-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, sP3MvdAfdiMeSMKtLtuI9G0BNtR/ilOLBdSPvY86gYZ2vvbjGhse5Y+ODBlMJWE5 bx430WCB1fs8P7m18RcdTw== 0000071304-94-000010.txt : 19940404 0000071304-94-000010.hdr.sgml : 19940404 ACCESSION NUMBER: 0000071304-94-000010 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: COMMONWEALTH ELECTRIC CO CENTRAL INDEX KEY: 0000071222 STANDARD INDUSTRIAL CLASSIFICATION: 0000 IRS NUMBER: 041659070 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 002-07749 FILM NUMBER: 94519461 BUSINESS ADDRESS: STREET 1: ONE MAIN ST CITY: CAMBRIDGE STATE: MA ZIP: 02142 BUSINESS PHONE: 6172254000 MAIL ADDRESS: STREET 1: P O BOX 9150 CITY: CAMBRIDGE STATE: MA ZIP: 02142-9150 FORMER COMPANY: FORMER CONFORMED NAME: NEW BEDFORD GAS & EDISON LIGHT CO DATE OF NAME CHANGE: 19810331 FORMER COMPANY: FORMER CONFORMED NAME: NEW BEDFORD GAS LIGHT CO DATE OF NAME CHANGE: 19701106 10-K 1 COMMONWEALTH ELECTRIC CO. 1993 FORM 10-K PAGE 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 Form 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1993 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 2-7749 COMMONWEALTH ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Massachusetts 04-1659070 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One Main Street, Cambridge, Massachusetts 02142-9150 (Address of principal executive offices) (Zip Code) 617-225-4000 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered None None Securities registered pursuant to Section 12(g) of the Act: Title of Class None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES x NO Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Outstanding at Class of Common Stock March 15, 1994 Common Stock, $25 par value 2,043,972 shares The Company meets the conditions set forth in General Instruction J(1)(a) and (b) of Form 10-K as a wholly-owned subsidiary and is filing this Form with the reduced disclosure format. Documents Incorporated by Reference Part in Form 10-K None Not Applicable List of Exhibits begins on page 39 of this report. PAGE 2 COMMONWEALTH ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1993 TABLE OF CONTENTS PART I PAGE Item 1. Business........................................ 3 General....................................... 3 Electric Power Supply......................... 3 New England Power Pool........................ 4 Power Contracts and Capacity Acquisition and Disposition Agreement....... 5 Energy Mix.................................... 5 Rates and Regulation.......................... 6 (a) Rate Proceedings........................ 6 (b) Cost Recovery........................... 6 (c) Economic Development Rate............... 7 Construction and Financing.................... 8 Employees..................................... 8 Item 2. Properties...................................... 8 Item 3. Legal Proceedings............................... 8 PART II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters..................... 9 Item 7. Management's Discussion and Analysis of Results of Operations........................... 10 Item 8. Financial Statements and Supplementary Data..... 17 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 17 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 38 Signatures.................................................. 57 PAGE 3 COMMONWEALTH ELECTRIC COMPANY PART I. Item 1. Business General Commonwealth Electric Company (the Company) is engaged in the generation, transmission, distribution and sale of electricity at retail to approximately 307,700 customers (including 48,400 seasonal) in 40 communities located in southeastern Massachusetts, including Cape Cod and the island of Martha's Vineyard, having an approximate year-round population of 549,000 and a large influx of summer residents. The results of the 1990 federal census taken in the Company's service area indicated a population increase of 18.1% since 1980. Also, the Company sells power to the New England Power Pool (NEPOOL) and is actively pursuing sales of certain available capacity to other utilities in and outside the New England region. The Company, which was organized on April 4, 1850 pursuant to a special act of the legislature of the Commonwealth of Massachusetts, operates under the jurisdiction of the Massachusetts Department of Public Utilities (DPU), which regulates retail rates, accounting, issuance of securities and other matters. In addition, the Company files its wholesale rates with the Federal Energy Regulatory Commission (FERC). Since the date of its organization, the Company has from time to time acquired or disposed of the property and franchises of or merged with various gas or electric companies. The Company is a wholly-owned subsidiary of Commonwealth Energy System ("System"), which, together with its subsidiaries, is collectively referred to as "the system." By virtue of its charter, which is unlimited in time, the Company distrib- utes electricity without direct competition in kind from any privately or municipally-owned utilities. Alternate sources of energy are available to customers within the service territory, but competition from these sources to date has not been a significant factor affecting the Company. Of the Com- pany's 1993 retail electric unit sales, 49% was sold to residential customers, 32% to commercial customers, 10% to industrial and 9% to municipal and other customers. Electric Power Supply The Company relies almost entirely on purchased power to meet its electric energy requirements. The Company owns generating facilities with a total capacity of 13.8 MW, which are principally used for emergency and peaking purposes. The Company also has a joint-ownership interest of 8.8 MW in Central Maine Power Company's oil-fired Wyman Unit 4. Power purchases for the Company and Cambridge Electric Light Company (Cambridge Electric), the other wholly-owned electric distribution subsidiary of the System, are arranged in accordance with their requirements. These arrangements include purchases from Canal Electric Company (Canal), another wholly-owned subsidiary of the System. Canal is a wholesale electric generat- ing company located in Sandwich, Massachusetts and an important source of purchased power for the Company. Under long-term contracts, system entitle- ments include one-quarter (143 MW) of the capacity and energy of Canal Unit 1 and one-half (292 MW) of the capacity and energy of Canal Unit 2. In 1991, Canal, on behalf of the Company, exchanged 50 MW of the system's entitlement in Canal Unit 2 with Central Vermont Public Service Corporation (CVPS) 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 in order to reduce the PAGE 4 COMMONWEALTH ELECTRIC COMPANY Company's reliance on oil-fired generation. Additionally, in 1993, Canal executed an exchange transaction with New England Power Company whereby 20 MW of Canal Unit 2 was exchanged for 20 MW of Bear Swamp Unit Nos. 1 and 2 through October 1993. On November 1, 1993, the exchange was increased to 50 MW through April 1997. The Bear Swamp Units are pumped storage hydro-electric generating facilities. In response to solicitations made to the NEPOOL member companies by Northeast Utilities (NU), Canal, on behalf of the Company and Cambridge Electric, agreed to purchase entitlements through various contracts ranging up to five years in length. The terms of the five-year agreement stipulate the purchase of 50 MW, on average, from NU annually from November 1989 through October 1994. The Company and Cambridge Electric are each appropriated a portion of the power received from NU based on need. In addition, the Company has a 73.1 MW entitlement from a nuclear unit in Plymouth, Massachusetts (Pilgrim) under a life-of-the-unit contract with Boston Edison Company. Also, through Canal's equity ownership in Hydro-Quebec Phase II and its 3.52% interest in the Seabrook nuclear power plant, the Company has entitlements of 48.2 MW and 32.4 MW, respectively. In-state non- utility sources which provide a portion of the Company's requirements include 67.0 MW from the SEMASS waste-to-energy plant (which includes 20.8 MW from the expansion unit which went on-line May 17, 1993), 10.0 MW from Boott Hydropow- er, Inc., 2.0 MW from Swift River Company and 0.5 MW from Pioneer Hydropower, Inc. In addition, the Company has contracted to purchase power from: (1) five natural gas-fired cogenerating facilities as follows: 23.8 MW from Consolidat- ed Power Company; 31.4 MW from Pepperell Power Associates; 44 MW from North- east Energy Associates, and effective July 31 and September 1, 1993, 51 MW and 27.5 MW from Masspower and Altresco Pittsfield, L.P., respectively, and (2), 61.8 MW from Dartmouth Power Associates, a natural gas-fired independent power producer. The Company expects to provide for future peak load plus reserve require- ments through existing and planned system generation, including purchasing available capacity from neighboring utilities and/or non-utility generators. These and other bulk electric power purchases are necessary in order to fulfill the system's NEPOOL obligation and for Canal to acquire and deliver sufficient electric generating capacity to meet the Company's and Cambridge Electric's capacity requirements. New England Power Pool The Company, together with other electric utility companies in the New England area, is a member of NEPOOL, which was formed in 1971 to provide for the joint planning and operation of electric systems throughout New England. NEPOOL operates a centralized dispatching facility to ensure reliability of service and to dispatch the most economically available generating units of member companies to fulfill the region's energy requirements. This concept is accomplished through the use of computers to monitor and forecast load requirements and provide for the economic dispatch of generation. The Company and the System's other 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 PAGE 5 COMMONWEALTH ELECTRIC COMPANY 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 in enhancing reliability. 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 Contracts and Capacity Acquisition and Disposition Agreement The Company has long-term contracts for the purchase of electricity from various sources. In addition, the Company's future generation needs will be met substantially through a Capacity Acquisition and Disposition Agreement with Canal. For further information on this agreement, refer to Note 2(b) of the Notes to Financial Statements filed under Item 8 of this report. Energy Mix The Company's energy mix, including purchased power, was as follows: 1993 1992 1991 Oil 27% 39% 36% Nuclear 20 22 28 Natural gas 35 24 19 Waste-to-energy 11 9 10 Hydro 4 3 4 Coal 3 3 3 Total 100% 100% 100% The Company's energy mix has shifted during the last several years from oil to natural gas and other types of generation due to the availability of capacity from independent power producing (IPP) facilities and cogenerating units and, to a lesser extent, an effort to reduce its reliance on oil. As stated in the "Electric Power Supply" section above, in 1993, the Company began receiving power from two gas-fired sources (Altresco Pittsfield and Masspower), additional energy from the expansion of a waste-to-energy plant (SEMASS) and extended commitments from a pumped storage facility (Bear Swamp) in exchange for power from the oil-fired Canal Unit 2. In 1991, Canal arranged for a long-term exchange of power with certain CVPS nuclear (Vermont Yankee) and a coal-fired unit (Merrimack 2). 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/Bear Swamp transaction alone will save the Company's customers $2.7 million over a four-year period that began in June 1993. These exchanges and other future capacity purchase power contracts with natural gas-fired IPPs will continue to shift the Company's energy mix from oil to other sources. In addition, the Company is actively pursuing sales of certain available capacity to utilities in and outside the New England region. PAGE 6 COMMONWEALTH ELECTRIC COMPANY Rates and Regulation (a) Rate Proceedings The Company operates under the jurisdiction of the DPU, which regulates retail rates, accounting, issuance of securities and other matters. In addition, the Company files its respective wholesale rates with FERC. The DPU requires historic test-year information to support changes in rates. In its last base rate filing with the DPU in December 1990, the Company requested a $17.3 million revenue increase. On July 1, 1991, the DPU issued an order increasing the Company's retail electric revenues by $10.9 million or 3.1% over the test year ended June 30, 1990. The DPU also ordered the Company to undertake an independent management audit in 1992. In October 1992, the DPU released the results of the audit which evaluated existing activities and processes and identified opportunities for improved operations in the areas of strategic planning, budget development, control of capital and operational costs, management of outside services, employment policies and customer services. Throughout 1993, follow-up discussions were held between Commonwealth Electric and the DPU regarding the status of each audit recommen- dation with both parties expressing overall satisfaction with their progress. Changes in the implementation plan were discussed, with the plan expected to be complete in 1994. (b) Cost Recovery Rate Schedule The Company files a Fuel Charge rate schedule, subject to DPU regulation, under which it is allowed current recovery, from retail customers, of fuel used in electric generation and a substantial portion of purchased power, demand and transmission costs. This schedule requires the quarterly computation of a Fuel Charge decimal based on forecasts of fuel, purchased power and transmission costs and billed unit sales for each period. To the extent that collections under the rate schedule do not match actual costs for that period, an appropriate adjustment is reflected in the calcula- tion of the decimal for the next calendar quarter. Purchased Power The Company has long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require that the Company pay a demand charge for its capacity entitlement and an energy charge to cover the cost of fuel. The DPU ordered the Company, effective July 1, 1991, to collect its capacity-related costs associated with certain long-term power arrangements through base rates. Prior to that date, the Company was recovering these costs through its Fuel Charge. The current recovery mechanism utilizes a cost 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, the Company experiences 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. The Company and Cambridge Electric made a filing in late 1992 with the DPU seeking an alterna- tive method of recovery. This request was denied in a letter order issued on October 6, 1993. However, the Company and Cambridge Electric 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 PAGE 7 COMMONWEALTH ELECTRIC COMPANY interested parties, including the Attorney General of Massachusetts, to reach a consensus solution on the issue for consideration in each company's next base rate proceeding. Conservation and Load Management Programs The Company and Cambridge Elec- tric have received approval from the DPU to recover conservation and load management program (C&LM) costs. The programs offer opportunities to all customers to save energy by investing in C&LM measures. The overall objective of the programs is to reduce capacity and energy requirements which in turn reduce the cost of providing service. The Company has Conservation Charge (CC) rate schedules which allow for current cost recovery from retail custom- ers. On June 30, 1993, the DPU issued an order in Phase I of a C&LM filing by the Company and Cambridge Electric which authorizes the recovery of "lost base revenues" from electric customers. The recovery of lost base revenues is allowed by the DPU to encourage effective implementation 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. The amount to be recovered is approximately $3.5 million for the Company and is based on anticipated KWH savings for the eighteen-month period beginning January 1, 1993. The revenue will be recovered from customers over a twelve- month period which began July 1, 1993. Through December 31, 1993, the Company had recovered approximately $2.3 million in lost base revenue. On October 25, 1993, the DPU issued an order in Phase II of the C&LM proceeding. In that order, the DPU disallowed approximately $195,000 in expenditures that it determined exceeded benefits to customers. In addition, the DPU ruled that approximately $1.1 million in C&LM Task Force related expenditures are not recoverable by the Company "at this time" because certain programs have yet to be implemented and thus ratepayers are receiving no current benefits. The Company removed these costs from the current CC decimal and is continuing with the development of the programs and plans to seek recovery of these costs in a subsequent filing with the DPU. Based on the language in the order and subsequent discussions with the parties involved in the proceeding, management believes that the ultimate recovery of a substan- tial portion of these costs is likely. Seabrook Costs The full commission of the FERC, in a final order issued on August 4, 1992, approved full recovery of Canal's investment in the Seabrook nuclear power plant. The Company and Cambridge Electric had been billing, subject to refund, Seabrook 1 charges to their retail customers since August 1, 1990 through Fuel Charge decimals approved by the DPU. In its June 1, 1993 rate decision, the DPU allowed Cambridge Electric to recover its Seabrook 1 costs in base rates. However, the Company continues to recover these costs through the Fuel Charge. The Company and Cambridge Electric collect, through their respective Fuel Charge, amounts being billed to them by Canal for costs associated with Seabrook 2 (over a ten-year period ending in 1997) pursuant to a Capacity Acquisition Agreement the terms of which were approved by both FERC and the DPU. (c) Economic Development Rate In an effort to foster industrial development in its service area, the Company began offering an Economic Development Rate (EDR) on October 1, 1991. PAGE 8 COMMONWEALTH ELECTRIC COMPANY The rate is offered to new or existing commercial and industrial customers who have an electric demand of 500 kilowatts or more and meet specific financial and other criteria. As of December 31, 1993, twenty-two industrial customers are 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 guide- lines and minimum customer eligibility requirements. The Company refiled its EDRs to comply with the ruling. The Company also received approval for a Vacant Space Rate which it filed in conformance with the new EDR guidelines that is available to qualifying small commercial and industrial customers who establish loads in previously unoccupied building space. Construction and Financing Information concerning the Company's financing and construction programs is contained in Note 2(a) of Notes to Financial Statements filed under Item 8 of this report. Employees The total number of full-time employees for the Company declined 12% to 917 in 1993 from 1,042 employees at year-end 1992 due to a second quarter work force reduction. Of the current total, 602 employees (66%) are represented by the Brotherhood of Utility Workers of New England, Inc. under three separate collective bargaining units with agreements expiring October 31, 1994, September 30, 1996 and October 31, 1997. Employee relations have generally been satisfactory and management views the current work force level to be appropriate to service the Company's customers. Item 2. Properties The principal properties of the Company consist of an integrated system of transmission and distribution lines, substations, an office building in the Town of Wareham, Massachusetts and other structures such as garages and service buildings. In addition, the Company owns and operates, for standby and emergency purposes only, two diesel plants with a combined capability of 13.8 MW located on the island of Martha's Vineyard. The Company also has a 1.4% joint-ownership interest in Central Maine Power Company's Wyman Unit 4 with an entitlement of 8.8 MW. The Company also owns a 60 MW steam electric generating station located in New Bedford, Massachusetts. This unit, which ceased operations in October 1992, was abandoned in 1993. As a result, the net book value of the plant of approximately $4 million was reclassified from Property, Plant and Equipment to a regulatory asset in anticipation of recovery. At December 31, 1993, the electric transmission and distribution system consisted of 5,691 pole miles of overhead lines, 3,423 cable miles of under- ground line, 142 substations and 326,674 active customer meters. Item 3. Legal Proceedings The Company is not a party to any pending material legal proceeding. PAGE 9 COMMONWEALTH ELECTRIC COMPANY PART II. Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters (a) Principal Market Not applicable. The Company is a wholly-owned subsidiary of Common- wealth Energy System. (b) Number of Shareholders at December 31, 1993 One (c) Frequency and Amount of Dividends Declared in 1993 and 1992 1993 1992 Per Share Per Share Declaration Date Amount Declaration Date Amount January 28, 1993 $1.90 February 24, 1992 $1.45 April 23, 1993 1.10 April 27, 1992 1.20 October 18, 1993 3.20 October 19, 1992 2.50 $6.20 $5.15 In 1992 and on January 28, 1993, dividends were declared on the 1,606,472 outstanding shares of common stock of the Company. On April 23, 1993 and October 18, 1993, dividends were declared on the 2,043,972 outstanding shares of common stock of the Company. Reference is made to Note 6 of the Notes to Financial Statements filed under Item 8 of this report for the restriction against the payment of cash dividends. (d) Future dividends may vary depending upon the Company's earnings and capital requirements as well as financial and other conditions existing at that time. PAGE 10 COMMONWEALTH ELECTRIC COMPANY Item 7. Management's Discussion and Analysis of Results of Operations The following is a discussion of certain significant factors which have affected operating revenues, expenses and net income during the periods included in the accompanying statements of income and is presented to facili- tate an understanding of the results of operations. This discussion should be read in conjunction with Item 1 of this report and the Notes to Financial Statements filed under Item 8 of this report. A summary of the period to period changes in the principal items included in the statements of income for the years ended December 31, 1993 and 1992, is shown below: Years Ended Years Ended December 31, December 31, 1993 and 1992 1992 and 1991 Increase (Decrease) (Dollars in Thousands) Electric Operating Revenues $ 20 991 5.1% $(13 746) (3.2)% Operating Expenses - Electricity purchased for resale and fuel 30 664 12.1 8 755 3.6 Transmission (404) (7.7) (1 831) (25.9) Other operation (7 275) (9.6) 3 430 4.7 Maintenance (1 429) (11.8) (712) (5.5) Depreciation 20 0.1 528 3.6 Conservation and load management (7 661) (64.8) (22 373) (65.4) Taxes - Federal and state income 3 602 101.3 (1 258) (26.1) Local property and other 349 4.5 869 12.6 17 866 4.6 (12 592) (3.2) Operating Income 3 125 13.2 (1 154) (4.7) Other Income (4) (1.6) (258) (50.5) Income Before Interest Charges 3 121 13.1 (1 412) (5.6) Interest Charges 47 0.3 (559) (3.6) Net Income $ 3 074 34.1 $ (853) (8.7) Retail Unit Sales MWH Increase 22 203 0.7 7 106 0.2 PAGE 11 COMMONWEALTH ELECTRIC COMPANY Revenues and Unit Sales The following is a summary of unit sales and customers for the periods indicated: Years Ended December 31, 1993 1992 1991 % % Unit Sales (MWH): Change Change Residential 1 587 338 0.1 1 586 577 2.7 1 545 308 Commercial 1 030 050 1.2 1 018 162 (4.0) 1 060 622 Industrial 328 220 0.7 325 912 (1.0) 329 173 Municipal and other 282 630 2.6 275 384 4.4 263 826 Total retail 3 228 238 0.7 3 206 035 0.2 3 198 929 Sales to other utilities 1 284 724 29.5 991 954 11.3 891 452 Total 4 512 962 7.5 4 197 989 2.6 4 090 381 Customers - 12 Month Average: Residential (1) 269 736 1.2 266 513 0.2 265 969 Commercial (1) 34 362 0.4 34 348 0.9 34 057 Industrial 326 1.2 322 (5.8) 342 Municipal and other 3 315 3.7 3 198 4.7 3 055 Total 307 739 1.1 304 381 0.3 303 423 (1) Includes seasonal customers of 48,364 in 1993, 47,527 in 1992 and 47,200 in 1991. Service is considered to be "seasonal" when the kilowatthours used in the billing months ending between June 1 and September 30 exceed the kilowatthours used in the preceding eight months. In 1993, operating revenues increased $21 million or 5.1% due primarily to the increase in purchased power and fuel costs of $30.7 million (12.1%), a 7.5% increase in total unit sales and the recovery of approximately $2.3 million in lost base revenues related to conservation and load management (C&LM) programs. Partially offsetting these increases was a lower level ($7.7 million) of C&LM program costs. Included in revenues were wholesale sales to NEPOOL and to non-associate utilities of $26.5 million, $22.3 million and $20.5 million in 1993, 1992 and 1991, respectively. Fluctuations in the level of wholesale electric sales have little, if any, impact on earnings. The Company has received approval from the Massachusetts Department of Public Utilities (DPU) to recover in revenues current costs associated with C&LM programs through the operation of a Conservation Charge (CC) decimal on a dollar-for-dollar basis. To the extent that these expenses increase or decrease from period to period based on customer participation, a corre- sponding change will occur in revenues. 1992 operating revenues decreased $13.7 million or 3.2% despite an increase in fuel and purchased power costs of $8.8 million (3.6%), a slight increase in retail unit sales and a full year of higher base rates for the Company. This reduction was due primarily to a $22.4 million or 65.4% decrease in C&LM costs recovered by the Company. Revenues during a portion of 1991 and through 1993 also reflect the impact of the Company's Economic Development Rate which became effective on October PAGE 12 COMMONWEALTH ELECTRIC COMPANY 1, 1991. Revenues were lower by $1.5 million, $1.3 million and $552,000 in 1993, 1992 and 1991, respectively. These amounts represent the difference between what certain commercial and industrial customers would have paid prior to the availability of this rate. For additional information on this special rate, refer to the "Economic Development Rate" section in Item 1 of this report. Although 1993 retail electric unit sales increased by less than 1%, each customer segment did show improvement. Unit sales reflect moderate growth in customers, primarily residential, a greater demand for power from commercial and seasonal customers reflecting an improving economy and, to a lesser extent, more extreme weather conditions resulting in additional use to meet heating or air conditioning requirements, offset somewhat by the impact of conservation programs. Retail electric unit sales were virtually unchanged in 1992 due primarily to a 2.7% increase in the residential sector caused by a return to normal (colder) temperatures, resulting in a more normal heating season in the first and fourth quarters of the year, offset somewhat by a cooler than average summer period, C&LM programs and the difficult economic conditions in communities served by the Company. Purchased Power, Fuel and Transmission The cost of fuel used for electric generation and purchased power per KWH sold was $.063, $.061 and $.060 for 1993, 1992 and 1991, respectively. These costs constitute 66%, 62% and 58% of electric operating revenues for the respective years. The upward trend since 1991 reflects the impact of the Company's contractual obligations to take higher-cost power contracted for in the 1980s when the Company's customer base grew dramatically and forecasts predicted continued growth. These contracts, which are typically long-term, will continue to drive costs up as additional capacity comes on line. The Company is currently involved in negotiations to restructure or buy out certain of these long-term contracts. For 1993 and 1992, fuel and purchased power costs increased $30.7 million or 12.1% and $8.8 million or 3.6%, respectively, due to higher unit sales in both years and the contractual obligations discussed above including addition- al power purchases from certain gas-fired independent power producing (IPP) facilities. Both 1993 and 1992 reflect reduced purchases from Canal Electric Company's units and other oil-fired units. The increased costs for power from the IPPs and other sources were offset somewhat by lower Seabrook 1 costs in both years. Reflected in purchased power and fuel for 1993 and 1992 was a reduction in fuel costs of nearly $900,000 and $1.5 million, respectively, due to the closing of the Company's Cannon Street generating station in late 1992 and a decline in other Company generation. In addition, purchased power and fuel expense for 1993 and 1992 includes $5.1 million and $1.5 million, respectively, for capacity-related costs associated with certain purchased power contracts that were not recovered in revenues due to the mechanism established by the DPU. The impact of this under-recovery reduced net income by $3.1 million and $906,000 in 1993 and 1992, respectively. (Refer to the "Purchased Power" section in Item 1 on page 6 of this report.) As more fully discussed in the "Energy Mix" section of Item 1 of this report, the Company's energy mix has shifted during the last several years PAGE 13 COMMONWEALTH ELECTRIC COMPANY from oil to natural gas and other types of generation due to the availability of capacity from IPP facilities and, to a lesser extent, an effort to reduce its reliance on oil. Oil-fired generation, although reduced from prior years' levels, still accounts for a major percentage of the Company's total sources, including purchased power. Reflected in the 1993 and 1992 cost is the increased use of a cleaner burning but more expensive (1% sulphur) fuel oil at Canal. Average oil prices in 1993 at Canal's generating plant were $14.02 per barrel as compared to $12.95 and $12.53 per barrel in 1992 and 1991, respectively. In compliance with restrictions on stack emissions, the Commonwealth of Massa- chusetts mandated a reduction in sulphur dioxide emissions requiring the periodic use of lower-sulphur (1%) content oil. In 1993, 1% oil averaged $15.16 per barrel for Canal, a 12.1% decrease from the $17.25 cost in 1992. However, lower-sulphur oil displaced 57.5% of the higher-sulphur (2.2%) content oil as compared to 24% in 1992. This higher cost oil is reflected in the total average cost per barrel for 1993 and 1992 but was not used at Canal in 1991. The price of oil at Canal is expected to average approximately $15.62 per barrel in 1994. Shown below is an analysis of fuel, purchased power and C&LM costs together with base rate components of retail electric revenue: Percent of Retail Electric Revenue 1993 1992 1991 Revenue components: Costs recovered in Fuel or Conservation Charges 52.2% 48.4% 57.6% Conservation and power costs in base rates 12.8 15.5 8.7 Base rates and other 35.0 36.1 33.7 100.0% 100.0% 100.0% Historically, revenue collected through base rates has been designed to reimburse the Company for all costs of operation other than fuel, purchased power and transmission expenses and provide a fair return on the capital invested in the business. As a result of the DPU's approval of new retail rates effective July 1, 1991, the Company was ordered to collect certain long- term capacity-related purchased power costs ($56.8 million in 1993, $52.9 million in 1992 and $26.2 million in 1991) and a portion of costs related to its C&LM programs ($8.6 million in 1992 and $8.3 million in 1991) through its base rates. Beginning February 1, 1992, the Company's recovery of C&LM costs were split from base rates through a separately stated Conservation Charge (CC) decimal based on KWH used. PAGE 14 COMMONWEALTH ELECTRIC COMPANY The following is an analysis of the Company's revenue components and current recoverable costs for the years 1993, 1992 and 1991: Years Ended December 31, 1993 1992 1991 (Dollars in Thousands) % % Retail electric revenue: Change Change Costs recovered in Fuel or Conservation Charges $210 717 12.4 $187 474 (19.2) $232 086 Conservation Charges and power costs in base rates 51 749 (14.0) 60 188 71.3 35 146 Base rates and other 141 555 1.4 139 579 3.0 135 531 Total retail revenue 404 021 4.3 387 241 (3.9) 402 763 Total wholesale revenue 26 463 18.9 22 252 8.7 20 476 Total revenue $430 484 5.1 $409 493 (3.2) $423 239 Other Operation In 1993, other operation decreased $7.3 million or 9.6% due to the absence in the current year of costs associated with the Company's Cannon Street generating station ($1.5 million) and the net savings of $1.1 million ($2.9 million in payroll savings less $1.8 million in severance costs) associated with the second quarter work force reduction which is expected to save more than $4 million annually in direct payroll costs. Also contributing to the lower costs in 1993 was the provision for bad debts expense which declined $2 million or 39.2% due to better payment experience reflecting improving economic conditions, lower affiliate services company charges ($1 million) due to the work force reduction and the absence in the current year of consulting fees ($900,000) associated with the independent management audit conducted in 1992. Also contributing to the lower expense level in 1993 was a decline in employee medical and life insurance costs of $700,000 and lower liability insurance costs of $300,000 due to fewer and less costly claims. Offsetting these decreases somewhat was an increase in pension costs of $600,000. Major factors contributing to the 4.7% increase in other operation in 1992 were the higher cost ($1.2 million) of medical and other types of insurance and approximately $900,000 for consulting fees associated with the aforemen- tioned management audit. Also, computer-related and other professional services provided to the Company by an affiliate services company were higher by $1.2 million in 1992. The provision for bad debts increased by $70,000 reflecting the difficult economic conditions in the Company's service territo- ry and a decline in fuel assistance programs. Certain factors offsetting these increases were: 1) a $1.7 million reduction in net pension expense as a result of asset valuation changes and the Company's deferral of $1.4 million of accrued pension costs pursuant to current rate-making; and 2) continued positive results from the Company's cost containment efforts, including reduced overtime, work force reductions through attrition, early retirements and the elimination of forty positions and associated costs relating to the closing of the Company's Cannon Street generating station on October 1. PAGE 15 COMMONWEALTH ELECTRIC COMPANY The total number of full-time employees declined 17.6% to 917 in 1993 from 1,113 employees at year-end 1991. Management views the current work force level to be appropriate for service to its customers. Maintenance Maintenance continued to decrease in 1993 from 1992 and 1991 levels due primarily to reduced transmission and distribution-related costs and, to a lesser extent, the decreased use and subsequent closing of the Cannon Street facility. Depreciation, Conservation and Load Management and Taxes Depreciation expense was virtually unchanged compared to 1992 reflecting a somewhat level depreciable plant base resulting from the abandonment of the Cannon Street generating station offsetting the impact of additions during the period. In 1992 depreciation expense rose 3.6% as a result of a higher level of plant in service, particularly additions to transmission and distribution facilities. C&LM costs for 1993 and 1992 included cash expenditures of $3.7 million and $8.1 million, respectively, and amortization of previously deferred costs which amounted to $500,000 in 1993 and $3.7 million in 1992. Income tax expense increased 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. In 1992, income tax expense decreased $1.3 million or 26.1% as a result of lower pretax income. The 1993 and 1992 increases in local property and other taxes reflect a combination of higher property tax rates and/or assessments in certain cities and towns in the Company's service area. Other Income and Interest Charges In 1993, the slight decrease in other income was due to the absence in 1993 of interest income from overpayment of Seabrook costs ($232,000) which were refunded to customers in 1992, a decrease in the interest on the unamor- tized portion of prior period conservation and load management program costs ($71,000) and a loss ($38,000) resulting from the disposition of the Cannon Street station oil inventory. This decrease was somewhat offset by an increase in interest income ($201,000) from loans to affiliated companies and a reduction in other income deductions ($117,000) that reflects a $75,000 reversal (in the third quarter of 1993) of a 1992 charge related to the Company's 2.5% interest in the Yankee Atomic Power Company. This reversal was made as a result of a Federal Energy Regulatory Commission audit in late 1993. The decline in other income in 1992 was due to a decrease in interest income ($208,000) from overpayment of Seabrook costs which were recovered in early 1992 and the inclusion in 1992 of industry-related membership fees ($120,000) in other income deductions which were included in other operation expense in 1991. Also included in 1992 is the Company's write-off of Hurri- cane Bob (August 1991) expenses of $9.2 million ($5.7 million after-tax) which had been deferred in 1991 and an equal after-tax amount of the regulatory PAGE 16 COMMONWEALTH ELECTRIC COMPANY liability related to deferred income taxes that would have otherwise been returned to customers. In 1993, short-term interest charges decreased $2.5 million due to lower interest rates and a lower average level of borrowings. Interest rates on short-term borrowings averaged 3.4% in 1993 compared to 4% in 1992. In addi- tion, 1993 reflects the absence of interest paid to customers in 1992 ($232,000) relating to the overcollection of Seabrook costs. The decreases in short-term interest charges were nearly offset by increases in long-term charges of $2.4 million in 1993, reflecting the issuance of $65 million in new long-term debt in March 1993. Total interest charges decreased 3.6% in 1992 due to the 9.7% decline in short-term interest charges ($456,000) and the 3.1% decline in long-term interest charges ($348,000). Despite a higher average level of short-term borrowings created, in part, by the retirement of the Company's $7.5 million Series D Note, short-term interest declined due to lower interest rates on bank borrowings which averaged 4% for 1992 as compared to 6.3% for 1991. In addition, accrued interest on the overcollection of Seabrook 1 costs noted above decreased $208,000. Financing Activity On March 31, 1993, the Company issued long-term notes totaling $65 million. The notes, which were sold through a private placement with institu- tional investors, consisted of the following: 10 Year, 7.43% Notes, Due 2003 $15,000,000 15 Year, 7.70% Notes, Due 2008 10,000,000 20 Year, 7.98% Notes, Due 2013 25,000,000 30 Year, 8.47% Notes, Due 2023 15,000,000 $65,000,000 The proceeds from the notes, together with the proceeds from the Company's sale of 437,500 shares of common stock to the System for $35 million, were used to repay outstanding short-term borrowings incurred to temporarily finance additions to property, plant and equipment and to retire $21.8 million of three series of long-term debt on March 1, 1993, as follows: Series E, 8.125% Notes, Due 1995 $ 4,860,000 Series B, 6.125% Notes, Due 1997 4,440,000 Series F, 8.375% Notes, Due 1998 12,000,000 $21,300,000 The Company paid a premium totaling $337,000 on the early retirement of debt and is amortizing this amount to expense over the remaining original life of the retired issues. New Accounting Standards Effective January 1, 1993, the Company adopted the provisions of State- ment of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." For further information, refer to Note 4(b) of the Notes to Financial Statements. PAGE 17 COMMONWEALTH ELECTRIC COMPANY In 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemploy- ment Benefits" (SFAS 112). The Company is required to adopt this statement effective January 1, 1994. SFAS 112 requires employers to recognize the obligation to provide benefits to former or inactive employees after employ- ment but before retirement (postemployment). Those benefits include salary continuation, supplemental employment benefits, severance benefits, disabili- ty-related benefits and continuation of health care and life insurance coverage if each of the following conditions are met: 1) the obligation is attributable to employee services already rendered, 2) employees' rights to those benefits accumulate or vest, 3) payment of the benefits is probable and 4) the cost of the benefits can be reasonably estimated. The Company believes that the adoption of the provisions of SFAS 112 will not have a material impact on its financial position or results of operations. Item 8. Financial Statements and Supplementary Data The Company's financial statements required by this item are filed here- with on pages 18 through 37 of this report. Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. PAGE 18 COMMONWEALTH ELECTRIC COMPANY Item 8. Financial Statements and Supplementary Data REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Commonwealth Electric Company: We have audited the accompanying balance sheets of COMMONWEALTH ELECTRIC COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Common- wealth Energy System) as of December 31, 1993 and 1992, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based upon our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Commonwealth Electric Company as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting princi- ples. As discussed in Note 4 to the financial statements, effective January 1, 1993, the Company changed its method of accounting for costs associated with postretirement benefits other than pensions. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to financial statements and schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Arthur Andersen & Co. Boston, Massachusetts, February 17, 1994. PAGE 19 COMMONWEALTH ELECTRIC COMPANY INDEX TO FINANCIAL STATEMENTS AND SCHEDULES PART II. FINANCIAL STATEMENTS Balance Sheets at December 31, 1993 and 1992 Statements of Income for the Years Ended December 31, 1993, 1992 and 1991 Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991 Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 Notes to Financial Statements PART IV. SCHEDULES III Investments in, Equity in Earnings of, and Dividends Received from Related Parties for the Years Ended December 31, 1991, 1992 and 1993 V Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 VI Accumulated Depreciation of Property, Plant and Equipment for the Years Ended December 31, 1993, 1992 and 1991 VIII Valuation and Qualifying Accounts for the Years Ended December 31, 1993, 1992 and 1991 IX Short-Term Borrowings for the Years Ended December 31, 1993, 1992 and 1991 SCHEDULES OMITTED All other schedules are not submitted because they are not applicable or not required or because the required information is included in the financial statements or notes thereto. Financial statements of 50% or less owned companies accounted for by the equity method have been omitted because they do not, considered individually, constitute a significant subsidiary. PAGE 20 COMMONWEALTH ELECTRIC COMPANY BALANCE SHEETS DECEMBER 31, 1993 AND 1992 ASSETS 1993 1992 (Dollars in Thousands) PROPERTY, PLANT AND EQUIPMENT, at original cost $475 348 $476 839 Less - Accumulated depreciation 133 349 135 684 341 999 341 155 Add - Construction work in progress 5 478 4 794 347 477 345 949 INVESTMENTS Equity in nuclear electric power company 601 601 Other 14 14 615 615 CURRENT ASSETS Cash 2 794 507 Advances to affiliates 4 485 - Accounts receivable - Affiliated companies 2 413 3 906 Customers, less reserves of $3,268,000 in 1993 and $3,131,000 in 1992 38 743 36 366 Unbilled revenues 9 332 15 444 Inventories, at average cost - Materials and supplies 4 658 6 040 Electric production fuel oil 202 485 Prepaid property taxes 2 538 2 380 Other 1 927 1 547 67 092 66 675 DEFERRED CHARGES (Notes 1, 2 and 4) 34 619 25 300 $449 803 $438 539 PAGE 21 COMMONWEALTH ELECTRIC COMPANY BALANCE SHEETS DECEMBER 31, 1993 AND 1992 CAPITALIZATION AND LIABILITIES 1993 1992 (Dollars in Thousands) CAPITALIZATION Common Equity - Common stock, $25 par value - Authorized and outstanding - 2,043,972 shares in 1993 and 1,606,472 shares in 1992, wholly-owned by Commonwealth Energy System (Parent) $ 51 099 $ 40 162 Amounts paid in excess of par value 97 112 73 049 Retained earnings (Note 6) 15 118 14 882 163 329 128 093 Long-term debt, including premiums, less current sinking fund requirements (Note 5) 158 858 116 213 322 187 244 306 CURRENT LIABILITIES Interim Financing (Note 5) - Notes payable to banks - 67 275 Advances from affiliates - 11 840 - 79 115 Other Current Liabilities - Current sinking fund requirements 1 053 537 Accounts payable - Affiliated companies 10 088 10 797 Other 22 044 17 231 Accrued taxes - Local property and other 3 017 2 637 Income 2 337 610 Accrued interest 4 027 3 092 Other 9 098 7 003 51 664 41 907 51 664 121 022 DEFERRED CREDITS Accumulated deferred income taxes 39 396 34 346 Unamortized investment tax credits 8 430 8 876 Other 28 126 29 989 75 952 73 211 COMMITMENTS AND CONTINGENCIES (Note 2) $449 803 $438 539 The accompanying notes are an integral part of these financial statements. PAGE 22 COMMONWEALTH ELECTRIC COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 1993 1992 1991 (Dollars in Thousands) ELECTRIC OPERATING REVENUES $430 484 $409 493 $423 239 OPERATING EXPENSES Electricity purchased for resale and fuel 284 980 254 316 245 561 Transmission 4 836 5 240 7 071 Other operation 68 797 76 072 72 642 Maintenance 10 714 12 143 12 855 Depreciation 15 032 15 012 14 484 Conservation and load management 4 165 11 826 34 199 Taxes - Income (Note 3) 7 158 3 556 4 814 Local property 5 023 4 694 3 730 Payroll and other 3 066 3 046 3 141 403 771 385 905 398 497 OPERATING INCOME 26 713 23 588 24 742 OTHER INCOME, net 249 253 511 INCOME BEFORE INTEREST CHARGES 26 962 23 841 25 253 INTEREST CHARGES Long-term debt 13 252 10 891 11 239 Other interest charges 1 738 4 248 4 704 Allowance for borrowed funds used during construction (106) (302) (547) 14 884 14 837 15 396 NET INCOME $ 12 078 $ 9 004 $ 9 857 The accompanying notes are an integral part of these financial statements. PAGE 23 COMMONWEALTH ELECTRIC COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 1993 1992 1991 (Dollars in Thousands) Balance at beginning of year $14 882 $14 151 $12 246 Add (Deduct): Net income 12 078 9 004 9 857 Cash dividends on common stock (11 842) (8 273) (7 952) Balance at end of year $15 118 $14 882 $14 151 The accompanying notes are an integral part of these financial statements. PAGE 24 COMMONWEALTH ELECTRIC COMPANY STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 1993 1992 1991 (Dollars in Thousands) OPERATING ACTIVITIES Net income $ 12 078 $ 9 004 $ 9 857 Effects of non-cash items - Depreciation and amortization 16 447 19 666 25 224 Deferred income taxes 4 407 (5 176) (729) Investment tax credits (446) (452) (482) Earnings from corporate joint ventures - (75) (73) Change in working capital exclusive of cash and interim financing - Accounts receivable and unbilled revenues 5 228 7 119 (7 485) Income taxes, net 1 727 (3 705) (2 280) Local property and other taxes, net 222 (25) 390 Accounts payable and other 8 935 (2 159) 4 608 Uncollected postretirement benefits costs (Note 4) (4 087) - - All other operating items (5 590) 7 580 (10 856) Net cash provided by operating activities 38 921 31 777 18 174 INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) (18 631) (20 821) (31 303) Allowance for borrowed funds used during construction (106) (302) (547) Advances to affiliates (4 485) - - Net cash used for investing activities (23 222) (21 123) (31 850) FINANCING ACTIVITIES Long-term debt issues 65 000 - - Sale of common stock to Parent 35 000 - - Payment of dividends (11 842) (8 273) (7 952) Proceeds from (payment of) short-term borrowings (67 275) 3 975 15 050 Advances from (payment to) affiliates (11 840) 2 290 7 215 Long-term debt issues refunded (21 300) (7 522) - Retirement of long-term debt through sinking funds (1 155) (631) (636) Net cash provided by (used for) financing activities (13 412) (10 161) 13 677 Net increase in cash 2 287 493 1 Cash at beginning of period 507 14 13 Cash at end of period $ 2 794 $ 507 $ 14 The accompanying notes are an integral part of these financial statements. PAGE 25 COMMONWEALTH ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS (1) Significant Accounting Policies (a) General and Regulatory Commonwealth Electric Company (the Company) is a wholly-owned subsidiary of 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 Company is regulated as to rates, accounting and other matters by various authorities including the Federal Energy Regula- tory Commission (FERC) and the Massachusetts Department of Public Utilities (DPU). The System is an exempt holding company under the provisions of the Public Utility Holding Company Act of 1935 and, in addition to its investment in the Company, has interests in other utility companies and several non- regulated companies. The Company has 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. At December 31, 1993, principal regulatory assets included in deferred charges were $8.6 million for unrecovered plant and decommissioning costs for the Yankee Atomic nuclear plant, $7.4 million in litigation costs associated with a settlement agreement with Boston Edison Company relative to the Pilgrim nuclear power plant, $4.4 million in abandon- ment costs for the Cannon Street generating station and $4.1 million for postretirement benefits costs. The more significant regulatory liabilities, reflected in deferred credits, include $8.6 million related to the Yankee Atomic nuclear plant and $4 million related to income taxes. (b) Reclassifications Certain prior year amounts are reclassified from time to time to conform with the presentation used in the current year's financial statements. (c) Transactions with Affiliates Transactions between the Company and other system companies include purchases and sales of electricity, including purchases from Canal Electric Company (Canal), an affiliate wholesale electric generating company. Other costs billed by Canal relate to the abandonment of Seabrook 2 for the three years ending in 1993 and the recovery of a portion of Seabrook 1 pre-commer- cial operation financing costs in 1991. In addition, payments for management, accounting, data processing and other services are made to affiliate COM/Ener- gy Services Company. Transactions with other system companies are subject to review by the DPU. The Company's operating revenues include the following major intercompany transactions for the periods indicated: Purchased Power and Transmission Period Ended Purchased Power Purchased Power From Canal December 31, Canal Units Seabrook 1 As Agent (Dollars in Thousands) 1993 $40 537 $36 467 $20 881 1992 46 844 37 482 22 992 1991 53 547 50 912 26 422 PAGE 26 COMMONWEALTH ELECTRIC COMPANY The Company sold electricity to other affiliates, primarily station service for Canal, totaling $2,973,000, $2,733,000 and $8,065,000 in 1993, 1992 and 1991, respectively, and the Company also purchased natural gas from affiliate Commonwealth Gas Company totaling $106,000 in 1992 and $1,288,000 in 1991 (there were no purchases in 1993). (d) Operating Revenues Customers are billed for their use of electricity on a cycle basis throughout the month. To reflect revenues in the proper period, the estimated amount of unbilled sales revenue is recorded each month. The Company is generally permitted to bill customers currently for fuel used in electric production, purchased power and transmission costs, and conservation and load management costs through adjustment clauses. Amounts recoverable under these clauses are subject to review and adjustment by the DPU. The Company collects 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 $3,056,000 in 1993 and $6,918,000 in 1992, is recorded as unbilled revenues. (e) Depreciation Depreciation is provided using the straight-line method at rates intended to amortize the original cost and the estimated cost of removal less salvage of properties over their estimated economic lives. The average composite depreciation rates were 3.31% in 1993 and 3.39% in 1992 and 1991. (f) Maintenance Expenditures for repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expense. Additions, replacements and renewals of property considered to be units of property are charged to the appropriate plant accounts. Upon retirement, accumulated depreciation is charged with the original cost of property units and the cost of removal less salvage. (g) Allowance for Funds Used During Construction Under applicable rate-making practices, the Company is permitted to include an allowance for funds used during construction (AFUDC) as an element of its depreciable property costs. This allowance is based on the amount of construction work in progress that is not included in the rate base on which the Company earns a return. An amount equal to the AFUDC capitalized in the current period is reflected in the accompanying Statements of Income. While AFUDC does not provide funds currently, these amounts are recover- able in revenues over the service life of the constructed property. The amount of AFUDC recorded was at a weighted average rate of 4% in 1993, 4.50% in 1992 and 6.75% in 1991. PAGE 27 COMMONWEALTH ELECTRIC COMPANY (2) Commitments and Contingencies (a) Financing and Construction Programs The Company is engaged in a continuous construction program presently estimated at $141 million for the five-year period 1994 through 1998. Of that amount, $24.8 million is estimated for 1994. The program is subject to periodic review and revision because of factors such as changes in business conditions, rates of customer growth, effects of inflation, maintenance of reliable and safe service, equipment delivery schedules, licensing delays, availability and cost of capital and environmental factors. The Company expects to finance these expenditures on an interim basis with internally generated funds and short-term borrowings which are ultimately expected to be repaid with the proceeds from sales of long-term debt and equity securities. (b) Power Contracts The Company has long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require that the Company pay a demand charge for the capacity entitlement and an energy charge to cover the cost of fuel. In addition, the Company pays its share of decommissioning expense to non-affiliate Boston Edison Company, the operator of the Pilgrim nuclear facility, as a cost of electricity purchased for resale. The Company has entered into Power Contracts with Canal for a portion of the capacity from Canal Units 1 and 2. In addition, Canal seeks to secure bulk electric power on a single system basis to provide cost savings for the customers of the Company and Cambridge Electric under terms of a Capacity Acquisition and Disposition Agreement (CADA) which has been accepted for filing as an amendment to Canal's rate schedule by the FERC. The CADA allows Canal to act as agent for the Company and Cambridge Electric in the procure- ment of additional capacity for one or both companies, or, to sell a portion of each company's entitlement of capacity and/or energy produced by Canal Unit 2. Such "Commitments" are in effect for Seabrook 1, Phases I and II of Hydro- Quebec, New England Power Company (Bear Swamp Units), Green Mountain Power Corporation, Northeast Utilities and for Central Vermont Public Service Corp. (Vermont Yankee and Merrimac 2 Unit). Exchange agreements are in place with several of these utilities whereby, in certain circumstances, it is possible to exchange capacity so that the mix of power improves the pricing for dispatch for both the seller and the purchaser. Power contracts are in place, whereby Canal bills or credits the Company and Cambridge Electric for the costs or revenues received associated with these facilities. The Company and Cambridge Electric, in turn, have billed or are billing these net charges (net of revenues from sales) to their customers through rates which are subject to DPU approval. PAGE 28 COMMONWEALTH ELECTRIC COMPANY Pertinent information with respect to life-of-the-unit contracts for power from the Pilgrim unit and an ownership in Central Maine Power Company's Wyman Unit 4, an oil-fired unit, is as follows: Wyman Pilgrim Unit 4 (Dollars in Thousands) Joint Ownership - 1.4% Plant Entitlement 11.0% 1.4% Plant Capability (MW) 664.7 619.2 Company's Entitlement (MW) 73.1 8.8 Contract Expiration Date 2012 - 1991 Actual Cost $30 992 $296 1992 Actual Cost 37 516 332 1993 Actual Cost 40 578 163 1994 Estimated Cost 41 963 205 The Company has also contracted to purchase power and transmission capacity from various other generating and transmission facilities as follows: Estimated 1991 1992 1993 1994 MW Cost MW Cost MW Cost MW Cost (Dollars in Thousands) Purchased Power - Nuclear 82.6 $42 016 6.8 $ 1 560 3.7 $ 1 187 2.2 $ 506 Hydro 30.9 13 052 14.0 11 784 15.1 9 731 15.0 11 087 Cogenerating 117.0 34 938 162.0 69 742 161.0 104 719 261.5 135 363 Waste-to-energy and other 92.1 33 009 78.9 31 336 74.7 36 013 72.1 35 862 Transmission - (Hydro-Quebec) - 3 884 - 2 991 - 3 015 - 3 165 Costs under these and other contracts are included in electricity pur- chased for resale and fuel in the accompanying Statements of Income and are recoverable in revenues through either the Fuel Charge or in base rates. (c) Yankee Atomic Nuclear Power Plant On February 26, 1992, the Board of Directors of Yankee Atomic Electric Company agreed to permanently discontinue power operation of its plant and, in time, decommission that facility. This plant provided less than 1% of the Company's capacity. The Company's 2.5% investment in Yankee Atomic is approximately $600,000. Presently, purchased power costs, which include a provision for ultimate decommissioning of the unit, are billed to the Company and collected from customers. The Company has estimated its unrecovered share of all costs associated with the shutdown of the facility, recovery of its respective plant investment and decommissioning and closing the plant to be approximately $8.6 million. This amount is reflected in the accompanying Balance Sheets as a liability and a corresponding regulatory asset at December 31, 1993. PAGE 29 COMMONWEALTH ELECTRIC COMPANY (d) Environmental Matters The Company is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installa- tion of expensive air and water pollution control equipment. These regula- tions have had an impact upon the Company's operations in the past and will continue to have an impact upon future operations, capital costs and construc- tion schedules of major facilities. (3) Income Taxes For financial reporting purposes, the Company provides federal and state income taxes on a separate return basis. However, for federal income tax purposes, the Company's taxable income and deductions are included in the consolidated income tax return of the System and it makes tax payments or receives refunds on the basis of its tax attributes in the tax return in accordance with applicable regulations. The following is a summary of the Company's provisions for income taxes for the years ended December 31, 1993, 1992 and 1991. 1993 1992 1991 (Dollars in Thousands) Federal Current $ 2 627 $ (15) $ 4 948 Deferred 3 705 (4 548) (668) Investment tax credits (446) (452) (482) 5 886 (5 015) 3 798 State Current 570 (34) 1 057 Deferred 749 348 (61) 1 319 314 996 7 205 (4 701) 4 794 Amortization of regulatory liability relating to deferred income taxes (47) (976) - $ 7 158 $(5 677) $ 4 794 Federal and state income taxes charged to: Operating expense $ 7 158 $ 3 556 $ 4 814 Other income - (9 233) (20) $ 7 158 $(5 677) $ 4 794 Effective January 1, 1992, the Company 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 tax rates in effect in the year in which the differences are expected to reverse. PAGE 30 COMMONWEALTH ELECTRIC COMPANY Accumulated deferred income taxes consisted of the following in 1993 and 1992: 1993 1992 (Dollars in Thousands) Liabilities Property-related $44 837 $40 483 Litigation costs 2 886 2 957 Postretirement benefits plan 2 222 376 All other 1 918 2 050 51 863 45 866 Assets Investment tax credit 5 441 5 507 Pension plan 1 384 1 302 Regulatory liability - 630 Uncollectible accounts 1 282 1 137 All other 2 463 1 706 10 570 10 282 Accumulated deferred income taxes $41 293 $35 584 The year-end deferred income tax liability above includes a current deferred tax liability of $1,897,000 in 1993 and $1,238,000 in 1992 which was reported in accrued income taxes in the accompanying Balance Sheets. The following table, detailing the significant timing differences for 1991 which resulted in deferred income taxes, is required to be disclosed pursuant to accounting standards for income taxes in effect prior to adoption of SFAS No. 109: 1991 (Dollars in Thousands) Accelerated depreciation $ 3 593 Seabrook power contract settlement (2 229) Capitalized interest during construction (150) Contributions in aid of construction (451) Capitalized leases (579) Pension costs and deferred compensation (394) Conservation and load management (4 370) Replacement power costs 1 656 Transmission costs (508) Storm damage 3 638 Voluntary retirement program (20) Other (915) Deferred income tax provision $ (729) PAGE 31 COMMONWEALTH ELECTRIC COMPANY The total income tax provision set forth above represents 37% in 1993, (171)% in 1992 and 33% in 1991 of income before such taxes. The following table reconciles the statutory federal income tax rate to these percentages: 1993 1992 1991 (000's) Federal statutory rate 35% 34% $ 1 131 34% Increase (Decrease) from statutory rate: Amortization of regulatory liability relating to deferred income taxes - (173) (5 768) - State tax net of federal tax benefit 4 7 228 5 Amortization of investment tax credit (2) (14) (452) (3) Tax versus book depreciation 1 3 111 1 Amortization of excess deferred reserves - (28) (920) (3) Other (1) - (7) (1) Effective federal tax rate 37% (171)% $(5 677) 33% On April 22, 1992, the Company reached a settlement agreement with the Attorney General of Massachusetts and a consumer group, which was approved by the DPU. The settlement resulted in the issuance of an accounting order authorizing the Company's 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, the Company 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 the Company 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 Company's federal income tax rate increased to 35% effective January 1, 1993. (4) Employee Benefit Plans (a) Pension The Company has a noncontributory pension plan covering substantially all regular employees who have attained the age of 21 and have completed a year of service. Pension benefits are based on an employee's years of service and compensation. The Company makes monthly contributions to the plan consistent with the funding requirements of the Employee Retirement Income Security Act of 1974. PAGE 32 COMMONWEALTH ELECTRIC COMPANY Components of pension expense were as follows: 1993 1992 1991 (Dollars in Thousands) Service cost $ 2 630 $ 2 728 $ 2 815 Interest cost 9 283 8 506 7 532 Return on plan assets (16 412) (10 992) (20 677) Net amortization and deferral 9 130 4 235 15 209 Total pension expense 4 631 4 477 4 879 Transfers to affiliated companies, net (465) (609) (575) Less: Amounts capitalized and deferred 1 379 2 127 839 Net pension expense $ 2 787 $ 1 741 $ 3 465 The following economic assumptions were used to measure year-end obliga- tions and the estimated pension expense for the subsequent year: 1993 1992 1991 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. The Company, in accordance with current rate-making, is 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 Company's pension plan (using a measurement date of December 31) is as follows: 1993 1992 (Dollars in Thousands) Accumulated benefit obligation: Vested $ (95 433) $ (74 178) Nonvested (13 030) (5 815) $(108 463) $ (79 993) Projected benefit obligation $(131 066) $(104 024) Plan assets at fair market value 120 685 107 529 Projected benefit obligation less (greater) than plan assets (10 381) 3 505 Unamortized transition obligation 5 146 5 789 Unrecognized prior service cost 5 520 4 139 Unrecognized gain (5 095) (17 321) Accrued pension liability $ (4 810) $ (3 888) 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. The increase in the accumulated benefit obligation and the projected benefit obligation from December 31, 1992 to December 31, 1993 was primarily due to a reduction of the discount rate in light of current interest rates. PAGE 33 COMMONWEALTH ELECTRIC COMPANY (b) Other Postretirement Benefits Through December 31, 1992, the Company 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 the Company or another subsidiary of the System. As of January 1, 1993, the Company eliminated postretirement health care benefits for those nonbargaining 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 bargain- ing employees are also participating under these new eligibility requirements. Effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postre- tirement Benefits Other Than Pensions" (SFAS No. 106). This new standard requires the accrual of the expected cost of such benefits during the employ- ees' years of service and the recognition of an actuarially determined postre- tirement benefit obligation earned by existing retirees. The assumptions and calculations involved in determining the accrual and the accumulated postre- tirement benefit obligation (APBO) closely parallel pension accounting requirements. The cumulative effect of implementation of SFAS No. 106 as of January 1, 1993 was approximately $48.3 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 insur- ance benefits under the traditional pay-as-you-go method totaled $1,915,000 during 1992 and $1,668,000 in 1991. In 1993, the Company began making contributions to various voluntary employee beneficiary association (VEBA) trusts that were established pursuant to section 501(c)9 of the Internal Revenue Code (the Code). The Company also made contributions to a sub-account of its pension plan pursuant to section 401(h) of the Code to satisfy a portion of its postretirement benefit obliga- tion. The Company contributed approximately $5,964,000 to these trusts during 1993. The net periodic postretirement benefit cost for the year ended December 31, 1993 included the following components: 1993 (Dollars in Thousands) Service cost $ 1 093 Interest cost 4 103 Return on plan assets (292) Amortization of transition obligation over 20 years 2 417 Net amortization and deferral 3 Total postretirement benefit cost 7 324 Less: Amounts capitalized and deferred 5 701 Net postretirement benefit cost $ 1 623 PAGE 34 COMMONWEALTH ELECTRIC COMPANY The funded status of the Company's postretirement benefit plan using a measurement date of December 31, 1993 is as follows: 1993 (Dollars in Thousands) Accumulated postretirement benefit obligation: Retirees $ (27 520) Active participants (23 033) (50 553) Plan assets at fair market value 5 308 Projected postretirement benefit obligation greater than plan assets (45 245) Unamortized transition obligation 45 917 Unrecognized gain (672) $ - In determining its estimated APBO and the funded status of the plan, the Company assumed a discount rate of 7.25%, an expected long-term rate of return on plan assets of 8.5%, and a medical care cost trend rate of 9%, which gradually decreases to 5% in the year 2007 and remains at that level thereaf- ter. The estimate also reflects a trend rate of 14.9% for reimbursement of Medicare Part B premiums which decreases to 5% by 2007 and a dental care trend rate of 5% in all years. A one percent change in the medical trend rate would have an $836,000 impact on the Company's annual expense (interest component - $564,000; service cost - $272,000) and would change the accumulated benefit obligation by $6.9 million. Plan assets consist primarily of fixed income and equity securities. Fluctuations in the fair market value of plan assets will affect postretire- ment 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 Electric 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 Company intends to seek recovery in its next rate proceeding. While the Company is unable to predict the outcome of that rate proceeding, it believes the DPU will authorize similar rate treat- ment as provided to Cambridge Electric and other Massachusetts electric and gas companies for the recovery of the cost of these benefits. Further, based on recent DPU action and discussions with regulators, the Company believes that it is appropriate to record the difference between the amount included in rates and SFAS No. 106 costs as a regulatory asset. At December 31, 1993, this deferral amounted to approximately $4.1 million. (c) Savings Plan The Company has an Employees Savings Plan that provides for Company contributions equal to contributions by eligible employees of up to four percent of each employee's compensation rate. Effective January 1, 1993, the rate was increased to five percent for those employees no longer eligible for postretirement benefits other than pensions. The Company's contribution was $1,700,000 in 1993, $1,808,000 in 1992 and $1,703,000 in 1991. PAGE 35 COMMONWEALTH ELECTRIC COMPANY (5) Long-Term Debt and Interim Financing (a) Long-Term Debt Maturities and Retirements Long-term debt outstanding, exclusive of current maturities, current sinking fund requirements and related premiums, is as follows: Original Balance December 31, Issue 1993 1992 (Dollars in Thousands) 25-Year Notes - Series E, 8 1/8%, due 1995 $ 9 000 $ - $ 4 860 Series F, 8 3/8%, due 1998 20 000 - 12 000 30-Year Notes - Series B, 6 1/8%, due 1997 6 000 - 4 440 15-Year Term Loan, 9.30%, due 2002 30 000 30 000 30 000 25-Year Term Loan, 9.37%, due 2012 20 000 18 947 20 000 10-Year Notes, 7.43%, due 2003 15 000 15 000 - 15-Year Notes, 9.50%, due 2004 15 000 15 000 15 000 15-Year Notes, 7.70%, due 2008 10 000 10 000 - 18-Year Notes, 9.55%, due 2007 10 000 10 000 10 000 20-Year Notes, 7.98%, due 2013 25 000 25 000 - 25-Year Notes, 9.53%, due 2014 10 000 10 000 10 000 30-Year Notes, 9.60%, due 2019 10 000 10 000 10 000 30-Year Notes, 8.47%, due 2023 15 000 15 000 - $158 947 $116 300 The balance of long-term debt at December 31, 1992 was exclusive of $103,000 principal amount purchased by the Company and deposited with the Trustee in anticipation of future sinking fund requirements. The Company may continue to purchase its outstanding notes in advance of sinking fund require- ments under favorable conditions. Under terms of its Indentures of Trust, the Company is required to make periodic sinking fund payments for retirement of outstanding long-term debt. The required sinking fund payments for the five years subsequent to December 31, 1993 are as follows: Year Sinking Funds (Dollars in Thousands) 1994 $1 053 1995 1 053 1996 3 553 1997 3 553 1998 3 553 (b) Notes Payable to Banks The Company and other 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, 1993, system companies had $115 million of committed lines of credit that will expire at varying intervals in 1994. These lines are normally renewed upon expiration PAGE 36 COMMONWEALTH ELECTRIC COMPANY and require annual fees up to .1875% of the individual line. At December 31, 1993, the uncommitted lines of credit totaled $70 million. Interest rates on the outstanding borrowings generally are at an adjusted money market rate. At December 31, 1993, the Company had no notes payable to banks. The Company had short-term notes payable to banks totaling $67,275,000 at December 31, 1992. (c) Advances from Affiliates At December 31, 1993, the Company had no notes payable to the System. The Company had short-term notes payable to the System totaling $8,445,000 at December 31, 1992. These notes are written for a term of eleven months and twenty-nine days. Interest is at the prime rate (6% at December 31, 1992) and is adjusted for changes in the rate during the term of the notes. The Company is a member of the COM/Energy Money Pool (the Pool), an arrangement among the subsidiaries of the System, whereby short-term cash surpluses are used to help meet the short-term borrowing needs of the utility subsidiaries. In general, lenders to the Pool receive a higher rate of return than they otherwise would on such investments, while borrowers pay a lower interest rate than those available from banks. The Company had $4,485,000 invested in the Pool at December 31, 1993, but had borrowings from the Pool of $3,395,000 at December 31, 1992. (d) Disclosures about Fair Value of Financial Instruments As required by Statement of Financial Accounting Standards No. 107, "Disclosures about Fair Value of Financial Instruments," the fair value of certain financial instruments included in the accompanying Balance Sheets as of December 31, 1993 and 1992 are as follows: 1993 1992 (Dollars in Thousands) Carrying Fair Carrying Fair Value Value Value Value Long-Term Debt $159 911 $184 180 $116 750 $128 600 The carrying amount of cash, advances to/from affiliates and notes payable to banks approximates the fair value because of the short maturity of the instruments. The estimated fair value of long-term debt is based upon quoted market prices of the same or similar issues or on the current rates offered for debt with the same remaining maturity. The fair values shown above do not purport to represent the amounts at which those obligations would be settled. (6) Dividend Restriction At December 31, 1993, approximately $11,700,000 of retained earnings was restricted against the payment of cash dividends by terms of the Indenture of Trust securing long-term debt. As of the same date, retained earnings also included approximately $218,000 representing the Company's equity in undis- tributed earnings of Yankee Atomic Electric Company. PAGE 37 COMMONWEALTH ELECTRIC COMPANY (7) Lease Obligations The Company leases equipment and office space under arrangements that are classified as operating leases. These lease agreements are for terms of one year or longer. Leases currently in effect contain no provisions which prohibit the Company from entering into future lease agreements or obliga- tions. Future minimum lease payments, by period and in the aggregate, of non-can- celable operating leases consisted of the following at December 31, 1993: Operating Leases (Dollars in Thousands) 1994 $ 3 412 1995 2 832 1996 2 020 1997 773 1998 352 Beyond 1998 1 192 Total future minimum lease payments $10 581 Total rent expense for all operating leases, except those with terms of a month or less, amounted to $3,491,000 in 1993, $3,669,000 in 1992 and $3,783,000 in 1991. There were no contingent rentals and no sublease rentals for the years 1993, 1992 and 1991. (8) Supplemental Disclosures of Cash Flow Information The Company's supplemental information concerning cash flow activities is as follows: 1993 1992 1991 (Dollars in Thousands) Cash paid during the periods for: Interest (net of capitalized amounts) $ 13 074 $ 14 084 $ 14 714 Income taxes 2 438 1 491 6 275 PAGE 38 COMMONWEALTH ELECTRIC COMPANY PART IV. Item 14.Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. Index to Financial Statements Financial statements and notes thereto of the Company together with the Report of Independent Public Accountants, are filed under Item 8 of this report and listed on the Index to Financial Statements and Schedules (page 19). (a) 2. Index to Financial Statement Schedules Filed herewith at page(s) indicated - Schedule III - Investments in, Equity in Earnings of, and Dividends Received from Related Parties - Years Ended December 31, 1991, 1992 and 1993 (page 50). Schedule V - Property, Plant and Equipment - Years Ended December 31, 1993, 1992 and 1991 (pages 51-53). Schedule VI - Accumulated Depreciation of Property, Plant and Equip- ment - Years Ended December 31, 1993, 1992 and 1991 (page 54). Schedule VIII - Valuation and Qualifying Accounts - Years Ended Decem- ber 31, 1993, 1992 and 1991 (page 55). Schedule IX - Short-term Borrowings - Years Ended December 31, 1993, 1992 and 1991 (page 56). (a) 3. Exhibits: Notes to Exhibits - a. Unless otherwise designated, the exhibits listed below are incorporat- ed by reference to the appropriate exhibit numbers and the Securities and Exchange Commission file numbers indicated in parentheses. b. If applicable, as designated by an asterisk, certain documents previ- ously filed by the Company have been disposed of by the Commission pursuant to its Records Control Schedule and are hereby being refiled by the Company. c. During 1981, the Company sold its gas business and properties to Commonwealth Gas and changed its corporate name from New Bedford Gas and Edison Light Company to Commonwealth Electric Company. d. 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 CEL ...................... Cambridge Electric Light Company CEC ...................... Canal Electric Company CG ....................... Commonwealth Gas Company NBGEL .................... New Bedford Gas and Edison Light Co. PAGE 39 COMMONWEALTH ELECTRIC COMPANY Exhibit Index: Exhibit 3. Articles of incorporation and by-laws 3.1.1 By-laws of the Company as amended, (Refiled as Exhibit 1 to the CE 1991 Form 10-K, File No. 2-7749). 3.1.2 Articles of Incorporation, as amended, of NBGEL, including certif- ication of name change to Commonwealth Electric Company as filed with the Massachusetts Secretary of State on March 1, 1981 (Re- filed as Exhibit 1 to the CE 1990 Form 10-K, File No. 2-7749). Exhibit 4. Instruments defining the rights of security holders, including indentures. 4.1.1 Original Indenture on Form S-1 (Nov., 1948) (Exhibit 7(a), File No. 2-7749). 4.1.2 First Supplemental on Form S-1 (Oct., 1950) (Exhibit 7(a-1), File No. 2-8605). 4.1.3 Second Supplemental (Exhibit 1 to the CE 1984 Form 10-K, File No. 2-7749). 4.1.4 Third Supplemental on Form 8-K (Feb., 1962) (Exhibit A, File No. 2-7749). 4.1.5 Fourth Supplemental (Exhibit 2 to the CE 1984 Form 10-K, File No. 2-7749). 4.1.6 Fifth Supplemental (Exhibit 3 to the CE 1984 Form 10-K, File No. 2-7749). 4.1.7 Sixth Supplemental (Exhibit 4 to the CE 1984 Form 10-K, File No. 2-7749). 4.1.8 Seventh Supplemental on Form S-1 (Dec., 1975) (Exhibit 4(b)2, File No. 2-54955). Cape & Vineyard Electric Company**: 4.1.9 Original Indenture on Form S-1 (Apr., 1957) (Exhibit 4(b)1, File No. 2-26429). 4.1.10 First Supplemental (Exhibit 5 to the CE 1984 Form 10-K, File No. 2-7749). 4.1.11 Second Supplemental (Exhibit 6 to the CE 1984 Form 10-K, File No. 2-7749). **Merged with the Company on January 1, 1971 Exhibit 10. Material Contracts. 10.1 Power contracts. 10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1, File No. 2-30057). 10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and NBGEL dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 2 to the CE 1991 Form 10-K, File No. 2-7749). PAGE 40 COMMONWEALTH ELECTRIC COMPANY 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 1 to the CE Form 10-Q (June 1988), File No. 2-7749). 10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July 1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (Septem- ber 1989), File No. 2-7749). 10.1.3 Agreement between NBGEL and Boston Edison Company (BECO) for the purchase of electricity from BECO's Pilgrim Unit No. 1 dated Aug- ust 1, 1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.3.1 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). 10.1.3.2 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). 10.1.3.3 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). 10.1.4 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: 10.1.4.1 First through Fifth Amendments to 10.1.4 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 (No- vember 7, 1975), File No. 2-54995). 10.1.4.2 Sixth through Eleventh Amendments to 10.1.4 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). 10.1.4.3 Twelfth through Fourteenth Amendments to 10.1.4 as amended May 16, 1980, December 31, 1980 and June 1, 1982, respectively (Refiled as Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No.2-7749). 10.1.4.4 Fifteenth and Sixteenth Amendments to 10.1.4 as amended April 27, 1984 and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10-Q (June 1984), File No. 2-30057). 10.1.4.5 Seventeenth Amendment to 10.1.4 as amended March 8, 1985 (Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2-30057). 10.1.4.6 Eighteenth Amendment to 10.1.4 as amended March 14, 1986 (Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2-30057). 10.1.4.7 Nineteenth Amendment to 10.1.4 as amended May 1, 1986 (Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2-30057). PAGE 41 COMMONWEALTH ELECTRIC COMPANY 10.1.4.8 Twentieth Amendment to 10.1.4 as amended September 19, 1986 (Ex- hibit 1 to the CEC 1986 Form 10-K, File No. 2-30057). 10.1.4.9 Twenty-First Amendment to 10.1.4 as amended November 12, 1987 (Exhibit 1 to the CEC 1987 Form 10-K, File No. 2-30057). 10.1.4.10 Settlement Agreement and Twenty-Second Amendment to 10.1.4, both dated January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.5 Interim Agreement to Preserve and Protect the Assets of and In- vestment in the New Hampshire Nuclear Units dated April 27, 1984 (Exhibit 2 to the CEC Form 10-Q (June 1984), File No. 2-30057). 10.1.6 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). 10.1.7 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). 10.1.7.1 First Amendment to 10.1.7 as amended March 8, 1985 (Exhibit 2 to the CEC Form 10-Q (March 1985), File No. 2-30057). 10.1.7.2 Second through Fifth Amendments to 10.1.7 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). 10.1.8 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). 10.1.8.1 Agreement to transfer ownership, construction and operational interest in the Seabrook Units 1 and 2 from CE to CEC dated Janu- ary 2, 1981 (Refiled as Exhibit 3 to the CE 1991 Form 10-K, File No. 2-7749). 10.1.9 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). 10.1.10 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 sell- er'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). PAGE 42 COMMONWEALTH ELECTRIC COMPANY 10.1.11 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). 10.1.11.1 Amendments No. 2 and 3 to 10.1.11 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). 10.1.12 Contract between CEC and NBGEL and CEL, affiliated companies, for the sale of specified amounts of electricity from Canal Unit 2 dated January 12, 1976 (Exhibit 7 to the System's 1985 Form 10-K, File No. 1-7316). 10.1.13 Capacity Acquisition Agreement between CEC,CEL and CE dated Sep- tember 25, 1980 (Exhibit 1 to the CEC 1991 Form 10-K, File No. 2- 30057). 10.1.13.1 Supplement to 10.1.13 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). 10.1.13.2 Supplements to 10.1.13 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). 10.1.13.3 Amendment to 10.1.13 as amended and restated June 1, 1993, hence- forth referred to as the Capacity Acquisition and Disposition Agreement, whereby CEC, as agent, in addition to acquiring power may also sell bulk electric power which CEL and/or the Company owns or otherwise has the right to sell (Exhibit 1 to the CEC Form 10-Q (September 1993), File No. 2-30057). 10.1.13.4 Capacity Disposition Commitment dated June 25, 1993 by and between CEC (Unit 2) and the Company for the sale of a portion of the Com- pany's entitlement in Unit 2 to Green Mountain Power Corp.(Exhibit 2 to the CEC Form 10-Q (September 1993), File No. 2-30057). 10.1.14 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 (Refiled as Exhibits 5 and 6 to the 1992 CE Form 10-K, File No. 2-7749). 10.1.14.1 Amendment No. 2 to 10.1.14 as amended November 1, 1982 (Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.14.2 Amendment No. 3 to 10.1.14 as amended January 1, 1986 (Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749). PAGE 43 COMMONWEALTH ELECTRIC COMPANY 10.1.15 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). 10.1.15.1 Supplement Amending 10.1.15 as amended June 24, 1970 (Exhibit 8 to the CES Form S-7, Amendment No. 1, File No. 2-38372). 10.1.16 Power Purchase Agreement (Revised) between Weweantic Hydro Associ- ates and the Company for the purchase of available hydro-electric energy produced by a facility located in Wareham, MA, originally dated December 13, 1982, revised and dated March 12, 1993 (Filed as Exhibit 1 to the CE Form 10-Q (June 1993), File No. 2-7749). 10.1.17* Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for the purchase of available hydro-electric energy produced by a facility located in Ware, Massachusetts, dated September 1, 1983 (Refiled herewith as Exhibit 1). 10.1.18* Power Purchase Agreement between Corporation Investments, Inc. (CI), and CE for the purchase of available hydro-electric energy produced by a facility located in Lowell, Massachusetts, dated January 10, 1983 (Refiled herewith as Exhibit 2). 10.1.18.1 Amendment to 10.1.18 between CI and Boott Hydropower, Inc., an assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.19 Phase 1 Terminal Facility Support Agreement dated December 1, 1981, Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November 1, 1982, between New England Electric Transmission Corpo- ration (NEET), other New England utilities and CE (Exhibit 1 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.19.1 Amendment No. 3 to 10.1.19 (Exhibit 2 to the CE Form 10-Q (June 1986), File No. 2-7749). 10.1.20 Preliminary Quebec Interconnection Support Agreement dated May 1, 1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated June 1, 1982, Amendment No. 3 dated November 1, 1982, Amend- ment No. 4 dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.21 Agreement with Respect to Use of Quebec Interconnection dated December 1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated November 1, 1982 among certain NEPOOL utilities (Ex- hibit 3 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.21.1 Amendatory Agreement No. 3 to 10.1.21 as amended June 1, 1990, among certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September 1990), File No. 2-30057). PAGE 44 COMMONWEALTH ELECTRIC COMPANY 10.1.22 Phase I New Hampshire Transmission Line Support Agreement between NEET and certain other New England Utilities dated December 1, 1981 (Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749). 10.1.23 Agreement, dated September 1, 1985, with Respect To Amendment of Agreement With Respect To Use Of Quebec Interconnection, dated December 1, 1981, among certain NEPOOL utilities to include Phase II facilities in the definition of "Project" (Exhibit 1 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.24 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). 10.1.24.1 First, Second and Third Amendments to 10.1.24 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). 10.1.24.2 Fifth, Sixth and Seventh Amendments to 10.1.24 as amended October 15, 1987, December 15, 1987 and March 1, 1988, respectively (Ex- hibit 1 to the CEC Form 10-Q (June 1988), File No. 2-30057). 10.1.24.3 Fourth and Eighth Amendments to 10.1.24 as amended July 1, 1987 and August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q (September 1988), File No. 2-30057). 10.1.24.4 Ninth and Tenth Amendments to 10.1.24 as amended November 1, 1988 and January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.24.5 Eleventh Amendment to 10.1.24 as amended November 1, 1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-30057). 10.1.24.6 Twelfth Amendment to 10.1.24 as amended April 1, 1990 (Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-30057). 10.1.25 Phase II Equity Funding Agreement for New England Hydro-Transmis- sion Electric Company, Inc. (New England Hydro) (Massachusetts), dated June 1, 1985, between New England Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.26 Phase II Massachusetts Transmission Facilities Support Agreement dated June 1, 1985, refiled as a single agreement incorporating Amendments 1 through 7 dated May 1, 1986 through January 1, 1989, respectively, between New England Hydro and certain NEPOOL utili- ties (Exhibit 2 to the CEC Form 10-Q (September 1990), File No. 2- 30057). 10.1.27 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). PAGE 45 COMMONWEALTH ELECTRIC COMPANY 10.1.28 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June 1, 1985, between New Hampshire Hydro and certain NEPOOL util- ities (Ex. 3 to the CEC Form 10-Q (Sept. 1985), File No. 2-30057). 10.1.28.1 Amendment No. 1 to 10.1.28 dated May 1, 1986 (Exhibit 6 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.28.2 Amendment No. 2 to 10.1.28 as amended September 1, 1987 (Exhibit 3 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.29 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). 10.1.29.1 Amendments Nos. 1 and 2 to 10.1.29 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.29.2 Amendments Nos. 3 and 4 to 10.1.29 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.30 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). 10.1.30.1 Amendments Nos. 1 and 2 to 10.1.30 as amended May 1, 1986 and February 1, 1987, respectively (Exhibit 2 to the CEC Form 10-Q (March 1987), File No. 2-30057). 10.1.30.2 Amendments Nos. 3 and 4 to 10.1.30 as amended June 1, 1987 and September 1, 1987, respectively (Exhibit 4 to the CEC Form 10-Q (September 1987), File No. 2-30057). 10.1.31 Agreement Authorizing Execution of Phase II Firm Energy Contract, dated September 1, 1985, among certain NEPOOL utilities in regard to participation in the purchase of power from Hydro-Quebec (Ex- hibit 8 to the CEC Form 10-Q (September 1985), File No. 2-30057). 10.1.32 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). 10.1.32.1 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). 10.1.32.2 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). 10.1.32.3 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). PAGE 46 COMMONWEALTH ELECTRIC COMPANY 10.1.32.4 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). 10.1.32.5 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). 10.1.33 Agreements by and between Swift River Company and CE for the purchase of available hydro-electric energy to be produced by units located in Chicopee and North Willbraham, Massachusetts, both dated September 1, 1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-7749). 10.1.33.1 Transmission Service Agreement between Northeast Utilities' compa- nies (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). 10.1.33.2 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). 10.1.34 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). 10.1.35 System Power Sales Agreement by and between CL&P, WMECO, as sell- ers, 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). 10.1.36 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). 10.1.37 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). 10.1.37.1 Power Sales Agreement to 10.1.37 for all capacity and related energy produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K, File No. 2-7749). PAGE 47 COMMONWEALTH ELECTRIC COMPANY 10.1.37.2 Amendment to 10.1.37 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). 10.1.37.3 Second Amendment to 10.1.37.2 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 the CE Form 10-Q (June 1991), File No. 2-7749). 10.1.38 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). 10.1.39 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). 10.1.40 Power Sale Agreement by and between CE (buyer) and Northeast Energy Associates, 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). 10.1.40.1 First Amendment to 10.1.40 as amended August 15, 1988 (Exhibit 1 to the CE Form 10-Q (September 1988), File No. 2-7749). 10.1.40.2 Second Amendment to 10.1.40 as amended January 1, 1989 (Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.40.3 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). 10.1.40.4 Amendment to 10.1.40.3 as amended January 1, 1989 (Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749). 10.1.41 Power Sale Agreement by and between CE (buyer) and CPC Lowell Cogeneration Corp.(seller) of all capacity and related energy produced, dated September 29, 1986 (Exhibit 2 to the CE Form 10-Q (March 1987), File No. 2-7749). 10.1.41.1 Restatement of 10.1.41 as restated March 30, 1987 (Exhibit 2 to the CE Form 10-Q (June 1987), File No. 2-7749). 10.1.42 Power Sale Agreement by and between CE (buyer) and Pepperell Power Associates Limited Partnership (seller) of all electricity pro- duced from a 38 KW generating unit, dated April 13, 1987 (Exhibit 3 to the CE Form 10-Q (March 1987), File No. 2-7749). 10.1.43 Power Contract between CEC (seller) and CE and CEL (purchasers) dated August 14, 1989 whereby purchasers agree to purchase the capacity and energy from seller's "Slice-of-System" entitlement from CL&P for the term of November 1, 1989 to October 31, 1994 (Exh. 1 to the CEC Form 10-Q (September 1989), File No. 2-30057). PAGE 48 COMMONWEALTH ELECTRIC COMPANY 10.1.43.1 Power Sale Agreement dated November 1, 1988, by and between CEC (buyer) and CL&P (seller), whereby buyer will purchase generating capacity totaling 250 MW from various seller's units ("Slice of System") for the term November 1, 1989 to October 31, 1994 (Exhib- it 3 to the CEC 1988 Form 10-K, File No. 2-30057). 10.1.44 Exchange of Power Agreement between Montaup Electric Company and CE dated January 17, 1991 (Exhibit 2 to the CE Form 10-Q (Septem- ber 1991), File No. 2-7749). 10.1.44.1 First Amendment, dated November 24, 1992, to Exchange of Power Agreement between Montaup Electric Company and the Company dated January 17, 1991 (Exhibit 1 to the CE Form 10-Q (March 1993), File No. 2-7749). 10.1.45 System Power Exchange Agreement by and between CE and New England Power Company dated January 16, 1992 (Exhibit 1 to the CE Form 10- Q (March 1992), File No. 2-7749). 10.1.45.1 First Amendment, dated September 8, 1992, to 10.1.45, dated January 16, 1992 (Exhibit 1 to the CE Form 10-Q (Sept. 1992), File No. 2-7749). 10.1.45.2 Second Amendment, dated March 2, 1993, to System Power Exchange Agreement by and between the Company and New England Power Company dated January 16, 1992 (Exhibit 2 to the CE Form 10-Q (March 1993), File No. 2-7749). 10.1.46 Power Purchase Agreement and First Amendment, dated September 5, 1989 and August 3, 1990, respectively, by and between 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). 10.1.47 Power Purchase Agreement by and between Masspower (seller) and the Company (buyer) for a 11.11% entitlement to the electric capacity and related energy of a 240 MW gas-fired cogeneration facility, dated February 14, 1992 (Exhibit 1 to the CE Form 10-Q (September 1993), File No. 2-7749). 10.1.48 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller) and the Company (buyer) for a 17.2% entitlement to the electric capacity and related energy of a 160 MW gas-fired cogen- eration facility, dated February 20, 1992 (Exhibit 2 to the CE Form 10-Q (September 1993), File No. 2-7749). 10.1.48.1 System Exchange Agreement by and among Altresco Pittsfield, L.P., CEL, the Company and New England Power Company, dated July 2, 1993 (Exhibit 3 to the CE Form 10-Q (September 1993), File No. 2-7749). PAGE 49 COMMONWEALTH ELECTRIC COMPANY 10.2 Other agreements. 10.2.1 Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended and restated January 1, 1993 (Exhibit 1 to the CES Form 10-Q (Sept. 1993), File No. 1-7316). 10.2.2 Employees Savings Plan of Commonwealth Energy System and Subsid- iary Companies as amended and restated as of January 1, 1993 (Ex- hibit 2 to the CES Form 10-Q (September 1993), File No. 1-7316). 10.2.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as amended through August 1, 1977, between NEGEA Service Corpora- tion, as agent for CEL, CEC, NBGEL, and various other electric utilities operating in New England together with amendments dated August 15, 1978, January 31, 1979 and February 1, 1980 (Exhibit 5(c)13 to New England Gas and Electric Association's Form S-16 (April 1980), File No. 2-64731). 10.2.3.1 Thirteenth Amendment to 10.2.3 as amended September 1, 1981 (Re- filed as Exhibit 3 to the CES 1991 Form 10-K, File No. 1-7316). 10.2.3.2 Fourteenth through Twentieth Amendments to 10.2.3 as amended December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985 and September 1, 1985, respective- ly (Exhibit 4 to the CES Form 10-Q (Sept. 1985), File No. 1-7316). 10.2.3.3 Twenty-first Amendment to 10.2.3 as amended to January 1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316). 10.2.3.4 Twenty-second Amendment to 10.2.3 as amended to September 1, 1986 (Exhibit 1 to the CES Form 10-Q (Sept. 1986), File No. 1-7316). 10.2.3.5 Twenty-third Amendment to 10.2.3 as amended to April 30, 1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File No. 1-7316). 10.2.3.6 Twenty-fourth Amendment to 10.2.3 as amended March 1, 1988 (Exhib- it 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.2.3.7 Twenty-fifth Amendment to 10.2.3. as amended to May 1, 1988 (Ex- hibit 1 to the CES Form 10-Q (March 1988), File No. 1-7316). 10.2.3.8 Twenty-sixth Agreement to 10.2.3 as amended March 15, 1989 (Exhib- it 1 to the CES Form 10-Q (March 1989), File No. 1-7316). 10.2.3.9 Twenty-seventh Agreement to 10.2.3 as amended October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-7316). (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended December 31, 1993. PAGE 50 SCHEDULE III COMMONWEALTH ELECTRIC COMPANY INVESTMENTS IN, EQUITY IN EARNINGS OF, AND DIVIDENDS RECEIVED FROM RELATED PARTIES FOR THE YEARS ENDED DECEMBER 31, 1991, 1992 AND 1993 (Dollars in Thousands) Name of Issuer and Description of Investment Common Stock - Yankee Atomic Electric Company Balance, December 31, 1990 Number of Shares: 3 835 Amount $524 1991 Add: Equity in Earnings 73 Less: Dividends Received 71 Balance, December 31, 1991 526 1992 Add: Equity in Earnings 75 Less: Dividends Received - Balance, December 31, 1992 601 1993 Add: Equity in Earnings - Less: Dividends Received - Balance, December 31, 1993 $601 There were no changes in the number of shares held during the years 1991, 1992 or 1993. Under terms of the capital funds agreements and power contracts, no stock may be sold or transferred except to another stockholder and, as such, no market exists for these securities. See Note 2(c) of the Notes to Financial Statements included in Item 8 of this report for a discussion of the permanent closing of the nuclear plant owned by Yankee Atomic Electric Company. PAGE 51 SCHEDULE V COMMONWEALTH ELECTRIC COMPANY PROPERTY, PLANT AND EQUIPMENT (A) FOR THE YEAR ENDED DECEMBER 31, 1993
Balance Retirements Balance Beginning Additions Charged To End of Classification of Year at Cost Reserve Other Transfers(B) Year (Dollars in Thousands) ELECTRIC Intangible plant $ 1 837 $ - $ - $ - $ - $ 1 837 Land and rights of way 7 885 5 - 1 - 7 889 Structures and leasehold improvements 24 995 654 69 - - 25 580 Production equipment 4 078 (10) 24 - 24 4 068 Transmission equipment 87 740 2 505 678 - 13 89 580 Distribution equipment 324 440 14 787 3 326 - (9) 335 892 General equipment, vehicles and other 24 205 112 64 - (15 560) 8 693 Total plant in service 475 180 18 053 4 161 1 (15 532) 473 539 Construction work in progress 4 794 684 - - - 5 478 Total electric 479 974 18 737 4 161 1 (15 532) 479 017 OTHER Miscellaneous physical property 1 659 - - - 150 1 809 Total property, plant and equipment $481 633 $18 737 $4 161 $ 1 $(15 382) $480 826 (A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates. (B) Represents the abandoned Cannon Street Generating Station reclassified to Deferred Charges. Amounts transferred from Property Held for Future Use to Deferred Charges (net of accumulated depreciation of $11,010,000) in anticipation of recovery.
PAGE 52 SCHEDULE V COMMONWEALTH ELECTRIC COMPANY PROPERTY, PLANT AND EQUIPMENT (A) FOR THE YEAR ENDED DECEMBER 31, 1992
Balance Retirements Balance Beginning Additions Charged To End of Classification of Year at Cost Reserve Other Transfers Year (Dollars in Thousands) (B) ELECTRIC Intangible plant $ 1 837 $ - $ - $ - $ - $ 1 837 Land and rights of way 7 927 195 - - (237) 7 885 Structures and leasehold improvements 30 039 143 13 - (5 174) 24 995 Production equipment 15 610 63 1 - (11 594) 4 078 Transmission equipment 79 519 9 287 1 047 - (19) 87 740 Distribution equipment 311 824 16 117 3 495 - (6) 324 440 General equipment, vehicles and other 8 601 228 82 - 15 458 24 205 Total plant in service 455 357 26 033 4 638 - (1 572) 475 180 Construction work in progress 9 704 (4 910) - - - 4 794 Total electric 465 061 21 123 4 638 - (1 572) 479 974 OTHER Miscellaneous physical property 87 - - - 1 572 1 659 Total property, plant and equipment $465 148 $21 123 $4 638 $ - $ - $481 633 (A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates. (B) Principally Cannon Street generating station which ceased power generation on October 1. Applicable plant balances transferred to Property Held for Future Use from Plant in Service.
PAGE 53 SCHEDULE V COMMONWEALTH ELECTRIC COMPANY PROPERTY, PLANT AND EQUIPMENT (A) FOR THE YEAR ENDED DECEMBER 31, 1991
Balance Retirements Balance Beginning Additions Charged To End of Classification of Year at Cost Reserve Other Transfers Year (Dollars in Thousands) ELECTRIC Intangible plant $ 1 678 $ 159 $ - $ - $ - $ 1 837 Land and rights of way 7 912 13 - 1 3 7 927 Structures and leasehold improvements 29 249 604 (186) - - 30 039 Production equipment 15 386 235 11 - - 15 610 Transmission equipment 76 944 2 643 69 - 1 79 519 Distribution equipment 288 460 26 331 2 966 - (1) 311 824 General equipment, vehicles and other 8 453 373 221 - (4) 8 601 Total plant in service 428 082 30 358 3 081 1 (1) 455 357 Construction work in progress 8 212 1 492 - - - 9 704 Total electric 436 294 31 850 3 081 1 (1) 465 061 OTHER Miscellaneous physical property 86 - - - 1 87 Total property, plant and equipment $436 380 $31 850 $3 081 $ 1 $ - $465 148 (A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.
PAGE 54 SCHEDULE VI COMMONWEALTH ELECTRIC COMPANY ACCUMULATED DEPRECIATION OF PROPERTY, PLANT AND EQUIPMENT (A) FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Dollars in Thousands)
Provision Balance at Transferred Clearing Amortization Balance Classifi- Beginning to Deferred Charged to Accounts and of Leasehold Removal at End cation of Year Charges (B) Operations Other Income Improvements Retirements Cost Salvage of Year YEAR ENDED DECEMBER 31, 1993 Electric $135 684 $(11 010) $15 032 $ - $ 424 $4 162 $3 263 $ 644 $133 349 YEAR ENDED DECEMBER 31, 1992 Electric $128 253 $ - $15 012 $ 5 $ 422 $4 638 $4 291 $ 921 $135 684 YEAR ENDED DECEMBER 31, 1991 Electric $118 646 $ - $14 484 $ - $ 434 $3 081 $2 802 $ 572 $128 253 (A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates. (B) Represents accumulated depreciation applicable to the abandoned Cannon Street generating station reclassified to Deferred Charges.
PAGE 55 SCHEDULE VIII COMMONWEALTH ELECTRIC COMPANY VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 and 1991 (Dollars in Thousands) Additions Balance Provision Deductions Balance Beginning Charged to Accounts at End Description of Year Operations Recoveries Written Off of Year Allowance for Doubtful Accounts Year Ended December 31, 1993 $3 131 $3 173 $783 $3 819 $3 268 Year Ended December 31, 1992 $2 653 $5 216 $854 $5 592 $3 131 Year Ended December 31, 1991 $2 341 $5 286 $985 $5 959 $2 653 PAGE 56 SCHEDULE IX COMMONWEALTH ELECTRIC COMPANY SHORT-TERM BORROWINGS (a) FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (Dollars in Thousands) Maximum Weighted Weighted Month-End Average Average Category of Average Amount Amount Interest Aggregate Balance Interest Outstanding Outstanding Rate Short-Term at End Rate at End During During the During the Borrowings of Period of Period the Period Period (b) Period (c) December 31, 1993 Notes Payable to Banks $ - - $80 350 $16 121 3.4% Notes Payable to System $ - - $12 970 $ 2 451 6.0% COM/Energy Money Pool $ - - $ 4 005 $ 858 3.2% December 31, 1992 Notes Payable to Banks $67 275 3.8% $68 700 $62 460 4.0% Notes Payable to System $ 8 445 6.0% $11 030 $ 7 765 6.3% COM/Energy Money Pool $ 3 395 3.4% $ 6 060 $ 3 856 3.7% December 31, 1991 Notes Payable to Banks $63 300 5.5% $68 250 $55 612 6.3% Notes Payable to System $ 5 950 6.5% $ 5 950 $ 2 167 8.3% COM/Energy Money Pool $ 3 600 4.6% $ 3 795 $ 2 878 5.8% (a) Refer to Note 5 of Notes to Financial Statements filed under Item 8 of this report for the general terms of each category of short-term borrowings. (b) The average amount outstanding during the period is determined by averaging the level of month-end principal balances outstanding for the prior thirteen-month period ending December 31. (c) The weighted average interest rate during the period is determined by averaging the interest rates in effect on all loans transacted for the twelve-month period ended December 31. PAGE 57 COMMONWEALTH ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1993 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 ELECTRIC COMPANY (Registrant) By: WILLIAM G. POIST William G. Poist, Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Principal Executive Officers: WILLIAM G. POIST March 30, 1994 William G. Poist, Chairman of the Board and Chief Executive Officer R. D. WRIGHT March 28, 1994 Russell D. Wright, President and Chief Operating Officer Principal Financial Officer: JAMES D. RAPPOLI March 30, 1994 James D. Rappoli, Financial Vice President and Treasurer Principal Accounting Officer: JOHN A. WHALEN March 28, 1994 John A. Whalen, Comptroller A majority of the Board of Directors: WILLIAM G. POIST March 30, 1994 William G. Poist, Director JAMES D. RAPPOLI March 30, 1994 James D. Rappoli, Director R. D. WRIGHT March 28, 1994 Russell D. Wright, Director EX-10 2 POWER PURCHASE AGREEMENT PAGE 1 EXHIBIT 1 AGREEMENT entered into this first day of September, 1983 by and between Commonwealth Electric Company, a Massachusetts corporation with offices located at 2421 Cranberry Highway, Wareham, Massachusetts 02571 ("Company") and Pioneer Hydropower, Incorporated, ("Pioneer") a Massachusetts corporation with offices located at 148 State Street, Boston, Massachusetts 02109 ("Sell- er"). Seller owns and operates a hydro-electric generating facility (the "Plant"), at its site in Ware, Massachusetts. Seller wishes to sell and the Company wishes to buy electric energy from the Plant, all pursuant to the terms and conditions as set forth in this Agreement. THEREFORE, the parties, each in consideration of the agreements of the other, hereby agree as follows: ARTICLE I. Sale of Power by Seller. (a) Seller agrees to sell and deliver to New England Power Company ("NEPCO"), and the Company agrees to purchase and accept delivery from NEPCO of all electric energy produced by the Plant during the term of this Agree- ment, except that the Seller shall have the option not to sell and deliver such electric energy as may be needed from time to time to satisfy Plant requirements ("Net Plant Output"). (b) The Company shall not be obligated to purchase or take delivery of electric energy from the Plant unless, in the reasonable judgment of the Company, the Plant is staffed, operated and maintained in a manner consistent with the standards applicable to generating facilities owned and operated by participants in the New England Power Pool ("NEPOOL"), as such standards may be in effect from time to time during the term of this Agreement. The Plant must be made available for NEPOOL dispatch in accordance with the provisions of Section 12.2 of the NEPOOL Agreement dated September 1, 1971 as amended ("NEPOOL Agreement"). (c) Without limiting the generality of Article 1(b) hereof, Seller shall be obligated hereby to undergo periodic capability audits pursuant to the terms of Section 8.13 of the NEPOOL Agreement. In the event that the Plant demonstrates a Capability (as defined at Section 15.6 of the NEPOOL Agreement) that is less than the "Qualified Capacity" of such Plant ("Capacity Deficien- cy"), the Company may assess Seller a charge equal to the Capability Respon- sibility Adjustment Charge established from time to time by NEPOOL pursuant to the provisions of Section 9.4 of the NEPOOL Agreement multiplied by such Capacity Deficiency. The Qualified Capacity of the Plant shall be determined by a capability audit conducted, under the general supervision of the adminis- trative committee established by Article X(f) of this Agreement, during the first winter period following the effective date of this Agreement. Such Qualified Capacity shall be the winter period Net Capability of the Plant (as computed pursuant to said capability audit) which shall be the same as the Capability of the Plant calculated pursuant to Section 15.6 of the NEPOOL Agreement. Notwithstanding the foregoing, if such winter period Net Capability of the plant is less than thirteen hundred ten (1310) kilowatts, the Qualified Capacity of the Plant shall be thirteen hundred ten (1310) kilowatts. PAGE 2 (d) The Company reserves the right to impose reasonable conditions consistent with the NEPOOL standards that are in effect from time to time during the term of this Agreement in substitution for the foregoing NEPOOL standards if NEPOOL ceases to establish such standards or if the Company should cease its participation in NEPOOL during the life of this Agreement. ARTICLE II. Effective Date and Term. (a) This Agreement shall become effective upon the date that electric energy is first delivered to Company by NEPCO, and unless sooner terminated in accordance with any applicable provision of this Agreement, shall remain in full force and effect for an initial term of thirty (30) years. Seller agrees to notify the Company at the end of the twenty ninth (29) year of its rights and intention to continue operation of the Plant beyond the initial term. In the event that Seller has the right to continue operation of the Plant and sell power to the Company beyond the initial term, this Agree- ment shall be renewed or extended at the Company's sole option by the giving of written notice to Seller within six (6) months following receipt of notice from Seller of such continued operation, said renewal to be for a term of fifteen (15) years. Seller agrees to use all reasonable efforts to continue operation of the Plant beyond the initial term. ARTICLE III. Purchase Price. (a) From and after the date of initial commencement of deliveries of electric energy from the Plant ("Start Date"), the Company shall pay Seller each month an amount equal to the greatest of: (1) the Energy Purchase Price as determined in accordance with Appendix A to this Agreement multiplied times the quantity of electric energy delivered to the Company by NEPCO hereunder, or (2) eighty-four mills ($0.084) per kilowatt-hour ("Floor Energy Price") multiplied times the quantity of electric energy delivered to the Company by NEPCO hereunder, or (3) beginning January 1, 1992 and ending at the close of the fifteenth (15th) year following the Start Date, the Floor Energy Price per kilowatthour ("Adjusted Floor Energy Price") shall be determined by the following formula: Adjusted Floor Energy Price = 84 mills + PGNP-2 x [9.1 + PGNP-1 (14.1)] Where: PGNP-1 is the cumulative percentage change in the Gross National Product Implicit Price Deflator ("PGNP") published by the United States Department of Commerce between the Start Date and December 31, 1991, and PGNP-2 is the cumulative percentage change in the PGNPafter January 1, 1992, multiplied times the quan- tity of electric energy delivered to the Company by NEPCO hereunder. PAGE 3 In the event the United States Department of Commerce should cease to publish the PGNP, the Company and Seller shall mutually agree upon a satisfactory replacement therefor or, failing to so agree, shall submit matter to arbitra- tion in accordance with the appropriate provisions of this Agreement. The Company has entered an agreement of even date herewith and similar hereto with Swift River Company relative to a hydro electric facility known as Chicopee. The amount of the Floor Energy Price of eighty-four mills ($0.084) per kilowatthour shown in Article III(a)(2) and (3) above is contingent upon Chicopee entering commercial operation no later than December 31, 1984. In the event that Chicopee does not enter commercial operation by December 31, 1984, the Floor Energy Price shall be reduced to eighty-two mills ($0.082) per kilowatthour and any payments made to Seller using such Floor Energy Price from the Start Date to December 31, 1984 shall be re-calculated and adjusted to reflect such reduction. (b) For the purpose of implementing Article III(a) of this Agreement, the Company shall pay Seller each month an amount determined in accordance with paragraph (1) thereof. Amounts payable to Seller pursuant to Article III(a)(1) shall be determined for each billing period on an estimated basis and paid monthly in accordance with Article VII hereof, subject to a final determination and reconciliation at the end of each such billing period established pursuant to Appendix A hereof. For purposes of such monthly payments, an estimated Energy Purchase Price for each rating period (as defined in Appendix A hereof) shall be determined as set forth in such Appendix A by setting Factor 0-2 equal to Factor 0-1. Such estimated Energy Purchase Price for each rating period shall be multiplied by the quantity of electric energy (measured in kilowatt-hours) delivered to the Company by Seller during such rating period during such month. Following the close of each such billing period, the Company will promptly determine its actual Energy Purchase Price for each rating period. Any difference between the forecast and actual Energy Purchase Price for the same billing period shall be subject to reconciling adjustment during the first month of the next subse- quent billing period. (c) If the Company determines that the Energy Purchase Price, computed with Factor R set equal to one-hundred percent (100%), exceeds the Company's avoided energy costs (as hereinafter defined), the Company may propose a change to Appendix A by giving Seller written notice thereof. Such proposed change shall be limited to the methodology for determining or calculating the Company's avoided energy costs and shall not deviate from the principle that the average decremental cost shall at least approximate the most costly ten percent (10%) of the load placed upon the Company's system by its firm-service customers during the relevant billing period. In the event that Seller fails to accept said proposed change and Seller and Company are unable to agree in writing upon a mutually satisfactory revised Appendix A within sixty (60) days of the giving of such notice, either the Seller or the Company may submit the matter to arbitration pursuant to the provisions of Article X(g) and (h) below. During the period of time in which said matter is in arbitration, the proposed revised Appendix A originally offered by the Company shall govern the computation of the Energy Purchase Price. Within thirty (30) days following resolution of said dispute by arbitration, the Company shall recompute, in accordance with said resolution, all amounts paid to, Seller during the pendency of such dispute and debit or credit Seller's account as appropriate. PAGE 4 (d) Avoided energy cost as used herein shall mean the incremental cost to the Company of electric energy which the Company would have generated or purchased but for the purchase of electric energy from Seller. (e) Any taxes on the production or sale of electric energy furnished by the Seller to the Company under this Agreement shall be the obligation of and paid by the Seller as and when due. ARTICLE IV. Energy Purchase Bank. (a) The Company will establish an account within its records, to be known as the Energy Purchase Bank, which shall be maintained separately from all other accounts therein. The Energy Purchase Bank shall be solely used to record such periodic energy purchase (and related) transactions and associated account balances as are specified within this Agreement as affecting such Energy Purchase Bank. (b) During the term of this Agreement, the difference between any amounts paid to Seller pursuant to the Floor Energy Price or the Adjusted Floor Energy Price and the amount that would have been paid to Seller under the Energy Purchase Price, computed with Factor R set equal to one-hundred percent (100%), shall be debited to the Energy Purchase Bank. (c) During any billing period for which the Energy Purchase Bank contains a debit balance and for which the Energy Purchase Price, computed with Factor R set equal to one hundred percent (100%), exceeds the Floor Energy Price or the Adjusted Floor Energy Price, the Energy Purchase Bank shall be credited as follows: (1) if the Energy Purchase Price with Factor R set at 100% exceeds the Floor or Adjusted Floor Energy Price, then one-half of said difference multiplied by the number of kilowatt hours purchased from Seller during such billing period shall be credited to the Energy Purchase Bank and one-half of said difference multiplied as specified above shall be paid to Seller. (2) provided nevertheless, that for the purpose of this subarticle, if the actual avoided energy cost exceeds the projections attached hereto as Appendix B, then all of the difference between said actual avoided costs for the year in question and those shown on Appendix B shall be credited to the Energy Purchase Bank until the debit balance in said Bank reaches zero, at which time the payment to Seller shall be calcu- lated according to Appendix A, using actual avoided cost figures. Said procedure shall continue throughout the term of this Agreement until any debit balance in the Energy Purchase Bank is reduced to zero. Any debit balance of the Energy Purchase Bank shall bear interest at a rate per annum which shall be at all times equal to the Base Rate of The First National Bank of Boston (or its successors) which shall mean the rate of interest designated by such Bank as its Base Rate and usually charged by it to substantial and responsible borrowers, as in effect from time to time. Each change in the said Base Rate shall be effective at the beginning of the business day on which such change occurs. PAGE 5 ARTICLE V. Delivery by Seller. Electric energy generated by the Seller at the Plant shall be delivered by NEPCO (pursuant to a Service Agreement between the Company and NEPCO of even date herewith) to the Company at the 345,000 volt bus located in the Canal Electric Company switchyard at Sandwich, Massachusetts ("point of delivery") in the form of three-phase, sixty hertz alternating current at approximately 345,000 volts nominal. All electric energy produced by Seller and delivered to NEPCO for transmission to the Company shall be adjusted for any transmission losses on NEPCO's system and any payments made by Company to Seller pursuant to Article III above shall be determined based on the net kilowatthours of electric energy delivered by NEPCO to Company at the point of delivery. It is understood that any payments by the Company to Seller made in accordance with Article III above shall be net of payments made by the Company to NEPCO for the transmission of such electric energy generated by Seller. Seller shall obtain and continuously maintain insurance, bond, or other debt instrument in form and amount satisfactory to the Company sufficient to reimburse the Company in full for any obligation it may incur with NEPCO under the above-mentioned Service Agreement for any period during which Seller is not producing electric energy under this Agreement. The Company shall be the specified beneficiary under the insurance, bond or debt instrument and evidence of the effectiveness of such insurance, bond, or debt instrument must be filed with the Company at all times during the term of this Agreement or the Company shall have the right to withhold payment hereunder. ARTICLE VI. Meters and Metering. (a) The Company shall have the right to review and approve the metering installations required to record the quantities of electricity purchased from the Seller. Such metering equipment will be capable, inter alia, of providing data required to determine kilowatt-hours per hour purchased during each hour of each rating period established by Appendix A hereto as well as total electric energy purchased per rating period under the terms of this Agreement. Seller shall install, own, operate and maintain such metering equipment, which equipment shall be located at Seller's bus (or buses). If, for any reason, it is impractical to install meters at such bus (or buses), appropriate adjust- ments shall be made to reflect the actual amount of electric energy which would have been recorded by meters located at such bus (or buses). (b) Seller shall maintain all metering equipment installed pursuant hereto accurate by regular testing and calibration in comparison to recognized standards. The metering equipment shall be sealed, and Seller will comply with any reasonable request of the Company with regard to the presence of the Company's representative when such seals are to be broken or when the meters are to be inspected, tested or adjusted. The Company may request, at any time, a test of the accuracy of any metering equipment installed pursuant hereto and shall bear the costs thereof in the event that said requests are made more frequently than once in each twelve months. The results of all meter calibra- tions or tests, whether or not performed at the Company's request, shall be open to examination by the Company at all reasonable times. (c) Any meter tested and found to register less than or equal to one-half of one percent (0.5%) above or below the recognized comparative standard shall be considered correct and accurate. If as a result of such PAGE 6 tests, the metering equipment is found to be defective or inaccurate, Seller shall restore it to a condition of accuracy or replace it. In such event, adjustment shall be made by the Company correcting all measurements made by the defective or inaccurate meter for either (i) the actual period during which inaccurate measurements were made, if determinable to the mutual satisfaction of the Company and Seller or (ii) if such period is not so determinable, for a period equal to one-half of the time elapsed since the last prior test, but in no event greater than twelve months. (d) Other provisions of this Article VI notwithstanding, the Company may elect to install its own metering equipment in supplement to the Seller's metering equipment. Should the Company so elect and should any metering equipment installed by the Seller fail to register the amount of electric energy delivered to the Company during any period of time, the Company's metering equipment shall be used to determine the amount of electric energy so delivered in lieu of the Company's estimates thereof. If the Company wishes its metering equipment to be so used, the Company agrees to operate, maintain and read such equipment according to the standards established by this Article VI. The Seller agrees, upon request of the Company, to provide a suitable location at the Plant for installation of the Company's meters at no cost to the Company. (e) Upon written request of the Company, Seller shall install and bear the cost of such telemetering equipment and data circuits as the Company may reasonably require for the transmission of various metered values to its operations center. The design of and equipment specifications for such telemetering equipment and data circuits shall be approved by the Company prior to installation thereof by Seller. (f) Seller shall read its meters daily for determination of the amount of purchases by the Company under the terms of this Agreement and shall supply the results of such meter readings to the Company on the morning of the next working day. ARTICLE VII. Payment. (a) The Company shall determine the quantity of electric energy pur- chased from Seller monthly based upon the metered values obtained in accordance with the several provisions of Article VI of this Agreement adjusted for any transmission losses as appropriate. The Company, after giving due effect to any reconciling adjustments necessary and deducting transmission payments made pursuant to Article V hereof ("Net Payment") shall pay to a specially designated account established by Seller for such electric energy monthly within thirty (30) calendar days following receipt of such metered values from Seller for the last day in each prior calendar month and shall show the derivation of such Net Payment in such detail as Seller may reason- ably request from time to time. (b) In the event that any data required for the purpose of determining payment hereunder are unavailable when required, such unavailable data may be estimated by the Company, subject to any required adjustment based upon actual data in a subsequent payment month. (c) In the event that, for any month, the quantity of electric energy purchased from Seller is such that the Net Payment to Seller would be less PAGE 7 than zero, such Net Payment shall be deemed to be a billing to Seller by the Company. Any such billing shall be due and payable within thirty (30) calendar days following receipt of metered values from Seller for the last day in the prior calendar month. ARTICLE VIII. Governmental Regulation. (a) This Agreement shall be submitted by the Company to the Massachu- setts Department of Public Utilities ("MDPU") in accordance with Section 94A, Chapter 164, of the Massachusetts General Laws and applicable regulations of the MDPU, and the Company shall use its best efforts to obtain expeditious approval thereof in accordance with such law and regulations. (b) It shall be the responsibility of each party hereto individually to take all necessary actions to satisfy any regulatory requirements which may be imposed upon such party by any federal, state or municipal statute, rule, regulation or ordinance which may be in effect from time to time relative to the performance of such party hereunder. (c) This Agreement and all rights and obligations of the parties hereunder are subject to all applicable state and federal laws and all duly promulgated orders and duly authorized actions of governmental authorities. (d) The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the Commonwealth of Massachu- setts. ARTICLE IX. Liability and Force Majeure. (a) The parties hereto shall be excused from performing hereunder and shall not be liable in damages or otherwise if and only to the extent that they are unable to do so or are prevented from doing so by statute or regula- tion or by action of any court or public authority having or purporting to have jurisdiction in the premises; or by loss or impairment of the supply of electricity; or by a break or fault in the Company's or other transmitting company's transmission or distribution system or failure or improper operation of transformers, switches or other equipment necessary for receipt of electric energy from Seller; or by reason of storm, flood, fire, earthquake, explosion, civil disturbance, labor dispute, act of God or the public enemy, failure of any supplier to perform, restraint by a court or regulatory agency, or any other cause, whether or not similar thereto, beyond the reasonable control of the affected party. Each party shall have the obligation to operate in accordance with good utility practices at all times and to use diligent effort to remove any cause of failure to supply or receive electric energy hereunder. Neither the Company nor Seller shall, in any event, be liable to the other or to any third party for any consequential, indirect or special damages to persons or property, whether arising in tort, contract or otherwise, by reason of this Agreement or any services performed or undertaken to be performed by the Company or Seller hereunder, except as otherwise expressly provided herein. (b) Whenever the Company's system or the systems with which it is directly or indirectly interconnected experience a "System Emergency", or whenever it is needful or desirable to aid in the restoration of service on its system or on the systems with which it is directly or indirectly intercon- PAGE 8 nected, the Company may, in its reasonable judgment, curtail or interrupt the taking of electric energy hereunder, provided such curtailment or interruption shall continue only for so long as is reasonably necessary. Such curtailment, interruption, or reduction shall not be deemed to be a default by the Company nor shall the Company be liable therefor to Seller or to any other party. A System Emergency means a condition on a utility's system which is likely to result in an imminent significant disruption of service or is imminently likely to endanger life or property. Notwithstanding any other provision of this Agreement to the contrary, in the event that the Company cannot receive electric energy from Seller into its own system because of a System Emergency but such System Emergency does not prevent Seller from delivering such electric energy to another utility with which the Company is interconnected, the Company shall pay Seller for such electric energy so delivered the exact amount, if any, that the Company receives in payment or credit from such utility for the delivery of such electric energy. (c) The Company and the Seller agree that each shall be responsible for the electricity on its respective side of the point of delivery and shall indemnify, save harmless and defend the other against all claims, demands, costs or expenses for loss, damage or injury to persons or property in any manner directly or indirectly arising from, connected with or growing out of the presence or use of electricity or the transmission of electricity over the wires, cables, devices or appurtenances owned by it, its agents or suppliers, saving only such loss, damage or injury as may be caused by the willful or negligent act of the other. The Company and the Seller respectively assume full responsibility in connection with the service rendered hereunder for their respective wires, cables and other devices used in connection with said service. Each party hereto shall be solely liable for all claims of its own employees arising from any workmen's compensation laws. (d) Neither by inspection nor non-rejection nor in any other way does either party give any warranty, expressed or implied, as to the adequacy, safety or other characteristics of any equipment, apparatus or devices, installed on the premises of or used by the other party, its agents or suppliers. Neither party shall be liable to the other for damages resulting in any way from its taking or supplying of electric energy pursuant to the terms of this Agreement or from the presence or operation of its apparatus, meters, appurtenances or other equipment on the premises of the other party. (e) Seller may from time to time withdraw the Plant from service and cease to supply electric energy to the Company as necessary to perform scheduled or unscheduled maintenance or repair upon the Plant. Seller shall comply with the provisions of NEPOOL Operating Procedure No. 5 as in effect from time to time when planning any scheduled maintenance or repair upon the Plant. Seller shall give the Company such notice as may be practicable the circumstances when withdrawing the Plant from service for unscheduled mainte- nance or repair. ARTICLE X. Miscellaneous Provisions (a) This Agreement constitutes the entire agreement between the parties relating to the subject matter hereof, and all previous agreements, discus- sions, communications and correspondence with respect to the subject matter hereof are superseded by the execution of this Agreement. PAGE 9 (b) This Agreement may not be modified or amended except in writing signed by or on behalf of both parties by their duly authorized officers. (c) Any qualified and properly identified employee of the Company shall have access to the Plant at all reasonable times for the purpose of reading or inspecting meters, examining the operation of the Plant or other purposes reasonably related to the Company's performance under the terms of this Agreement. Such access shall not interfere with Seller's normal business operations. (d) This Agreement shall inure to the benefit of and bind the respective successors and permitted assigns of the parties hereto, provided, however, that no assignment by Seller or any successor or assignee of Seller of its rights and obligations hereunder, except an assignment to a wholly-owned subsidiary whose principal functions are to hold Seller's ownership interest in and to operate the Plant, shall be made or become effective without the prior written consent of the Company in each case obtained. The Company will provide consent to any assignment of Seller's rights and obligations hereunder to the extent necessary for Seller to obtain construction or permanent financing for the Plant with an institutional lender and to assure that the Company's right to receive the output of the Plant shall apply as against any person or entity that might obtain title and possession of the Plant pursuant to such financing. (e) All notices required or permitted under this Agreement shall be in writing and shall be deemed to have been given when delivered personally or deposited in the mails, postage prepaid, registered mail addressed to the party to whom notice is being given at its address set forth above. Either party may change its address by notice similarly given. (f) The parties hereto agree to establish an administrative committee. Such committee will be empowered to do all acts and things necessary to implement the intent of the parties hereto as set forth herein and to take such further actions as may be required in the circumstances, provided that they are not inconsistent with this Agreement. The Company and Seller shall have equal representation upon said committee. (g) In the case of any dispute between the parties with respect to the interpretation of this Agreement, or the performance of the same, or under Article III(d) above, either party may give notice in writing to the other of its desire to submit such questions to arbitration, and may designate an arbitrator. Within thirty (30) days after the receipt of such notice, the other party may, in writing, serve upon the party invoking such arbitration a notice designating an arbitrator on its behalf. The two arbitrators so chosen shall, within twenty (20) days after the appointment of the second arbitrator, in writing, designate a third arbitrator. Upon the failure of the party notified to appoint the second arbitrator within such time, the party invoking such arbitration may proceed with the single arbitrator. If the first and second arbitrators are unable to agree on a third arbitrator within twenty (20) days of the appointment of the second arbitrator, the first and second arbitrator shall invoke the services of the American Arbitration Association to appoint a third arbitrator. Said third arbitrator shall, to the extent practicable, have special competence and experience with respect to the subject matter under consideration. An arbitrator so appointed shall have full authority to act pursuant to this Article. No arbitrator, whether chosen by a PAGE 10 party hereto or appointed, shall have the power to amend or add to this Agreement. (h) The party calling the arbitration shall, within twenty (20) days after either the failure of the other party to name an arbitrator, or the appointment of the third arbitrator, as the case may be, fix, in writing, a time and a place of hearing, to be not less than twenty (20) days from delivery of notice to the other party. The arbitrator or arbitrators shall, thereupon, proceed promptly to hear and determine the controversy pursuant to the then-current rules of the American Arbitration Association for the conduct of commercial arbitration proceedings, except that if such rules shall conflict with the then current provisions of the laws of the Commonwealth of Massachusetts relating to arbitration, such conflict shall be governed by the then current provisions of the laws of the Commonwealth of Massachusetts relating to arbitration. Such arbitrator or arbitrators shall fix a time within which the matter shall be submitted to him or them by either or both of the parties, and shall make his or their decision, within ten (10) days after the final submission to him or them unless, for good reasons to be certified by him or them in writing, he or they shall extend such time. The decision of the single arbitrator, or two of the three arbitrators, shall be taken as the arbitration decision. Such decision shall be made in writing and in duplicate, and one copy shall be delivered to each of the parties. The expense of the arbitration shall be borne by the unsuccessful party, unless the arbitrator or arbitrators by his or their award shall otherwise provide, except that each party shall pay the costs of its own counsel. Each party shall accept and abide by the decision. The award of the arbitral tribunal shall be final except as otherwise provided by applicable law. Judgment upon such award may be entered by the prevailing party in any court having jurisdiction thereof, or application may be made by such party to any such court for judicial acceptance of such award and an order of enforcement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the day and year first above written. COMMONWEALTH ELECTRIC COMPANY By: J. V. Donovan Its: Executive Vice President PIONEER HYDROPOWER, INC. By: Peter B. Clark Its: President PAGE 11 APPENDIX A ENERGY PURCHASE PRICE The Energy Purchase Price applicable to electric energy delivered to the Company by Seller during any billing period will be equal to the rate, taken to the nearest one-tenth of a mill per kilowatt-hour, determined in accordance with the following formula, separately applied to each rating period hereinaf- ter defined: P = R x F (0-2/0-1) Where: P = Energy purchase price R = Avoided cost ratio F = Average decremental cost of generated and/or purchased energy 0-2 = Actual cost of energy produced and/or purchased from fossil fuels 0-1 = Estimated cost of energy produced and/or purchased from fossil fuels (1) Definitions (a) Factor R. Commencing on the Start Date and continuing until December 31, 1999, Factor R shall be eighty percent (80%). Commencing January 1, 2000, and continuing until December 31, 2010, Factor R shall be reduced from said eighty percent (80%), one percentage point on each successive January 1. Commencing January 1, 2011 and continuing until December 31, 2015, Factor R shall be reduced by two percentage points on each successive January 1. (b) Factor F. Factor F shall be the Company's estimated average decremental cost of generated and/or purchased energy as delivered to its system, sepa- rately determined (as set forth herein) for each billing period hereinafter defined. Factor F shall be computed not more than sixty (60) days prior to the beginning of such billing period. Said average decremental cost of energy shall be defined by the following formula, taken to the nearest one-tenth of a mill per kilowatt-hour: F = Cost1 - Cost2 KWHl - KWH2 where: Cost1 and KWH1 represent the estimated cost and quantity (respec- tively) of energy generated and/or purchased by the Company to meet one-hundred percent (100%) of the load placed upon its system by its firm-service customers during any billing period. Cost2 and KWH2 represent the estimated cost and quantity (respec tively) of energy generated and/or purchased by the Company to meet ninety percent (90%) of the load placed upon its system by its firm-service customers during the same billing period. (c) Factors O. The two Factors O shall be the average cost of energy generated by and/or purchased from generating units fired with fossil fuels during any billing period, either as actually experienced by the Company during such billing period (Factor O2) or as estimated by the Company for such PAGE 12 billing period (Factor Ol) and as included in its computations determining the average decremental cost of energy, all measured to the nearest one-tenth of a mill per kilowatt-hour. (2) Billing Period A billing period hereunder shall be any three (3) month period beginning January first, April first, July first and October first of any year during the term of this Agreement. (3) Rating Periods There shall be two rating periods for purposes of computing the Energy Purchase Prices. The Peak Period shall be defined as all hours in the billing period from 9:00 A.M. to 9:00 P.M. Eastern Standard Time on weekdays (Monday through Friday). The Off-Peak Period shall include all hours in the billing period not included in the Peak Period. The Company reserves the right to revise the definition of its rating periods from time to time during the term of this Agreement upon reasonable notice to Seller. PAGE 13 APPENDIX B Projected Avoided Energy Cost Year $.00/KWH 1983 4.74 1984 4.93 1985 5.32 1986 5.95 1987 6.48 1988 7.17 1989 8.20 1990 9.38 1991 10.62 1992 12.54 1993 14.36 1994 16.27 1995 12.20 1996 13.03 1997 14.27 1998 15.08 1999 17.24 2000 19.66 2001 22.23 2002 24.49 PAGE 14 SCHEDULE B COMMONWEALTH ELECTRIC COMPANY ENERGY PURCHASED FROM PIONEER HYDROPOWER, INCORPORATED TWELVE MONTHS ENDING AUGUST 31,1984 ESTIMATED KWH ESTIMATED COST PURCHASED OF ENERGY (*) 1983SEPTEMBER 180,000 $15,120 OCTOBER 240,000 20,160 NOVEMBER 360,000 30,240 DECEMBER 540,000 45,360 1984JANUARY 600,000 50,400 FEBRUARY 600,000 50,400 MARCH 960,000 80,640 APRIL 900,000 75,600 MAY 720,000 60,480 JUNE 480,000 40,320 JULY 240,000 20,160 AUGUST 180,000 15,120 TOTAL 12 MONTHS 6,000,000 $504,000 (*) BASED UPON AN ENERGY PURCHASE PRICE OF $0.084 PER KWH, THE MINIMUM ENERGY PURCHASE PRICE STATED AT SECTION III(A)(2) OF THE AGREEMENT. EX-10 3 POWER PURCHASE AGREEMENT PAGE 1 EXHIBIT 2 SCHEDULE A Filing Public Utility: COMMONWEALTH ELECTRIC COMPANY Qualifying Small Power Producer or Cogenerator: CORPORATION INVESTMENTS, INC. Service Provided: Agreement for the purchase of electric energy produced by Corporation Investments, Inc. at its hydro-electric generating facility in Lowell, Massachusetts. PAGE 2 AGREEMENT entered into this 10th day of January, 1983 by and between Commonwealth Electric Company, a Massachusetts corporation with offices located at 2421 Cranberry Highway, Wareham, Massachusetts 02571 ("Company") and Corporation Investments, Inc., a Massachusetts corporation with offices located at 9 Central Street, Lowell, Massachusetts 01853 ("Seller"). Seller plans to construct, own and operate an hydro-electric generating facility (the "Plant"), at its site in Lowell, Massachusetts, as more fully described and defined within Seller's "Application for License: Plant No. 2790, Lowell Hydroelectric Plant", dated May 20, 1980 as amended and tendered for filing with the Federal Energy Regulatory Commission ("FERC"). Seller wishes to sell and the Company wishes to buy electric energy from the Plant, all pursuant to the terms and conditions as set forth in this Agreement. THEREFORE, the parties, each in consideration of the agreements of the other, hereby agree as follows: ARTICLE I. Sale of Power by Seller. (a) Seller agrees to sell and deliver, and the Company agrees to purchase and accept delivery of, all electric energy produced by the Plant during the term of this Agreement, except that the Seller shall have the option not to sell and deliver such electric energy as may be needed from time to time to satisfy Plant requirements ("Net Plant Output"). (b) Seller shall have the option to reduce the quantity of electric energy sold to the Company under the provisions of this Agreement by an amount not in excess of forty-nine percent (49%) of the Net Plant Output under the following conditions: (1) Seller must exercise such option not later than six (6) months from the date first above-written, and (2) Seller may exercise such option only once, and only for the purpose of selling the electric energy to the Massachusetts Municipal Wholesale Electric Company ("MMWEC"), and (3) Seller may offer to sell to MMWEC only on the same terms and conditions upon which it has agreed to sell to the Company. (c) The Company shall not be obligated to purchase or take delivery of electric energy from the Plant unless, in the reasonable judgment of the Company, the Plant is staffed, operated and maintained in a manner consistent with the standards applicable to generating facilities owned and operated by participants in the New England Power Pool ("NEPOOL"), as such standards may be in effect from time to time during the term of this Agreement. The Plant must be made available for NEPOOL dispatch in accordance with the provisions of Section 12.2 of the NEPOOL Agreement dated September 1, 1971 as amended ("NEPOOL Agreement"). (d) Without limiting the generality of Article I(c) hereof, Seller shall be obligated hereby to undergo periodic capability audits pursuant to the terms of Section 8.13 of the NEPOOL Agreement. In the event that the Plant demonstrates a Capability (as defined at Section 15.6 of the NEPOOL Agreement) that is less than the "Qualified Capacity" of the Plant ("Capacity Deficien- PAGE 3 cy"), the Company may assess Seller a charge equal to the Capability Responsi- bility Adjustment Charge established from time to time by NEPOOL pursuant to the provisions of Section 9.4 of the NEPOOL Agreement multiplied by such Capacity Deficiency. In the event that Seller has elected to reduce the quantity of electric energy sold to the Company pursuant to its option in Article I(b) above, then in case of a Capacity Deficiency, the Company may only assess Seller a charge equal to the Capability Responsibility Adjustment Charge established from time to time by NEPOOL pursuant to the provisions of Section 9.4 of the NEPOOL Agreement multiplied by the factor that results from multiplying the total Capacity Deficiency times the percentage of Net Plant Output that the Company is entitled to purchase. The Qualified Capacity of the Plant shall be determined once in a capability audit conducted, under the general supervision of the administrative committee established by Article X(f) of this Agreement, during the first winter period following the date of commercial operation of the Plant. Such Qualified Capacity shall be the winter period Net Capability of the Plant (as computed pursuant to said capability audit) which shall be the same as the Capability of the Plant calculated pursuant to Section 15.6 of the NEPOOL Agreement. Notwithstanding the forego- ing, if such winter period Net Capability of the Plant is less than twenty thousand (20,000) kilowatts, the Qualified Capacity of the Plant shall be twenty thousand (20,000) kilowatts. (e) The Company reserves the right to impose reasonable conditions consistent with the NEPOOL standards that are in effect from time to time during the term of this Agreement in substitution for the foregoing NEPOOL standards if NEPOOL ceases to establish such standards or if the Company should cease its participation in NEPOOL during the life of this Agreement. (f) During a reasonable period of time prior to the date of commercial operation of the Plant ("Testing Period"), the Plant may generate some electric energy ("Test Power"). The Company agrees to take and pay for any Test Power offered for sale and delivered to it by Seller during the Testing Period, subject to the following conditions: (i) the tests conducted during the Testing Period shall be in accordance with standard industry practice and done under the general supervision of the administrative committee established by Article X(f) of this Agreement, and (ii) the Company shall pay for any Test Power monthly at a price equal to the Energy Purchase Price established by Article III(a)(1) hereof, computed with Factor R set equal to eighty-five percent (85%,). ARTICLE II. Effective Date and Term. (a) This Agreement shall become effective upon the date first above-written, and unless sooner terminated in accordance with any applicable provision of this Agreement, shall remain in full force and effect for a term equal to the initial term of the license for the Plant as issued by the FERC. In the event that such license is renewed or extended, this Agreement may similarly be renewed or extended at the Company's sole option by the giving of written notice to Seller within six (6) months following receipt of notice from Seller of the renewal or extension of such license. Seller agrees to use all reasonable efforts to secure a renewal or extension of such license, as the case may be. (b) The Seller shall have the option, exercisable upon not less than sixty (60) days written notice to the Company, to terminate this Agreement at PAGE 4 a date not later than November 1, 1983 if: (1) Seller is unable to obtain financing for the costs of the acquisition and construction of the Plant upon terms and at a rate of interest acceptable to Seller, or (2) Seller is unable to contract for transmission services necessary to deliver electric energy to the Company on terms and conditions acceptable to Seller, or (3) FERC fails to license the Plant or issues such a license for an initial term of less than twenty-five (25) years. (c) The Company shall have the option, exercisable upon not less than sixty (60) days written notice to Seller, to terminate this Agreement if the Plant has not entered or cannot reasonably be expected to enter commercial service by December 31, 1986. (d) Upon any termination pursuant to Articles II(b) or II(c) hereof, neither party shall have any liability to the other except such liabilities, if any, which shall have been incurred hereunder prior to such termination, which liabilities shall continue until satisfied. ARTICLE III. Purchase Price. (a) From and after the date of commercial operation of the Plant (currently estimated to be February 1, 1985), the Company shall pay Seller semi-annually an amount equal to the greatest of: (1) the Energy Purchase Price as determined in accordance with Appendix A to this Agreement multiplied times the quantity of electric energy delivered to the Company by Seller hereunder, or (2) ninety mills ($0.090) per kilowatt-hour ("Floor Energy Price") multiplied times the quantity of electric energy delivered to the Company by Seller hereunder, or (3) beginning January 1, 1992 and ending at the close of the fifteenth (15th) year following the date of commercial operation of the Plant, a price per kilowatt-hour ("Adjusted Floor Energy Price") determined by the following formula: Adjusted Floor Energy Price = 90 mills + PGNP-2 x [16.8 + PGNP-l (11.1)] Where:PGNP-1 is the cumulative percentage change in the Gross National Product Implicit Price Deflator ("PGNP") published by the United States Department of Commerce between the date of commercial operation of the Plant and December 31, 1991, and PGNP-2 is the cumulative percentage change in the PGNP after January 1, 1992, multiplied times the quantity of electric energy delivered to the Company by Seller hereunder. In the event the United States Department of Commerce should cease to publish the PGNP, the Company and Seller shall mutually PAGE 5 agree upon a satisfactory replacement therefor or, failing to so agree, shall submit the matter to arbitration in accordance with the appropriate provisions of this Agree- ment. (b) For the purpose of implementing Article III(a) of this Agreement, the Company shall pay Seller each month an amount determined in accordance with paragraph (1) thereof, subject to semi-annual reconciliation as set forth in Article III(c) below. Amounts payable to Seller pursuant to Article III(a)(1) shall be determined on an estimated basis and paid monthly in accordance with Article VII hereof, subject to a final determination and reconciliation at the end of each billing period established pursuant to Appendix A hereof. For purposes of such monthly payments, an estimated Energy Purchase Price for each rating period (as defined in Appendix A hereof) shall be determined as set forth in such Appendix A by setting Factor O-2 equal to Factor O-1. Such estimated Energy Purchase Price for each rating period shall be multiplied by the quantity of electric energy (measured in kilowatt-hours) delivered to the Company by Seller during such rating period during such month. Following the close of each such billing period, the Company will promptly determine its actual Energy Purchase Price for each rating period. Any difference between the forecast and actual Energy Purchase Price for the same billing period shall be subject to reconciling adjustment during the first month of the next subsequent billing period. (c) The Company shall semi-annually compute the weighted average price paid for electric energy purchased hereunder during the semi-annual period then ending by dividing the total of the monthly payments to Seller for electric energy by the total kilowatt-hours purchased. In the event that such weighted average semi-annual price is less than the Floor Energy Price or the Adjusted Floor Energy Price, the Company shall pay to Seller an amount equal to the difference between such weighted average semi-annual price and the greater of the Floor Energy Price or the Adjusted Floor Energy Price, multi- plied by the total kilowatt-hours purchased from Seller, all during such semi-annual period. Any "Semi-Annual Adjustments" under this Article III(c) shall be made during the first month following the semi-annual period which is being adjusted according to the provisions hereof. (d) If, after the first fifteen (15) years following the date of commercial operation of the Plant, the Company determines that the Energy Purchase Price, computed with Factor R set equal to one-hundred percent (100%), exceeds the Company's avoided energy costs (as hereinafter defined), the Company may propose a change to Appendix A by giving Seller written notice thereof. Such proposed change shall be limited to the methodology for deter- mining or calculating the Company's avoided energy costs and shall not deviate from the principle that the average decremental cost shall at least approxi- mate the most costly ten percent (10%) of the load placed upon the Company's system by its firm-service customers during the relevant billing period. In the event that Seller fails to accept said proposed change and Seller and Company are unable to agree in writing upon a mutually satisfactory revised Appendix A within sixty (60) days of the giving of such notice, either the Seller or the Company may submit the matter to arbitration pursuant to the provisions of Article X(g) and (h) below. During the period of time in which said matter is in arbitration, the proposed revised Appendix A originally offered by the Company shall govern the computation of the Energy Purchase Price. Within thirty (30) days following resolution of said dispute by PAGE 6 arbitration, the Company shall recompute, in accordance with said resolution, all amounts paid to Seller during the pendency of such dispute and debit or credit Seller's account as appropriate. (e) Avoided energy cost as used herein shall mean the incremental cost to the Company of electric energy which the Company would have generated or purchased but for the purchase of electric energy from Seller. (f) Any taxes on the production or sale of electric energy furnished by the Seller to the Company under this Agreement shall be the obligation of and paid by the Seller as and when due. ARTICLE IV. Energy Purchase Bank. (a) The Company will establish an account within its records, to be known as the Energy Purchase Bank, which shall be maintained separately from all other accounts therein. The Energy Purchase Bank shall be solely used to record such periodic energy purchase (and related) transactions and associated account balances as are specified within this Agreement as affecting such Energy Purchase Bank. (b) During the period beginning January 1, 1992 and ending at the close of the fifteenth year following the date of commercial operation of the Plant, the difference between any amounts paid to Seller pursuant to the Adjusted Floor Energy Price and the amounts that would have been paid to Seller under the greater of the Energy Purchase Price or the Floor Energy Price, whichever would otherwise have been applicable, shall be debited to the Energy Purchase Bank. Except during such period, there shall be no debit entries to the Energy Purchase Bank during the term of this Agreement. (c) During any billing period for which the Energy Purchase Bank contains a debit balance and for which the Energy Purchase Price exceeds both the Floor Energy Price and the Adjusted Floor Energy Price, any payment to Seller for electric energy purchased hereunder shall be reduced by an amount equal to the difference between the Energy Purchase Price and the greater of either the Floor Energy Price or the Adjusted Floor Energy Price multiplied by the number of kilowatt-hours purchased from Seller during such billing period (which amount shall in no event exceed the then-current debit balance of the Energy Purchase Bank). Such amount shall be credited to the Energy Purchase Bank. Said procedure shall continue throughout the term of this Agreement until the debit balance in the Energy Purchase Bank is reduced to zero. Any debit balance of the Energy Purchase Bank shall bear interest at a rate per annum which shall be at all times equal to the Base Rate of The First National Bank of Boston (or its successors) which shall mean the rate of interest designated by such Bank as its Base Rate and usually charged by it to substan- tial and responsible borrowers, as in effect from time to time. Each change in the said Base Rate shall be effective at the beginning of the business day on which such change occurs. ARTICLE V. Delivery by Seller. Electric energy generated by the Seller at the Plant shall be delivered to the Company at the 345,000 volt bus located in the Canal Electric Company switchyard at Sandwich, Massachusetts ("point of delivery") in the form of three-phase, sixty hertz alternating current at approximately 345,000 volts PAGE 7 nominal. Seller shall bear the sole cost and responsibility for securing transmission services adequate for the delivery to the Company at the point of delivery of electric energy purchased by the Company hereunder. ARTICLE VI. Meters and Metering. (a) The Company shall have the right to review and approve the metering installations required to record the quantities of electricity purchased from the Seller. Such metering equipment will be capable, inter alia, of providing data required to determine kilowatt-hours per hour purchased during each hour of each rating period established by Appendix A hereto as well as total electric energy purchased per rating period under the terms of this Agreement. Seller shall install, own, operate and maintain such metering equipment, which equipment shall be located at Seller's bus (or buses). If, for any reason, it is impractical to install meters at such bus (or buses), appropriate adjust- ments shall be made to reflect the actual amount of electric energy which would have been recorded by meters located at such bus (or buses). (b) Seller shall maintain all metering equipment installed pursuant hereto accurate by regular testing and calibration in comparison to recognized standards. The metering equipment shall be sealed, and Seller will comply with any reasonable request of the Company with regard to the presence of the Company's representative when such seals are to be broken or when the meters are to be inspected, tested or adjusted. The Company may request, at any time, a test of the accuracy of any metering equipment installed pursuant hereto and shall bear the costs thereof in the event that said requests are made more frequently than once in each twelve months. The results of all meter calibra- tions or tests, whether or not performed at the Company's request, shall be open to examination by the Company at all reasonable times. (c) Any meter tested and found to register less than or equal to one-half of one percent (0.5%) above or below the recognized comparative standard shall be considered correct and accurate. If as a result of such tests, the metering equipment is found to be defective or inaccurate, Seller shall restore it to a condition of accuracy or replace it. In such event, adjustment shall be made by the Company correcting all measurements made by the defective or inaccurate meter for either (i) the actual period during which inaccurate measurements were made, if determinable to the mutual satisfaction of the Company and Seller or (ii) if such period is not so determinable, for a period equal to one-half of the time elapsed since the last prior test, but in no event greater than twelve months. (d) Other provisions of this Article VI notwithstanding, the Company may elect to install its own metering equipment in supplement to the Seller's metering equipment. Should the Company so elect and should any metering equipment installed by the Seller fail to register the amount of electric energy delivered to the Company during any period of time, the Company's metering equipment shall be used to determine the amount of electric energy so delivered in lieu of the Company's estimates thereof. If the Company wishes its metering equipment to be so used, the Company agrees to operate, maintain and read such equipment according to the standards established by this Article VI. The Seller agrees, upon request of the Company, to provide a suitable location at the Plant for installation of the Company's meters at no cost to the Company. PAGE 8 (e) Upon written request of the Company, Seller shall install and bear the cost of such telemetering equipment and data circuits as the Company may reasonably require for the transmission of various metered values to its operations center. The design of and equipment specifications for such telemetering equipment and data circuits shall be approved by the Company prior to installation thereof by Seller. (f) Seller shall read its meters on or about the last working day of each calendar month for determination of the amount of purchases by the Company under the terms of this Agreement and shall supply the results of such meter readings to the Company within five (5) business days following the taking thereof. The time period between two successive meter readings shall be deemed to be a month for purposes of this Agreement. ARTICLE VII. Payment. (a) The Company shall determine the quantity of electric energy pur- chased from Seller monthly based upon the metered values obtained in accor- dance with the several provisions of Article VI of this Agreement as appropri- ate. The Company, after giving due effect to any reconciling adjustments necessary, shall pay Seller for such electric energy monthly within twenty (20) calendar days following receipt of such metered values from Seller and shall show the derivation of such payment in such detail as Seller may reasonably request from time to time. (b) In the event that any data required for the purpose of determining payment hereunder are unavailable when required, such unavailable data may be estimated by the Company, subject to any required adjustment based upon actual data in a subsequent payment month. ARTICLE VIII. Governmental Regulation. (a) This Agreement shall, within ten (10) days of the date hereof, be submitted by the Company to the Massachusetts Department of Public Utilities ("MDPU") in accordance with Section 94A, Chapter 164, of the Massachusetts General Laws and applicable regulations of the MDPU, and the Company shall use its best efforts to obtain expeditious approval thereof in accordance with such law and regulations. (b) It shall be the responsibility of each party hereto individually to take all necessary actions to satisfy any regulatory requirements which may be imposed upon such party by any federal, state or municipal statute, rule, regulation or ordinance which may be in effect from time to time relative to the performance of such party hereunder. (c) This Agreement and all rights and obligations of the parties hereunder are subject to all applicable state and federal laws and all duly promulgated orders and duly authorized actions of governmental authorities. (d) The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the Commonwealth of Massachu- setts. PAGE 9 ARTICLE IX. Liability and Force Majeure. (a) The parties hereto shall be excused from performing hereunder and shall not be liable in damages or otherwise if and only to the extent that they are unable to do so or are prevented from doing so by statute or regula- tion or by action of any court or public authority having or purporting to have jurisdiction in the premises; or by loss or impairment of the supply of electricity; or by a break or fault in the Company's transmission or distribu- tion system or failure or improper operation of transformers, switches or other equipment necessary for receipt of electric energy from Seller; or by reason of storm, flood, fire, earthquake, explosion, civil disturbance, labor dispute, act of God or the public enemy, failure of any supplier to perform, restraint by a court or regulatory agency, or any other cause, whether or not similar thereto, beyond the reasonable control of the affected party. Each party shall have the obligation to operate in accordance with good utility practices at all times and to use diligent effort to remove any cause of failure to supply or receive electric energy hereunder. Neither the Company nor Seller shall, in any event, be liable to the other or to any third party for any consequential, indirect or special damages to persons or property, whether arising in tort, contract or otherwise, by reason of this Agreement or any services performed or undertaken to be performed by the Company or Seller hereunder, except as otherwise expressly provided herein. (b) Whenever the Company's system or the systems with which it is directly or indirectly interconnected experience a "System Emergency", or whenever it is needful or desirable to aid in the restoration of service on its system or on the systems with which it is directly or indirectly intercon- nected, the Company may, in its reasonable judgment, curtail or interrupt the taking of electric energy hereunder, provided such curtailment or interruption shall continue only for so long as is reasonably necessary. Such curtailment, interruption, or reduction shall not be deemed to be a default by the Company nor shall the Company be liable therefor to Seller or to any other party. A System Emergency means a condition on a utility's system which is likely to result in an imminent significant disruption of service or is imminently likely to endanger life or property. Notwithstanding any other provision of this Agreement to the contrary, in the event that the Company cannot receive electric energy from Seller into its own system because of a System Emergency but such System Emergency does not prevent Seller from delivering such electric energy to another utility with which the Company is interconnected, the Company shall pay Seller for such electric energy so delivered the exact amount, if any, that the Company receives in payment or credit from such utility for the delivery of such electric energy. (c) The Company and the Seller agree that each shall be responsible for the electricity on its respective side of the point of delivery and shall indemnify, save harmless and defend the other against all claims, demands, costs or expenses for loss, damage or injury to persons or property in any manner directly or indirectly arising from, connected with or growing out of the presence or use of electricity or the transmission of electricity over the wires, cables, devices or appurtenances owned by it, its agents or suppliers, saving only such loss, damage or injury as may be caused by the willful or negligent act of the other. The Company and the Seller respectively assume full responsibility in connection with the service rendered hereunder for their respective wires, cables and other devices used in connection with said service. Each party hereto shall be solely liable for all claims of its own PAGE 10 employees arising from any workmen's compensation laws. (d) Neither by inspection nor non-rejection nor in any other way does either party give any warranty, expressed or implied, as to the adequacy, safety or other characteristics of any equipment, apparatus or devices, installed on the premises of or used by the other party, its agents or suppliers. Neither party shall be liable to the other for damages resulting in any way from its taking or supplying of electric energy pursuant to the terms of this Agreement or from the presence or operation of its apparatus, meters, appurtenances or other equipment on the premises of the other party. (e) Seller may from time to time withdraw the Plant from service and cease to supply electric energy to the Company as necessary to perform scheduled or unscheduled maintenance or repair upon the Plant. Seller shall comply with the provisions of NEPOOL Operating Procedure No. 5 as in effect from time to time when planning any scheduled maintenance or repair upon the Plant. Seller shall give the Company such notice as may be practicable in the circumstances when withdrawing the Plant from service for unscheduled mainte- nance or repair. ARTICLE X. Miscellaneous Provisions (a) This Agreement constitutes the entire Agreement between the parties relating to the subject matter hereof, and all previous agreements, discus- sions, communications and correspondence with respect to the subject matter hereof are superseded by the execution of this Agreement. (b) This Agreement may not be modified or amended except in writing signed by or on behalf of both parties by their duly authorized officers. (c) Any qualified and properly identified employee of the Company shall have access to the Plant at all reasonable times for the purpose of reading or inspecting meters, examining the operation of the Plant or other purposes reasonably related to the Company's performance under the terms of this Agreement. Such access shall not interfere with Seller's normal business operations. (d) This Agreement shall inure to the benefit of and bind the respective successors and permitted assigns of the parties hereto, provided, however, that no assignment by Seller or any successor or assignee of Seller of its rights and obligations hereunder, except an assignment to a wholly-owned subsidiary whose principal functions are to hold Seller's ownership interest in and to operate the Plant, shall be made or become effective without the prior written consent of the Company in each case obtained. The Company will provide consent to any assignment of Seller's rights and obligations hereunder to the extent necessary for Seller to obtain construction or permanent financing for the Plant with an institutional lender and to assure that the Company's right to receive the output of the Plant shall apply as against any person or entity that might obtain title and possession of the Plant pursuant to such financing. (e) All notices required or permitted under this Agreement shall be in writing and shall be deemed to have been given when delivered personally or deposited in the mails, postage prepaid, registered mail addressed to the party to whom notice is being given at its address set forth above. Either PAGE 11 party may change its address by notice similarly given. (f) The parties hereto agree to establish an administrative committee. Such committee will be empowered to do all acts and things necessary to implement the intent of the parties hereto as set forth herein and to take such further actions as may be required in the circumstances, provided that they are not inconsistent with this Agreement. The Company and Seller shall have equal representation upon said committee. (g) In the case of any dispute between the parties with respect to the interpretation of this Agreement, or the performance of the same, or under Article III(d) above, either party may give notice in writing to the other of its desire to submit such questions to arbitration, and may designate an arbitrator. Within thirty (30) days after the receipt of such notice, the other party may, in writing, serve upon the party invoking such arbitration, a notice designating an arbitrator on its behalf. The two arbitrators so chosen shall, within twenty (20) days after the appointment of the second arbitrator, in writing, designate a third arbitrator. Upon the failure of the party notified to appoint the second arbitrator within such time, the party invoking such arbitration may proceed with the single arbitrator. If the first and second arbitrators are unable to agree on a third arbitrator within twenty (20) days of the appointment of the second arbitrator, the first and second arbitrator shall invoke the services of the American Arbitration Association to appoint a third arbitrator. Said third arbitrator shall, to the extent practicable, have special competence and experience with respect to the subject matter under consideration. An arbitrator so appointed shall have full authority to act pursuant to this Article. No arbitrator, whether chosen by a party hereto or appointed, shall have the power to amend or add to this Agreement. (h) The party calling the arbitration shall, within twenty (20) days after either the failure of the other party to name an arbitrator, or the appointment of the third arbitrator, as the case may be, fix, in writing, a time and a place of hearing, to be not less than twenty (20) days from delivery of notice to the other party. The arbitrator or arbitrators shall, thereupon, proceed promptly to hear and determine the controversy pursuant to the then-current rules of the American Arbitration Association for the conduct of commercial arbitration proceedings, except that if such rules shall conflict with the then current provisions of the laws of the Commonwealth of Massachusetts relating to arbitration, such conflict shall be governed by the then current provisions of the laws of the Commonwealth of Massachusetts relating to arbitration. Such arbitrator or arbitrators shall fix a time within which the matter shall be submitted to him or them by either or both of the parties, and shall make his or their decision, within ten (10) days after the final submission to him or them unless, for good reasons to be certified by him or them in writing, he or they shall extend such time. The decision of the single arbitrator, or two of the three arbitrators, shall be taken as the arbitration decision. Such decision shall be made in writing and in duplicate, and one copy shall be delivered to each of the parties. The expense of the arbitration shall be borne by the unsuccessful party, unless the arbitrator or arbitrators by his or their award shall otherwise provide, except that each party shall pay the costs of its own counsel. Each party shall accept and abide by the decision. The award of the arbitral tribunal shall be final except as otherwise provided by applicable law. Judgment upon such award may be entered by the prevailing party in any court having jurisdiction thereof, PAGE 12 or application may be made by such party to any such court for judicial acceptance of such award and an order of enforcement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed as of the day and year first above written. COMMONWEALTH ELECTRIC COMPANY By: J. V. Donovan, Executive Vice President CORPORATION INVESTMENTS, INC. By: Eldred L. Field, Chairman PAGE 13 APPENDIX A ENERGY PURCHASE PRICE The Energy Purchase Price applicable to electric energy delivered to the Company by Seller during any billing period will be equal to the rate, taken to the nearest one-tenth of a mill per kilowatt-hour, determined in accordance with the following formula, separately applied to each rating period hereinaf- ter defined: P = R X F (O-2/O-1) Where: P = Energy purchase price R = Avoided cost ratio F = Average decremental cost of generated and/or purchased energy. O-2 = Actual cost of energy produced and/or purchased from fossil fuels O-1 = Estimated cost of energy produced and/or purchased from fossil fuels (1) Definitions (a) Factor R. During the first fifteen (15) years following the date of commercial operation of the Plant, Factor R shall be eighty-five percent (85%). During the sixteenth such year, Factor R shall be eighty percent (80%). During the seventeenth such year and for the remaining term of this Agreement, Factor R shall be seventy-five percent (75%). (b) Factor F. Factor F shall be the Company's estimated average decremental cost of generated and/or purchased energy as delivered to its system, separately determined (as set forth herein) for each billing period hereinafter defined. Factor F shall be computed not more than sixty (60) days prior to the beginning of such billing period. Said average decremental cost of energy shall be defined by the following formula, taken to the nearest one-tenth of a mill per kilowatt-hour: F = Cost-1 - Cost-2/KWH-1 - KWH-2 where: Cost-1 and KWH-1 represent the estimated cost and quantity (respectively) of energy generated and/or purchased by the Company to meet one-hundred percent (100%) of the load placed upon its system by its firm-service customers during any billing period. Cost-2 and KWH-2 represent the estimated cost and quantity (respectively) of energy generated and/or purchased by the Company to meet ninety percent (90%) of the load placed upon its system by its firm ser- vice customers during the same billing period. PAGE 14 (c) Factors O. The two Factors O shall be the average cost of energy generated by and/or purchased from generating units fired with fossil fuels during any billing period, either as actually experienced by the Company during such billing period (Factor O-2) or as estimated by the Company for such billing period (Factor O-1) and as included in its computations determin- ing the average decremental cost of energy, all measured to the nearest one-tenth of a mill per kilowatt-hour. (2) Billing Period A billing period hereunder shall be any three (3) month period beginning January first, April first, July first and October first of any year during the term of this Agreement. (3) Rating Periods There shall be two rating periods for purposes of computing the Energy Purchase Prices. The Peak Period shall be defined as all hours in the billing period from 9:00 A.M. to 9:00 P.M. Eastern Standard Time on weekdays (Monday through Friday). The Off-Peak Period shall include all hours in the billing period not included in the Peak Period. The Company reserves the right to revise the definition of its rating periods from time to time during the term of this Agreement upon reasonable notice to Seller. PAGE 15 SCHEDULE B COMMONWEALTH ELECTRIC COMPANY ESTIMATED PURCHASE FROM CORPORATION INVESTMENTS, INC. TWELVE MONTHS ENDING JANUARY 31, 1986 ENERGY PURCHASE (KWH) COST OF ENERGY (* ) PEAK OFF-PEAK TOTAL PEAK OFF-PEAK TOTAL 1985 February 3146760 5594240 8741000 283208 503482 786690 March 3117960 5543040 8661000 280616 498874 779490 April 3494160 6211840 9706000 314474 559066 873540 May 3102480 5515520 8618000 279223 496397 775620 June 3672360 6528640 10201000 330512 587578 918090 July 2682360 4768640 7451000 241412 429178 670590 August 1539720 2737280 4277000 138575 246355 384930 September 1285920 2286080 3572000 115733 205747 321480 October 1198440 2130560 3329000 107860 191750 299610 November 1729440 3074560 4804000 155650 276710 432360 December 2708280 4814720 7523000 243745 433325 677070 1986 January 3282120 5834880 9117000 295391 525139 820530 Total 12 mos. 30960000 55040000 86000000 2786400 4953600 7740000 (*) The energy purchase price is estimated to be 90 mills per kwh pursuant to Article III(a)(2) of the agreement. -----END PRIVACY-ENHANCED MESSAGE-----