-----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, tvOlA7qDAdwPqmoHeUh7JzlIHUeK6Qe2V6ibci6FWilxOxLBpiW1M9qhMMVFCbCS zhDqr/W9K0og82zOIp7RCg== 0000071304-94-000035.txt : 19941116 0000071304-94-000035.hdr.sgml : 19941116 ACCESSION NUMBER: 0000071304-94-000035 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19940930 FILED AS OF DATE: 19941114 SROS: BSE SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: COMMONWEALTH ENERGY SYSTEM CENTRAL INDEX KEY: 0000071304 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 041662010 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-07316 FILM NUMBER: 94559259 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 ENGLAND GAS & ELECTRIC ASSOCIATION DATE OF NAME CHANGE: 19810603 10-Q 1 COMMONWEALTH ENERGY SYSTEM FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549-1004 FORM 10-Q (Mark One) X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For quarterly period ended September 30, 1994 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________________ to ________________ Commission File Number 1-7316 COMMONWEALTH ENERGY SYSTEM (Exact name of registrant as specified in its Declaration of Trust) Massachusetts 04-1662010 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One Main Street, Cambridge, Massachusetts 02142-9150 (Address of principal executive offices) (Zip Code) (617) 225-4000 (Registrant's telephone number, including area code) (Former name, address and fiscal year, if changed since last report) 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 November 1, 1994 Common Shares of Beneficial Interest, $4 par value 10,521,774 shares PART I. - FINANCIAL INFORMATION Item 1. Financial Statements COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONDENSED BALANCE SHEETS SEPTEMBER 30, 1994 AND DECEMBER 31, 1993 ASSETS (Unaudited) September 30, December 31, 1994 1993 (Dollars in Thousands) PROPERTY, PLANT AND EQUIPMENT, at original cost Electric $1 036 929 $1 018 121 Gas 332 005 322 314 Other 58 455 58 473 1 427 389 1 398 908 Less - Accumulated depreciation and amortization 455 443 425 483 971 946 973 425 Add - Construction work in progress and nuclear fuel in process 11 393 11 089 983 339 984 514 LEASED PROPERTY, net 15 594 16 150 INVESTMENTS Nuclear electric power companies (2.5% to 4.5%) 10 004 9 660 Other investments 3 896 3 889 13 900 13 549 CURRENT ASSETS Cash 3 675 6 007 Accounts receivable 70 946 93 663 Unbilled revenues 18 445 43 279 Inventories, at average cost 36 604 36 102 Prepaid taxes and other 19 879 15 231 149 549 194 282 DEFERRED CHARGES 126 105 106 668 $1 288 487 $1 315 163 COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONDENSED BALANCE SHEETS SEPTEMBER 30, 1994 AND DECEMBER 31, 1993 CAPITALIZATION AND LIABILITIES (Unaudited) September 30, December 31, 1994 1993 (Dollars in Thousands) CAPITALIZATION Common share investment - Common shares, $4 par value - Authorized - 18,000,000 shares Outstanding - 10,460,623 in 1994 and 10,295,077 in 1993 $ 41 842 $ 41 180 Amounts paid in excess of par value 100 980 94 657 Retained earnings 214 865 201 233 357 687 337 070 Redeemable preferred shares, less current sinking fund requirements 14 660 15 480 Long-term debt, including premiums, less current sinking fund requirements and maturities 437 137 448 893 809 484 801 443 CAPITAL LEASE OBLIGATIONS 14 026 14 456 CURRENT LIABILITIES Interim Financing - Notes payable to banks 13 925 71 975 Maturing long-term debt 20 000 10 000 33 925 81 975 Other Current Liabilities - Current sinking fund requirements 6 793 6 793 Accounts payable 86 240 90 006 Accrued taxes 20 711 9 090 Other 38 774 37 322 152 518 143 211 186 443 225 186 DEFERRED CREDITS Accumulated deferred income taxes 162 676 156 851 Unamortized investment tax credits and other 115 858 117 227 278 534 274 078 COMMITMENTS AND CONTINGENCIES $1 288 487 $1 315 163 See accompanying notes. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONDENSED STATEMENTS OF INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER, 30, 1994 AND 1993 (Unaudited) Three Months Ended Nine Months Ended 1994 1993 1994 1993 (Dollars in Thousands) OPERATING REVENUES Electric $174 421 $168 510 $493 500 $465 987 Gas 46 251 47 429 244 557 222 098 Steam and other 2 627 1 945 11 780 10 048 223 299 217 884 749 837 698 133 OPERATING EXPENSES Fuel and purchased power 95 516 94 484 277 536 259 129 Cost of gas sold 29 263 30 526 137 185 120 113 Other operation and maintenance 62 185 58 417 190 082 190 188 Depreciation 9 724 9 436 32 963 31 704 Taxes - Local property and other 5 470 4 882 19 074 18 830 Federal and state income 3 502 4 098 23 022 19 374 205 660 201 843 679 862 639 338 OPERATING INCOME 17 639 16 041 69 975 58 795 OTHER INCOME (EXPENSE) (759) 530 49 5 110 INCOME BEFORE INTEREST CHARGES 16 880 16 571 70 024 63 905 INTEREST CHARGES Long-term debt 9 942 9 632 29 644 27 877 Other interest charges 830 1 330 2 804 4 276 Allowance for borrowed funds used during construction (108) (87) (351) (181) 10 664 10 875 32 097 31 972 NET INCOME 6 216 5 696 37 927 31 933 Dividends on preferred shares 294 309 888 933 EARNINGS APPLICABLE TO COMMON SHARES $ 5 922 $ 5 387 $ 37 039 $ 31 000 AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 10 440 347 10 231 955 10 383 895 10 194 489 EARNINGS PER COMMON SHARE $ .57 $ .52 $3.57 $3.04 DIVIDENDS DECLARED PER COMMON SHARE $ .75 $ .73 $2.25 $2.19 See accompanying notes. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES CONDENSED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1994 AND 1993 (Unaudited) 1994 1993 (Dollars in Thousands) OPERATING ACTIVITIES Net income $ 37 927 $ 31 933 Effects of non-cash items - Depreciation and amortization 43 066 39 672 Deferred income taxes and investment tax credits, net 6 506 5 107 Equity earnings from corporate joint ventures (1 313) (1 202) Dividends from corporate joint ventures 962 1 237 Change in working capital, exclusive of cash and interim financing 51 708 38 410 All other operating items (31 450) (23 619) Net cash provided by operating activities 107 406 91 538 INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) - Electric (19 818) (18 807) Gas (11 351) (14 766) Other (282) (974) Allowance for borrowed funds used during construction (351) (181) Net cash used for investing activities (31 802) (34 728) FINANCING ACTIVITIES Sale of common shares 6 985 4 862 Payment of dividends (24 295) (23 288) Payment of short-term borrowings (58 050) (77 325) Long-term debt issues - 65 000 Long-term debt issues refunded - (21 300) Sinking funds payments (2 576) (2 589) Net cash used for financing activities (77 936) (54 640) Net increase (decrease) in cash (2 332) 2 170 Cash at beginning of period 6 007 1 522 Cash at end of period $ 3 675 $ 3 692 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the period for: Interest (net of capitalized amounts) $ 29 635 $ 28 513 Income taxes $ 14 088 $ 13 472 See accompanying notes. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Accounting Policies Commonwealth Energy System, the parent company, is referred to in this report as the "System" and together with its subsidiaries is sometimes collectively referred to as "the system." The system's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in its 1993 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For interim reporting purposes, the system follows these same basic accounting policies but considers each interim period as an integral part of an annual period and makes allocations of certain expenses to interim periods based upon estimates of such expenses for the year. Regulated subsidiaries of the System have established various regulatory assets in cases where the Massachusetts Department of Public Utilities (DPU) and/or the Federal Energy Regulatory Commission (FERC) have permitted, or are expected to permit, recovery of specific costs over time. Similarly, certain regulatory liabilities established by the system are required to be refunded to customers over time. As of September 30, 1994, principal regulatory assets included in deferred charges were $20 million for transition costs associated with FERC Order 636, $17.9 million for postretirement benefit costs including pensions, $13.2 million for abandonment and nonconstruction costs related to the Seabrook project, $13.2 million for unrecovered plant and decommissioning costs for the Yankee Atomic nuclear plant, $11.5 million for Commonwealth Electric Company's (Commonwealth Electric) rate stabilization plan, $7.3 million related to deferred income taxes and $7.1 million in litigation costs associated with a settlement agreement with Boston Edison Company relative to the Pilgrim nuclear plant. The principal regulatory liability, reflected in deferred credits, was $17.7 million related to income taxes. Generally, expenses which relate to more than one interim period are allocated to other periods to more appropriately match revenues and expenses. Principal items of expense which are allocated other than on the basis of passage of time are depreciation and property taxes of the gas subsidiary, Commonwealth Gas Company (Commonwealth Gas). These expenses are recorded for interim reporting purposes based upon projected gas revenue. Income tax expense is recorded using the statutory rates in effect applied to book income subject to tax for each interim period. The unaudited financial statements for the periods ended September 30, 1994 and 1993, reflect, in the opinion of the System, all adjustments necessary to summarize fairly the results for such periods. In addition, certain prior period amounts are reclassified from time to time to con- form with the presentation used in the current period's financial statements. The results for interim periods are not necessarily indicative of results for the entire year because of seasonal variations in the consumption of energy and Commonwealth Gas' seasonal rate structure. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES (2) Commitments and Contingencies (a) Construction The system is engaged in a continuous construction program presently estimated at $358.3 million for the five-year period 1994 through 1998. Of that amount, $71.9 million is estimated for 1994. The program is subject to periodic review and revision. (b) Decommissioning of Nuclear Power Plants The system, through Canal Electric Company (Canal), has a 3.52% joint-ownership interest in the Seabrook nuclear power plant. Canal and the other joint owners have established a Seabrook Nuclear Decommissioning Financing Fund to cover post operational decommissioning costs. The estimated cost to decommission the plant is $378 million, in 1994 dollars, through September 30, 1994. Canal's share, less its share of the market value of the decommissioning trust ($995,000), amounts to approximately $12.3 million. The system also has equity ownership interests in four nuclear generating facilities in New England and is obligated to pay its proportionate share of the capacity and energy costs associated with these units, which include depreciation, operations and maintenance, a return on invested capital and the estimated cost of decommissioning the nuclear plants at the end of their estimated service lives. Pertinent information with respect to projected decommissioning costs, in 1994 dollars, resulting from life-of-the-unit contracts from those units still operating is as follows: Connecticut Maine Vermont Yankee Yankee Yankee (Dollars in Millions) Equity ownership (%) 4.50 4.00 2.50 Plant entitlement (%) 4.50 3.59 2.25 Plant capability (MW) 560.0 870.0 496.0 Company entitlement (MW) 25.2 31.2 11.2 Contract expiration date 1998 2008 2012 Decommissioning cost estimate (100%) ($) 356.5 338.2 325.3 System's decommissioning cost ($) 16.0 12.1 7.3 Market value of assets (100%) ($) 145.5 74.3 111.1 System's market value of assets ($) 6.5 2.7 2.5 In February 1992, the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) agreed to permanently discontinue power operation and decommission the Yankee Nuclear Power Station (the plant). At September 30, 1994, Cambridge Electric Light Company's (Cambridge Electric) and Commonwealth Electric's respective 2% and 2.5% investment in Yankee Atomic is approximately $1.1 million. The companies' estimated decommissioning costs include its unrecovered share of all costs associ- ated with the shutdown of the plant, recovery of its plant investment, and decommissioning and closing the plant. The amount currently reflected in COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES the accompanying Balance Sheets as a liability and a corresponding regulatory asset is $13.2 million. The market value of the companies' share of assets in the plant's decommissioning fund at September 30, 1994 is approximately $4.7 million. On October 26, 1994, Yankee Atomic filed with the Nuclear Regulatory Commission a revised estimate to decommission the plant of $370 million (in 1994 dollars). The total cost to permanently shut down the plant is approximately $438.6 million. The companies' share of this liability is approximately $19.7 million. The companies are reviewing Yankee Atomic's filing and adjustments to the liability and regulatory asset accounts will be made as appropriate during the fourth quarter of 1994. (c) Environmental The system is subject to laws and regulations administered by federal, state and local authorities relating to the quality of the environment. These laws and regulations affect, among other things, the siting and operation of electric generating and transmission facilities and can require the installation of expensive air and water pollution control equipment. These regulations have had an impact upon the system's operations in the past and will continue to have an impact upon future operations, capital costs and construction schedules of major facilities. For additional information, see "Environmental Matters" in Management's Discussion and Analysis of Financial Condition and Results of Operations. (d) FERC Order No. 636 As a result of implementing FERC Order No. 636 (Order 636), each interstate pipeline company is allowed to collect certain transition costs from their customers that resulted from the pipelines' need to buy out gas supply contracts entered into prior to the issuance of Order 636. Commonwealth Gas has been billed a total of approximately $24.5 million from Tennessee Gas Pipeline Company (Tennessee), Algonquin Gas Transmission Company and Texas Eastern Transmission Company (Texas Eastern) through September 30, 1994. As of October 29, 1993, Commonwealth Gas received preliminary DPU authorization to recover these costs, with carrying charges, through the cost of gas adjustment (CGA) over a four-year period that began in November 1993. As a result, a regulatory asset totaling $20 million is reflected in deferred charges as of September 30, 1994. In addition, a related liability of $6.7 million is reflected in deferred credits. After extensive negotiations between Texas Eastern, Tennessee and their customers (including Commonwealth Gas), settlements were reached regarding a number of transition obligation issues. The settlement with Texas Eastern, which was recently approved by FERC, calls for the pipeline to absorb approximately 20% of all transition costs incurred from June 1993 forward. This agreement also provides for an extended billing period and annual caps on the collection of future costs. Commonwealth Gas believes that the absorption requirement will give the pipeline incentive to minimize future costs. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The settlement with Tennessee, which has yet to be approved by FERC, will lower one element of Commonwealth Gas' transition obligation by approximately $1 million. Further negotiations are underway with Tennessee to craft a total settlement similar to that achieved with Texas Eastern. Commonwealth Gas is continuing to negotiate with the pipelines on several other issues. As a result Commonwealth Gas is unable to predict its final transition obligation at this time, however, based on these and subsequent settlement activities, Commonwealth Gas will adjust its regulatory asset and liability accounts accordingly. (e) Rate Stabilization Plan Commonwealth Electric implemented a Fuel Charge (FC) rate settlement on April 1, 1994 that will stabilize its quarterly FC rate during the years 1994 through 1996 at 6.5 cents per KWH and no greater than 6.7 cents per KWH during 1997. The settlement results in billing at a significantly lower rate than would have otherwise been in effect and could save custom- ers between 1.75% and 5% on their annual electric bills from 1994 through 1997. This rate stabilization results from the use of a cost deferral mechanism that was sponsored jointly by Commonwealth Electric and the Massachusetts Attorney General and approved by the DPU. The deferred costs are being reflected as a regulatory asset to be recovered, with carrying charges, over the subsequent six-year period beginning in 1998 pursuant to a recovery schedule subject to DPU review. The deferred amount, excluding carrying charges, is restricted to a maximum of $40 million during the settlement period (1994 through 1997) and is further limited to an annual cost deferral of $16 million which is the amount Commonwealth Electric anticipates will be deferred in 1994. As of September 30, 1994, Commonwealth Electric has deferred $11.5 million, including carrying charges. The rate stabilization mechanism is part of a long-term plan to control Commonwealth Electric's retail rates. This plan will help to eliminate the disincentive for economic development resulting from a volatile and unpredictable FC rate. The stabilized FC rate will enable current and prospective customers to better plan their business and personal finances in a more efficient and effective manner. In addition to the Massachusetts Attorney General, this proposal has been widely supported by various business and customer groups and other political interests. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Condition Capital resources of the System and its subsidiaries are derived principally from retained earnings and equity funds provided through the System's Dividend Reinvestment and Common Share Purchase Plan (DRP). Supplemental interim funds are borrowed on a short-term basis and, when necessary, replaced with new equity and/or debt issues through permanent financing secured on an individual company basis. The system purchases 100% of all subsidiary common stock issues and provides, to the extent possible, a portion of the subsidiaries' short-term financing needs. These capital resources provide the funds required for the subsidiary companies' construction programs, current operations, debt service and other capital requirements. For the first nine months of 1994, cash flows from operating activities amounted to approximately $107.4 million and reflect net income of $37.9 million and non-cash items such as depreciation ($33.4 million), amortization ($9.7 million) and deferred income taxes (net of investment tax credits) which amounted to $6.5 million. The change in working capital since December 31, 1993, exclusive of the changes in cash ($2.3 million) and interim financing ($58.1 million), amounted to $51.7 million and had a significant positive effect on cash flows from operating activities. The working capital change reflects lower levels of unbilled revenues ($24.8 million) and accounts receivable ($22.7 million) coupled with higher levels of accrued taxes ($11.6 million) and other miscellaneous current liabilities ($1.3 million). These were offset, in part, by a higher level of prepaid property taxes ($5.8 million) and a lower level of accounts payable ($3.8 million). The change in all other operating items of $31.5 million includes an $11.5 million regulatory asset established pursuant to Commonwealth Electric's rate stabilization plan and a $6.4 million increase in the regulatory asset pertaining to postretirement benefits for both electric and gas operating subsidiaries. Construction expenditures for the first nine months of 1994 were approximately $31.8 million, including nuclear fuel and an allowance for funds used during construction (AFUDC). Construction expenditures for the period, together with the preferred and common dividend requirements of the System ($24.3 million), were funded entirely with internally generated funds. In addition, short-term borrowings were reduced by $58.1 million to $13.9 million for the most part with internal funds generated from higher retail unit sales for both the electric and gas divisions during the first nine months of this year and continued cost containment efforts. 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 condensed statements of income. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES This discussion should be read in conjunction with the Notes to Condensed Financial Statements appearing elsewhere in this report. A summary of the period to period changes in the principal items included in the condensed statements of income for the three and nine months ended September 30, 1994 and 1993 is shown below: Three Months Nine Months Ended September 30, Ended September 30, 1994 and 1993 1994 and 1993 Increase (Decrease) (Dollars in Thousands) Operating Revenues Electric $ 5 911 3.5% $ 27 513 5.9% Gas (1 178) (2.5) 22 459 10.1 Steam and other 682 35.1 1 732 17.2 5 415 2.5 51 704 7.4 Operating Expenses Fuel and purchased power 1 032 1.1 18 407 7.1 Cost of gas sold (1 263) (4.1) 17 072 14.2 Other operation and maintenance 3 768 6.5 (106) (0.1) Depreciation 288 3.1 1 259 4.0 Taxes - Local property and other 588 12.0 244 1.3 Federal and state income (596) (14.5) 3 648 18.8 3 817 1.9 40 524 6.3 Operating Income 1 598 10.0 11 180 19.0 Other Income (1 289) (243.2) (5 061) (99.0) Income Before Interest Charges 309 1.9 6 119 9.6 Interest Charges (211) (1.9) 125 0.4 Net Income 520 9.1 5 994 18.8 Dividends on preferred shares (15) (4.9) (45) (4.8) Earnings Applicable to Common Shares $ 535 9.9 $ 6 039 19.5 The following are the period to period changes in electric and gas unit sales for the three and nine months ended September 30, 1994 and 1993. Unit Sales Electric - Megawatthours (MWH) Retail 36 492 3.0 86 549 2.5 Wholesale (151 111) (14.9) 245 032 8.6 (114 619) (5.1) 331 581 5.3 Gas - Billions of British Thermal Units (BBTU) Firm 80 2.6 1 164 4.3 Interruptible 3 040 335.2 4 756 334.5 3 120 77.4 5 920 20.9 COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES Three Months Ended Nine Months Ended September 30, September 30, 1994 1993 1994 1993 Electric Sales - MWH Residential 468 998 450 210 1 360 515 1 321 794 Commercial 589 229 575 414 1 565 199 1 522 381 Industrial 113 108 109 126 314 505 304 439 Other 90 917 91 010 284 971 290 027 Total retail sales 1 262 252 1 225 760 3 525 190 3 438 641 Wholesale to other systems 865 562 1 016 673 3 085 321 2 840 289 Total 2 127 814 2 242 433 6 610 511 6 278 930 Gas Sales - BBTU Residential 1 413 1 449 15 774 15 370 Commercial 953 975 7 874 7 582 Industrial 720 618 3 114 2 815 Other 119 83 1 354 1 185 Total firm sales 3 205 3 125 28 116 26 952 Interruptible sales 3 947 907 6 178 1 422 Total 7 152 4 032 34 294 28 374 Electric Revenues, Fuel and Purchased Power and Electric Unit Sales For the first nine months of 1994 electric operating revenues increased $27.5 million or 5.9% due primarily to higher fuel and purchased power costs, higher base rates for Cambridge Electric which became effective June 1, 1993 and higher retail unit sales (discussed below). This increase was slightly offset by a $900,000 reduction in conservation and load management costs (C&LM) for electric operations which are being recovered through revenues. The recovery of lost base revenues related to the C&LM programs increased by $313,000 and $720,000 for the current quarter and nine-month period, respectively, when compared to the same reporting periods during 1993. The recovery of lost base revenues is allowed by the DPU to encourage effective implementation of C&LM programs. To the extent that current costs associated with C&LM programs increase or decrease from period to period based on customer participation, a corresponding change will occur in revenues. For the current nine-month period, fuel and purchased power costs increased $18.4 million or 7.1% and averaged 4.2 cents per KWH compared to 4.1 cents per KWH for the same period in 1993 and reflects purchases from higher-cost non-utility generators and, to a lesser extent, higher fuel oil costs at Canal Electric's generating station. The increases were moderated by the deferral of $11.1 million of costs related to Commonwealth Electric's rate stabilization mechanism which was implemented on April 1, 1994. The increase of 2.5% in retail unit sales for the current nine-month period reflects higher unit sales to the residential (2.9%), commercial (2.8%) and industrial (3.3%) sectors that resulted from the extreme cold weather conditions experienced in the system's service territory during the first quarter. Retail unit sales for the quarter were 3% higher and reflect a record peak demand of 962 MW achieved on July 21, 1994. The COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES fluctuation in wholesale unit sales during the current quarter and nine- month period reflects the changing capacity needs of the New England Power Pool and non-affiliated utilities. Changes in the level of wholesale electric sales have little, if any, impact on net income. Gas Revenues, Cost of Gas Sold and Gas Unit Sales For the current nine-month period, gas operating revenues increased approximately $22.5 million or 10.1% due primarily to an increase in the cost of gas sold ($14.2 million), higher C&LM costs ($2.5 million) and higher firm and interruptible sales. Despite the increase in the cost of gas sold, the average cost of gas per MMBTU during the current quarter and nine-month period decreased from $7.57 to $4.09 and from $4.23 to $4.00, respectively. The decrease from both periods of last year was mainly due to the inclusion of transition charges related to Order 636 in the cost of gas sold last year. These charges totaled $6.8 million and $9.6 million in the prior third quarter and nine-month period, respectively. In the fourth quarter of 1993, these charges were reclassified as a regulatory asset pursuant to the aforementioned DPU order issued on October 29, 1993. Commonwealth Gas will recover these costs, with carrying charges, over a four-year period which began in November 1993. For the current nine-month period firm gas unit sales increased 4.3% as each customer segment showed improvement due primarily to the extreme cold weather experienced during the first quarter of 1994. Although interruptible sales increased significantly during both the current nine months and third quarter of 1994, fluctuations in the level of these sales have little, if any, impact on net income. Steam and Other Operating Revenue Steam and other operating revenue increased 35.1% and 17.2% during the current quarter and nine-month period, respectively, due primarily to higher steam sales to Harvard University, Massachusetts General Hospital and a biotechnology company which became a steam customer in August 1993. Other Operating Expenses For the first nine months of 1994, other operation and maintenance costs were virtually unchanged compared to the same period in 1993 reflecting savings resulting from the second quarter 1993 work force reduction ($2.7 million), the absence of severance pay incurred in 1993 ($3.7 million), lower maintenance activity ($1.3 million) and a decline in the provision for bad debts due to improved collection experience ($1.1 million). These factors were offset, somewhat, by higher levels of current and amortized C&LM charges ($1.6 million) and insurance and employee benefit costs ($1.6 million). The 6.5% or $3.8 million increase in other operation and maintenance for the three months ended September 30, 1994 was due to increases in insurance and employee benefit costs ($1.8 million), increased maintenance expense on Canal Electric's Unit 1 ($951,000), a higher level of current COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES C&LM costs incurred at Commonwealth Gas ($464,000) and slightly higher payroll costs ($318,000). Depreciation and Taxes Depreciation expense increased 3.1% and 4% during the current quarter and current nine-month period, respectively, due to higher levels of plant in service. The change in local property and other taxes for the three and nine-months periods reflects higher property tax rates and assessments ($604,000 and $722,000) offset by a reduction in payroll taxes ($16,000 and $478,000). The increase in property taxes was also due to an adjustment to the 1993 property tax accrual (approximately $300,000) associated with revisions made to the nuclear station property tax assessed by the state of New Hampshire to the joint-owners of Seabrook during the third quarter of 1993. The increase in federal and state income taxes for the current nine-month period reflects the higher level of pretax income. For the current quarter, however, federal and state income taxes declined 14.5% due to the absence of a retroactive adjustment made in the third quarter of 1993 to reflect the increase in the federal tax rate to 35% and, to a lesser extent, the level of pretax income. Other Income and Interest Charges The substantial decrease in other income in the nine-month period was primarily due to the absence of a 1993 second quarter reversal of a reserve ($3.8 million pretax) related to Canal Electric's Seabrook investment. The decision to eliminate this reserve was prompted by the inclusion in base rates of Seabrook costs at the state level for Cambridge Electric. Another factor contributing to the decrease in the three and nine-month periods was a reserve related to a settlement negotiated with an outside party for certain costs associated with Commonwealth Electric's energy conservation program. The decline for the nine-month period was offset, somewhat, by a $595,000 increase in other interest and dividends due, in part, to higher equity earnings from Cambridge Electric's investments in nuclear generating companies and a Massachusetts sales tax abatement received by the system during the first quarter. For the current nine-month period, long-term interest charges increased $1.8 million due to a higher level of long-term debt reflecting the new debt issued by Commonwealth Electric, Commonwealth Gas and Hopkinton LNG Corp. at various times in 1993. Interest on short-term borrowings declined by $1.8 million due to the significantly lower average level of borrowings resulting from the 1993 financing activity. Environmental Matters Commonwealth Gas is participating in the assessment of a number of former manufactured gas plant (MGP) sites and alleged MGP waste disposal locations to determine if and to what extent such sites have been contaminated and whether Commonwealth Gas may be responsible for remedial actions. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES The costs associated with the assessment and clean-up of these sites are recoverable in rates through the cost of gas adjustment clause pursuant to a 1990 DPU order over a seven-year amortization period without carrying costs. Commonwealth Gas has recorded an estimated $2.3 million liability that reflects its best estimate (based on current information) of the costs to be incurred in connection with the assessment and remediation activities identified to this point. Commonwealth Gas has also recorded a regulatory asset in anticipation of recovery of these costs. Commonwealth Gas is unable to predict the total cost to ultimately resolve these matters, due to significant uncertainty as to the actual site conditions and the extent of any associated remediation activities and the assignment of responsibility. However, it is expected that all such costs will continue to be recovered in rates as described above. Commonwealth Gas and certain other system subsidiaries are also involved in other known or potentially contaminated sites where the associated costs may not be recoverable in rates and have recorded an estimated liability (and a charge to operations) of $560,000 to cover the expected costs associated with assessment and remediation activities. These estimates are reviewed and adjusted periodically as further investigation and assignment of responsibility occurs. As noted above, the system is unable to predict at this time the ultimate cost to resolve these matters due to the uncertainties inherent in the site investigation and remediation process. Power Contracts Cambridge Electric and Commonwealth Electric have long-term contracts for the purchase of electricity from various sources. Generally, these contracts are for fixed periods and require that Cambridge Electric and Commonwealth Electric pay a demand charge for their capacity entitlement in each unit and an energy charge to cover the cost of fuel. Cambridge Electric and Commonwealth Electric collect a portion of their capacity- related purchased power costs associated with certain long-term power arrangements through their base rates. The recovery mechanism for these costs uses a per KWH factor which is calculated using historical (test- period) capacity costs and unit sales. This factor is then applied to current monthly KWH sales. When current period capacity costs and/or unit sales vary from test-period levels, Cambridge and Commonwealth Electric experience a revenue excess or shortfall. All other capacity and energy- related purchased power costs are recovered through their respective Fuel Charge. Power Contract Negotiations On May 2, 1994, Commonwealth Electric and Cambridge Electric gave notice of termination of power purchase agreements with Eastern Energy Corp. (Eastern), the developer of a proposed 300 MW coal-fired plant in New Bedford, Massachusetts. In June 1989, in order to meet rising energy requirements, Commonwealth Electric and Cambridge Electric agreed to buy 27% (50 MW and 33 MW, respectively) of the power to be produced by the proposed plant, originally scheduled to begin operation in January 1992. That date and later revised scheduled operating dates have not been COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES achieved, and the proposed plant has still not received the necessary permits. Efforts to reshape the Eastern power purchase agreements to provide a satisfactory arrangement were unsuccessful. The companies' actions are based on Eastern's failure to meet its contractual obligations. In a letter dated June 30, 1994, Eastern objected to the notice of termination and provided to Commonwealth Electric and Cambridge Electric written notice of arbitration and its designation of an arbitrator pursuant to the 1989 agreements. The companies responded by designating their arbitrator, and the parties are now in the process of selecting a third, neutral arbitrator through the Boston, Massachusetts office of the American Arbitration Association. An arbitrator decision on the legality of the companies' termination action is expected in 1995. Commonwealth Electric has filed for regulatory approval of restructured power sale agreements with two other non-utility generators that will allow Commonwealth Electric to eliminate or reduce purchased power from the units. Also, Commonwealth Electric has reached an agreement in principle on an innovative power contract with another New England utility that is expected to produce long-term customer savings beginning in 1995. This agreement will allow Commonwealth Electric to purchase peaking unit capacity during the periods when it might otherwise have incurred deficiency charges from the New England Power Pool, or have been required to purchase capacity from other regional utilities at much higher prices. This contract provides for cost-effective resources to cover power needs in a changing environment. COMMONWEALTH ENERGY SYSTEM AND SUBSIDIARY COMPANIES PART II - OTHER INFORMATION Item 1. Legal Proceedings The system is not a party to any pending material legal proceeding. Item 2. Changes in the Rights of the Company's Security Holders None Item 3. Defaults by the Company on its Senior Securities None Item 4. Results of Votes of Security Holders None Item 5. Other Information Peter H. Cressy has been elected to the System's Board of Trustees effective September 22, 1994. Dr. Cressy is currently the Chancellor of the University of Massachusetts, Dartmouth. He was formerly President of the Massachusetts Maritime Academy and a Rear Admiral in the United States Navy. Dr. Cressy is a 1963 graduate of Yale University, holds master's degrees from George Washington University and the Naval War College, an MBA from the University of Rhode Island, and a doctorate from the University of San Francisco. He fills the vacant position created by the retirement of Robert E. Siegfried, earlier this year. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Filed herewith: Exhibit 10 Material Contracts. 10.3 Other Agreements. 10.3.3.10 Twenty-Eighth Agreement Amending New England Power Pool Agreement dated September 1, 1971, as amended September 15, 1992 (Filed herewith as Exhibit 1). 10.3.3.11 Twenty-Ninth Agreement Amending New England Power Pool Agreement dated September 1, 1971, as amended May 1, 1993 (Filed herewith as Exhibit 2). Exhibit 27 Financial Data Schedule for the nine months ended September 30, 1994 (Filed herewith as Exhibit 3). (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended September 30, 1994. COMMONWEALTH ENERGY SYSTEM SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. COMMONWEALTH ENERGY SYSTEM (Registrant) Principal Financial Officer: JAMES D. RAPPOLI James D. Rappoli, Financial Vice President and Treasurer Principal Accounting Officer: JOHN A. WHALEN John A. Whalen, Comptroller Date: November 14, 1994 EX-10 2 10.3.3.10 NEPOOL 28TH AMENDMENT EXHIBIT 1 TWENTY-EIGHTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS AGREEMENT, dated as of the 15th day of September, 1992 is entered into by the signatories hereto for the amendment by them of the New England Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"), as previously amended or proposed to be amended by twenty-seven (27) amendments, the most recent of which was dated as of October 1, 1990. WHEREAS, in response to the factors specified in Section 5.10 of the NEPOOL Agreement regarding election of members of the Management Committee to serve as an Executive Committee, the member of the Management Committee representing Public Service Company of New Hampshire has been elected to serve as a member of the Executive Committee since the formation of NEPOOL; and WHEREAS, Northeast Utilities has recently acquired Public Service Company of New Hampshire, Public Service Company of New Hampshire has elected to be treated as a single Participant with the other Entities controlled by Northeast Utilities, and Public Service Company of New Hampshire is no longer entitled to be separately represented by a member of the Management Committee; and WHEREAS, the signatory Participants have determined to amend the NEPOOL Agreement in the manner specified below in order to reflect the fact that the considerations specified in Section 5.10 for membership on the Executive Committee can now be satisfied by election of only ten members. NOW THEREFORE, the signatories hereby agree as follows: SECTION I TEXT OF AMENDMENT Section 5.10 of the NEPOOL Agreement is amended to read as follows: Election of Executive Committee Members Unless there are less than eleven members of the Management Committee, the Management Committee, at each annual meeting, shall elect ten of its members to serve as an Executive Committee. In electing the Executive Committee, the Management Committee shall give such consideration as it shall deem advisable to qualifications for the office, geographic distribution, the relative sizes of Participants and the public and private sectors of the electric utility industry. Each member so selected may designate an alternate who is acceptable to the Management Committee. SECTION II EFFECTIVENESS OF AGREEMENT Following its execution by the requisite number of Participants, this Agreement, and the amendment provided for above, shall become effective on December 1, 1992, or on such later date as the Federal Energy Regulatory Commission shall provide that such amendment shall become effective. SECTION III USAGE OF DEFINED TERMS The usage in this Agreement of terms which are defined in the NEPOOL Agreement shall be deemed to be in accordance with the definitions thereof in the NEPOOL Agreement. SECTION IV COUNTERPARTS This Agreement may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereof, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. IN WITNESS WHEREOF, each of the signatories has caused a counterpart signature page to be executed by its duly authorized representative, as of the 15th day of September, 1992. CONFORMED COPY COUNTERPART SIGNATURE PAGE TO TWENTY-EIGHTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 15, 1992 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-seven (27) amendments, the most recent prior amendment being an amendment dated as of October 1, 1990. Ashburnham Municipal Light Department Bangor Hydro-Electric Company By: /s/ Robert W. Gould By: /s/ Robert S. Briggs Manager President & CEO 86 Central Street 33 State Street Ashburnham, MA 01430 Bangor, Maine 04402-0932 Belmont Municipal Light Department Boston Edison Company By: /s/ Timothy L. McCarthy By: /s/ Cameron H. Daley Acting Manager Senior Vice President 450 Concord Avenue 800 Boylston Street Belmont, MA 02178 Boston, MA 02199 Boylston Municipal Light Department Central Maine Power Company By: /s/ H. Bradford White, Jr. By: /s/ Donald F. Kelly Manager Senior Vice President P.O. Box 560 Edison Drive Boylston, MA 01505 Augusta, Maine 04336 City of Chicopee Municipal Lighting Plant Commonwealth Energy System Cos. Commonwealth Electric Company Cambridge Electric Light Co. Canal Electric Company By: /s/ Barry W. Soden By: /s/ Harold N. Scherer, Jr. General Manager President and CEO 725 Front Street 2421 Cranberry Highway Chicopee, MA 01021-0405 Wareham, MA 02571 Concord Municipal Light Plant CT Municipal Elec. Energy Co-op By: /s/ Daniel J. Sack By: /s/ Maurice R. Scully Superintendent Executive Director 135 Keyes Road 30 Stott Avenue Concord, MA 01742 Norwich, CT 06360-1526 Eastern Utilities Groton Electric Light Department By: /s/ Donald G. Pardus By: /s/ Roger H. Beeltje Chairman/CEO Manager One Liberty Square P.O. Box 679 Boston, MA 02109 Groton, MA 01450 Hingham Municipal Lighting Plant Holden Municipal Light Department By: /s/ Joseph R. Spadea, Jr. By: /s/ Edla Ann Bloom General Manager Director of Electric Services 19 Elm Street 94 Reservoir Street Hingham, MA 02043 Holden, MA 01520 Holyoke Gas & Electric Department Ipswich Municipal Light Dept. By: /s/ George E. Leary By: /s/ Donald R. Stone Manager Director of Utilities 70 Suffolk Street P.O. Box 151 Holyoke, MA 01040 Ipswich, MA 01938 Mansfield Municipal Electric Department Marblehead Municipal Light Dept. By: /s/ John Larch By: /s/ Richard L. Bailey Manager General Manager 50 West Street 80 Commercial Street Mansfield, MA 02048 Marblehead, MA 01945 Merrimac Municipal Light Department Middleton Municipal Elec. Dept. By: /s/ David Vance By: /s/ William E. Kelley Commissioner Manager 2 School Street 197 North Main Street Merrimac, MA 01860 Middleton, MA 01949 The Narragansett Electric Company New England Power Company By: /s/ Robert L. McCabe By: /s/ Jeffrey D. Tranen President Vice President 280 Melrose Street 25 Research Drive Providence, Rhode Island Westborough, MA 01582 Massachusetts Electric Company Granite State Electric Company By: /s/ John H. Dickson By: /s/ Lydia M. Pastuszek President President 25 Research Drive 33 West Lebanon Road Westborough, MA 01582 Lebanon, New Hampshire The Connecticut Light and Power Company Western Massachusetts Elec. Co. By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox President President P.O. Box 270 P.O. Box 270 Hartford, CT 06141-0270 Hartford, CT 06141-0270 Holyoke Water Power Company Holyoke Power and Electric Co. By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox President President P.O. Box 270 P.O. Box 270 Hartford, CT 06141-0270 Hartford, CT 06141-0270 Public Service Company of New Hampshire Pascoag Fire Dist.-Electric Dept. By: /s/ Bernard M. Fox By: /s/ James E. Daniels President Chairman, Operating Committee P.O. Box 270 55 South Main Street Hartford, CT 06141-0270 Pascoag, RI 02859 Princeton Municipal Light Department Rowley Municipal Lighting Plant By: /s/ Sharon A. Staz By: /s/ G. Robert Merry Manager Manager P.O. Box 247 47 Summer Street Princeton, MA 01541-0247 Rowley, MA 01969 Taunton Municipal Lighting Plant The United Illuminating Company By: /s/ Joseph M. Blain By: /s/ Richard J. Grossi General Manager Chairman and CEO 55 Weir Street 157 Church Street Taunton, MA 02780 New Haven, CT 06506-0901 Vermont Electric Power Company, Inc. Central Vermont Public Svc. Corp. By: /s/ Richard W. Mallary By: /s/ Robert de R. Stein President Vice President P.O. Box 548 77 Grove Street Rutland, Vermont 05702-0548 Rutland, VT 05701 Citizens Utilities Company City of Burlington Electric Dept. By: /s/ James P. Avery By: /s/ Dale L. Pohlman Vice President General Manager High Ridge Park 585 Pine Street Stamford, CT 06905 Burlington, VT 05401 Franklin Electric Light Co. Green Mountain Power Corporation By: /s/ Hugh H. Gates By: /s/ John V. Cleary President President & CEO P.O. Box 96 P.O. Box 850 Franklin, VT 05457-0096 S. Burlington, Vermont 05402 Rochester Electric Light & Power Company Vermont Marble Company By: /s/ Thomas Pierce By: /s/ John M. Mitchell President President P.O. Box 6 61 Main Street Rochester, Vermont 05767 Proctor, Vermont 05765 Vermont Public Power Supply Authority Village of Hardwick Elec. Dept. By: /s/ William J. Gallagher By: /s/ Jack E. Young General Manager General Manager 512 St. George Road Box 516 Williston, VT 05495 Hardwick, Vermont 05843 Village of Ludlow Village of Morrisville Electric Light Department Water and Light Department By: /s/ Donald Ellison By: /s/ James C. Fox Commissioner, Chairman Superintendent P.O. Box 289 18 Portland Street Ludlow, Vermont 05149 Morrisville, VT 05661 Village of Northfield Village of Orleans Electric Department Electric Department By: /s/ Kevin O'Donnell By: /s/ Slayton R. Marsh Municipal Manager Superintendent 26 South Main Street Memorial Square Northfield, Vermont 05663 Orleans, VT 05860 Village of Readsboro Wakefield Municipal Light Dept. Electric Light Department By: /s/ Annette Caruso By: /s/ William J. Wallace Utility Clerk Manager P.O. Box 247 11 Albion Street Readsboro, Vermont 05350 Wakefield, MA 01880 EX-10 3 10.3.3.11 NEPOOL 29TH AMENDMENT EXHIBIT 2 TWENTY-NINTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS AGREEMENT, dated as of the 1st day of May, 1993 is entered into by the signatories hereto for the amendment by them of the New England Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"), as previously amended by twenty-eight (28) amendments, the most recent of which was dated as of September 15, 1992. WHEREAS, Participant generation resources, other than hydroelectric units, whose annual hours of operation are restricted by regulatory requirements, contract terms or engineering or operating constraints, may require treatment different from that otherwise provided in the NEPOOL Agreement for Capability Responsibility and energy billing purposes; and WHEREAS, the signatory Participants have determined to amend the NEPOOL Agreement in the manner specified below in order to provide for a modified Capability Responsibility and energy billing treatment for restricted generation resources. NOW THEREFORE, the signatories hereby agree as follows: SECTION I TEXT OF AMENDMENTS A. Amendment of Section 9.2(b)(2) Section 9.2(b)(2) of the NEPOOL Agreement is amended by inserting the following additional provisions immediately following the present final paragraph of Section 9.2(b)(2): The New Unit Adjustment Factor for any Restricted Unit for which proposed plans were submitted subsequent to November 1, 1990 for review pursuant to Section 10.4 (or, in the case of a unit with a rated capacity of less than 5MW, for which notification was first given to NEPOOL subsequent to November 1, 1990) and for the Peabody Municipal Light Plant's Waters River #2 unit shall be determined in accordance with the formula previously specified in this Section 9.2(b)(2), modified as follows: n = K1(c-C)+K2(f-F)+K3(m-M)+K4(d-D)+K5(f-F)c2+K6(2500-a) The symbols used in the above formula, as modified, shall have the meanings previously specified, except that the symbols "K6" and "a" shall have the following meanings: K6 is a scaling factor of 0.0001. a is as follows: for units with more than 2500 annual hours available for operation, "a" = 2500, for units with annual hours available for operation between 500 and 2500, inclusive, "a" = annual hours available for operation, and for units with annual hours available for operation less than 500 hours, "a" = -7500; provided, however, that a Participant may elect to avoid, in whole or part, the effect on its Capability Responsibility of a Restricted Unit's availability being limited to 2500 hours or less a year by agreeing to leave unfilled a portion of its dispatchable load allocation in accordance with rules to be adopted by the Operations Committee. B. Amendment of Section 12.6 The first two sentences of Section 12.6 of the NEPOOL Agreement are amended to read as follows: If pursuant to Section 12.5A, a Participant is deemed to have received energy service in any hour when the Participant (i) had Entitlements in one or more generating units which were available for service but were not scheduled for operation by NEPEX at their full available Reserve Capability (or, to the extent applicable, at their full available Temporary Reserve Capability) and which, in the case of any Restricted Unit, had an unused portion of an available Restricted Unit Operational Allowance and/or (ii) had Scheduled Outage Service Entitlements, the Participant shall be deemed to have received Economy Flow Service and/or Scheduled Outage Service in an amount equal to the lesser of: (a) the amount of energy service the Participant is deemed to have received pursuant to Section 12.5A, or (b) the amount of energy service which could have been provided from its share of (1) the unused portion of the available Reserve or Temporary Reserve Capabilities of the units described in (i) above, as limited in the case of any Restricted Unit by the unused portion of its available Restricted Unit Operational Allowance, plus (2) its Scheduled Outage Service Entitlements. Economy Flow Service is service which a Participant is deemed to receive at any time to replace service which it could have provided at the time from units described in (i) above, and the amount of Economy Flow Service which it is deemed to receive at the time shall not exceed the amount of energy service which could have been provided from its share of the unused portions of the available Reserve Capabilities (or, to the extent applicable, the unused portion of the available Temporary Reserve Capabilities or the unused portion of the available Restricted Unit Operational Allowances, whichever is controlling) of such units. C. Addition of Definitions of "Restricted Unit" and "Restricted Unit Operational Allowance". The NEPOOL Agreement is amended by adding the following definitions following the definition of "Reserve Savings Shares" in Section 15.37A: 15.37B. Restricted Unit is a generating unit, other than a hydroelectric unit, that is restricted in annual hours available for operation by regulatory requirements, contract terms or actual engineering or operating constraints. Planned or forced outages due to maintenance requirements are not considered restrictions in annual hours available for operation. 15.37C. Restricted Unit Operational Allowance ("Allowance") for a Participant's Entitlement in a Restricted Unit for any calendar year (or for the term of the Entitlement in any year, if such term is for a shorter period than the year) is the number of hours for which the Restricted Unit is available for operation during the year or such shorter period, whichever is applicable. The Allowance for a Participant's Entitlement in a Restricted Unit for any year or shorter period shall be deemed to be exhausted when (i) the number of hours that the Operations Committee determines the Participant would have used its Restricted Unit Entitlement to minimize the Participant's overall energy costs in the absence of NEPEX dispatch, plus (ii) the number of hours that the Participant is deemed to receive Scheduled Outage Service with respect to its Entitlement in the Restricted Unit during the year or such shorter period pursuant to Section 12.6, equals the Allowance. D. Modification of Definition of "Scheduled Outage Service Entitlement". The definition of "Scheduled Outage Service Entitlement" in Section 15.38B of the NEPOOL Agreement is amended to read as follows: 15.38B Scheduled Outage Service Entitlement of a Participant is the amount of Scheduled Outage Service which the Participant is entitled to receive in any hour with respect to a generating unit which is scheduled by the Operations Committee to be out of service, in whole or in part, for maintenance during a period approved for it by the Operations Committee for Scheduled Outage Service and is in fact out of service, in whole or in part, for any reason during the approved period. Such amount is equal to the lesser of (i) the portion of the Participant's share of the Reserve Capability of such unit which is unavailable for service times an estimated average availability of such unit between its periodic scheduled outages or (ii) in the case of any generating unit with a currently applicable Temporary Reserve Capability, the portion of the Participant's share of the Temporary Reserve Capability which is unavailable for service; provided, however, that (a) in the case of any Limited Fuel Unit, the amount of a Participant's Scheduled Outage Service Entitlement shall be reduced, if appropriate, to take account of any limit on the availability of stream flow or fuel to operate the unit during the outage period, and (b) in the case of any Restricted Unit, the Participant's Scheduled Outage Service Entitlement shall be limited to the unused portion, if any, of its currently available Restricted Unit Operational Allowance for the unit. The Operations Committee shall develop rules for establishing the estimated average availability of each unit between scheduled outages. Such rules shall become effective upon approval by the Management Committee. SECTION II EFFECTIVENESS OF AGREEMENT Following its execution by the requisite number of Participants, this Agreement, and the amendments provided for above, shall become effective on August 1, 1993, or on such later date as the Federal Energy Regulatory Commission shall provide that such amendment shall become effective. SECTION III USAGE OF DEFINED TERMS The usage in this Agreement of terms which are defined in the NEPOOL Agreement shall be deemed to be in accordance with the definitions thereof in the NEPOOL Agreement. SECTION IV COUNTERPARTS This Agreement may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereof, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. IN WITNESS WHEREOF, each of the signatories has caused a counterpart signature page to be executed by its duly authorized representative, as of the 1st day of May, 1993. CONFORMED COPY COUNTERPART SIGNATURE PAGE TO TWENTY-NINTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF MAY 1, 1993 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-eight (28) amendments, the most recent prior amendment being an amendment dated as of September 15, 1992. Ashburnham Municipal Light Department Bangor Hydro-Electric Company By: /s/ Robert W. Gould By: /s/ Carroll R. Lee Manager Vice President, Operations 86 Central Street 33 State Street Ashburnham, MA 01430 Bangor, ME 04402-0932 Braintree Electric Light Department Boston Edison Company By: /s/ Walter R. McGrath By: /s/ B.W. Reznicek General Manager Chairman, President & CEO 44 Allen Street 800 Boylston Street Braintree, MA 02184 Boston, MA 02199 Boylston Municipal Light Department Central Maine Power Company By: /s/ H. Bradford White, Jr. By: /s/ Donald F. Kelly Manager Senior Vice President Tivnan Rd, P.O. Box 560 Edison Drive Boylston, MA 01505 Augusta, ME 04336 Fitchburg Gas and Electric Light Co. Commonwealth Electric Company By: /s/ David K. Foot By: /s/ James J. Keane Senior Vice President Vice President-Power Supply 216 Epping Road and Transmission Exeter, NH 03833 2421 Cranberry Highway Wareham, MA 02571 Concord Municipal Light Plant CT Municipal Elec. Energy Co-op By: /s/ Daniel J. Sack By: /s/ Maurice R. Scully Superintendent Executive Director 135 Keyes Road 30 Stott Avenue Concord, MA 01742 Norwich, CT 06360-1526 Eastern Utilities Groton Electric Light Department By: /s/ Donald G. Pardus By: /s/ Roger H. Beeltje Chairman/CEO Manager P.O. Box 2333 P.O. Box 679 Boston, MA 02107 Groton, MA 01450 Hingham Municipal Lighting Plant Holden Municipal Light Department By: /s/ Joseph R. Spadea, Jr. By: /s/ Edla Ann Bloom General Manager Director of Electric Services 19 Elm Street 94 Reservoir Street Hingham, MA 02043 Holden, MA 01520 Holyoke Gas & Electric Department Georgetown Municipal Light Dept. By: /s/ George E. Leary By: /s/ Edward Stanley Manager Manager 70 Suffolk Street Moulton and West Main Streets Holyoke, MA 01040 Georgetown, MA 01938 Littleton Electric Light and Water Dept. Marblehead Municipal Light Dept. By: /s/ Curtis J. Lanciani By: /s/ Richard L. Bailey General Manager General Manager 39 Ayer Road 80 Commercial Street, Box 369 Littleton, MA 01460 Marblehead, MA 01945 Middleborough Gas & Electric Department Middleton Municipal Elec. Dept. By: /s/ John W. Dunfey By: /s/ William E. Kelley General Manager Interim Manager 32 South Main Street 197 North Main Street Middleborough, MA 02346 Middleton, MA 01949 Paxton Light Department New England Electric System By: /s/ Harold L. Smith By: /s/ Jeffrey D. Tranen Manager Vice President 578 Pleasant Street 25 Research Drive Paxton, MA 01612 Westborough, MA 01582 Shrewsbury's Electric Light Plant Town of S. Hadley Electric Light Department By: /s/ Thomas R. Josie By: /s/ Wayne D. Doerpholz General Manager Manager 100 Maple Ave. 85 Main Street Shrewsbury, MA 01545 South Hadley, MA 01075 The Connecticut Light and Power Company Western Massachusetts Elec. Co. By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox President and CEO President and CEO P.O. Box 270 P.O. Box 270 Hartford, CT 06141-0270 Hartford, CT 06141-0270 Holyoke Water Power Company Holyoke Power and Electric Co. By: /s/ Bernard M. Fox By: /s/ Bernard M. Fox President and CEO President and CEO P.O. Box 270 P.O. Box 270 Hartford, CT 06141-0270 Hartford, CT 06141-0270 Public Service Company of New Hampshire Pascoag Fire Dist.-Electric Dept. By: /s/ W.T. Frain, Jr. By: /s/ Thomas J. Beauregard Senior Vice President Chairman 1000 Elm Street P.O. Box 107 Manchester NH 03105 Pascoag, RI 02859 Princeton Municipal Light Department Rowley Municipal Lighting Plant By: /s/ Sharon A. Staz By: /s/ G. Robert Merry General Manager Manager P.O. Box 247 47 Summer Street Princeton, MA 01541-0247 Rowley, MA 01969 Taunton Municipal Lighting Plant The United Illuminating Company By: /s/ Joseph M. Blain By: /s/ Richard J. Grossi General Manager Chairman and CEO P.O. Box 870 157 Church Street Taunton, MA 02780 New Haven, CT 06506-0901 Vermont Electric Power Company, Inc. Central Vermont Public Svc. Corp. By: /s/ Richard W. Mallary By: /s/ Robert de R. Stein President Vice President P.O. Box 548 77 Grove Street Rutland, Vermont 05702-0548 Rutland, VT 05701 Templeton Municipal Light Plant UNITIL Power Corporation By: /s/ Gerald Skelton By: /s/ David K. Foote Manager/Engineer Senior Vice President 2 School Street 216 Epping Road Baldwinville, MA 01436 Exeter, NH 03833 Franklin Electric Light Co. Green Mountain Power Corporation By: /s/ Hugh H. Gates By: /s/ John V. Cleary President President & CEO P.O. Box 96 P.O. Box 850 Franklin, VT 05457-0096 S. Burlington, Vermont 05402 Village of Jacksonville Vermont Marble Power Div. of OMYA, Inc. By: /s/ Earle S. Holland By: /s/ John M. Mitchell President Board of Trustees Executive Vice President P.O. Box 73 61 Main Street Jacksonville, Vermont 05342 Proctor, Vermont 05765 Village of Ludlow Village of Morrisville Electric Light Department Water and Light Department By: /s/ Donald Ellison By: /s/ James C. Fox Commissioner, Chairman Superintendent P.O. Box 289 P. O. Box 325 Ludlow, Vermont 05149 Morrisville, VT 05661 Village of Northfield Readsboro Electric Electric Department By: /s/ Kevin O'Donnell By: /s/ Annette Caruso Municipal Manager Clerk 26 South Main Street P.O. Box 247 Northfield, Vermont 05663 Readsboro, VT 05350 Westfield Gas and Electric Wakefield Municipal Light Dept. Light Department By: /s/ Daniel Golubek By: /s/ William J. Wallace General Manager General Manager 100 Elm Street 9 Albion Street Westfield, MA 01085 Wakefield, MA 01880 EX-27 4 FINANCIAL DATA SCHEDULE - SEPTEMBER 30, 1994
UT This schedule contains summary financial information extracted from the balance sheet, statement of income and statement of cash flows contained in Form 10-Q of Commonwealth Energy System for the nine months ended September 30, 1994 and is qualified in its entirety by reference to such financial statements. 0000071304 COMMONWEALTH ENERGY SYSTEM 1,000 9-MOS DEC-31-1994 SEP-30-1994 PER-BOOK 983,339 13,900 149,549 126,105 15,594 1,288,487 41,842 100,980 214,865 357,687 14,660 0 437,137 13,925 0 0 25,973 820 14,026 1,568 422,691 1,288,487 749,837 23,022 656,840 679,862 69,975 49 70,024 32,097 37,927 888 37,039 23,407 29,644 107,406 3.57 3.57
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