approximately 239,000 customers in 51 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1,128,000. Twelve of these communities are also served by Cambridge Electric or Commonwealth Electric with electricity. Some of the larger communities served by Commonwealth Gas include Cambridge, Somerville, New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of Boston.
Advanced Energy Systems, Inc.'s principal assets include a total energy plant (MATEP) and related contracts that were acquired on June 1, 1998 from Harvard University. MATEP provides steam, electricity and chilled water services to several hospitals and professional schools in the Longwood Medical Area of Boston under long-term contracts that will remain in place until at least September 2015. Its major customers are Brigham and Women's Hospital, Beth Israel Deaconess Hospital, Dana-Farber Cancer Institute, the Joslin Diabetes Center, Children's Hospital and Harvard's medical, dental and public health schools. For additional information concerning MATEP, refer to Note 3(e) of Notes to Consolidated Financial Statements filed under Item 8 of this report.
Steam, which was produced by Cambridge Electric in connection with the generation of electricity, was purchased by COM/Energy Steam and, together with its own production, is distributed to 19 customers in Cambridge and two customers (including Massachusetts General Hospital) in Boston. Steam is used for space heating and other purposes.
Industry in the territories served by COM/Energy companies is highly diversified. The larger industrial customers include high-technology firms and manufacturers of such products as photographic equipment and supplies, computer diskettes, rubber products, textiles, wire and other fastening devices, abrasives and grinding wheels, candy, copper and alloys, and chemicals.
In December 1998, the Parent signed an Agreement and Plan of Merger with BEC Energy, the parent company of Boston Edison Company, that will create NSTAR, an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts including more than one million electric customers in 81 communities and 240,000 gas customers in 51 communities. The merger is expected to occur shortly after the satisfaction of certain conditions, including receipt of certain regulatory approvals. The regulatory
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approval process is expected to be completed during the second half of 1999.
Electric Power Supply
On May 27, 1998, COM/Energy agreed to sell substantially all of its non- nuclear generating assets (984 MW) to affiliates of The Southern Company of Atlanta, Georgia. The sale was conducted through an auction process that was outlined in a restructuring plan filed with the DTE in November 1997 in conjunction with the state's industry restructuring legislation enacted in 1997. The sale was approved by the DTE on October 30, 1998 and by the FERC on November 12, 1998. Proceeds from the sale of these assets, after construction-related adjustments at the closing that occurred on December 30, 1998, amounted to approximately $453.9 million or 6.1 times their book value of approximately $74.2 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments, amounted to $358.6 million and will be used to reduce transition costs related to electric industry restructuring that otherwise would have been collected through a non- bypassable transition charge.
Prior to December 30, 1998, COM/Energy owned generating facilities with a net capability at the time of peak load (1,004.7 MW on July 23, 1998) totaling 1,010.6 MW including 559.2 MW provided by Canal Electric Unit 1, of which three-quarters (419.4 MW) was sold to neighboring utilities under long- term contracts, and 275.7 MW was provided by Canal Unit 2. Another 126.1 MW was provided by various smaller units. Of the 541.6 MW available to COM/Energy, 63.1 MW was used principally for peaking purposes. Central Maine Power Company's Wyman Unit 4, an oil-fired facility in which COM/Energy had a 1.4% joint-ownership interest, provided 8.8 MW.
A 3.52% ownership interest in the Seabrook 1 nuclear power plant provides 40.9 MW of capability to COM/Energy. In addition, through Canal Electric's equity ownership in Hydro-Quebec Phase II, COM/Energy has an entitlement of 67.8 MW. Purchase power arrangements were also in place with four natural gas-fired cogenerating units in Massachusetts totaling 204.7 MW. COM/Energy also receives 67 MW from a waste-to-energy plant and has entitlements totaling 23.4 MW through contracts with four hydroelectric sup- pliers.
To satisfy demand requirements and provide required reserve capacity, COM/Energy supplemented its generating capacity by purchasing power on a long and short-term basis through capacity entitlements under power contracts with other New England and Canadian utilities and with Qualifying Facilities and other non-utility generators through a competitive bidding process that is regulated by the DTE.
Pursuant to a restructured Power Sale Agreement (PSA), effective January 1, 1995, a non-utility generator (NUG) ceased supplying capacity and energy to Commonwealth Electric. The restructured PSA defers Commonwealth Electric's obligation to purchase the NUG's capacity and energy for a maximum of six years.
COM/Energy also has available 84.8 MW from two operating nuclear units in which its distribution companies have life-of-the-unit contracts for power. Information with respect to these units is as follows:
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Vermont Yankee Pilgrim
Year of Initial Operation 1972 1972 Contract Expiration Date 2012 2004 Equity Ownership (%) 2.50 - Plant Entitlement (%) 2.25 11.0 Plant Capability (MW) 531.0 668.9 COM/Energy Entitlement (MW) 11.2 73.6
Commonwealth Electric has an 11% entitlement in the Pilgrim nuclear power plant that is expected to be sold by Boston Edison Company in 1999 to Entergy Nuclear Generating Company. In conjunction with this sale, Commonwealth Electric has reached an agreement to buy out of this contract, but will continue to buy power on a declining basis through 2004. Cambridge Electric has a 2.5% equity ownership in the Vermont Yankee nuclear power plant. Vermont Yankee has granted AmerGen Energy Co. an exclusive right to negotiate an agreement to buy the plant.
Information relative to nuclear units that are no longer operating in which COM/Energy has an equity ownership is as follows:
Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands)
Year of Shutdown 1996 1997 1992 Equity Ownership (%) 4.50 4.00 4.50 Equity Ownership Balance $4,713 $3,476 $395
For additional information, refer to Note 3(d) of the Notes to Consolidated Financial Statements filed under Item 8 of this report.
Cambridge Electric, Canal Electric and Commonwealth Electric, together with other electric utility companies in the New England area, are members of Independent System Operator (ISO) - New England (formerly the New England Power Pool or NEPOOL), which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England. ISO - New England operates a centralized dispatching facility to ensure reliability of service and to dispatch the most economically available generating units of the member companies to fulfill the region's energy requirements. This concept is accomplished by use of computers to monitor and forecast load requirements.
ISO - New England, on behalf of its members entered into an Interconnection Agreement with Hydro-Quebec, a Canadian utility operating in the Province of Quebec. The agreement provided for construction of an interconnection (referred to as the Hydro-Quebec Project-Phase I and Phase II) between the electrical systems of New England and Quebec. The parties also entered into an Energy Contract and an Energy Banking Agreement; the former which obligated Hydro-Quebec to offer ISO - New England participants up to 33 million MWH of surplus energy during an eleven-year term that began September 1, 1986 has since expired, and the latter provided for energy transfers between the two systems. ISO - New England also entered into Phase II agreements for an additional purchase from Hydro-Quebec of 7 million MWH per
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year for a twenty-five year period that began in late 1990.
Canal Electric is obligated to pay its share of operating and capital costs for Phase II over a 25 year period ending in 2015. Future minimum lease payments for Phase II have an estimated present value of $11.1 million at December 31, 1998. In addition, Canal has an equity interest in Phase II which amounted to $2.8 million in 1998 and $3.1 million in 1997.
COM/Energy's electric subsidiaries are also members of the Northeast Power Coordinating Council (NPCC), an advisory organization that includes the major power systems in New England and New York plus the Provinces of Ontario and New Brunswick in Canada. NPCC establishes criteria and standards for reliability and serves as a vehicle for coordination in the planning and operation of these systems.
The reserve requirements used by the ISO - New England participants in planning future additions are determined by ISO - New England to meet the reliability criteria recommended by the NPCC. COM/Energy estimates that, during the next ten years, reserve requirements so determined will be approximately 20% of peak load.
Power Supply Commitments and Support Agreements
Cambridge Electric and Commonwealth Electric, through Canal Electric, secure cost savings for their respective customers by planning for bulk power supply on a single system basis. Additionally, Cambridge Electric and Commonwealth Electric have long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. For additional information concerning commitments under long-term power contracts, refer to Note 3(d) of Notes to Consolidated Financial Statements filed under Item 8 of this report.
COM/Energy's 3.52% interest in the Seabrook nuclear power plant is owned by Canal Electric to provide for a portion of the capacity and energy needs of Cambridge Electric and Commonwealth Electric. For additional information concerning Seabrook 1, refer to Note 3(b) of Notes to Consolidated Financial Statements filed under Item 8 of this report.
Commonwealth Electric and Cambridge Electric continue to evaluate bids related to capacity entitlements associated with power contracts in response to electric industry restructuring legislation enacted in Massachusetts in November 1997.
Electric Fuel Supply
(a) Oil and Natural Gas
Of COM/Energy's total energy requirement for 1998, approximately 48% was generated using imported residual oil and approximately 30% was generated using natural gas.
Effective March 15, 1998, Canal Electric executed a one-year contract with Coastal Refining and Marketing, Inc. (Coastal) for the purchase of 1% sulfur residual fuel oil. The contract provided for delivery of a set
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percentage of Canal Electric's fuel requirement, the balance (a maximum of 50%) to be met by spot purchases or by Coastal at the discretion of Canal Electric.
Energy Supply & Credit Corporation (ESCO Massachusetts, Inc.) operated Canal's fuel oil terminal and managed the receipt of and payment for fuel oil under assignment of Canal Electric's supply contracts to ESCO Massachusetts, Inc. Residual fuel oil in the terminal's shore tanks was held in inventory by ESCO Massachusetts, Inc. and delivered upon demand to Canal Electric's two day tanks.
During 1996, Unit 2 was converted to dual-fuel capability, residual fuel oil and natural gas. Canal Electric anticipated that dual-fuel capability would result in future savings as the least expensive fuel was utilized.
(b) Nuclear Fuel Supply and Disposal
Approximately 13% of COM/Energy's total energy requirement for 1998 was generated by nuclear plants. The nuclear fuel contract and inventory information for Seabrook 1 has been furnished to COM/Energy by North Atlantic Energy Services Corporation (NAESCO), the managing agent responsible for operation of the unit. Seabrook's requirement for nuclear fuel components are 100% covered through 2002 by existing contracts.
There are no spent fuel reprocessing or disposal facilities currently operating in the United States. Instead, commercial nuclear electric gener- ating units operating in the United States are required to retain spent fuel on-site. As required by the Nuclear Waste Policy Act of 1982 (the Act), as amended, the joint-owners entered into a contract with the Department of Energy for the transportation and disposal of spent fuel and high level radioactive waste at a national nuclear waste repository or Monitored Retrievable Storage (MRS) facility. Owners or generators of spent nuclear fuel or its associated wastes are required to bear the costs for such transportation and disposal through payment of a fee of approximately 1 mill/KWH based on net electric generation to the Nuclear Waste Fund. Under the Act, a storage or disposal facility for nuclear waste was anticipated to be in operation by 1998; a reassessment of the project's schedule requires extending the completion date of the permanent facility until at least 2010. Seabrook 1 is currently licensed for enough on-site storage to accommodate spent fuel expected to be accumulated through at least the year 2010.
Gas Supply
Commonwealth Gas purchases transportation, storage and balancing services from Tennessee Gas Pipeline Company (Tennessee) and Algonquin Gas Transmission Company (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines) and purchases all of its gas supplies from third-party vendors, utilizing firm contracts with terms of less than one year. The vendors vary from small independent marketers to major gas and oil companies.
In addition to firm transportation and gas supplies mentioned above, Commonwealth Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The underground storage contracts are a
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combination of existing and new agreements which are the result of Federal Energy Regulatory Commission (FERC) Order 636 service unbundling. The LNG facilities, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season.
Commonwealth Gas entered into a multi-party agreement in 1992 to assume a portion of Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta Northeast (ANE) and have the volumes delivered by the Iroquois Gas Transmission System and Tennessee pipelines. The ANE gas supply contract was filed with the DTE and hearings were completed in April 1993. The DTE approved the ANE gas supply contract in November 1995. Commonwealth Gas is presently in negotiations with the parties to allow for final execution of all pertinent agreements and contracts.
Commonwealth Gas began transporting gas on its distribution system in 1990 for end-users. As of December 31, 1998, there were 593 customers using this transportation service, accounting for 11,146 BBTU or approximately 24% of total throughput.
Hopkinton LNG Facility
A portion of the gas supply for Commonwealth Gas during the heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of the Parent. The facility consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 million MCF of natural gas.
In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 500,000 MCF of natural gas that are filled with LNG trucked from Hopkinton.
Commonwealth Gas has contracts for LNG service with Hopkinton extending on a year to year basis with notice of termination required five years in advance of the anticipated termination date. Current contract payments include a demand charge sufficient to cover Hopkinton's fixed charges and an operating charge which covers liquefaction and vaporization expenses. Commonwealth Gas furnishes pipeline gas during the period April 15 to November 15 each year for liquefaction and storage. As the need arises, LNG is vaporized and placed in the distribution system of Commonwealth Gas.
Based upon information presently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, Commonwealth Gas believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales.
Rates, Regulation and Legislation
Certain of COM/Energy's utility subsidiaries operate under the jurisdiction of the DTE which regulates retail rates, accounting, issuance of securities and other matters. In addition, Canal, Cambridge Electric and Commonwealth Electric file their respective wholesale rates with the FERC.
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Electric Industry
(a) Restructuring Legislation
On November 25, 1997, the Governor of Massachusetts signed into law the Electric Industry Restructuring Act (the Act). This legislation provided, among other things, that customers of retail electric utility companies who take standard offer service receive a 10 percent rate reduction and be allowed to choose their energy supplier, effective March 1, 1998. The Act also provides that utilities be allowed full recovery of transition costs subject to review and an audit process. The rate reduction mandated by the legisla- tion increases to 15 percent effective September 1, 1999 for customers who continue to take standard offer service. A statewide ballot referendum that sought to repeal the legislation was defeated by a wide margin on November 3, 1998.
COM/Energy had filed a comprehensive electric restructuring plan with the DTE in November 1997, that was substantially approved by the DTE in February 1998. The divestiture of COM/Energy's non-nuclear generation assets and the entitlements associated with its purchased power contracts through an auction process was an integral part of COM/Energy's restructuring plan and is consistent with the Act. While COM/Energy is encouraged with the treatment afforded net non-mitigable transition costs (which, for COM/Energy, are primarily the result of above-market purchased power contracts with non- utility generators) by the legislation and the DTE, the mandated rate reduc- tion has had a significant impact on cash flows of COM/Energy. However, the successful sale of the generating assets, as discussed below, will reduce the negative impact that the rate reductions will have on future cash flows.
On May 27, 1998, COM/Energy selected affiliates of Southern Energy New England, L.L.C. (Southern Energy), an affiliate of The Southern Company of Atlanta, Georgia, to buy substantially all of its non-nuclear electric generating assets. As a result of construction-related adjustments at the closing on December 30, 1998, the final amount of proceeds from the sale was approximately $454 million. These facilities represented 984 megawatts (MW) of electric capacity and had a book value of $74 million. The plants sold include: Canal Unit 1 (566 mw) and a one-half interest in Canal Unit 2 (282.5 MW) located in Sandwich, MA and owned by Canal Electric; the Kendall Station facility (67 MW) and the adjacent Kendall Jets (46 MW), located in Cambridge, MA and owned by Cambridge Electric; five diesel generators (13.8 MW) in Oak Bluffs and West Tisbury on the island of Martha's Vineyard that are owned by Commonwealth Electric, and a 1.4 percent joint-ownership interest (8.9 MW) in Wyman Unit No. 4 located in Yarmouth, ME, also owned by Commonwealth Electric.
COM/Energy continues to evaluate bids related to the purchased power contracts. COM/Energy is also evaluating the disposition of the Blackstone Station generating unit (15.3 MW) owned by Cambridge Electric and located in Cambridge, MA that is subject to a right of first offer held by Harvard University on any divestiture of the facility.
On July 31, 1998, a divestiture filing was submitted to the FERC and the DTE that requested approval of the sale of the generating assets to Southern Energy and further proposed (subject to completion of the sale) that the current 10 percent rate reduction increase, effective January 1, 1999. On October 30, 1998, the DTE approved COM/Energy's sale of assets to Southern
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Energy. However, at that time, the DTE deferred ruling on the allocation of the net proceeds from the sale of Canal Units 1 and 2 between Cambridge Electric and Commonwealth Electric and on the rate of return to be paid to customers on the net proceeds from the sale over an eleven-year period. The FERC approved the sale on November 12, 1998.
On December 23, 1998, the DTE approved COM/Energy's proposal to establish a special purpose affiliate, Energy Investment Services, Inc. (EIS), that will administer the above-book value net proceeds from the sale of the Canal units with the goal of preserving capital and maximizing earnings for the benefit of retail customers. EIS will credit the proceeds and any return earned to the accounts of Commonwealth Electric and Cambridge Electric, resulting in a reduction in the transition costs to be billed to customers. In addition, COM/Energy agreed to pursue the buyout of above-market purchased power contracts, including the Pilgrim nuclear unit in which Commonwealth Electric has an 11% entitlement. This transaction is expected to occur in the second quarter of 1999.
On December 23, 1998, the DTE approved the divestiture filing that was submitted to the FERC and the DTE on July 31, 1998 that requested approval of the sale of the generating assets to Southern Energy and further proposed (subject to completion of the sale which occurred December 30, 1998) that the 10 percent rate reduction increase, effective January 1, 1999, to approximately 12 percent for Commonwealth Electric and to approximately 16 percent for Cambridge Electric. In addition, the companies proposed to increase the retail price of standard offer service, starting January 1, 1999, from 2.8 cents per kilowatthour (kwh) to 3.5 cents. At the same time, the transition charge for Commonwealth Electric's customers declined from 4.08 cents per kwh to 3.159 cents and for Cambridge Electric's customers from 2.73 cents per kwh to 1.447 cents. These changes are intended to further reduce the cost of electricity to customers, to make the market increasingly more attractive for independent power suppliers to sell electricity directly to consumers, and to reduce cost deferrals associated with the pricing of standard offer service.
No gain was recorded on the sale of the generating assets on a consoli- dated basis as COM/Energy is obligated to reduce Cambridge Electric's and Commonwealth Electric's transition costs by the net proceeds of the sale.
(b) Unbundled Rates
As a result of electric industry restructuring, both Commonwealth Electric and Cambridge Electric have unbundled their rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and have afforded custom- ers the opportunity to purchase generation supply in the competitive market. Unbundled delivery rates are composed of a customer charge (to collect metering and billing costs), a distribution charge (to collect the costs of delivering electricity), a transition charge (to collect past costs for investments in generating plants and costs related to power contracts), a transmission charge (to collect the cost of moving the electricity over high voltage lines from a generating plant), an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge (to collect the cost to support the development and promotion of renewable energy projects). Electricity supply services provided by COM/Energy include optional standard offer service and default service.
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Standard offer service is the electricity that is supplied by the local distribution company (such as Cambridge Electric and Commonwealth Electric) until a competitive power supplier is chosen by the customer. It is designed as a seven-year transitional service to give the customer time to learn about competitive power suppliers. The price of standard offer service will increase over time. Default service is 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, Commonwealth Electric and Cambridge Electric had Fuel Charge rate schedules that generally allowed for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. These schedules required a quarterly computation and DTE approval of a Fuel Charge decimal based upon forecasts of fuel, purchased power, transmission costs and billed unit sales for each period. To the extent that collections under the rate schedules did not match actual costs for that period, an appropriate adjustment was reflected in the calculation of the next subsequent calendar quarter decimal. These rate schedules are no longer in effect.
Also prior to March 1, 1998, Cambridge Electric and Commonwealth Elec- tric collected a portion of capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The recovery mechanism for these costs used a per kwh factor that was calculated using historical (test-period) capacity costs and unit sales. This factor was then applied to current monthly kwh sales. When current period capacity costs and/or unit sales varied from test-period levels, Cambridge Electric and Commonwealth Electric experienced a revenue excess or shortfall that had a significant impact on net income. However, as part of the settlement agree- ments approved by the DTE in May 1995, Cambridge Electric and Commonwealth Electric were allowed to defer these costs (within certain limits) which neutralized their sometimes volatile effect on net income. Both companies also had separately stated Conservation Charge rate schedules that allowed for current recovery, from retail customers, of conservation and load management costs. These rate schedules are no longer in effect.
(c) Retail Choice Pilot Program
Prior to March 1, 1998, the date retail choice was available for all customers, Commonwealth Electric had designed a program to allow a limited number of customers the opportunity to possibly reduce their electric bills while Commonwealth Electric learned more about real-time pricing and the administrative requirements associated with open-market competition. Through the program, Commonwealth Electric developed internal procedures for billing and allocating the costs for providing an alternative supply to its retail customers, and developed methods for educating customers regarding retail choice. The program was available to 18 commercial and industrial customers of Commonwealth Electric that took service under one of Commonwealth Electric's economic development rates. This program was discontinued on February 28, 1998.
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(d) Customer Transition Charge
In September 1995, the DTE issued a ruling largely approving four rate tariffs, including a Customer Transition Charge (CTC), that were filed by Cambridge Electric on March 15, 1995. The CTC was intended to protect remaining customers from paying certain stranded costs that were incurred in the event that Cambridge Electric's largest customers discontinued full service, yet still remain connected for back-up and other services. These costs included long-term power contracts entered into to meet projected energy requirements, investments in substations, underground and overhead lines and current and future decommissioning costs associated with nuclear plants. This ruling is believed to be the first retail stranded cost charge approved nationally and follows the DTE's initial restructuring order which endorsed, in principle, the recovery of stranded costs.
Through the CTC, Cambridge Electric recovered 75% of net stranded costs as calculated in its proposal. Cambridge Electric's other rates include a Supplemental Service Rate, a Standby Service Rate and a Maintenance Service Rate each of which were approved with only minor changes.
Cambridge Electric was an intervenor in an appeal at the Massachusetts Supreme Judicial Court (SJC) filed by the Massachusetts Institute of Technology (MIT) involving this DTE decision approving the CTC for the recovery of stranded investment costs. By its terms, the CTC was terminated on March 1, 1998, coincident with the retail access date established by the Massachusetts Legislature in the Electric Industry Restructuring Act. On September 18, 1997, the SJC remanded the CTC matter to the DTE for further consideration. The SJC stated that, although recovery of prudent and verifiable stranded costs by utility companies is in the public interest and consistent with the Public Utility Regulatory Policies Act, the insufficiencies of the DTE's subsidiary findings precluded the SJC from undertaking a meaningful review of the DTE's calculations that formed the basis of the CTC. The DTE is in the process of determining whether to hear additional evidence in the remand or to rely on the record and pleadings already filed.
(e) Wholesale Rate Proceedings
The Town of Belmont Massachusetts Municipal Light Department (Belmont) is a municipally-owned utility that provides electric service to approximately 25,000 residential customers as well as commercial customers. Belmont purchases approximately 80 percent of its electric requirements from Cambridge Electric under a Net Requirements Power Supply Agreement (NRA). The balance of its electric requirements are currently purchased from the New York Power Authority (NYPA) and Boston Edison Company and transmitted to Belmont under a Transmission Services Agreement with Cambridge Electric.
Net Requirements Power Supply Agreement
Cambridge Electric has provided electric service to Belmont for nearly a century. Historically, Belmont was a full-requirements customer of Cambridge Electric, purchasing a "bundled" power supply and transmission service. In 1985, however, when Belmont received an allocation of approximately two megawatts of low-cost "preference" power from NYPA, Cambridge Electric agreed to provide transmission service for Belmont's NYPA
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power under its firm transmission tariff, and to provide "bundled" power supply and transmission service for the remainder of Belmont's power needs under a "partial requirements" tariff.
On March 8, 1993, Cambridge Electric filed, with the concurrence of Belmont, the NRA which was approved by FERC's June 18, 1993 letter order.
Prior to approving the NRA however, FERC Staff advised Cambridge Electric that the cost-of-service formula in the NRA needed to be clarified and that Cambridge Electric should file such clarification at least sixty days prior to the April 1, 1998 date upon which the formula rate would become applicable under the NRA. In compliance with this requirement, on January 21, 1998, Cambridge Electric submitted a supplemental filing containing the clarification to the formula rate set forth in the NRA. On February 19, 1998, Belmont filed with the FERC a protest claiming that Cambridge Electric's November 1997 announcement of its intention to leave the power supply business would have profound implications for Belmont as they were served from Cambridge Electric's general mix of electric power and that the divestiture will result in unjust and unreasonable charges.
On March 30, 1998, the FERC issued its order approving Cambridge Electric's filing to become effective April 1, 1998 subject to the outcome of the pending proceeding.
On April 29, 1998 Belmont filed a request for rehearing alleging the FERC erred in its March 30 Order by accepting Cambridge Electric's proposed modifications to the NRA without hearing or suspension, and without requiring that Cambridge Electric explain the basis for its deletion of certain protective standards. On May 29, 1998, the FERC issued its order denying rehearing.
Subsequently, Cambridge Electric and Belmont entered into negotiations to settle certain outstanding issues. An amendment to the Order has been signed by both parties and a joint offer of settlement (Joint Offer) was filed January 15, 1999. Cambridge Electric awaits FERC action on the Joint Offer.
Transmission Services Agreement
Cambridge Electric and Belmont entered into discussions in early 1993 to negotiate a transmission services agreement (TSA). However, there were significant differences between the parties and final negotiations were held in late February 1994.
As Cambridge Electric and Belmont were unable to agree on the terms of a TSA, Cambridge Electric filed a proposed TSA with the FERC on June 29, 1994. Belmont intervened in the proceeding. The FERC set the TSA for hearing to determine whether or not it was consistent with a previous memorandum of understanding (MOU) and whether the transmission rates were just and reasonable. Cambridge Electric and Belmont settled on the rate of return before hearings started.
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After the hearing and filing of initial and reply briefs, on September 14, 1995, the presiding administrative law judge (ALJ) issued an initial decision.
The ALJ found that: (i) the proposed transmission agreement rates were not just and reasonable and directed Cambridge Electric to revise the rates based on directly assigned facilities and further that use rights should be based on the same direct assigned facilities; (ii) the proposed transmission agreement, revised in accordance with the findings made in the decision, are consistent with the parties' MOU and; (iii) that Cambridge Electric's pre- existing firm transmission tariff rate is just and reasonable.
On October 16, 1995, Belmont filed a motion for expedited review and issuance of decision. On July 2, 1998, Belmont renewed its motion for issuance of a decision. On July 20, 1998, the FERC issued its opinion and order and affirmed certain parts and reversed other parts of the initial decision.
On August 19, 1998, both Cambridge Electric and Belmont filed requests for rehearing of the July 20, 1998 order each citing issues on which they felt the FERC had erred.
On November 4, 1998, the FERC issued its opinion and order by granting a rehearing for certain issues and denying a rehearing for others.
In the order on rehearing the FERC granted Cambridge Electric's rehearing request on the limited rate issue regarding the method for allocating certain costs. The rehearing order resulted in Cambridge Electric being able to increase its transmission rate to Belmont. In addition to Cambridge Electric receiving increased transmission revenues in the future, the decision substantially reduced Cambridge Electric's refund obligation to Belmont. The FERC's rehearing order denied all of Belmont's rehearing requests including when Belmont has the ability to purchase rights of use from Cambridge Electric.
The Order obligated Cambridge Electric to make a compliance filing to include the necessary revisions to the TSA. Once the FERC approved and accepted the compliance filing, Cambridge Electric would have 30 days to make refunds to Belmont, with interest, back to the refund effective date of January 29, 1995.
On December 4, 1998, Cambridge Electric made its compliance filing. On December 28, 1998, Belmont filed its protest claiming Cambridge Electric's compliance filing contains proposed revisions to the TSA which were not directed by the FERC and therefore should be rejected.
On January 4, 1999, Belmont filed with the United States Court of Appeals for the District of Columbia Circuit a petition for review of the July 20, 1998 and November 4, 1998 FERC orders.
On January 12, 1999, Cambridge Electric filed its response to Belmont's December 28, 1998 protest. Cambridge Electric awaits FERC action on Belmont's protest.
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(f) Transmission Rate Matters
On March 29, 1995, the FERC issued two notices of proposed rulemaking concerning open access transmission and stranded costs. The FERC's notices proposed to remove impediments to competition in the wholesale bulk power marketplace and to bring more efficient, lower-cost power to electric consumers. On March 29, 1996, Cambridge Electric filed transmission tariffs that implemented the FERC's requirements for non-discriminatory open access transmission for both point-to-point and network service. The tariffs were accepted on May 17, 1996 to be effective on May 28, 1996, but the rates are subject to an investigation initiated by the FERC itself. A settlement with the FERC regarding this investigation was filed on February 6, 1997.
On April 24, 1996, the FERC issued Order No. 888, a set of three inter- related rules resolving the above rulemakings. The FERC required all public utilities that own, control or operate transmission facilities in interstate commerce to have on file wholesale Open Access Transmission Tariffs (OATTs) that conform to the FERC pro-forma tariff contained in Order No. 888. On July 9, 1996, Cambridge Electric and Commonwealth Electric filed OATTs that conform to the FERC's pro-forma tariffs. On November 13, 1996, the FERC accepted the non-rate terms and conditions of these tariffs effective July 9, 1996, subject to a revision of one section dealing with the scheduling of services.
On January 21, 1997, Cambridge Electric and Commonwealth Electric filed revised OATTs to be consistent with the recently filed NEPOOL OATT. On March 4, 1997, the FERC issued Order No. 888-A which required revisions to the tariffs filed in compliance with Order No. 888. Cambridge Electric and Commonwealth Electric filed their revised OATTs on July 14, 1997. On July 31, 1997, the FERC issued an order on the July 9, 1996 filings, approving the rates, pending the outcome of any outstanding proceedings. On November 25, 1997, the FERC issued Order No. 888-B requiring minor changes that did not require an additional filing.
On July 31, 1998, Cambridge Electric filed a Settlement Agreement at FERC on regarding the outstanding proceeding referred to in the Order. On September 31, 1998, following the filing of ISO - New England's revised OATT, Cambridge Electric and Commonwealth Electric filed revised OATTs for consistency with ISO - New England. On January 28, 1999. FERC approved the July 31, 1998 Settlement Agreement which applied to Cambridge Electric's July 9, 1996 OATT.
Currently, Cambridge Electric and Commonwealth Electric are awaiting decisions by FERC on the OATTs filed after 1996.
Gas Industry
(a) Industry Restructuring
Commonwealth Gas and eight other gas utilities initiated the Massachu- setts Gas Unbundling Collaborative (the Collaborative) on September 15, 1997, to explore and develop generic principles to achieve the goals set forth by the DTE. Collaborative participants represented a broad array of stakeholder interests including the utilities, natural gas marketers, interstate pipe- lines, producers, energy consultants, labor unions, consumer advocates and representatives for the DTE, the Massachusetts Attorney General's Office, and
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the Massachusetts Division of Energy Resources.
On March 18, 1998, the Collaborative filed a report to the DTE that summarized its progress. The Collaborative reported that it had made substan- tial progress in the areas of rate unbundling and terms and conditions for unbundled services. The report also described at least two policy issues, capacity disposition and cost responsibility, on which the Collaborative's participants require specific regulatory guidance before completing a compre- hensive framework for the transition to a more competitive market structure. In response to this report, the DTE issued a Notice of Inquiry (NOI) to address the Collaborative's unresolved issues. On May 1, 1998, Commonwealth Gas filed initial written comments in the proceeding arguing in favor of a mandatory capacity assignment proposal. On June 8, 1998, the DTE, as part of the aforementioned NOI, received final comments regarding the feasibility of implementing comprehensive unbundling for all local distribution companies (LDCs) by November 1, 1998. On June 29, 1998, Commonwealth Gas and three other Massachusetts LDCs submitted unbundled rate settlements to the DTE for consideration.
The DTE issued a procedural order regarding the NOI on July 2, 1998 which stated that the introduction of comprehensive unbundling for all classes of customers for all LDCs is not feasible by November 1, 1998. The DTE stated that unbundled rates for the four LDCs that filed settlements on June 29, 1998 (including Commonwealth Gas) shall be in place by November 1, 1998 and that comprehensive unbundling shall be implemented no later than April 1, 1999. Also, as part of the July 2, 1998 procedural order, the DTE ordered that a set of proposed Model Terms and Conditions be submitted by the Collaborative no later than July 15, 1998. A partial set of Model Terms and Conditions were submitted on July 10, 1998 that excluded provisions for capacity assignment as well as those related sections of the terms and conditions that required further development by the Collaborative once the issues being addressed in the NOI were resolved by the DTE.
On August 15, 1998, the DTE approved the unbundled rate settlement submitted by Commonwealth Gas. Commonwealth Gas submitted compliance rates consistent with the settlement agreement on September 11, 1998, and unbundled rates became effective on November 1, 1998.
On November 30, 1998 the DTE issued an order approving the partial set of Model Terms and Conditions that were submitted by the Collaborative on July 10, 1998. In response to that order, however, the ten gas companies partici- pating in the Collaborative informed the DTE that an April 1, 1999 implementa- tion date for comprehensive gas unbundling was no longer feasible due to the significant time required by the Collaborative to complete the Model Terms and Conditions once the unresolved issues in the aforementioned NOI were answered by the DTE, as well as the additional time required by the gas companies to develop the systems necessary to implement unbundling consistent with these provisions.
On February 1, 1999, the DTE issued an order in the NOI with regard to capacity assignment and cost responsibility. The DTE found in favor of mandatory capacity assignment, where gas marketers would be required to accept the full cost and contractual obligations of the capacity that the gas companies had historically procured to serve their common customers. In support of its decision, the DTE determined that the capacity market in
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Massachusetts was not yet workably competitive to allow it to remove tradi- tional regulatory controls that were designed to ensure the reliability of gas service to customers. The DTE further reaffirmed that the LDCs must continue with their obligation to plan for and procure sufficient upstream capacity. Finally, the DTE found that alternative approaches to mandatory capacity assignment would result in transition costs that would conflict with the well-established policy on cost allocation.
On February 17, 1999, the Collaborative reconvened to continue its work in completing the Model Terms and Conditions consistent with the DTE's order on capacity assignment with a goal to begin the implementation of comprehen- sive unbundling for all LDCs beginning in 1999.
(b) Unbundled Rates
New unbundled rates for Commonwealth Gas went into effect on November 1, 1998. The unbundled rates were developed in accordance with a Settlement Agreement reached by participants in the Massachusetts Gas Unbundling Collaborative (MGUC) that was filed with the Massachusetts Department of Telecommunications and Energy on June 29, 1998 and approved on August 15, 1998. The new unbundled rates reflect the separation of the Company's gas supply function from its local distribution function.
Commencing with the billing month of November 1998, Commonwealth Gas has a Seasonal Cost of Gas Adjustment Clause (CGAC) and a Local Distribution Adjustment Clause (LDAC) that provide for the recovery, from firm customers or Default Service customers, of certain costs previously recovered through base rates. The CGAC provides for rates that must be approved semi-annually by the DTE. The LDAC provides for rates that require annual approval.
As part of its new unbundled rates, Commonwealth Gas modified its existing CGAC to allow for the following changes: (a) the addition of provisions that allow for the recovery of certain bad-debt expenses; (b) new formulas that no longer adjust the Gas Adjustment Factors for the seasonal embedded gas costs that were in existing sales rates; (c) updated language reflecting the ratemaking requirements for non-core revenue margins; and (d) the removal of provisions for the recovery of environmental remediation costs and FERC Order 636 transition costs, which will instead be recovered through the LDAC.
Commonwealth Gas' new LDAC recovers conservation charges, environmental remediation costs, balancing penalty revenue credits, and costs associated with the its participation in the MGUC.
Competition
COM/Energy continues to develop and implement strategies that deal with the restructured utility industry. The planned merger with BEC Energy, the sale of substantially all its non-nuclear generating assets and the purchase of MATEP are actions that are indicative of COM/Energy's commitment to seeking competitive advantages and other benefits by taking advantage of its strengths. For a more detailed discussion of the pending merger with BEC Energy, refer to the "Merger with BEC Energy" section of Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 of this report. For additional information concerning the
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purchase of MATEP, refer to Note 3(e) of Notes to Consolidated Financial Statements filed under Item 8 of this report.
On February 6, 1997, due to the dramatically changing nature of the electric and gas industries, COM/Energy announced the consolidation of management personnel of Commonwealth Electric, Commonwealth Gas and COM/Energy Services Company effective on that date. The companies continue to operate under their existing company names. The consolidation process for these companies involved the merging of similar functions and activities to eliminate duplication in order to create the most efficient and cost-effective operation possible. In addition, COM/Energy initiated a voluntary personnel reduction program during the second quarter of 1997 which reduced the total number of regular employees by approximately 13%. COM/Energy has reduced its full-time work force approximately 37% since 1990. Also, the introduction of advanced technologies in the workplace continues to improve customer service and COM/Energy's competitive position.
Segment Information
COM/Energy companies provide electric, gas and steam services to retail customers in service territories located in central, eastern and southeastern Massachusetts and, in addition, sell electricity at wholesale to Massachusetts customers and own and operate a cogeneration plant that provides the Longwood Medical Area of Boston with heating, chilled water service and electricity. Other operations of COM/Energy include the pursuit of new business opportunities and the operation of rental properties and other investment activities which do not presently contribute significantly to either revenues or operating income.
Reference is made to additional industry segment information in Note 11 of Notes to Consolidated Financial Statements filed under Item 8 of this re- port.
Environmental Matters
COM/Energy is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. COM/Energy's compliance with these laws and regulations will require capital expenditures of $585,000 from 1999 through 2003 for the electric and gas divisions.
For additional information concerning environmental issues, refer to the "Environmental Matters" section of "Management's Discussion and Analysis of Financial Condition and Results of Operations" filed under Item 7 of this report.
Construction and Financing
For information concerning COM/Energy's financing and construction programs refer to Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 and Note 3(a) of the Notes to Consolidated Financial Statements filed under Item 8 of this report.
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Employees
The total number of full-time employees for COM/Energy declined by approximately 5% to 1,638 in 1998 from 1,727 employees at year-end 1997. Of the current total, 1,029 (63%) are represented by various collective bargaining units covered by separate contracts with expiration dates ranging from March 2001 through April 2003. Although a labor dispute with one collective bargaining unit occurred during 1996, employee relations have generally been satisfactory since the dispute was resolved in September 1996.
Item 2.
Item 2. Properties
Substantially all of COM/Energy's non-nuclear generating assets were sold on December 30, 1998. COM/Energy, through its Canal Electric subsidiary, retained its 3.52% interest (40.5 MW of capacity) in Seabrook 1 and a steam electric generating unit, Blackstone Station in Cambridge, MA with a capability of 15.3 MW, is still owned and operated by Cambridge Electric.
Prior to the sale, COM/Energy's principal electric properties consisted of Canal Unit 1, a 569 MW oil-fired steam electric generating unit, and its one-half ownership in Canal Unit 2, a 580 MW steam electric generating unit with the ability to burn both oil and natural gas, both located in Sandwich, Massachusetts. Additionally, Cambridge Electric owned and operated a steam electric generating station and two gas turbine units located in Cambridge, Massachusetts with a total capability of 100 MW and Commonwealth Electric had an interest in smaller generating units totaling 13.8 MW and a 1.4% (8.8 MW) joint-ownership interest in Central Maine Power Company's Wyman Unit 4.
Other electric properties include an integrated system of distribution lines and substations. In addition, COM/Energy's other principal properties consist of an electric division office building in Wareham, Massachusetts and other structures such as garages and service buildings.
At December 31, 1998, the electric transmission and distribution system consisted of 5,861 pole miles of overhead lines, 4,540 cable miles of underground line, 385 substations and 386,241 active customer meters.
The principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At December 31, 1998, the gas system included 2,826 miles of gas distribution lines, 168,188 services and 247,560 customer meters together with the necessary measuring and regulating equipment. In addition, COM/Energy owns a liquefaction and vaporization plant, a satellite vaporization plant and above- ground cryogenic storage tanks having an aggregate storage capacity equivalent to 3.5 million MCF of natural gas. COM/Energy's gas division owns a central headquarters and service building in Southborough, Massachusetts, five district office buildings and several natural gas receiving and take stations.
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Item 3.
Item 3. Legal Proceedings
Cambridge Electric is an intervenor in an appeal at the Massachusetts Supreme Judicial Court (SJC) filed by MIT of a decision by the DTE approving a customer transition charge that allows Cambridge Electric to recover certain stranded costs. For additional information refer to the "Customer Transition Charge" section in Item 1 of this report.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None
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PART II.
Item 5.
Item 5. Market for the Registrant's Securities and Related Stockholder Matters
(a) Principal Markets
The Parent's common shares are listed on the New York and Pacific stock exchanges. The table below sets forth the high and low closing prices as reported on the New York Stock Exchange composite transactions tape.
1998 by Quarter First Second Third Fourth High $40 $40 13/16 $37 3/4 $40 1/2 Low 30 15/16 34 5/8 29 1/8 31 11/16
1997 by Quarter First Second Third Fourth High $24 1/2 $24 $27 $34 9/16 Low 20 7/8 19 23 3/4 25 11/16
(b) Number of Shareholders at December 31, 1998
11,839 shareholders
(c) Frequency and Amount of Dividends Declared in 1998 and 1997
1998 1997 Per Per Share Share Declaration Date Amount Declaration Date Amount March 26, 1998 $ .405 March 27, 1997 $ .395 June 25, 1998 .405 June 26, 1997 .395 September 24, 1998 .405 September 25, 1997 .395 December 17, 1998 .405 December 18, 1997 .395 $1.620 $1.580
(d) Future dividends may vary depending upon the Parent's earnings and capital requirements as well as financial and other conditions existing at that time.
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Item 6.
Item 6. Selected Financial Data
1998 1997 1996 1995 1994 (Dollars in thousands except common share data)
Operating Revenues Electric $ 636,563 $ 688,508 $ 649,678 $ 604,980 $ 638,150 Gas 306,099 333,977 341,867 306,953 323,568 Steam and other 37,453 19,259 19,360 17,355 15,867 Total $ 980,115 $1,041,744 $1,010,905 $ 929,288 $ 977,585
Net Income $ 54,404 $ 49,901 $ 59,175 $ 51,396 $ 48,968
Common Share Data- Earnings per share $2.48 $2.27 $2.70 $2.36 $2.29 Dividends declared per share $1.62 $1.58 $1.54 $1.50 $1.50 Average shares outstanding 21,534,042 21,531,433 21,529,676 21,311,836 20,827,562
Total Assets $1,762,888 $1,485,050 $1,428,955 $1,392,342 $1,345,032
Long-term debt $ 385,602 $ 364,311 $ 355,305 $ 377,181 $ 418,307 Redeemable preferred shares 11,380 12,200 13,020 13,840 14,660 Common share investment 449,592 430,770 415,694 390,785 362,997 Total Capitalization $ 846,574 $ 807,281 $ 784,019 $ 781,806 $ 795,964
1998 by Quarter 1st 2nd 3rd 4th (Dollars in thousands except per share amounts)
Operating Revenues $276,604 $204,291 $233,606 $265,614 Operating Income 35,054 11,546 15,959 26,301 Income Before Interest Charges 35,749 12,350 28,853 24,361 Net Income 25,559 1,065 16,070 11,710 Earnings per Common Share 1.18 .03 .74 .53 Dividends Declared per Common Share .405 .405 .405 .405 Closing Price of Common Shares- High 40 40 13/16 37 3/4 40 1/2 Low 30 15/16 34 5/8 29 1/8 31 11/16
1997 by Quarter 1st 2nd 3rd 4th (Dollars in thousands except per share amounts)
Operating Revenues $316,190 $221,944 $222,115 $281,495 Operating Income 35,892 7,793 16,887 27,078 Income Before Interest Charges 36,541 8,774 17,227 27,709 Net Income (Loss) 26,400 (1,334) 7,147 17,688 Earnings per Common Share 1.21 (.07) .32 .81 Dividends Declared per Common Share .395 .395 .395 .395 Closing Price of Common Shares- High 24 1/2 24 27 34 9/16 Low 20 7/8 19 23 3/4 25 11/16
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Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
Earnings and Dividends
Earnings and earnings per common share by organizational element for the three-year period were as follows: 1998 1997 1996 Per Per Per Amount Share Amount Share Amount Share (Dollars in thousands except per share amounts)
Electric........... $34,234 $1.59 $34,811 $1.62 $39,667 $1.85 Gas................ 12,214 .57 14,681 .68 16,229 .75 Other.............. 7,026 .32 (579) (.03) 2,229 .10 Total.......... $53,474 $2.48 $48,913 $2.27 $58,125 $2.70
Parent company earnings and dividends on preferred shares were allocated among the electric, gas and other operations of COM/Energy based on the Parent's equity investment in each segment.
1998 versus 1997
Earnings per share for the year 1998 were $2.48 compared to the $2.27 achieved in 1997 and include a one-time gain of 50 cents per share from the sale of real estate. Earnings for 1997 include a one-time after-tax charge of 50 cents per share that related to a voluntary Personnel Reduction Program (PRP). Excluding these one-time items, the decline in earnings for the year was due to an increase in other operation expense (19 cents) reflecting costs associated with outsourcing the information technology, telecommunications and network services function (including costs related to Year 2000 compliance) net of PRP savings. Other factors that negatively impacted earnings were a 17% decline in firm gas sales (27 cents), a revenue shortfall related to demand-side management activity (25 cents), higher interest costs (10 cents), costs associated with new business development (4 cents) and costs related to supporting the industry restructuring referendum question on the November 1998 ballot (2 cents). Factors that had a positive impact on earnings were the labor savings realized from the PRP, a decline in the provision for bad debts (6 cents) and an increase in retail electric sales (2 cents).
1997 versus 1996
Earnings per share for the year 1997 were $2.27 compared to the record level of $2.70 achieved in 1996. Excluding the aforementioned PRP, factors that had a positive impact on earnings for the year were lower operating and maintenance expenses (25 cents) that resulted, in part, from the PRP, an increase in electric unit sales (11 cents) and the absence in 1997 of costs associated with a labor dispute in 1996 (13 cents). Earnings for 1997 were negatively affected by the absence of a 1996 refund associated with a power contract settlement agreement (11 cents), lower firm gas unit sales (8 cents), costs associated with new business development (12 cents), the absence of a 1996 recognition of the recoverability of costs associated with Canal Electric Company's postretirement benefits costs that were subsequently recovered in
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wholesale rates (5 cents) and a lower investment base on generation assets (6 cents).
In March 1998, the Parent's Board of Trustees increased the quarterly dividend rate per share 2.5% from 39 1/2 cents to 40 1/2 cents ($1.62 on an annualized basis). This was the third consecutive year and the fourth time in five years that the Board had voted to increase the quarterly dividend rate. Dividends paid to common shareholders in 1998 were $34.9 million, representing a payout ratio of 65% of 1998 earnings per share.
Electric Operations
Operating revenues from regulated operations for 1998 were $75.7 million (11%) lower than in 1997 due primarily to a 10 percent rate reduction (further discussed below) and decreases in electricity purchased for resale and fuel charges ($58.8 million). The decline in these costs reflects a cost deferral of $42.5 million in conjunction with COM/Energy's restructuring plan as approved by the Massachusetts Department of Telecommunications and Energy (DTE). As a result of electric industry restructuring, COM/Energy has unbun- dled its rates, provided customers with a 10 percent rate reduction as of March 1, 1998 and has afforded customers the opportunity to purchase genera- tion supply in the competitive market. Delivery rates are composed of a customer charge (to collect metering and billing costs), a distribution charge, a transition charge (to collect stranded costs), a transmission charge, an energy conservation charge (to collect costs for demand-side management programs) and a renewable energy charge. Electricity supply services provided by COM/Energy include optional standard offer service and default service. Amounts collected through these various charges will be reconciled to actual expenditures on an on-going basis. For additional information concerning electric industry restructuring, refer to the Rates, Regulation and Legislation section filed under Item 1 of this report. Operating revenues from two non-regulated subsidiaries increased $23.8 million.
Electric operating revenues from regulated operations for 1997 increased $38.8 million (6%) due to greater wholesale sales reflecting the changing capacity needs of non-affiliated utilities ($11.7 million) and the Independent System Operator (ISO) - New England (the agency that operates a centralized facility to ensure reliability of service and dispatch of economically available generating units throughout New England) ($11 million) and higher retail unit sales ($2.4 million). Offsetting these factors was the absence of a $4 million refund associated with a 1996 power contract settlement agreement and lower revenues ($2.1 million) due to the return allowed on Canal Electric's declining investment base.
Unit sales (in Megawatthours or MWH) were as follows: % % 1998 Change 1997 Change 1996
Residential.......... 1,814,258 (0.9) 1,830,793 1.5 1,802,973 Commercial........... 2,560,433 2.2 2,506,215 3.1 2,430,188 Industrial and other. 458,877 (0.5) 459,104 2.1 449,844 Total retail..... 4,833,568 0.8 4,796,112 2.4 4,683,005 Wholesale............ 4,030,454 2.9 3,916,974 43.9 2,721,623 Total............ 8,864,022 1.7 8,713,086 17.7 7,404,628
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In 1998 and 1997, retail unit sales increased due to strong commercial sector sales and approximately 5,700 (1.5%) and 4,200 (1.2%) additional customers, respectively, most of which are permanent year-round residential and commercial customers. In 1998, the increase in the level of wholesale sales primarily reflected increased sales to non-associated utilities, and to a lesser extent, increased sales to the Town of Belmont and to ISO - New England. The change in wholesale sales in 1997 reflected the increased availability of Canal Unit 1 and greater sales to ISO - New England. The changes in wholesale unit sales have little, if any, impact on net income.
The $38.1 million increase (10.7%) in fuel and purchased power costs in 1997 was due primarily to higher wholesale unit sales and higher costs for replacement power due to the shutdown for repairs of both Connecticut Yankee and Maine Yankee in mid- and late-1996, respectively. These units remained out of service until their permanent shutdown in December 1996 and August 1997, respectively.
Gas Operations
Operating revenues from regulated operations decreased $41.9 million (12.7%) during 1998 due primarily to the considerable decline in firm unit sales. Operating revenues from an unregulated subsidiary increased $14.1 million. Also affecting revenues in both periods was a lower average cost of gas.
In 1997, operating revenues from regulated operations decreased $11 million (3.2%) primarily due to a 5.6% decline in firm unit sales ($11.1 million) and lower conservation and load management (C&LM) costs ($1.8 million), offset by an increase in transportation revenues of $1.8 million and revenues from sales of gas to third parties of $3.9 million. Operating revenues from an unregulated subsidiary increased $3.1 million.
Unit sales and transportation volume (in billions of British thermal units or BBTU) were as follows: % % 1998 Change 1997 Change 1996
Residential......... 19,514 (11.5) 22,043 (3.1) 22,759 Commercial.......... 8,965 (19.1) 11,077 (4.2) 11,558 Industrial and other 3,524 (37.0) 5,594 (16.2) 6,676 Total firm....... 32,003 (17.3) 38,714 (5.6) 40,993 Off-system.......... 4,429 65.7 2,673 10.5 2,420 Interruptible and other 1,658 (14.2) 1,933 (34.5) 2,949 Total sales...... 38,090 (12.1) 43,320 (6.6) 46,362 Transportation...... 9,230 41.9 6,506 34.1 4,852 Total............ 47,320 (5.0) 49,826 (2.7) 51,214
The decrease in unit sales to firm customers in 1998 reflects the impact of the milder weather conditions experienced during the year on all customer segments. The fluctuation in interruptible and other sales reflects the competitive market that exists today in the natural gas industry. A portion of the margin realized on these sales reduced the cost of gas sold to firm customers. Degree days for the current year totaled 5,754, 11% lower than last year and 12.1% below the normal level of 6,541.
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The decline in firm unit sales in 1997 was due to decreases to all customer segments that reflected milder weather experienced in the region during the first quarter as compared to a colder period in 1996. Degree days for 1997 totaled 6,463, 3.6% lower than 1996 and 1.2% below normal.
Other Operating Expenses
In 1998, other operation increased $9.8 million (4.3%), despite reflecting the absence of a one-time charge ($17.7 million) related to the aforementioned PRP, due to higher costs related to the outsourcing of the information tech- nology, telecommunications and network services function ($13.3 million) that includes costs associated with Year 2000 compliance, costs associated with new business development ($13.3 million), increased C&LM costs ($5 million) and higher costs associated with real estate operations ($1.3 million). These increases were offset, in part, by a decline in insurance and employee benefits costs ($1.1 million) and labor savings from the PRP, the absence of storm damage costs related to an April 1997 blizzard ($2 million) and a decline in the provision for bad debts ($2.1 million).
Other operation in 1997 increased $10.3 million (4.8%) due to a one-time charge related to the aforementioned PRP, costs associated with new business development ($3.6 million), and an increase in the provision for bad debts ($1.4 million) that reflected higher reserve requirements. The impact of these factors was offset, in part, by lower operating costs ($5 million) that resulted, in part, from the PRP, lower pension costs ($2.7 million) and the absence of costs related to the 1996 labor dispute ($4.6 million).
Maintenance increased $3 million (8.2%) in 1998 due to the addition of the Medical Area Total Energy Plant (MATEP) facility ($1.9 million) and greater expenses related to Canal Unit 1 boiler plant and related equipment. In 1997, maintenance declined $4.1 million (10%) and resulted from a reduction in transmission and distribution-related projects and, to a lesser extent, the PRP.
Depreciation increased $7.6 million (14.2%) during 1998 and reflects the treatment allowed for certain production plant pursuant to the electric industry restructuring legislation as well as a higher level of depreciable plant including the newly acquired MATEP facility. Depreciation increased $1.6 million (3.1%) in 1997 due to additions to property, plant and equipment, that included the costs associated with the conversion of Canal Unit 2 in mid- 1996 to burn natural gas as well as oil.
Federal and state income taxes decreased $4.8 million (15.4%) during 1998 reflecting the level of pre-tax income related to normal operations. The tax impact from the sale of real estate ($6.3 million) was reflected as an offset to the gain from the sale in Other Income on the Consolidated Statements of Income. Federal and state income taxes decreased $4.8 million (13.4%) during 1997 due mainly to the lower level of pre-tax income.
The increase of $823,000 (2.9%) in local property and other taxes for 1998 was due primarily to real estate taxes associated with MATEP and higher real estate tax rates and assessments offset, in part, by a decline in payroll taxes attributable to savings realized from the aforementioned PRP. Local property and other taxes were higher during 1997 due to higher property tax
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rates and assessments within COM/Energy's service territory and an increase in payroll-related taxes due to a 1996 labor dispute.
Other Income
In 1998, other income increased $9.9 million due to the gain from the aforementioned sale of real estate ($10.8 million net of taxes). In 1997, other income decreased $2 million due primarily to the absence of a 1996 recognition of the recoverability of costs associated with Canal Electric's postretirement benefits ($1.8 million) following Federal Energy Regulatory Commission (FERC) approval, and the absence of a gain from the sale of real estate ($402,000 net of taxes) in 1996.
Interest Charges
The $6.6 million (16.3%) increase in total interest charges for 1998 resulted from higher levels of short-term borrowings, the full impact from the issuance of two series of long-term debt in September 1997 and the issuance of new long-term debt in the third quarter of 1998, partially offset by maturing long-term debt and scheduled sinking fund payments. The $2 million decline in total interest charges for 1997 was due to maturing long-term debt and scheduled sinking fund payments partially offset by a slightly higher average level of short-term borrowings.
Liquidity and Capital Resources
Financial Condition
COM/Energy's cash requirements are essentially met through the generation of cash flows from the sale of electricity, natural gas (including liquefied natural gas), steam and chilled water. Cash requirements for current opera- tions, construction programs, debt service and other capital requirements are maintained through internal generation and short-term borrowings made avail- able through COM/Energy's credit lines with banks. Long-term debt issues are used to permanently finance short-term debt when deemed appropriate by management.
The Parent, through its Advanced Energy Systems, Inc. subsidiary (AES), purchased the MATEP total energy plant, that was formerly owned and operated by Harvard University and is located in the Longwood Medical Area of Boston, and related contracts, for $146.3 million on June 1, 1998. This acquisition was ultimately financed with a $40 million equity contribution from the Parent to AES (financed with a 2-year term note issued by the Parent) and $112.5 million in 23-year term notes at a rate of 6.924% with sinking fund payments scheduled to begin in 2003. The notes are secured by long-term contracts between MATEP and its customers. This new venture increased revenues by approximately $34 million in 1998 and it is projected that annual revenues from this facility will average approximately $60 million in the years 1999 through 2003.
COM/Energy's 1998 net cash flow from operating activities ($81.9 million) exceeded funds required to support normal additions to property, plant and equipment. The improved cash flow position also reflects proceeds from the sale of COM/Energy's generating assets and real estate ($466.6 million). No gain was recorded on the sale of the generating assets on a consolidated basis
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as COM/Energy is obligated to reduce Cambridge Electric's and Commonwealth Electric's transition costs by the net proceeds of the sale.
The year's cash requirements for the payment of preferred and common divi- dends ($35.9 million), the payment of maturing long-term debt and sinking fund requirements ($102.1 million) and the repayment of short-term borrowings ($92.1 million) were provided from operations and proceeds from the issuance of long-term debt ($152.5 million) and the sale of assets. Other information on the sources and uses of cash for the past three years is included in the Consolidated Statements of Cash Flows.
On February 12, 1999, the holders of the Parent's Cumulative Preferred Shares (Series A 4.80%, Series B 8.10% and Series C 7.75%) were notified that each series will be redeemed in full effective April 1, 1999. The redemption price of $102 for Series A and $101 for each of Series B and C, plus accrued dividends will be paid upon redemption.
Capital Requirements ------------------------------------------------------------------- Bar graph illustration of comparative two-year (1997-1998) actual and five-year (1999-2003) forecast of capital requirements based on values listed in chart below. -------------------------------------------------------------------
Forecast 1997 1998 1999 2000 2001 2002 2003 (Dollars in millions) Construction- Electric $ 35 $ 38 $ 38 $ 38 $ 41 $ 41 $ 44 Gas 18 19 19 18 19 19 19 Other 4 3 6 10 5 5 5 Maturing Debt 23 102 48 27 5 37 20 Purchase of MATEP - 146 - - - - - Retirement of Preferred Shares - - 11 - - - - $ 80 $308 $122 $ 93 $ 70 $102 $ 88
Capital Requirements and Resources
COM/Energy's projected capital expenditures for the years 1999 through 2003 are $475.8 million, including $122.1 million for 1999 that consists of $63.4 million for construction expenditures and $58.7 million for maturing debt, sinking fund payments and the redemption of the preferred shares. These 1999 expenditures will be met through a combination of long and short-term debt issues and internally-generated funds.
COM/Energy's goal is to maintain a capital structure that preserves an appropriate balance between debt and equity. Management believes its capital resources and liquidity are sufficient to meet its current and projected requirements.
COMMONWEALTH ENERGY SYSTEM
COM/Energy's capitalization structure is presented below:
1998 1997 (Dollars in thousands)
Long-term debt $434,602 48.4% $383,311 41.7% Preferred shares 11,380 1.3 12,200 1.3 Common equity 449,592 50.1 430,770 46.8 Short-term debt 2,000 0.2 94,075 10.2 Total capitalization $897,574 100.0% $920,356 100.0%
Capitalization ------------------------------------------------------------------- Bar graph illustration of comparative five-year (1999-2003) forecast of capitalization components based on values listed in chart below. -------------------------------------------------------------------
Forecast 1999 2000 2001 2002 2003 (Dollars in millions)
Common Equity $ 474 45% $ 488 46% $ 509 47% $ 537 49% $ 566 51% Long-term Debt 480 46 454 43 447 42 435 40 540 48 Short-term Debt 92 9 120 11 121 11 114 11 7 1 $1,046 100% $1,062 100% $1,077 100% $1,086 100% $1,113 100%
Forward-Looking Statements
This discussion contains statements which, to the extent it is not a recitation of historical fact, constitute "forward-looking statements" and is intended to be subject to the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995. A number of important factors affecting the Parent's business and financial results could cause actual results to differ materially from those reflected in the forward-looking statements or projected amounts. Those factors include developments in the legislative, regulatory and competitive environment, certain environmental matters, demands for capital and new business development expenditures and the availability of cash from various sources.
COMMONWEALTH ENERGY SYSTEM
Merger with BEC Energy
The electric utility industry has continued to change in response to legislative and regulatory mandates that are aimed at lowering prices for energy by creating a more competitive marketplace. These pressures have resulted in an increasing trend in the electric industry to seek competitive advantages and other benefits through business combinations. On December 5, 1998, the Parent and BEC Energy (BEC), headquartered in Boston, Massachusetts, entered into an Agreement and Plan of Merger (the Merger Agreement). Pursuant to the Merger Agreement, the Parent and BEC will be merged into a new holding company to be known as NSTAR. Holders of Parent common shares will receive 1.05 shares of NSTAR common stock for each share held while BEC common shareholders will receive one share of NSTAR common stock for each share held. In addition, current Parent and BEC common shareholders have the right to receive cash rather than NSTAR common stock in the amount of $44.10 for each share held, up to an aggregate maximum of $300 million. At the close of the merger, Parent shareholders will own approximately 32% of NSTAR common stock and BEC shareholders will own approximately 68%. The merger is expected to occur shortly after the satisfaction of certain conditions, including the receipt of certain regulatory approvals including that of the DTE. The regulatory approval process is expected to be completed during the second half of 1999.
The merger will create an energy delivery company serving approximately 1.3 million customers located entirely within Massachusetts, including more than one million electric customers in 81 communities and 240,000 gas custom- ers in 51 communities.
Shareholder votes on the merger will be held as part of each of the Parent's and BEC's annual shareholder meetings scheduled for the second quarter of 1999. The Merger Agreement may be terminated under certain circumstances, including by any party if the merger is not consummated by December 5, 1999, subject to an automatic extension of six months if the requisite regulatory approvals have not yet been obtained by such date. The merger will be accounted for using the purchase method of accounting.
Upon effectiveness of the merger, Thomas J. May, BEC's current Chairman, President and Chief Executive Officer (CEO), will become the Chairman and CEO of NSTAR. Russell D. Wright, the Parent's current President and CEO, will become the President and Chief Operating Officer of NSTAR and will serve on NSTAR's board of directors. Also, upon effectiveness of the merger, NSTAR's board of directors will consist of the Parent's and BEC's current trustees.
Provisions of Statement of Financial Accounting Standards No. 71
As described in Note 2(b) of the Notes to Consolidated Financial State- ments, COM/Energy follows the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In the event COM/Energy is somehow unable to meet the criteria for following SFAS No. 71, the accounting impact would be an extraordinary,
COMMONWEALTH ENERGY SYSTEM
non-cash charge to operations in an amount that could be material. Conditions that could give rise to the discontinuance of SFAS No. 71 include: 1) increas- ing competition restricting COM/Energy's ability to establish prices to recover specific costs, and 2) a significant change in the current manner in which rates are set by regulators. COM/Energy monitors these criteria to ensure that the continuing application of SFAS No. 71 is appropriate. Based on the current evaluation of the various factors and conditions that are expected to impact future cost recovery, COM/Energy believes that its retail electric utility operations, excluding generation-related assets, remain subject to SFAS No. 71 and its regulatory assets, including those related to electric generation, remain probable of future recovery.
As a result of electric industry restructuring, COM/Energy's retail electric companies discontinued application of accounting principles applied to their investment in electric generation facilities effective March 1, 1998. COM/Energy will not be required to write off any of its generation-related assets, including regulatory assets. These assets have been retained on the Consolidated Balance Sheets because the legislation and the DTE's plan for a restructured electric industry specifically provide for their recovery through the non-bypassable transition charge.
Year 2000
The Year 2000 issue is the result of computer programs being written using two digits rather than four to define the applicable year. Any computer program that has date sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a temporary inability to process transactions or engage in normal business activities. COM/Energy has been involved in Year 2000 compliancy since 1996.
COM/Energy, on a coordinated basis and with the assistance of RCG Informa- tion Technologies and other consultants, is addressing the Year 2000 issue. COM/Energy has followed a five-phase process in its Year 2000 compliance efforts, as follows: Awareness (through a series of internal announcements to employees and through contacts with vendors); Inventory (all computers, applications and embedded systems that could potentially be affected by the Year 2000 problem); Assessment (all applications or components and the impact on overall business operations and a plan to correct deficiencies and the cost to do so); Remediation (the modification, upgrade or replacement of deficient hardware and software applications and infrastructure modifications); and Testing (a detailed, comprehensive testing program for the modified critical component, system or software that involves the planning, execution and analysis of results).
COM/Energy's inventory phase required an assessment of all date sensitive information and transaction processing computer systems and determined that approximately 90% of its software systems needed some modifications or replacement. Plans were developed and are being implemented to correct and test all affected systems, with priorities assigned based on the importance of the activity. COM/Energy has identified the software and hardware installa- tions that are necessary. All installations are expected to be completed and tested by mid-1999.
COM/Energy has also inventoried its non-information technology systems that may be date sensitive (facilities, electric and gas operations, energy
COMMONWEALTH ENERGY SYSTEM
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.
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,
COMMONWEALTH ENERGY SYSTEM
there may be no practical alternative course of action available to COM/Energy.
COM/Energy is working with other energy industry entities, both regionally and nationally with respect to Year 2000 readiness and is cooperating in the development of local and wide-scale contingency planning.
While COM/Energy believes its efforts to address the Year 2000 issue will allow it to be successful in avoiding any material adverse effect on COM/Energy's operations or financial condition, it recognizes that failing to resolve Year 2000 issues on a timely basis would, in a "most reasonably likely worst case scenario," significantly limit its ability to acquire and distrib- ute energy and process its daily business transactions for a period of time, especially if such failure is coupled with third party or infrastructure failures. Similarly, COM/Energy could be significantly effected by the failure of one or more significant suppliers, customers or components of the infrastructure to conduct their respective operations after 1999. Adverse affects on COM/Energy could include, among other things, business disruption, increased costs, loss of business and other similar risks.
The foregoing discussion regarding Year 2000 project timing, effective- ness, implementation and costs includes forward-looking statements that are based on management's current evaluation using available information. Factors that might cause material changes include, but are not limited to, the availability of key Year 2000 personnel, the readiness of third parties, and COM/Energy's ability to respond to unforeseen Year 2000 complications.
Environmental Matters
Commonwealth Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether Commonwealth Gas may be responsible for remedial actions. In April 1998, Commonwealth Gas recorded an additional liability and corresponding regulatory asset of $500,000 due to an increase in the site clean-up cost estimate for an MGP site for which Commonwealth Gas was previously cited as a Potentially Responsible Party. The DTE has approved recovery of costs associated with MGP sites.
Commonwealth Gas and certain other COM/Energy subsidiaries are also involved in other known or potentially contaminated sites where the associated costs may not be recoverable in rates and have recorded in prior years an estimated liability (and a charge to operations) of $1.8 million to cover the expected costs associated with assessment and remediation activities. These estimates are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. COM/Energy is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of COM/Energy's current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse effect on COM/Energy's results of operations or financial position.
On January 1, 1997, COM/Energy adopted the provisions of Statement of Position (SOP) 96-1, "Environmental Remediation Liabilities." SOP 96-1 pro- vides authoritative guidance for recognition, measurement, display and
COMMONWEALTH ENERGY SYSTEM
disclosure of environmental remediation liabilities in financial statements. COM/Energy has recorded environmental remediation liabilities net of amounts paid of $2.9 million at December 31, 1998. The adoption of SOP 96-1 did not have a material adverse effect on COM/Energy's results of operations or financial position.
New Accounting Principles
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts possibly including fixed-price fuel supply and power con- tracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999 and may be implemented as of the beginning of any fiscal quarter after issuance but cannot be applied retroactively. SFAS No. 133 must be applied to derivative instruments and certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1997 and, at the company's election, before January 1, 1998.
In April 1998, the American Institute of Certified Public Accountants issued SOP 98-5, "Reporting on the Costs of Start-Up Activities" (SOP 98-5). SOP 98-5 provides guidance on the financial reporting of start-up and organi- zation costs and requires that these costs be expensed as incurred.
The adoption of SFAS No. 133 and SOP 98-5 is not expected to have a material impact on COM/Energy's results of operations or financial condition.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Although COM/Energy has material commodity purchase contracts and finan- cial instruments (debt), these instruments are not subject to market risk. COM/Energy's electric distribution and gas distribution subsidiaries have rate making mechanisms which allow for the recovery of fuel costs from customers. The fuel adjustment mechanisms allow COM/Energy's subsidiaries to pass all costs related to the purchase of commodities to the customer, thereby insulat- ing COM/Energy from market risk.
Similarly, any change in the fair market value of COM/Energy's prudently incurred debt obligations realized by COM/Energy would be borne by customers through future rates.
COMMONWEALTH ENERGY SYSTEM
Although not a rate regulated subsidiary, COM/Energy's MATEP facility has cost of service based contracts with its customers which are similar to fuel recovery mechanisms discussed above. Under these contracts, the cost of commodities purchased for generation is passed on to the customer, thereby protecting COM/Energy from changes in the market price of fuel.
Item 8.
Item 8. Financial Statements and Supplementary Data
The Company's financial statements required by this item are filed herewith on pages 37 through 61 of this report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
COMMONWEALTH ENERGY SYSTEM
Item 8. Financial Statements and Supplementary Data
MANAGEMENT'S REPORT Commonwealth Energy System and Subsidiary Companies
The consolidated financial statements presented herein are representa- tions of the management of Commonwealth Energy System. Management recognizes its responsibility for the preparation and presentation of financial state- ments in conformity with generally accepted accounting principles. To fulfill this responsibility, management maintains a system of internal accounting controls, including established policies and procedures and a comprehensive internal auditing program to evaluate the adequacy and effectiveness of accounting and operating controls, compliance with system policies and procedures and the safeguarding of system assets.
The responsibility of our independent auditors' examination is limited to the expression of an opinion as to the fairness of the consolidated financial statements presented. The independent auditors are selected by the Board of Trustees and report their findings thereto through the Audit Commit- tee, which is comprised of three outside Trustees. The Board of Trustees is responsible for ensuring that both the independent auditors and management fulfill their respective responsibilities as they pertain to these consolidat- ed financial statements.
James D. Rappoli, Financial Vice President and Treasurer
February 18, 1999
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees of Commonwealth Energy System:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of COMMONWEALTH ENERGY SYSTEM (the System) (a Massachusetts trust) and subsidiary companies as of December 31, 1998 and 1997, and the related consolidated statements of income, cash flows, changes in common shareholders' investment and changes in redeemable preferred shares for each of the three years in the period ended December 31, 1998. These consolidated financial statements are the responsibility of the System and subsidiary companies' management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Common- wealth Energy System and subsidiary companies as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with general- ly accepted accounting principles.
Arthur Andersen LLP
Boston, Massachusetts February 18, 1999
COMMONWEALTH ENERGY SYSTEM
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
PART II.
FINANCIAL STATEMENTS
Consolidated Statements of Income for the Years Ended December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996
Consolidated Balance Sheets at December 31, 1998 and 1997
Consolidated Statements of Capitalization for the Years Ended December 31, 1998, 1997 and 1996
Consolidated Statements of Changes in Common Shareholders' Investment for the Years Ended December 31, 1998, 1997 and 1996
Consolidated Statements of Changes in Redeemable Preferred Shares for the Years Ended December 31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements
PART IV.
SCHEDULES
I Investments in, Equity in Earnings of, and Dividends Received from Related Parties for the Years Ended December 31, 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.
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(Dollars in thousands except per share amounts)
1998 1997 1996
Operating Revenues Electric $ 636,563 $ 688,508 $ 649,678 Gas 306,099 333,977 341,867 Steam and other 37,453 19,259 19,360 980,115 1,041,744 1,010,905
Operating Expenses Fuel used in electric production, principally oil 107,066 129,021 91,690 Electricity purchased for resale 228,920 265,805 265,019 Cost of gas sold 163,701 184,122 187,530 Other operation 235,426 225,658 215,319 Maintenance 39,864 36,838 40,913 Depreciation 60,997 53,405 51,782 Taxes- Local property 20,879 19,130 18,049 Income 26,253 31,040 35,840 Payroll and other 8,149 9,075 7,839 891,255 954,094 913,981 Operating Income 88,860 87,650 96,924
Other Income Gain from sale of real estate, net 10,789 - 402 Other 1,664 2,601 4,217 12,453 2,601 4,619
Income Before Interest Charges 101,313 90,251 101,543
Interest Charges Long-term debt 37,435 33,572 35,586 Other interest charges 9,474 6,778 6,782 46,909 40,350 42,368
Net Income 54,404 49,901 59,175 Dividends on preferred shares 930 988 1,050 Earnings Applicable to Common Shares $ 53,474 $ 48,913 $ 58,125
Average Number of Common Shares Outstanding 21,534,042 21,531,433 21,529,676 Basic and Diluted Earnings Per Common Share $2.48 $2.27 $2.70
The accompanying notes are an integral part of these consolidated financial statements.
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
(Dollars in thousands)
1998 1997 Assets
Property, Plant and Equipment, at original cost Electric $ 963,181 $1,173,797 Gas 391,069 373,541 Other 118,717 72,475 1,472,967 1,619,813 Less-Accumulated depreciation and amortization 462,153 577,962 1,010,814 1,041,851 Construction work in progress 6,942 7,864 Nuclear fuel in process 1,568 193 1,019,324 1,049,908
Equity in Corporate Joint Ventures Nuclear electric power companies (2.5% to 4.5%) 10,391 10,368 Other investments 3,640 3,399 14,031 13,767
Restricted Cash - Long-term 172,239 -
Current Assets Cash and cash equivalents 74,840 4,299 Restricted cash 21,094 - Accounts receivable, less reserves of $9,084 in 1998 and $9,408 in 1997 122,064 128,946 Unbilled revenues 21,211 32,029 Inventories, at average cost- Electric production fuel oil 572 1,902 Natural gas 24,519 23,301 Materials and supplies 7,833 7,441 Prepaid property taxes 8,112 9,282 Other 5,466 5,786 285,711 212,986
Deferred Charges Regulatory assets 210,628 178,864 Power sale agreements 29,685 - Other 31,270 29,525 271,583 208,389
$1,762,888 $1,485,050
The accompanying notes are an integral part of these consolidated financial statements.
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
(Dollars in thousands)
1998 1997
Capitalization and Liabilities
Capitalization (See separate statement) Common share investment $ 449,592 $ 430,770 Redeemable preferred shares, less current sinking fund requirements 11,380 12,200 Long-term debt, less current sinking fund requirements and maturing debt 385,602 364,311 846,574 807,281
Capital Lease Obligations 10,982 12,272
Current Liabilities Interim Financing- Notes payable to banks 2,000 94,075 Maturing long-term debt 49,000 19,000 51,000 113,075
Other Current Liabilities- Current sinking fund requirements 8,123 8,473 Accounts payable 106,952 107,157 Accrued taxes- Local property and other 10,633 9,795 Income 134,768 14,410 Accrued interest 5,213 6,778 Dividends declared 8,732 8,517 Other 54,462 43,627 328,883 198,757 379,883 311,832
Deferred Credits Accumulated deferred income taxes - 176,354 Regulatory liabilities 375,207 14,087 Nuclear units' purchased power contracts 59,507 69,659 Unamortized investment tax credits 21,616 25,340 Other 69,119 68,225 525,449 353,665
Commitments and Contingencies
$1,762,888 $1,485,050
The accompanying notes are an integral part of these consolidated financial statements.
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(Dollars in thousands)
1998 1997 1996 Operating Activities Net income $ 54,404 $ 49,901 $ 59,175 Gain from sale of real estate, net (10,789) - (402) Effects of noncash items- Depreciation and amortization 74,110 65,646 63,331 Deferred income taxes, net (126,114) 2,542 3,515 Investment tax credits, net (3,723) (1,278) (1,285) Earnings from corporate joint ventures (1,636) (1,348) (1,557) Dividends from corporate joint ventures 1,887 1,272 1,376 Change in working capital, exclusive of cash- Accounts receivable and unbilled revenues 17,700 (12,269) (9,446) Accrued (prepaid) income taxes 120,358 6,500 (14,097) Accrued (prepaid) local property and other taxes 2,008 532 (555) Accounts payable and other 9,449 20,756 (33,956) Transition costs deferral (42,498) - - Fuel charge stabilization deferral, net 1,465 (5,543) 2,372 Deferred postretirement benefits costs - (2,126) (2,157) All other operating items (14,672) (17,034) (3,689) Net cash provided by operating activities 81,949 107,551 62,625
Investing Activities Additions to property, plant and equipment (inclusive of AFUDC)- Electric (38,289) (34,524) (38,844) Gas (19,362) (18,230) (11,611) Other (3,297) (4,804) (2,730) Purchase of total energy plant and related contracts (146,270) - - Proceeds from sale of real estate 22,175 - 700 Proceeds from sale of generating assets, net 444,474 - - Net cash (provided by) used for investing activities 259,431 (57,558) (52,485)
Financing Activities Sale of common shares - - 32 Payment of dividends (35,858) (35,056) (34,205) Proceeds from (payment of) short-term borrowings, net (92,075) (24,400) 62,875 Long-term debt issues 152,500 35,000 - Retirement of long-term debt and preferred shares through sinking funds (8,123) (8,473) (8,436) Long-term debt issues refunded (93,950) (14,260) (33,230) Net cash used for financing activities (77,506) (47,189) (12,964)
Net increase (decrease) in cash, cash equivalents and restricted cash 263,874 2,804 (2,824) Cash and cash equivalents at beginning of period 4,299 1,495 4,319 Cash, cash equivalents and restricted cash at end of period $ 268,173 $ 4,299 $ 1,495
Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of capitalized amounts) $ 44,685 $ 38,201 $ 41,294 Income taxes $ 28,164 $ 24,436 $ 46,563
The accompanying notes are an integral part of these consolidated financial statements.
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1998 AND 1997
(Dollars in thousands)
1998 1997 Common Share Investment Common shares, $2 par value- Authorized-50,000,000 shares Outstanding-21,540,550 shares in 1998 and 21,531,784 shares in 1997 $ 43,081 $ 43,063 Amounts paid in excess of par value 112,170 111,912 Retained earnings 294,341 275,795 Total common share investment 449,592 430,770
Redeemable Preferred Shares, Cumulative, $100 Par Value Series A, 4.80% 2,400 2,520 Series B, 8.10% 3,680 3,840 Series C, 7.75% 6,120 6,660 Less-Current sinking fund requirements (820) (820) Total redeemable preferred shares 11,380 12,200
Long-term Debt Parent Senior Notes due- 1998, 10.45% - 10,000 1999, 10.58% 10,000 10,000 2000, variable rate (5.673% in 1998) 40,000 - Less-Maturing long-term debt (30,000) (10,000) Total Parent long-term debt 20,000 10,000
Subsidiary companies Mortgage Bonds, collateralized by property of operating subsidiaries, due- 2001, 8.99% 10,800 14,450 2006, 8.85% - 34,300 2007, 6.54% 10,000 10,000 2017, 7.04% 25,000 25,000 2020, 7 3/8% - 10,000 2020, 9 7/8% - 40,000 2020, 9.95% 25,000 25,000 2033, 7.11% 35,000 35,000
Notes due- 1999, variable rate (6.25% in 1998 and 6.391% in 1997) 9,000 9,000 1999, 8.04% 10,000 10,000 2002, 7 3/4% 2,400 2,500 2002, 9.30% 30,000 30,000 2003, 7.43% 15,000 15,000 2004, 9.50% 7,500 10,000 2007, 8.70% 5,000 5,000 2007, 9.55% 10,000 10,000 2008, 7.70% 10,000 10,000 2012, 9.37% 14,737 15,789 2013, 7.98% 25,000 25,000 2014, 9.53% 10,000 10,000 2019, 9.60% 10,000 10,000 2021, 6.924% 112,500 - 2023, 8.47% 15,000 15,000 Less-Maturing long-term debt (19,000) (9,000) Current sinking fund requirements (7,303) (7,653) Unamortized discount, net (32) (75) Total subsidiary companies' long-term debt 365,602 354,311
Total long-term debt 385,602 364,311
Total capitalization $846,574 $807,281
The accompanying notes are an integral part of these consolidated financial statements.
COMMONWEALTH ENERGY SYSTEM
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS' INVESTMENT
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Amounts Par Paid in Value Excess $2 Per of Par Retained Shares Share Value Earnings Total (Dollars in thousands)
Balance December 31, 1995 21,528,268 $43,056 $111,749 $235,980 $390,785 Add (Deduct)- Net income - - - 59,175 59,175 Sale of shares 1,408 3 29 - 32 Cost of stock split - - (93) - (93) Cash dividends declared- Common shares-$1.54 per share - - - (33,155) (33,155) Preferred shares - - - (1,050) (1,050) Balance December 31, 1996 21,529,676 43,059 111,685 260,950 415,694 Add (Deduct)- Net income - - - 49,901 49,901 Shares issued pursuant to Long-Term Incentive Compensation Plan 2,108 4 43 - 47 Amortization of deferred compensation - - 184 - 184 Cash dividends declared- Common shares-$1.58 per share - - - (34,068) (34,068) Preferred shares - - - (988) (988) Balance December 31, 1997 21,531,784 43,063 111,912 275,795 430,770 Add (Deduct)- Net income - - - 54,404 54,404 Shares issued pursuant to Long-Term Incentive Compensation Plan 8,766 18 178 - 196 Amortization of deferred compensation - - 80 - 80 Cash dividends declared- Common shares-$1.62 per share - - - (34,928) (34,928) Preferred shares - - - (930) (930) Balance December 31, 1998 21,540,550 $43,081 $112,170 $294,341 $449,592
Consolidated Statements of Changes in Redeemable Preferred Shares Commonwealth Energy System and Subsidiary Companies For the Years Ended December 31, 1998, 1997 and 1996
Authorized and Outstanding Cumulative Preferred Shares-$100 Par Value
Series A Series B Series C Total 4.80% 8.10% 7.75% Shares
Balance December 31, 1995 27,600 41,600 77,400 146,600 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1996 26,400 40,000 72,000 138,400 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1997 25,200 38,400 66,600 130,200 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1998 24,000 36,800 61,200 122,000
The accompanying notes are an integral part of these consolidated financial statements.
COMMONWEALTH ENERGY SYSTEM
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) General Information
Commonwealth Energy System (the Parent) is an exempt public utility holding company with investments in four operating public utility companies located in central, eastern and southeastern Massachusetts. The Parent, together with its subsidiaries, is collectively referred to as "COM/Energy." Electric operations have been involved in the production, distribution and sale of electricity to 373,000 customers in 41 communities including New Bedford, Plymouth, Cambridge and the geographic area comprising Cape Cod. Gas operations serve 239,000 customers in 51 communities including New Bedford, Cambridge, Plymouth and Worcester. In addition to the utility companies, the Parent owns a subsidiary that operates a total energy plant serving the Longwood Medical Area of Boston (see Note 3(e)), a steam distribution company, five real estate trusts, a company engaged in the operation of LNG facilities and a subsidiary that is pursuing energy-related business opportunities.
COM/Energy has 1,638 regular employees including 1,029 (63%) represented by various collective bargaining units covered by separate contracts with expiration dates ranging from March 2001 through April 2003.
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 in 1998 to focus on the transmission and distribution of energy and related services (see Note 2(c).
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 customers in 81 communities and 240,000 gas customers in 51 communities.
(2) Significant Accounting Policies
(a) Principles of Consolidation and Accounting
The consolidated financial statements include the accounts of the Parent and all of its subsidiary companies. All significant intercompany accounts and transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements.
(b) Regulatory Assets and Liabilities
COM/Energy's operating utility companies are regulated as to rates, accounting and other matters by various authorities, including the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Telecommunications and Energy (DTE).
Based on the current regulatory framework, COM/Energy accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulated subsidiaries of the Parent have established various regulatory assets in cases where the DTE and/or the FERC have permitted or are expected to permit recovery of specific costs over time.
COMMONWEALTH ENERGY SYSTEM
Similarly, the regulatory liabilities established by COM/Energy 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 extraordi- nary, 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 COM/Energy'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, COM/Energy believes that its regulatory assets, including those related to generation, are probable of future recovery.
As a result of electric industry restructuring, COM/Energy's retail electric companies discontinued application of accounting principles applied to their investment in electric generation facilities effective March 1, 1998. COM/Energy will not be required to write off any of its generation-related assets, including regulatory assets. These assets will be retained on the Consolidated Balance Sheets because the legislation and the DTE's plan for a restructured electric industry specifically provide for their recovery through a non-bypassable transition charge.
The principal regulatory assets included in deferred charges were as follows: 1998 1997 (Dollars in thousands)
Transition costs $ 47,771 $ - Fuel charge stabilization 26,682 29,655 Postretirement benefit costs 23,958 25,475 Power contract buy-out 15,717 17,609 Deferred income taxes 15,737 13,089 FERC Order 636 transition costs 5,968 7,336 Maine Yankee unrecovered plant and decommissioning costs 30,646 34,908 Connecticut Yankee unrecovered plant and decommissioning costs 25,185 28,566 Yankee Atomic unrecovered plant and decommissioning costs 3,676 6,184 Seabrook related costs 3,008 4,324 Environmental costs 5,079 3,930 Other 7,201 7,788 $210,628 $178,864
The regulatory liabilities, reflected in the accompanying Consolidated Balance Sheets were as follows: 1998 1997 (Dollars in thousands)
Regulatory liability related to sale of generating assets $358,604 $ - Deferred income taxes 12,196 13,143 Demand-side management deferral 3,956 - Other 451 944 $375,207 $ 14,087
The regulatory liability of $358.6 million was established pursuant to COM/Energy's divestiture filing that was approved by the DTE in which COM/Energy agreed to use the net proceeds from the sale of its non-nuclear 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.
COMMONWEALTH ENERGY SYSTEM
COM/Energy's regulatory assets, including the costs associated with existing power contracts with three Yankee nuclear power plants that have shut down permanently (see Note 3(d)), and all of its regulatory liabilities are reflected in rates charged to customers. Regulatory assets are to be recov- ered 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 Parent's electric subsidiaries filed a restructuring plan with the DTE. The plan, approved by the DTE on February 27, 1998, provides that the Parent's retail electric subsidiaries, 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 reductions 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 facili- ties, 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 state's industry restructuring legislation enacted in 1997. The sale was approved by the DTE on October 30, 1998 and by the FERC on November 12, 1998. Proceeds from the sale of these assets, after construction-related adjustments at the closing that occurred on December 30, 1998, amounted to approximately $453.9 million or 6.1 times their book value of approximately $74.2 million. The proceeds from the sale, net of book value, transaction costs and certain other adjustments, amounted to $358.6 million and will be used to reduce transition costs related to electric industry restructuring that otherwise would have been collected through a non-bypassable transition charge.
COM/Energy established Energy Investment Services, Inc. as the vehicle to invest the net proceeds from the sale of Canal Electric Company's (Canal Electric) generation assets. These proceeds will be invested in a conserva- tive 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 Cambridge Electric Light Company (Cambridge Electric) and Commonwealth Electric Company (Commonwealth Electric). The net proceeds have been classi- fied as restricted cash on the Consolidated Balance Sheet.
(d) Equity Method of Accounting
COM/Energy uses the equity method of accounting for investments in corporate joint ventures due, in part, to its ability to exercise significant influence over operating and financial policies of these entities. Under this method, it records as income the proportionate share of the net earnings of the joint ventures with a corresponding increase in the carrying value of the investment. The investment is reduced as cash dividends are received. COM/Energy conducts business with the corporate joint ventures in which it has investments, principally four nuclear generating facilities located in New England and a 3.8% interest in Hydro-Quebec Phase II.
COMMONWEALTH ENERGY SYSTEM
(e) Operating Revenues
Customers are billed for their use of electricity and gas on a cycle basis throughout the month. To reflect revenues in the proper period, the estimated amount of unbilled sales revenue is recorded each month.
COM/Energy's utility companies are generally permitted to bill customers for costs associated with purchased power and transmission, fuel used in electric production, gas, conservation and load management and environmental costs. The amount of such costs incurred but not yet reflected in customers' bills is recorded as unbilled revenues.
(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 rates were as follows:
1998 1997 1996
Electric 3.81% 3.66% 3.65% Gas 2.95 2.95 2.94 District heating and cooling 4.09 3.80 3.89 LNG 3.61 3.65 3.59
(g) Allowance for Funds Used During Construction
Under applicable rate-making practices, COM/Energy companies are permitted to include an allowance for funds used during construction (AFUDC) as an element of their depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which utility companies earn a return. An amount equal to the AFUDC capitalized in the current period is reflected in other interest charges in the accompanying Consolidated Statements of Income and amounted to $413,000, $368,000 and $257,000 in 1998, 1997 and 1996, respectively.
While AFUDC does not provide funds currently, these amounts are recover- able in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 5.5% in 1998, 6.1% in 1997 and 6.2% in 1996.
(h) Earnings Per Share
SFAS No. 128, "Earnings Per Share," requires the presentation of both basic and diluted earnings per share (EPS). Diluted EPS reflect the possible impact on EPS that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. The Parent granted potential awards in the form of common shares to certain key employees pursuant to its Long Term Incentive Compensation Plan (see Note 5(d)) during the first quarter of 1997, and to members of the Board of Trustees in June 1998 pursuant to the Restricted Common Share Plan for Trustees. The granting of these shares did not have a material impact on the Parent's EPS.
(3) Commitments and Contingencies
(a) Capital Expenditures
COM/Energy is engaged in a continuous construction program presently estimated at $327.9 million for the five-year period 1999 through 2003. Of that amount, $63.4 million is estimated for 1999. The program is subject to periodic review and revision.
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(b) Seabrook Nuclear Power Plant
COM/Energy's 3.52% interest in the Seabrook nuclear power plant is owned by Canal Electric, a wholesale electric generating subsidiary, to provide for a portion of the capacity and energy needs of affiliates Cambridge Electric and Commonwealth Electric. Canal Electric is recovering 100% of its Seabrook 1 investment through a power contract with Cambridge Electric and Commonwealth Electric pursuant to FERC and DTE approval.
Pertinent information with respect to Canal Electric's joint-ownership interest in Seabrook 1 and information relating to operating expenses that are included in the accompanying financial statements are as follows:
1998 1997 (Dollars in thousands)
Utility plant-in- service $232,471 $232,471 Plant capacity (MW) 1,150 Nuclear fuel 23,581 22,207 Canal Electric's share: Accumulated depreciation Percent interest 3.52% and amortization (71,929) (64,379) Entitlement (MW) 40.5 Construction work in In-service date 1990 progress 1,852 1,036 Operating license $185,975 $191,335 expiration date 2026
1998 1997 1996 (Dollars in thousands) Operating expenses: Fuel $ 1,274 $ 1,471 $ 1,727 Other operation 4,369 4,206 4,091 Maintenance 1,437 2,364 990 Depreciation 6,577 6,314 6,544 Amortization 1,319 1,319 1,319 $14,976 $15,674 $14,671
Canal Electric and the other joint owners have established a decommis- sioning fund to cover decommissioning costs. The estimated cost to decommis- sion the plant is $489 million in current dollars. Canal Electric's share of this liability (approximately $17.2 million), less its share of the market value of the assets held in a decommissioning trust (approximately $3.2 million), is approximately $14 million at December 31, 1998.
(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.
COM/Energy has an equity ownership interest in four nuclear generating facilities as well as a 3.52% joint-ownership interest in Seabrook 1. The operators of these units maintain nuclear insurance coverage (on behalf of the owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II) and the 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
COMMONWEALTH ENERGY SYSTEM
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 decontamina- tion 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 that 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 COM/Energy has an equity ownership interest have been permanently shut down. The Nuclear Regulatory Commission has approved each of these units' requests to withdraw from participation in the secondary insur- ance 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 five nuclear generating facilities, COM/Energy's retrospective premium could be $600,000 annually or a cumulative total of $5.3 million, exclusive of the effect of inflation indexing (at five-year intervals) and a 5% surcharge ($2.9 million) in the event that total public liability claims from a nuclear incident exceed the funds available to pay such claims.
(d) Power Contracts
COM/Energy has long-term contracts to purchase capacity from various generating facilities. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. Information relative to these contracts is as follows: Range of Contract Expiration Entitlement Cost Dates % MW 1998 1997 1996 (Dollars in thousands) Type of Unit Natural gas 2008-2017 (a) 212.0 $120,926 $127,580 $120,842 Nuclear 2004-2012 (b) 85.1 41,969 41,058 41,280 Waste-to-energy 2015 100 67.0 44,423 43,038 39,622 Hydro 2014-2023 100 23.9 11,359 10,952 12,537 Total 388.0 $218,677 $222,628 $214,281
(a) Includes contracts to purchase power from various non-utility generators with capacity entitlements ranging from 11.1% to 100%.
(b) Commonwealth Electric has an 11% entitlement in the Pilgrim nuclear power plant that is expected to be sold by Boston Edison Company in 1999 to Entergy Nuclear Generating Company. In conjunction with this sale, Commonwealth Electric has reached an agreement to buy out of this contract, but will continue to buy power on a declining basis through 2004. Cambridge Electric has a 2.5% ownership interest in the Vermont Yankee nuclear power plant. The estimated cost to decommission this plant is $406.7 million in current dollars. COM/Energy's share of this liability (approximately $9.2 million), less its share of the market value of the assets held in a decommissioning trust (approximately $5.1 million), is approximately $4 million at December 31, 1998.
COMMONWEALTH ENERGY SYSTEM
Pertinent information with respect to life-of-the-unit contracts with nuclear units that are no longer operating in which COM/Energy has an equity ownership is as follows:
Connecticut Maine Yankee Yankee Yankee Atomic (Dollars in thousands)
Equity Ownership (%) 4.50 4.00 4.50 Plant Entitlement (%) 4.50 3.59 4.50 Contract Expiration Date 2007 2008 2000 Year of Shutdown 1996 1997 1992 1996 Actual Cost ($) 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%) ($) 465,693 403,418 81,699 COM/Energy's decommissioning cost ($) 20,956 14,483 3,676 Market value of assets (100%) ($) 260,641 212,664 148,464 COM/Energy's market value of assets ($) 11,729 7,635 6,681
Based upon regulatory precedent, the operators of the Yankee units believe they will be permitted to continue to collect from power purchasers - (including COM/Energy companies) 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. COM/Energy 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 power contracts are included in electricity purchased for resale in the accompanying Consolidated Statements of Income and are recoverable in revenues.
The estimated aggregate obligations for capacity under the long-term purchased power contracts and a life-of-the-unit contract from the one remaining operating Yankee nuclear unit (Vermont Yankee) in effect for the five years subsequent to 1998 is as follows:
Long-Term Purchased Equity Owned Power Nuclear Unit Total (Dollars in thousands)
1999 $208,479 $5,704 $214,183 2000 205,695 5,318 211,013 2001 211,151 5,710 216,861 2002 216,715 5,876 222,591 2003 215,387 5,621 221,008
Due to changing conditions within the nuclear industry, it is possible that the remaining operating nuclear plant in which COM/Energy has an equity ownership interest could be shut down prior to the expiration of that unit's operating license.
The costs associated with these power contract obligations are a significant component of COM/Energy's stranded costs that are being recovered through a transition charge pursuant to DTE approval.
(e) Acquisition
On June 1, 1998, Advanced Energy Systems, Inc. (AES), a wholly-owned subsidiary of the Parent, acquired for $146.3 million all of the issued and outstanding shares of capital stock of Harvard University's Medical Area Total
COMMONWEALTH ENERGY SYSTEM
Energy Plant, Inc. subsidiary (MATEP) and all rights under customer contracts owned by Harvard University. MATEP's principal asset is a cogeneration plant that provides heating, chilled water service and electricity to several hospitals, medical research centers and teaching institutions in the 200-acre Longwood Medical Area of Boston pursuant to the contracts that were assigned to AES. The purchase price was established through a sealed-bid auction process and the transaction was ultimately financed with an equity contribu- tion from the Parent to AES of approximately $40 million and the proceeds from a permanent financing of $112.5 million in 23-year term notes at a rate of 6.924% with sinking fund payments scheduled to begin in 2003. The notes are secured by long-term contracts between MATEP and its customers.
Results for MATEP are included in the accompanying consolidated finan- cial statements from the date of acquisition.
The acquisition was accounted for under the purchase method of account- ing. The purchase price was allocated based on the fair value of assets acquired and resulted in the recognition of an intangible asset amounting to approximately $31 million that is being amortized on a straight-line basis over fifteen years.
Based on unaudited data, the following pro forma summary presents the consolidated results of operations as if the acquisition had occurred at the beginning of the years presented:
1998 1997 1996 (Dollars in thousands except per share amounts)
Revenues $1,002,205 $1,101,462 $1,070,723
Net Income Applicable to Common Shares $ 51,741 $ 50,913 $ 60,185
Basic and Diluted Earnings per Common Share $2.40 $2.36 $2.80
The pro forma results do not purport to be indicative of the results of operations that actually would have resulted had the acquisition been made at the beginning of the years presented, or of results that may occur in the future.
(f) Environmental Matters
COM/Energy 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 COM/Energy's operations in the past and will continue to have an impact on future operations, capital costs and construc- tion schedules of major facilities with the exception of electric generating facilities since substantially all of COM/Energy's non-nuclear generating assets were sold in 1998. For additional environmental information, see "Environmental Matters" in Management's Discussion and Analysis of Financial Condition and Results of Operations.
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(4) Income Taxes
COM/Energy files a consolidated federal income tax return. For finan- cial reporting purposes, the Parent and its subsidiaries provide taxes on a separate return basis.
The following is a summary of the consolidated provisions for income taxes:
1998 1997 1996 (Dollars in thousands) Federal Current $ 135,073 $24,396 $28,375 Deferred (111,581) 2,612 2,784 Investment tax credits, net (3,723) (1,278) (1,285) 19,769 25,730 29,874 State Current 27,294 5,389 5,542 Deferred (14,073) 316 890 13,221 5,705 6,432 32,990 31,435 36,306 Amortization of regulatory liability relating to deferred income taxes (460) (386) (159) $ 32,530 $31,049 $36,147 Federal and state income taxes charged to: Operating expense $ 26,253 $31,040 $35,840 Other (income) expense 6,277 9 307 $ 32,530 $31,049 $36,147
The significant change in the current and deferred provisions for income taxes in 1998 reflects the current tax related to the sale of COM/Energy's non-nuclear generating assets and the related deferred tax benefit.
Deferred tax liabilities and assets are determined based on the differ- ence between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in the year in which the differences are expected to reverse.
Accumulated deferred income taxes consisted of the following:
1998 1997 (Dollars in thousands) Liabilities Property-related $149,354 $198,183 Transition costs 17,966 - Power contract buy-out 6,135 6,853 Fuel charge stabilization 11,300 12,241 Postretirement benefits plan 6,317 7,742 All other 19,033 16,847 210,105 241,866 Assets Sale of generating assets 139,912 - Long-term power contracts 23,358 - Investment tax credits 16,332 16,058 Pension plan 9,512 6,409 Regulatory liability 5,671 6,103 Personnel reduction program 1,654 1,540 All other 22,688 20,960 219,127 51,070 Accumulated deferred income taxes (deferred tax asset), net $ (9,022) $190,796
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The net deferred tax asset for 1998 is included in other deferred charges in the accompanying Consolidated Balance Sheets. The net deferred income tax liability for 1997 includes a current deferred tax liability of $14,442,000 which is included in accrued income taxes.
The total income tax provision set forth previously represents 37% in 1998 and 38% in 1997 and 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 $30,427 $28,332 $33,363 Increase (Decrease) from statutory levels: State tax net of federal tax benefit 8,594 3,708 4,181 Tax versus book depreciation 1,492 1,714 1,553 Amortization of investment tax credits (3,723) (1,278) (1,285) Reversals of capitalized expenses (672) (654) (654) Dividend received deduction (401) (366) (381) Amortization of excess deferred reserves (2,984) (386) (159) Other (203) (21) (471) $32,530 $31,049 $36,147
Effective federal income tax rate 37% 38% 38%
(5) Employee Benefit Plans
(a) Pension
COM/Energy has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. COM/Energy 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 $ 409,039 $ 340,850 Service cost 7,431 7,565 Interest cost 28,266 24,824 Actuarial loss 39,799 57,936 Benefits paid (25,520) (22,136) Obligation at end of year $ 459,015 $ 409,039
1998 1997 (Dollars in thousands)
Change in plan assets Fair value of plan assets at beginning of year $ 390,625 $ 343,884 Actual return on plan assets 30,228 61,095 Employer contributions 6,048 7,782 Benefits paid (25,520) (22,136) Fair value of plan assets at end of year $ 401,381 $ 390,625
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1998 1997 (Dollars in thousands)
Funded status $ (57,634) $ (18,414) Unrecognized transition obligation 4,822 6,429 Unrecognized prior service cost 10,487 11,922 Unrecognized net actuarial (gain) loss 18,994 (20,480) Prepaid (accrued) benefit cost $ (23,331) $ (20,543)
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 $ 7,431 $ 7,565 $ 7,663 Interest cost 28,266 24,824 24,462 Expected return on plan assets (29,903) (26,596) (24,483) Amortization of transition obligation 1,607 1,607 1,607 Amortization of prior service cost 1,435 1,435 1,435 Total 8,836 8,835 10,684 Less: Amounts capitalized and deferred 2,112 3,017 2,203 Net periodic pension cost $ 6,724 $ 5,818 $ 8,481
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. Commonwealth Electric and Cambridge Electric, in accordance with current ratemaking, are deferring the difference between the pension contribution which is reflected in base rates, and pension expense.
(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, COM/Energy makes contributions to various voluntary employees' beneficiary association trusts that were estab- lished pursuant to section 501(c)(9) of the Internal Revenue Code (the Code). COM/Energy 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:
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1998 1997 (Dollars in thousands) Change in benefit obligation Obligation at beginning of year $ 149,364 $ 125,647 Service cost 2,064 1,919 Interest cost 10,087 9,223 Actuarial loss 8,447 18,620 Participant contributions 134 82 Benefits paid (8,429) (6,127) Obligation at end of year $ 161,667 $ 149,364
1998 1997 (Dollars in thousands) Change in plan assets Fair value of plan assets at beginning of year $ 61,632 $ 45,967 Actual return on plan assets 5,039 9,483 Employer contributions 11,786 12,227 Participant contributions 134 82 Benefits paid (8,429) (6,127) Fair value of plan assets at end of year $ 70,162 $ 61,632
Funded status $ (91,505) $ (87,732) Unrecognized transition obligation 74,697 80,033 Unrecognized net actuarial loss 16,808 7,699 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
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 $ 2,064 $ 1,919 $ 2,211 Interest cost 10,087 9,223 9,352 Expected return on plan assets (5,701) (4,247) (3,138) Amortization of transition obligation 5,336 5,336 5,336 Total 11,786 12,231 13,761 Add: Net amortization of deferrals 3,026 1,119 64 Less: Amounts capitalized and deferred 1,479 1,585 1,678 Net periodic postretirement benefit cost $13,333 $11,765 $12,147
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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 $ 1,730 $ (1,430) Effect on postretirement benefit obligation $19,786 $(18,638)
On April 15, 1997, the DTE issued an accounting ruling allowing Common- wealth Gas Company to include postretirement benefits costs in cost-of-service and to amortize the deferred balance of $10.5 million at March 31, 1997 associated with these costs over a period not to exceed ten years that began in April 1997.
(c) Savings Plan
COM/Energy has an Employees Savings Plan that provides for contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate and up to five percent for those employees no longer eligible for postretirement health benefits. The total COM/Energy contribution was $3,688,000 in 1998, $4,173,000 in 1997 and $4,053,000 in 1996.
(d) Long-Term Incentive Compensation Plan
The Long-Term Incentive Compensation Plan (the Plan), approved by shareholders in 1994, was established to advance the interests of the Parent by providing long-term financial incentives, primarily common shares of the Parent, to selected key employees of COM/Energy for achieving specified objectives. The Parent, in encouraging such share ownership, seeks to attract, retain and motivate employees who hold positions of significant responsibility. Eligible employees are chosen by the Executive Compensation Committee of the Board of Trustees and are presented grant share awards which mature after a three-year vesting period. Shares are issued to participants in March following the close of the third plan year. All shares are subject to forfeiture if specified performance measures are not met. During the applicable vesting period, participants have all the voting, dividend and other related rights of a record holder except that the shares are nontrans- ferable. Common shares granted under the Plan cannot exceed 1% of the total shares issued and outstanding. In 1997, 31,606 common shares, valued at approximately $707,000, were granted to COM/Energy officers. Compensation costs of approximately $270,000 and $231,000 were recorded in 1998 and 1997, respectively, with the remainder to be recognized over the remaining vesting period of 14 months. Common shares granted pursuant to the Plan had no material impact on earnings per share.
(6) Interim Financing and Long-Term Debt
(a) Notes Payable to Banks
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, the uncommitted lines of credit totaled $10 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 5.7% and 5.8% in 1998 and 1997, respectively. Notes payable to banks totaled $2,000,000 and $94,075,000 at December 31, 1998 and 1997, respective- ly.
COMMONWEALTH ENERGY SYSTEM
(b) Long-term Debt Maturities and Retirements
Under terms of various indentures and loan agreements, the Parent and certain subsidiary companies are required to make periodic sinking fund payments for retirement of outstanding long-term debt. These payments and balances of maturing debt issues for the five years subsequent to 1998 are as follows:
Sinking Funds Maturing Debt Issues Year Subsidiaries Parent Subsidiaries Total (Dollars in thousands)
1999 $7,303 $30,000 $19,000 $56,303 2000 7,303 20,000 - 27,303 2001 8,660 - 3,500 12,160 2002 5,010 - 32,000 37,010 2003 4,910 - 15,000 19,910
(7) Redeemable Preferred Shares
Each series of the Parent's preferred shares was issued at par value, $100 per share, and is subject to periodic, mandatory sinking fund payments. The Parent can make additional voluntary redemptions, not exceeding the required redemption, at par, on a non-cumulative basis, on each sinking fund date.
Preferred shares may also be called for redemption, in whole or in part, in excess of the required and voluntary sinking fund redemptions. The obligation to make mandatory redemptions is cumulative and the Parent is not allowed to pay dividends to common shareholders or make optional sinking fund payments if mandatory redemptions are in arrears. Details of redemptions for each series are contained in the following table:
Sinking Funds Optional Dividend 1999-2003 Redemption Rate Mandatory Optional Call Prices (Dollars in thousands)
Series A 4.80% $120 $120 $102 Series B 8.10 160 160 101 Series C 7.75 540 540 101
Preferred shareholders have no voting rights except in the event that six full quarterly dividends have not been paid. In this circumstance, the preferred shareholders are entitled, voting as a class, to elect two of the nine Trustees of the Parent.
The preference of these shares in involuntary liquidation is equal to par value. The shares are of equal rank and are entitled to cumulative dividends at the annual rate established for each series. No dividend can be declared on any series unless proportionate dividends are concurrently declared on the other outstanding series and in the event that dividend payments are in arrears, the Parent may not redeem any shares unless all shares of all preferred series are redeemed.
On February 12, 1999, the holders of each series of preferred shares were notified that the Parent will redeem each series in full effective April 1, 1999.
COMMONWEALTH ENERGY SYSTEM
(8) Disclosures About Fair Value of Financial Instruments
The fair value of certain financial instruments included in the accom- panying Consolidated Balance Sheets as of December 31, 1998 and 1997 are as follows:
1998 1997 Carrying Fair Carrying Fair Value Value Value Value (Dollars in thousands)
Long-term debt $441,905 $480,937 $390,964 $444,970 Preferred shares 12,200 14,848 13,020 14,708
The carrying amount of cash and notes payable to banks approximates the fair value because of the short maturity of these financial instruments.
The estimated fair value of long-term debt and preferred stock are based on quoted market prices of the same or similar issues or on the current rates offered for debt or preferred shares with the same remaining maturity. The fair values shown above do not purport to represent the amounts at which those obligations would be settled.
(9) Lease Obligations
COM/Energy companies lease property, transmission facilities and equipment under agreements, some of which are capital leases. Several subsid- iaries renegotiate certain lease agreements annually. These new agreements are for a term of one year and are renewable monthly thereafter. COM/Energy Services Company has agreements in effect for office furniture, computer and transportation equipment. Generally, these agreements require the lessee to pay related taxes, maintenance and other costs of operation. Leases currently in effect contain no provisions which prohibit COM/Energy companies from entering into future lease agreements or obligations.
The following is a breakdown, by major class, of property under capital lease at December 31: 1998 1997 (Dollars in thousands)
Transmission facilities $11,119 $11,801 Office furniture, computer equipment and other 1,271 1,753 12,390 13,554 Less: Accumulated amortization 68 53 $12,322 $13,501
Future minimum lease payments, by period and in the aggregate, of capital leases and non cancelable operating leases consisted of the following at December 31, 1998: Capital Operating Leases Leases (Dollars in thousands)
1999 $ 2,594 $ 9,974 2000 2,141 4,881 2001 1,643 3,374 2002 1,582 3,374 2003 1,520 3,025 Beyond 2003 15,422 8,394 Total future minimum lease payments 24,902 $33,022 Less: Estimated interest element included therein 12,580 Estimated present value of future minimum lease payments $12,322
COMMONWEALTH ENERGY SYSTEM
Total rent expense for all operating leases, except those with terms of a month or less, amounted to $11,471,000 in 1998, $11,181,000 in 1997 and $12,922,000 in 1996. There were no contingent rentals and no sublease rentals for the years 1998, 1997 and 1996.
(10) Dividend Restriction
At December 31, 1998, approximately $110,799,000 of consolidated retained earnings was restricted against the payment of cash dividends by terms of indentures and note agreements securing long-term debt.
(11) Operating Segment Information
COM/Energy's operations are classified into four reportable segments: utility operations, district heating and cooling, non-regulated energy-related services, and real estate operations.
COM/Energy's four regulated operating public utility companies provide electricity and natural gas services to approximately 612,000 retail customers in communities located in central, eastern and southeastern Massachusetts and sold electricity at wholesale to several other New England utilities. District heating and cooling operations include a steam distribution company, and a company that operates a total energy plant acquired June 1, 1998 that provides electricity, steam, and chilled water services in Boston's Longwood Medical Area. Energy-related services represent subsidiaries that operate liquefied natural gas facilities, marketed electricity and natural gas to high volume customers in the Northeast, and operate an energy information technolo- gy company. Real estate operations consist of five real estate trusts that have been engaged in the development, sale and lease of properties.
The accounting policies used to develop segment information correspond to those described in Note 2, "Significant Accounting Policies." COM/Energy evaluates performance based on earnings from operations before income taxes and nonrecurring gains and losses. The Parent accounts for inter-segment sales and transfers at current market prices. Profits on inter-segment sales are not eliminated.
1998 1997 1996 (Dollars in thousands) Revenues from unaffiliated customers Utility operations $ 901,729 $1,022,485 $ 991,545 District heating and cooling 47,940 16,879 17,242 Energy-related services 28,501 125 - Real estate operations 1,945 2,255 2,118 $ 980,115 $1,041,744 $1,010,905
Inter-segment revenues Utility operations $ 112,893 $ 128,636 $ 109,378 Energy-related services 61,537 47,207 46,514 $ 174,430 $ 175,843 $ 155,892
Income tax expense Utility operations $ 30,284 $ 31,820 $ 35,377 District heating and cooling 1,062 425 1,020 Energy-related services (3,772) (1,679) (1,063) Real estate operations (1,321) 474 506 $ 26,253 $ 31,040 $ 35,840
Depreciation and amortization expense Utility operations $ 69,318 $ 63,642 $ 61,587 District heating and cooling 3,156 298 292 Energy-related services 1,636 1,706 1,452 $ 74,110 $ 65,646 $ 63,331
COMMONWEALTH ENERGY SYSTEM
Interest income Utility operations $ 1,705 $ 1,681 $ 1,721 District heating and cooling 65 40 22 Real estate operations 636 337 237 $ 2,406 $ 2,058 $ 1,980
Interest expense Utility operations $ 38,002 $ 37,055 $ 38,398 District heating and cooling 3,165 4 - Energy-related services 5,681 3,290 3,843 Real estate operations 61 1 127 $ 46,909 $ 40,350 $ 42,368
Net income (loss) Utility operations $ 50,569 $ 52,410 $ 58,088 District heating and cooling 1,956 361 1,583 Energy-related services (7,594) (3,214) (700) Real estate operations 9,473 344 204 $ 54,404 $ 49,901 $ 59,175
Assets Utility operations $1,617,469 $1,434,424 $1,392,302 District heating and cooling 101,149 8,014 7,230 Energy-related services 38,761 36,322 23,236 Real estate operations 5,509 6,290 6,187 $1,762,888 $1,485,050 $1,428,955
Capital Expenditures (including AFUDC) Utility operations $ 57,283 $ 53,221 $ 51,997 District heating and cooling 2,124 1,021 288 Energy-related services 1,541 3,265 769 Real estate operations - 51 131 $ 60,948 $ 57,558 $ 53,185
Significant nonrecurring items (after-tax) Personnel Reduction Program Utility operations $ - $ (10,738) $ -
Gain from Sale of Real Estate Utility operations $ 1,292 $ - $ 402 Real estate operations 9,497 - - $ 10,789 $ - $ 402
Significant noncash items Deferred income taxes and ITC, net Utility operations $ (131,534) $ 1,798 $ 1,972 District heating and cooling 905 (11) 8 Energy-related services 169 (1,305) (63) Real estate operations 623 782 313 $ (129,837) $ 1,264 $ 2,230
Earnings of Corporate Joint Ventures Utility operations $ (1,636) $ (1,348) $ (1,557)
Investment in equity-method investees Utility operations $ 13,219 $ 13,471 $ 13,395 District heating and cooling 12 296 - Energy-related services 800 - - $ 14,031 $ 13,767 $ 13,395
All segment amounts reported above correspond to items reported in the consolidated financial statements and are consistent with the presentation adopted in internal management reports.
COMMONWEALTH ENERGY SYSTEM
PART III.
Item 10.
Item 10. Trustees and Executive Officers of the Registrant
a. Trustees of the Registrant:
Three Trustees will be elected at the Annual Meeting of Shareholders to hold office for the ensuing three years in accordance with the Declaration of Trust which provides for staggered terms of Trustees of three years each. The three Trustees elected at this meeting will hold office for a three-year term and until the election and qualification of their respective successors. Under the terms of the Declaration of Trust, Trustees are required to be elected by a plurality vote of the Shareholders.
The Shares represented by the enclosed form of proxy will be voted, and the persons named in such form of proxy will, unless otherwise directed in the proxy, vote Shares represented by proxies received for the election of the following nominees: Peter H. Cressy William J. O'Brien Russell D. Wright
It is not contemplated that any of the three nominees will be unable to serve. Should any of the nominees be unable to serve, your proxy will be voted for the election of a nominee acceptable to the remaining Trustees.
Information Concerning Nominees and Trustees Common Shares Beneficially Year First Owned as of Became a March 1, Name, Principal Occupation and Term of Office Trustee Age 1999
(A) KEVIN C. BRYANT, General Manager - (D) BankBoston - Europe TERM EXPIRES IN 2000................. (1997) 38 484
(C) SHELDON A. BUCKLER, Chairman of the Board of Commonwealth Energy System; Retired Vice Chairman of the Board, Polaroid Corporation, Cambridge, Massachusetts; Director, Aseco Corp.; Lord Corporation; Nashua Corporation and Parlex Corp. TERM EXPIRES IN 2001................. (1991) 67 6,821
(A) PETER H. CRESSY, Chancellor, University of (E) Massachusetts Dartmouth, North Dartmouth, Massachusetts; Retired Rear Admiral, United States Navy TERM EXPIRES IN 1999 (NOMINEE)....... (1994) 57 637
(A) BETTY L. FRANCIS, Executive Vice President (D) and Chief Credit Officer, HomeSide Lending, Inc., Jacksonville, Florida TERM EXPIRES IN 2001................. (1991) 52 685
COMMONWEALTH ENERGY SYSTEM
Information Concerning Nominees and Trustees (Continued)
Common Shares Beneficially Year First Owned as of Became a March 1, Name, Principal Occupation and Term of Office Trustee Age 1999
(C) FRANKLIN M. HUNDLEY, Of Counsel, (D) Rich, May, Bilodeau & Flaherty, P.C., Boston, Massachusetts (Attorneys); Chairman of the Board and a Trustee, Berkshire Energy Resources TERM EXPIRES IN 2000................ (1985) 64 5,389
(B) WILLIAM J. O'BRIEN, Partner, Centre For (C) Generative Leadership L.L.C., Hamilton, Massachusetts (Consulting); Retired President and CEO, The Hanover Insurance Company TERM EXPIRES IN 1999 (NOMINEE)........ (1994) 66 5,785
(B) MICHAEL C. RUETTGERS, President, Chief (E) Executive Officer and a Director, EMC Corporation, Hopkinton, Massachusetts (Data storage technology); Director, EG&G Inc. TERM EXPIRES IN 2001.................. (1995) 56 1,280
(B) GERALD L. WILSON, Vannevar Bush Professor of (E) Engineering, Massachusetts Institute of Technology, Cambridge, Massachusetts; Director, Analogics Corp. and Aseco Corp. TERM EXPIRES IN 2000.................. (1985) 59 1,975
RUSSELL D. WRIGHT, President and Chief Executive Officer of Commonwealth Energy System and Chairman and a Director of its subsidiary companies TERM EXPIRES IN 1999 (NOMINEE)........ (1998) 52 15,561
Each of the persons named above has held his or her present position (or another executive position with the same employer) for more than the past five years.
Each Trustee, including nominees, owned beneficially less than one-third of one percent of the outstanding Common Shares.
(A) Member of Audit Committee. (B) Member of Executive Compensation Committee. (C) Member of Nominating Committee. (D) Member of Benefit Review Committee. (E) Member of Strategic Planning Committee.
COMMONWEALTH ENERGY SYSTEM
b. Executive Officers of the Registrant: Age at December Name of Officer Position and Business Experience 31, 1998
Russell D. Wright President, Chief Executive Officer 52 and Trustee of the Parent and Chairman and Chief Executive Officer of its principal subsidiary companies effective September 1, 1998; Vice Chairman and Chief Executive Officer of Utility Operations effective March 1, 1998; President and Chief Operating Officer of Commonwealth Gas Company* effective February 6, 1997 and President and Chief Operating Officer of Cambridge Electric Light Company*, Canal Electric Company*, COM/Energy Steam Company*, and Commonwealth Electric Company* effective March 1, 1993; Financial Vice President and Treasurer of the Parent and Financial Vice President of its subsidiary companies from 1987 to 1993.
Deborah A. McLaughlin President and Chief Operating Officer of 40 Utility Operations effective March 1, 1998; Vice President of Customer Service for Utility Operations from 1997 to 1998; Vice President of Customer Service for Cambridge Electric Light Company*, Canal Electric Company*, COM/Energy Steam Company*, and Commonwealth Electric Company* from 1993 to 1997; Audit Manager for COM/Energy Services Company* from 1987 to 1993.
James D. Rappoli Financial Vice President and Treasurer of 47 the Parent and its subsidiary companies effective March 1, 1993; Treasurer of Parent subsidiary companies from 1990 to 1993; Assistant Treasurer of Parent subsidiary companies from 1989 to 1990.
Michael P. Sullivan Vice President, Secretary, and 50 General Counsel of the Parent and subsidiary companies (effective June 1993); Vice President, Secretary, and General Attorney of the Parent and subsidiary companies since 1981.
* Subsidiary of the Parent.
COMMONWEALTH ENERGY SYSTEM
b. Executive Officers of the Registrant (Continued): Age at December Name of Officer Position and Business Experience 31, 1998
John R. Williams Vice President of Corporate Services of 55 COM/Energy Services Company* (effective December 2, 1996); Vice President of Operations at Commonwealth Electric* from 1993 to 1996; Vice President of Human Resources and Communications at COM/Energy Services Company* from 1990 to 1993; Vice President of Corporate Human Resources at COM/Energy Services Company* from 1987 to 1990.
* Subsidiary of the Parent.
The term of office for Parent officers expires on the date of the next Annual Organizational Meeting.
There are no family relationships between any trustee and executive officer and any other trustee or executive of the Parent. There were no arrangements or understandings between any officer or trustee and any other person pursuant to which he was or is to be selected as an officer, trustee or nominee.
There have been no events under any bankruptcy act, no criminal pro- ceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any trustee or executive officer during the past five years.
COMMONWEALTH ENERGY SYSTEM
Item 11.
Item 11. Executive Compensation
The following table shows compensation paid by the Parent and its subsidiaries to the Parent's President and Chief Executive Officer and the four other highest paid Executive Officers of the Parent whose total compensa- tion in 1998 exceeded $100,000.
COMMONWEALTH ENERGY SYSTEM
PENSION PLAN
The following table shows annual retirement benefits payable to employees, including Executive Officers, upon retirement at age 65, in various compensation and years of service classifications, assuming the election of a retirement allowance payable as a life annuity from the Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies and the Executive Salary Continuation and Excess Benefit Plan for Employees of Commonwealth Energy System and Subsidiary Companies, as of December 31, 1998.
With regard to the annual benefit to be paid under the Pension Plan, federal law places certain limits on the amount of benefits which can be paid from qualified pension plans. Payments made by the Parent in excess of the applicable limitations are made pursuant to the terms of the Executive Salary Continuation and Excess Benefit Plan for Employees of Commonwealth Energy System and Subsidiary Companies. For 1998, the maximum annual compensation limit under the Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies was $160,000, and the maximum annual benefit under that Plan was $130,000.
The Pension Plan is a non-contributory defined benefit plan. The Plan is a final average earnings type plan under which benefits reflect the employee's years of credited service. The employee receives the higher of either a Social Security integrated or non-integrated formula to realize the maximum retirement benefit applicable to his or her employment history. Both of the formulae are based on the average of the three highest consecutive January 1 base salaries during the ten-year period preceding the employee's retirement or termination. Retirement benefits are available to employees on or after age fifty-five provided the sum of their age and years of service is at least seventy-five. Mr. Wright, Mr. Poist, Ms. McLaughlin, Mr. Rappoli and Mr. Sullivan have 31, 27, 19, 24 and 23 credited years of service respective- ly. For the purposes of calculating the annual retirement benefits of Mr. Wright, Mr. Poist, Ms. McLaughlin, Mr. Rappoli and Mr. Sullivan pursuant to the Plan, only the amounts set forth in the summary compensation table as "Salary" are utilized to determine each Executive Officer's three highest consecutive January 1 base salaries during the ten-year period preceding the Executive Officer's retirement or termination.
COMMONWEALTH ENERGY SYSTEM
OTHER EXECUTIVE OFFICER BENEFITS
Each Executive Officer of the Parent has elected certain pre-retirement death benefits and supplemental retirement benefits in exchange for waiving certain standard life insurance benefits (in excess of $50,000), and the survivor income benefits generally available to all eligible employees. The alternative program for Executive Officers provides a pre-retirement death benefit of either: (i) a lump-sum payment of three times annual base salary or (ii) fifty percent of monthly base salary for one hundred and eighty months. The supplemental retirement benefit provides that an Executive Officer may retire after the attainment of age fifty-five and completion of ten years of service. Normal retirement at age sixty-five provides an annual payment equal to thirty-five percent of final base salary per year for life or for a period of one hundred and eighty months, whichever is longer. Benefits are reduced for retirement prior to age sixty-five. The supplemental retire- ment benefits are in addition to the amounts shown in the table above and are not subject to limitation. If termination of employment occurs following a change in control of the Parent after the Executive Officer's completion of ten years of service with the Parent but before the attainment of age fifty-five, the Executive Officer shall be entitled to receive upon attainment of age fifty-five a retirement benefit equal to the amounts that would have been payable had the Executive Officer remained in the employment of the Parent until the date of the Executive Officer's fifty-fifth birthday and retired on that date. Should the employment of the Executive Officer termi- nate for any other reason (other than death) and before completion of ten years of service and attainment of age fifty-five, there are no benefits payable under this alternative program for Executive Officers.
The Parent has entered into Severance Agreements with its Executive Officers, including Mr. Wright, Ms. McLaughlin, Mr. Rappoli and Mr. Sullivan. The Severance Agreements provide that in the event of termination of employ- ment following a change of control of the Parent, as defined in the Severance Agreements, the Parent shall pay to the Executive Office a lump sum severance benefit payable to Mr. Wright, Ms. McLaughlin, Mr. Rappoli and Mr. Sullivan is up to three times their salary and annual incentive compensation. No benefit would be paid if the effect of any payment would be to provide benefits above those normally payable beyond age sixty-five.
COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Executive Compensation Committee of the Board of Trustees (the "Committee") is composed of three independent, non-employee Trustees. The Committee reviews and approves compensation levels for the Parent's Chief Executive Officer and oversees the Parent's executive compensation programs affecting all Executive Officers. These programs have been designed in order to attract, retain, motivate and reward those individuals who are most responsible for the Parent's growth and profitability. The programs reflect the Committee's objectives of tying a substantial portion of each Executive Officer's compensation to both the Parent's and the individual's success in meeting designated goals and objectives and in realizing increases in total shareholder return.
Compensation for Executive Officers consists of base salary, annual cash incentive compensation and long-term incentive awards in the form of restrict- ed stock awards of Common Shares. Executive Officers also participate in the Pension Plan and the Employee Savings Plan and receive benefits under medical and other benefit plans which are available to employees generally.
COMMONWEALTH ENERGY SYSTEM Base Salary
In setting the base salaries for the Chief Executive Officer and all other Executive Officers, the Committee evaluates the general responsibilities of the particular position and the individual's experience in that position and also applies the data and criteria described in the next paragraph. The Chief Executive Officer's base salary target is designed generally to match the market median for the utility reference group described in the next paragraph. The Committee adjusts the Chief Executive Officer's salary in relation to the salary range target through the evaluation of the same objective criteria used to determine the Chief Executive Officer's annual incentive award set forth below. Less emphasis is placed on base salary adjustments than on incentive compensation, consistent with the Committee's objectives of placing increasingly greater emphasis on performance based, at-risk incentive compensation.
In setting the Chief Executive Officer's base salary for 1998, the Committee surveyed and reviewed compensation levels and the reference criteria relating to such compensation levels within the gas and electric utility industry. Compensation data and comparisons were provided to the Committee by independent sources and were used by the Committee together with market compensation data provided by the Parent's human resources department, compensation reports contained in proxy materials for companies considered by the Committee to be similar to the Parent in size, responsibility and complex- ity and utility industry references such as those provided by the Edison Electric Institute. Among the reference criteria reviewed by the Committee in developing external market pay norms were business type (investor-owned utilities), scope (utilities with revenues of approximately $500 million to $2 billion) and location (utilities headquartered in the northeast region of the U.S.). This market reference group of companies represents a subset of Value Line, Inc.'s utility sample.
Annual Incentive Compensation
The Chief Executive Officer is eligible to receive annual cash bonus compensation under the Parent's Annual Incentive Plan. In 1998, the Annual Incentive Plan provided for awards to the Chief Executive Officer of up to a maximum of 47% of annual base salary. Both individual and Parent performance goals and objectives were set. The Chief Executive Officer's award for 1998 was determined on a weighted basis, with two-thirds of the award potential attributable to the attainment of Parent goals and objectives and one-third of the award potential attributable to individual goals and objectives. For 1998, the Parent criteria forming the goals and objectives applicable to the Annual Incentive Plan were: 1) meeting pre-established targets comparing Parent actual net income to budgeted net income for 1998; 2) success in implementing budgetary constraints in the interest of controlling costs; and 3) meeting certain pre-established benchmark measures of operation and maintenance expenses per customer, as compared to a peer group of 18 utility companies recommended by the Parent's independent compensation consultant. Each of the three Parent goals and objectives are equally weighted, and awards are made based on meeting, exceeding or reaching maximum attainment of targets.
The goal established for actual net income was to meet or exceed the approved budgeted amounts. The Parent's 1998 net income exceeded targeted net income by 7.5%. The goal established for cost control was for operation and maintenance expenses in 1998 to be below the approved budgeted amounts. This goal was met, as the Parent reduced actual operation and maintenance expenses to 3.8% below established budgets. The goal of maintaining operation and maintenance expenses per customer within the top 50% of the 18 company industry peer group was also exceeded, as the Parent was rated the fourth most effective of the 18 companies in controlling operation and maintenance
COMMONWEALTH ENERGY SYSTEM
expenses. In the aggregate, the goals and objectives applicable to the Parent component of the Annual Incentive Plan were rated as 92% achieved.
The individual goals of Mr. Wright for 1998 under the Annual Incentive Plan included: timely completion of COM/Electric's Restructuring Plan before the Massachusetts Department of Telecommunications and Energy; the sale of COM/Electric's generation assets to Southern Energy; the development of procedures to ensure compliance by the Parent with state and federal affiliate transaction and Standards of Conduct laws and regulations; and the completion of various investor relations programs as recommended by the Parent's investor relations consultant. Performance relative to achieving individual goals was rated as 90% achieved, resulting in an aggregate performance rating of 90% achievement. In addition, Mr. Poist was given a discretionary award of $40,000 under the Annual Incentive Plan.
Long-Term Compensation
The Long-Term Incentive Plan, approved by shareholders in 1994, measures performance and provides for the potential for awards of Common Shares over a three-year Plan Period. The Plan provides for awards to the Chief Executive Officer of up to a maximum of 50% of annual base salary, awarded in the form of restricted Common Shares. Awards of Common Shares under the Plan are made if the Parent's average three-year total return (share appreciation and dividends), as compared to the peer group index of utility companies as established by Value Line, Inc., meets or exceeds the achievement standards set by the Committee at the beginning of a Plan Period. In this way, the interests of Executive Officers and Shareholders continue to be aligned.
For the three-year Plan Period commencing in 1996, the Threshold, Plan Target and Maximum Shareholder Return achievement standards were 95% of Index Average, Index Average, and 120% of Index Average, respectively. During this Plan Period, the Parent's average total return was equal to 150% of the peer group index, resulting in a maximum award in March of 1999 to Mr. Wright equal to 50% of his January 1, 1998 base salary ($120,000) in restricted Common Share. Under the terms of the Long Term Incentive Plan, the restricted Common Shares generally vest three years from the date they are issued.
Other Executive Officers
The Chief Executive Officer, in conjunction with the Parent's human resources department and an independent consultant, established salary ranges for each Executive Officer. The salary ranges were based in part upon salaries provided to executive officers in the Parent's industry peer group, as reported by the Edison Electric Institute and from regional salary surveys, so as to establish salary ranges generally in the median of the peer group. Specific salary levels were then established through an evaluation of the responsibilities of the position, the individual's experience in that position and the Executive Officer's achievement of goals and performance of duties. The base salary levels, as recommended by the Chief Executive Officer, were also reviewed and approved by the Executive Compensation Committee.
In addition to base salary, the named Executive Officers are also eligible to receive compensation under the Annual Incentive Plan and the Long Term Incentive Plan. The named Executive Officers are eligible to receive compensation of up to a maximum of 42% (for Vice Presidents) to 47% (for the Operating Companies' President) of annual base salary under the Annual Incentive Plan and of up to 40% (for Vice Presidents) to 50% (for the Operat- ing Companies' President) of annual base salary in restricted Common Shares under the Long Term Incentive Plan. In 1998, the Parent goals and objectives constituting the annual performance criteria and the corresponding weightings which determined eligibility for awards to the named Executive Officers under
COMMONWEALTH ENERGY SYSTEM
the Annual Incentive Plan were the same as those applicable to the Chief Executive Officer. The individual goals and objectives of the other Executive Officer Annual Incentive Plan participants included: completion of the purchase of the MATEP facility; Year 2000 compliance for the Parent's Share- holder Record Systems; continuing and expanding the Parent's Investor Rela- tions Program; completing the sale of COM/Electric's generating assets to Southern Energy; and timely completion of COM/Electric's Restructuring Plan before the Massachusetts Department of Telecommunications and Energy on or before March 1, 1998.
The performance criteria applicable to the named Executive Officers under the Long Term Incentive Plan are the same as those applicable to the Chief Executive Officer.
Policy on Deductibility of Compensation
Pursuant to Section 162(m) of the Internal Revenue Code, the ability of the Parent to deduct the compensation paid to any of the five most highly paid officers in excess of $1 million is limited by Federal Law. The compensation of each of the Parent's Executive Officers, however, is lower than the $1 million threshold at which tax deductions are limited. It is therefore not necessary that the Committee formulate a policy with respect to qualifying compensation for deductibility under the Internal Revenue Code.
Conclusion
The Committee continues to take action to link executive compensation directly to corporate performance and shareholder total return. A substantial portion of each Executive Officer's compensation is now dependent upon measurable individual performance and Parent Common Share appreciation.
THE EXECUTIVE COMPENSATION COMMITTEE Michael C. Ruettgers, Chairperson William J. O'Brien Gerald L. Wilson
COMPARATIVE TOTAL SHAREHOLDER RETURN
The line graph below compares the cumulative total shareholder return for the Parent's Common Shares to the cumulative total return of the S&P 500 Stock Index and a Peer Group Index which is comprised of 83 utility companies (including the Parent) which are followed by Value Line, Inc. The entities which comprise the Peer Group are also set forth hereinafter.
COMMONWEALTH ENERGY SYSTEM
Comparative Five-Year Total Returns Commonwealth Energy System, S&P 500 and Value Line Peer Group (Performance results through 12/31/98)
---------------------------------------------------------------
Line graph illustration of
comparative five-year (1994-1998) cumulative
total returns based on values listed
in chart below.
---------------------------------------------------------------
1993 1994 1995 1996 1997 1998
COM/Energy $100 $ 85 $112 $126 $190 $242 S&P 500 100 102 140 172 230 295 Peer Group 100 90 116 124 168 198
Assumes $100 invested at the close of trading on the last trading day of 1993 in COM/Energy Common Shares, S&P 500 and the Peer Group. Also assumes reinvestment of dividends.
Source: Value Line, Inc.
PEER GROUP
Allegheny Power System, Inc. MidAmerican Energy Holdings Co. Ameren Corp. Minnesota Power, Inc. American Electric Power Co., Inc. Montana Power Co. Baltimore Gas and Electric Co. Nevada Power Co. BEC Energy New Century Energies, Inc. Black Hills Corp. New England Electric System Carolina Power & Light Co. Niagara Mohawk Power Corp. Central & South West Corp. NIPSCO Industries, Inc. Central Hudson Gas & Electric Corp. Northeast Utilities Central Vermont Public Service Corp. Northern States Power Co. CILCORP Northwestern Corp. CINergy Corp. OGE Energy, Inc. CLECO Corp. Orange & Rockland Utilities CMS Energy Corp. Otter Tail Power Co. Commonwealth Energy System PacifiCorp. Conectiv, Inc. PECO Energy Co. Consolidated Edison, Inc. PG&E Corp. Dominion Resources, Inc. Pinnacle West Capital DPL, Inc. Potomac Electric Power Co. DQE PP&L Resources, Inc. DTE Energy Co. Public Service Co. of New Mexico Duke Power Corp. Public Service Enterprise Group Inc. Eastern Utilities Associates Puget Sound Energy Inc. Edison International Rochester Gas and Electric Corp. Empire District Electric Co. SCANA Corp. Energy East Corp. Sierra Pacific Resources Entergy Corp. SIGCORP, Inc.
COMMONWEALTH ENERGY SYSTEM
FirstEnergy Corp. Southern Co. Florida Progress Corp. St. Joseph Light & Power Co. FPL Group, Inc. TECO Energy, Inc. GPU, Inc. Texas Utilities Company Green Mountain Power Corp. TNP Enterprises, Inc. Hawaiian Electric Industries, Inc. Unicom Corp. Houston Industries, Inc. Unisource Energy Corp. IDACORP, Inc. United Illuminating Co. Illinova Corp. UtiliCorp United Inc. Interstate Energy Corp. Washington Water Power Co. IPALCO Enterprises, Inc. Western Resources, Inc. Kansas City Power & Light Wisconsin Energy Corp. LG&E Energy Corp. WPS Resources Corp. MDU Resources Group Inc.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires Trustees, Executive Officers and persons who beneficially own more than ten percent (10%) of the Parent's Common Shares to file initial reports of ownership on Form 3 and reports of changes in ownership on Form 4 and/or Form 5 with the Securities and Exchange Commission (the Commission) and any national securities exchange on which the Parent's securities are registered. Trustees, Executive Officers and greater than ten percent (10%) beneficial owners are required by the Commission's regulations to furnish the Parent with copies of all Section 16(a) forms they file.
Based on a review of the copies of such forms furnished to the Parent and written representations from the Trustees and Executive Officers, the Parent believes that all Section 16(a) filing requirements applicable to its Trust- ees, Executive Officers and greater than ten percent (10%) beneficial owners were complied with for 1998.
The following table shows the beneficial ownership, reported to the Parent as of March 1, 1999, of Common Shares of the Parent owned by the Chief Executive Officer and the four other most highly paid Executive Officers and, as a group, all Trustees and Executive Officers of the Parent.
Total Common Percent of Name Shares (1) Class
Russell D. Wright 15,561 0.1% William G. Poist 20,472 0.1% Deborah A. McLaughlin 4,744 0.1% James D. Rappoli 10,292 0.1% Michael P. Sullivan 8,739 0.1% All Trustees and Executive Officers as a group (13 persons) 82,864 0.3%
(1) Beneficial ownership includes, where applicable, shares with respect to which voting or investment power is attributed to an Executive Officer or Trustee because of joint fiduciary ownership of the Shares or relationship of the Executive Officer or Trustee to the record owner, such as a spouse, together with shares held under the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies.
COMMONWEALTH ENERGY SYSTEM
Item 13.
Item 13. Certain Relationships and Related Transactions
The Parent paid legal fees in 1998 to the firm of Rich, May, Bilodeau & Flaherty, P.C., of which Mr. Hundley is Of Counsel. The firm has been employed in the last fiscal year and the current fiscal year.
PART IV.
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. Index to Financial Statements
Consolidated financial statements and notes thereto of Commonwealth Energy System and Subsidiary Companies, together with the Report of Independent Public Accountants, are filed under Item 8 of this Form 10-K and listed on the Index to Financial Statements and Schedules (page 38).
(a) 2. Index to Financial Statement Schedules
Commonwealth Energy System and Subsidiary Companies
Filed herewith at page(s) indicated -
Report of Independent Public Accountants on Schedules (page 75).
Schedule I - Investments in, Equity in Earnings of, and Dividends Re- ceived from Related Parties - Years Ended December 31, 1998, 1997 and 1996 (pages 89-91).
Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1998, 1997 and 1996 (page 92).
All other schedules have been omitted because they are not applicable, not required or because the required information is included in the financial statements or notes thereto.
Subsidiaries not Consolidated and Fifty-Percent or Less Owned Persons
Financial statements of 50% or less owned persons accounted for by the equity method have been omitted because they do not, considered individ- ually or in the aggregate, constitute a significant subsidiary.
Form 11-K, Annual Reports of Employee Stock Purchases, Savings and Similar Plans
Pursuant to Rule 15(d)-21 of the Securities and Exchange Act of 1934, the information, financial statements and exhibits required by Form 11-K with respect to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies will be filed as an amendment to this report under cover of Form 10-K/A no later than April 30, 1999.
COMMONWEALTH ENERGY SYSTEM
(a) 3. Exhibits: Notes to Exhibits -
a. Unless otherwise designated, the exhibits listed below are incorporated by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses.
b. During 1981, New Bedford Gas and Edison Light Company sold its gas business and properties to Commonwealth Gas Company and changed its corporate name to Commonwealth Electric Company.
c. The following is a glossary of Commonwealth Energy System and subsid- iary companies' acronyms that are used throughout the following Exhibit Index:
CES ...................... Commonwealth Energy System CE ....................... Commonwealth Electric Company CEL ...................... Cambridge Electric Light Company CEC ...................... Canal Electric Company CG ....................... Commonwealth Gas Company NBGEL .................... New Bedford Gas and Edison Light Company HOPCO .................... Hopkinton LNG Corp.
Exhibit Index
Exhibit 3. Declaration of Trust
Commonwealth Energy System (Registrant)
3.1.1 Declaration of Trust of CES dated December 31, 1926, as amended by vote of the shareholders and trustees May 7, 1998 (Exhibit 1 to the CES Form 10-Q (September 1998), File No. 1-7316).
Exhibit 4. Instruments defining the rights of security holders, including indentures
Commonwealth Energy System (Registrant)
Debt Securities -
4.1.1 CES Note Agreement ($40 Million Privately Placed Senior Notes) dated June 28, 1989 (Exhibit 1 to the CES Form 10-Q (September 1989), File No. 1-7316).
Cambridge Electric Light Company
Indenture of Trust or Supplemental Indenture of Trust -
4.2.1 Original Indenture on Form S-1 (April, 1949) (Exhibit 7(a), File No. 2-7909).
4.2.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2- 7909).
COMMONWEALTH ENERGY SYSTEM
4.2.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2- 7909).
4.2.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No. 2- 7909).
Subsidiary Companies of the Registrant
4.2.5 Seventh Supplemental on Form 10-Q (June 1992), (Exhibit 1, File No 2-7909).
Canal Electric Company
Indenture of Trust and First Mortgage or Supplemental Indenture of Trust and First Mortgage -
4.3.1 Indenture of Trust and First Mortgage with State Street Bank and Trust Company, Trustee, dated October 1, 1968 (Exhibit 4(b) to Form S-1, File No. 2-30057).
4.3.2 First and General Mortgage Indenture with Citibank, N.A., Trustee, dated September 1, 1976 (Exhibit 4(b)2 to Form S-1, File No. 2- 56915).
4.3.3 First Supplemental dated October 1, 1968 with State Street Bank and Trust Company, Trustee, dated September 1, 1976 (Exhibit 4(b)3 to Form S-1, File No. 2-56915).
4.3.4 Third Supplemental dated September 1, 1976 with Citibank, N.A., New York, NY, Trustee, dated December 1, 1990 (Exhibit 3 to 1990 Form 10-K, File No. 2-30057).
4.3.5 Fourth Supplemental dated September 1, 1976 with Citibank, N.A., New York, NY, Trustee, dated December 1, 1990 (Exhibit 4 to 1990 Form 10-K, File No. 2-30057).
Commonwealth Gas Company
Indenture of Trust or Supplemental Indenture of Trust -
4.4.1 Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No. 2-7820).
4.4.2 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No. 2- 1647).
4.4.3 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No. 2-1647).
4.4.4 Eighteenth Supplemental on Form 10-Q (March 1994) (Exhibit 1, File No. 2-1647).
4.4.5 Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No. 2- 1647).
COMMONWEALTH ENERGY SYSTEM
Exhibit 10. Material Contracts
10.1 Power contracts.
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No. 2-30057).
10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and CEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 1 to the 1991 CEL Form 10-K, File No. 2-7909).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the CEL Form 10-Q (June 1988), File No. 2-7909).
10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (Septem- ber 1989), File No. 2-7909).
10.1.3 Power Contract between YAEC and NBGEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to the 1991 CE Form 10-K, File No. 2-7749).
10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE Form 10-Q (June 1988), File No. 2-7749).
10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989), File No. 2-7749).
10.1.4 Power Contract between Connecticut Yankee Atomic Power Company (CYAPC) and CEL dated July 1, 1964 (Exhibit 13-K1 to the Parent's Form S-1, (April 1967) File No. 2-25597).
10.1.4.1 Additional Power Contract providing for extension on contract term between CYAPC and CEL dated April 30, 1984 (Exhibit 5 to the CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.4.2 Second Supplementary Power Contract providing for decommissioning financing between CYAPC and CEL dated April 30, 1984 (Exhibit 6 to the CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.5 Power contract between Vermont Yankee Nuclear Power Corporation (VYNPC) and CEL dated February 1, 1968 (Exhibit 3 to the CEL 1984 Form 10-K, File No. 2-7909).
10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and Second Amendment dated April 15, 1983 (decommissioning financing) to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1984), File No. 2- 7909).
COMMONWEALTH ENERGY SYSTEM
10.1.5.2 Third Amendment dated April 1, 1985 and Fourth Amendment dated June 1, 1985 to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1986), File No. 2-7909).
10.1.5.3 Fifth and Sixth Amendments to 10.1.5 dated February 1, 1968, both as amended May 6, 1988 (Exhibit 1 to the CEL Form 10-Q (June 1988), File No. 2-7909).
10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as amended June 15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No. 2-7909).
10.1.5.5 Additional Power Contract dated February 1, 1984 between CEL and VYNPC providing for decommissioning financing and contract extension (Refiled as Exhibit 1 to CEL 1993 Form 10-K, File No. 2-7909).
10.1.6 Power contract between Maine Yankee Atomic Power Company (MYAPC) and CEL dated May 20, 1968 (Exhibit 5 to the Parent's Form S-7, File No. 2-38372).
10.1.6.1 First Amendment dated March 1, 1984 (decommissioning financing) and Second Amendment dated January 1, 1984 (supplementary payments) to 10.1.6 (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit 1 to the CEL Form 10-Q (September 1984), File No. 2-7909).
10.1.7 Agreement between NBGEL and Boston Edison Company (BECO) for the purchase of electricity from BECO's Pilgrim Unit No. 1 dated Au- gust 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.7.1 Service Agreement between NBGEL and BECO for purchase of stand-by power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.7.2 System Power Sales Agreement by and between CE and BECO dated July 12, 1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No. 2-7749).
10.1.7.3 Power Exchange Agreement by and between BECO and CE dated December 1, 1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.7.4 Service Agreement for Non-Firm Transmission Service between BECO and CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File No. 2-7909).
10.1.8 Agreement for Joint-Ownership, Construction and Operation of New Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to the NBGEL Form S-1 dated October 1973, File No. 2-49013 and as amended below:
10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974 and January 31, 1975, respectively (Exhibit 13(m) to the NBGEL Form S-1 (November 7, 1975), File No. 2-54995).
10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979 and December 15, 1979, respectively (Refiled as Exhibit 1 to the CEC 1989 Form 10-K, File No. 2-30057).
COMMONWEALTH ENERGY SYSTEM
10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as amended May 16, 1980, December 31, 1980 and June 1, 1982, respectively (Filed as Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749).
10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended April 27, 1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10- Q (June 1984), File No. 2-30057).
10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985 (Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2-30057).
10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986 (Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2-30057).
10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2-30057).
10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19, 1986 (Exhib- it 1 to the CEC 1986 Form 10-K, File No. 2-30057).
10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12, 1987 (Exhibit 1 to the CEC 1987 Form 10-K, File No. 2-30057).
10.1.8.10 Settlement Agreement and Twenty-Second Amendment to 10.1.8, both dated January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File No. 2-30057).
10.1.9 Purchase and Sale Agreement together with an implementing Addendum dated December 31, 1981, between CE and CEC, for the purchase and sale of the CE 3.52% joint-ownership interest in the Seabrook units, dated January 2, 1981 (Refiled as Exhibit 4 to the CE 1992 Form 10-K, File No. 2-7749).
10.1.10 Agreement to transfer ownership, construction and operational interest in the Seabrook Units 1 and 2 from CE to CEC dated January 2, 1981 (Refiled as Exhibit 3 to the 1991 CE Form 10-K, File No. 2- 7749).
10.1.11 Power Contract, as amended to February 28, 1990, superseding the Power Contract dated September 1, 1986 and amendment dated June 1, 1988, between CEC (seller) and CE and CEL (purchasers) for seller's entire share of the Net Unit Capability of Seabrook 1 and related energy (Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2- 30057).
10.1.12 Agreement between NBGEL and Central Maine Power Company (CMP), for the joint-ownership, construction and operation of William F. Wyman Unit No. 4 dated November 1, 1974 together with Amendment No. 1 dated June 30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No. 2-54955).
COMMONWEALTH ENERGY SYSTEM
10.1.12.1 Amendments No. 2 and 3 to 10.1.12 as amended August 16, 1976 and December 31, 1978 (Exhibit 5(a) 14 to the Parent's Form S-16 (June 1979), File No. 2-64731).
10.1.13 Agreement between the registrant and Montaup Electric Company (MEC) for use of common facilities at Canal Units I and II and for allocation of related costs, executed October 14, 1975 (Exhibit 1 to the CEC 1985 Form 10-K, File No. 2-30057).
10.1.13.1 Agreement between the registrant and MEC for joint-ownership of Canal Unit II, executed October 14, 1975 (Exhibit 2 to the CEC 1985 Form 10-K, File No. 2-30057).
10.1.13.2 Agreement between the registrant and MEC for lease relating to Canal Unit II, executed October 14, 1975 (Exhibit 3 to the CEC 1985 Form 10-K, File No. 2-30057).
10.1.14 Contract between CEC and NBGEL and CEL, affiliated companies, for the sale of specified amounts of electricity from Canal Unit 2 dated January 12, 1976 (Exhibit 7 to the Parent's 1985 Form 10-K, File No. 1-7316).
10.1.15 Capacity Acquisition Agreement between CEC,CEL and CE dated Septem- ber 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File No. 2-30057).
10.1.15.1 Amendment to 10.1.15 as amended and restated June 1, 1993, hence- forth referred to as the Capacity Acquisition and Disposition Agreement, whereby Canal Electric Company, as agent, in addition to acquiring power may also sell bulk electric power which Cambridge Electric Light Company and/or Commonwealth Electric Company owns or otherwise has the right to sell (Exhibit 1 to Canal Electric's Form 10-Q (September 1993), File No. 2-30057).
10.1.16 Phase 1 Vermont Transmission Line Support Agreement and Amendment No. 1 thereto between Vermont Electric Transmission Company, Inc. and certain other New England utilities, dated December 1, 1981 and June 1, 1982, respectively (Exhibits 5 and 6 to the CE 1992 Form 10-K, File No. 2-7749).
10.1.16.1 Amendment No. 2 to 10.1.16 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.16.2 Amendment No. 3 to 10.1.16 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749).
10.1.17 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for the purchase of available hydro-electric energy produced by a facility located in Ware, Massachusetts, dated September 1, 1983 (Refiled as Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
COMMONWEALTH ENERGY SYSTEM
10.1.18 Power Purchase Agreement between Corporation Investments, Inc. (CI), and CE for the purchase of available hydro-electric energy produced by a facility located in Lowell, Massachusetts, dated January 10, 1983 (Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.18.1 Amendment to 10.1.18 between CI and Boott Hydropower, Inc., an assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.19 Phase 1 Terminal Facility Support Agreement dated December 1, 1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November 1, 1982, between New England Electric Transmission Corpo- ration (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.19.1 Amendment No. 3 to 10.1.19 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749).
10.1.20 Preliminary Quebec Interconnection Support Agreement dated May 1, 1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amend- ment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.21 Agreement with Respect to Use of Quebec Interconnection dated December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated November 1, 1982 among certain NEPOOL utilities (Exhib- it 3 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.21.1 Amendatory Agreement No. 3 to 10.1.21 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.22 Phase I New Hampshire Transmission Line Support Agreement between NEET and certain other New England Utilities dated December 1, 1981 (Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.23 Agreement, dated September 1, 1985, with Respect To Amendment of Agreement With Respect To Use Of Quebec Interconnection, dated December 1, 1981, among certain NEPOOL utilities to include Phase II facilities in the definition of "Project" (Exhibit 1 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.24 Agreement to Preliminary Quebec Interconnection Support Agreement - Phase II among Public Service Company of New Hampshire (PSNH), New England Power Co. (NEP), BECO and CEC whereby PSNH assigns a portion of its interests under the original Agreement to the other three parties, dated October 1, 1987 (Exhibit 2 to the CEC 1987 Form 10-K, File No. 2-30057).
COMMONWEALTH ENERGY SYSTEM
10.1.25 Preliminary Quebec Interconnection Support Agreement - Phase II among certain New England electric utilities dated June 1, 1984 (Exhibit 6 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.25.1 First, Second and Third Amendments to 10.1.25 as amended March 1, 1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.25.2 Fifth, Sixth and Seventh Amendments to 10.1.25 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhib- it 1 to the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.25.3 Fourth and Eighth Amendments to 10.1.25 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057).
10.1.25.4 Ninth and Tenth Amendments to 10.1.25 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057).
10.1.25.5 Eleventh Amendment to 10.1.25 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.25.6 Twelfth Amendment to 10.1.25 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.26 Phase II Equity Funding Agreement for New England Hydro-Transmis- sion Electric Company, Inc. (New England Hydro) (Massachusetts), dated June 1, 1985, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.27 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro and certain NEPOOL utili- ties (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2- 30057).
10.1.28 Phase II New Hampshire Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 8 dated May 1, 1986 through January 1, 1990, respectively, between New England Hydro-Transmission Corporation (New Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.29 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June 1, 1985, between New Hampshire Hydro and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.29.1 Amendment No. 1 to 10.1.29 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057).
COMMONWEALTH ENERGY SYSTEM
10.1.29.2 Amendment No. 2 to 10.1.29 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.30 Phase II New England Power AC Facilities Support Agreement, dated June 1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.30.1 Amendments Nos. 1 and 2 to 10.1.30 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.30.2 Amendments Nos. 3 and 4 to 10.1.30 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.31 Agreement Authorizing Execution of Phase II Firm Energy Contract, dated September 1, 1985, among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro-Quebec (Exhib- it 8 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.32 Agreements by and between Swift River Company and CE for the purchase of available hydro-electric energy to be produced by units located in Chicopee and North Willbraham, Massachusetts, both dated September 1, 1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.33 Power Purchase Agreement by and between SEMASS Partnership, as seller, to construct, operate and own a solid waste disposal facility at its site in Rochester, Massachusetts and CE, as buyer of electric energy and capacity, dated September 8, 1981 (Exhibit 17 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.33.1 Power Sales Agreement to 10.1.33 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749).
10.1.33.2 Amendment to 10.1.33 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated March 14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2-7749).
10.1.33.3 Amendment to 10.1.33 for all additional electric capacity and related energy to be produced by an addition to the Original Unit, dated May 24, 1991 (Exhibit 1 to CE Form 10-Q (June 1991), File No. 2-7749).
10.1.34 Power Sale Agreement by and between CE (buyer) and Northeast Energy Associated, Ltd. (NEA) (seller) of electric energy and capacity, dated November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March 1987), File No. 2-7749).
10.1.34.1 First Amendment to 10.1.34 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749).
COMMONWEALTH ENERGY SYSTEM
10.1.34.2 Second Amendment to 10.1.34 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.34.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for the purchase of 21 MW of electricity (Exhibit 2 to the CE Form 10-Q (September 1988), File No. 2-7749).
10.1.34.4 Amendment to 10.1.34.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.35 Power Purchase Agreement and First Amendment, dated September 5, 1989 and August 3, 1990, respectively, by and between Commonwealth Electric (buyer) and Dartmouth Power Associates Limited Partnership (seller), whereby buyer will purchase all of the energy (67.6 MW) produced by a single gas turbine unit (Exhibit 1 to the CE Form 10- Q (June 1992), File No. 2-7749).
10.1.35.1 Second Amendment, dated June 23, 1994, to 10.1.50 by and between Commonwealth Electric Company and Dartmouth Power Associates, L.P. dated September 5, 1989 (Exhibit 4 to the CE Form 10-Q (June 1995), File No. 2-7749).
10.1.36 Power Purchase Agreement by and between Masspower (seller) and Com- monwealth Electric Company (buyer) for a 11.11% entitlement to the electric capacity and related energy of a 240 MW gas-fired cogen- eration facility, dated February 14, 1992 (Exhibit 1 to Common- wealth Electric's Form 10-Q (September 1993), File No. 2-7749).
10.1.37 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller) and Commonwealth Electric Company (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 2 to Commonwealth Electric's Form 10-Q (September 1993), File No. 2- 7749).
10.1.37.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., Cambridge Electric Light Company, Commonwealth Electric Company and New England Power Company, dated July 2, 1993 (Exhibit 3 to Common- wealth Electric's Form 10-Q (September 1993), File No 2-7749).
10.1.37.2 Power Sale Agreement by and between Altresco Pittsfield, L. P. (seller) and Cambridge Electric Light Company (Cambridge Electric) (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogeneration facility, dated February 20, 1992 (Exhibit 1 to Cambridge Electric's Form 10-Q (September 1993), File No. 2-7909).
10.1.37.3 First Amendment, dated November 7, 1994, to 10.1.37 by and between Commonwealth Electric Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed as Exhibit 3 to Commonwealth Electric Company's Form 10-Q (June 1995), File 2-7749).
COMMONWEALTH ENERGY SYSTEM
10.1.37.4 First Amendment, dated November 7, 1994, to 10.1.37.2 by and between Cambridge Electric Light Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed as Exhibit 2 to Cambridge Electric Light Company's Form 10-Q (June 1995), File 2-7909).
10.2 Natural gas purchase contracts.
10.2.1 Transportation Agreement between CNG and CG to provide for trans- portation of natural gas on a daily basis from Steuben Gas Storage Company to TGP (Exhibit 10 to the CG 1991 Form 10-K, File No. 2- 1647).
10.3 Other agreements.
10.3.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 1 to CES Form 10-Q (September 1993), File No. 1-7316).
10.3.2 Employees Savings Plan of Commonwealth Energy System and Subsid- iary Companies as amended and restated January 1, 1993.(Exhibit 2 to CES Form 10-Q (September 1993), File No. 1-7316).
10.3.2.1 First Amendment to 10.3.2, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), File No. 1-7316).
10.3.2.2 Second Amendment to 10.3.2, effective April 1, 1996 (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.3.2.3 Third Amendment to 10.3.2, effective January 1, 1997 (Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
10.3.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corpora- tion, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731).
10.3.3.1 Thirteenth Amendment to 10.3.3 as amended September 1, 1981 (Re- filed as Exhibit 3 to the Parent's 1991 Form 10-K, File No. 1-7316).
10.3.3.2 Fourteenth through Twentieth Amendments to 10.3.3 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316).
10.3.3.3 Twenty-first Amendment to 10.3.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316).
10.3.3.4 Twenty-second Amendment to 10.3.3 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316).
COMMONWEALTH ENERGY SYSTEM
10.3.3.5 Twenty-third Amendment to 10.3.3 as amended to April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316).
10.3.3.6 Twenty-fourth Amendment to 10.3.3 as amended March 1, 1988 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316).
10.3.3.7 Twenty-fifth Amendment to 10.3.3. as amended to May 1, 1988 (Exhib- it 1 to the CES Form 10-Q (March 1988), File No. 1-7316).
10.3.3.8 Twenty-sixth Agreement to 10.3.3 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316).
10.3.3.9 Twenty-seventh Agreement to 10.3.3 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316).
10.3.3.10 Twenty-eighth Agreement to 10.3.3 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316).
10.3.3.11 Twenty-ninth Agreement to 10.3.3 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316).
10.3.4 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as initial lender) covering the unconditional guarantee of a portion of the payment obligations of Maine Yankee Atomic Power Company under a loan agreement and note initially between Maine Yankee and MYA Fuel Company (Exhibit 3 to the CEL Form 10-K for 1985, File No. 2-7909).
Exhibit 21. Subsidiaries of the Registrant
Incorporated by reference to Exhibit 1 to the Parent's 1997 Annual Report on Form 10-K, File No. 1-7316.
Exhibit 27. Financial Data Schedule
Filed herewith as Exhibit 2 is the Financial Data Schedule for the twelve months ended December 31, 1998.
(b) Reports on Form 8-K
One report on Form 8-K was filed during the three months ended December 31, 1998. The report was filed on December 10, 1998 for an event first reported on December 7, 1998 regarding the planned merger between the Parent and BEC Energy.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Trustees of Commonwealth Energy System:
We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements of Commonwealth Energy System included in this Form 10-K and have issued our report thereon dated February 18, 1999. Our audits were made for the purpose of forming an opinion on those consoli- dated financial statements taken as a whole. The schedules listed in Part IV, Item 14 of this Form 10-K are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 18, 1999.
SCHEDULE I COMMONWEALTH ENERGY SYSTEM INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1998 (Dollars in Thousands) Balance at Balance at Beginning of Year Additions Deductions End of Year Notes Number Equity Number Receive- of in Other Distribution Other of able Shares Investment Earnings (A) of Earnings (B) Shares Investment (C) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Co. 346,600 $ 48,225 $ 8,821 $ - $ 4,246 $ - 346,600 $ 52,800 $ - COM/Energy Steam Co. 25,500 3,508 1,119 - 765 - 25,500 3,862 - Canal Electric Co. 1,523,200 99,531 199,117 - 10,282 - 1,523,200 288,366 - Commonwealth Gas Co. 2,857,000 116,035 13,269 - 12,142 - 2,857,000 117,162 - Darvel Realty Trust 26 1,053 - - - - 26 1,053 - COM/Energy Freetown Rlty. 1 4,684 (553) - - - 1 4,131 2,255 COM/Energy Research Park Rlty. 1 931 9,915 - 9,000 - 1 1,846 860 COM/Energy Cambridge Rlty. 1 38 (8) - - - 1 30 - COM/Energy Acushnet Rlty. 1 701 119 - - - 1 820 - COM/Energy Services Co. 3,250 284 42 - - - 3,250 326 - Commonwealth Electric Co. 2,043,972 180,204 15,109 - 10,118 - 2,043,972 185,195 - Hopkinton LNG Corp. 5,000 3,882 546 - 275 - 5,000 4,153 165 Advanced Energy Systems, Inc. 100 1,017 837 40,280 - - 100 42,134 - COM/Energy Resources, Inc. 100 41 8 - - - 100 49 - COM/Energy Marketing, Inc. 100 442 (1,385) - - - 100 (943) 3,440 COM/Energy Technologies, Inc. 100 2,384 (3,062) 4,200 - - 100 3,522 2,290 $462,960 243,894 44,480 $46,828 $ - $704,506 $ 9,010 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $10,368 $ 1,650 - $ 1,626 $ - 52,454 $ 10,392 Hydro-Quebec Phase II 127,034 3,075 454 - 468 261 116,722 2,800 Other Investments - 324 - 515 - - - 839 $ 13,767 $ 1,278 296 $ 971 $261 $ 14,031 NOTES: (A) Additional investment. (B) In 1998, New England Hydro-Transmission Company, Inc. repurchased 8.1% (10,249.2 shares) of its outstanding shares. Canal Electric Company received proceeds of $145,028 ($14.15 per share) and has included this amount with dividends. Also in 1998, New England Hydro-Transmission Corporation repurchased 10.1% (63.2 shares) of its outstanding shares. Canal Electric Company received proceeds of $115,910 (1,833.92 per share) and has included this amount with dividends. (C) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. /TABLE
SCHEDULE I COMMONWEALTH ENERGY SYSTEM INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1997 (Dollars in Thousands) Balance at Balance at Beginning of Year Additions Deductions End of Year Notes Number Equity Number Receive- of in Other Distribution Other of able Shares Investment Earnings (A) of Earnings (B) Shares Investment (C) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Co. 346,600 $ 45,851 $ 5,216 $ - $ 2,842 $ - 346,600 $ 48,225 $ 7,500 COM/Energy Steam Co. 25,500 3,194 1,265 - 951 - 25,500 3,508 375 Canal Electric Co. 1,523,200 99,021 14,828 - 14,318 - 1,523,200 99,531 - Commonwealth Gas Co. 2,857,000 110,020 15,443 - 9,428 - 2,857,000 116,035 - Darvel Realty Trust 26 1,001 52 - - - 26 1,053 - COM/Energy Freetown Rlty. 1 5,031 (347) - - - 1 4,684 1,730 COM/Energy Research Park Rlty. 1 877 582 - 528 - 1 931 - COM/Energy Cambridge Rlty. 1 43 (5) - - - 1 38 - COM/Energy Acushnet Rlty. 1 694 62 - 55 - 1 701 - COM/Energy Services Co. 3,250 262 22 - - - 3,250 284 - Commonwealth Electric Co. 2,043,972 175,545 16,923 - 12,264 - 2,043,972 180,204 - Hopkinton LNG Corp. 5,000 3,881 549 - 548 - 5,000 3,882 650 Advanced Energy Systems, Inc. - - (904) 1,921 - - 100 1,017 - COM/Energy Resources, Inc. - - (60) 101 - - 100 41 - COM/Energy Marketing, Inc. - - (758) 1,200 - - 100 442 - COM/Energy Technologies, Inc. - - (916) 3,300 - - 100 2,384 - $445,420 $51,952 $6,522 $40,934 $ - $462,960 $ 9,795 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $10,046 $ 1,045 - $ 723 $ - 52,454 $ 10,368 Hydro-Quebec Phase II 137,329 3,321 233 - 248 231 127,034 3,075 Other Investments - 28 - 296 - - - 324 $ 13,395 $ 1,278 296 $ 971 $231 $ 13,767 NOTES: (A) Additional investment. (B) In 1997, New England Hydro-Transmission Company, Inc. repurchased 7.5% (10,249.2 shares) of its outstanding shares. Canal Electric Company received proceeds of $145,539 ($14.20 per share) and has included this amount with dividends. Also in 1997, New England Hydro-Transmission Corporation repurchased 6.85% (46.124 shares) of its outstanding shares. Canal Electric Company received proceeds of $85,207 (1,847.46 per share) and has included this amount with dividends. (C) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. /TABLE
SCHEDULE I COMMONWEALTH ENERGY SYSTEM INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1996 (Dollars in Thousands)
Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Distribution Other of Receivable Shares Investment Earnings of Earnings (B) Shares Investment (A)
SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 346,600 $ 44,179 $ 5,120 $ 3,448 $ - 346,600 $ 45,851 $ 4,665 COM/Energy Steam Company 25,500 3,539 1,583 1,928 - 25,500 3,194 2,155 Canal Electric Company 1,523,200 98,471 16,574 16,024 - 1,523,200 99,021 5,620 Commonwealth Gas Company 2,857,000 109,659 16,789 16,428 - 2,857,000 110,020 5,495 Darvel Realty Trust 26 1,055 75 129 - 26 1,001 - COM/Energy Freetown Realty 1 5,477 (446) - - 1 5,031 1,305 COM/Energy Research Park Realty 1 739 461 323 - 1 877 - COM/Energy Cambridge Realty 1 48 (5) - - 1 43 - COM/Energy Acushnet Realty 1 575 119 - - 1 694 - COM/Energy Services Company 3,250 337 (27) 48 - 3,250 262 - Commonwealth Electric Company 2,043,972 168,919 19,605 12,979 - 2,043,972 175,545 2,240 Hopkinton LNG Corp. 5,000 3,893 548 560 - 5,000 3,881 1,015 $436,891 $60,396 $51,867 $ - $445,420 $22,495
OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52,454 $ 9,814 $ 1,059 $ 827 $ - 52,454 $ 10,046 Hydro-Quebec Phase II 137,391 3,372 498 436 113 137,329 3,321 Other Investments - 28 - - - - 28 $ 13,214 $ 1,557 $ 1,263 $113 $ 13,395
NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. (B) In 1996, New England Hydro-Transmission Corporation repurchased 6.52% of their outstanding shares at $1,831.30 per share. Canal Electric Company received $112,616 for the repurchase of 61.495 shares, and has included this amount with dividends. /TABLE
SCHEDULE II
COMMONWEALTH ENERGY SYSTEM
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 at End Description of Year Operations Recoveries Written Off of Year
Year Ended December 31, 1998
Allowance for Doubtful Accounts $9,408 $6,613 $2,265 $ 9,202 $9,084
Year Ended December 31, 1997
Allowance for Doubtful Accounts $8,324 $8,638 $2,085 $ 9,639 $9,408
Year Ended December 31, 1996
Allowance for Doubtful Accounts $8,040 $7,152 $1,866 $ 8,734 $8,324
COMMONWEALTH ENERGY SYSTEM
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.
COMMONWEALTH ENERGY SYSTEM (Registrant)
By: R. D. WRIGHT Russell D. Wright, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Principal Executive Officer:
R. D. WRIGHT March 25, 1999 Russell D. Wright, President and Chief Executive Officer
Principal Financial and Accounting Officer:
JAMES D. RAPPOLI March 25, 1999 James D. Rappoli, Financial Vice President and Treasurer
A majority of the Board of Trustees:
SHELDON A. BUCKLER March 25, 1999 Sheldon A. Buckler, Chairman of the Board
March , 1999 Kevin C. Bryant, Trustee
PETER H. CRESSY March 25, 1999 Peter H. Cressy, Trustee
B. L. FRANCIS March 25, 1999 Betty L. Francis, Trustee
FRANKLIN M. HUNDLEY March 25, 1999 Franklin M. Hundley, Trustee
COMMONWEALTH ENERGY SYSTEM
FORM 10-K DECEMBER 31, 1998
SIGNATURES (Continued)
March , 1999 William J. O'Brien, Trustee
MICHAEL C. RUETTGERS March 25, 1999 Michael C. Ruettgers, Trustee
G. L. WILSON March 25, 1999 Gerald L. Wilson, Trustee
R. D. WRIGHT March 25, 1999 Russell D. Wright, Trustee
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by reference of our reports included in this Form 10-K into the System's previously filed Registration Statements on Form S-8 File No. 33-57467 and on Form S-3 File No. 33-55593. It should be noted that we have not audited any financial statements of the System subsequent to December 31, 1998 or per- formed any audit procedures subsequent to the date of our report.
ARTHUR ANDERSEN LLP
Boston, Massachusetts March 31, 1999.