0000071304-95-000019.txt : 19950815 0000071304-95-000019.hdr.sgml : 19950815 ACCESSION NUMBER: 0000071304-95-000019 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19950630 FILED AS OF DATE: 19950814 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: COMMONWEALTH ELECTRIC CO CENTRAL INDEX KEY: 0000071222 STANDARD INDUSTRIAL CLASSIFICATION: UNKNOWN SIC - 0000 [0000] IRS NUMBER: 041659070 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 002-07749 FILM NUMBER: 95563012 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-Q 1 COMMONWEALTH ELECTRIC COMPANY - 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 the quarterly period ended June 30, 1995 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________________ to ________________ Commission File Number 2-7749 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) (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 August 1, 1995 Common Stock, $25 par value 2,043,972 shares The Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q as a wholly-owned subsidiary and is therefore filing this Form with the reduced disclosure format. PART I - FINANCIAL INFORMATION Item 1. Financial Statements COMMONWEALTH ELECTRIC COMPANY CONDENSED BALANCE SHEETS JUNE 30, 1995 AND DECEMBER 31, 1994 ASSETS (Unaudited) June 30, December 31, 1995 1994 (Dollars in Thousands) PROPERTY, PLANT AND EQUIPMENT, at original cost $505 495 $496 166 Less - Accumulated depreciation 150 732 143 877 354 763 352 289 Add - Construction work in progress 8 270 5 216 363 033 357 505 INVESTMENTS Equity in nuclear electric power company 616 654 Other 14 14 630 668 CURRENT ASSETS Cash 967 1 637 Accounts receivable - Affiliates 3 304 3 713 Customers 37 441 37 862 Unbilled revenues 5 528 8 899 Prepaid property taxes - 2 739 Inventories and other 6 071 6 032 53 311 60 882 DEFERRED CHARGES 90 006 57 831 $506 980 $476 886 COMMONWEALTH ELECTRIC COMPANY CONDENSED BALANCE SHEETS JUNE 30, 1995 AND DECEMBER 31, 1994 CAPITALIZATION AND LIABILITIES (Unaudited) June 30, December 31, 1995 1994 (Dollars in Thousands) CAPITALIZATION Common Equity - Common stock, $25 par value - Authorized and outstanding - 2,043,972 shares wholly-owned by Commonwealth Energy System (Parent) $ 51 099 $ 51 099 Amounts paid in excess of par value 97 112 97 112 Retained earnings 14 773 15 350 162 984 163 561 Long-term debt, less current sinking fund requirements 156 770 157 817 319 754 321 378 CURRENT LIABILITIES Interim Financing - Notes payable to banks 7 900 6 400 Advances from affiliates 30 010 200 37 910 6 600 Other Current Liabilities - Current sinking fund requirements 1 053 1 053 Accounts payable - Affiliates 6 849 7 716 Other 27 804 31 911 Accrued taxes - Local property and other 304 3 721 Income 13 233 8 049 Other 12 481 13 691 61 724 66 141 99 634 72 741 DEFERRED CREDITS Accumulated deferred income taxes 43 101 42 074 Unamortized investment tax credits 7 778 7 994 Other 36 713 32 699 87 592 82 767 COMMITMENTS AND CONTINGENCIES $506 980 $476 886 See accompanying notes. COMMONWEALTH ELECTRIC COMPANY CONDENSED STATEMENTS OF INCOME AND RETAINED EARNINGS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 1995 AND 1994 (Unaudited) Three Months Ended Six Months Ended 1995 1994 1995 1994 (Dollars in Thousands) ELECTRIC OPERATING REVENUES $ 97 226 $ 98 244 $210 434 $216 734 OPERATING EXPENSES Electricity purchased for resale, transmission and fuel 62 969 64 267 140 932 145 042 Other operation and maintenance 20 372 21 795 39 997 41 795 Depreciation 4 103 3 984 8 205 7 998 Taxes - Income 1 701 1 011 4 365 4 021 Local property 1 382 1 240 2 764 2 524 Payroll and other 630 636 1 640 1 628 91 157 92 933 197 903 203 008 OPERATING INCOME 6 069 5 311 12 531 13 726 OTHER INCOME 1 122 208 2 782 295 INCOME BEFORE INTEREST CHARGES 7 191 5 519 15 313 14 021 INTEREST CHARGES Long-term debt 3 520 3 544 7 041 7 090 Other interest charges 943 115 1 318 225 Allowance for borrowed funds used during construction (123) (88) (236) (153) 4 340 3 571 8 123 7 162 NET INCOME 2 851 1 948 7 190 6 859 RETAINED EARNINGS - Beginning of period 16 214 16 759 15 350 15 118 Dividends on common stock (4 292) (3 884) (7 767) (7 154) End of period $ 14 773 $ 14 823 $ 14 773 $ 14 823 See accompanying notes. COMMONWEALTH ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 1995 AND 1994 (Unaudited) 1995 1994 (Dollars in Thousands) OPERATING ACTIVITIES Net income $ 7 190 $ 6 859 Effects of noncash items - Depreciation and amortization 9 597 9 481 Deferred income taxes and investment tax credits, net 3 221 (350) Change in working capital, exclusive of cash, advances to affiliates and interim financing 2 484 18 384 Buy-out of power contract (25 500) - Fuel charge stabilization deferral (6 865) (11 087) All other operating items (599) (6 061) Net cash (used for) provided by operating activities (10 472) 17 226 INVESTING ACTIVITIES Additions to property, plant and equipment (exclusive of AFUDC) (12 458) (9 387) Allowance for borrowed funds used during construction (236) (153) Payment from affiliates - (810) Net cash used for investing activities (12 694) (10 350) FINANCING ACTIVITIES Proceeds from short-term borrowings 1 500 - Proceeds from affiliates 29 810 - Payment of dividends (7 767) (7 154) Sinking funds payments (1 047) (1 047) Net cash provided by (used for) financing activities 22 496 (8 201) Net decrease in cash (670) (1 325) Cash at beginning of period 1 637 2 794 Cash at end of period $ 967 $ 1 469 SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid (received) during the period for: Interest (net of capitalized amounts) $ 7 792 $ 6 942 Income taxes $ (1 287) $ (821) See accompanying notes. COMMONWEALTH ELECTRIC COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS (1) Accounting Policies Commonwealth Electric Company (the Company) is a wholly-owned subsid- iary 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's significant accounting policies are described in Note 1 of Notes to Financial Statements included in its 1994 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For interim reporting purposes, the Company 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. The Company has 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 regula- tory liabilities established by the Company are required to be refunded to its customers over time. In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to be Disposed Of" (SFAS 121). SFAS 121 imposes stricter criteria for regulatory assets by requiring that such assets be probable of future recovery at each balance sheet date. Based on the current regulatory framework, the Company accounts for the economic effects of regulation in accordance with the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" and does not expect that the adoption of SFAS 121, which the Company expects to adopt on January 1, 1996, will have a material impact on its financial position or results of operations. However, this conclusion may change in the future if changes are made in the current regulatory framework or as competitive factors influence wholesale and retail pricing in this industry. The principal regulatory assets included in deferred charges were as follows: June 30, December 31, 1995 1994 (Dollars in Thousands) Purchased power contract buy-out $25 539 $ - Fuel charge stabilization 23 503 16 638 Postretirement benefit costs including pensions 12 529 11 215 Yankee Atomic unrecovered plant and decommissioning costs 8 982 10 204 Pilgrim nuclear plant litigation costs 6 822 7 001 Cannon Street generating plant abandonment, net 4 400 4 400 Conservation and load management costs 3 307 3 659 Other 893 1 049 Total regulatory assets $85 975 $54 166 COMMONWEALTH ELECTRIC COMPANY The regulatory liabilities included in deferred credits - other, principally related to taxes, amounted to $11.7 million and $3.7 million at June 30, 1995 and December 31, 1994, respectively. Income tax expense is recorded using the statutory rates in effect applied to book income subject to tax recorded in the interim period. The unaudited financial statements for the periods ended June 30, 1995 and 1994 reflect, in the opinion of the Company, all adjustments (consist- ing of only normal recurring accruals) necessary to summarize fairly the results for such periods. In addition, certain prior period amounts are reclassified from time to time to conform 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 con- sumption of energy. (2) Commitments and Contingencies (a) Construction and Financing Programs The Company is engaged in a continuous construction program presently estimated at $141 million for the five-year period 1995 through 1999. Of that amount, $27.1 million is estimated for 1995. As of June 30, 1995, the Company's construction expenditures amounted to approximately $12.7 million, including an allowance for funds used during construction. 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. The program is subject to periodic review and revision due to 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 environ- mental regulations. (b) Decommissioning of Yankee Atomic Nuclear Power Plant In February 1992, the Board of Directors of Yankee Atomic Electric Company (Yankee Atomic) agreed to permanently discontinue power operation of its plant and decommission the Yankee Nuclear Power Station (the plant). The Company's 2.5% investment in Yankee Atomic is approximately $616,000. The most recent cost estimate to permanently shut down the plant is approximately $396 million. The Company's share of this liabili- ty is $9 million and is currently reflected in the accompanying balance sheets as a liability and corresponding regulatory asset. COMMONWEALTH ELECTRIC COMPANY Item 2. 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 condensed statements of income. 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 six months ended June 30, 1995 and 1994 and unit sales for these periods is shown below: Three Months Ended Six Months Ended June 30, June 30, 1995 and 1994 1995 and 1994 Increase (Decrease) (Dollars in Thousands) Electric Operating Revenues $ (1 018) (1.0)% $ (6 300) (2.9)% Operating Expenses - Electricity purchased for resale, transmission and fuel (1 298) (2.0) (4 110) (2.8) Other operation and maintenance (1 423) (6.5) (1 798) (4.3) Depreciation 119 3.0 207 2.6 Taxes - Federal and state income 690 68.2 344 8.6 Local property and other 136 7.2 252 6.1 (1 776) (1.9) (5 105) (2.5) Operating Income 758 14.3 (1 195) (8.7) Other Income 914 439.4 2 487 843.1 Income Before Interest Charges 1 672 30.3 1 292 9.2 Interest Charges 769 21.5 961 13.4 Net Income $ 903 46.4 $ 331 4.8 Unit Sales (Megawatthours or MWH) Retail 20 307 2.7 (32 049) (2.0) Wholesale (215 380) (59.7) (330 547) (44.1) Total unit sales (195 073) (17.5) (362 596) (15.3) The following is a summary of unit sales (in MWH) for the periods indicated: Three Months Six Months Period Ended Total Retail Wholesale Total Retail Wholesale June 30, 1995 920 774 775 600 145 174 2 007 624 1 589 133 418 491 June 30, 1994 1 115 847 755 293 360 554 2 370 220 1 621 182 749 038 COMMONWEALTH ELECTRIC COMPANY Operating Revenues, Electricity Purchased for Resale, Transmission and Fuel Operating revenues for the three and six-month periods ended June 30, 1995 decreased by $1 million (1%) and $6.3 million (2.9%), respectively, from the corresponding periods in 1994 due primarily to declines in wholesale unit sales. However, fluctuations in the level of wholesale sales have little, if any, impact on net income. In the first half of 1995, unit sales to residen- tial customers declined 4.9% reflecting extremely mild weather in the first quarter of this year as compared to the record cold experienced during the same period of 1994. In the second quarter of 1995, total retail electric revenues increased $3.8 million as unit sales increased 2.7%, and nearly offset the $4.6 million revenue decline caused by lower wholesale sales. The current three and six-month periods reflect the absence of power purchases from Canal Electric Company's (Canal) Unit 1, the reduced purchases from Canal Unit 2 and reduced power purchases from the non-affiliated Pilgrim nuclear unit and an independent power producer (IPP) reflecting the restruc- turing of a power contract that defers purchases for a six-year period that began in early 1995. In January 1995, the Company terminated a long-term power contract with another IPP through a buy-out arrangement which will reduce future power costs. Somewhat offsetting these reduced power sources were greater power purchases from Seabrook and several other non-utility genera- tors. The Company has received approval from the Massachusetts Department of Public Utilities (DPU) to recover in revenues certain current costs associated with conservation and load management (C&LM) programs through the operation of a Conservation Charge 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 corresponding change will occur in revenues. In 1995, the collection of these revenues declined $868,000 and $1.3 million in the current quarter and six-month period when compared to the same periods last year. Historically, revenues collected through base rates have been designed to reimburse the Company for all costs of operation other than fuel, the energy portion of purchased power, transmission and C&LM costs, and provide a fair return on capital invested in the business. However, as a result of a DPU- mandated recovery mechanism implemented in July 1991 for capacity-related costs associated with certain long-term purchased power contracts, the Company has experienced a revenue excess or shortfall when unit sales and/or the costs recoverable in base rates vary from test-period levels. This issue, which has had a significant impact on net income, was addressed in a settlement agree- ment approved by the DPU in May 1995. (Refer to the "Rate Settlement Agree- ment" section for additional details.) For the current three and six-month periods, in accordance with the settlement agreement, approximately $1.1 million was deferred for future recovery. The Company's undercollection of these capacity-related costs up to the effective date of the settlement was $1.6 million and $2 million for the current three and six-month periods, respectively. As a result, net income was reduced by $322,000 and $589,000 for the current three and six-month periods, respectively, an improvement of $868,000 and $818,000 from the same periods last year. COMMONWEALTH ELECTRIC COMPANY Other Operation and Maintenance Other operation and maintenance (O&M) declined in the current quarter and six-month period of 1995 due to lower C&LM program costs ($843,000 and $1.3 million), a decline in maintenance expense of $564,000 and $315,000 (primarily transmission and distribution facilities) and continued savings resulting from other on-going cost containment measures. These decreases were offset, in part, in the current quarter and six-month period, respectively, by higher labor and benefit costs ($274,000 and $560,000), primarily reflecting the full recognition of expenses relating to postretirement benefits other than pensions and amortization of previously deferred postretirement benefits costs. (Refer to the "Rate Settlement Agreement" section for additional information.) Also, legal fees associated with power contract arbitration proceedings ($380,000) were included in both current periods. Depreciation and Taxes Depreciation expense increased slightly in the current three and six- month periods due to a higher level of depreciable property, plant and equip- ment. The increases in federal and state income taxes was due to a higher level of pretax income. Local property and other tax increases for the three and six-month periods of 1995 primarily reflect higher rates and assessments ($142,000 and $240,000, respectively). Other Income and Interest Charges Other income for the current six-month period increased by $2.5 million due primarily to the reversal of a contingency reserve related to certain costs associated with the Company's energy conservation program ($1.4 mil- lion), the recovery of which has since been approved by the DPU. Also contributing to the increase in the current three and six-month periods was a higher level of interest income related to the fuel charge stabilization deferral ($369,000 and $759,000, respectively) and, for both current periods, carrying costs associated with the April 1995 buy-out of a power contract ($684,000) with an IPP. The cost of the buy-out is being recovered from customers over a seven-year period. Total interest charges increased by $769,000 (21.5%) and $961,000 (13.4%) during the current three and six-month periods reflecting an increases of $732,000 and $966,000, respectively, in interest on short-term borrowings which were not required during the first half of 1994. Power Contract Arbitration On June 7, 1995, a three-member panel of arbitrators upheld the termina- tion by the Company of a power contract with Eastern Energy Corporation (Eastern), the developer of a proposed 300 MW coal-fired plant. In June 1989, the Company agreed to buy 16% (50 MW) of the power to be produced by the proposed plant, originally scheduled to begin operation in January 1992. However, in May 1994, the Company gave notice of termination of its power contract with Eastern based upon its failure to meet the permitting, con- struction or operation milestones established by the contract, obtain the required permits, commence construction or sell any additional power from the proposed plant. Efforts to reshape the power contract to provide a satisfac- tory arrangement were unsuccessful. In a letter dated June 30, 1994, Eastern COMMONWEALTH ELECTRIC COMPANY objected to the notice of termination and invoked arbitration seeking $31.2 million from the Company. The panel's decision is binding and prevents Eastern from further litigating or contesting the termination of the contracts in any other forum. This action is expected to save the Company's customers approximately $60 million over the next ten years and as much as $135 million over twenty years. Rate Settlement Agreement In May 1995, the DPU approved a settlement proposal sponsored jointly by the Company and the Attorney General of Massachusetts which resolved issues related to cost of service, rates, accounting matters and generating unit performance reviews. The Company's settlement: (1) implements a $2.7 million annual retail base rate decrease effective May 1, 1995 including its share of excess deferred tax reserves related to Seabrook Unit No. 1 which Canal refunded to the Company in May. Further, the settlement imposes a moratorium on retail rate filings until October 1998; (2) limits the Company's return on equity, as defined in the settlement, for the period through December 31, 1997; (3) terminates several 1987-1994 generating unit performance review proceedings pending before the DPU; (4) amends the Company's fuel charge stabilization mechanism established on April 1, 1994 to include the deferral (without carrying charges) of certain long-term purchased power and transmission capacity costs within the original limits established for the fuel charge stabiliza- tion deferral ($16 million in any given calendar year and $40 million over the life of the mechanism); (5) requires the Company to fully expense costs relating to postretire- ment benefits other than pensions in accordance with Statement of Financial Accounting Standards No. 106 and amortize the current deferred balance of $8.6 million over a ten-year period; (6) provides eligible Economic Development Rate customers with a discount of up to 30% but also requires these customers to provide the Company with a five-year notice if they intend to self-generate or acquire electricity from another provider; and (7) prohibits the Company from seeking recovery of the costs incurred in realizing costs savings through a 1993 work force reduction and restructuring, totaling approximately $3 million. The Company's management is encouraged by the support provided through the Office of the Attorney General and believes that this settlement will eliminate the need for potentially costly litigation and regulatory proceed- ings and, by moderating rate impacts and enabling the Company to remain competitive in a changing environment, is in the best interest of the Company and its customers. COMMONWEALTH ELECTRIC COMPANY PART II - OTHER INFORMATION Item 1. Legal Proceedings The Company is subject to legal claims and matters arising from its course of business, including its participation in a power contract arbitration proceeding involving the recovery of excess fuel charges billed to the Company for power purchases with Dartmouth Power Associates Limited Partnership. Also, the Company's decision to cancel a power contract with Eastern Energy Corporation was upheld by a binding arbitration panel decision in June 1995 (refer to "Power Contract Arbitration" in Part I, Item 2 - "Management's Discussion and Analysis of Results of Operations" section of this report.) Item 5. Other Information None. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit 10 - Material Contracts 10.1.35.1 System Power Sales Agreement by and between The Connecticut Light and Power Co., Western Massachusetts Electric Co., and Public Service Company of New Hampshire, as sellers, and the Company, as buyer, of power for peaking capacity and related energy, dated January 13, 1995, as effective June 1, 1995 and extending to October 31, 2000 (Filed herewith as Exhibit 2). 10.1.46.2 First Amendment, dated November 7, 1994, to Power Sale Agreement by and between the Company and Altresco Pittsfield, L.P. dated February 20, 1992 (Filed herewith as Exhibit 3). 10.1.44.1 Second Amendment, dated June 23, 1994, to Power Purchase Agreement by and between the Company and Dartmouth Power Associates, L.P. dated September 5, 1989 (Filed herewith as Exhibit 4). Exhibit 27 - Financial Data Schedule Filed herewith as Exhibit 1 is the Financial Data Schedule for the six months ended June 30, 1995. (b) Reports on Form 8-K No reports on Form 8-K were filed during the three months ended June 30, 1995. COMMONWEALTH ELECTRIC COMPANY 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 ELECTRIC COMPANY (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: August 14, 1995 EX-27 2 FINANCIAL DATA SCHEDULE - JUNE 30, 1995
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 Electric Company for the six months ended June 30, 1995 and is qualified in its entirety by reference to such financial statements. 0000071222 COMMONWEALTH ELECTRIC COMPANY 1,000 DEC-31-1995 JUN-30-1995 6-MOS PER-BOOK 363,033 630 53,311 90,006 0 506,980 51,099 97,112 14,773 162,984 0 0 156,770 37,910 0 0 1,053 0 0 0 148,263 506,980 210,434 4,365 193,538 197,903 12,531 2,782 15,313 8,123 7,190 0 7,190 7,767 7,041 (10,472) 0 0
EX-10 3 10.1.35.1 SYSTEM POWER SALES AGREEMENT SYSTEM POWER SALES AGREEMENT DATED: January 13, 1995 BETWEEN: NORTHEAST UTILITIES SERVICE COMPANY AS AGENT FOR: THE CONNECTICUT LIGHT AND POWER COMPANY WESTERN MASSACHUSETTS ELECTRIC COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND COMMONWEALTH ELECTRIC COMPANY SYSTEM POWER SALES AGREEMENT This SYSTEM POWER SALES AGREEMENT ("Agreement") dated as of January 13, 1995, by and between Northeast Utilities Service Company ("NUSCO") as agent for The Connecticut Light and Power Company ("CL&P"), Western Massachusetts Electric Company ("WMECO"), and Public Service Company of New Hampshire ("PSNH"), and Commonwealth Electric Company (hereinafter "Buyer" or "Common- wealth"). NUSCO and the Buyer are referred to herein individually as "Party" or collectively as "Parties." WHEREAS, CL&P, WMECO, and PSNH are operating companies of the Northeast Utilities ("NU") System Companies (hereinafter collectively referred to as "Seller"); and WHEREAS, Commonwealth is a regulated public utility desiring to purchase economical and reliable sources of wholesale power supply; and WHEREAS, Buyer solicited bids for peaking capacity and related energy in a request for proposals dated February 7, 1994 and Seller responded to such solicitation with a bid; and WHEREAS, pursuant to a letter of intent between the Parties dated June 15, 1994, Seller has expressed its willingness to sell and the Buyer has expressed its willingness to purchase peaking capacity and related energy pursuant to terms of this Agreement; and WHEREAS, the NU System Companies and Commonwealth are participants in the New England Power Pool ("NEPOOL") and as such are subject to the terms and conditions of the NEPOOL Agreement dated as of September 1, 1971, as amended from time to time (the "NEPOOL Agreement"); and WHEREAS, the Parties hereto desire to provide for the terms and condi- tions pursuant to which Seller will sell to Commonwealth and Commonwealth will purchase 75 megawatt-years of peaking capacity and related energy from the NU System Companies during the term of this Agreement; NOW, THEREFORE, in consideration of the premises and of the mutual agreements herein contained, the Parties to this Agreement covenant and agree as follows: 1. Term Subject to Federal Energy Regulatory Commission ("FERC" or "Commission") authorization and final approval of the Agreement by the Massachusetts Department of Public Utilities ("MDPU") pursuant to M.G.L.C. 164, SS94A (in form and substance acceptable to both parties) within 90 days of Common- wealth's filing with the MDPU for approval, the term of this Agreement and service to be rendered hereunder shall become effective at 0001 hours on June 1, 1995, and shall end at 2400 hours on October 31, 2000, unless extended by mutual agreement of the Parties (such period hereinafter called the "Term"). The applicable provisions of this Agreement shall continue in effect after termination hereof to the extent necessary to provide for final billing, billing adjustments, and payments. 2. Purchase Seller shall sell to Buyer and Buyer shall purchase from Seller a total of 75 megawatt-years of electrical system capacity during the Term of this Agreement. The total megawatt-years of electrical system capacity purchased will be the sum of the annual capacity entitlements elected by the Buyer. Such electrical system capacity shall be in the form of peaking system or unit entitlements. The amount of peaking capacity to be purchased and sold may vary at Commonwealth's discretion by month, subject to a monthly maximum purchase of 125 MW-month and the scheduling provisions set forth in Schedule II, so long as the total amount of peaking system capacity purchased over the Term is 75 megawatt-years. 3. NEPOOL Dispatch For purposes of Buyer's NEPOOL own-load dispatch, electrical energy made available hereunder will be dispatchable by Buyer each hour up to the applica- ble purchase amount and such dispatched energy shall be part of Seller's NEPOOL own-load energy requirements for the applicable hour (de-Coupled Dispatch). The energy prices given to NEPOOL by Seller for purposes of economic dispatch of energy made available hereunder in Buyer's own load dispatch shall be the same as the Energy Charge Rate as determined in accor- dance with Section 6 of this Agreement. Electrical energy will be made available to Buyer in its NEPOOL own-load dispatch subject to the availability criteria specified in Section 4 of this Agreement. Seller will notify NEPOOL of Buyer's purchase prior to the commencement of the Term. 4. Availability The peaking system energy associated with the peaking system capacity will be made available to the Buyer in its NEPOOL own-load dispatch in accor- dance with Section 3 of this Agreement, whenever any two of the four South Meadow internal combustion units are available. The four South Meadow internal combustion units each have a combined winter normal claimed capability of 46 megawatts and a summer normal claimed capability of 36 megawatts. In the event that the peaking system energy is unavailable, the Buyer will be entitled to the appropriate NEPOOL outage service made available as a result of the outages at the South Meadow units. If the NEPOOL capability credit received by the Buyer for the peaking system is reduced to zero as the result of the applicable unit outages, the Seller will substitute capacity of similar operating characteristics for the purposes of this Section 4. 5. Transmission The peaking system power purchased hereunder will be delivered to the boundary of the NU System Companies at the Card Street/Sherman Road Intercon- nection at the Connecticut-Rhode Island border ("Point of Delivery"). Trans- mission service for the peaking system power will be provided pursuant to the terms and conditions of the NU System Companies' Transmission Service Tariff No. 1, on file with FERC. The capacity charges pursuant to Section 6 of this Agreement include the full cost of said transmission service on the NU System Companies. Buyer shall be responsible for all transmission electrical losses incurred on the NU system in transmitting power to Buyer. Such losses shall be determined in accordance with the provisions of Tariff No. 1. The Point of Delivery may be changed by mutual agreement of the Parties. 6. Payment A. Capacity Charges The Capacity Charge for any calendar month shall be the product of (i) the amount of system capacity purchased pursuant to this Agreement (expressed in kW) for which Buyer receives NEPOOL Capability credit during the month, and (ii) one-twelfth of the applicable fixed Capacity Charge Rate for the applicable annual period as listed in Schedule I for the selected Scheduling Procedure pursuant to Schedule II. B. Energy Charge The Energy Charge for any calendar month shall equal the product of (i) the number of system kilowatt-hours of electrical energy deliv- ered by Seller to Buyer for the account of the Buyer in each hour during that month; and (ii) a heat rate of 12,000 Btu/kilowatt-hour, and (iii) the replacement fuel price of jet kerosene as reported to NEPOOL, pursuant to applicable NEPOOL Criteria, Rules and Standards, for South Meadow Station (in $/Btu). Notwithstanding the foregoing, if South Meadow Station no longer burns jet kerosene, then the Energy Charge will be the product of the applicable heat rate as stated above and the monthly average of the replacement fuel price as reported to NEPOOL for the all jet turbines for the NU System Companies. 7. Contingency Regarding Taxes and Fees If any governmental authority hereafter imposes a tax (including, but not limited to sales tax, gross revenue tax, energy tax, but excluding taxes assessed on income or property), fee for assessment on the capacity and/or energy sold or delivered under this Agreement, which is not in effect on the date this Agreement becomes effective, and such tax, fee or assessment is payable by Seller, Buyer shall reimburse Seller for the amount of such tax, fee or assessments actually paid by Seller with respect to the purchase, sale or delivery of capacity and/or energy hereunder; provided, however, that to the extent any such tax, fee or assessment is reflected in the replacement fuel cost as defined by Section 6.B of this Agreement, Buyer shall not be responsible for reimbursing to Seller the portion of such tax that is reflect- ed in such replacement fuel cost. Within twenty (20) days of the rendering of a bill or invoice for such tax, fee, or assessment, Buyer shall pay to Seller any uncontested amount not previously billed to and paid for by Buyer. Any contested amounts shall be subject to the provisions of Section 14 of this Agreement. Seller shall make a timely rate schedule change filing with the Commis- sion under Section 205 of the Federal Power Act in order to recover the costs associated with payment of any such new tax, fee or assessment. The annual charge FERC assesses against the Seller pursuant to Order No. 472 ("FERC Assessment") is based on the amount of electric energy generated and/or transmitted on the Seller's system during the year (expressed in megawatt-hours), as reported by the Seller in accordance with Reporting Requirement 582, as outlined in Order No. 472. Seller will charge monthly to the Buyer a portion of the FERC Assessment which shall be an estimated dollar amount equal to the product of (1) the amount of electric energy generated and/or transmitted on the Seller's system for the Buyer under this Agreement during that period of the Term which falls within such month (expressed in megawatt-hours), and (2) the applicable FERC rate for the most recently assessed year (expressed in dollars per megawatt-hour) as such rate appears on the appropriate FERC "Statement of Annual Charges." Within six months of receipt by Seller of the applicable FERC rate for a period of the term which has been billed on an estimated basis, Seller will adjust the previously estimated charges for that period covered by the actual applicable FERC Assessment. Buyer shall provide to Seller any necessary information for the calculation of such charge. 8. Billing Buyer shall be obligated to pay to Seller all charges billed in accor- dance with the terms of to this Agreement. Seller shall submit a bill for all applicable charges to Buyer as soon as practicable after the end of each calendar month during the Term. The bill shall include information in such reasonable detail to enable the Buyer to determine the basis for the charges for such month. Each bill shall be subject to adjustment as set forth in Section 9 hereof and for any errors in arithmetic, computation, meter readings, estimat- ing, or otherwise. All bills shall be due and payable not later than the Due Date, defined as (20) days after the date of invoice (the period of 20 days after date of invoice is intended to allow 5 days for invoice delivery and 15 days after receipt of invoice for payment). Any amount remaining unpaid after such twenty (20) days shall bear interest at the annual rate of two (2) percentage points over the Prime Rate (sometimes called Base Rate) for commercial loans to large corporate customers then in effect at the main office of the Bank of Boston, or such other lending institution as may be Seller's primary commercial lender from time to time during the period, from the Due Date to the date of payment by Buyer. If the Buyer, in good faith, disputes the amount of any bill, it shall pay to Seller the entire amount due and shall itemize the basis for its dispute in a written notice to Seller given on or before the Due Date. Upon final resolution of the dispute, if refunds are due to Buyer, Seller shall make such refunds together with interest calculated at the rate set forth above on all such disputed amounts that were paid to Seller and itemized in a written notice to Seller. 9. Estimates and Adjustments Pending the availability of actual data, computations by Seller of the charges for the purposes of billings hereunder for which actual data is not so available shall be based upon estimates made by Seller. Seller may make adjustments to any billing for a period of up to twelve (12) months from the date of such original billing in order to reflect differences in charges resulting from Seller's receipt of more current data. Buyer may dispute such adjustment in accordance with Section 8 of this Agreement. Seller shall make additional adjustments to billings after the twelve (12) month period to the extent such adjustments are required based upon final resolution of any claim, action, or proceeding that is based upon data contained in an original billing and that is formally initiated by, or noticed to Seller prior to the end of the twelve (12) month period following the date of such original billing. Seller shall promptly provide notice to Buyer of any such claim, action, or proceeding it becomes aware of, and include in such notice Seller's estimate of the potential impact of any such claim, action, or proceeding upon billed amounts. 10. Liability for Delivery Subject to Force Majeure, as defined in Section 11 of this Agreement, Buyer agrees that Seller's obligations for delivery under this Agreement shall be limited to delivery only over the NU System Companies' transmission system to the Point of Delivery. 11. Force Majeure As used in this Agreement, "Force Majeure" means any cause beyond the reasonable control of, and without the fault or negligence of, the Party claiming Force Majeure. It shall include, without limitation, sabotage, strikes, riots or civil disturbance, acts of God, act of public enemy, drought, earthquake, flood, explosion, fire, lightning, landslide, or similar- ly cataclysmic occurrence, or appropriation or diversion of electricity by sale or order of any governmental authority having jurisdiction thereof. Economic hardship of either Party shall not constitute a Force Majeure under this Agreement. If either Party is rendered wholly or partly unable to perform its obligations under this Agreement because of Force Majeure as defined above, that Party shall be excused from whatever performance is affected by the Force Majeure, to the extent so affected, provided that: (a) The non-performing Party promptly, but in no case longer than five working days after the occurrence of the Force Majeure, gives the other Party written notice describing the particulars of the occurrence. (b) The suspension of performance shall be of no greater scope and of no longer duration than is reasonably required by the Force Majeure. (c) The non-performing Party uses reasonable efforts to remedy its inability to perform. (d) The Seller's obligation to provide energy and the Buyer's obliga- tion to make payment shall be modified in proportion to the effect of Force Majeure conditions. 12. Assignment This Agreement shall be binding upon and shall inure to the benefit of, and may be performed by, the successors and assignees of the Parties, except that no assignment, pledge or other transfer of this Agreement by either Party shall operate to release the assignor, pledgor, or transferor from any of its obligations under this Agreement unless: (i) the other Party (or its succes- sors or assigns) consents in writing to the assignment, pledge or other transfer and expressly releases the assignor, pledgor, or transferor from its obligations hereunder, or (ii) the assignment, pledge or other transfer is to another company in the same holding company system as the assignor, pledgor or transferor and the assignee, pledgee or transferee is capable of fulfilling, and expressly assumes the obligations of the assignor, pledgor or transferor, or (iii) such transfer is incident to a merger or consolidation with, or transfer of all (or substantially all) of the assets of the transferor to another person or business entity which shall, as a part of such succession, assume all the obligations of the assignor, pledgor or transferor under this Agreement. No assignment, pledge, or transfer of this Agreement shall be made without the prior written consent of the other Party, which shall not be unreasonably withheld, except no prior written consent will be required as necessary for the assignment, pledge, or transfer to any of the member companies of such Parties' holding company system in accordance with (ii) of this Section 12. Nothing contained in this Section 12 shall restrict the Buyer's right to resale. 13. Interpretation The interpretation and performance of this Agreement shall be in accor- dance with and shall be controlled by the Federal Power Act and regulations and orders of the FERC thereunder and, to the extent not controlled thereby, the laws of the state of Connecticut. 14. Resolution of Disputes A. Any dispute between the Seller and Buyer involving service under this Agreement shall be referred to a senior representative of NUSCO and a senior representative of the Buyer designated by the Buyer for resolution on an informal basis as promptly as practica- ble. In the event the designated senior representatives are unable to resolve the dispute within thirty (30) days, or such other period as the parties may jointly agree upon, if NUSCO and the Buyer jointly agree, such dispute may be submitted to arbitration and resolved in accordance with the arbitration procedure set forth herein. If they do not agree, such dispute shall be present- ed promptly to FERC, but in no event more than sixty (60) days after rejecting arbitration. B. The arbitration shall be conducted before a single neutral arbi- trator appointed by the Parties. If the Parties fail to agree upon a single arbitrator within ten (10) days of the referral of the dispute to arbitration, NUSCO and the Buyer shall each choose one arbitrator, who shall sit on a three-member arbitration panel. The two arbitrators so chosen shall within twenty (20) days select a third arbitrator to act as chairman of the arbitration panel. In either case, the arbitrators shall be knowledgeable in electric utility matters, including electricity transmission and bulk power issues, and shall not have any current or past substantial busi- ness or financial relationships with any Party to the arbitration. The arbitrator(s) shall afford each of the Parties an opportunity to be heard and, except as otherwise provided herein, shall generally conduct the arbitration in accordance with the Commer- cial Arbitration Rules of the American Arbitration Association. There shall be no formal discovery conducted in connection with the arbitration, however, the Parties shall exchange witness lists and copies of any exhibits that they intend to utilize in their direct presentations at any hearing before the arbitrator(s) at least ten (10) days prior to such hearing, along with any other information or documents specifically requested by the arbitra- tor(s) prior to the hearing. Unless otherwise agreed, the arbitra- tor(s) shall render a decision within ninety (90) days of his, her, or their appointment and shall notify the Parties in writing of such decision and the reasons therefore, and shall make an award apportioning the payment of the costs and expenses of arbitration among the Parties, provided, however, that each Party shall bear the costs and expenses of its own arbitrator, attor- neys, expert witnesses and consultants. The arbitrator(s) shall be authorized only to interpret and apply the provisions of this Agreement and shall have no power to modify or change any of the terms of this Agreement in any manner. The decision of the arbi- trator(s) shall be final and binding upon the Parties, and judg- ment on the award may be entered in any court having jurisdiction. The decision of the arbitrator(s) may be appealed solely on the grounds that the conduct of the arbitrator(s), or the decision itself, violated the standards set forth in the Federal Arbitra- tion Act and/or the Administrative Dispute Resolution Act. 15. Accounts and Records Seller shall keep complete and accurate records and meter readings of its operations hereunder and shall maintain such data for a period of no more than three (3) years following the end of a calendar year of service hereun- der. Buyer shall have the right, during normal business hours, to examine and inspect all such records and meter readings insofar as may be necessary for the purpose of ascertaining the reasonableness and accuracy of all relevant data, estimates or statement of charges submitted to it hereunder. The costs of the audit shall be borne by the Buyer. 16. Authority of Northeast Utilities Service Company The NU System Companies hereby appoint and authorize NUSCO to represent and act for them in all matters relating to this Agreement. 17. Liability and Indemnification Except for willful misconduct, willful breach of contract, or negli- gence, neither Party (including such Parties' affiliated companies, trustees, directors, officers, employees, and agents) shall be liable to the other Party in tort, contract, or otherwise for any damages, costs, fines, penalties, or claims whatsoever which may result from such Parties' failure to perform its obligations hereunder. The Parties agree to indemnify, defend, and hold the other Party, affiliated companies, trustees, directors, officers, employees, and agents harmless from and against any and all costs, claims, liabilities, actions, or proceedings whatsoever arising from or claimed to have arisen from such Parties' failure to perform its obligations hereunder. Except for claims arising from willful misconduct, willful breach of contract, or gross negligence as provided for in the above paragraph, each Party (the indemnifying Party) agrees to indemnify, defend, and hold the other Party (including the other Party's affiliated companies, trustees, directors, officers, employees, and agents) harmless from and against any and all damages, costs (including attorney's fees), claims, liabilities, fines, penalties, actions or proceedings in tort, contract or otherwise, resulting from claims of third Parties arising or claimed to have arisen, from the acts or omissions of such indemnifying Party. The Parties hereby waive and release the other Party as well as the other Party's affiliated companies, trustees, directors, officers, employees, and agents from any liability, claim, or action arising from damage to property of the Parties due to the performance of the Parties hereunder, except where such damage is the result of gross negligence or willful miscon- duct. 18. Notices Any notice, demand, or request permitted or required under this Agree- ment shall be delivered in person or mailed by certified mail, postage prepaid, return receipt requested, or otherwise to confirm receipt, to a Party at the applicable address set forth below: To Buyer: Manager, Power Supply Administrator Commonwealth Electric Company 2421 Cranberry Highway Wareham, MA 02571 To Seller: Frank P. Sabatino Vice President - Wholesale Marketing Northeast Utilities Service Company Post Office Box 270 Hartford, CT 06141-0270 Such addresses may be changed from time to time by written notice by either Party to the other Party. 19. Miscellaneous (a) Each Party shall prepare, execute and deliver to the other Party at no additional expense any documents reasonably required to implement any provision hereof. (b) Any number of counterparts of this Agreement may be executed and each shall have the same force and effect as the original. (c) This Agreement, together with the attached Schedules I and II, shall constitute the entire understanding between the Parties and shall supersede any and all previous understandings pertaining to the subject matter of this Agreement. (d) This Agreement may be modified only by an instrument in writing signed by the Parties whereto. The rates for service specified herein shall remain in effect for the Term and shall not be subject to change through application to the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act absent the agreement of all Parties hereto. (e) Failure of either Party to enforce any provision of this Agreement or to require performance by the other Party of any of the provi- sions hereof, shall not be construed as a waiver of such provi- sions or affect the validity of this Agreement, any part hereof, or the right of either Party to thereafter enforce each and every provision. (f) The acceptance by the FERC of this Agreement as a rate schedule filing under Section 205 of the Federal Power Act will supersede the letter dated June 15, 1994, confirming the mutual agreement of Seller and Commonwealth concerning the sale of system capacity and energy. IN WITNESS WHEREOF, Seller and Commonwealth have caused this Agreement to be signed by their respective duly authorized representatives as of the date first above written. Seller: Northeast Utilities Service Company By FRANK P. SABATINO Its Vice President as agent for: The Connecticut Light and Power Company Western Massachusetts Electric Company Public Service Company of New Hampshire Buyer: Commonwealth Electric Company By JAMES J. KEANE Its Vice President SCHEDULE I CAPACITY CHARGE RATE CAPACITY CHARGE RATE SCHEDULING SCHEDULING YEAR PROCEDURE #1 PROCEDURE #2 $/KW - YEAR $/KW - YEAR 1995 25 27 1996 30 32 1997 35 37 1998 40 42 1999 45 47 2000 50 52 SCHEDULE II SCHEDULING PROCEDURES 1. Commonwealth shall provide at least 6 months advance written notice to NUSCO of the amount of system capacity to be purchased in each month of a 6 month period. 2. Commonwealth shall provide at least 6 months advance written notice to NUSCO of the amount of system capacity to be purchased in a given month. EX-10 4 10.1.46.2 FIRST AMEND. TO POWER SALE AGREEMENT AMENDMENT TO POWER SALE AGREEMENT BY AND BETWEEN COMMONWEALTH ELECTRIC COMPANY AND ALTRESCO PITTSFIELD, L.P. AMENDMENT dated as of this 7th day of November 1994, by and between Common- wealth Electric Company, a Massachusetts corporation with a usual place of business at 2421 Cranberry Highway, Wareham, Massachusetts ("Company") and Altresco Pittsfield, L.P., a Delaware limited partnership with a principal place of business at One Bowdoin Square, Boston, Massachusetts ("Seller"), to the Power Sale Agreement dated February 20, 1992 ("Agreement"). WHEREAS the Company, pursuant to the Agreement and subject specifically to the provisions contained in Article 2.1 of the Agreement, purchases 17.2 percent of the electricity produced by the Seller's electric cogeneration facility, which is capable of generating approximately one-hundred sixty (160) megawatts ("MW") of electricity and which is located at a site owned by General Electric in Pittsfield, Massachusetts (the "Facility" or "Unit"); and WHEREAS, the Total Purchase Price for electricity purchased by the Company pursuant to Section 1 of Appendix B of the Agreement includes a component known as the Monthly Energy Charge, which component is defined in Section 3 of Appendix B of the Agreement; and WHEREAS, the Monthly Energy Charge is calculated, in part, by reference to the Tennessee Gas Pipeline Company's ("Tennessee") Current Average Cost of Purchased Gas, also known as the Weighted Average Cost of Gas ("WACOG"), or its successor index, as specified in Tennessee's approved Federal Energy Regulatory Commission ("FERC") Gas Tariff; and WHEREAS, Tennessee's WACOG ceased to be available as of July, 1992 as a consequence of the restructuring of Tennessee's services pursuant to FERC Order No. 636, and no successor index to Tennessee's WACOG exists; and WHEREAS, the Company and the Seller have agreed upon the terms of an index to replace Tennessee's WACOG for purposes of calculating the Monthly Energy Charge, and desire to execute this Amendment for purposes of memorializing their agreement. NOW, THEREFORE, in consideration of the mutual covenants set forth herein, the Company and the Seller agree as follows: 1. Unless otherwise defined herein, capitalized terms shall have the same meaning given to them in the Agreement. 2. For the purposes of determining the Monthly Energy Charge as defined in Section 3 of Appendix B of the Agreement, the first sentence of said section shall be deleted in its entirety and the following shall be substituted in place thereof: The Monthly Energy Charge shall be equal to the product of (i) the Delivered Energy and (ii) the Kilowatthour Charge, where the Kilowatthour Charge is equal to the product of (i) one and thirty-six hundredths cents per kilowatthour ($0.0136/kWh) and (ii) an index factor represented by the quantity M/N, where M shall be equal to the monthly weighted average sum of the following three fuel components, each expressed in U.S. dollars per MMBtu: (a) 50% weighting for the monthly average of the daily quotes during the Billing Period for No. 6 residual 2.2% sulfur fuel oil as listed in Platt's Oilgram under the heading "Estimated New York Harbor Spot Price," using the low cargo quotation, and assuming 6.3 MMBtu per barrel; and (b) 40% weighting for the average of the T2 spot price for each of the twelve (12) months immediately preceding the Billing Peri- od, where the T2 spot price for any month shall be equal to the arithmetic average of the following six indices for such month: the Louisiana & Offshore (zone 1 ) and Texas (zone 0) indices for Tennessee and the East Louisiana, West Louisiana, East Texas and South Texas indices for the Texas Eastern Transmis- sion Corporation, or their successor indices, each as published in the first of the month edition of Inside F.E.R.C.'s Gas Market Report, by reference to the table entitled "Prices of Spot Gas Delivered to Pipelines...," provided that at least four of the six indices, or their successor indices, are so published for any month, and if at least four of the six indi- ces are not so published for any month, the parties shall determine mutually acceptable substitute indices to use for the calculation of the T2 spot price; and (c) 10% weighting for New England Power Company's weighted average delivered cost of coal as reported in the most recently submit- ted FERC Form 423 for New England Power Company from time to time, and where N is $1.81/MMBtu. 3. The Company shall submit this Amendment to the Massachusetts Department of Public Utilities for approval. This Amendment shall become effective upon the receipt of such approvals in form and substance acceptable to the Company and the Seller. 4. All other terms and conditions of said Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the Company and the Seller have caused this Amendment to be duly executed as of the day and year first above written. COMMONWEALTH ELECTRIC COMPANY ALTRESCO PITTSFIELD, L.P. BY JMC ALTRESCO, INC. ITS GENERAL PARTNER By: JAMES J. KEANE By: JAMES A. KELLER James J. Keane Title: Vice President Title: Vice President Power Supply & Transmission EX-10 5 10.1.44.1 SECOND AMEND. TO POWER PURCHASE AGREE. SECOND AMENDMENT TO POWER PURCHASE AGREEMENT AMENDMENT dated as of this 23rd day of June, 1994, by and between Commonwealth Electric Company, a Massachusetts corporation with a principal place of business at One Main Street, Cambridge, Massachusetts ("the Company") and Dartmouth Power Associates Limited Partnership, a Massachusetts Limited Partnership with a place of business at One Energy Road, Dartmouth, Massachu- setts ("Seller"), to the Power Purchase Agreement by and between the Company and Seller, dated as of September 5, 1989 and amended by an Amendment to Power Purchase Agreement by and between the Company and Seller, dated as of August 3, 1990 (as amended, "the Agreement"). WHEREAS the Company, pursuant to the Agreement, purchases all electricity produced by the Seller's 67,600 KW generating facility located at One Energy Road, in Dartmouth, Massachusetts ("the Unit"); and WHEREAS the Total Purchase Price for electricity purchased by the Company pursuant to the Agreement includes a component known as the Monthly Energy Charge, which is defined (in section 4 of Appendix B of the Agreement) as including a component known as the Variable Fuel Supply Rate; and WHEREAS, the Variable Fuel Supply Rate is calculated, in part, by reference to the following indices for natural gas pipeline service: The "Tennessee CD-6" index (for service pursuant to the CD-6 rate under a FERC approved tariff by Tennessee Gas Pipeline Company, "Tennessee") and (2) the "Algonquin F-l" Index (for service pursuant to the F-1 rate under a FERC approved tariff by Algon- quin Gas Transmission Company, "Algonquin"); and WHEREAS, both the Algonquin F-1 rate and the Tennessee CD-6 rate have ceased to be available as a consequence of the restructuring of services of each of those respective pipelines pursuant to Federal Energy Regulatory Commission ("FERC") Order No. 636; and WHEREAS, the Variable Fuel Supply Rate is calculated, in, part, by reference to an index calculated by the Alberta Petroleum Marketing Commission for the Minister of Energy for the Province of Alberta, Canada known as the Alberta Market Price (AMP); and WHEREAS, the AMP, effective December 31, 1993 is no longer published; and WHEREAS, the Company and Seller have agreed upon the terms of an index to replace the F-1, CD-6 and AMP indices for purposes of calculating the Variable Fuel Supply Rate, and desire to execute this Amendment for purposes of memorializing their agreement. NOW, THEREFORE, in consideration of the mutual covenants set forth herein, the Company and Seller agree as follows: 1. That for the purposes of determining the Variable Fuel Supply Rate as referenced in section 4.1 of Appendix B of the Agreement, the last para- graph (including the table) of said section shall be deleted in its entirety and the following shall be substituted in place thereof: The Initial Variable Fuel Supply Rate shall be adjusted monthly to reflect the proportional change in the T2 index (as hereinafter defined) and the Alberta Reference Price, using the year 1988 as a base, and shall be calculated pursuant to the provisions of subsection 4.14. 4.14 For each Billing Period during the term of this Agreement, the Variable Fuel Supply Rate shall equal the product of (i) the Initial Variable Fuel Supply Rate and (ii) an Index Factor, the numerator of which shall be "N1" (as hereinafter defined) and the denominator of which shall be "D1" (as hereinafter defined); Where: "N1" shall equal the sum of (i) "T2" (as hereinafter defined) and (ii) the available Alberta Reference Price for the billing month. "D1" shall equal two (2) multiplied by "AFC-l". "T2" shall be calculated as the arithmetic average of the following four indices for the Billing Period: (a) the Offshore and Louisiana (Zone 1) index for Tennessee Gas Pipeline Company; (b) the Louisiana and Texas (Zone 0) index for Tennessee Gas Pipeline Company; (c) the arithmetic average of the East Texas and South Texas indices for Texas Eastern Transmission Corporation; (d) the arithmetic average of the East Louisiana and West Louisiana indices for the Texas Eastern Transmission Corpo- ration. all as reported in the table entitled "Prices of Spot Gas Delivered to Pipelines" in the first of the month edition of Inside F.E.R.C.'s Gas Market Report, provided that if any of the above described indices, or their successors, are not reported in any month, T2 shall be equal to the arithmetic average of the indices that are reported, provided that at least three of the above indices are so reported. If at least three of the above indices are not reported in any month, then the Henry Hub Cash Price, as reported in the first of the month edition of Inside F.E.R.C.'s Gas Market Report will serve as a Proxy for T2. However, the Henry Hub Cash Price shall not be used as a Proxy for T2 for two consecutive months unless agreed to by both parties. "AFC-1" shall equal $1.486 per MMBTU. This value is the sum of (i) the average "T2" value for calendar year 1988 and (ii) the average Alberta Market Price for calendar year 1988, divided by two (2). The "Alberta Reference Price" is the gas reference price prescribed by the Minister of Energy for the Province of Alberta, Canada for the calendar month of the Billing Period (for example, the gas reference price published by the Minister for June, 1994 would be the Alberta Reference Price used to calculate the Variable Fuel Supply Rate for June, 1994 but actually reflect data for the month of April, 1994). The data is published by the Alberta Petroleum Marketing Commission. 2. The following shall be inserted as section 4.3 of Appendix B of the Agreement: 4.3 Redetermination of the Variable Fuel Supply Rate: Either the Seller or the Company shall have the right to require a redetermination of the provisions of subsection 4.14 of this Appendix relating to the composition of the Index Factor, effec- tive upon November 1 of each of the following years: 1997, 2002, 2007 and 2012 (the "Redetermination Dates"). A party electing to require such a redetermination shall provide written notice (the "Redetermination Notice") to the other party no less than six (6) months and no more than one (1) year before the Redetermination Date on which such redetermination is to take effect. If a Redetermination Notice is not served by either party upon the other party during the specified time period, the Variable Fuel Supply Rate in effect immediately prior to the relevant Redeterm- ination Date shall continue to be calculated in the manner in effect prior to such Redetermination Date. If a Redetermination Notice is served within the time required, then the provisions of subsections 4.3.1 through 4.3.4 below shall apply. 4.3.1 Following receipt of a Redetermination Notice, the parties will negotiate in good faith to determine mutually satis- factory modifications to the Variable Fuel Supply Rate. 4.3.2 If the parties are unable to agree upon renegotiated Variable Fuel Supply Rate provisions on or before the date which is three (3) months prior to the Redetermination Date, either party may elect by written notice (the "Arbitration Notice") to the other party, to refer the redetermination of the Variable Fuel Supply Rate provisions to binding arbitration pursuant to Article 12 of the Agreement. If an Arbitration Notice is not issued by either party before the date which is three (3) months prior to the Redetermination Date, and the parties have not agreed upon renegotiated Variable Fuel Supply Rate provisions on or before the Redetermination Date, the Variable Fuel Supply Rate provisions shall continue to be calculated in the manner in effect immediate- ly prior to such Redetermination Date. 4.3.3 During the renegotiation of the Variable Fuel Supply Rate provisions and during any arbitration relating thereto, the parties and the arbitrators shall work to modify the Index Factor, N1/D1, as defined in subsection 4.14 such that the renegotiated Variable Fuel Supply Rate provisions will yield: (a) a price of natural gas that reflects the value of other long-term baseload gas supplies delivered at the city gate to local electric utility companies in Massachusetts and Rhode Island, where such prices have been adjusted by sub- tracting all applicable costs (at 100% load factor) of firm pipeline transportation from the wellhead to the respective city gates, including commodity charges, demand charges and fuel gas costs. (b) a Variable Fuel Supply Rate that the parties anticipate will enable the Unit to operate at an average capacity factor of at least sixty percent (60%) over the following five year period. (c) in the event that the objectives in (a) and (b) above are in conflict, objective (b) relating to operation at a capacity factor of at least sixty percent (60%) shall be considered the controlling factor. 4.3.4 Whenever there is a redetermination of the Variable Fuel Supply Rate in progress, transactions under this Agreement shall continue in the same fashion as they were conducted before such redetermination was initiated without prejudice to the rights of either party under this section 4.3, pending a redetermination resulting from renegotiation or arbitration. The Variable Fuel Supply Rate in effect prior to such redetermination shall be applied to all electricity delivered pursuant to this Agreement during the time period after the Redetermination Date until the day upon which a renegotiated or arbitrated decision is reached and issued (in this section, the "Subject Period"), whereupon the Variable Fuel Supply Rate Provisions as determined by the re- negotiation or arbitration shall, unless otherwise agreed by the parties, be applied to the Subject Period with interest (at the annual rate of two percentage points over the current interest rate on prime commercial loans then in effect at the First Nation- al Bank of Boston) and with appropriate adjustments (i.e., payment by the Company to the extent the Redetermined Variable Fuel Supply Rate is greater; payment by the Seller to the extent the Redeter- mined Rate is less) being made between the parties to reflect the change in the Variable Fuel Supply Rate Provisions. 3. The Company shall submit this Amendment to the MDPU, and the Seller shall submit this Amendment to the FERC, for the approval of each of the MDPU and the FERC. This Amendment shall become effective upon the receipt of such approvals in form and substance acceptable to the Company and the Seller. 4. All other terms and conditions of said Agreement shall remain in full force and effect. IN WITNESS WHEREOF, the Company and the Seller have caused this Amendment to be duly executed as of the day and year first above written. DARTMOUTH POWER ASSOCIATES LIMITED PARTNERSHIP BY EMI/DARTMOUTH, INC., ITS GENERAL PARTNER By: JAMES S. GORDON Title: President COMMONWEALTH ELECTRIC COMPANY By: JAMES J. KEANE Title: Vice President - Power Supply & Transmission