10-K 1 COMMONWEALTH ENERGY SYSTEM 1994 FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 Form 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Mark One) [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1994 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ________________ to ________________ Commission file number 1-7316 COMMONWEALTH ENERGY SYSTEM (Exact name of registrant as specified in its Declaration of Trust) Massachusetts 04-1662010 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One Main Street, Cambridge, Massachusetts 02142-9150 (Address of principal executive offices) (Zip Code) (617) 225 4000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Shares of Beneficial New York Stock Exchange, Inc. Interest $4 par value Boston Stock Exchange, Inc. Pacific Stock Exchange, Inc. Securities registered pursuant to Section 12(g) of the Act: Title of Class None Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ x ] Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES [ x ] NO [ ] Aggregate market value of the voting stock held by non-affiliates of the registrant as of March 15, 1995: $427,406,076 Common Shares outstanding at March 15, 1995: 10,585,909 shares Document Incorporated by Reference Part in Form 10-K Notice of 1995 Annual Meeting, Proxy State- ment and 1994 Financial Information, dated March 31, 1995 (pages as specified herein) Parts I, II and III List of Exhibits begins on page 21 of this report. COMMONWEALTH ENERGY SYSTEM TABLE OF CONTENTS PART I PAGE Item 1. Business............................................... 3 General............................................. 3 Electric Power Supply............................... 5 Power Supply Commitments and Support Agreements..... 7 Electric Fuel Supply................................ 8 Nuclear Fuel Supply and Disposal.................... 8 Gas Supply.......................................... 9 Rates, Regulation and Legislation................... 10 Competition......................................... 13 Segment Information................................. 14 Environmental Matters............................... 14 Construction and Financing.......................... 14 Employees........................................... 14 Item 2. Properties............................................. 14 Item 3. Legal Proceedings...................................... 15 Item 4. Submission of Matters to a Vote of Security Holders.... 15 PART II Item 5. Market for the Registrant's Securities and Related Stockholder Matters.................................... 16 Item 6. Selected Financial Data................................ 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 16 Item 8. Financial Statements and Supplementary Data............ 17 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 17 PART III Item 10. Trustees and Executive Officers of the Registrant...... 18 Item 11. Executive Compensation................................. 19 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 19 Item 13. Certain Relationships and Related Transactions......... 19 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................................ 20 Signatures........................................................ 47 COMMONWEALTH ENERGY SYSTEM PART I. Item 1. Business General Commonwealth Energy System, a Massachusetts trust, is an unincorporated business organization with transferable shares. It is organized under a Declaration of Trust dated December 31, 1926, as amended, pursuant to the laws of Massachusetts. It is an exempt public utility holding company under the provisions of the Public Utility Holding Company Act of 1935, holding all of the stock of four operating public utility companies. Commonwealth Energy System, the parent company, is referred to in this report as the "System" and, together with its subsidiaries, is collectively referred to as "the system." The operating utility subsidiaries of the System are engaged in the generation, transmission and distribution of electricity and the distribution of natural gas, all within Massachusetts. These subsidiaries are: Electric Gas Cambridge Electric Light Company Commonwealth Gas Company Canal Electric Company Commonwealth Electric Company In addition to the utility companies, the System also owns all of the stock of a steam distribution company (COM/Energy Steam Company), five real estate trusts and a liquefied natural gas (LNG) and vaporization facility (Hopkinton LNG Corp.). Subsidiaries of the System have common executive and financial management and receive technical assistance as well as financial, data processing, accounting, legal and other services from a wholly-owned services company subsidiary (COM/Energy Services Company). The five real estate subsidiaries are: Darvel Realty Trust, which is a joint-owner of the Riverfront Office Park complex in Cambridge; COM/Energy Acushnet Realty, which leases land to Hopkinton LNG Corp. (Hopkinton); COM/Energy Research Park Realty, which was organized to develop a research building in Cambridge; COM/Energy Cambridge Realty, which was organized to hold various properties; and COM/Energy Freetown Realty (Freetown), which was organized in 1986 to purchase and develop 596 acres of land in Freetown, Massachusetts. As a result of unsuccessful efforts to develop an energy park on this site, the System wrote down its investment in the Freetown project and plans to sell the property. Each of the operating utility subsidiaries serves retail customers except for Canal Electric Company (Canal) which operates an electric generating station located in Sandwich, Massachusetts. The station consists of two oil-fired steam electric generating units: Canal Unit 1, with a rated capacity of 569 MW, wholly-owned by Canal; and Canal Unit 2, with a rated capacity of 580 MW, jointly-owned by Canal and Montaup Electric Company (Montaup) (an unaffiliated company). Canal Unit 2 is operated under an agreement with Montaup which provides for the equal sharing of output, fixed charges and operating expenses. In October 1993, Canal reached an agreement with Montaup and Algonquin Gas Transmission Company to build a natural gas COMMONWEALTH ENERGY SYSTEM pipeline that will serve Unit 2, subject to regulatory approvals. The project will improve air quality on Cape Cod, enable the plant to exceed the stringent 1995 air quality standards established by the Massachusetts Department of Environmental Protection and strengthen Canal's bargaining position as it seeks to secure the lowest-cost fuel for its customers. Plant conversion and pipeline construction are expected to be completed in 1996. Electric service is furnished by Cambridge Electric Light Company (Cam- bridge Electric) and Commonwealth Electric Company (Commonwealth Electric) at retail to approximately 308,000 year-round and 49,000 seasonal customers in 41 communities in eastern Massachusetts covering 1,112 square miles and having an aggregate population of 645,000. The territory served includes the communities of Cambridge, New Bedford and Plymouth and the geographic area comprising Cape Cod and Martha's Vineyard. Cambridge Electric also sells power at wholesale to the Town of Belmont, Massachusetts. Natural gas is distributed by Commonwealth Gas Company (Commonwealth Gas) to approximately 232,000 customers in 49 communities in central and eastern Massachusetts covering 1,067 square miles and having an aggregate population of 1,128,000. Twelve of these communities are also served by system companies with electricity. Some of the larger communities served by Commonwealth Gas include Cambridge, Somerville, New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of Boston. Steam, which is produced by Cambridge Electric in connection with the generation of electricity, is purchased by COM/Energy Steam and, together with its own production, is distributed to 20 customers in Cambridge and one customer (Massachusetts General Hospital) in Boston. Steam is used for space heating and other purposes. On August 17, 1993 COM/Energy Steam began providing steam service to Genzyme Corporation (Genzyme), a biotechnology company that is expected to become one of its largest customers. Genzyme's steam need for 1995 is estimated to be 83.3 million pounds, which represents approximately 5% of steam unit sales, for heating, air conditioning and testing processes. In 1996, Genzyme's annual requirement is estimated to reach approximately 175 million pounds based upon the expectation of commercial manufacturing of a biotherapeutic product in 1995. Industry in the territories served by system companies is highly diversified. The larger industrial customers include high-technology firms and manufacturers of such products as photographic equipment and supplies, rubber products, textiles, wire and other fastening devices, abrasives and grinding wheels, candy, copper and alloys, and chemicals. Among customers served are several major educational institutions, including Harvard University (Harvard) and the Massachusetts Institute of Technology (MIT). MIT has completed construction of a 19 MW natural gas-fired cogeneration facility which is expected to be in operation in 1995. MIT anticipates this cogeneration facility will meet approximately 94% of its power, heating and cooling requirements. Sales to MIT in 1994 accounted for approximately 1.8% of total unit sales. MIT and Cambridge Electric were unsuccessful in attempts to reach agreement on the cost to provide back up and supplemental service. In March 1995, Cambridge Electric filed four rate schedules with the Massachusetts Department of Public Utilities (DPU) which, in part, seek to recover costs incurred to serve large customers such as MIT. These rates COMMONWEALTH ENERGY SYSTEM include costs associated with providing standby, maintenance and supplemental service on an ongoing basis as well as a customer transition charge to recover other costs incurred to serve its largest customers should they discontinue service with Cambridge Electric while remaining in Cambridge. In March 1994, Cambridge Electric was successful in negotiating a seven- year service agreement with another large customer, Harvard, whose sales in 1994 accounted for approximately 1.6% of the System's total unit sales. Electric Power Supply To satisfy demand requirements and provide required reserve capacity, the system supplements its generating capacity by purchasing power on a long and short-term basis through capacity entitlements under power contracts with other New England and Canadian utilities and with Qualifying Facilities and other non-utility generators through a competitive bidding process that is regulated by the DPU. System companies own generating facilities with a capability totaling 1,046.5 MW at December 31, 1994. Including 560 MW provided by Canal Unit 1, of which three-quarters (420 MW) is sold to neighboring utilities under long- term contracts, and 292.0 MW provided by Canal Unit 2. Another 145.1 MW is provided by various smaller system units. Of the 577.1 MW available to the system, 77.6 MW are used principally for peaking purposes. A 3.52% ownership interest in the Seabrook 1 nuclear power plant provides 40.5 MW of capability to the system and Central Maine Power Company's Wyman Unit 4, an oil-fired facility in which the system has a 1.4% joint-ownership interest, provides 8.9 MW. In 1991, Canal executed a transaction with Central Vermont Public Service Corporation (CVPS) whereby 50 MW of Canal Unit 2 was exchanged for 25 MW each of CVPS's entitlement in the Vermont Yankee nuclear power plant and the Merrimack 2 coal-fired unit through October 1995. Additionally, in 1993, Canal extended an agreement with New England Power Company (NEP) whereby 50 MW of Canal Unit 2 (previously 20 MW) is exchanged for 50 MW of Bear Swamp Unit Nos. 1 and 2 through April 1997. The Bear Swamp Units are pumped storage hydro electric generating facilities. These contracts are designed to reduce the system's reliance on oil. In addition, through Canal's equity ownership in Hydro-Quebec Phase II, the system has an entitlement of 67.9 MW. Purchase power arrangements were also in place with the following natural gas-fired cogenerating units in Massachusetts: 23 MW from Lowell Cogeneration Company Limited Partnership (Lowell), 38 MW from Pepperell Power Associates Limited Partnership (Pepperell), 53.0 MW from Northeast Energy Associates, 59.9 MW from Masspower and 58.9 MW from Altresco Pittsfield. Additionally, the system receives 67.0 MW from the SEMASS waste-to-energy plant (which includes 20.8 MW from the expansion unit which went on-line in May 1993); has entitlements totaling 24.4 MW through contracts with five (5) hydroelectric suppliers, including 20 MW from Boott Hydropower, Inc., in Lowell, Massachusetts; and also receives 68.2 MW from a natural gas-fired independent power producer, Dartmouth Power Associates. The system anticipates providing for future peak load plus reserve requirements through existing system generation, including purchasing COMMONWEALTH ENERGY SYSTEM available capacity from neighboring utilities and/or non-utility generators. Effective January 1, 1995, the system negotiated a restructured power sale agreement with Lowell and terminated the Pepperell power sale agreement through a buy-out arrangement, effective January 27, 1995. In addition, the system has available 140.7 MW from four nuclear units in which system distribution companies have life-of-the-unit contracts for power. Information with respect to these units is as follows: Connecticut Maine Vermont Yankee Yankee Yankee Pilgrim Year of Initial Operation 1968 1972 1972 1972 Contract Expiration Date 1998 2008 2012 2012 Equity Ownership (%) 4.50 4.00 2.50 - Plant Entitlement (%) 4.50 3.59 2.25 11 Plant Capability (MW) 560.0 870.0 496.0 664.7 System Entitlement (MW) 25.2 31.2 11.2 73.1 On February 26, 1992, the Yankee Atomic Electric Company (Yankee) board of directors agreed to permanently cease power operation of the Yankee nuclear power plant in Rowe, Massachusetts. For additional information, refer to Note 2(e) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. One of the operating nuclear units, located in Wiscasset, Maine and operated by Maine Yankee Atomic Power Company, has been experiencing degradation of its steam generator tubes, principally in the form of circumferential cracking, which until early 1995 was believed to be limited to a relatively small number of tubes. During a refueling and maintenance outage that began in early February 1995, Maine Yankee, through the use of new inspection methods, detected increased degradation of the tubes well above its expectations. Maine Yankee is currently evaluating alternative courses of action to remedy this situation, most of which could result in significant capital expenditures and an extended outage period. At this time, Cambridge Electric cannot predict what action will be needed to rectify the situation, the costs to be incurred or the length of the outage. The Board of Directors of Maine Yankee will be meeting in early April 1995 to consider various options. On October 1, 1992, Commonwealth Electric ceased power generation at its 60 MW Cannon Street generating station located in New Bedford, Massachusetts. During the past few years, the plant had been used primarily to meet peak electric demand and as a backup unit for Commonwealth Electric and the New England Power Pool (NEPOOL). A sharp decline in electric demand brought about by the present economic slowdown was the key factor in management's decision to close the plant. This decision was viewed as the most cost-effective among several alternatives and leaves Commonwealth Electric with the most flexibility for future capacity planning. Cambridge Electric, Canal and Commonwealth Electric, together with other electric utility companies in the New England area, are members of NEPOOL, which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England. COMMONWEALTH ENERGY SYSTEM NEPOOL operates a centralized dispatching facility to ensure reliability of service and to dispatch the most economically available generating units of the member companies to fulfill the region's energy requirement. This concept is accomplished by use of computers to monitor and forecast load requirements. NEPOOL, on behalf of its members entered into an Interconnection Agree- ment with Hydro-Quebec, a Canadian utility operating in the Province of Quebec. The agreement provided for construction of an interconnection (referred to as the Hydro-Quebec Project-Phase I and Phase II) between the electrical systems of New England and Quebec. The parties have also entered into an Energy Contract and an Energy Banking Agreement; the former obligates Hydro-Quebec to offer NEPOOL participants up to 33 million MWH of surplus energy during an eleven-year term that began September 1, 1986 and the latter provides for energy transfers between the two systems. NEPOOL has also entered into Phase II agreements for an additional purchase from Hydro-Quebec of 7 million MWH per year for a twenty-five year period which began in late 1990. Canal is obligated to pay its share of operating and capital costs for Phase II over a 25 year period ending in 2015. Future minimum lease payments for Phase II have an estimated present value of $13.8 million at December 31, 1994. In addition, Canal has an equity interest in Phase II which amounted to $3.8 million in 1994 and $3.9 million in 1993. The System's electric subsidiaries are also members of the Northeast Power Coordinating Council (NPCC), an advisory organization that includes the major power systems in New England and New York plus the Provinces of Ontario and New Brunswick in Canada. NPCC establishes criteria and standards for reliability and serves as a vehicle for coordination in the planning and operation of these systems. The reserve requirements used by the NEPOOL participants in planning future additions are determined by NEPOOL to meet the reliability criteria recommended by NPCC. The system estimates that, during the next ten years, reserve requirements so determined will be in the range of 23% to 29% of peak load. Power Supply Commitments and Support Agreements Cambridge Electric and Commonwealth Electric, through Canal, secure cost savings for their respective customers by planning for bulk power supply on a single system basis. Additionally, Cambridge Electric and Commonwealth Electric have long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. For additional information concerning system commitments under long-term power contracts, refer to Note 2(d) of Notes to Consolidated Financial Statements filed under Item 8 of this report. The system's 3.52% interest in the Seabrook nuclear power plant is owned by Canal to provide for a portion of the capacity and energy needs of Cambridge Electric and Commonwealth Electric. For additional information COMMONWEALTH ENERGY SYSTEM concerning Seabrook 1, refer to Note 2(b) of Notes to Consolidated Financial Statements filed under Item 8 of this report. Electric Fuel Supply (a) Oil Imported residual oil is the fuel used in the generation of power in system generating plants, producing approximately 24% of the system's total energy requirement for 1994. Effective July 1, 1993, Canal executed a twenty-two month contract with Coastal Oil of New England, Inc. (Coastal) for the purchase of residual fuel oil. The contract provides for delivery of a set percentage of Canal's fuel requirement, the balance (a maximum of 20%) to be met by spot purchases or by Coastal at the discretion of Canal. Through December 31, 1994, approximately 16% of Canal's total requirements have been met by lower-cost spot purchases. Energy Supply and Credit Corporation (ESCO) operates Canal's oil terminal and manages the purchase, receipt and payment of oil under assignment of Canal's supply contracts to ESCO (Massachusetts), Inc. Oil in the terminal's tanks is held in inventory by ESCO and delivered upon demand to Canal's tanks. Fuel oil storage facilities at the Canal site have a capacity of 1,199,000 barrels, representing 60 days of normal operation of the two units. During 1994, ESCO maintained an average daily inventory of 575,000 barrels of fuel oil which represents 30 days of normal operation of the two units. This supply is maintained by tanker deliveries approximately every ten to fifteen days. Reference is made to Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," for a discussion of the cost of fuel oil. (b) Nuclear Fuel Supply and Disposal Approximately 25% of the system's total energy requirement for 1994 was generated by nuclear plants. The nuclear fuel contract and inventory informa- tion for Seabrook 1 has been furnished to the system by North Atlantic Energy Services Corporation (NAESCO), the plant manager responsible for operation of the unit. Seabrook's requirement for nuclear fuel components are 100% covered through 1999 by existing contracts. There are no spent fuel reprocessing or disposal facilities currently operating in the United States. Instead, commercial nuclear electric generating units operating in the United States are required to retain high level wastes and spent fuel on-site. As required by the Nuclear Waste Policy Act of 1982 (the Act), as amended, the joint-owners entered into a contract with the Department of Energy for the transportation and disposal of spent fuel and high level radioactive waste at a national nuclear waste repository or a monitored retrievable storage facility. Owners or generators of spent nuclear fuel or its associated wastes are required to bear all of the costs for such transportation and disposal through payment of a fee of approximately COMMONWEALTH ENERGY SYSTEM 1 mill/KWH based on net electric generation to the Nuclear Waste Fund. Under the Act, a temporary storage facility for nuclear waste was anticipated to be in operation by 1998; however, a reassessment of the project's schedule requires extending the completion date of the permanent facility until at least 2010. Seabrook 1 is currently licensed for enough on-site storage to accommodate all spent fuel expected to be accumulated through at least the year 2010. Gas Supply In April 1992, the Federal Energy Regulatory Commission (FERC) issued Order No. 636 (Order 636) which became effective on November 1, 1993. The order requires interstate pipelines to unbundle existing gas sales contracts into separate components (gas sales, transportation and storage services) and to provide transportation services that allow customers to receive the same level and quality of service they had with the previous bundled contracts. Prior to the implementation of Order 636 Commonwealth Gas purchased the majority of its gas supplies from either Tennessee Gas Pipeline Company (Tennessee) or Algonquin Gas Transmission Company (Algonquin), supplemented with third-party firm gas purchases, storage services, and firm transportation from various pipelines. Presently, Commonwealth Gas purchases only transportation, storage, and balancing services from these pipelines (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines) and procures all of its gas supplies from third-party vendors, utilizing firm contracts with terms ranging from less than one year to three or more years. The vendors vary from small independent marketers to major gas and oil companies. For additional information on Order 636, refer to Note 2(g) of Notes to Financial Statements filed under Item 8 of this report. In addition to firm transportation and gas supplies mentioned above, Commonwealth Gas utilizes contracts for underground storage and LNG facilities to meet its winter peaking demands. The underground storage contracts are a combination of existing and new agreements which are the result of Order 636 service unbundling. The LNG facilities, described below, are used to liquefy and store pipeline gas during the warmer months for use during the heating season. During 1994, over 98% of the gas utilized by Commonwealth Gas was delivered by the interstate pipeline system, the remaining small quantity (approximately 662,000 MMBTU) was delivered as liquid LNG from Distrigas of Massachusetts. Commonwealth Gas entered into a multi-party agreement in 1992 to assume a portion of Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta Northeast (ANE), and have the volumes delivered by the Iroquois Gas Transmission System and Tennessee pipelines. The ANE gas supply contract was filed with the DPU and hearings were completed in April 1993. Commonwealth Gas is currently awaiting an order from the DPU. Commonwealth Gas began transporting gas on its distribution system in 1990 for end-users. There are currently eleven customers using this transpor- tation service, accounting for 2,208 BBTU (4.5%) of system throughput in 1994. COMMONWEALTH ENERGY SYSTEM Hopkinton LNG Facility A portion of Commonwealth Gas' gas supply during the heating season is provided by Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of the System. The facility consists of a liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3 million MCF of natural gas. In addition, Hopkinton owns a satellite vaporization plant and two above-ground cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate capacity of 500,000 MCF of natural gas and are filled with LNG trucked from Hopkinton. Commonwealth Gas has a contract for LNG service with Hopkinton ex- tending through 1996, thereafter renewable year to year with notice of termination due five years in advance. Contract payments include a demand charge sufficient to cover Hopkinton's fixed charges and an operating charge which covers liquefaction and vaporization expenses. Commonwealth Gas furnishes pipeline gas during the period April 15 to November 15 each year for liquefaction and storage. As the need arises, LNG is vaporized and placed in the distribution system of Commonwealth Gas. Based upon information presently available regarding projected growth in demand and estimates of availability of future supplies of pipeline gas, Commonwealth Gas believes that its present sources of gas supply are adequate to meet existing load and allow for future growth in sales. Rates, Regulation and Legislation Certain of the System's utility subsidiaries operate under the jurisdiction of the DPU, which regulates retail rates, accounting, issuance of securities and other matters. In addition, Canal, Cambridge Electric and Commonwealth Electric file their respective wholesale rates with the FERC. (a) Most Recent Rate Case Proceedings Electric On May 28, 1993, the DPU issued an order increasing Cambridge Electric's retail revenues by approximately $7.2 million, or 6.4%. The rates, based on a June 30, 1992 test-year and effective June 1, 1993, provide an overall return of 9.95%, including an equity return of 11% and represented approximately 70% of the amount requested. The new rates reflect the costs associated with postretirement benefits other than pensions which were determined in accordance with Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," adopted as of January 1, 1993. The DPU authorized full recovery of these costs over a four-year phase-in period with carrying costs on the deferred portion. The new base rates also reflect the roll-in of costs associated with the Seabrook nuclear power plant which are billed to Cambridge Electric by Canal. Previously these costs were recovered through Cambridge Electric's Fuel Charge decimal. COMMONWEALTH ENERGY SYSTEM On July 1, 1991, the DPU issued an order increasing Commonwealth Elec- tric's retail electric revenues by $10.9 million, or 3.1%. The requested increase was $17.3 million. The order, based on a June 30, 1990 test-year, provided an overall return of 10.49%, including a return on equity of 12%. Gas On April 16, 1991, Commonwealth Gas requested a $27.7 million (11.3%) revenue increase in a filing with the DPU using a test-year ended December 31, 1990. On September 16, 1991, the DPU approved a settlement of the revenue requirements portion of the filing authorizing a $22.8 million increase in annual revenues, approximately 82% of the original request. The agreement included a return on equity, for accounting purposes, of 13%. The DPU later ruled on the rate design portion of the request and new rates went into effect on November 1, 1991. In May 1994, Commonwealth Gas requested the DPU to change the backup service charges under its firm transportation rate. Back up charges result when Commonwealth Gas sells gas from its system supplies to a customer whose off-system gas supply has failed or is temporarily unavailable for causes beyond the customer's control. The change involved an upward indexing based on changes in the gas supply demand costs occasioned by Order 636. On December 22, 1994, the DPU approved Commonwealth Gas' requested change effective January 1, 1995. This change, which has no effect on revenue, results in a more equitable recovery of pipeline capacity costs between Commonwealth Gas' total requirements and transportation customers. (b) Wholesale Rate Proceedings Cambridge Electric requires FERC approval to increase its wholesale rates to the Town of Belmont, Massachusetts (Belmont), a "partial requirements" customer since 1986. These rates include a fuel adjustment clause which reflects changes in costs of fuels and purchased power used to supply Belmont. During March of 1993, Cambridge Electric and Belmont signed a net requirements power supply agreement, the terms and conditions of which required Belmont to pay for all costs except transmission fees which Cambridge Electric and Belmont attempted to negotiate. The negotiations were not successful and Cambridge Electric filed for approval of transmission rates with the FERC on June 29, 1994. The FERC accepted the rates effective January 25, 1995, subject to refund. At the same time, an investigation was opened by the FERC to determine the reasonableness of both the existing and the proposed transmission rates charged to Belmont. Cambridge Electric filed its case with the FERC on October 25, 1994 and hearings are scheduled to begin during the second quarter of 1995. (c) Automatic Adjustment Clauses Electric Both Commonwealth Electric and Cambridge Electric have Fuel Charge rate schedules which generally allow for current recovery, from retail customers, of fuel used in electric production, purchased power and transmission costs. COMMONWEALTH ENERGY SYSTEM These schedules require a quarterly computation and DPU approval of a Fuel Charge decimal based upon forecasts of fuel, purchased power, transmission costs and billed unit sales for each period. To the extent that collections under the rate schedules do not match actual costs for that period, an appropriate adjustment is reflected in the calculation of the next subsequent calendar quarter decimal. Cambridge Electric and Commonwealth Electric collect a portion of the capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The recovery mechanism for these costs uses a per kilowatthour (KWH) factor that is calculated using historical (test- period) capacity costs and unit sales. This factor is then applied to current monthly KWH sales. When current period capacity costs and/or unit sales vary from test-period levels, Cambridge Electric and Commonwealth Electric experience a revenue excess or shortfall which can have a significant impact on net income. All other capacity and energy-related purchased power costs are recovered through the Fuel Charge. Cambridge Electric and Commonwealth Electric made a filing in late 1992 with the DPU seeking an alternative method of recovery. This request was denied in a letter order issued on October 6, 1993. However, the companies were encouraged by the DPU's acknowledgement that the issues presented warrant further consideration. The DPU encouraged each company to continue to work with other interested parties, including the Attorney General of Massachusetts, to reach a consensus solution on the issue for future consideration. The companies have been involved in discussions with interested parties in an effort to resolve this issue in a positive fashion and hope to reach an agreement in the near future. Both Commonwealth Electric and Cambridge Electric have separately stated Conservation Charge rate schedules which allow for current recovery, from retail customers, of Conservation and Load Management program costs. For further information, refer to Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 of this report. Gas Commonwealth Gas has a Standard Seasonal Cost of Gas Adjustment rate schedule (CGA) which provides for the recovery, from firm customers, of purchased gas costs not collected through base rates. These schedules, which require DPU approval, are estimated semi-annually and include credits for gas pipeline refunds and profit margins applicable to interruptible sales. Actual gas costs are reconciled annually as of October 31 and any difference is included as an adjustment in the calculation of the decimals for the two subsequent six-month periods. The DPU and the Massachusetts Energy Facilities Siting Council (the Council) were merged in 1992. The Council is now a division of the DPU. Periodically, Commonwealth Gas is required to file a long-range forecast of the energy needs and requirements of its market area and annual supplements thereto with the Council. To approve a long-range forecast, the Council must find, among other things, that Commonwealth Gas plans for construction of new gas manufacturing or storage facilities and certain high-pressure gas pipelines are consistent with current health, environmental protection, and resource use and development policies as adopted by the Commonwealth of COMMONWEALTH ENERGY SYSTEM Massachusetts. Commonwealth Gas filed a long-range forecast with the Council on July 20, 1990 and updated aspects of the filing in March 1991. This forecast was combined with the DPU review of the ANE contract. Both issues are pending before the DPU. (d) Gas Demand, Take-or-Pay Costs and Transition Costs Commonwealth Gas is obligated, as part of its pipeline transportation and supplier gas purchase contracts, to pay monthly demand charges which are recovered through the CGA. In June 1991, Tennessee filed a settlement with the FERC dealing with a variety of contract restructuring issues, including the allocation of take-or- pay costs to Tennessee's customers including Commonwealth Gas. This comprehensive settlement was approved and implemented on July 1, 1992. As part of the settlement, the allocation of take-or-pay costs was changed from a deficiency basis to a contract demand basis which increased Commonwealth Gas' allocation. There are still some small on-going amounts of take-or-pay costs being collected by the pipeline, however, Tennessee has nearly reached the cap of allowable collections under the settlement. Algonquin made a series of filings with the FERC to recover from its customers take-or-pay charges imposed on it by its upstream suppliers. Algonquin billed Commonwealth Gas for gas supply inventory charges from Texas Eastern and others through the Algonquin commodity rate. With the implementation of Order 636, Algonquin allocated the remaining costs utilizing a formula based on actual purchases for the twelve months prior to May 1, 1993. Commonwealth Gas' allocation was in excess of $5 million. Commonwealth Gas successfully appealed Algonquin's allocation method to the FERC. The change in allocation, combined with issues being settled in Algonquin's current rate case will reduce Commonwealth Gas' allocated share to $2.5 million. In addition, a settlement was reached with Koch Gateway Pipeline (formerly the United Gas Pipeline) whereby Commonwealth Gas received approximately $2 million in refunds for take-or-pay costs allocated through Texas Eastern and Algonquin since 1985. This amount is currently being refunded to firm customers through the CGA. Commonwealth Gas is collecting all contract restructuring costs from its customers through the CGA as permitted by the DPU. Competition This past year, the system continued to develop and implement strategies to deal with the increasingly competitive environment in our gas and electric businesses. The inherently high cost of providing energy services in the Northeast has placed the region at a competitive disadvan- tageas more customers begin to explore alternative supply options. Many state and federal government agencies are considering implementing programs under which utility and non-utility generators can sell electricity to customers of other utilities without regard to previously closed franchise service areas. In 1994, the DPU began an inquiry into incentive rate-making and in February 1995 opened an investigation into electric industry restructuring. COMMONWEALTH ENERGY SYSTEM Actions by system companies in response to the new competitive challenges have been well received by regulators, business groups and customers. For a more detailed discussion of competition and the programs currently in place within the system, refer to the "Competition" section of Management's Discussion and Analysis of Financial Condition and Results of Operation filed under Item 7 of this report. Segment Information System companies provide electric, gas and steam services to retail customers in service territories located in central and eastern Massachusetts and, in addition, sell electricity at wholesale to Massachusetts customers. Other operations of the system include the development and management of new real estate ventures and 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 10 of Notes to Consolidated Financial Statements filed under Item 8 of this re- port. Environmental Matters The system is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. System compliance with these laws and regulations will require capital expenditures of $41.8 million from 1995 through 1999 for the electric and gas divisions. For additional information concerning environmental issues including those relating to former gas manufacturing sites, refer to the "Environmental Matters" section of "Management's Discussion and Analysis of Financial Condi- tion and Results of Operations" filed under Item 7 of this report. Construction and Financing For information concerning the system's financing and construction programs refer to Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 and Note 2(a) of the Notes to Consolidated Financial Statements filed under Item 8 of this report. Employees The total number of full-time employees for the system declined 2.2% to 2,169 in 1994 from 2,217 employees at year-end 1993. Of the current total, 1,282 (59%) are represented by various collective bargaining units. Existing agreements are for varying periods and expire in 1995 and thereafter. Employee relations have generally been satisfactory. Item 2. Properties The system's principal electric properties consist of Canal Unit 1, a 569 MW oil-fired steam electric generating unit, and its one-half ownership in Canal Unit 2, a 580 MW oil-fired steam electric generating unit, both located COMMONWEALTH ENERGY SYSTEM at Canal Electric's facility in Sandwich, Massachusetts. Other electric properties include an integrated system of distribution lines and substations together with Commonwealth Electric's 60 MW steam electric generating station located in New Bedford, Massachusetts which ceased operations in October 1992 and was abandoned in 1993. Cambridge Electric has two steam electric generating stations with a net capability of 76.5 MW located in Cambridge, Massachusetts. In addition, the system has a 3.52% interest (40.5 MW of capacity) in Seabrook 1 and a 1.4% or 8.9 MW joint-ownership interest in Central Maine Power Company's Wyman Unit 4. The system also has an interest in smaller generating units totaling 77.6 MW used primarily for peaking and emergency purposes. In addition, the system's other principal properties consist of an electric division office building in Wareham, Massachusetts and other structures such as garages and service buildings. At December 31, 1994, the electric transmission and distribution system consisted of 5,790 pole miles of overhead lines, 4,192 cable miles of underground line, 355 substations and 374,055 active customer meters. The principal natural gas properties consist of distribution mains, services and meters necessary to maintain reliable service to customers. At the end of 1994, the gas system included 2,761 miles of gas distribution lines, 162,971 services and 239,302 customer meters together with the necessary measuring and regulating equipment. In addition, the system owns a liquefaction and vaporization plant, a satellite vaporization plant and above- ground cryogenic storage tanks having an aggregate storage capacity equivalent to 3.5 million MCF of natural gas. The system's gas division owns a central headquarters and service building in Southborough, Massachusetts, five district office buildings and several natural gas receiving and take stations. Item 3. Legal Proceedings The system is subject to legal claims and matters arising from its course of business, including its participation in power contract arbitrations as discussed in the "Power Contract Arbitrations" section of Management's Discussion and Analysis of Financial Condition and Results of Operations filed under Item 7 of this report. Item 4. Submission of Matters to a Vote of Security Holders None COMMONWEALTH ENERGY SYSTEM PART II. Item 5. Market for the Registrant's Securities and Related Stockholder Matters (a) Principal Markets The System's common shares are listed on the New York, Boston 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. 1994 by Quarter First Second Third Fourth High $45 1/2 $43 3/4 $40 3/4 $38 3/4 Low 42 7/8 39 1/2 37 1/2 35 3/8 1993 by Quarter First Second Third Fourth High $48 7/8 $48 5/8 $50 1/8 $49 3/4 Low 40 1/2 43 3/8 46 3/4 43 (b) Number of Shareholders at December 31, 1994 15,081 shareholders (c) Frequency and Amount of Dividends Declared in 1994 and 1993 1994 1993 Per Per Share Share Declaration Date Amount Declaration Date Amount March 24, 1994 $ .75 March 25, 1993 $ .73 June 23, 1994 .75 June 24, 1993 .73 September 22, 1994 .75 September 23, 1993 .73 December 15, 1994 .75 December 16, 1993 .73 $3.00 $2.92 (d) Future dividends may vary depending upon the System's earnings and capital requirements as well as financial and other conditions existing at that time. Item 6. Selected Financial Data Information required by this item is incorporated herein by reference to Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information dated March 31, 1995, page 58. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Information required by this item is incorporated herein by reference to Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information dated March 31, 1995, pages 20 through 35. COMMONWEALTH ENERGY SYSTEM Item 8. Financial Statements and Supplementary Data The following consolidated financial statements and supplementary data of the System and its subsidiaries are incorporated herein by reference to Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information dated March 31, 1995 on pages 35 through 58. Proxy Page Reference Management's Report 35 Report of Independent Public Accountants 36 Consolidated Balance Sheets - At December 31, 1994 and 1993 37/38 Consolidated Statements of Income - Years Ended December 31, 1994, 1993 and 1992 39 Consolidated Statements of Cash Flows - Years Ended December 31, 1994, 1993 and 1992 40 Consolidated Statements of Capitalization - At December 31, 1994 and 1993 41 Consolidated Statements of Changes in Common Shareholders' Investment and in Redeemable Preferred Shares - Years Ended December 31, 1994, 1993 and 1992 42 Notes to Consolidated Financial Statements 43/57 Quarterly Information pertaining to the results of operations for the years ended December 31, 1994 and 1993 58 Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure None COMMONWEALTH ENERGY SYSTEM PART III. Item 10. Trustees and Executive Officers of the Registrant a. Trustees of the Registrant: Information required by this item is incorporated herein by reference to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information dated March 31, 1995, pages 3-6. b. Executive Officers of the Registrant: Age at December Name of Officer Position and Business Experience 31, 1994 William G. Poist President, Chief Executive Officer and 61 Trustee of the System and Chairman and Chief Executive Officer of its principal subsidiary companies since January 1, 1992; Vice President of the System and COM/Energy Services Company* effective September 1, 1991; President and Chief Operating Officer of Commonwealth Gas Company* from 1983 to 1991 and Hopkinton LNG Corp.* from 1985 to 1991. James D. Rappoli Financial Vice President and Treasurer of 43 the System and its subsidiary companies effective March 1, 1993; Treasurer of System subsidiary companies 1990; Assistant Treas- urer of System subsidiary companies 1989. Russell D. Wright President and Chief Operating Officer of 48 Cambridge Electric Light Company*, Canal Electric Company*, COM/Energy Steam Company*, and Commonwealth Electric Company* effective March 1, 1993; Financial Vice President and Treasurer of the System and Financial Vice President of its subsidiary companies (July 1987 to March 1993); Treasurer of System subsidiary companies (December 1989 to December 1990), Assistant Vice President- Finance of System subsidiary companies 1986. Kenneth M. Margossian President and Chief Operating Officer of 46 Commonwealth Gas Company* and Hopkinton LNG Corp.* effective September 1, 1991; Vice President of Operations from 1988 to 1991; Vice President of Facilities Develop- ment from 1987 to 1988; Vice President of Human Resources and Administration of Commonwealth Gas Company from 1985 to 1987. *Subsidiary of the System. COMMONWEALTH ENERGY SYSTEM b. Executive officers of the Registrant (Continued): Age at December Name of Officer Position and Business Experience 31, 1994 Michael P. Sullivan Vice President, Secretary, and 46 General Counsel of the System and subsidiary companies (effective June 1993); Vice President, Secretary, and General Attorney of the System and subsidiary companies since 1981. John A. Whalen Comptroller of the System and subsidiary 47 companies since 1978. The term of office for System officers expires May 4, 1995, the date of the next Annual Organizational Meeting. There are no family relationships between any trustee and executive officer and any other trustee or executive of the System. There were no arrangements or understandings between any officer or trustee and any other person pursuant to which he was or is to be selected as an officer, trustee or nominee. There have been no events under any bankruptcy act, no criminal pro- ceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any trustee or executive officer during the past five years. Item 11. Executive Compensation Information required by this item is incorporated herein by reference to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Informa- tion dated March 31, 1995, pages 6-11. Item 12. Security Ownership of Certain Beneficial Owners and Management Information required by this item is incorporated herein by reference to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Inform- ation dated March 31, 1995, pages 3-6. Item 13. Certain Relationships and Related Transactions Information required by this item is incorporated herein by reference to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Inform- ation dated March 31, 1995, pages 3-6. COMMONWEALTH ENERGY SYSTEM PART IV. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. Index to Financial Statements Consolidated financial statements and notes thereto of Commonwealth Energy System and Subsidiary Companies together with the Report of Independent Public Accountants, as detailed on page 17 in Item 8 of this Form 10-K, have been incorporated herein by reference to Exhibit A to the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information dated March 31, 1995. (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 42). Schedule I - Investments in, Equity in Earnings of, and Dividends Received from Related Parties - Years Ended December 31, 1994, 1993 and 1992 (pages 43-45). Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 1994, 1993 and 1992 (page 46). 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 May 1, 1995. (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. COMMONWEALTH ENERGY SYSTEM 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 5, 1994 (Exhibit 1 to the CES Form S-3 (September 1994), 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) 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) COMMONWEALTH ENERGY SYSTEM 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). 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). COMMONWEALTH ENERGY SYSTEM 10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and CEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 1 to the 1991 CEL Form 10-K, File No. 2-7909). 10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the CEL Form 10-Q (June 1988), File No. 2-7909). 10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (September 1989), File No. 2-7909). 10.1.3 Power Contract between YAEC and NBGEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to the 1991 CE Form 10-K, File No. 2-7749). 10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended October 1, 1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE Form 10-Q (June 1988), File No. 2-7749). 10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989), File No. 2-7749). 10.1.4 Power Contract between Connecticut Yankee Atomic Power Company (CYAPC) and CEL dated July 1, 1964 (Exhibit 13-K1 to the System's Form S-1, (April 1967) File No. 2-25597). 10.1.4.1 Additional Power Contract providing for extension on contract term between CYAPC and CEL dated April 30, 1984 (Exhibit 5 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.4.2 Second Supplementary Power Contract providing for decommissioning financing between CYAPC and CEL dated April 30, 1984 (Exhibit 6 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.5 Power contract between Vermont Yankee Nuclear Power Corporation (VYNPC) and CEL dated February 1, 1968 (Exhibit 3 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and Second Amendment dated April 15, 1983 (decommissioning financing) to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q (June 1984), File No. 2- 7909). 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). COMMONWEALTH ENERGY SYSTEM 10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as amended June 15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No. 2-7909). 10.1.5.5 Additional Power Contract dated February 1, 1984 between CEL and VYNPC providing for decommissioning financing and contract extension (Refiled as Exhibit 1 to CEL 1993 Form 10-K, File No. 2-7909). 10.1.6 Power contract between Maine Yankee Atomic Power Company (MYAPC) and CEL dated May 20, 1968 (Exhibit 5 to the System's Form S-7, File No. 2-38372). 10.1.6.1 First Amendment dated March 1, 1984 (decommissioning financing) and Second Amendment dated January 1, 1984 (supplementary payments) to 10.1.6 (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No. 2-7909). 10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit 1 to the CEL Form 10-Q (September 1984), File No. 2-7909). 10.1.7 Agreement between NBGEL and Boston Edison Company (BECO) for the purchase of electricity from BECO's Pilgrim Unit No. 1 dated August 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2- 7749). 10.1.7.1 Service Agreement between NBGEL and BECO for purchase of stand-by power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.7.2 System Power Sales Agreement by and between CE and BECO dated July 12, 1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No. 2-7749). 10.1.7.3 Power Exchange Agreement by and between BECO and CE dated December 1, 1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.7.4 Power Exchange Agreement by and between BECO and CEL dated December 1, 1984 (Exhibit 5 to the CEL 1984 Form 10-K, File No. 2- 7909). 10.1.7.5 Service Agreement for Non-Firm Transmission Service between BECO and CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File No. 2-7909). 10.1.8 Agreement for Joint-Ownership, Construction and Operation of New Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to the NBGEL Form S-1 dated October 1973, File No. 2-49013 and as amended below: 10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974 and January 31, 1975, respectively (Exhibit 13(m) to the NBGEL Form S-1 (November 7, 1975), File No. 2-54995). COMMONWEALTH ENERGY SYSTEM 10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended April 18, 1979, April 25, 1979, June 8, 1979, October 11, 1979 and December 15, 1979, respectively (Refiled as Exhibit 1 to the CEC 1989 Form 10-K, File No. 2-30057). 10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as amended May 16, 1980, December 31, 1980 and June 1, 1982, respectively (Filed as Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749). 10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended April 27, 1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10- Q (June 1984), File No. 2-30057). 10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985 (Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2-30057). 10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986 (Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2-30057). 10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2-30057). 10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19, 1986 (Exhibit 1 to the CEC 1986 Form 10-K, File No. 2-30057). 10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12, 1987 (Exhibit 1 to the CEC 1987 Form 10-K, File No. 2-30057). 10.1.8.10 Settlement Agreement and Twenty-Second Amendment to 10.1.8, both dated January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.9 Interim Agreement to Preserve and Protect the Assets of and Investment in the New Hampshire Nuclear Units dated April 27, 1984 (Exhibit 2 to the CEC Form 10-Q (June 1984), File No. 2-30057). 10.1.10 Resolutions proposed by Merrill Lynch Capital Markets and adopted by the Joint-Owners of the Seabrook Nuclear Project regarding Project financing, dated May 14, 1984 (Exhibit 1 to the CEC Form 10-Q (March 1984), File No. 2-30057). 10.1.11 Agreement for Seabrook Project Disbursing Agent establishing YAEC as the disbursing agent under the Joint-Ownership Agreement, dated May 23, 1984 (Exhibit 4 to the CEC Form 10-Q (June 1984), File No. 2-30057). 10.1.11.1 First Amendment to 10.1.11 as amended March 8, 1985 (Exhibit 2 to the CEC Form 10-Q (March 1985), File No. 2-30057). 10.1.11.2 Second through Fifth Amendments to 10.1.11 as amended May 20, 1985, June 18, 1985, January 2, 1986 and November 12, 1987, respectively (Exhibit 4 to the CEC 1987 Form 10-K, File No. 2-30057). COMMONWEALTH ENERGY SYSTEM 10.1.12 Agreement to Share Certain Costs Associated with the Tewksbury- Seabrook Transmission Line dated May 8, 1986 (Exhibit 2 to the CEC 1986 Form 10-K, File No. 2-30057). 10.1.13 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). 10.1.14 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). 10.1.15 Termination Supplement between CEC, CE and CEL for Seabrook Unit 2, dated December 8, 1986 (Exhibit 3 to the CEC 1986 Form 10-K, File No. 2-30057). 10.1.16 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). 10.1.17 Agreement between NBGEL and Central Maine Power Company (CMP), for the joint-ownership, construction and operation of William F. Wyman Unit No. 4 dated November 1, 1974 together with Amendment No. 1 dated June 30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No. 2-54955). 10.1.17.1 Amendments No. 2 and 3 to 10.1.17 as amended August 16, 1976 and December 31, 1978 (Exhibit 5(a) 14 to the System's Form S-16 (June 1979), File No. 2-64731). 10.1.18 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). 10.1.18.1 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). 10.1.18.2 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). 10.1.19 Contract between CEC and NBGEL and CEL, affiliated companies, for the sale of specified amounts of electricity from Canal Unit 2 dated January 12, 1976 (Exhibit 7 to the System's 1985 Form 10-K, File No. 1-7316). COMMONWEALTH ENERGY SYSTEM 10.1.20 Capacity Acquisition Agreement between CEC,CEL and CE dated September 25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File No. 2-30057). 10.1.20.1 Supplement to 10.1.20 consisting of three Capacity Acquisition Commitments each dated May 7, 1987, concerning Phases I and II of the Hydro-Quebec Project and electricity acquired from Connecticut Light and Power Company (CL&P) (Exhibit 1 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.20.2 Supplements to 10.1.20 consisting of two Capacity Acquisition Commitments each dated October 31, 1988, concerning electricity acquired from Western Massachusetts Electric Company and/or CL&P for periods ranging from November 1, 1988 to October 31, 1994 (Exhibit 2 to the CEC Form 10-Q (September 1989), File No. 2- 30057). 10.1.20.3 Amendment to 10.1.20 as amended and restated June 1, 1993, henceforth referred to as the Capacity Acquisition and Disposition Agreement, whereby Canal Electric Company, as agent, in addition to acquiring power may also sell bulk electric power which Cambridge Electric Light Company and/or Commonwealth Electric Company owns or otherwise has the right to sell (Exhibit 1 to Canal Electric's Form 10-Q (September 1993), File No. 2-30057). 10.1.20.4 Capacity Disposition Commitment dated June 25, 1993 by and between Canal Electric Company (Unit 2) and Commonwealth Electric Company for the sale of a portion of Commonwealth Electric's entitlement in Unit 2 to Green Mountain Power Corporation (Exhibit 2 to Canal Electric's Form 10-Q (September 1993), File No. 2-30057). 10.1.21 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). 10.1.21.1 Amendment No. 2 to 10.1.21 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.21.2 Amendment No. 3 to 10.1.21 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749). 10.1.22 Participation Agreement between MEPCO and CEL and/or NBGEL dated June 20, 1969 for construction of a 345 KV transmission line between Wiscasset, Maine and Mactaquac, New Brunswick, Canada and for the purchase of base and peaking capacity from the NBEPC (Exhibit 13 to the CES 1984 Form 10-K, File No. 1-7316). 10.1.22.1 Supplement Amending 10.1.22 as amended June 24, 1970 (Exhibit 8 to the CES Form S-7, Amendment No. 1, File No. 2-38372). COMMONWEALTH ENERGY SYSTEM 10.1.23 Power Purchase Agreement between Weweantic Hydro Associates and CE for the purchase of available hydro-electric energy produced by a facility located in Wareham, Massachusetts, dated December 13, 1982 (Exhibit 1 to the CE 1983 Form 10-K, File No. 2-7749). 10.1.23.1 Power Purchase Agreement (Revised) between Weweantic Hydro Associ- ates and Commonwealth Electric (CE) for the purchase of available hydro-electric energy produced by a facility located in Wareham, MA, originally dated December 13, 1982, revised and dated March 12, 1993 (Exhibit 1 to the CE Form 10-Q (June 1993), File No. 2-7749). 10.1.24 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). 10.1.25 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). 10.1.25.1 Amendment to 10.1.25 between CI and Boott Hydropower, Inc., an assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.26 Phase 1 Terminal Facility Support Agreement dated December 1, 1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November 1, 1982, between New England Electric Transmission Corporation (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.26.1 Amendment No. 3 to 10.1.26 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749). 10.1.27 Preliminary Quebec Interconnection Support Agreement dated May 1, 1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amendment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.28 Agreement with Respect to Use of Quebec Interconnection dated December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated November 1, 1982 among certain NEPOOL utilities (Exhibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.28.1 Amendatory Agreement No. 3 to 10.1.28 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057). 10.1.29 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). COMMONWEALTH ENERGY SYSTEM 10.1.30 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). 10.1.31 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). 10.1.32 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). 10.1.32.1 First, Second and Third Amendments to 10.1.32 as amended March 1, 1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.32.2 Fifth, Sixth and Seventh Amendments to 10.1.32 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Exhibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057). 10.1.32.3 Fourth and Eighth Amendments to 10.1.32 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057). 10.1.32.4 Ninth and Tenth Amendments to 10.1.32 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.32.5 Eleventh Amendment to 10.1.32 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057). 10.1.32.6 Twelfth Amendment to 10.1.32 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057). 10.1.33 Phase II Equity Funding Agreement for New England Hydro- Transmission Electric Company, Inc. (New England Hydro) (Massachusetts), dated June 1, 1985, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.34 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2-30057). COMMONWEALTH ENERGY SYSTEM 10.1.35 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). 10.1.36 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). 10.1.36.1 Amendment No. 1 to 10.1.36 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.36.2 Amendment No. 2 to 10.1.36 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.37 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). 10.1.37.1 Amendments Nos. 1 and 2 to 10.1.37 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.37.2 Amendments Nos. 3 and 4 to 10.1.37 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.38 Phase II Boston Edison AC Facilities Support Agreement, dated June 1, 1985, between BECO and certain NEPOOL utilities (Exhibit 7 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.38.1 Amendments Nos. 1 and 2 to 10.1.38 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.38.2 Amendments Nos. 3 and 4 to 10.1.38 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.39 Agreement Authorizing Execution of Phase II Firm Energy Contract, dated September 1, 1985, among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro-Quebec (Exhibit 8 to the CEC Form 10-Q (September 1985), File No. 2- 30057). 10.1.40 System Power Sales Agreement by and between CE, as seller, and Central Vermont Public Service Corporation (CVPS), as buyer, dated September 15, 1984 (Exhibit 2 to the CE Form 10-Q (September 1984), File No. 2-7749). COMMONWEALTH ENERGY SYSTEM 10.1.40.1 System Sales Agreement by CVPS, as seller, and CE, as buyer, dated September 15, 1984 (Exhibit 9 to the CE 1984 Form 10-K, File No. 2- 7749). 10.1.40.2 System Sales and Exchange Agreement by and between CVPS and CE on energy transactions, dated September 15, 1984 (Exhibit 10 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.40.3 System Exchange Agreement by and between CE and CVPS for the exchange of capacity and associated energy, dated September 3, 1985 (Exhibit 1 to the CE 1985 Form 10-K, File No. 2-7749). 10.1.40.4 Purchase Agreement by and between CEC and CVPS for the purchase of capacity from CEC for the term March 1, 1991 to October 31, 1995, dated March 1, 1991 (Exhibit 1 to CEC Form 10-Q (June 1991), File No. 2-30057). 10.1.40.5 Power Sale Agreement by and between CEC and CVPS for the purchase of 50 MW of capacity from CVPS's units (25 MW from Vermont Yankee and 25 MW from Merrimack 2) for the term of March 1, 1991 to October 31, 1995, dated March 1, 1991 (Exhibit 2 to CEC Form 10-Q (June 1991), File No. 2-30057). 10.1.41 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). 10.1.41.1 Transmission Service Agreement between Northeast Utilities' companies (NU) - The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO), and CE for NU companies to transmit power purchased from Swift River Company's Chicopee Units to CE, dated October 1, 1984 (Exhibit 14 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.41.2 Transformation Agreement between WMECO and CE whereby WMECO is to transform power to CE from the Chicopee Units, dated December 1, 1984 (Exhibit 15 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.42 System Power Sales Agreement by and between CL&P and WMECO, as buyers, and CE, as seller, dated January 13, 1984 (Exhibit 13 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.43 System Power Sales Agreement by and between CL&P, WMECO, as sellers, and CEL, as buyer, of power in excess of firm power customer requirements from the electric systems of the NU Companies, dated June 1, 1984, as effective October 25, 1985 (Exhibit 1 to CEL 1985 Form 10-K, File No. 2-7909). 10.1.44 Power Purchase Agreement with Respect to South Meadow Unit Nos. 11, 12, 13, and 14 of the NU system company of CL&P (seller) and CE (buyer), dated November 1, 1985 (Exhibit 1 to the CE Form 10-Q (June 1986), File No. 2-7749). COMMONWEALTH ENERGY SYSTEM 10.1.45 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). 10.1.45.1 Power Sales Agreement to 10.1.45 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749). 10.1.45.2 Amendment to 10.1.45 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). 10.1.45.3 Amendment to 10.1.45 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). 10.1.46 System Power Sales Agreement by and between CE (seller) and NEP (buyer), dated January 6, 1984 (Exhibit 1 to the CE Form 10-Q (June 1985), File No. 2-7749). 10.1.47 Service Agreement by and between CE and NEP dated March 24, 1984, whereas CE agrees to purchase short-term power applicable to NEP'S FERC Electric Tariff Number 5 (Exhibit 1 to the CE Form 10-Q (June 1987), File No. 2-7749). 10.1.48 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). 10.1.48.1 First Amendment to 10.1.48 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749). 10.1.48.2 Second Amendment to 10.1.48 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.48.3 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). 10.1.48.4 Amendment to 10.1.48.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.49 Exchange of Power Agreement between Montaup Electric Company and CE dated January 17, 1991 (Exhibit 2 to CE Form 10-Q (September 1991) File No. 2-7749). COMMONWEALTH ENERGY SYSTEM 10.1.49.1 First Amendment, dated November 24, 1992, to Exchange of Power Agreement between Montaup Electric Company and Commonwealth Electric Company (CE) dated January 17, 1991 (Exhibit 1 to CE Form 10-Q (March 1993) File No. 2-7749). 10.1.50 System Power Exchange Agreement by and between Commonwealth Electric Company (CE) and New England Power Company dated January 16, 1992 (Exhibit 1 to CE Form 10-Q (March 1992), File No. 2-7749). 10.1.50.1 First Amendment, dated September 8, 1992, to System Power Exchange Agreement by and between Commonwealth Electric Company (CE) and New England Power Company dated January 16, 1992 (Exhibit 1 to CE Form 10-Q (September 1992), File No. 2-7749). 10.1.50.2 Second Amendment, dated March 2, 1993, to System Power Exchange Agreement by and between CE and New England Power Company (NEP) dated January 16, 1992 (Exhibit 2 to CE Form 10-Q (March 1993) File No. 2-7749). 10.1.51 Power Purchase Agreement and First Amendment, dated September 5, 1989 and August 3, 1990, respectively, by and between Commonwealth Electric (CE) (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). 10.1.52 Power Exchange Contract, dated March 24, 1993, between NEP and Canal Electric Company (Canal) for an exchange of unit capacity in which NEP will purchase 20 MW of Canal Unit 2 capacity in exchange for Canal's purchase of 20 MW of NEP's Bear Swamp Units 1 and 2 (10 MW per unit) commencing May 31, 1993 through April 28, 1997 and NEP will purchase 50 MW of Canal's Unit 2 capacity in exchange for Canal's purchase of 50 MW of NEP's Bear Swamp Units 1 and 2 (25 MW per unit) commencing November 1, 1993 through April 28, 1997 (Exhibit 1 to Canal's Form 10-Q (March 1993) File No. 2-30057). 10.1.53 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). 10.1.54 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). 10.1.54.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., Cambridge Electric Light Company, Commonwealth Electric Company and New England Power Company, dated July 2, 1993 (Exhibit 3 to Commonwealth Electric's Form 10-Q (September 1993), File No 2- 7749). COMMONWEALTH ENERGY SYSTEM 10.1.54.2 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). 10.2 Natural gas purchase contracts. 10.2.2 Service Agreement Applicable to Rate Schedule F-1 between AGT and CG for Firm natural gas services, dated January 28, 1981 (Exhibit 1 to the CG Form 10-Q (March 1987), File No. 2-1647). 10.2.3 Service Agreement Applicable to Rate Schedule F-2 between AGT and CG for the purchase of certain quantities of natural gas acquired by AGT from CGS, dated April 11, 1985 (Exhibit 2 to the CG Form 10- Q (March 1987), File No. 2-1647). 10.2.4 Service Agreement Applicable to Rate Schedule F-3 between AGT and CG for the purchase of certain quantities of natural gas acquired by AGT from National Fuel Gas Supply Corporation, dated April 11, 1985 (Exhibit 3 to the CG Form 10-Q (March 1987), File No. 1-1647). 10.2.5 Service Agreement Applicable to Rate Schedule F-4 between AGT and CG for the purchase of certain quantities of natural gas acquired by AGT from Texas Eastern Transmission Company, dated December 26, 1985 (Exhibit 4 to the CG Form 10-Q (March 1987), File No. 2-1647). 10.2.6 Gas Service Contract between HOPCO and NBGEL for the performance of liquefaction, storage and vaporization service and the operation and maintenance of an LNG facility located at Acushnet, MA dated September 1, 1971 (Exhibit 8 to the CG 1984 Form 10-K, File No. 2- 1647). 10.2.6.1 Gas Service Contract between HOPCO and CG for the performance of liquefaction, storage and vaporization services and the operation of LNG facilities located in Hopkinton, MA dated September 1, 1971 (Exhibit 9 to the CG 1984 Form 10-K, File No. 2-1647). 10.2.6.2 Amendments to 10.2.6 and 10.2.6.1 as amended December 1, 1976 (Exhibits 2 and 3 to the CG 1986 Form 10-K, File No. 2-1647). 10.2.6.3 Supplement 1 to Gas Service Contract between HOPCO and NBGEL dated September 1, 1973 and September 14, 1977 (Exhibit 5(c)5 to the CES Form S-16 (June 1979), File No. 2-64731). 10.2.6.4 Supplement 1 to 10.2.6.1 dated September 14, 1977 (Exhibit 5(c)6 to the CG Form S-16 (June 1979), File No. 2-64731). 10.2.6.5 Supplement 2 to 10.2.6.1 dated September 30, 1982 (Refiled as Exhibit 2 to the CG 1992 Form 10-K, File No. 2-1647). COMMONWEALTH ENERGY SYSTEM 10.2.6.6 1986 Consolidating Supplement to CG Service Contract and NBGEL Service Contract by and between CG and HOPCO dated December 31, 1986 amending and consolidating the CG Service Contract and the NBGEL Service Contract both as amended December 1, 1976 and supplemented September 14, 1977 (Exhibit 2 to CG Form 10-Q (March 1988), File No. 2-1647). 10.2.7 Operating Agreement between Air Products and Chemicals, Inc., (APC) and HOPCO, dated as of September 1, 1971, as supplemented by Supplements No. 1, No. 2 and No. 3 dated as of July 1, 1974, August 1, 1975 and January 1, 1985, respectively, with respect to the operation and maintenance by APC of HOPCO's liquefied natural gas facilities located at Hopkinton, MA (Exhibit 11 to the CES 1984 Form 10-K, File No. 1-7316). 10.2.7.1 Engineering and Prime Contracting Agreement between APC and HOPCO for performance of engineering services and capital project construction at LNG facility in Hopkinton, MA (Exhibit 12 to the CES 1984 Form 10-K, File No. 1-7316). 10.2.8 Firm Storage Service Transportation Contract by and between TGP and CG providing for firm transportation of natural gas from CGT, dated December 15, 1985 (Exhibit 1 to the CG 1985 Form 10-K, File No. 2- 1647). 10.2.9 Agency Agreement for Certain Transportation Arrangements by and between CG and Citizens Resources Corporation (CRC) whereby CRC arranges for a third party transportation of natural gas acquired by CG, dated April 14, 1986 (Exhibit 1 to the CG Form 10-Q (June 1986), File No. 2-1647). 10.2.9.1 Natural Gas Sales Agreement between CG and CRC, dated April 14, 1986 (Exhibit 2 to CG Form 10-Q (June 1986), File No. 2-1647). 10.2.10 Gas Sales Agreement by and between Enron Gas Marketing, Inc. and CG relating to the sale and purchase of natural gas on an interruptible basis, dated June 17, 1986 (Exhibit 3 to the CG Form 10-Q (June 1986), File No. 2-1647). 10.2.11 Agency Agreement for Certain Transportation Arrangements, dated June 18, 1985 and Gas Purchase and Sales Agreement dated August 6, 1985 by and between CG and Tenngasco Corporation and other related entities (Exhibit 4 to the CG Form 10-Q (June 1986), File No. 2-1647). 10.2.12 Service Agreement dated December 14, 1985 and an amendment thereto dated May 15, 1986 by and between Texas Eastern Transmission Corporation (TET) and CG to receive, transport and deliver to points of delivery natural gas for the account of CG, dated December 14, 1985 (Exhibit 5 to the CG Form 10-Q (June 1986), File No. 2-1647). COMMONWEALTH ENERGY SYSTEM 10.2.13 Gas Transportation Agreement by and between TET and CG to receive, transport and deliver on an interruptible basis, certain quantities of natural gas for the account of CG, dated January 31, 1986 (Exhibit 6 to the CG Form 10-Q (June 1986), File No. 2-1647). 10.2.14 Service Agreement dated May 19, 1988, by and between TET and CG, whereby TET agrees to receive, transport and deliver natural gas to CG (Exhibit 1 to the CG Form 10-Q (September 1988), File No. 2- 1647). 10.2.15 Gas Sales Agreement by and between Texas Eastern Gas Trading Company and CG providing for the sale of certain quantities of natural gas to CG, dated May 15, 1986 (Exhibit 7 to the CG Form 10- Q (June 1986), File No. 2-1647). 10.2.16 Service Agreement applicable to Rate Schedule TS-3 between TET and CG for Firm natural gas service, dated April 16, 1987 (Exhibit 1 to the CG Form 10-Q (June 1987), File No. 2-1647). 10.2.17 Natural Gas Sales Agreement between Summit Pipeline and Producing Company and CG, dated April 16, 1987 (Exhibit 2 to the CG Form 10-Q (June 1987), File No. 2-1647). 10.2.18 Natural Gas Sales Agreement between Natural Gas Supply Company and CG, dated May 12, 1987 (Exhibit 3 to the CG Form 10-Q (June 1987), File No. 2-1647). 10.2.19 Natural Gas Sales Agreement between Stellar Gas Company and CG, dated April 15, 1988 (Exhibit 1 to the CG Form 10-Q (March 1988), File No. 2-1647). 10.2.20 Natural Gas Sales Agreement between Amalgamated Gas Pipeline Company and CG dated April 5, 1988 (Exhibit 1 to the CG Form 10-Q (June 1988), File No. 2-1647). 10.2.21 Natural Gas Sales Agreement between Gulf Ohio Pipeline Corporation and CG dated May 18, 1988 (Exhibit 2 to the CG Form 10-Q (June 1988), File No. 2-1647). 10.2.22 Natural Gas Sales Agreement between Phillips Petroleum Company and CG dated May 18, 1988 (Exhibit 3 to the CG Form 10-Q (June 1988), File No. 2-1647). 10.2.23 Natural Gas Sales Agreement between TXO Gas Marketing Corp. and CG dated April 25, 1988 (Exhibit 1 to the CG 1988 Form 10-K, File No. 2-1647). 10.2.24 Gas Transportation Agreement by and between AGT and CG to receive, transport and deliver certain quantities of natural gas on a firm basis for the account of CG dated December 1, 1988 (Exhibit 2 to the CG 1988 Form 10-K, File No. 2-1647). COMMONWEALTH ENERGY SYSTEM 10.2.25 Natural Gas Sales Agreement between Enermark Gas Gathering Corporation and CG dated January 6, 1989 (Exhibit 3 to the CG 1988 Form 10-K, File No. 2-1647). 10.2.26 Gas Sales Agreement between BP Gas Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated March 31, 1989 with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (March 1989), File No. 2-1647). 10.2.27 Gas Sales Agreement between Tejas Power Corporation (seller) and CG (purchaser) for the purchase of spot market gas, dated February 21, 1989 with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (March 1989), File No. 2-1647). 10.2.28 Gas Sales Agreement between Catamount Natural Gas, Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated April 5, 1988, with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (June 1989), File No. 2-1647). 10.2.29 Gas Sales Agreement between Transco Energy Marketing Company (seller) and CG (purchaser) for the purchase of spot market gas, dated March 1, 1989, with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (June 1989), File No. 2-1647). 10.2.30 Gas Sales Agreement between V.H.C. Gas Systems, L.P. (seller) and CG (purchaser) for the purchase of spot market gas, dated June 2, 1989, with a contract term of at least one year (Exhibit 3 to the CG Form 10-Q (June 1989), File No. 2-1647). 10.2.31 Gas Sales Agreement between End-Users Supply System (seller) and CG (purchaser) for the purchase of spot market gas, dated June 29, 1989, with a contract term of at least one year (Exhibit 1 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.32 Gas Sales Agreement between Entrade Corporation (seller) and CG (purchaser) for the purchase of spot market gas, dated August 14, 1989, with a contract term of at least one year (Exhibit 2 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.33 Gas Sales Agreement between Fina Oil and Chemical Company (seller) and CG (purchaser) for the purchase of spot market gas, dated July 10, 1989, with a contract term of at least one year (Exhibit 3 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.34 Gas Sales Agreement between Mobil Natural Gas Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated August 14, 1989, with a contract term of at least one year (Exhibit 4 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.35 Gas Storage Agreement between Steuben Gas Storage Company (Steuben) and CG (customer) for the storage and delivery of customer's natural gas to and from underground gas storage facilities, dated May 23, 1989, with a contract term of at least one year (Exhibit 4 to the CG Form 10-Q (June 1989), File No. 2-1647). COMMONWEALTH ENERGY SYSTEM 10.2.35.1 Amendment, dated August 28, 1989, to 10.2.35 dated May 23, 1989 (Exhibit 5 to the CG Form 10-Q (September 1989), File No. 2-1647). 10.2.36 Gas Sales Agreement between PSI, Inc. (seller) and CG (purchaser) for the purchase of spot market gas, dated September 25. 1989, with a term of at least one year (Exhibit 1 to the CG 1989 Form 10-K, File No. 2-1647). 10.2.37 Gas Sales Agreement between Hadson Gas Systems (seller) and CG (purchaser) for the purchase of firm gas, dated August 15, 1990, with a contract term of at least six years (Exhibit 1 to the CG Form 10-Q (September 1990), File No. 2-1647). 10.2.38 Gas Sales Agreement between Odeco Oil Company (seller) and CG (purchaser) for the purchase of firm gas, dated August 15, 1990, with a contract term of at least five years (Exhibit 2 to the CG Form 10-Q (September 1990), File No. 2-1647). 10.2.39 Operating Agreement between AGT, CG and Distrigas of Massachusetts Corporation in connection with the deliveries of regasified liquified natural gas into the Algonquin J-system, dated August 1, 1990 (Exhibit 3 to the CG Form 10-Q (September 1990), File No.2- 1647). 10.2.40 Gas Sales Agreement between TEX/CON Marketing Gas Company (seller) and CG (purchaser) for the purchase of firm gas, dated September 12, 1990, with a contract term of five years (Exhibit 3 to the CG 1990 Form 10-K, File No. 2-1647). 10.2.41 Transportation Agreement between AGT and CG to provide for firm transportation of natural gas on a daily basis, dated December 1, 1988 (Exhibit 3 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.42 Transportation Assignment Agreement between AGT and CG regarding Rate Schedule ATAP Agreement No. 9020016 which provides for the assignment, on an interruptible basis, of firm service rights on TET's system under Rate Schedule FT-1, dated January 3, 1990, for a term ending October 31, 1999 (Exhibit 4 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.43 Gas Sales Agreement between AFT and CG to reduce the volume of Rate Schedule F-1, dated October 15, 1990 (Exhibit 5 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.44 Transportation Agreement between AFT and CG for Rate Schedule AFT- 1, dated November 1, Agreement No. 90103, 1990 (Exhibit 6 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.45 Transportation Assignment Agreement between AFT and CG regarding Rate Schedule ATAP Agreement No. 90202, which provides for the assignment, on a firm basis, of firm service rights on TET's system under Rate Schedule FT-1 dated November 1, 1990 (Exhibit 7 to the CG 1991 Form 10-K, File No. 2-1647). COMMONWEALTH ENERGY SYSTEM 10.2.46 Gas Sales Agreement between TGP and CG under TGP's CD-6 Rate Schedules dated September 1, 1991 (Exhibit 8 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.47 Transportation Agreement between TGP and CG dated September 1, 1991 (Exhibit 9 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.48 Transportation Agreement between CNG and CG to provide for transportation of natural gas on a daily basis from Steuben Gas Storage Company to TGP (Exhibit 10 to the CG 1991 Form 10-K, File No. 2-1647). 10.2.49 Service Line Agreement by and between Commonwealth Gas Company (CG) and Milford Power Limited Partnership dated March 12, 1992 for a term ending January 1, 2013. (Exhibit 1 to the CG Form 10-Q (March 1992), File No. 2-1647. 10.3 Other agreements. 10.3.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 1 to CES Form 10-Q (September 1993), File No. 1-7316). 10.3.2 Employees Savings Plan of Commonwealth Energy System and Subsid- iary Companies as amended and restated January 1, 1993.(Exhibit 2 to CES Form 10-Q (September 1993), File No. 1-7316). 10.3.2.1 First Amendment to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies, as amended and restated as of January 1, 1993, effective October 1, 1994. (Exhibit 1 to CES Form S-8 (January 1995), File No. 1-7316). 10.3.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corporation, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731). 10.3.3.1 Thirteenth Amendment to 10.3.3 as amended September 1, 1981 (Refiled as Exhibit 3 to the System's 1991 Form 10-K, File No. 1-7316). 10.3.3.2 Fourteenth through Twentieth Amendments to 10.3.3 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the CES Form 10-Q (September 1985), File No. 1-7316). 10.3.3.3 Twenty-first Amendment to 10.3.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316). 10.3.3.4 Twenty-second Amendment to 10.3.3 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316). 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 (Exhibit 1 to the CES Form 10-Q (March 1988), File No. 1-7316). 10.3.3.8 Twenty-sixth Agreement to 10.3.3 as amended March 15, 1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.3.3.9 Twenty-seventh Agreement to 10.3.3 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316) 10.3.3.10 Twenty-eighth Agreement to 10.3.3 as amended September 15, 1992 (Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316) 10.3.3.11 Twenty-ninth Agreement to 10.3.3 as amended May 1, 1993 (Exhibit 2 to the CES Form 10-Q (September 1994), File No. 1-7316) 10.3.4 Fuel Supply, Facilities Lease and Operating Contract by and between, on the one side, ESCO (Massachusetts), Inc. and Energy Supply and Credit Corporation, and on the other side, CEC, dated as of February 1, 1985 (Exhibit 1 to the CEC 1984 Form 10-K, File No. 2-30057 10.3.4.1 Amendments Nos. 1 and 2 to 10.3.5 as amended July 1, 1986 and November 15, 1989, respectively (Exhibit 3 to the CEC 1989 Form 10- K, File No. 2-30057). 10.3.5 Assignment and Sublease Agreement and Canal's Consent of Assignment thereto whereby ESCO-Mass assigns its rights and obligations under Part II of the Resupply Agreement dated February 1, 1985 to ESCO Terminals Inc., dated June 4, 1985 (Exhibit 4 to CEC Form 10-Q (June 1985), File No. 2-30057). 10.3.6 Oil Supply Contract by and between CEC (buyer) and Coastal Oil New England, Inc. (seller) for a portion of CEC's requirements of No. 6 residual fuel oil, dated July 1, 1991 (Exhibit 3 to CEC Form 10-Q (June 1991), File No. 2-30057). 10.3.6.1 Assignment Agreement between CEC and ESCO (Massachusetts), Inc. (ESCO-Mass) and Energy Supply and Credit Corporation whereby CEC assigns to ESCO-Mass rights and obligations under 10.3.7 (above) dated July 1, 1991 (Exhibit 4 to CEC Form 10-Q (June 1991), File No. 2-30057). 10.3.7 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as initial lender) covering the unconditional guarantee of a portion of the payment obligations of Maine Yankee Atomic Power Company under a loan agreement and note initially between Maine Yankee and MYA Fuel Company (Exhibit 3 to the CEL Form 10-K for 1985, File No. 2-7909). COMMONWEALTH ENERGY SYSTEM 10.3.8 Stock Purchase Agreement by and among Texas Eastern Corporation (purchaser) and Eastern Gas and Fuel Associates, Commonwealth Energy System and Providence Energy Corporation (sellers) for the purchase and sale of ownership interests in Algonquin Energy, Inc., dated June 10, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 1-7316). Exhibit 21. Subsidiaries of the Registrant Incorporated by reference to Exhibit 2 (page 101) to the System's 1988 Annual Report on Form 10-K, File No. 1-7316. Exhibit 22. Published Report Regarding Matters Submitted to Vote of Security Holders. Filed herewith as Exhibit 1 is the Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information dated March 31, 1995. Exhibit 27. Financial Data Schedule Filed herewith as Exhibit 2 is the Financial Data Schedule for the twelve months ended December 31, 1994. (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended December 31, 1994. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Commonwealth Energy System: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements of Commonwealth Energy System appearing in Exhibit A to the proxy statement for the 1995 annual meeting of shareholders, incorporated by reference in this Form 10-K, and have issued our report thereon dated February 21, 1995. Our audits were made for the purpose of forming an opinion on those consolidated financial statements taken as a whole. The schedules listed in Part IV, Item 14 of this Form 10-K are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Arthur Andersen LLP Boston, Massachusetts February 21, 1995 SCHEDULE I COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1994 (Dollars in Thousands)
Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Other Distribution of Receivable Shares Investment Earnings (B) of Earnings Shares Investment (A) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 346 600 $ 43 674 $ 6 242 $ - $ 6 132 346 600 $ 43 784 $ 410 COM/Energy Steam Company 25 500 3 321 1 976 - 1 187 25 500 4 110 105 Canal Electric Company 1 523 200 94 552 14 158 - 10 662 1 523 200 98 048 9 350 Commonwealth Gas Company 2 857 000 107 004 13 568 - 14 571 2 857 000 106 001 2 935 Darvel Realty Trust 26 759 111 - - 26 870 - COM/Energy Freetown Realty 1 (18 832) (335) 25 000 - 1 5 833 360 COM/Energy Research Park Realty 1 1 045 296 - 455 1 886 - COM/Energy Cambridge Realty 1 74 (17) - - 1 57 - COM/Energy Acushnet Realty 1 558 66 - 100 1 524 - COM/Energy Services Company 3 250 337 49 - 49 3 250 337 - Commonwealth Electric Company 2 043 972 163 329 16 073 - 15 841 2 043 972 163 561 200 Hopkinton LNG Corp. 5 000 4 019 548 - 674 5 000 3 893 - $399 840 $52 735 $25 000 $49 671 $427 904 $13 360 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52 454 $ 9 660 $ 1 242 $ - $ 1 084 52 454 $ 9 818 Hydro-Quebec Phase II 137 442 3 861 508 - 567 137 442 3 802 Other Investments - 28 - - - - 28 $ 13 549 $ 1 750 $ - $ 1 651 $ 13 648 NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. (B) Additional investment.
SCHEDULE I COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1993 (Dollars in Thousands)
Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Other Distribution of Receivable Shares Investment Earnings (B) of Earnings Shares Investment (A) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 346 600 $ 42 774 $ 3 101 $ - $ 2 201 346 600 $ 43 674 $ - COM/Energy Steam Company 25 500 3 113 1 703 - 1 495 25 500 3 321 830 Canal Electric Company 1 523 200 110 899 15 122 - 31 469 1 523 200 94 552 - Commonwealth Gas Company 2 407 000 88 157 16 299 18 000 15 452 2 857 000 107 004 355 Darvel Realty Trust 26 1 127 (368) - - 26 759 - COM/Energy Freetown Realty 1 (16 565) (2 267) - - 1 (18 832) 26 480 COM/Energy Research Park Realty 1 885 347 - 187 1 1 045 - COM/Energy Cambridge Realty 1 157 (8) - 75 1 74 - COM/Energy Acushnet Realty 1 560 69 - 71 1 558 - COM/Energy Services Company 3 250 337 49 - 49 3 250 337 - Commonwealth Electric Company 1 606 472 128 093 12 078 35 000 11 842 2 043 972 163 329 - Hopkinton LNG Corp. 5 000 4 931 548 - 1 460 5 000 4 019 190 $364 468 $46 673 $53 000 $64 301 $399 840 $27 855 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52 454 $ 9 690 $ 1 069 $ - $ 1 099 52 454 $ 9 660 Hydro-Quebec Phase II 137 442 4 170 573 - 882 137 442 3 861 Other Investments - 28 - - - - 28 $ 13 888 $ 1 642 $ - $ 1 981 $ 13 549 NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. (B) Additional investment.
SCHEDULE I COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31, 1992 (Dollars in Thousands)
Balance at Balance at Beginning of Year Additions Deductions End of Year Number Equity Number Notes of in Other Distribution of Receivable Shares Investment Earnings (B) of Earnings Shares Investment (A) SUBSIDIARIES CONSOLIDATED: (All issues are common stock) Cambridge Electric Light Company 304 600 $ 37 945 $ 64 $5 250 $ 485 346 600 $ 42 774 $ - COM/Energy Steam Company 25 500 3 106 1 272 - 1 265 25 500 3 113 - Canal Electric Company 1 523 200 109 069 19 347 - 17 517 1 523 200 110 899 2 840 Commonwealth Gas Company 2 407 000 82 930 14 855 - 9 628 2 407 000 88 157 5 780 Darvel Realty Trust 26 1 557 45 - 475 26 1 127 - COM/Energy Freetown Realty 1 (15 317) (1 248) - - 1 (16 565) 25 262 COM/Energy Research Park Realty 1 1 240 380 - 735 1 885 - COM/Energy Cambridge Realty 1 82 75 - - 1 157 - COM/Energy Acushnet Realty 1 558 72 - 70 1 560 - COM/Energy Services Company 3 250 337 49 - 49 3 250 337 - Commonwealth Electric Company 1 606 472 127 362 9 004 - 8 273 1 606 472 128 093 8 445 Hopkinton LNG Corp. 5 000 4 295 1 322 - 686 5 000 4 931 70 $353 164 $45 237 $5 250 $39 183 $364 468 $42 397 OTHER INVESTMENTS: (Accounted for by the equity method) Nuclear Electric Power Companies 52 454 $ 9 629 $ 1 397 $ - $ 1 336 52 454 $ 9 690 Hydro-Quebec Phase II 137 442 4 372 619 - 821 137 442 4 170 Other Investments - 28 - - - - 28 $ 14 029 $ 2 016 $ - $ 2 157 $ 13 888 NOTES: (A) Notes are written for 11 months and 29 days. Interest is at the prime rate and is adjusted for changes in the rate during the term of the notes. (B) Additional investment.
SCHEDULE II COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (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, 1994 Allowance for Doubtful Accounts $7 761 $ 9 396 $2 138 $11 339 $7 956 Year Ended December 31, 1993 Allowance for Doubtful Accounts $6 861 $ 9 468 $2 142 $10 710 $7 761 Year Ended December 31, 1992 Allowance for Doubtful Accounts $5 233 $12 082 $1 918 $12 372 $6 861 COMMONWEALTH ENERGY SYSTEM FORM 10-K DECEMBER 31, 1994 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. COMMONWEALTH ENERGY SYSTEM (Registrant) By: WILLIAM G. POIST William G. Poist, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. Principal Executive Officer: WILLIAM G. POIST March 23, 1995 William G. Poist, President and Chief Executive Officer Principal Financial Officer: JAMES D. RAPPOLI March 23, 1995 James D. Rappoli, Financial Vice President and Treasurer Principal Accounting Officer: JOHN A. WHALEN March 23, 1995 John A. Whalen, Comptroller A majority of the Board of Trustees: SINCLAIR WEEKS, JR. March 23, 1995 Sinclair Weeks, Jr., Chairman of the Board SHELDON A. BUCKLER March 23, 1995 Sheldon A. Buckler, Trustee PETER H. CRESSY March 23, 1995 Peter H. Cressy, Trustee HENRY DORMITZER March 23, 1995 Henry Dormitzer, Trustee COMMONWEALTH ENERGY SYSTEM FORM 10-K DECEMBER 31, 1994 SIGNATURES (Continued) B. L. FRANCIS March 23, 1995 Betty L. Francis, Trustee FRANKLIN M. HUNDLEY March 23, 1995 Franklin M. Hundley, Trustee WILLIAM J. O'BRIEN, March 23, 1995 William J. O'Brien, Trustee WILLIAM G. POIST March 23, 1995 William G. Poist, Trustee March , 1995 Gerald L. Wilson, Trustee CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in this Form 10-K of our report dated February 21, 1995 included in Exhibit A to the proxy statement for the 1995 annual meeting of shareholders and the incorporation of our reports included and incorporated by reference 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, 1994 or performed any audit procedures subsequent to the date of our report. ARTHUR ANDERSEN LLP Arthur Andersen LLP Boston, Massachusetts March 30, 1995 EX-22 2 1995 PROXY AND 1994 FINANCIAL INFORMATION EXHIBIT 1 Commonwealth Energy System Notice of 1995 Annual Meeting, Proxy Statement and 1994 Financial Information Please sign and return your proxy promptly COMMONWEALTH ENERGY SYSTEM Cambridge, Massachusetts Notice of Annual Meeting of Shareholders May 4, 1995 To the Shareholders of COMMONWEALTH ENERGY SYSTEM Notice is hereby given that the Annual Meeting of Shareholders of Commonwealth Energy System will be held at the office of the System, One Main Street, P.O. Box 9150, Cambridge, Massachusetts 02142-9150, on Thursday, May 4, 1995, at 10:30 o'clock A.M., Eastern Daylight Time, for the following purposes: 1. To elect three Trustees to hold office for a three-year term and until the election and qualification of their respective successors. 2. To take action on a proposal by the Board of Trustees to amend Section 6 of the System's Declaration of Trust, as amended, to revise the geographic residency requirement for Trustees. 3. To consider and vote upon a shareholder proposal, if presented at the meeting, as described herein. 4. To transact such other business as may properly come before the meeting or any adjournment or adjournments thereof. Common Shareholders of record at the close of business on March 17, 1995 are entitled to notice of, and to vote at, the meeting. By order of the Trustees, MICHAEL P. SULLIVAN Michael P. Sullivan Vice President, Secretary and General Counsel March 31, 1995 IMPORTANT We cordially invite you to attend the Annual Meeting of Shareholders, but IF YOU DO NOT EXPECT TO BE PRESENT, PLEASE MAIL YOUR PROXY IN ORDER THAT THE PRESENCE OF A QUORUM MAY BE ASSURED. Because our shares are widely distributed over a large number of holders, it is both necessary and desirable that all Shareholders send in their proxies. Failure to secure a quorum on the date set would necessitate an adjournment, which would cause the System considerable and needless expense. To avoid this, please SIGN AND DATE the accompanying proxy and mail it promptly in the enclosed envelope to Commonwealth Energy System, P.O. Box 9150, Cambridge, Massachusetts 02142- 9150. PROXY STATEMENT This statement is furnished in connection with the solicitation of proxies by the Board of Trustees of Commonwealth Energy System (hereinafter called the "System") to be used at the Annual Meeting of Shareholders of the System, to be held on Thursday, May 4, 1995, at the principal executive office of the System, One Main Street, P.O. Box 9150, Cambridge, Massachusetts 02142- 9150, of which due notice has been given in accordance with the System's Declaration of Trust dated December 31, 1926, as amended. If the enclosed form of proxy is executed and returned, it may nevertheless be revoked at any time insofar as it has not been exercised. A properly executed and returned proxy will be voted in accordance with the directions contained thereon. Abstentions shall be voted neither "for" nor "against," but shall be counted in the determination of a quorum. Broker non-votes will not be counted either in calculating the number of shares present for the purpose of determination of a quorum or for the purpose of determining whether a matter has received the required number of votes. The giving of a later-dated proxy revokes all proxies previously given. The approximate date on which this Proxy Statement and the accompanying proxy card will first be mailed to Shareholders is March 31, 1995. FINANCIAL STATEMENTS The audited financial statements of Commonwealth Energy System and Subsidiary Companies, which include comparative Balance Sheets as of December 31, 1994 and 1993, Statements of Income and Statements of Cash Flows for the three years ended December 31, 1994 and the Report of Independent Public Accountants, are included in Exhibit A of this Proxy Statement. VOTING SECURITIES Each Common Share is entitled to one vote. Only Shareholders of record at the close of business on March 17, 1995 are qualified to vote at the meeting. There were outstanding as of the record date 10,585,909 Common Shares. The Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies owned beneficially 1,711,590 Common Shares representing 16.2% of the outstanding Common Shares as of February 1, 1995. Members of the Plan are entitled to give voting instructions with respect to their interests. OWNERSHIP BY MANAGEMENT OF VOTING SECURITIES The following table shows the beneficial ownership, reported to the System as of February 1, 1995 of Common Shares of the System owned by the Chief Executive Officer and the four other most highly compensated Executive Officers and, as a group, all Trustees and Executive Officers of the System. Total Common Percent of Name Shares (1) Class William G. Poist 5,309 0.1% Russell D. Wright 4,153 0.1% Kenneth M. Margossian 3,025 0.1% James D. Rappoli 1,167 0.1% Leonard R. Devanna 1,636 0.1% All Trustees and Executive Officers as a group (14 persons) 25,642 0.2% (1) Beneficial ownership set forth in this Proxy Statement includes, where applicable, shares with respect to which voting or investment power is attributed to an Executive Officer or Trustee because of joint or 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. MATTERS TO BE BROUGHT BEFORE THE MEETING 1-ELECTION OF TRUSTEES 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: Sheldon A. Buckler Betty L. Francis Michael C. Ruettgers Of the three nominees, Dr. Buckler and Ms. Francis are presently Trustees. Mr. Ruettgers was nominated by the Board on February 23, 1995 to fill a vacancy which will be occasioned by the retirement of Mr. Sinclair Weeks, who is retiring from the Board at the conclusion of his term effective May 4, 1995. Although it is not contemplated that any of the three (3) nominees will be unable to serve, in the event a vacancy in the list of the System's nominees is occasioned by death or other unexpected occurrence, 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 February 1, Name, Principal Occupation and Term of Office Trustee Age 1995 (B) SHELDON A. BUCKLER, formerly Vice Chairman (C) of the Board and Director, Polaroid (E) Corporation, Cambridge, Massachusetts (Manufacturer of photographic equipment and supplies); Director, Lord Corp.; Aseco Corp.; Nashua Corporation; Parlex Corp.; Spectrum Information Technologies, Inc.; and Speech Systems, Inc. TERM EXPIRES IN 1995 (NOMINEE).......... (1991) 63 1,069 (A) PETER H. CRESSY, Chancellor, University of Massachusetts Dartmouth, North Dartmouth, Massachusetts TERM EXPIRES IN 1996 ................... (1994) 53 100 INFORMATION CONCERNING NOMINEES AND TRUSTEES Common Shares Beneficially Year First Owned as of Became a February 1, Name, Principal Occupation and Term of Office Trustee Age 1995 (B) HENRY DORMITZER, formerly Executive Vice (D) President, Wyman-Gordon Company, Worcester, Massachusetts (Producer of forgings for aerospace and transportation industries) TERM EXPIRES IN 1997 ................... (1985) 60 700 (A) BETTY L. FRANCIS, Executive Vice President and Chief Financial Officer, BancBoston Mortgage Corporation, Jacksonville, Florida TERM EXPIRES IN 1995 (NOMINEE).......... (1991) 48 100 (C) FRANKLIN M. HUNDLEY, Member and a Managing (D) Director, Rich, May, Bilodeau & Flaherty, P.C., Boston, Massachusetts (Attorneys); Director, The Berkshire Gas Company TERM EXPIRES IN 1997 ................... (1985) 60 2,293 (A) WILLIAM J. O'BRIEN, President, William J. O'Brien, Inc., Southborough, Massachusetts (management consulting) TERM EXPIRES IN 1996................... (1994) 62 1,100 WILLIAM G. POIST, President and Chief Executive Officer of Commonwealth Energy System and Chairman, Chief Executive Officer and a Director of its principal subsidiary companies TERM EXPIRES IN 1996 .................. (1992) 61 5,309 MICHAEL C. RUETTGERS, President, Chief Executive Officer and Director, EMC Corporation, Hopkinton, Massachusetts (data storage technology); Director, Keane, Inc. and Cross Comm Corporation (NOMINEE).............................. - 52 - (B) GERALD L. WILSON, Vannevar Bush Professor of (D) Engineering, Massachusetts Institute of (E) Technology, Cambridge, Massachusetts; Director, Analogic Corp. TERM EXPIRES IN 1997 ................... (1985) 55 464 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 except for Ms. Francis, who served in various executive capacities at the Boston Five Cents Savings Bank from 1986 to 1990; Dr. Wilson, who served as Vice President-Corporate Technology and Manufacturing at Carrier Corporation during 1991-1992 while on a leave of absence from Massachusetts Institute of Technology; and Mr. O'Brien, who served as President and Chief Executive Officer of The Hanover Insurance Company from 1979 to 1992. During 1994, fees of $669,427 were incurred for legal services rendered by the firm of Rich, May, Bilodeau & Flaherty, P.C., of which Mr. Hundley is a Member and a Managing Director. The firm has been employed in the last fiscal year and the current fiscal year. Each Trustee, including nominees, owned beneficially less than one-third of one percent of 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. COMPENSATION OF EXECUTIVE OFFICERS DURING THE YEAR 1994 The following table shows compensation paid by the System and its subsidiaries to the System's President and Chief Executive Officer and the four other highest paid Executive Officers of the System whose total compensation in 1994 exceeded $100,000. SUMMARY COMPENSATION TABLE
Long-Term Compensation (3) Annual Compensation Awards Payouts Long- Options Term Other /Stock Incen- All Annual Restr- Apprec- tive Other Compen- icted iation Plan Compen- Name and Salary sation Stock Rights (LTIP) sation Principal Position Year (1) Bonus (2) Awards (SARS) Payouts (4) William G. Poist 1994 $320,000 $98,721 - - - - $12,804 President and Chief 1993 291,888 78,031 - - - - 11,604 Executive Officer of 1992 270,000 65,121 - - - - 10,800 the System and Chair- man and Chief Exec- utive Officer of its principal subsidiary companies Russell D. Wright 1994 $215,897 $60,964 - - - - $ 8,400 President and Chief 1993 195,000 53,814 - - - - 7,704 Operating Officer 1992 167,140 40,665 - - - - 6,884 of Cambridge Electric Light Company, Canal Electric Company, COM/Energy Steam Company and Commonwealth Electric Company Kenneth M. Margossian 1994 $179,917 $52,005 - - - - $ 7,140 President and 1993 165,000 47,256 - - - - 6,564 Chief Operating 1992 153,833 38,733 - - - - 6,120 Officer of Common- wealth Gas Company and Hopkinton LNG Corp.
SUMMARY COMPENSATION TABLE (CONT'D)
Long-Term Compensation (3) Annual Compensation Awards Payouts Long- Options Term Other /Stock Incen- All Annual Restr- Apprec- tive Other Compen- icted iation Plan Compen- Name and Salary sation Stock Rights (LTIP) sation Principal Position Year (1) Bonus (2) Awards (SARS) Payouts (4) James D. Rappoli 1994 $151,686 $43,196 - - - - $ 5,880 Financial Vice 1993 130,333 36,184 - - - - 5,082 President and 1992 93,917 21,931 - - - - 3,732 Treasurer of the System and its subsidiary companies Leonard R. Devanna 1994 $142,166 $41,745 - - - - $ 5,912 Vice President-New 1993 133,333 37,542 - - - - 6,603 Business Development 1992 124,167 29,939 - - - - 4,899 of COM/Energy Services Company
-------------------- (1) The amounts in this column represent the aggregate total of cash compensation received and compensation deferred by the above-named individuals. Compensation is deferred pursuant to the provisions of the Employees Savings Plan and the Executive Salary Continuation and Excess Benefit Plan of Commonwealth Energy System and Subsidiary Companies. (2) The dollar value of perquisites and other personal benefits, securities or property totalling either $50,000 or 10% of total annual salary and bonus, together with various other earnings, amounts reimbursed for the payment of taxes, and the dollar value of any stock discounts not generally available are required to be disclosed in this column. In 1994, there were no such perquisites, earnings, reimbursements or discounts paid or made. (3) In 1994, the System did not provide to its employees, including Executive Officers, any payments or awards in the form of restricted stock, stock options, stock appreciation rights, long-term incentive plan payouts or other forms of long-term compensation. (4) The amounts in this column represent the aggregate contributions by the System and certain subsidiary companies during 1994 on behalf of the above-named individuals to the Employees Savings Plan and the Executive Salary Continuation and Excess Benefit Plan of Commonwealth Energy System and Subsidiary Companies. The Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies is a defined contribution plan. The Plan incorporates salary deferral provisions pursuant to Section 401(k) of the Internal Revenue Code for all employees who have elected to participate on that basis. The Executive Salary Continuation and Excess Benefit Plan of Commonwealth Energy System and Subsidiary Companies is a defined contribution/defined benefit plan. Unlike the Employees Savings Plan, this Plan is not a qualified plan under Section 401(a) of the Internal Revenue Code of 1986. The Plan was established to provide an additional benefit to any participant in the Employees Savings Plan whose benefit under the plan would be curtailed by limits in effect under the Internal Revenue Code for qualified plans. Of the amounts set forth in the "All Other Compensation" column, $6,162, $8,400, $4,622, $2,311 and $2,887 represent the contributions made on behalf of Messrs. Poist, Wright, Margossian, Rappoli and Devanna, respectively, by the Employees Savings Plan. Contributions made on behalf of Messrs. Poist, Wright, Margossian, Rappoli and Devanna by the Executive Salary Continuation and Excess Benefit Plan in 1994 equalled $6,642, $0, $2,518, $3,569 and $4,139, respectively. PENSION PLAN TABLE 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 of Commonwealth Energy System and Subsidiary Companies, as of December 31, 1994.
Highest Annual Consecutive 3-Year Average Base Salary of Last Annual Benefit for Years of Service (1) 10 Years 10 Years 15 Years 20 Years 25 Years 30 Years 35 Years $ 90,000 .... $15,818 $23,728 $ 31,637 $ 39,546 $ 47,455 $ 51,614 120,000 .... 21,318 31,978 42,637 53,296 64,955 69,614 150,000 .... 26,818 40,228 53,637 67,046 80,455 87,614 180,000 .... 32,318 48,478 64,637 80,796 96,955 105,614 210,000 .... 37,818 56,728 75,637 94,546 113,455 123,614 240,000 .... 43,318 64,978 86,637 108,296 129,955 141,614 270,000 .... 48,818 73,228 97,637 122,046 146,455 159,614 300,000 .... 54,318 81,478 108,637 135,796 162,955 177,614 330,000 .... 59,818 89,728 119,637 149,546 179,455 195,614 360,000 .... 65,318 97,978 130,637 163,296 195,955 213,614 ------------- (1) Federal law places certain limits on the amount of benefits which can be paid from qualified pension plans. Payments made by the System in excess of the applicable limitations are made pursuant to the terms of the Executive Salary Continuation and Excess Benefit Plan of Commonwealth Energy System and Subsidiary Companies. For 1994, the maximum annual compensation limit under the Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies was $150,000, and the maximum annual benefit under that Plan was $118,800.
The Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies 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 an integrated or non-integrated Plan formula to realize the maximum retirement benefit applicable to his or her employment history. Both of the Plan 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. Messrs. Poist, Wright, Margossian, Rappoli and Devanna have 30, 27, 25, 20 and 13 credited years of service respectively. For the purposes of calculating the annual retirement benefits of Messrs. Poist, Wright, Margossian, Rappoli and Devanna pursuant to the Plan, only the amounts set forth in the summary compensation table as "Salary" are utilized to determine each executive's three highest consecutive January 1 base salaries during the ten year period preceding the executive's retirement or termination. Each Executive Officer of the System 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 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 retirement benefits are in addition to the amounts shown in the table above and are not subject to limitation. If the employment of the Executive Officer shall terminate for any 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. COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION The Executive Compensation Committee of the Board of Trustees has furnished the following report on executive compensation for 1994: The Chief Executive Officer's base salary compensation is determined by review of comparable utility salary data and evaluation of certain reference criteria. The Executive Compensation Committee (the "Committee") reviews compensation comparisons prepared by an independent consultant for roles comparable in scope to the Chief Executive Officer's and other executives. In addition, the Committee reviews market compensation data provided by the System's human resources department, selected utility proxy material, 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 are 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's utility sample. The Chief Executive Officer's base salary target (i.e., control point) is designed to match the market median for the utility reference group. The Committee adjusts the Chief Executive Officer's salary in relation to the salary range target on a subjective basis through evaluation of the same objective criteria used to determine the Chief Executive Officer's annual incentive award and individual goals as set forth below. The Chief Executive Officer's award for 1994 pursuant to the System's Annual Incentive Plan, as hereinafter described, was determined on a weighted basis, with two-thirds of the award potential attributable to the attainment of System goals and objectives, and one-third of the award potential attributable to individual goals and objectives. For 1994, the System criteria forming the goals and objectives applicable to the Annual Incentive Plan were: 1) meeting pre-established targets comparing System actual net income to budgeted net income for 1994; 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 19 utility companies chosen by the System's compensation consultant. Each of the three System 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 System's 1994 net income of $48.97 million exceeded targeted net income of $41.20 million by 18.9%, resulting in a maximum award. The goal established for cost control was for operating and maintenance expenses in 1994 to be below the approved budgeted amounts. This goal was achieved by the System having reduced actual operation and maintenance expenses to 5.3% below established budgets, resulting in a maximum award for having exceeded the 5% below budget maximum target. The goal of maintaining operating and maintenance expenses per customer within the top 50% of the 19 company industry peer group was exceeded, as the System was rated the seventh most effective of the 19 companies in controlling operation and maintenance expenses. In the aggregate, the goals and objectives applicable to the System component of the Annual Incentive Plan were rated as 95.8% achieved. The individual goals of the Chief Executive Officer for 1994 under the Annual Incentive Plan included: developing a System business development plan, overseeing the formation of a key performance factor metering system, and improving electric operations' overall customer favorability as measured by customer surveys. The Chief Executive Officer's performance relative to achieving individual goals was rated as 90% achieved, resulting in an aggregate performance rating of 94% achievement. The System's Long Term Incentive Plan, approved by shareholders in 1994, measures performance and provides the potential for awards of Common Shares over a three-year Plan Period. The first year of the initial Plan Period established under that Plan was 1994, and as a result no award was made under the Plan for 1994. With respect to other Executive Officers, the Chief Executive Officer, in conjunction with the System's human resources staff, established salary ranges for each Executive Officer. The salary ranges were based in part upon salaries provided to executive officers in the System'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 Executive Officer's performance of goals and 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 under the Annual Incentive Plan to receive annual variable incentive compensation of up to a maximum of 30% of annual base salary. In 1994, the System goals and objectives constituting the annual performance criteria and the corresponding weightings which determined eligibility for awards to the named Executive Officers under 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 Plan participants included various financial and operating performance standards, such as management of outside legal services, the stabilization of electric customers' costs of purchased power, and the maintenance of individual department total annual expenses at amounts not exceeding approved budgets. THE EXECUTIVE COMPENSATION COMMITTEE Henry Dormitzer, Chairperson Sheldon A. Buckler Gerald L. Wilson COMPARATIVE TOTAL SHAREHOLDER RETURN Set forth below is a line graph comparing the cumulative total shareholder return for the System's Common Shares to the cumulative total return of the S&P 500 Stock Index and a Peer Group Index which is comprised of 93 utility companies (including the System) which are followed by Value Line, Inc. The entities which comprise the Peer Group are also set forth hereinafter. Comparative Five-Year Total Returns Commonwealth Energy System, S&P 500 and Value Line Peer Group (Performance results through 12/31/94) --------------------------------------------------------------- Line graph illustration of comparative five-year (1990-1994) cumulative total returns based on values listed in chart below. --------------------------------------------------------------- 1989 1990 1991 1992 1993 1994 COM/Energy $100.00 $ 94.55 $121.82 $142.53 $164.76 $139.27 S&P 500 100.00 96.83 126.41 136.26 150.00 151.73 Peer Group 100.00 101.47 131.43 140.92 156.53 137.46 Assumes $100 invested at the close of trading on the last trading day of 1989 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. Minnesota Power & Light Co. American Electric Power Co., Inc. Montana Power Co. Atlantic Energy Inc. Nevada Power Co. Baltimore Gas and Electric Company New England Electric System Boston Edison Company New York State Electric & Gas Corp. Carolina Power & Light Co. Niagara Mohawk Power Corporation Centerior Energy Corporation NIPSCO Industries Inc. Central Hudson Gas & Electric Corp. Northeast Utilities Central Louisiana Electric Company Inc. Northern States Power Co. Central Maine Power Co. Northwestern Public Service Co. Central & South West Corp. Ohio Edison Co. Central Vermont Public Service Corp. Oklahoma Gas & Electric Co. CILCORP Inc. Orange and Rockland Utilities, Inc. CINergy Corp. Otter Tail Power Co. CIPSCO Incorporated Pacific Gas & Electric Co. CMS Energy Corp. PacifiCorp. Commonwealth Energy System PECO Energy Company Consolidated Edison Co. of New York, Inc. Pennsylvania Power & Light Co. DPL Inc. Pinnacle West Capital Corp. Delmarva Power & Light Company Portland General Electric Co. The Detroit Edison Company Potomac Electric Power Co. Dominion Resources, Inc. Public Service Co. of Colorado DQE Public Service Co. of New Mexico Duke Power Co. Public Service Enterprise Group Inc. Eastern Utilities Associates Puget Sound Power & Light Co. El Paso Electric Rochester Gas and Electric Corp. Empire District Electric Company St. Joseph Light & Power Co. Entergy Corporation San Diego Gas & Electric Co. Florida Progress SCANA Corp. FPL Group, Inc. SCEcorp General Public Utilities Corp. Sierra Pacific Power Co. Green Mountain Power Corp. The Southern Company Hawaiian Electric Co., Inc. Southern Indiana Gas & Electric Co. Houston Industries Incorporated Southwestern Public Service Co. Idaho Power Co. TECO Energy, Inc. IES Industries Texas Utilities Company Illinova Corp. TNP Enterprises, Inc. Interstate Power Co. Tucson Electric Power Co. Iowa-Illinois Gas and Electric Company Unicom Corp. IPALCO Enterprises, Inc. Union Electric Co. Kansas City Power & Light Co. United Illuminating Co. KU Energy Corporation UtiliCorp. United Inc. LG&E Energy Corp. Washington Water Power Co. Long Island Lighting Co. Western Resources Inc. MDU Resources Wisconsin Energy Corp. Midwest Resources, Inc. Wisconsin Public Service Corp. WPL Holdings, Inc. MEETINGS OF THE BOARD OF TRUSTEES AND COMMITTEES The System's Board of Trustees held thirteen meetings throughout 1994. The Board has an Audit Committee, an Executive Compensation Committee, a Nominating Committee, a Benefit Review Committee and a Strategic Planning Committee. The Audit Committee is composed of Betty L. Francis, Chairperson, Peter H. Cressy and William J. O'Brien. The Committee held four meetings in 1994. The Committee's functions are: to recommend the selection of an independent public accountant; to review the scope of and approach to audit work; to review non-audit services provided by the independent public accountants; and to review accounting principles and practices and the adequacy of internal controls. The Executive Compensation Committee is composed of Henry Dormitzer, Chairperson, Sheldon A. Buckler and Gerald L. Wilson. During 1994 the Committee held four meetings. The Committee was formed for the purpose of reviewing and recommending compensation and promotional adjustments for certain of the System's personnel. The Nominating Committee is composed of Sinclair Weeks, Jr., Chairperson, Franklin M. Hundley and Sheldon A. Buckler. The Committee held two meetings in 1994. The functions of the Committee are: to coordinate suggestions or searches for potential nominees for the position of Trustee; to review and evaluate qualifications of potential nominees; and to recommend to the Board of Trustees nominees for vacancies occurring from time to time on the Board of Trustees. The Committee will consider nominees recommended by Shareholders upon the timely submission of the names of such nominees with their qualifications and biographical information forwarded to the Nominating Committee of the Board of Trustees. The Benefit Review Committee is composed of Franklin M. Hundley, Chairperson, Henry Dormitzer and Gerald L. Wilson. During 1994 the Committee held one meeting. The Committee was organized to consider and recommend to the Board of Trustees matters associated with the System's major funded benefit plans. Functions of the Committee include: recommending the composition of benefit plan boards and reviewing investment policy, objectives, performance or proposed changes related to the plans. The Strategic Planning Committee is composed of Gerald L. Wilson, Chairperson and Sheldon A. Buckler. The Committee held seven meetings during 1994. The functions of this Committee are: attendance at strategic planning sessions, support and insight to management and coordination and communication of management planning activities with the Board of Trustees. Each Trustee who was not an employee of the System is compensated for his or her services as Trustee at the rate of $10,000 per annum, plus $850 for each Trustee and Committee meeting attended. The Chairpersons of the Audit, Executive Compensation, Benefit Review and Strategic Planning Committees each receive an additional $1,000 during the year. In addition, the Chairman of the Board receives a retainer of $10,000 per year for his services as Chairman of the Board and of the Nominating Committee. The Retirement Plan for Trustees of Commonwealth Energy System was adopted to provide retirement benefits to non-management members of the Board of Trustees in recognition of their services to the System. Members of the Board of Trustees who have served as Trustees for at least five years are eligible to participate in the Plan. Each eligible Trustee qualifies for an annual retirement benefit payment equal to fifty percent of the annual retainer fee in effect at retirement (excluding retainers for chairing committees), plus 10% of the annual retainer fee for each year in addition to five years served, up to 100% of such fee. The annual retirement benefit payment is adjusted to reflect the first subsequent increase, if any, in the annual retainer fee for service on the Board following the Trustee's retirement. The annual retirement benefit payment becomes vested at the time of eligibility and is payable to Trustees for a period equal to the greater of ten years or the number of years of service as a Trustee. 2-AMENDMENT TO SECTION 6 OF THE DECLARATION OF TRUST There will be presented to shareholders by the Board of Trustees a proposal to consent to an amendment to Section 6 of the System's Declaration of Trust, which section contains the requirement that at least two-thirds of the Trustees be at all times residents of Massachusetts and that each of the remaining Trustees be a resident of one of the New England states. The purpose of the amendment is to remove the restriction which requires that each of the Trustees who are not Massachusetts residents be a resident of one of the New England states. The text of the proposed amendment to section 6 is set forth as follows: Section 6 of the System's Declaration of Trust would be amended by deleting from the second and third lines of the first paragraph of Section 6 the words "and each of the remaining Trustees shall at all times be a resident of one of the New England states" so that the first sentence of section 6 reads as follows: "At least two-thirds of the Trustees hereunder shall at all times be residents of Massachusetts". The Trustees believe that this amendment would be in the best interests of Shareholders, as it will enable the System to attract and retain qualified candidates for the position of Trustee throughout the System's geographic shareholder base, which includes all of the United States. At the same time, retention of the Massachusetts residency requirement for two-thirds of the Board reflects the fact that the System is predominantly an intra-state Massachusetts gas and electric utility company. The proposed amendment will also allow for the continued service on the Board by Ms. Francis, who has taken a position in the Jacksonville, Florida office of BancBoston Mortgage Corporation. The Board of Trustees believes that the restrictions relative to residency which were inserted into the Declaration of Trust over forty years ago no longer reflect the System's shareholder demographics, and that such restrictions both limit the selection and retention of Trustees and fail to provide for the mobility of today's workforce. At the same time, the provisions set forth in section 6 requiring two-thirds of the Trustees to be residents of Massachusetts will continue to ensure that the Board has a majority of members who are aware of the business climate within which the System operates so as to be able to provide valuable insight and advice in the management of the System's affairs. Upon the consent of the holders of the majority of the outstanding Common Shares present at the meeting and entitled to vote on the proposed amendment, the Trustees of the System will on May 4, 1995 vote to amend the Declaration of Trust and will file the amended Declaration of Trust, as required by the terms of the Declaration of Trust and the laws of the Commonwealth of Massachusetts. THE TRUSTEES RECOMMEND A VOTE "FOR" THE APPROVAL OF THE AMENDMENT. 3-SHAREHOLDER PROPOSAL The System has been advised that Mr. John Jennings Crapo, Porter Square Branch, P.O. Box 151, Cambridge, Massachusetts, 02140-0002, holder of 225 Common Shares, proposes to submit the following proposal at the 1995 Annual Meeting: RESOLVED: It is the judgment of the Shareholders of Commonwealth Energy System ("CES") that it is advisable to amend the CES Declaration of Trust, dated December 31, 1926, as amended, and that the Board of Trustees present to Shareholders at the next Annual Meeting of Shareholders an appropriate amendment to said Declaration of Trust to accomplish the following: Trustees elected at the annual meeting of Shareholders commencing with the 1997 Annual Meeting of Shareholders shall be elected to hold office until the next annual meeting and until their successors are elected and qualified. SUPPORTING STATEMENT: This is a reasonable proposal. It has been considered Annually at CES Shareholder Annual Meetings starting with 1991. It provides for the appropriate modification to the Declaration of Trust in 1996, the election of ALL Trustees ANNUALLY commencing in 1997, in a carefully thought out manner. This proposal at the May 05, 1994 Annual Meeting of Shareholders received as follows: 1,483,947 Common Shares or 14% were voted "For" the Proposal 5,917,813 Common Shares or 57% were voted "Against" the Proposal, and 3% "Abstained" from the Proposal. System Vice President, General Counsel, and Secretary, Mr. Michael P. Sullivan, Esquire, has advised Proponent that based on this vote and the applicable regulations Proponent may bring forth the Proposal again. A proposal to abolish the Classified Board of Directors of Tri-Continental Corporation, presented by this proponent May 19, 1994 at Chemical Bank, New York City, received the following votes as reported to Proponent: 48,067,020 shareholders representing 59.8% of the shares outstanding & eligible to vote balloted in person or by proxy ballot. 20.0% of the shares outstanding and 33.5% of the votes cast voted "For" Proponent's proposal. 35.9% of the shares outstanding and entitled to vote and 60.9% of the shareholder votes cast voted "Against" proponent's proposal. And, 3.9% of the shares outstanding and entitled to vote and 6.5% of votes cast votes "Abstained." Objections of TY were that a classified board: provides continuity, stability, and experience in leadership and in direction strategy...; ensures Board Members will be fully accountable to Stockholders because each year a portion of the Board must stand before Stockholders for election...; improves the ability of Board Members to more effectively represent the interests of all Stockholders. The reactions of CES Shareholders and other Shareholders points out the necessity for CES Shareholders to vote again on Board declassification. BOARD OF TRUSTEES RECOMMENDATION: The Board of Trustees recommends a vote AGAINST this proposal for the following reasons: This proposal has been submitted at each Annual Meeting since 1991. It requests that the Board of Trustees submit a proposal to Shareholders at the 1996 Annual Meeting, calling for the repeal of the classified Board, so that all Trustees would be elected on an annual basis. The classified board was adopted at the 1987 Annual Meeting, when Shareholders voted to amend the System's Declaration of Trust to create three classes of Trustees, with an equal number of Trustees in each class, and to provide that the Trustees would serve three-year staggered terms, such that three Trustees are eligible for election each year. The classified board is intended to help to ensure continued familiarity of Board members with the business, management and policies of the System, since a majority of the Trustees at any given time would have prior experience as Board members. These amendments are also designed to encourage persons seeking to acquire control of the System to initiate an acquisition through arms-length negotiations with the System's management and Board of Trustees, by making it more difficult to change the composition of the Board. Also, the amendments may allow the System's management to obtain more time and information for evaluating a takeover proposal, in order to fully protect the interests of the System and its Shareholders. The Board continues to believe that each Trustee is fully accountable to Shareholders throughout each term of office, whether that term is three years or one year. The Board further notes that the classified board system was determined to be of sufficient merit such that the Massachusetts legislature has codified that system, in its 1990 amendments to the laws pertaining to Massachusetts business corporations (however, the System, as a Massachusetts Trust, is not affected by this legislation). Repeal of the classified Board (which, if the present proposal is adopted, would actually be pursuant to the acceptance of a proposed Amendment to the Declaration of Trust to be offered at the 1996 Annual Meeting of Shareholders) requires the affirmative vote or written consent of three- quarters of the shares entitled to vote, in accordance with the terms of the System's Declaration of Trust. ACCORDINGLY, A VOTE "AGAINST" THE PROPOSAL IS RECOMMENDED. 4-OTHER BUSINESS The Board of Trustees of the System knows of no matters other than those set forth in the Notice of the Annual Meeting which are likely to be brought before the meeting. However, if any other matters of which the Board of Trustees is not aware are appropriately presented for action, it is the intention of the persons named in the proxy to vote in accordance with their judgment on such matters. MISCELLANEOUS The independent public accounting firm selected by the Trustees as Auditor of the System is Arthur Andersen LLP. It is expected that representatives of Arthur Andersen LLP will be present at the Annual Meeting with the opportunity to make a statement if they desire to do so and to respond to appropriate questions. The cost of soliciting proxies will be borne by the System. A limited number of regular employees may solicit proxies by telephone or in person subsequent to the initial solicitation by mail. In addition, the System has retained the firm of D. F. King to aid in such solicitation of proxies. The System expects to pay such firm a fee of $5,500 plus expenses. The System will reimburse banks, brokerage firms and other custodians, nominees and fiduciaries for reasonable expenses incurred in sending proxy material to security owners. The proxy card for a participant in the System's Dividend Reinvestment and Common Share Purchase Plan includes the number of shares which are registered in the participant's name and the number of shares beneficially owned by the participant that are held in the name of the nominee of the System for the Plan. A participant's vote with respect to the shares registered in the participant's name is also an instruction by the participant to the nominee to vote the shares credited to the participant's account under the Plan. In order for Shareholder proposals for the 1996 Annual Meeting of Shareholders to be eligible for inclusion in the System's Proxy Statement, they must be received by the System at its principal office in Cambridge, Massachusetts, prior to December 2, 1995. It is important that proxies be returned promptly to avoid unnecessary expense. Therefore, Shareholders are urged, regardless of the number of shares owned, to SIGN, DATE and RETURN the enclosed proxy promptly. MICHAEL P. SULLIVAN Michael P. Sullivan Vice President, Secretary and General Counsel Cambridge, Massachusetts 02142-9150 March 31, 1995 Commonwealth Energy System 1994 Financial Information Exhibit A CONTENTS PAGE REFERENCE PUBLISHED EDGAR Management's Discussion and Analysis of Financial Condition and Results of Operations........................... A-3 20 Management's Report............................................ A-15 35 Report of Independent Public Accountants....................... A-15 36 Consolidated Balance Sheets.................................... A-16 37 Consolidated Statements of Income.............................. A-18 39 Consolidated Statements of Cash Flows.......................... A-19 40 Consolidated Statements of Capitalization...................... A-20 41 Consolidated Statements of Changes in Common Shareholders' Investment and Consolidated Statements of Changes in Redeemable Preferred Shares.................................. A-21 42 Notes to Consolidated Financial Statements..................... A-22 43 Selected Financial Data........................................ A-36 58 COMMONWEALTH ENERGY SYSTEM MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations Earnings Earnings and earnings per common share by organizational element for the three-year period are summarized in the table below: 1994 1993 1992 Per Per Per Amount Share Amount Share Amount Share (Dollars in Thousands Except Per Share Amounts) Electric.......... $32,952 $3.16 $28,742 $2.82 $23,295 $2.31 Gas............... 12,346 1.19 15,746 1.54 13,253 1.32 Other............. 2,500 .24 116 .01 2,058 .20 Total........... $47,798 $4.59 $44,604 $4.37 $38,606 $3.83 Parent company earnings and dividends on preferred shares were allocated among the electric, gas and other operations of the system based on the Parent's equity investment in each segment. 1994 versus 1993 In 1994, earnings improved by 7.2% to the highest year-end level in the history of the System. Return on average common equity for 1994 was 13.7%, equaling the return for 1993, which was the highest since 1985. Significant factors that contributed to the improved earnings were: 1) cost savings of $2.7 million in direct payroll and the absence in 1994 of $3.7 million in severance pay attributable to a work force reduction implemented at our electric division and services company during the second quarter of 1993; 2) reduced undercollection of certain purchased power capacity costs that resulted in a positive earnings change of $2.9 million; 3) a full year of new base rates for Cambridge Electric Light Company that became effective in June 1993; 4) an increase of 1.4% in retail electric unit sales; and 5) lower short-term interest costs of $2.3 million reflecting a 38% decrease in the debt level to $44.9 million (the lowest year-end amount since 1986 and only 5.2% of total capitalization). The higher earnings in 1994 were achieved despite the decline in earnings from gas operations that reflected milder weather conditions in the fourth quarter when degree days were 14% below both normal and the fourth quarter of the prior year. For the year, firm gas sales decreased 1.7% but several record daily send-outs were achieved, including a new peak on January 19, 1994 of 364,799 MMBTU. 1993 versus 1992 Earnings improved in 1993 by 15.5% due, in part, to a significant reduction in other operation expense ($16.6 million or 7.4%) that reflected the system's cost containment efforts which included the shutdown of the Cannon Street generating station in late 1992 ($1.5 million) and the work force reduction that provided a net payroll savings of $1.6 million. The provision for bad debt expense declined by $2.7 million and resulted from improved collection experience. Other factors which contributed to the earnings increase were: 1) higher retail electric unit sales and firm gas sales during the heating season; 2) new base rates for Cambridge Electric; 3) the recognition of electric conservation and load management (C&LM) related lost base revenues ($2.4 million); and 4) the reversal of a reserve ($3.8 million) following the resolution of uncertainties related to the system's Seabrook investment. Electric Revenues and Unit Sales Electric operating revenues for the years 1994, 1993 and 1992 consisted of: 1994 1993 1992 Operating Revenues - In Thousands Retail....................... $525,326 $513,160 $483,151 Wholesale.................... 108,171 105,445 108,197 Other........................ 5,630 5,415 5,921 Total.................... $639,127 $624,020 $597,269 Unit sales (in Megawatthours or MWH) for the years 1994, 1993 and 1992 consisted of: % % 1994 Change 1993 Change 1992 Residential.......... 1,770,095 1.5 1,744,181 1.0 1,726,139 Commercial........... 2,049,949 2.1 2,008,213 2.9 1,951,228 Industrial and Other. 801,165 (0.3) 803,630 1.4 792,505 Total Retail......... 4,621,209 1.4 4,556,024 1.9 4,469,872 Wholesale............ 3,803,786 3.1 3,689,129 (5.4) 3,898,924 Total.............. 8,424,995 2.2 8,245,153 (1.5) 8,368,796 Customers served..... 357,000 1.4 352,000 1.1 348,000 In 1994, electric operating revenues increased $15.1 million (2.4%) due primarily to higher fuel and purchased power costs of $11 million (3.2%), the new base rates for Cambridge Electric that became effective June 1, 1993 and higher total unit sales of 2.2%. Another factor contributing to the increased level of revenues was a greater recovery of lost base revenues of approximate- ly $920,000. Partially offsetting these increases was a $1.5 million reduc- tion in C&LM program costs for electric operations which are being recovered through revenues. To the extent that costs associated with these programs increase or decrease from period to period, a corresponding change will occur in revenues. The recovery of lost base revenues is allowed by the Massachu- setts Department of Public Utilities (DPU) to encourage effective implementa- tion of C&LM programs. The rise in wholesale revenues of $2.7 million (2.6%) was due to a $9.3 million (12.8%) increase in sales to other utilities offset, in part, by a $5.9 million (21.7%) decline in sales to the New England Power Pool. Fluctuations in the level of wholesale electric sales have little, if any, impact on earnings. For 1994, retail electric unit sales gained 1.4% as a result of increased heating demand caused by the extremely cold weather conditions during the first quarter and greater usage, particularly air conditioning load, during the summer months. Unit sales reflect continued moderate growth of approximately 5,000 customers, mainly in the residential and commercial sectors, resulting from more housing units and an improved economy that produces added heating and air conditioning loads. Growth in unit sales is reduced somewhat by the system's conservation programs. The system expects that its retail unit sales growth will average 1% - 2% over the next five years. 1993 electric operating revenues increased $26.8 million (4.5%) due primarily to the net increase in fuel and purchased power costs of $35.8 million (11.4%), the base rate increase for Cambridge Electric, a 1.9% increase in retail unit sales and the recovery of approximately $2.4 million in C&LM lost base revenues. Partially offsetting these increases was a lower level ($9 million) of C&LM program costs. The decline in wholesale revenues of $2.8 million (2.5%) was due to a 5.9% drop in unit sales to non-associated utilities. Retail electric unit sales for 1993 increased by 1.9%, as each customer segment improved, offset somewhat by the impact of conservation programs. In particular, unit sales reflected a moderate increase in customers, primarily residential and commercial, a greater demand for power from seasonal custom- ers, reflecting an improved economy and to a lesser extent, more extreme weather conditions. Fuel and Purchased Power To satisfy demand requirements and provide required reserve capacity, the system supplements its generating capacity by purchasing power on a long- and short-term basis through entitlements pursuant to 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 DPU. The cost of fuel used for electric generation and purchased power per KWH sold was $.043, $.042 and $.037 for 1994, 1993 and 1992, respectively. These costs constitute 56% in both 1994 and 1993 and 52% in 1992 of electric operating revenues for the respective years and reflect the impact of the system's contractual obligations to purchase higher-cost power. These contracts, negotiated in the 1980s when the system's customer base grew dramatically and forecasts predicted continued growth, persisted to drive costs up as additional "must run" capacity came on line displacing lower cost units as the economy slowed. In 1994, the system took aggressive action to deal with the escalating energy costs by concluding the negotiation of a restructured power sales agreement, effective January 1, 1995, with an independent power producer (IPP) that defers purchases for a maximum of six years and requires the facility to provide power on a dispatchable basis at the discretion of Commonwealth Electric. Another purchased power contract was terminated through a buy-out arrangement effective January 27, 1995, pending final Federal Energy Regulatory Commission (FERC) approval. For further details, refer to the "Power Contract Negotiations" discussion that follows. In 1994, the average cost reflects the moderating impact of the deferral of $16 million of costs associated with Commonwealth Electric's rate stabilization mechanism that was implemented on April 1, 1994 and is further discussed in the "Rate Stabilization Plan" section to follow. The cost per KWH would have been $.045 in 1994 were this mechanism not in effect. For 1994 and 1993, fuel and purchased power costs increased $11 million (3.2%) and $35.8 million (11.4%), respectively, due to higher unit sales in both years and the contractual obligations discussed above prior to the restructuring of one contract and the termination of a second. In both years, there were additional power purchases from certain natural gas-fired IPP facilities and reduced generation from Canal Electric Company's units (for sales to non-associate utilities). Fuel and purchased power in 1994 and 1993 includes the increased cost of using cleaner burning but more expensive fuel oil (1% sulphur) at Canal Electric. In addition, 1993 expense includes $5.6 million for capacity- related costs associated with certain purchased power contracts that were not recovered in revenues due to the recovery mechanism established by the DPU. In 1994, this underrecovery was reduced to $800,000. This underrecovery reduced net income by $485,000 and $3.4 million in 1994 and 1993, respective- ly. (Refer to the "Cost Recovery" section of this discussion for more information.) Energy Mix The system's energy mix, including purchased power, is shown below: Actual 1994 1993 1992 Natural gas................. 38% 29% 21% Nuclear..................... 25 26 27 Oil......................... 24 31 41 Waste-to-energy............. 9 8 7 Hydro....................... 2 3 2 Coal........................ 2 3 2 Total..................... 100% 100% 100% The system's energy mix has shifted during the last several years from oil to natural gas and other fuels due to the requirement to purchase capacity from IPP facilities and, to a lesser extent, continued efforts to reduce its reliance on oil. There were no new sources of system generation or purchased power in 1994. In 1993, Commonwealth Electric began receiving power from: 1) an 11.1% entitlement in a 240 megawatt (MW) gas-fired cogeneration facility; 2) a 17.2% entitlement in a 160 MW gas-fired cogeneration facility; 3) additional energy from the expansion of a waste-to-energy plant; and 4) an extended commitment to April 1997 to exchange 50 MW of Canal Electric's oil- fired generation with 50 MW of pumped storage energy capacity from non- affiliate New England Power Company's Bear Swamp Units (an initial, smaller exchange of 25 MW began in 1992). In 1991, Canal Electric arranged for a long-term exchange of power with Central Vermont Public Service Company (CVPS) whereby 50 MW from Canal Electric's oil-fired Unit 2 was exchanged for 25 MW from CVPS's Vermont Yankee nuclear unit and 25 MW from its Merrimack Unit 2 coal-fired facility. This agreement expires in October 1995. In certain circumstances, it is possible to exchange capacity with another utility so that the mix of power improves the pricing for dispatch for both the seller and the purchaser. The Canal Electric/Bear Swamp transaction alone will save the system's customers $2.7 million over a four-year period that began in June 1993. In 1995, it is expected that these exchanges, combined with a reduction in the capacity from purchased power contracts with natural gas-fired IPPs, will necessitate increased purchases from the oil-fired Canal Electric units. In October 1993, the system reached an agreement (subject to regulatory approvals) with Montaup Electric Company (the 50% owner of Canal Unit 2) and Algonquin Gas Transmission Company to build a natural gas pipeline that will serve the Canal Unit 2 generating station. Unit 2 will be modified to burn gas as well as oil. (Refer to "Environmental Matters" section for more information.) Oil-fired generation has been significantly reduced from pre-1993 levels but still accounts for 24% of the system's total sources, with higher levels anticipated for 1995 and beyond. Average oil prices in 1994 at Canal Elec- tric's generating plant, a major supplier of electricity for the system, were $14.33 per barrel as compared to $14.02 and $12.95 per barrel in 1993 and 1992, respectively. In conformance with tighter restrictions on stack emissions, the Massachusetts Department of Environmental Protection (DEP) mandated a reduction in sulphur dioxide emissions requiring the periodic use of lower-sulphur (1%) content oil. In 1994, 1% oil averaged $14.92 per barrel, a 1.6% and 12.1% decrease from the $15.16 and $17.25 per barrel cost in 1993 and 1992, respectively. However, in 1994 and 1993 lower-sulphur oil displaced 70.4% and 57.5% of the higher-sulphur (2.2%) content oil as compared to 24% in 1992. In addition to power purchases, the system is actively pursuing the marketing of certain capacity at competitive terms and rates to utilities in and outside the New England region at a higher price (thus saving the system's customers the difference) than if it were to sell to the New England Power Pool. This situation is a result of several utilities in New England (the system included) having excess capacity and lowered prospects for sales growth. This competitive business developed for the system in the early 1990s when it began to formally request proposals to supply short-term energy and associated capacity to other utilities on the open market to fulfill their power requirements. Increased emphasis on the marketing of this capacity yielded approximate savings of $1,039,000, $429,000 and $451,000 in 1994, 1993 and 1992, respectively. Gas Revenues, Unit Sales and Cost of Gas Sold Gas operating revenues for the years 1994, 1993 and 1992 consisted of: 1994 1993 1992 Operating Revenues - In Thousands Firm............................ $296,027 $291,986 $283,792 Interruptible................... 5,864 5,367 6,389 Transportation.................. 2,563 1,566 1,087 Other........................... 19,114 3,725 3,606 Total........................ $323,568 $302,644 $294,874 Unit sales and transportation volume (in billions of British thermal units or BBTU) for the years 1994, 1993 and 1992 consisted of: % % 1994 Change 1993 Change 1992 Residential......... 21,515 (3.3) 22,252 (0.6) 22,392 Commercial.......... 10,728 (1.9) 10,931 0.2 10,913 Industrial and other 6,296 4.3 6,036 (7.2) 6,505 Total firm....... 38,539 (1.7) 39,219 (1.5) 39,810 Off-system.......... 6,401 - - - - Quasi-firm.......... 487 - - - - Interruptible....... 1,927 1.6 1,896 (23.1) 2,464 Total sales...... 47,354 15.2 41,115 (2.7) 42,274 Transportation...... 2,208 26.0 1,753 59.9 1,096 Total............. 49,562 15.6 42,868 (1.2) 43,370 Customers served.... 232,000 - 232,000 2.2 227,000 For 1994, gas operating revenues increased $20.9 million (6.9%) due primarily to an increase in the cost of gas sold of $20.4 million (13%), higher C&LM costs ($2.6 million) that are recovered through a Conservation Charge (CC) recovery mechanism which is part of the existing Cost of Gas Adjustment Clause (CGAC), an increase in transportation revenues ($997,000) and higher interruptible sales. To the extent that costs associated with C&LM programs increase or decrease from period to period, a corresponding change will occur in revenues. Included in other revenues for the first time were new off-system sales. The margin on these sales will be shared with one-half used to reduce the cost of gas to firm customers and the remainder deferred pending DPU approval of Commonwealth Gas Company's margin sharing proposal that is expected to be filed in 1995. Although the per unit cost of gas sold decreased slightly, the increase in the total cost of gas sold reflects a 15% increase in the volume of gas purchased due primarily to the off-system sales noted above (there were no sales of this type in 1993) and sales from a new "quasi-firm" service available to certain customers. Quasi-firm sales service is designed for larger customers and provides a combination of firm and interruptible service. In exchange for prices lower than full firm service, quasi-firm customers will receive interruptible service in peak demand months and firm service in off-peak months. Gas operating revenues for 1993 rose $7.8 million (2.6%) due primarily to increases in C&LM costs ($4.8 million), the cost of gas sold ($2.4 million) and an increase in transportation revenues ($479,000). Offsetting these increases were slightly lower unit sales. Firm sales gains from extreme cold weather experienced during the first quarter of 1994 (5.6%) were substantially offset by the decline in fourth quarter sales (15%) due to mild weather. During January 1994, on four different occasions, the system established all-time highs for daily send-out, setting a new peak on January 19 of 364,799 MMBTU. The previous all-time peak was 336,998 MMBTU set in January 1988. In 1993, firm gas sales declined by 1.5%, including a 7.2% decline in sales to industrial and other customers; however, firm sales during the heating season when seasonal rates are in effect increased by nearly 3%. Although interruptible sales decreased 23% during 1993, these sales have no impact on net income since all of the margin from these sales are flowed back to firm customers through the CGAC. The variations from year to year in weather conditions, particularly during the heating season, cause gas usage to fluctuate. The system expects that its firm unit sales growth will average 1% - 2% over the next five years. The total number of customers remained stable in 1994 but increased at a rate of 1.8% in 1993 due to new home construction and conversion activity. The fluctuation in interruptible sales during the three-year period reflects the competitive market conditions for energy resources and the conversion in 1994 of interruptible sales to quasi-firm. The cost of gas sold per MMBTU averaged $3.74, $3.81 and $3.65 in the years 1994, 1993 and 1992, respectively. The average per unit cost in 1994 and 1993 reflects the amortization of FERC Order No. 636 (Order 636) transition costs of $3.6 million and $396,000, respectively. Pursuant to a DPU order issued on October 29, 1993, transition charges related to Order 636 costs are reflected as a regulatory asset which Commonwealth Gas will recover, with carrying charges, over a four-year period that began in November 1993, as further discussed in the "Cost Recovery" section that follows. Other Operation and Maintenance In 1994, other operation was virtually unchanged due to the savings resulting from the second quarter 1993 work force reduction ($2.7 million), the absence of severance pay incurred in 1993 ($3.7 million) and a decline in the provision for bad debt expense due to improved collection experience ($600,000). The impact of these factors was offset by higher levels of insurance and employee benefit costs ($2.4 million), a $1 million increase in C&LM costs and the impact of inflation on the cost of labor, materials and other services. Other operation in 1993 decreased $16.6 million (7.4%) due to lower C&LM costs ($4.2 million), the absence in 1993 of costs associated with Common- wealth Electric's Cannon Street generating station ($1.5 million), which ceased operations in October 1992, and the net savings of $1.6 million ($5.3 million in payroll savings less $3.7 million in severance costs) associated with the second quarter work force reduction. Also contributing to the decrease in costs in 1993 was the provision for bad debt expense which declined $2.7 million (22.8%) due to improved collection experience, lower liability insurance costs of $1.7 million due to lower claims, lower Seabrook operating costs of $1.1 million and a decline in employee medical and life insurance costs of $800,000. Offsetting these decreases, in part, was an increase in pension costs of $1.5 million. Cambridge Electric, Commonwealth Electric and Commonwealth Gas have received approval from the DPU to recover certain costs associated with C&LM programs through the operation of a CC decimal. For the years ended December 31, 1994, 1993 and 1992, C&LM costs (including amortization of prior period amounts), which are included in other operation expense in the accompanying consolidated statements of income, were as follows: 1994 1993 1992 (Dollars in Thousands) Cambridge Electric............ $ 1,227 $ 2,905 $ 4,246 Commonwealth Electric......... 4,302 4,165 11,826 Commonwealth Gas.............. 7,685 5,094 286 Total...................... $13,214 $12,164 $16,358 Maintenance in 1994 declined $4.1 million (10%) due primarily to the timing of scheduled maintenance at the Canal Units. Maintenance in 1993 increased by $700,000 (1.9%) due primarily to a scheduled major inspection and overhaul of the Canal Unit 2 boiler, turbine and generator. The total number of full-time employees declined 13.6% to 2,169 in 1994 from 2,510 employees at year-end 1991. Management believes the work force level is adequate to service its customers. Depreciation, Amortization and Taxes Depreciation expense in 1994 increased $1.7 million (4%) due to slightly higher rates and higher levels of plant in service and the absence of an adjustment made in 1993 which lowered that year's expense by approximately $700,000 (1.6%) due to an adjustment to the accrual rate used by Canal Electric to reflect an extension of the depreciable life of Unit 1 from 1996 to 2002. The abandonment of the Cannon Street generating station also contributed to the decrease in 1993. Amortization increased by less than 2% in 1994, while the decline in this expense for 1993 of $1.7 million (21.9%) was due to the absence of amortization costs related to Commonwealth Gas' automated mapping system. Income tax expense increased $900,000 (3.2%) in 1994 due to a higher level of pretax income. In 1993, income tax expense rose $7.7 million (37.5%) due to the significantly higher level of pretax income and, to a lesser extent, an increase in the federal income tax rate to 35%, retroactive to January 1, 1993. Local property taxes increased $1.1 million (6.8%) in 1994 reflecting higher tax rates and assessments. The 2.7% increase in local property taxes in 1993 primarily reflects higher tax rates and assessments offset, in part, by an adjustment to the 1993 property tax accrual associated with revisions made to the nuclear station property tax assessed by the state of New Hampshire to the joint-owners of Seabrook 1. Payroll and other taxes in 1994 declined nearly $600,000 (6.8%) reflecting the lower number of employees in the current period. The 3.8% increase in payroll and other taxes in 1993 was due to an increase in unemployment tax rates. Other Income The substantial decrease in other income during 1994 was primarily due to the absence of a 1993 second quarter reversal of a reserve ($3.8 million pretax) related to Canal Electric's Seabrook 1 investment. The decision to eliminate this reserve was prompted by the inclusion of Seabrook 1 costs in base rates at the state level for Cambridge Electric. Another factor contributing to the decrease was a $2 million (pretax) charge related to a settlement negotiated with an outside party for certain costs associated with Commonwealth Electric's energy conservation program. The decline for 1994 was offset, somewhat, by accrued interest on Commonwealth Electric's fuel charge stabilization deferral ($674,000) and the equity component of allowance for funds used during construction (AFUDC) of $341,000. There was no equity AFUDC in 1993. The substantial increase in other income during 1993 reflects the reversal of the aforementioned reserve, offset, in part, by the absence in 1993 of equity AFUDC. Interest Charges For 1994, long-term interest charges increased $2 million (5.4%) due to a higher level of long-term debt reflecting a full year of new debt issued at various times in 1993 by Commonwealth Electric, Commonwealth Gas and Hopkinton LNG Corp. ($134 million). Interest on short-term borrowings declined by $2.3 million (33.5%) despite higher average interest rates (4.4% versus 3.5%) due to the significantly lower average level of borrowings ($23.9 million versus $103.1 million) resulting from a higher level of internally generated funds and the 1993 financing activity. Interest charges increased in 1993 by $2.5 million (6.1%) due to a lower level of AFUDC debt resulting from the Seabrook settlement noted previously and an increase in interest on long-term debt of $700,000 primarily due to the issuance of $65 million in new debt in the first quarter of 1993. Somewhat offsetting these increases was a $300,000 decline in other interest charges due to lower rates (3.5% versus 4%) and a lower average level of short-term borrowings ($103.1 million versus $126.3 million). Liquidity and Capital Resources Overview The System is the largest combination public utility holding company in New England with annual revenues approaching $1 billion and assets of approxi- mately $1.3 billion. Capital resources of the System and its subsidiaries are derived principally from retained earnings and equity funds provided through the System's Dividend Reinvestment and Common Share Purchase Plan (DRP). During 1994, nearly 34% of the System's shareholders participated in DRP. Supplemental interim funds are borrowed on a short-term basis and, when necessary, replaced with new equity and/or debt issues through permanent financing secured on an individual company basis. The System and its subsidi- aries have over the years, maintained adequate financial resources and access to the capital markets and further, do not anticipate a change in 1995 or beyond. The System purchases 100% of all subsidiary common stock issues and provides, to the extent possible, a portion of the subsidiaries' short-term financing needs. These combined resources provide the funds required for the subsidiary companies' construction programs, current operations, debt service and other capital requirements. In March 1994, the System's Board of Trustees voted to increase the quarterly dividend per common share from 73 cents to 75 cents (2.7%) based on the System's improving financial condition and to provide shareholders a fair and reasonable return. Through February 1995, the System has paid dividends without interruption or reduction since 1947 (191 consecutive quarters). Financial Condition For 1994, cash flows from operating activities amounted to approximately $126.6 million including net income of nearly $49 million and non-cash items such as depreciation ($44.2 million), amortization ($9.5 million) and deferred income taxes of $14.8 million. The change in working capital since December 31, 1993, exclusive of the changes in cash ($1.7 million) and interim financing ($27.1 million), amounted to $52.7 million and had a significant positive effect on cash flows from operating activities. The working capital change reflects lower levels of unbilled revenues ($10.1 million) and accounts receivable ($1.5 million) coupled with higher levels of accounts payable ($27.9 million), accrued taxes ($8.9 million) and other miscellaneous current assets and liabilities ($4.3 million). The change in other operating items of $41.8 million includes $16 million related to Commonwealth Electric's rate stabilization deferral, $8.5 million related to uncollected postretirement benefit costs, $2.6 million in uncollected Order 636 transition costs and $14.7 million in other deferred costs. Capital Requirements Construction expenditures for 1994 were $58.6 million, including AFUDC and nuclear fuel while sinking fund requirements and redemptions of long-term debt amounted to $16.4 million for a total capital requirement of $75 million, a decrease of $23.6 million from the 1993 level. These requirements for 1994 were funded entirely with internally generated funds. In addition, short-term borrowings were reduced by $27.1 million to $44.9 million, which for the most part, was funded with internal cash generated from higher retail electric unit sales and continued cost containment efforts. The system anticipates that future capital requirements, as shown below, will be met primarily through internally generated funds, supplemented by a combination of debt and equity financings. As conditions warrant, the system will refinance certain of its outstanding securities based on acceptable market conditions resulting in a lower cost of debt. The timing and amount of future debt and equity financings will be dictated by economic and financial market conditions and the needs of system subsidiaries. Capital requirements estimated for 1995 through 1999 are as follows: 1995 1996 1997 1998 1999 Total (Dollars in Millions) Construction expenditures including AFUDC.............. $ 88 $ 77 $ 62 $ 66 $ 64 $357 Long-term debt maturities....... 25 33 14 19 20 111 Mandatory sinking funds on long- term debt and preferred shares. 6 9 9 8 8 40 Total........................ $119 $119 $ 85 $ 93 $ 92 $508 Sources of Capital It is anticipated that approximately $371 million or 73% of the projected capital requirements shown above will be provided from internal sources, a portion of which is the collection of accounts receivable generated from the sale of electricity, gas and steam to retail and wholesale customers. Other cash sources include the sale of Common Shares through DRP, periodic short-term borrowings from banks, rental income and dividends from investments. Capital financings during the five-year forecast period are projected to be issued by subsidiary companies, including common stock issued exclusively to the System, as follows: 1996 1998 1999 Total (Dollars in Millions) Long-term debt...................... $ 62 $ 48 $ 41 $151 Common stock........................ 20 28 17 65 Total............................ $ 82 $ 76 $ 58 $216 The System could also raise capital through the issuance of additional series of preferred shares or additional Common Shares. However, there are no projected financings of this type anticipated at this time. Cash provided by subsidiary company operations continues to be the prim- ary source of funds. The proceeds from these sources were used to provide for the payment of dividends and meet capital requirements. The System believes its capital resources and liquidity are sufficient to meet its current and projected requirements. In 1994, the subsidiaries of the system provided $49.7 million to the Parent, and proceeds from DRP provided $9.4 million. In 1993, these amounts were $64.3 million and $7.1 million, respectively. System companies also maintain lines of credit with banks. At December 31, 1994, short-term notes payable to banks were $44.9 million, representing the lowest year-end level since 1986 and a decrease of $27.1 million (38%) from last year. Bank borrowings are used to temporarily fund construction projects and to repay the long-term debt of the System and its subsidiary companies ($10 million in 1994). Arrangements for bank lines of credit totaled $90 million in committed lines and $90 million in uncommitted lines at December 31, 1994, at which time approximately $135 million was available to the system. At December 31, 1999, the system's level of bank borrowings is projected to be approximately $1.8 million. Subsidiary companies also participate in the COM/Energy Money Pool (the Pool). This is an arrangement whereby subsidiary companies' short-term cash surpluses are used to help meet the short-term borrowing needs of the utility subsidiaries. In general, lenders to the Pool receive a higher rate of return than they otherwise would on such investments, while borrowers pay a lower interest rate than those available from banks. Capital Structure The system's objective is to maintain a capital structure that preserves an appropriate balance between debt and equity. All long-term debt, preferred shares and common equity issued by the system is ultimately used to repay short-term debt. The system's capitalization structure, including short-term debt, is presented below: Estimate 1993 1994 1999 (Dollars in Thousands) Long-term debt.... $458,893 51.9% $443,307 51.2% $447,052 46.8% Preferred shares.. 15,480 1.8 14,660 1.7 10,560 1.1 Common equity..... 337,070 38.2 362,997 41.9 495,796 51.9 Short-term debt... 71,975 8.1 44,850 5.2 1,806 0.2 Total capitalization $883,418 100.0% $865,814 100.0% $955,214 100.0% Rates and Regulatory Matters Certain System utility subsidiaries operate under the jurisdiction of the DPU, which regulates retail rates, accounting, issuance of securities and other matters. The DPU requires historic test-year information to support changes in rates. In addition, Canal Electric, Cambridge Electric and Commonwealth Electric file their respective wholesale rates with the FERC. Retail Rate Proceedings The most recent general rate proceedings approved by, or settled with, the DPU for the System's retail electric and gas subsidiaries were as follows: Return on Effective Common Total Date Requested Authorized Equity Return (Dollars in Millions) Cambridge Electric June 1, 1993 $10.2 $ 7.2 11% 9.95% Commonwealth Electric November 1, 1991 27.7 22.8 13% 11.22% Commonwealth Gas July 1, 1991 17.3 10.9 12% 10.49% Cost Recovery Fuel and Purchased Power Commonwealth Electric and Cambridge Electric file Fuel Charge (FC) rate schedules, subject to DPU regulation, under which they are allowed current recovery from retail customers of costs of fuel used in electric generation and a substantial portion of purchased power, demand and transmission costs. Cambridge Electric and Commonwealth Electric collect a portion of their capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The recovery mechanism for these costs uses a per kilowatthour (KWH) factor that is calculated using historical (test- period) capacity costs and unit sales. This factor is then applied to current monthly KWH sales. When current period capacity costs and/or unit sales vary from test-period levels, Cambridge Electric and Commonwealth Electric experience a revenue excess or shortfall which can have a significant impact on net income. All other capacity and energy-related purchased power costs are recovered dollar-for-dollar through the FC. Cambridge Electric and Commonwealth Electric made a filing in late 1992 with the DPU seeking an alternative method of recovery. This request was denied in a letter order issued on October 6, 1993. However, the companies were encouraged by the DPU's acknowledgement that the issues presented warranted further considera- tion. The DPU encouraged each company to continue to work with other interested parties, including the Attorney General of Massachusetts, to reach a consensus solution on the issue for future consideration. The companies have been involved in discussions with interested parties in an effort to resolve this issue in a positive fashion and hope to reach an agreement in the near future. Cost of Gas Sold Commonwealth Gas has a standard seasonal Cost of Gas Adjustment Clause which provides for the recovery, from firm customers, of purchased gas costs not recovered through base rates. These adjustment charges, which require DPU approval, are estimated semi-annually and include credits for gas pipeline refunds and profit margins applicable to interruptible and other non-firm sales. Actual gas costs are reconciled annually as of October 31, and any difference is included as an adjustment in the following year. C&LM Programs The system has implemented a variety of cost-effective C&LM programs for its gas and electric customers which are designed to reduce future energy use. On June 30, 1993, the DPU issued an order in Phase I of a C&LM cost recovery filing made by Cambridge Electric and Commonwealth Electric which allows the recovery of "lost base revenues" from electric customers. The recovery of lost base revenues is employed by the DPU to encourage effective implementa- tion of C&LM programs. The KWH savings that are realized as a result of the successful implementation of C&LM programs serve as the basis for determining lost base revenues. Commonwealth Electric and Cambridge Electric recovered approximately $3.6 million based on estimated KWH savings for the eighteen- month period that began January 1, 1993. Customer collections began July 1, 1993 over a twelve-month period. On June 30, 1994, the DPU issued an order that further allows the companies to recover approximately $3.8 million in additional lost base revenues for a one-year period that commenced July 1, 1994. Through December 31, 1994, the combined recovery was approximately $5.7 million, $2.4 million of which was collected in 1993. Commonwealth Gas offers conservation measures and energy savings to its residential and multi-family customers through programs approved by the DPU in June 1992 and is recovering costs via separately stated CC decimals approved in that year. On November 23, 1994, the DPU approved a settlement agreement extending Commonwealth Gas' existing demand-side management (DSM) programs until October 31, 1995 and allowing the recovery of "lost margins" from its customers that commenced in January 1995. Specifically, the settlement allows Commonwealth Gas to recover through the CC decimal the portion of the lost margins related solely to savings resulting from installations during the twelve-month period which began in November 1994. In addition, the lost margins related to savings occurring from prior period installations will be held in an interest-bearing account pending the completion of a DSM impact evaluation proceeding currently before the DPU. FERC Order No. 636 In April 1992, the FERC issued Order No. 636 (Order 636), which became effective on November 1, 1993. The order requires interstate pipelines to unbundle existing gas sales contracts into separate components (gas sales, transportation and storage services). Order 636 requires pipelines to provide transportation services that allow customers to receive the same level and quality of service they had with the previous bundled contracts. Prior to the implementation of Order 636, Commonwealth Gas purchased the majority of its gas supplies from either Tennessee Gas Pipeline Company or Algonquin Gas Transmission Company, supplemented with third-party firm gas purchases, storage services, and firm transportation from various pipelines. Presently, Commonwealth Gas purchases only transportation, storage and balancing services from these pipelines (and other upstream pipelines that bring gas from the supply wells to the final transporting pipelines) and purchases all of its gas supplies from third-party vendors, utilizing firm contracts with terms ranging from less than one year to three or more years. The vendors vary from small independent marketers to major gas and oil companies. (Refer to Note 2(g) of the accompanying Notes to Consolidated Financial Statements for more information.) Potential Impact of Regulatory Restructuring Based on the current regulatory framework in which it operates, the system accounts for the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Under SFAS No. 71, a utility is allowed to defer costs that would otherwise be expensed in recognition of the ability to recover them in future rates. As a result, the system has accumulated $111.7 million of regulatory assets (approximately 8% of total assets) as of December 31, 1994. Management believes that the current regulatory framework provides for the continued recovery of these assets. In the event that recovery of specific costs through rates becomes uncertain or unlikely in the future either as a result of the expanding effects of competition or specific regulatory actions, the system could be required to move away from cost-of-service ratemaking and, therefore, SFAS No.71 would no longer apply. Discontinuation of SFAS No. 71 could lead to the write-off of various regulatory assets, which would have an adverse impact on the system's financial position and results of operations. At this time, management believes that it is unlikely that regulatory action would lead to the discontinuation of SFAS No. 71 in the near future. Competition This past year, the system continued to develop and implement strategies to deal with the increasingly competitive environment in our gas and electric businesses. The inherently high cost of providing energy services in the Northeast has placed the region at a competitive disadvantage as more customers begin to explore alternative supply options. Many state and federal government agencies are considering implementing programs under which utility and non-utility generators can sell electricity to customers of other utilities without regard to previously closed franchise service areas. In 1994, the DPU began an inquiry into incentive ratemaking and in February 1995 opened an investigation into electric industry restructuring. System company actions in response to the new competitive challenges have been well received by regulators, business groups and customers. Commonwealth Gas and Commonwealth Electric have developed and continue to develop innovative pricing mechanisms designed to retain existing customers, add new retail and wholesale customers and expand beyond current markets. Commonwealth Electric recently revised its Economic Development Rate which will benefit a number of high-use industrial customers and contribute to economic development in the area. Another new rate will provide incentive for business to expand into previously vacant space and its Rate Stabilization Plan, approved in 1994, continues to hold the line on costs passed on to customers while aggressively pursuing other cost reduction measures. Recently completed contract negotiations are expected to save customers approximately $42 million through 1999 as we continue to explore opportunities to reduce purchased power costs. Commonwealth Electric recently signed an agreement with another New England utility to purchase peaking-unit capacity at rates lower than that available from the New England Power Pool or other regional utilities. FERC Order 636 (November 1993) marked the beginning of the deregulation and restructuring of the natural gas industry. In addition to opening up customer markets to competition, the regulations shifted many supply-related responsibilities to local distribution companies including direct gas purchases from suppliers, pipelines and producers, transportation services and storage services. Commonwealth Gas has developed a gas control and informa- tion system that is one of the most sophisticated purchasing and tracking systems in the industry. This ability, coupled with aggressive planning and procurement strategies will help to secure Commonwealth Gas' existing market and permit the expansion of core and non-core supply capabilities. Commonwealth Gas' substantial LNG and storage capabilities provide it with the reliability needed during the coldest winter days and the flexibility to sell capacity when supply and pricing conditions are favorable. Twenty percent of the gas purchased during 1994 was sold outside Commonwealth Gas' franchise area. These off-system sales reduced average gas costs by four cents per MMBTU or a total of $1.7 million. These developments are pushing the gas business beyond traditional markets and Commonwealth Gas will begin to profit from these actions, pending DPU approval, by sharing in the margins produced in the new competitive arena. System companies continue to be aggressive in their cost containment efforts. For example, through work force reductions and attrition the system has reduced its work force approximately 16.3% since 1989. Also, the intro- duction of advanced technologies in the workplace continues to improve customer service and our competitive position in our businesses. The system has yet to be significantly impacted by the increase in competition, and absent a major shift in regulation at the state level, believes its current strategy will have a positive impact in the near-term. Some of the more specific details of the innovative measures taken in response to competition include the following: Rate Stabilization Plan Commonwealth Electric implemented a FC rate settlement on April 1, 1994 that stabilizes its quarterly FC rate during the years 1994 through 1996 at 6.5 cents per KWH and no greater than 6.7 cents per KWH during 1997. The settlement results in billings at a lower rate than would have otherwise been in effect and could save customers between 1.75% and 5% on their annual elec- tric bills through 1997. This rate stabilization is achieved through the use of a cost deferral mechanism that was sponsored jointly by Commonwealth Electric and the Massachusetts Attorney General and approved by the DPU. The deferred costs are reflected as a regulatory asset to be recovered, with carrying charges, over the subsequent six-year period beginning in 1998 pursuant to a recovery schedule yet to be determined and subject to DPU approval. The deferred amount, excluding carrying charges, is restricted to a maximum of $40 million during the settlement period (1994 through 1997) and is further limited to an annual amount of $16 million. Commonwealth Electric deferred $15,964,000 in 1994. In view of recent contract renegotiations, the system does not expect deferred amounts to exceed $20 million through 1997. The rate stabilization mechanism is part of a long-term plan to control Commonwealth Electric's retail rates. This plan will help eliminate the disincentive for economic development resulting from a volatile and unpredict- able FC rate. The stabilized FC rate will enable current and prospective customers to better plan their business and personal finances in a more efficient and effective manner. In addition to the Massachusetts Attorney General, this proposal has been widely supported by various business and customer groups and other political interests. Power Contract Negotiations Commonwealth Electric concluded the negotiation of a restructured Power Sale Agreement (PSA), effective January 1, 1995, with Lowell Cogeneration Company Limited Partnership (23 MW). The restructured PSA will allow the system to defer the purchase of capacity and energy for a maximum of six years and allows the purchase of power from the plant, when called back into service, to be dispatched only when needed at the discretion of Commonwealth Electric. In addition, Commonwealth Electric terminated a PSA with Pepperell Power Associates Limited Partnership (38 MW), effective January 27, 1995, through a buy-out arrangement that is subject to final FERC approval. In 1994, the power purchased from these units cost the system 6 cents per kilowatthour as compared to costs at the system's Canal Electric units of 3.5 cents. It is expected that the resolution of these contracts will enhance Commonwealth Electric's competitiveness by lowering costs and saving customers approximately $42 million through 1999. Economic Development Realizing a healthy regional economy benefits not only businesses but all area residents, Commonwealth Electric actively encourages economic growth by working in partnership with communities and businesses, providing resources and incentives to drive the region's economy. One initiative involves funding the development of an action plan to guide the work of the Massachusetts Textile and Apparel Council, a trade group organized to improve competitive- ness and job creation throughout the industry. Commonwealth Electric also funded the development of a business plan that focuses on improving infrastructure, regulation, access to capital, marketing and promotion, cooperation and leadership on Cape Cod. In an effort to foster industrial development in its service area, Commonwealth Electric began offering an Economic Development Rate (EDR) in October 1991 to new or existing industrial customers who have an electric demand of 500 kilowatts or more and meet specific financial and other criteria. As of December 31, 1994, twenty-three commercial and industrial customers were benefitting from this special rate. The rate is available for a six-year term. In 1993, the DPU conducted a generic investigation into EDRs and rendered a decision on September 1, 1993 that established rate design guidelines and minimum customer eligibility requirements. Commonwealth Electric refiled its EDRs to comply with the ruling. The new EDR is available to both commercial and industrial customers with loads greater than 500 kilowatts. Revenues were lower by $1.7 million, $1.5 million and $1.3 million in 1994, 1993 and 1992, respectively. These amounts represent the difference between what certain commercial and industrial customers would have paid prior to the availability of this rate. Commonwealth Electric also received approval for a Vacant Space Rate that is available to qualifying small commercial and industrial customers who establish loads in previously unoccupied building space. Quasi-firm and Off-system Gas Sales Services In late August 1994, Commonwealth Gas received regulatory approval for a new quasi-firm sales service that is designed for larger customers and provides a combination of firm and interruptible service. In exchange for prices lower than full firm service, quasi-firm customers will receive interruptible service in peak demand months and firm service in off-peak months. These arrangements will give Commonwealth Gas and its customers more flexibility in a constantly changing environment. During 1994, Commonwealth Gas was able to maximize the use of its gas supply resources through off-system sales. These efforts primarily help to reduce the cost of gas to Commonwealth Gas' firm customers thereby serving to make Commonwealth Gas more competitive in its traditional markets. Environmental Matters Commonwealth Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether Commonwealth Gas may be responsible for remedial actions. The costs associated with the assessment and clean-up of these sites are recoverable in rates through the cost of gas adjustment clause over a seven- year amortization period without carrying costs pursuant to a 1990 DPU order. Commonwealth Gas has recorded an estimated $2.3 million liability that reflects its best estimate (based on current information) of the costs to be incurred in connection with the assessment and remediation activities identified to this point. Commonwealth Gas has also recorded a regulatory asset in anticipation of recovery of these costs. Commonwealth Gas is unable to predict the total cost to ultimately resolve these matters, due to significant uncertainty as to the actual site conditions and the extent of any associated remediation activities and the assignment of responsibility. However, it is expected that all such costs will continue to be recovered in rates as described above. Commonwealth Gas and certain other system subsidiaries are also involved in other known or potentially contaminated sites where the associated costs may not be recoverable in rates and have recorded an estimated liability (and a charge to operations) of $760,000 to cover the expected costs associated with assessment and remediation activities. These estimates are reviewed and adjusted periodically as further investigation and assignment of responsibil- ity occurs. The system is unable to estimate its ultimate liability for future environmental remediation costs. However, in view of the system's current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, management does not believe that these matters will have a material adverse effect on the system's results of operations or financial position. In October 1993, the system reached an agreement with Montaup Electric Company (the 50% owner of Canal Unit 2) and Algonquin Gas Transmission Company to build a natural gas pipeline that will serve the Canal Unit 2 generating station, subject to regulatory approvals. Unit 2 will be modified to burn gas in addition to oil. The project will improve air quality on Cape Cod, enable the plant to exceed the stringent 1995 air quality standards established by the DEP and strengthen the system's bargaining position as it seeks to secure the lowest-cost fuel for its customers. Plant conversion and pipeline construction are expected to be completed in 1996. Power Contract Arbitrations On May 2, 1994, Commonwealth Electric and Cambridge Electric gave notice of termination of power purchase agreements with Eastern Energy Corporation, the developer of a proposed 300 MW coal-fired plant, based upon the developer's failure to meet its contractual obligations. In June 1989, Commonwealth Electric and Cambridge Electric agreed to buy 27% (50 MW and 33 MW, respectively) of the power to be produced by the proposed plant, original- ly scheduled to begin operation in January 1992. The developer did not meet the permitting, construction or operation milestones established by the contracts, and has not yet obtained the required permits, commenced construc- tion or sold any additional power from the proposed plant. Efforts to reshape the power purchase agreements to provide a satisfactory arrangement were unsuccessful. In a letter dated June 30, 1994, the developer objected to the notices of termination and invoked arbitration, which is pending. A decision by the arbitrators on the legality of Commonwealth Electric's and Cambridge Electric's termination is expected in 1995. Commonwealth Electric has initiated an arbitration proceeding with Dartmouth Power Associates, an IPP, seeking approximately $5 million for recovery of excess fuel charges billed to Commonwealth Electric for power purchases in 1992. A decision is expected from the arbitrators in 1995. ______________________________________________________ MANAGEMENT'S REPORT The consolidated financial statements presented herein are representations of the management of Commonwealth Energy System. Management recognizes its responsibility for the preparation and presentation of financial statements in conformity with generally accepted accounting principles. To fulfill this responsibility, management maintains a system of internal accounting controls, including established policies and procedures and a comprehensive internal auditing program to evaluate the adequacy and effectiveness of accounting and operating controls, compliance with system policies and procedures and the safeguarding of system assets. The responsibility of our independent auditors' examination is limited to the expression of an opinion as to the fairness of the consolidated financial statements presented. The independent auditors are selected by the Board of Trustees and report their findings thereto through the Audit Committee, which is comprised of three outside Trustees. The Board of Trustees is responsible for ensuring that both the independent auditors and management fulfill their respective responsibilities as they pertain to these financial statements. JAMES D. RAPPOLI James D. Rappoli, Financial Vice President February 21, 1995. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Trustees of Commonwealth Energy System: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of COMMONWEALTH ENERGY SYSTEM (a Massachusetts trust) and subsidiary companies as of December 31, 1994 and 1993, 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, 1994. These 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 the System and subsidiary companies as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As discussed in Note 4 to the consolidated financial statements, effective January 1, 1993, the System and subsidiary companies changed their method of accounting for costs associated with postretirement benefits other than pensions. ARTHUR ANDERSEN LLP Arthur Andersen LLP Boston, Massachusetts February 21, 1995. Consolidated Balance Sheets December 31, 1994 and 1993 1994 1993 (Dollars in Thousands) Assets Property, Plant and Equipment, at original cost Electric $1,047,140 $1,018,121 Gas 338,111 322,314 Other 59,213 58,473 1,444,464 1,398,908 Less-Accumulated depreciation and amortization 461,310 425,483 983,154 973,425 Construction work in progress 15,835 9,448 Nuclear fuel in process 139 1,641 999,128 984,514 Leased Property, net 15,729 16,150 Equity in Corporate Joint Ventures Nuclear electric power companies (2.5% to 4.5%) 9,818 9,660 Other investments 3,830 3,889 13,648 13,549 Current Assets Cash 7,722 6,007 Accounts receivable, less reserves of $7,956,000 in 1994 and $7,761,000 in 1993 92,157 93,663 Unbilled revenues 33,161 43,279 Inventories, at average cost- Electric production fuel oil 1,689 1,440 Natural gas 24,161 25,810 Materials and supplies 7,736 8,852 Prepaid taxes 8,806 8,582 Other 5,858 6,649 181,290 194,282 Deferred Charges 134,921 106,668 $1,344,716 $1,315,163 Consolidated Balance Sheets December 31, 1994 and 1993 1994 1993 (Dollars in Thousands) Capitalization and Liabilities Capitalization (See separate statement) Common share investment $ 362,997 $ 337,070 Redeemable preferred shares, less current sinking fund requirements 14,660 15,480 Long-term debt, less current sinking fund requirements and maturing debt 418,307 448,893 795,964 801,443 Capital Lease Obligations 14,098 14,456 Current Liabilities Interim Financing- Notes payable to banks 44,850 71,975 Maturing long-term debt 25,000 10,000 69,850 81,975 Other Current Liabilities- Current sinking fund requirements 6,793 6,793 Accounts payable 117,953 90,006 Accrued taxes- Local property and other 10,293 9,090 Income 7,654 - Accrued interest 7,251 7,325 Dividends declared 7,894 7,544 Other 23,359 22,453 181,197 143,211 251,047 225,186 Deferred Credits Accumulated deferred income taxes 160,944 156,851 Unamortized investment tax credits 29,304 30,774 Other 93,359 86,453 283,607 274,078 Commitments and Contingencies $1,344,716 $1,315,163 The accompanying notes are an integral part of these consolidated financial statements. Consolidated Statements of Income For the Years Ended December 31, 1994, 1993 and 1992 1994 1993 1992 (Dollars in Thousands) Operating Revenues Electric $639,127 $624,020 $597,269 Gas 323,568 302,644 294,874 Steam and other 15,867 14,035 14,307 978,562 940,699 906,450 Operating Expenses Fuel used in electric production, principally oil 90,414 90,346 104,640 Electricity purchased for resale 269,418 258,490 208,427 Cost of gas sold 177,150 156,709 154,304 Other operation 207,502 207,053 223,620 Maintenance 36,522 40,574 39,836 Depreciation 44,188 42,480 43,164 Amortization 5,868 5,764 7,697 Taxes- Local property 17,467 16,350 15,923 Income 29,154 28,256 20,557 Payroll and other 8,087 8,676 8,357 885,770 854,698 826,525 Operating Income 92,792 86,001 79,925 Other Income (Expense) Allowance for equity funds used during construction 341 - 1,827 Other, net (691) 3,784 (417) (350) 3,784 1,410 Income Before Interest Charges 92,442 89,785 81,335 Interest Charges Long-term debt 39,442 37,416 36,722 Other interest charges 4,475 6,730 7,034 Allowance for borrowed funds used during construction (443) (195) (2,318) 43,474 43,951 41,438 Net Income 48,968 45,834 39,897 Dividends on preferred shares 1,170 1,230 1,291 Earnings Applicable to Common Shares $ 47,798 $ 44,604 $ 38,606 Average Number of Common Shares Outstanding 10,413,781 10,215,614 10,081,868 Earnings Per Common Share $4.59 $4.37 $3.83 The accompanying notes are an integral part of these consolidated financial statements. Consolidated Statements of Cash Flows For the Years Ended December 31, 1994, 1993 and 1992 1994 1993 1992 (Dollars in Thousands) Operating Activities Net income $ 48,968 $ 45,834 $ 39,897 Effects of non cash items- Depreciation and amortization 53,727 53,088 58,883 Deferred income taxes, net 14,846 17,059 (74) Investment tax credits (1,470) (1,500) (1,543) Allowance for equity funds used during construction (341) - (1,827) Earnings from corporate joint ventures (1,750) (1,642) (2,016) Dividends from corporate joint ventures 1,651 1,981 2,157 Change in working capital, exclusive of cash- Accounts receivable and unbilled revenues 11,624 (3,961) 4,814 Prepaid (accrued) income taxes 8,016 7,321 (4,539) Prepaid (accrued) local property and other taxes 616 301 (598) Accounts payable and other 32,437 4,642 1,441 Fuel charge stabilization deferral (15,964) - - Deferred postretirement benefit and pension costs (8,536) (10,175) (1,418) Deferred Order 636 transition costs, net (2,585) (8,805) - All other operating items (14,676) (17,451) 5,233 Net cash provided by operating activities 126,563 86,692 100,410 Investing Activities Additions to property, plant and equipment (exclusive of AFUDC)- Electric (37,997) (29,490) (26,080) Gas (17,993) (23,099) (20,437) Other (1,843) (1,796) (2,577) Allowance for borrowed funds used during construction (443) (195) (2,318) Net cash used for investing activities (58,276) (54,580) (51,412) Financing Activities Sale of common shares 9,434 7,118 5,233 Payment of dividends (32,475) (31,101) (30,770) Proceeds from (payment of) short-term borrowings, net (27,125) (93,625) 19,800 Long-term debt issues - 134,000 15,000 Retirement of long-term debt and preferred shares through sinking funds (6,406) (6,419) (5,678) Long-term debt issues refunded (10,000) (37,600) (51,632) Net cash used for financing activities (66,572) (27,627) (48,047) Net increase in cash 1,715 4,485 951 Cash at beginning of period 6,007 1,522 571 Cash at end of period $ 7,722 $ 6,007 $ 1,522 Supplemental Disclosures of Cash Flow Information Cash paid during the period for: Interest (net of capitalized amounts) $ 41,022 $ 39,685 $ 40,116 Income taxes $ 17,563 $ 13,528 $ 14,460 The accompanying notes are an integral part of these consolidated financial statements. Consolidated Statements of Capitalization December 31, 1994 and 1993 1994 1993 (Dollars in Thousands) Common Share Investment Common shares, $4 par value- Authorized-18,000,000 shares Outstanding-10,525,897 in 1994 and 10,295,077 in 1993 $ 42,103 $ 41,180 Amounts paid in excess of par value 103,168 94,657 Retained earnings 217,726 201,233 Total common share investment 362,997 337,070 Redeemable Preferred Shares, Cumulative, $100 Par Value Series A, 4.80% 2,880 3,000 Series B, 8.10% 4,320 4,480 Series C, 7.75% 8,280 8,820 Less-Current sinking fund requirements (820) (820) Total redeemable preferred shares 14,660 15,480 Long-term Debt Notes due- 1995, 4.70% 15,000 25,000 System Senior Notes due- 1995, 10.39% 10,000 10,000 1997, 10.48% 10,000 10,000 1998, 10.45% 10,000 10,000 1999, 10.58% 10,000 10,000 Less-Maturing long-term debt (25,000) (10,000) Total System long-term debt 30,000 55,000 Subsidiary companies' long-term debt Mortgage Bonds, collateralized by property of operating subsidiaries, due- 1996, 7% 4,560 5,320 1996, 8.99% 10,000 10,000 2001, 8.99% 25,400 29,050 2006, 8.85% 35,000 35,000 2020, 7 3/8% 10,000 10,000 2020, 9 7/8% 40,000 40,000 2020, 9.95% 25,000 25,000 2033, 7.11% 35,000 35,000 Notes due- 1996, 9.97% 20,000 20,000 1997, 6 1/4% 4,380 4,440 1998, variable rate (6.75% in 1994 and 4.03% in 1993) 9,000 9,000 1999, 8.04% 10,000 10,000 2002, 7 3/4% 2,800 2,900 2002, 9.30% 30,000 30,000 2003, 7.43% 15,000 15,000 2004, 9.50% 15,000 15,000 2007, 8.70% 5,000 5,000 2007, 9.55% 10,000 10,000 2008, 7.70% 10,000 10,000 2012, 9.37% 18,947 20,000 2013, 7.98% 25,000 25,000 2014, 9.53% 10,000 10,000 2019, 9.60% 10,000 10,000 2023, 8.47% 15,000 15,000 Less-Current sinking fund requirements (5,973) (5,973) Unamortized discount, net (807) (844) Total subsidiary companies' long-term debt 388,307 393,893 Total long-term debt 418,307 448,893 Total capitalization $795,964 $801,443 The accompanying notes are an integral part of these consolidated financial statements. Consolidated Statements of Changes in Common Shareholders' Investment For the Years Ended December 31, 1994, 1993 and 1992 Amounts Par Paid in Value Excess $4 Per of Par Retained Shares Share Value Earnings Total (Dollars in Thousands) Balance December 31, 1991 10,007,237 $40,029 $ 83,457 $177,373 $300,859 Add (Deduct)- Net income - - - 39,897 39,897 Sale of shares 134,438 538 4,695 - 5,233 Cash dividends declared- Common shares-$2.92 per share - - - (29,479) (29,479) Preferred shares - - - (1,291) (1,291) Balance December 31, 1992 10,141,675 40,567 88,152 186,500 315,219 Add (Deduct)- Net income - - - 45,834 45,834 Sale of shares 153,402 613 6,505 - 7,118 Cash dividends declared- Common shares-$2.92 per share - - - (29,871) (29,871) Preferred shares - - - (1,230) (1,230) Balance December 31, 1993 10,295,077 41,180 94,657 201,233 337,070 Add (Deduct)- Net income - - - 48,968 48,968 Sale of shares 230,820 923 8,511 - 9,434 Cash dividends declared- Common shares-$3.00 per share - - - (31,305) (31,305) Preferred shares - - - (1,170) (1,170) Balance December 31, 1994 10,525,897 $42,103 $103,168 $217,726 $362,997 Consolidated Statements of Changes in Redeemable Preferred Shares For the Years Ended December 31, 1994, 1993 and 1992 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, 1991 32,400 48,000 99,000 179,400 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1992 31,200 46,400 93,600 171,200 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1993 30,000 44,800 88,200 163,000 Less-Sinking fund redemptions 1,200 1,600 5,400 8,200 Balance December 31, 1994 28,800 43,200 82,800 154,800 The accompanying notes are an integral part of these consolidated financial statements. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Significant Accounting Policies (a) General and Regulatory Commonwealth Energy System, the parent company, is referred to in this report as the "System" and, together with its subsidiaries, is collectively referred to as "the system." The operating companies are regulated as to rates, accounting and other matters by various authorities, including the Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of Public Utilities (DPU). Regulated subsidiaries of the System have established various regulatory assets in cases where the DPU and/or the FERC have permitted or are expected to permit recovery of specific costs over time. Similarly, certain regula- tory liabilities established by the system are required to be refunded to customers over time. The principal regulatory assets included in deferred charges at December 31, 1994 and 1993 were as follows: 1994 1993 (Dollars in Thousands) Postretirement benefit costs including pensions $ 20,129 $ 11,593 FERC Order 636 transition costs 19,201 21,939 Yankee Atomic unrecovered plant and decommissioning costs 18,368 15,525 Fuel charge stabilization 16,638 - Seabrook related costs 12,648 15,774 Pilgrim nuclear plant litigation costs 7,001 7,358 Deferred income taxes 5,537 7,345 Cannon Street generating plant abandonment, net 4,400 4,391 Conservation and load management 3,773 4,136 Other 4,042 3,478 Total regulatory assets $111,737 $ 91,539 Regulatory assets as a percent of total assets 8.3% 7.0% The principal regulatory liabilities, reflected in deferred credits- other and relating to income taxes, were $17.3 million and $17.9 million at December 31, 1994 and 1993, respectively. (b) Principles of Consolidation The consolidated financial statements include the accounts of the System and all of its subsidiary companies. All significant intercompany accounts and transactions have been eliminated in consolidation. (c) Reclassifications Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements. (d) Equity Method of Accounting The system uses the equity method of accounting for investments in corporate joint ventures due, in part, to its ability to exercise significant influence over operating and financial policies of these entities. Under this method, it records as income the proportionate share of the net earnings of the joint ventures with a corresponding increase in the carrying value of the investment. The investment is reduced as cash dividends are received. The system conducts business with the corporate joint ventures in which it has investments, principally four nuclear generating facilities located in New England and a 3.8% interest in Hydro-Quebec Phase II. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (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. System utility companies are generally permitted to bill customers currently for fuel used in electric production, purchased power and transmission costs, total gas costs and conservation and load management and environmental costs through adjustment clauses. Amounts recoverable under these clauses are subject to review and adjustment by the DPU. Cambridge Electric Light Company (Cambridge) and Commonwealth Electric Company (Commonwealth Electric) collect a portion of capacity-related purchased power costs associated with certain long-term power arrangements through base rates. The amount of such fuel and energy costs incurred but not yet reflected in customers' bills, which totaled $306,000 in 1994 and $5,565,000 in 1993, is recorded as unbilled revenues. Commonwealth Electric also has implemented a Fuel Charge (FC) rate settlement that stabilizes its quarterly FC rate for the years 1994 through 1997 by utilizing a cost deferral mechanism approved by the DPU. The deferral, which will ultimately be recovered in revenues beginning in 1998, is limited to $16 million annually (excluding carrying charges) and is further restricted to a maximum of $40 million during the settlement period. (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: 1994 1993 1992 Electric 3.30% 3.28% 3.49% Gas 2.98 2.95 2.90 Steam 3.94 3.61 3.50 LNG 3.12 3.07 3.00 (g) Allowance for Funds Used During Construction Under applicable rate-making practices, system companies are permitted to include an allowance for funds used during construction (AFUDC) as an element of their depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which utility companies earn a return. An amount equal to the AFUDC capitalized in the current period is reflected in the accompanying consolidated statements of income. While AFUDC does not provide funds currently, these amounts are recoverable in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 9.1% in 1994, 3.9% in 1993 and 4.5% in 1992. (2) Commitments and Contingencies (a) Construction The system is engaged in a continuous construction program presently estimated at $357.4 million for the five-year period 1995 through 1999. Of that amount, $87.7 million is estimated for 1995. The program is subject to periodic review and revision. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (b) Seabrook Nuclear Power Plant The system's 3.52% interest in the Seabrook nuclear power plant is owned by Canal Electric Company (Canal), a wholesale electric generating subsidiary, to provide for a portion of the capacity and energy needs of affiliates Cambridge and Commonwealth Electric. Canal is recovering 100% of its Seabrook 1 investment through a power contract with Cambridge and Commonwealth Electric pursuant to FERC and DPU approval. Pertinent information with respect to Canal's joint-ownership interest in Seabrook 1 and information relating to operating expenses which are included in the accompanying financial statements are as follows: 1994 1993 (Dollars in Thousands) Utility-plant-in service $232,374 $233,140 Plant capacity (MW) 1,150 Nuclear fuel 18,500 18,514 Canal's share: Accumulated depreciation Percent interest 3.52% and amortization (41,654) (34,771) Entitlement (MW) 40.5 Construction work in In-Service date 1990 progress 651 881 Operating license $209,871 $217,764 expiration date 2026 1994 1993 1992 (Dollars in Thousands) Operating expenses: Fuel $ 1,939 $ 3,853 $ 3,952 Other operation 4,340 4,580 5,705 Maintenance 1,688 893 1,508 Depreciation 6,531 6,522 6,426 Amortization 1,320 1,319 1,320 $15,818 $17,167 $18,911 Canal and the other joint owners have established a Seabrook Nuclear Decommissioning Financing Fund to cover post operation decommissioning costs. For the years 1994, 1993 and 1992, Canal paid $271,000, $259,000 and $235,000, respectively, as its share of the cost of this fund. The estimated cost to decommission the plant is $382 million in 1994 dollars, through December 31, 1994. Canal's share of this liability (approximately $13.4 million) less its share of the market value of the decommissioning trust ($1 million) is approximately $12.4 million. (c) Price-Anderson Act Under the Price-Anderson Act (the Act), owners of nuclear power plants have the benefit of approximately $9 billion of public liability coverage which would compensate the public for valid bodily injury and property loss on a no fault basis in the event of an accident at a commercial nuclear power plant. Under the provisions of the Act, each nuclear reactor with an operating license can be assessed up to $79.2 million per nuclear incident with a maximum assessment of $10 million per incident within one calendar year. Nuclear plant owners have initiated insurance programs designed to help cover liability claims relating to property damage, decontamination, replacement power and business interruption costs for participating utilities arising from a nuclear incident. The system has an equity ownership interest in four nuclear generating facilities as well as a 3.52% joint-ownership interest in Seabrook 1. The operators of these units maintain nuclear insurance coverage (on behalf of the owners of the facilities) with Nuclear Electric Insurance Limited (NEIL II and NEIL III) and the combined American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters (ANI). NEIL II provides $1.4 billion of property, COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) boiler, machinery and decontamination insurance coverage, including $250 million of accidental premature decommissioning losses both in excess of the $500 million required by the Act. NEIL III provides $850 million of additional insurance coverage. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available. ANI provides $500 million of "all risk" property damage, boiler, machinery and decontamination insurance. An additional $200 million of primary financial protection coverage is provided for off-site bodily injury or property damage caused by a nuclear incident. ANI also provides secondary financial protection liability insurance which currently provides $8.7 billion of retrospective insurance premium benefits in accordance with the provisions of the Act. Additional coverage provided by ANI includes tort liability protection arising out of radiation injury claims by nuclear workers and injury or property damage caused by the transportation or shipment of nuclear materials or waste. Based on its various ownership interests in the five nuclear generating facilities, the system's retrospective premium could be as high as $1.9 million yearly or a cumulative total of $15.1 million, exclusive of the effect of inflation indexing (at five-year intervals) and a 5% surcharge ($4 million) in the event that total public liability claims from a nuclear incident exceed the funds available to pay such claims. (d) Power Contracts Cambridge and Commonwealth Electric have long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require payment of a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. Pertinent information with respect to life-of-the-unit contracts for power from operating nuclear units in which the system has an equity ownership (Yankee Nuclear Units) is as follows: Connecticut Maine Vermont Yankee Yankee Yankee (Dollars in Thousands) Equity Ownership (%) 4.50 4.00 2.50 Plant Entitlement (%) 4.50 3.59 2.25 Plant Capability (MW) 560.0 870.0 496.0 System Entitlement (MW) 25.2 31.2 11.2 Contract Expiration Date 1998 2008 2012 1992 Actual Cost ($) 9,508 6,671 3,970 1993 Actual Cost ($) 10,016 7,050 4,076 1994 Actual Cost ($) 8,902 6,250 3,660 Decommissioning cost estimate (100%) ($) 361,994 342,706 329,586 System's decommissioning cost ($) 16,290 12,303 7,416 Market value of assets (100%) ($) 148,474 108,678 113,300 System's market value of assets ($) 6,681 3,902 2,549 Cambridge pays its share of the decommissioning expense to each of the operators of these nuclear facilities as a cost of electricity purchased for resale. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The system also has long-term contracts to purchase capacity from other generating facilities. Information relative to these contracts is as follows: Range of Contract Expiration Entitlement 1994 1993 1992 Dates % MW Cost Cost Cost (Dollars in Thousands) Type of Unit Cogenerating 2008-2017 * 255.9 $137,304 $104,599 $ 69,742 Nuclear 2012 11 73.1 41,475 40,578 37,516 Waste-to-energy 2015 100 70.2 38,107 34,189 27,206 Hydro 2008-2014 100 29.9 7,521 8,904 10,941 Total 429.1 $224,407 $188,270 $145,405 * Includes contracts to purchase power from various cogenerating units with capacity entitlements ranging from 11.1% to 100%. Costs pursuant to these contracts are included in electricity purchased for resale in the accompanying consolidated statements of income and are recoverable in revenues through either the Fuel Charge or in base rates. The estimated aggregate obligations for capacity under the life-of-the- unit contracts from the operating Yankee Nuclear Units and other long-term purchased power contracts in effect for the five years subsequent to 1994 is as follows: Long-Term Equity Owned Purchased Nuclear Units Power Total (Dollars in Thousands) 1995 $21,740 $203,320 $225,060 1996 22,959 207,372 230,331 1997 20,609 212,419 233,028 1998 24,801 227,272 252,073 1999 24,487 240,243 264,730 Commonwealth Electric successfully negotiated a restructured Power Sale Agreement (PSA), effective January 1, 1995, with an independent power producer (IPP) that defers purchases for a maximum of six years and requires the facility to provide power on a dispatchable basis at the discretion of Commonwealth Electric. In addition, Commonwealth Electric terminated a PSA with another IPP, effective January 27, 1995, through a buy-out arrangement, the cost of which will be recorded as a regulatory asset in 1995 pending final FERC approval. (e) Yankee Atomic Nuclear Power Plant In February 1992, the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) agreed to permanently discontinue power operation and decommission the Yankee Nuclear Power Station (the plant). At December 31, 1994, Cambridge and Commonwealth Electric's respective 2% and 2.5% investment in Yankee Atomic was approximately $1.2 million. The companies' estimated decommissioning costs include its unrecovered share of all costs associated with the shutdown of the plant, recovery of its plant investment, and decommissioning and closing the plant. The most recent cost estimate to permanently shut down the plant is approximately $408.2 million. The companies' share of this liability is $18.4 million and is currently reflected in the accompanying consolidated balance sheets as a liability and corresponding regulatory asset. The market value of the companies' share of assets in the plant's decommissioning fund at December 31, 1994 is approximately $4.9 million. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (f) Environmental Matters The system is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installation of expensive air and water pollution control equipment. These regulations have had an impact on the System's operations in the past and will continue to have an impact on future operations, capital costs and construction schedules of major facilities. For additional information, see "Environmental Matters" in Management's Discussion and Analysis of Financial Condition and Results of Operations. (g) FERC Order No. 636 As a result of implementing FERC Order No. 636 (Order 636), each interstate pipeline company is allowed to collect certain transition costs from its customers that resulted from the pipelines' need to buy out gas supply contracts entered into prior to the issuance of Order 636. Commonwealth Gas has been billed a total of approximately $21.7 million from Tennessee Gas Pipeline Company (Tennessee), Algonquin Gas Transmission Company and Texas Eastern Transmission Company (Texas Eastern) through December 31, 1994. As of October 29, 1993, Commonwealth Gas received preliminary DPU authorization to recover these costs, with carrying charges, through the cost of gas adjustment (CGA) over a four-year period that began in November 1993. As a result, a regulatory asset totaling $19.2 million is reflected in deferred charges as of December 31, 1994. In addition, a related liability of $7.8 million is reflected in deferred credits. Final DPU approval for recovery was received in March 1995. After extensive negotiations between Texas Eastern, Tennessee and their customers (including Commonwealth Gas), settlements were reached regarding a number of transition obligation issues. The settlement with Texas Eastern, which was approved by FERC, calls for the pipeline to absorb approximately 20% of all transition costs incurred from June 1993 forward. This agreement also provides for an extended billing period and annual caps on the collection of future costs. Commonwealth Gas believes that the absorption requirement will give the pipeline incentive to minimize future costs. This settlement resulted in a refund of $2.7 million to Commonwealth Gas which will be refunded to firm customers beginning in 1995. The settlement with Tennessee, which received preliminary approval from the FERC on November 15, 1994, pending rehearings, will lower one element of Commonwealth Gas' transition obligation by approximately $1 million. Further negotiations are underway with Tennessee to craft a total settlement similar to that achieved with Texas Eastern. Commonwealth Gas is continuing to negotiate with the pipelines on several other issues. As a result, Commonwealth Gas is unable to predict its final transition obligation at this time; however, based on these and subsequent settlement activities, Commonwealth Gas will adjust its regulatory asset and liability accounts accordingly. (3) Income Taxes The system files a consolidated federal income tax return. For financial reporting purposes, the System and its subsidiaries provide taxes on a separate return basis. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following is a summary of the consolidated provisions for income taxes for the years ended December 31, 1994, 1993 and 1992: 1994 1993 1992 (Dollars in Thousands) Federal Current $12,789 $ 9,438 $10,581 Deferred 12,562 15,127 69 Investment tax credits (1,470) (1,500) (1,543) 23,881 23,065 9,107 State Current 3,171 2,692 2,599 Deferred 2,403 2,282 2,046 5,574 4,974 4,645 29,455 28,039 13,752 Amortization of regulatory liability relating to deferred income taxes (119) (350) (2,189) $29,336 $27,689 $11,563 Federal and state income taxes charged to: Operating expense $29,154 $28,256 $20,557 Other income/(expense) 182 (567) (8,994) $29,336 $27,689 $11,563 Effective January 1, 1992, the system adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109). SFAS No. 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis 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 in 1994 and 1993: 1994 1993 (Dollars in Thousands) Liabilities Property-related $183,019 $178,739 Fuel charge stabilization 6,526 - Postretirement benefits plan 5,543 4,136 Order 636 transition costs, net 4,094 3,450 Seabrook nonconstruction 4,504 6,017 All other 19,999 17,054 223,685 209,396 Assets Investment tax credit 18,941 19,891 Pension plan 6,744 5,720 Regulatory liability 9,536 9,452 All other 19,452 17,689 54,673 52,752 Accumulated deferred income taxes, net $169,012 $156,644 The net year-end deferred income tax liability above includes a current deferred tax liability of $8,068,000 and a current deferred tax asset of $207,000 in 1994 and 1993, respectively, which are included in accrued income taxes and prepaid income taxes, respectively, in the accompanying consolidated balance sheets. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The total income tax provision set forth on the previous page represents 37% in 1994, 38% in 1993 and 23% in 1992 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages: 1994 1993 1992 (Dollars in Thousands) Federal statutory rate 35% 35% 34% Federal income tax expense at statutory levels $27,406 $25,733 $17,496 Increase (Decrease) from statutory levels: Amortization of regulatory liability relating to deferred income taxes - - (5,700) State tax net of federal tax benefit 3,623 3,233 3,353 Tax versus book depreciation 1,471 1,501 1,069 Amortization of investment tax credits (1,457) (1,454) (1,468) Reversals of capitalized expenses (654) (655) - Dividend received deduction (428) (405) (480) Amortization of excess deferred reserves (174) (350) (820) Other (451) 86 (1,887) $29,336 $27,689 $11,563 Effective federal income tax rate 37% 38% 23% On April 22, 1992, the DPU approved a settlement agreement between Commonwealth Electric, the Attorney General of Massachusetts and a consumer group, which resulted in the issuance of an accounting order authorizing its retention of $5.7 million in excess deferred taxes subject to obtaining a favorable ruling from the Internal Revenue Service which was received on November 30, 1992. In accordance with the above settlement agreement, Commonwealth Electric wrote off in 1992 storm damage costs of $9.2 million ($5.7 million net of tax). The balance of the excess reserves that would have been returned to customers was removed from the deferred tax reserve account and, after adjustment to its pretax amount as required by SFAS 109, was credited to a liability account. The excess reserves/regulatory liability which Common- wealth Electric would retain pursuant to the settlement agreement was also removed from this liability account and credited to other income together with the related income taxes. These amounts were classified as income tax expense and were used in the reconciliation of the income tax rate. As a result of the Revenue Reconciliation Act of 1993, the System's con- solidated federal income tax rate increased to 35% effective January 1, 1993. (4) Employee Benefit Plans (a) Pension The system has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. The system makes monthly contributions to the plan consistent with the funding requirements of the Employee Retirement Income Security Act of 1974. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Components of pension expense and related assumptions to develop pension expense were as follows: 1994 1993 1992 (Dollars in Thousands) Service cost $ 7,316 $ 6,069 $ 5,973 Interest cost 21,452 20,410 18,653 Return on plan assets-(gain)/loss 4,544 (36,552) (24,524) Net amortization and deferral (21,990) 20,669 9,644 Total pension expense 11,322 10,596 9,746 Less: Amounts capitalized and deferred 2,823 2,130 2,761 Net pension expense $ 8,499 $ 8,466 $ 6,985 Discount rate 7.25% 8.50% 8.50% Assumed rate of return 8.50 8.50 8.50 Rate of increase in future compensation 4.50 5.50 5.50 Pension expense reflects the use of the projected unit credit method which is also the actuarial cost method used in determining future funding of the plan. Commonwealth Electric and Cambridge, in accordance with current ratemaking, are deferring the difference between pension contribution, which is allowed currently in base rates, and pension expense, recognized pursuant to Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions." The funded status of the system's pension plan (using a measurement date of December 31) is as follows: 1994 1993 (Dollars in Thousands) Accumulated benefit obligation: Vested $(200,273) $(209,966) Nonvested (23,299) (28,184) $(223,572) $(238,150) Projected benefit obligation $(274,120) $(288,309) Plan assets at fair market value 255,263 268,672 Projected benefit obligation greater than plan assets (18,857) (19,637) Unamortized transition obligation 11,250 12,857 Unrecognized prior service cost 16,227 14,524 Unrecognized gain (24,998) (20,905) Accrued pension liability $ (16,378) $ (13,161) The following actuarial assumptions were used in determining the plan's year-end funded status: 1994 1993 Discount rate 8.50% 7.25% Rate of increase in future compensation 5.00 4.50 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. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (b) Other Postretirement Benefits Through December 31, 1992, the system provided postretirement health care and life insurance benefits to eligible retired employees. Employees became eligible for these benefits if their age plus years of service at retirement equaled 75 or more, provided, however, that such service was performed for a subsidiary of the System. As of January 1, 1993, the system eliminated postretirement health care benefits for those non-bargaining employees who were less than 40 years of age or had less than 12 years of service at that date. Under certain circumstances, eligible employees are now required to make contributions for postretirement benefits. Certain bargaining employees are also participating under these new eligibility requirements. Effective January 1, 1993, the system adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106). This new standard requires the accrual of the expected cost of such benefits during the employees' years of service and the recognition of an actuarially determined postretirement benefit obligation earned by existing retirees. The assumptions and calculations involved in determining the accrual and the accumulated postretirement benefit obligation (APBO) closely parallel pension accounting requirements. The cumulative effect of implementation of SFAS No. 106 as of January 1, 1993 was approximately $106.7 million which is being amortized over 20 years. Prior to 1993, the cost of postretirement benefits was recognized as the benefits were paid. The cost of retiree medical care and life insurance benefits under the traditional pay-as-you-go method totaled $4,738,000 during 1992. In 1993, the system began making contributions to various voluntary employees' beneficiary association (VEBA) trusts that were established pursuant to section 501(c)9 of the Internal Revenue Code (the Code). The system also makes contributions to a subaccount of its pension plan pursuant to section 401(h) of the Code to satisfy a portion of its postretirement benefit obligation. The system contributed approximately $14.5 million and $12.6 million to these trusts during 1994 and 1993, respectively. The net periodic postretirement benefit cost for the years ended December 31, 1994 and 1993 include the following components and related assumptions: 1994 1993 (Dollars in Thousands) Service cost $ 2,198 $ 2,100 Interest cost 8,299 9,017 Return on plan assets (186) (661) Amortization of transition obligation over 20 years 5,336 5,336 Net amortization and deferral (1,118) 30 Total postretirement benefit cost 14,529 15,822 Less: Amounts capitalized and deferred 8,811 10,832 Net postretirement benefit cost $ 5,718 $ 4,990 Discount rate 7.25% 8.50% Assumed rate of return 8.50 8.50 Rate of increase in future compensation 4.50 4.50 COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The funded status of the system's postretirement benefit plan using a measurement date of December 31, 1994 and 1993 is as follows: 1994 1993 (Dollars in Thousands) Accumulated postretirement benefit obligation: Retirees $ (63,280) $ (63,211) Fully eligible active plan participants (10,680) (10,922) Other active plan participants (37,396) (37,726) (111,356) (111,859) Plan assets at fair market value 19,972 11,037 Accumulated postretirement benefit obligation greater than plan assets (91,384) (100,822) Unamortized transition obligation 96,039 101,375 Unrecognized gain (4,655) (553) $ - $ - The following actuarial assumptions were used in determining the plan's year-end funded status: 1994 1993 Discount rate 8.50% 7.25% Rate of increase in future compensation 5.00 4.50 In determining its estimated APBO and the funded status of the plan for 1994 and 1993, the system assumed estimated health care trend rates as follows: 1994 1993 Medicare part B premiums 12.30% 14.90% Medical care 8.50 9.00 Dental care 5.00 5.00 The above rates, with the exception of the dental rate which remains constant, decrease to five percent in the year 2007 and remain at that level thereafter. A one percent change in the medical trend rate would have a $1.6 million impact on the system's annual expense (interest component - $1.1 million; service cost - $500,000) and would change the transition obligation by approximately $13.9 million. Plan assets consist primarily of fixed-income and equity securities. Fluctuations in the fair market value of plan assets will affect postretirement benefit expense in future years. The DPU's policy on postretirement benefits is to allow in rates the maximum tax deductible contributions made to trusts that have been established specifically to pay postretirement benefits. Effective with its June 1, 1993 rate order from the DPU, Cambridge was allowed to recover its SFAS No. 106 expense in base rates over a four-year phase-in period with carrying costs on the deferred balance. The other System companies intend to seek recovery in their next rate proceeding. While the system is unable to predict the outcome of these rate proceedings, it believes the DPU will authorize similar rate treatment as provided to Cambridge and other Massachusetts electric and gas companies for the recovery of the cost of these benefits. Further, based on DPU action and discussions with regulators, the system believes that it is appropriate to record the difference between the amount included in rates and SFAS No. 106 expense as a regulatory asset. At December 31, 1994 and 1993, this deferral amounted to approximately $15.7 million and $8.9 million, respectively. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (c) Savings Plan The system has an Employees Savings Plan that provides for system contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate. Effective January 1, 1993, the rate was increased to five percent for those employees no longer eligible for postretirement health benefits. The total system contribution was $4,302,000 in 1994, $4,245,000 in 1993 and $4,134,000 in 1992. (5) Interim Financing and Long-Term Debt (a) Notes Payable to Banks System companies maintain both committed and uncommitted lines of credit for the short-term financing of their construction programs and other corporate purposes. As of December 31, 1994, system companies had $90 million of committed lines of credit that will expire at varying intervals in 1995. These lines are normally renewed upon expiration and require annual fees of up to .1875% of the individual line. At December 31, 1994, the uncommitted lines of credit totaled $90 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate and averaged 4.4% and 3.5% in 1994 and 1993, respectively. Notes payable to banks totaled $44,850,000 and $71,975,000 at December 31, 1994 and 1993, respectively. (b) Long-term Debt Maturities and Retirements Under terms of various indentures and loan agreements, the System and certain subsidiary companies are required to make periodic sinking fund payments for retirement of outstanding long-term debt. These payments and balances of maturing debt issues for the five years subsequent to December 31, 1994 are as follows: Sinking Funds Maturing Debt Issues Year Subsidiaries System Subsidiaries Total (Dollars in Thousands) 1995 $5,973 $25,000 $ - $30,973 1996 8,283 - 33,230 41,513 1997 7,653 10,000 4,260 21,913 1998 7,653 10,000 9,000 26,653 1999 7,653 10,000 10,000 27,653 (6) Redeemable Preferred Shares Each series of the System's preferred shares was issued at par value, $100 per share, and is subject to periodic, mandatory sinking fund payments. The System can make additional voluntary redemptions, not exceeding the required redemption, at par, on a non-cumulative basis, on each sinking fund date. Preferred shares may also be called for redemption, in whole or in part, in excess of the required and voluntary sinking fund redemptions. The obligation to make mandatory redemptions is cumulative and the System is not allowed to pay dividends to common shareholders or make optional sinking fund payments if mandatory redemptions are in arrears. Details of redemptions for each series are contained in the following table: Sinking Funds Optional Dividend 1995-1999 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 COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Preferred shareholders have no voting rights except in the event that six full quarterly dividends have not been paid. In this circumstance, the preferred shareholders are entitled, voting as a class, to elect two of the nine Trustees of the System. The preference of these shares in involuntary liquidation is equal to par value. The shares are of equal rank and are entitled to cumulative dividends at the annual rate established for each series. No dividend can be declared on any series unless proportionate dividends are concurrently declared on the other outstanding series and in the event that dividend payments are in arrears, the System may not redeem any shares unless all shares of all preferred series are redeemed. (7) Disclosures About Fair Value of Financial Instruments The fair value of certain financial instruments included in the accompanying Consolidated Balance Sheets as of December 31, 1994 and 1993 are as follows: 1994 1993 (Dollars in Thousands) Carrying Fair Carrying Fair Value Value Value Value Long-term Debt $449,280 $449,292 $464,866 $526,405 Preferred Stock 15,480 14,687 16,300 15,759 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. (8) Lease Obligations System companies lease property, transmission facilities and equipment under agreements, some of which are capital leases. Several subsidiaries renegotiate certain lease agreements annually. These new agreements are for a term of one year and are renewable monthly thereafter. COM/Energy Services Company has agreements in effect for office furniture, computer, transportation and other equipment. Generally, these agreements require the lessee to pay related taxes, maintenance and other costs of operation. Leases currently in effect contain no provisions which prohibit system companies from entering into future lease agreements or obligations. The following is a breakdown, by major class, of property under capital lease at December 31, 1994 and 1993: 1994 1993 (Dollars in Thousands) Transmission facilities $13,844 $14,150 Office furniture and computer equipment 2,136 10,719 Other 100 85 16,080 24,954 Less: Accumulated amortization 351 8,804 $15,729 $16,150 COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 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, 1994: Capital Operating Leases Leases (Dollars in Thousands) 1995 $ 3,213 $11,264 1996 2,865 8,010 1997 1,963 1,947 1998 1,888 995 1999 1,825 413 Beyond 1999 22,640 1,036 Total future minimum lease payments 34,394 $23,665 Less: Estimated interest element included therein 18,665 Estimated present value of future minimum lease payments $15,729 Total rent expense for all operating leases, except those with terms of a month or less, amounted to $13,052,000 in 1994, $12,701,000 in 1993 and $13,149,000 in 1992. There were no contingent rentals and no sublease rentals for the years 1994, 1993 and 1992. (9) Dividend Restriction At December 31, 1994, approximately $114,876,000 of consolidated retained earnings was restricted against the payment of cash dividends by terms of indentures and note agreements securing long-term debt. (10) Segment Information System companies provide electric, gas and steam services to retail customers in communities located in central and eastern Massachusetts and, in addition, sell electricity at wholesale to Massachusetts customers. Other operations of the system include the development and operation of rental properties and other activities which do not presently contribute significantly to either revenues or operating income. Operating income of the various industry segments includes income from transactions with affiliates and is exclusive of interest expense, income taxes and equity in earnings of unconsolidated corporate joint ventures. COMMONWEALTH ENERGY SYSTEM NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The amount of identifiable assets represented by the system's investment in corporate joint ventures consists principally of a percentage ownership in the assets of four regional electric generating plants and a 3.8% interest in Hydro-Quebec Phase II. 1994 1993 1992 (Dollars in Thousands) Revenues from Unaffiliated Customers Electric $ 639,127 $ 624,020 $ 597,269 Gas 323,568 302,644 294,874 Steam and other 15,867 14,035 14,307 Total Revenues $ 978,562 $ 940,699 $ 906,450 Capital Expenditures (including AFUDC) Electric $ 38,754 $ 29,667 $ 30,207 Gas 18,020 23,117 20,455 Other 1,843 1,796 2,577 $ 58,617 $ 54,580 $ 53,239 Operating Income Before Income Taxes Electric $ 86,800 $ 76,117 $ 65,169 Gas 31,664 35,001 32,891 Steam and other 3,482 3,139 2,422 Total Operating Income Before Income Taxes $ 121,946 $ 114,257 $ 100,482 Identifiable Assets Electric $ 930,852 $ 914,571 $ 911,877 Gas 380,805 376,683 328,410 Steam and other 53,914 53,062 53,497 1,365,571 1,344,316 1,293,784 Intercompany eliminations (34,503) (42,702) (35,653) Investment in corporate joint ventures 13,648 13,549 13,888 Total Identifiable Assets $1,344,716 $1,315,163 $1,272,019 Depreciation Expense Electric $ 33,188 $ 32,188 $ 33,632 Gas 9,559 8,939 8,270 Steam and other 1,441 1,353 1,262 Total Depreciation $ 44,188 $ 42,480 $ 43,164 COMMONWEALTH ENERGY SYSTEM SELECTED FINANCIAL DATA 1994 1993 1992 1991 1990 (Dollars In Thousands Except Common Share Data) Operating Revenues Electric $ 639,127 $ 624,020 $ 597,269 $ 607,371 $ 576,416 Gas 323,568 302,644 294,874 252,239 244,074 Steam and other 15,867 14,035 14,307 13,824 15,308 Total $ 978,562 $ 940,699 $ 906,450 $ 873,434 $ 835,798 Net Income $ 48,968 $ 45,834 $ 39,897 $ 19,472 $ 22,636 Common Share Data- Earnings per share $4.59 $4.37 $3.83 $1.82 $2.16 Dividends declared per share $3.00 $2.92 $2.92 $2.92 $2.92 Average shares outstanding 10,413,781 10,215,614 10,081,868 9,944,433 9,810,180 Total Assets $1,344,716 $1,315,163 $1,272,019 $1,247,386 $1,238,083 Long-term debt $ 418,307 $ 448,893 $ 361,092 $ 366,010 $ 412,211 Redeemable preferred share investment 14,660 15,480 16,300 17,120 17,940 Common share investment 362,997 337,070 315,219 300,859 307,282 Total Capitalization $ 795,964 $ 801,443 $ 692,611 $ 683,989 $ 737,433 1994 by Quarter 1st 2nd 3rd 4th (Dollars In Thousands Except Per Share Amounts) Operating Revenues $312,906 $213,632 $223,299 $228,725 Operating Income 38,135 14,201 17,639 22,817 Income Before Interest Charges 38,745 14,399 16,880 22,418 Net Income 27,951 3 760 6,216 11,041 Earnings per Common Share 2.68 .32 .57 1.02 Dividends Declared per Common Share .75 .75 .75 .75 Closing Price of Common Shares- High 45 1/2 43 3/4 40 3/4 38 3/4 Low 42 7/8 39 1/2 37 1/2 35 3/8 1993 by Quarter 1st 2nd 3rd 4th (Dollars In Thousands Except Per Share Amounts) Operating Revenues $276,902 $203,347 $217,884 $242,566 Operating Income 33,868 8,886 16,041 27,206 Income Before Interest Charges 34,319 13,015 16,571 25,880 Net Income 24,063 2,174 5,696 13,901 Earnings per Common Share 2.34 .18 .52 1.33 Dividends Declared per Common Share .73 .73 .73 .73 Closing Price of Common Shares- High 48 7/8 48 5/8 50 1/8 49 3/4 Low 40 1/2 43 3/8 46 3/4 43 Commonwealth Energy System One Main Street Post Office Box 9150 Cambridge, Massachusetts 02142-9150 Telephone (617) 225-4000 Appendices COMMONWEALTH ENERGY SYSTEM Proxy-Annual Meeting of Shareholders-May 4, 1995 This Proxy is Solicited on Behalf of the Board of Trustees The undersigned hereby appoints Henry Dormitzer, William G. Poist and Sinclair Weeks, Jr., and each or any of them, with power of substitution, as proxies to attend the Annual Meeting of Shareholders of the System to be held on Thursday, May 4, 1995 and at any adjournment thereof and to vote the number of shares which the shareholder(s) would be entitled to vote if personally present: To vote your shares for all Trustee nominees, mark the "FOR" box on item 1. To withhold voting for all nominees, mark the "WITHHELD" box. If you do not wish your shares voted "FOR" a particular nominee, mark the "EXCEPTION" box and enter name(s) of the exception(s) in the space provided. _____________________________________________________________________________ The Trustees recommend a vote "FOR" #1 and #2 1. Election of Trustees Nominees: S. A. Buckler, B. L. Francis, M. C. Ruettgers [ ] FOR [ ] WITHHELD [ ] EXCEPTIONS EXCEPTIONS: ____________________ 2. Amendment to Declaration of Trust [ ] FOR [ ] AGAINST [ ] ABSTAIN _____________________________________________________________________________ The Trustees recommend a vote "AGAINST" #3 3. Shareholder Proposal [ ] FOR [ ] AGAINST [ ] ABSTAIN _____________________________________________________________________________ 4. Upon any other business that may properly come before the meeting. _____________________________________________________________________________ This Proxy will be voted as directed above. If no other indication is made, this proxy will be voted FOR proposals #1 and 2, and AGAINST proposal #3. Any proxy or proxies to vote such shares at said meeting heretofore given by the shareholder(s) are hereby revoked. PLEASE SIGN AND DATE ON REVERSE SIDE ____________________________________________________ ____________________________________________________ Signature(s) should agree with name(s) printed below (When signing as attorney, executor or administrator, trustee or guardian, etc., please indicate your full title as such.) Acct. No. No. of Shares Dated_______________________, 1995 PLEASE SIGN, DATE AND RETURN IN ENCLOSED PREPAID ENVELOPE EX-27 3 1994 FINANCIAL DATA SCHEDULE
UT This schedule contains summary financial information extracted from the balance sheet, statement of income and statement of cash flows contained in Form 10-K of Commonwealth Energy System for the fiscal year ended December 31, 1994 and is qualified in its entirety by reference to such financial statements. 0000071304 COMMONWEALTH ENERGY SYSTEM 1,000 DEC-31-1994 DEC-31-1994 YEAR PER-BOOK 999,128 13,648 181,290 134,921 15,729 1,344,716 42,103 103,168 217,726 362,997 14,660 0 418,307 0 44,850 0 30,973 820 14,098 1,631 456,380 1,344,716 978,562 29,154 856,616 885,770 92,792 (350) 92,442 43,474 48,968 1,170 47,798 31,305 39,442 126,563 4.59 0