-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IGj3Jn2b2OkapbxIGKs0jMpbCzQMu/4ynY5XwW5Ok7+uhj6mywEYgp/Bei1wcEoV 3e1maKVFqn8e4UZYX806NQ== 0000043704-02-000027.txt : 20020814 0000043704-02-000027.hdr.sgml : 20020814 20020814144400 ACCESSION NUMBER: 0000043704-02-000027 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20020630 FILED AS OF DATE: 20020814 FILER: COMPANY DATA: COMPANY CONFORMED NAME: GREEN MOUNTAIN POWER CORP CENTRAL INDEX KEY: 0000043704 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 030127430 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-08291 FILM NUMBER: 02734959 BUSINESS ADDRESS: STREET 1: 163 ACORN LANE STREET 2: . CITY: COLCHESTER STATE: VT ZIP: 05446 BUSINESS PHONE: 8028645731 MAIL ADDRESS: STREET 1: 163 ACORN LANE STREET 2: . CITY: COLCHESTER STATE: VT ZIP: 05446 10-Q 1 june200210q.txt SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 __________________________ FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2002 ------------- 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 1-8291 ------ GREEN MOUNTAIN POWER CORPORATION -------------------------------- (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) VERMONT 03-0127430 - ------------------ ---------- (STATE OR OTHER JURISDICTION OF INCORPORATION (I.R.S. EMPLOYER IDENTIFICATION NO.) OR ORGANIZATION) 163 ACORN LANE COLCHESTER, VT 05446 - --------------------- ----------- ADDRESS OF PRINCIPAL EXECUTIVE OFFICES (ZIP CODE) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (802) 864-5731 --------------- 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. CLASS - COMMON STOCK OUTSTANDING AT AUGUST 9, 2002 - --------------------------- ---------------------------------- $3.33 1/3 PAR VALUE 5,723,540 GREEN MOUNTAIN POWER CORPORATION INDEX TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES AT AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2002 AND 2001 Financial Statements Page Consolidated Statements of Income 3 Consolidated Statements of Cash Flows 4 Consolidated Balance Sheets 5 Notes to Consolidated Financial Statements 7 Management's Discussion and Analysis of Financial Condition 16 And Results of Operations Other Information 25 Exhibits and Reports on Form 8-K 25 The accompanying notes are an integral part of the consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED COMPARATIVE INCOME STATEMENTS UNAUDITED ---------- THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30 JUNE 30 2002 2001 2002 2001 -------- -------- --------- --------- In thousands, except per share data OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $65,135 $67,471 $134,001 $142,267 -------- -------- --------- --------- OPERATING EXPENSES Power Supply Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 8,191 5,737 16,265 19,422 Company-owned generation. . . . . . . . . . . . . . . . . . 617 (133) 1,578 2,243 Purchases from others . . . . . . . . . . . . . . . . . . . 37,588 40,166 75,734 78,541 Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,547 4,405 7,054 7,773 Transmission . . . . . . . . . . . . . . . . . . . . . . . . 4,002 3,544 7,972 7,002 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 2,059 2,078 4,274 3,535 Depreciation and amortization. . . . . . . . . . . . . . . . 3,408 3,623 6,939 7,312 Taxes other than income. . . . . . . . . . . . . . . . . . . 1,934 1,915 3,905 3,903 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 975 1,861 3,025 3,687 -------- -------- --------- --------- Total operating expenses. . . . . . . . . . . . . . . . . 62,321 63,196 126,746 133,418 -------- -------- --------- --------- OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 2,814 4,275 7,255 8,849 -------- -------- --------- --------- OTHER INCOME Equity in earnings of affiliates and non-utility operations. 535 584 1,069 1,135 Allowance for equity funds used during construction. . . . . 49 45 122 59 Other income (deductions), net . . . . . . . . . . . . . . . 15 (47) (53) (74) -------- -------- --------- --------- TOTAL OTHER INCOME (DEDUCTIONS) . . . . . . . . . . . . . 599 582 1,138 1,120 -------- -------- --------- --------- INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 3,413 4,857 8,393 9,969 -------- -------- --------- --------- INTEREST CHARGES Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,254 1,547 2,613 3,095 Other interest . . . . . . . . . . . . . . . . . . . . . . . 295 232 508 710 Allowance for borrowed funds used during construction. . . . (22) (41) (54) (103) -------- -------- --------- --------- TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,527 1,738 3,067 3,702 -------- -------- --------- --------- INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 1,886 3,119 5,326 6,267 DISCONTINUED OPERATIONS Preferred stock dividend requirement . . . . . . . . . . . . 11 235 95 469 -------- -------- --------- --------- Income from continuing operations. . . . . . . . . . . . . . 1,875 2,884 5,231 5,798 Net income from discontinued segment operations . . . . . . . . . . . . . . . . . . . . . . . . . - Loss on disposal, including provisions for operating losses during phaseout period. . . . . . . . . . . - (150) - (150) -------- -------- --------- --------- NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 1,875 $ 2,734 $ 5,231 $ 5,648 ======== ======== ========= ========= Common stock data Basic earnings per share . . . . . . . . . . . . . . . . . . $ 0.33 $ 0.49 $ 0.92 $ 1.01 Diluted earnings per share . . . . . . . . . . . . . . . . . 0.32 0.47 0.89 0.98 Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 $ 0.28 $ 0.28 Weighted average common shares outstanding-basic . . . . . . 5,711 5,615 5,701 5,602 Weighted average common shares outstanding-diluted . . . . . 5,877 5,777 5,866 5,759 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Balance - beginning of period. . . . . . . . . . . . . . . . $10,644 $ 2,639 $ 8,070 $ 493 Net Income . . . . . . . . . . . . . . . . . . . . . . . . . 1,886 2,969 5,326 6,117 Preferred stock dividend requirement . . . . . . . . . . . . (11) (235) (95) (469) Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . (50) - (50) - Cash Dividends-common stock. . . . . . . . . . . . . . . . . (786) (771) (1,568) (1,539) -------- -------- --------- --------- Balance - end of period. . . . . . . . . . . . . . . . . . . $11,683 $ 4,602 $ 11,683 $ 4,602 ======== ======== ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION UNAUDITED --------- CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30 2002 2001 -------------- --------- OPERATING ACTIVITIES: In thousands Net income before preferred stock dividend requirement $ 5,326 $ 6,117 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 6,939 7,312 Dividends from associated companies less equity income 97 21 Allowance for funds used during construction (176) (162) Amortization of purchased power costs 3,611 2,008 Deferred income taxes 988 (1,714) Deferred revenues - 3,158 Deferred purchased power costs (2,075) (1,966) Accrued purchase power contract option call - (2,376) Earnings cap deferral and rate levelization liability (4,309) 4,869 Environmental and conservation amortization (deferrals), net (800) (1,377) Changes in: Accounts receivable 1,209 1,034 Accrued utility revenues 849 708 Fuel, materials and supplies 173 (261) Prepayments and other current assets 1,670 1,578 Accounts payable (2,363) (1,346) Accrued income taxes payable and receivable 1,359 2,125 Other current liabilities (680) 389 Other 152 (1,856) -------------- --------- Net cash provided by continuing operations 11,970 18,261 INVESTING ACTIVITIES: Construction expenditures (8,638) (5,224) Investment in nonutility property (100) (101) -------------- --------- Net cash used in investing activities (8,738) (5,325) -------------- --------- FINANCING ACTIVITIES: Redemption of preferred stock (12,325) - Issuance of common stock 472 806 Reduction in long term debt (5,100) (1,700) Power supply option obligation, net - 244 Short-term debt, net 10,400 (10,608) Cash dividends and preferred stock dividend requirement (1,664) (2,008) -------------- --------- Net cash used in financing activities (8,217) (13,266) -------------- --------- Net increase(decrease) in cash and cash equivalents (4,985) (330) Cash and cash equivalents at beginning of period 5,006 341 -------------- --------- Cash and cash equivalents at end of period $ 21 $ 11 ============== ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid year-to-date for: Interest (net of amounts capitalized) $ 3,053 $ 1,354 Income taxes, net 2,349 -
The accompanying notes are an integral part of these consolidated financial statements.
PART I, ITEM 1 GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED BALANCE SHEETS UNAUDITED --------- AT JUNE 30, DECEMBER 31, 2002 2001 2001 ------------- -------- -------- In thousands ASSETS UTILITY PLANT Utility plant, at original cost $ 306,127 $295,133 $302,489 Less accumulated depreciation 122,950 114,380 119,054 ------------- -------- -------- Net utility plant 183,177 180,753 183,435 Property under capital lease 5,959 6,449 5,959 Construction work in progress 10,530 6,955 7,464 ------------- -------- -------- Total utility plant, net 199,666 194,157 196,858 ------------- -------- -------- OTHER INVESTMENTS Associated companies, at equity 14,019 14,322 14,093 Other investments 7,108 6,598 6,852 ------------- -------- -------- Total other investments 21,127 20,920 20,945 ------------- -------- -------- CURRENT ASSETS Cash and cash equivalents 21 11 5,006 Certficate of deposit, pledged as collateral - 15,936 - Accounts receivable, customers and others, less allowance for doubtful accounts of $613, $613, and $613 15,902 24,560 17,111 Accrued utility revenues 5,015 6,385 5,864 Fuel, materials and supplies, at average cost 3,885 4,316 4,058 Prepayments 413 889 1,976 Income tax receivable - - 1,699 Other 363 278 469 ------------- -------- -------- Total current assets 25,599 52,375 36,183 ------------- -------- -------- DEFERRED CHARGES Demand side management programs 6,687 6,485 6,961 Purchased power costs 1,995 8,604 3,504 Pine Street Barge Canal 12,425 12,370 12,425 Power supply derivative deferral 33,694 15,714 37,313 Other 14,612 15,749 14,870 ------------- -------- -------- Total deferred charges 69,413 58,922 75,073 ------------- -------- -------- NON-UTILITY Cash and cash equivalents - - - Other current assets 8 8 8 Property and equipment 250 251 250 Other assets 775 847 817 ------------- -------- -------- Total non-utility assets 1,033 1,106 1,075 ------------- -------- -------- TOTAL ASSETS $ 316,838 $327,480 $330,134 ============= ======== ========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED BALANCE SHEETS UNAUDITED --------- AT JUNE 30, DECEMBER 31, 2002 2001 2001 --------- --------- --------- In thousands except share data CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity Common stock, $3.33 1/3 par value, authorized 10,000,000 shares (issued 5,716,975, 5,641,009 and 5,701,010) $ 19,110 $ 18,802 $ 19,004 Additional paid-in capital 74,948 73,933 74,581 Retained earnings 11,683 4,602 8,070 Treasury stock, at cost (15,856 shares) (378) (378) (378) --------- --------- --------- Total common stock equity 105,363 96,959 101,277 Redeemable cumulative preferred stock 85 12,560 12,325 Long-term debt, less current maturities 71,000 70,400 74,400 --------- --------- --------- Total capitalization 176,448 179,919 188,002 --------- --------- --------- CAPITAL LEASE OBLIGATION 5,959 6,449 5,959 --------- --------- --------- CURRENT LIABILITIES Current maturities of preferred stock 150 235 235 Current maturities of long-term debt 8,000 9,700 9,700 Short-term debt 10,400 4,892 - Accounts payable, trade and accrued liabilities 6,410 8,985 7,237 Accounts payable to associated companies 6,825 5,932 8,361 Accrued taxes 933 - - Customer deposits 838 816 971 Purchased power call option liability - 5,901 - Interest accrued 1,145 1,075 1,100 Energy East power supply obligation - 16,163 - Rate Levelization liability 4,218 4,869 8,527 Deferred revenues - 3,158 - Other 1,081 1,959 2,945 --------- --------- --------- Total current liabilities 40,000 63,685 39,076 --------- --------- --------- DEFERRED CREDITS Power supply derivative liability 33,694 15,714 37,313 Accumulated deferred income taxes 24,888 24,071 23,759 Unamortized investment tax credits 3,272 3,554 3,413 Pine Street Barge Canal site cleanup 9,436 11,080 10,059 Other 20,787 21,374 20,852 --------- --------- --------- Total deferred credits 92,077 75,793 95,396 --------- --------- --------- COMMITMENTS AND CONTINGENCIES NON-UTILITY Other Liabilities 2,354 1,634 1,701 --------- --------- --------- Total non-utility liabilities 2,354 1,634 1,701 --------- --------- --------- TOTAL CAPITALIZATION AND LIABILITIES $316,838 $327,480 $330,134 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. GREEN MOUNTAIN POWER CORPORATION NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2002 PART I-ITEM 1 1. SIGNIFICANT ACCOUNTING POLICIES It is our opinion that the financial information contained in this report reflects all normal, recurring adjustments necessary to present a fair statement of results for the period reported, but such results are not necessarily indicative of results to be expected for the year due to the seasonal nature of our business and include other adjustments discussed elsewhere in this report necessary to reflect fairly the results of the interim periods. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, the disclosures herein, when read with the annual report for 2001 filed on Form 10-K, are adequate to make the information presented not misleading. The Vermont Public Service Board ("VPSB"), the regulatory commission in Vermont, sets the rates we charge our customers for their electricity. In periods prior to April 2001, we charged our customers higher rates for billing cycles in December through March and lower rates for the remaining months. These were called seasonally differentiated rates. Seasonal rates were eliminated in April 2001, and generated approximately $8.5 million of revenues deferred in 2001 that we estimate will be used to offset increased costs during 2002, including $2.2 million that was recognized during the first quarter, and $2.1 million recognized in the second quarter. Certain line items on the prior year's financial statements have been reclassified for consistent presentation with the current year. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions that affect assets and liabilities, and revenues and expenses. Actual results could differ from those estimates. UNREGULATED OPERATIONS We have or have had unregulated, wholly owned subsidiaries: Northern Water Resources, Inc. ("NWR"); Green Mountain Propane Gas Company Limited ("GMPG"); GMP Real Estate Corporation; and Green Mountain Resources, Inc. ("GMRI"). During 2000 and 2001, we sold most of the assets of NWR, and reported its results as income (loss) from operations of a discontinued segment. See the disclosure under the caption "Segments and Related Information" for a more detailed discussion. We also have a rental water heater program that is not regulated by the VPSB. The results of the operations of these subsidiaries, including NWR during 2002, and the rental water heater program are included in equity in earnings of affiliates and non-utility operations in the Other Income section of the Consolidated Comparative Income Statements. 2. INVESTMENT IN ASSOCIATED COMPANIES We recognize net income from our affiliates (companies in which we have ownership interests) listed below based on our percentage ownership (equity method). VERMONT YANKEE NUCLEAR POWER CORPORATION ("VY", OR "VERMONT YANKEE") Percent ownership: 19.0% common
Three Months Ended Six Months Ended June 30 June 30 2002 2001 2002 2001 ------- ------- ------- ------- (in thousands) Gross Revenue. . . . . $46,764 $57,031 $85,495 $97,995 Net Income Applicable. 1,462 1,574 2,949 3,124 to Common Stock Equity in Net Income . 258 287 571 560
On August 15, 2001, VY agreed to sell its nuclear power plant to Entergy Corporation for approximately $180 million. On July 31, 2002, Vermont Yankee announced that the sale of its nuclear power plant to Entergy Nuclear Vermont Yankee ("Entergy") had been completed. In addition to the sale of the generating plant, the transaction calls for Entergy to provide 20 percent of the plant output to the Company through 2012, which represents approximately 35 percent of the Company's energy requirements. The Company continues to own approximately 19 percent of the common stock of VY. The benefits to Green Mountain Power of the plant sale and power contract with Entergy include: Vermont Yankee receives cash approximately equal to the book value of the plant assets, removing the potential for stranded costs associated with the plant. Vermont Yankee and its owners will no longer bear operating risks associated with running the plant. Vermont Yankee and its owners will no longer bear the risks associated with the eventual decommissioning of the plant. Prices under the power contract with Entergy range from $39 to $45 per megawatt-hour, substantially lower than the forecasted cost of continued ownership and operation by Vermont Yankee. The power contract with Entergy calls for a downward adjustment in the price if market prices for electricity fall by defined amounts beginning no later than November 2005. If market prices rise, however, the contract prices are not adjusted upward. The Company remains responsible for procuring replacement energy at market prices during periods of scheduled or unscheduled outages at the Entergy plant. The VY plant had fuel rods that required repair during May 2002, a maintenance requirement that is not unique to VY. VY shutdown the plant for a twelve-day period, beginning on May 11, 2002, to repair the rods. The Company estimates its portion of the cost for repair, including incremental replacement energy costs, to be approximately $2.0 million. The Company received an accounting order from the Vermont Public Service Board on August 2, 2002, allowing it to defer the additional costs related to the outage, and believes that such amounts are probable of future recovery. The Company's ownership share of VY has increased from approximately 17.9 percent last year to approximately 19.0 percent currently, due to VY's purchase of certain minority shareholders' interests. VERMONT ELECTRIC POWER COMPANY, INC. ("VELCO") Percent ownership: 29.5% common 30.0% preferred VELCO is a corporation engaged in the transmission of electric power within the State of Vermont. VELCO has entered into transmission agreements with the State of Vermont and various electric utilities, including the Company, and under these agreements, VELCO bills all costs, including interest on debt and a fixed return on equity, to the State and others using VELCO's transmission system.
Three Months Ended Six Months Ended June 30 June 30 2002 2001 2002 2001 ------ ------ ------- ------- (in thousands) Gross Revenue . . . . $5,312 $8,548 $11,796 $15,718 Net Income. . . . . . 318 309 513 552 Equity in Net Income. 92 91 169 146
3. COMMITMENTS AND CONTINGENCIES ENVIRONMENTAL MATTERS The electric industry typically uses or generates a range of potentially hazardous products in its operations. We must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. We believe that we are in substantial compliance with these requirements and that there are no outstanding material complaints about the Company's compliance with present environmental protection regulations, except for developments related to the Pine Street Barge Canal site. PINE STREET BARGE CANAL SITE The Federal Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), commonly known as the "Superfund" law, generally imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. We are one of several potentially responsible parties ("PRPs") for cleanup of the Pine Street Barge Canal ("Pine Street") site in Burlington, Vermont, where coal tar and other industrial materials were deposited. In September 1999, we negotiated a final settlement with the United States, the State of Vermont (the "State"), and other parties to a Consent Decree that covers claims with respect to the site and implementation of the selected site cleanup remedy. In November 1999, the Consent Decree was filed in the federal district court. The Consent Decree addresses claims by the Environmental Protection Agency (the "EPA") for past Pine Street site costs, natural resource damage claims and claims for past and future oversight costs. The Consent Decree also provides for the design and implementation of response actions at the site. As of June 30, 2002, our total expenditures related to the Pine Street site since 1982 were approximately $25.9 million. This includes amounts not recovered in rates, amounts recovered in rates, and amounts for which rate recovery has been sought but which are presently waiting further VPSB action. The bulk of these expenditures consisted of transaction costs. Transaction costs include legal and consulting costs associated with the Company's opposition to the EPA's earlier proposals of a more expensive remedy at the site, litigation and related costs necessary to obtain settlements with insurers and other PRPs to provide amounts required to fund the clean up ("remediation costs"), and to address liability claims at the site. A smaller amount of past expenditures was for site-related response costs, including costs incurred pursuant to EPA and State orders that resulted in funding response activities at the site, and to reimbursing the EPA and the State for oversight and related response costs. The EPA and the State have asserted and affirmed that all costs related to these orders are appropriate costs of response under CERCLA for which the Company and other PRPs were legally responsible. We estimate that we have recovered or secured, or will recover, through settlements of litigation claims against insurers and other parties, amounts that exceed estimated future remediation costs, future federal and state government oversight costs and past EPA response costs. We currently estimate our unrecovered transaction costs mentioned above, which were necessary to recover settlements sufficient to remediate the site, to oppose much more costly solutions proposed by the EPA, and to resolve monetary claims of the EPA and the State, together with our remediation costs, to be $12.4 million over the next 32 years. The estimated liability is not discounted, and it is possible that our estimate of future costs could change by a material amount. We also have recorded an offsetting regulatory asset, and we believe that it is probable that we will receive future revenues to recover these costs. Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and received recovery for ongoing expenses associated with the Pine Street site. While reserving the right to argue in the future about the appropriateness of full rate recovery of the site-related costs, the Company and the Vermont Department of Public Service (the "Department"), and as applicable, other parties, reached agreements in these cases that the full amount of the site-related costs reflected in those rate cases should be recovered in rates. We proposed in our rate filing made on June 16, 1997 recovery of an additional $3.0 million in such expenditures. In an Order in that case released March 2, 1998, the VPSB suspended the amortization of expenditures associated with the Pine Street site pending further proceedings. Although it did not eliminate the rate base deferral of these expenditures, or make any specific order in this regard, the VPSB indicated that it was inclined to agree with other parties in the case that the ultimate costs associated with the Pine Street site, taking into account recoveries from insurance carriers and other PRPs, should be shared between customers and shareholders of the Company. In response to our Motion for Reconsideration, the VPSB on June 8, 1998 stated its intent was "to reserve for a future docket issues pertaining to the sharing of remediation-related costs between the Company and its customers". The VPSB Order released January 23, 2001 and discussed below did not change the status of Pine Street cost recovery. RETAIL RATE CASE The Company reached a final settlement agreement with the Department in its 1998 rate case during November 2000. The final settlement agreement contained the following provisions: * The Company received a rate increase of 3.42 percent above existing rates, beginning with bills rendered January 23, 2001, and prior temporary rate increases became permanent; * Rates were set at levels that recover the Company's Hydro-Quebec VJO contract costs, effectively ending the regulatory disallowances experienced by the Company from 1998 through 2000; * The Company agreed not to seek any further increase in electric rates prior to April 2002 (effective in bills rendered January 2003) unless certain substantially adverse conditions arise, including a provision allowing a request for additional rate relief if power supply costs increase in excess of $3.75 million over forecasted levels; * The Company agreed to write off in 2000 approximately $3.2 million in unrecovered rate case litigation costs, and to freeze its dividend rate until it successfully replaces short-term credit facilities with long-term debt or equity financing; * Seasonal rates were eliminated in April 2001, which generated approximately $8.5 million in additional cash flow in 2001 that can be utilized to offset increased costs during 2002 and 2003; * The Company agreed to consult extensively with the Department regarding capital spending commitments for upgrading our electric distribution system and to adopt customer care and reliability performance standards, in a first step toward possible development of performance-based rate-making; * The Company agreed to withdraw its Vermont Supreme Court appeal of the VPSB's Order in a 1997 rate case; and * The Company agreed to an earnings limitation for its electric operations in an amount equal to its allowed rate of return of 11.25 percent, with amounts earned over the limit being used to write off regulatory assets. The Company earned approximately $30,000 in excess of its allowed rate of return during 2001 before writing off regulatory assets in the same amount. On January 23, 2001, the VPSB approved the Company's settlement (the "Settlement Order") with the Department, with two additional conditions: * The Company and customers shall share equally any premium above book value realized by the Company in any future merger, acquisition or asset sale, subject to an $8.0 million limit on the customers' share; and * The Company's further investment in non-utility operations is restricted. POWER CONTRACT COMMITMENTS Under an arrangement established on December 5, 1997 ("9701"), Hydro-Quebec paid $8.0 million to the Company. In return for this payment, we provided Hydro-Quebec options for the purchase of power. Commencing April 1, 1998 and effective through 2015, the term of a previous contract with Hydro-Quebec (the "1987 Contract"), Hydro-Quebec may purchase up to 52,500 MWh ("option A") on an annual basis, at the 1987 Contract energy prices, which are substantially below current market prices. The cumulative amount of energy that may be purchased under option A shall not exceed 950,000 MWh. Over the same period, Hydro-Quebec may exercise an option to purchase a total of 600,000 MWh ("option B") at the 1987 Contract energy prices. Under option B, Hydro-Quebec may purchase no more than 200,000 MWh in any year. During the first half of 2002, $1.5 million in power supply expense was recognized to reflect the cost of option A, which is recognized ratably over the year. Hydro-Quebec has previously agreed not to call option B during the 2002 contract year. At June 30, 2002, the cumulative amount of power purchased by Hydro-Quebec under option B is approximately 432,000 MWh. During the first quarter of 2001, Hydro-Quebec exercised option A and option B, calling for deliveries of 134,592 MWh during June, July and August of 2001. The Company recognized $3.3 million in expense during the six months ended June 30, 2001 to reflect 9701 estimated costs. A regulatory asset of $3.3 million was established for the remaining estimated difference between the option exercise price and the expected cost of replacement power for 2001. If estimated costs of fulfilling the Hydro-Quebec option calls exceed amounts recovered in rates, the excess cost would be immediately charged against earnings. No charge for excess cost was required during the first half of 2002 and 2001. No charges in excess of amounts provided in rates or previously recorded are anticipated for the remainder of 2002. Hydro-Quebec's option to curtail energy deliveries pursuant to a July 1994 Agreement can be exercised in addition to these purchase options if documented drought conditions exist. The exercise of this curtailment option is limited to five times, requiring notice four months in advance of any contract year, and cannot reduce deliveries by more than approximately 13 percent. The Company may defer the curtailment by one year. Hydro-Quebec also has the option to reduce the load factor from 75 percent to 65 percent under the 1987 Contract a total of three times over the life of the contract. The Company can delay the load factor reduction by one year under the same contract. During 2001, Hydro-Quebec exercised the first of its load factor reduction options intended for 2002, and the Company delayed the effective date of this exercise until 2003. The Company estimates that the net cost of Hydro-Quebec's exercise of its load factor reduction option will increase power supply expense during 2003 by approximately $0.4 million. It is possible our estimate of future power supply costs could differ materially from actual results. COMPETITION During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated inquiries and legal procedures to establish its own electric utility, seeking to purchase an existing hydro-generation facility from a third party, and the associated distribution plant owned by the Company within Rockingham. In March 2002, voters in Rockingham authorized Rockingham to create a municipal utility by acquiring a municipal plant, which would include the Bellows Falls hydroelectric facility and the electric distribution systems of the Company and/or Central Vermont Public Service Corporation. The Company receives annual revenues of approximately $4.0 million from its customers in Rockingham. Should Rockingham create a municipal system, the Company would vigorously pursue its right to receive just compensation from Rockingham. Such compensation would include full reimbursement for Company assets, if acquired, and full reimbursement of any other costs associated with the loss of customers in Rockingham, to assure that our remaining customers do not subsidize a Rockingham municipal utility. 4. SEGMENTS AND RELATED INFORMATION The Company has two reportable segments during 2002, the electric utility and NWR. NWR was reported as discontinued operations in 2001. The Company was unable to sell all of the NWR investments and believes that classification and reporting as discontinued operations is no longer appropriate. The electric utility is engaged in the distribution and sale of electrical energy in the State of Vermont and also reports the results of its wholly owned unregulated subsidiaries (GMPG, GMRI, NWR and GMP Real Estate) and the rental water heater program as a separate line item in the Other Income section in the Consolidated Statement of Income. NWR is an unregulated business that invested in energy generation, energy efficiency and wastewater treatment projects. As of June 30, 2002, most of NWR's net assets and liabilities have been sold or otherwise disposed. The remaining net liability reflects expected warranty obligations, net of equity investments in two wind farms and wastewater treatment projects. In 2001, the Company reported NWR results as discontinued operations. The provisions for loss from discontinued operations reflected the Company's most recent estimate at that time. The ultimate loss remains subject to the disposition of NWR's remaining liabilities, primarily wastewater treatment warranty obligations, and could exceed amounts recorded. Results of operations for NWR for the three and six months ended June 30, 2002 are now reported as continuing operations under the caption Equity in earnings of affiliates and non-utility operations. Segment information compared with the Company's results includes the following:
Three months ended Six months ended June 30 June 30 2002 2001 2002 2001 -------- -------- --------- --------- (in thousands, except per share data) External revenues Electric utility . . . . . . . . . . $65,135 $74,796 $134,001 $142,267 NWR segment. . . . . . . . . . . . . 62 35 62 104 Net income from operations Electric utility . . . . . . . . . . $ 1,890 $ 2,884 $ 5,272 $ 5,798 NWR segment. . . . . . . . . . . . . (15) (150) (41) (150) -------- -------- --------- --------- Consolidated net income . . . . . . . $ 1,875 $ 2,914 $ 5,231 $ 5,648 ======== ======== ========= ========= Basic earnings per share Discontinued operations. . . . . . $ - $ (0.03) $ - $ (0.03) Continuing operations. . . . . . . 0.33 0.51 0.92 1.04 Diluted earnings per share Discontinued operations. . . . . . $ - $ (0.03) $ - $ (0.03) Continuing operations. . . . . . . 0.32 0.47 0.89 0.98
5. DERIVATIVE INSTRUMENTS AND RISK MANAGEMENT In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended ("SFAS 133"). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS 133, as amended by SFAS 137, was effective for the Company beginning 2001. One objective of the Company's risk management program is to stabilize cash flow and earnings by minimizing power supply risks. Transactions permitted by the risk management program include futures, forward contracts, option contracts, swaps and transmission congestion rights with counter-parties that have at least investment grade ratings. These transactions are used to hedge the risk of fossil fuel and spot market electricity price increases. Futures, swaps and forward contracts are used to hedge market prices should option calls by Hydro-Quebec be exercised. The Company's risk management policy specifies risk measures, the amount of tolerable risk exposure, and authorization limits for transactions. On April 11, 2001, the VPSB issued an accounting order that requires the Company to defer recognition of any earnings effects relating to future periods caused by application of SFAS 133. At June 30, 2002, the Company had a liability reflecting the fair value of the two derivatives described below, as well as a corresponding regulatory asset of approximately $33.7 million. The Company believes that the regulatory asset is probable of recovery in future rates. The liability is based on current estimates of future market prices that are subject to change by material amounts. If a derivative instrument is terminated early because it is probable that a transaction or forecasted transaction will not occur, any gain or loss would be recognized in earnings immediately. For derivatives held to maturity, the earnings impact would be recorded in the period that the derivative is sold or matures. The Company has a contract with Morgan Stanley Capital Group, Inc. ("MS") used to hedge against increases in fossil fuel prices. MS purchases the majority of the Company's power supply resources at index (fossil fuel resources) or specified (i.e., contracted resources) prices and then sells to us at a fixed rate to serve pre-established load requirements. This contract allows management to fix the cost of much of its power supply requirements, subject to power resource availability and other risks. The MS contract is a derivative under SFAS 133 and was scheduled to expire on December 31, 2003. In August 2002, the Company extended the contract with MS through December 31, 2006. Beginning in 2004, the extended contract includes only our interests in the Wyman and Stonybrook plants with respective capacities of 7 MW and 45 MW, and our estimated load requirements not satisfied by contractual arrangements and other owned generation. The cost of power purchased from MS for 2003 is expected to be approximately $6.0 million less than the cost of power purchased from MS during 2002. The remainder of our load requirements are substantially provided through our power supply contracts and arrangements with Hydro-Quebec and our entitlements to power generated at the Vermont Yankee nuclear plant now owned by Entergy. Management's estimate of the fair value of the future net cost of this contract at June 30, 2002 is approximately $5.1 million. We also sometimes use future contracts to hedge forecasted wholesale sales of electric power, including material sales commitments. We currently have an arrangement with Hydro-Quebec that grants it an option to call power at prices below current and estimated future market rates. This arrangement is a derivative and is effective through 2015. Management's estimate of the fair value of the future net cost for this arrangement at June 30, 2002 is approximately $28.6 million. 6. NEW ACCOUNTING STANDARDS In June 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations ("SFAS 141"), and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets ("SFAS 142"). SFAS 141 requires the use of the purchase method to account for business combinations initiated after June 30, 2001 and uses a non-amortization approach to purchased goodwill and other indefinite-lived intangible assets. Under SFAS 142, effective for fiscal years beginning after December 15, 2001, goodwill and intangible assets deemed to have indefinite lives, will no longer be amortized, and will be subject to annual impairment tests. The adoption of these accounting standards did not impact the Company's financial position or results of operations as of June 30, 2002. In 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"), effective for the Company's 2003 fiscal year, which provides guidance on accounting for nuclear plant decommissioning costs. SFAS 143 prescribes fair value accounting for asset retirement liabilities, including nuclear decommissioning obligations, and requires recognition of such liabilities at the time incurred. The Company has not yet determined what impact, if any, the accounting standard will have on its financial position or results of operations. In 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets" ("SFAS 144"). SFAS 144 specifies accounting and reporting for the impairment or disposal of long-lived assets. The adoption of SFAS 144 did not impact the Company's financial position or results of operations as of June 30, 2002. 7. COMPUTATION OF EARNINGS PER SHARE Earnings per share are based on the weighted average number of common and common stock equivalent shares outstanding during each year. The Company established a stock incentive plan for all directors and employees during the year ended December 31, 2000, and options granted are exercisable over vesting schedules of between one and four years.
Three months ended Six months ended June 30 June 30 2002 2001 2002 2001 ------ ------ ------ ------ (in thousands) Net income before preferred dividends. . $1,886 $2,969 $5,326 $6,117 Preferred stock dividend requirement . . 11 235 95 469 ------ ------ ------ ------ Net income applicable to common stock. . $1,875 $2,734 $5,231 $5,648 ====== ====== ====== ====== Average number of common shares-basic. . 5,711 5,615 5,701 5,602 Dilutive effect of stock options . . . . 166 162 165 157 Anti-dilutive stock options. . . . . . . - - - - ------ ------ ------ ------ Average number of common shares-diluted. 5,877 5,777 5,866 5,759 ====== ====== ====== ======
GREEN MOUNTAIN POWER CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS JUNE 30, 2002 PART I-ITEM 2 In this section, we explain the general financial condition and the results of operations for Green Mountain Power Corporation (the "Company") and its subsidiaries. This includes: Factors that affect our business; Our earnings and costs in the periods presented and why they changed between periods; The source of our earnings; Our expenditures for capital projects year-to-date and what we expect they will be in the future; Where we expect to get cash for future capital expenditures; and How all of the above affects our overall financial condition. Management believes the most critical accounting policies include the regulatory accounting framework within which we operate and the manner in which we account for certain power supply arrangements that qualify as derivatives. These accounting policies, among others, affect the Company's more significant judgments and estimates used in the preparation of its consolidated financial statements, including estimates and judgments used in determining the current period recognition of revenues deferred in 2001, as discussed further under the caption "Operating Revenues and MWh Sales-Revenues", in this section. As you read this section it may be helpful to refer to the consolidated financial statements and notes in Part I-Item 1. There are statements in this section that contain projections or estimates and are considered to be "forward-looking" as defined by the Securities and Exchange Commission. In these statements, you may find words such as "believes," "estimates", "expects," "plans," or similar words. These statements are not guarantees of our future performance. There are risks, uncertainties and other factors that could cause actual results to be materially different from those projected. Some of the reasons the results may be different are listed below and are discussed under "Competition and Restructuring" in this section: Regulatory and judicial decisions or legislation; Weather; Energy supply and demand and pricing; Availability, terms, and use of capital; General economic and business risk; Nuclear and environmental issues; Changes in technology; and Industry restructuring and cost recovery (including stranded costs). These forward-looking statements represent only our estimates and assumptions as of the date of this report. RESULTS OF OPERATIONS EARNINGS SUMMARY - OVERVIEW In this section, we discuss our earnings and the principal factors affecting them. We separately discuss earnings for the utility business and for our unregulated businesses.
Total basic earnings per share of Common Stock* Three months ended Six months ended June 30 June 30 2002 2001 2002 2001 ----- ------- ----- ------- Utility business . . . . $0.31 $ 0.51 $0.89 $ 0.99 Unregulated businesses . 0.02 0.01 0.03 0.05 ----- ------- ----- ------- Earnings from: Continuing operations. . 0.33 0.52 0.92 1.04 Discontinued segment . . - (0.03) - (0.03) ----- ------- ----- ------- Basic earnings per share $0.33 $ 0.49 $0.92 $ 1.01 ===== ======= ===== =======
*The three and six months ended June 30, 2002 include recognition of $2.1 million and $4.2 million of deferred revenues, respectively UTILITY BUSINESS The Company recorded basic earnings per share from utility operations of $0.31 in the quarter ended June 30, 2002, compared with utility earnings of $0.51 per share in the second quarter of 2001. Earnings declined as a result of increased power supply costs during the second quarter of 2002, compared with the same quarter of 2001. Power supply costs rose as a result of increased costs under our power supply agreement with Morgan Stanley, capacity cost increases at the Vermont Yankee nuclear plant and reimbursement of approximately $1.0 million received in 2001 for power supply costs incurred during previous periods. The increases in power supply costs in the second quarter of 2002 were partially offset by a reduction in costs arising from decreased sales of electricity to wholesale customers. Retail operating revenues increased by $2.7 million during the second quarter of 2002, compared with the same quarter of 2001, primarily due to the recognition of $2.1 million in revenues deferred during 2001 in accordance with the settlement of the Company's retail rate case approved by the Vermont Public Service Board in January 2001. Basic earnings per share from utility operations for the six months ended June 30, 2002 were $0.89 compared with basic earnings per share of $0.99 for the same period in 2001, due to the same factors influencing second quarter results. UNREGULATED BUSINESSES Earnings from unregulated businesses included in results from continuing operations for the three months ended June 30, 2002 were lower than during the same period in 2001. A financial summary for these businesses follows:
Three Months Ended Six Months Ended June 30 June 30 2002 2001 2002 2001 ------------- ----- ----- ----- In thousands Revenue. . $ 253 $ 251 $ 502 $ 510 Expense. . 150 131 $ 316 256 ------------- ----- ----- ----- Net Income $ 103 $ 120 $ 186 $ 254 ============= ===== ===== =====
OPERATING REVENUES AND MWH SALES Our revenues from operations, megawatthour ("MWh") sales and average number of customers for the three and six months ended June 30, 2002 and 2001 are summarized below:
Three months ended Six months ended June 30 June 30 2002 2001 2002 2001 -------- ---------- ---------- ---------- (dollars in thousands) Operating revenues Retail. . . . . . . . $ 48,256 $ 45,586 $ 100,745 $ 97,539 Sales for Resale. . . 16,092 20,760 31,901 42,598 Other . . . . . . . . 787 1,126 1,355 2,131 -------- ---------- ---------- ---------- Total Operating Revenues. $ 65,135 $ 67,472 $ 134,001 $ 142,268 ======== ========== ========== ========== MWh sales-Retail. . . . . 457,128 459,144 952,622 977,405 MWh sales for Resale. . . 517,937 545,288 1,036,224 1,183,384 -------- ---------- ---------- ---------- Total MWh Sales . . . . . 975,065 1,004,432 1,988,846 2,160,789 ======== ========== ========== ==========
Average Number of Customers Three months ended Six months ended June 30 June 30 2002 2001 2002 2001 ------ ------ ------ ------ Residential . . . . . . . 73,730 73,075 73,831 73,112 Commercial and Industrial 13,104 12,998 13,076 12,966 Other . . . . . . . . . . 64 66 65 66 ------ ------ ------ ------ Total Number of Customers. . 86,898 86,139 86,972 86,143 ====== ====== ====== ======
REVENUES Total revenues from operations in the second quarter of 2002 decreased $2.3 million or 3.5 percent compared with the same period in 2001. Operating revenues result from retail and wholesale sales of electricity. Retail revenues in the second quarter of 2002 were $2.7 million or 5.9 percent higher compared with the same period in 2001, primarily as a result of the recognition of $2.1 million of revenues deferred during 2001 under a settlement order in the Company's retail rate filing that was approved by the Vermont Public Service Board in January 2001. Total retail MWh sales of electricity in the second quarter of 2002 decreased by 0.4 percent from the same quarter of 2001, reflecting a decrease in sales to industrial customers of 5.5 percent that was substantially offset by increased sales of 3.4 percent to small commercial and industrial customers and 1.5 percent to residential customers. Retail revenues for the six months ended June 30, 2002 were $3.2 million or 3.3 percent higher when compared with the same period in 2001, reflecting the recognition of $4.3 million of deferred revenues, partially offset by decreased retail MWh sales of approximately 2.5 percent due to warmer than normal winter temperatures and a softening economy in 2002. The Company currently estimates that its earnings for 2002 will approximate its allowed rate of return of 11.25% percent, and that it will recognize the remaining balance of $4.2 million of deferred revenues during 2002. We sell wholesale electricity to others for resale. Our revenue from wholesale MWh sales of electricity decreased $4.7 million or 22.5 percent in the second quarter of 2002 compared with the same period in 2001. The decrease was due primarily to decreased sales under various arrangements with Hydro-Quebec. OPERATING EXPENSES POWER SUPPLY EXPENSES Power supply expenses increased 1.4 percent or $0.6 million in the second quarter of 2002 over the same period in 2001, as a result of increased costs under our power supply agreement with Morgan Stanley, capacity cost increases at the Vermont Yankee nuclear plant and reimbursement of approximately $1.0 million received in 2001 for power supply costs incurred during previous periods. The increases in power supply costs in the second quarter of 2002 were partially offset by a reduction in costs arising from decreased sales of electricity to wholesale customers. Power supply expenses at Vermont Yankee increased 42.8 percent or $2.5 million during the second quarter of 2002 compared with the second quarter of 2001, due to the deferral of maintenance and repair costs associated with a scheduled refueling outage in 2001. The sale of the VY generating plant is discussed under Part I, Item 2, "Investment in Associated Companies". Company-owned generation expenses increased $0.7 million in the second quarter of 2002 compared with the same period in 2001 primarily due to a 2001 reimbursement of fuel costs expended in periods prior to 2001 to support system reliability. The Company received reimbursement of its costs of running its generating units for system reliability from the Independent System Operator of New England ("ISO") during the second quarter of 2001. The cost of power that we purchased from other companies decreased 6.4 percent or $2.6 million in the second quarter of 2002 compared with the same period in 2001. This was primarily due to a $4.7 million reduction in wholesale electric revenues, and decreased expenses under the 9701 arrangement with Hydro-Quebec, pursuant to which Hydro-Quebec has the right to purchase electricity from the Company at rates below current market prices. These decreases were partially offset by higher power supply costs under both the MS contract and small power producer contracts. See the discussion under "Commitments and Contingencies-Power Contract Commitments" for more detail regarding the 9701 arrangement and the MS contract, including the recent renegotiation of the MS contract. The 9701 arrangement allows Hydro-Quebec to exercise an option to purchase power from the Company at energy prices based on a 1987 contract. During the second quarter of 2002, $0.8 million in power supply expense was recognized to reflect the costs of option A, which are recognized ratably over the year. During the second quarter of 2001, $1.6 million in power supply expense was recognized to reflect the costs of options A and B. Hydro-Quebec has previously agreed not to call option B during the 2002 contract year. The cumulative amount of power purchased to date by Hydro-Quebec under option B is approximately 432,000 MWh out of a total of 600,000 MWh which may be called over the life of the of the arrangement. Power supply expenses for the first half of 2002 decreased 6.6 percent or $6.6 million compared with the first half of 2001, primarily due to a reduction in low margin wholesale purchases and lower retail sales of electricity. Power supply expense at Vermont Yankee increased $2.4 million or 17.3 percent for the first half of 2002 compared with the first half of 2001, primarily due to the deferral of maintenance and repair costs associated with a scheduled refueling outage in 2001. Vermont Yankee scheduled outage costs are deferred and amortized over an eighteen-month refueling cycle. Company-owned generation expenses decreased $0.7 million or 29.7 percent in the first half of 2002 compared with the same period in 2001, primarily due to lower fuel costs and reduced need to run peak generation facilities for system reliability. During 2001, the Company recorded a reduction of generation expense of approximately $1.9 million for its costs of running peak generation facilities for system reliability and we received reimbursement of these amounts from the ISO in July 2001. This reduction was partially offset by increased generation expense in the first quarter of 2001 caused by higher fuel costs. Purchased power expense decreased $8.4 million or 9.9 percent in the first half of 2002 compared with the first half of 2001, primarily due to a $10.7 million decrease in wholesale electric revenues, decreased expenses under the 9701 arrangement with Hydro-Quebec and reductions in retail MWh sales of electricity. Both the 9701 arrangement and any related forward purchase contracts are considered derivative instruments as defined by SFAS 133. On April 11, 2001, the VPSB issued an accounting order that allows the Company to defer recognition of any earnings or other comprehensive income effect relating to future periods caused by application of SFAS 133, and as a result, we do not anticipate SFAS 133 to cause earnings volatility. At June 30, 2002, the Company had a regulatory asset of approximately $33.7 million related to derivatives that the Company believes is probable of recovery. The regulatory asset is based on current estimates of future market prices that are likely to change by material amounts. The cost of power purchased from MS for 2003 is expected to be approximately $6.0 million less than the cost of power purchased from MS during 2002. The remainder of our load requirements are substantially provided through our power supply contracts and arrangements with Hydro-Quebec and our entitlements to power generated at the Vermont Yankee nuclear plant now owned by Entergy. OTHER OPERATING EXPENSES Other operating expenses decreased 19.4 percent or $0.8 million in the second quarter of 2002 compared with the same period in 2001, as a result of increased reserves for medical benefits and vendor claims expensed in 2001. Other operating expenses decreased 9.3 percent or $0.7 million in the first six months of 2002 compared with the same period in 2001 for the same reasons. TRANSMISSION EXPENSES Transmission expenses increased by approximately $0.5 million or 12.9% for the three months ended June 30, 2002 compared with the same period in 2001. The Company's relative share of transmission costs varies with the peak demand recorded on Vermont's transmission system. The Company's share of those costs has increased due to its increased load growth, relative to other Vermont utilities, experienced during the previous twelve months. Transmission expenses increased by approximately $0.9 million or 13.8 percent for the six months ended June 30, 2002, compared with the same period in 2001 for the same reasons mentioned in the three month comparison. Congestion charges recorded in the first six months of 2002 and 2001 reflect the lack of adequate transmission or generation capacity in certain locations within New England, and these charges are allocated to all ISO New England members. Congestion charges recorded in the first quarter of 2001 reflect the lack of adequate transmission or generation capacity in certain locations within New England, and these charges are allocated to all ISO New England members. A system of locational pricing is likely to be adopted by ISO New England, as early as January 2003. Currently, it is expected that the Vermont zone will be set at state boundaries. The intent of locational pricing is to encourage generation and transmission solutions in areas experiencing constraints (congestion). The Company is unable to predict the magnitude or duration of future congestion charge allocations, but amounts could be material. MAINTENANCE EXPENSES Maintenance expenses were substantially unchanged during the second quarter of 2002 compared with the same period in 2001. Maintenance expenses increased by approximately $0.7 million or 20.9% during the first half of 2002 compared with the same period in 2001, primarily due to the costs of repair from a series of minor storms in 2002 and increases in maintenance costs at our wind generation facility located in Searsburg, Vermont. DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization expenses decreased $0.2 million or 6.0 percent during the second quarter of 2002 compared with the same period in 2001 primarily due to decreased amortization of demand side management assets. Depreciation and amortization expenses decreased $0.4 million or 5.1 percent during the first six months of 2002 compared with the same period in 2001 for the same reason. TAXES OTHER THAN INCOME TAXES Other taxes expense for the second quarter and the first six months of 2002 were essentially unchanged compared with the same respective periods in 2001. INCOME TAXES Income taxes decreased $0.9 million in the second quarter of 2002 compared with the same period in 2001 due to a decrease in pretax book income for core electric operations. Income taxes decreased $0.7 million for the first six months of 2002 compared with the same period in 2001 for the same reason. OTHER INCOME Other income for the three and six months ended June 30, 2002 was essentially unchanged from the same period in 2001. INTEREST CHARGES Interest charges decreased $0.2 million or 12.2 percent in the second quarter of 2002 compared with the same period in 2001 primarily due to the redemption of first mortgage bonds in December 2001 and May 2002, partially offset by increased short-term borrowings and related interest costs. Interest charges decreased $0.6 million or 17.2 percent in the first half of 2002 compared with the same period in 2001 for the same reasons. LIQUIDITY AND CAPITAL RESOURCES In the six months ended June 30, 2002, we spent $9.3 million principally for expansion and improvements of our transmission, distribution and generation plant. We expect to spend approximately $10.4 million during the remainder of 2002. The Company renegotiated a 364-day revolving credit agreement with Fleet Financial Services ("Fleet") joined by KeyBank National Association, ("KeyBank") with the renegotiated agreement expiring June 18, 2003 (the "Fleet-Key Agreement"). The Fleet-Key Agreement is for $35.0 million, unsecured, and allows the Company to choose either a daily variable prime rate, or a fixed term LIBOR-based rate. There was $10.4 million outstanding with an interest rate of 4.75 percent on the Fleet-Key Agreement at June 30, 2002. There was no non-utility short-term debt outstanding at June 30, 2002. On July 27, 2001, the VPSB approved a $12.0 million two-year unsecured loan agreement, with Fleet, joined by KeyBank, and the loan was made to the Company on August 24, 2001. At June 30, 2002, there was $12.0 million outstanding under the two-year loan agreement. On June 21, 2002, the Company paid $1.0 million to redeem the remaining 7.32 percent Class E preferred stock outstanding. In August 2002, the Company submitted a request to the Vermont Public Service Board to approve an issuance of first mortgage bonds sufficient to retire the Company's short and intermediate term debt. The credit ratings of the Company's securities at June 30, 2002 are:
Fitch Moody's Standard & Poor's ----- ------- ----------------- First mortgage bonds BBB Baa2 BBB Preferred stock. . . BBB- Ba2 BB
The following table presents payments contractually due by category:
In thousands Contractual Obligations Less at June 30, 2002 than 1 1-3 4-5 After Total year years years 5 years -------- ------- -------- -------- -------- Long-term Debt. . . . . . . . . . . $ 79,000 $ 8,000 $ 20,000 $ 14,000 $ 37,000 Revolving Credit. . . . . . . . . . 10,400 10,400 - Interest on Long Term Debt. . . . . 60,013 5,123 8,208 6,681 40,001 Capital Lease . . . . . . . . . . . 5,959 426 852 852 3,829 Preferred Stock . . . . . . . . . . 235 150 60 25 Hydro-Quebec power supply contracts 691,343 47,977 96,360 100,836 446,170 MS power supply contract. . . . . . 18,874 13,744 5,130 - - - Total Contractual Cash Obligations. $865,823 $85,819 $130,610 $122,394 $527,000 ======== ======= ======== ======== ========
FUTURE OUTLOOK COMPETITION AND RESTRUCTURING-The electric utility business continues to experience rapid and substantial changes. These changes are the result of the following trends: disparity in electric rates, transmission, and generating capacity among and within various regions of the country; improvements in generation efficiency; increasing demand for customer choice; consolidation through business combinations; new regulations and legislation intended to foster competition, also known as restructuring; and increasing volatility of wholesale market prices for electricity. We are unable to predict what form future restructuring legislation, if adopted, will take and what impact that might have on the Company, but it could be material. During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated inquiries and legal procedures to establish its own electric utility, seeking to purchase an existing hydro-generation facility from a third party, and the associated distribution plant owned by the Company within Rockingham. In March 2002, voters in Rockingham authorized Rockingham to create a municipal utility by acquiring a municipal plant, which would include the Bellows Falls hydroelectric facility and the electric distribution systems of the Company and/or Central Vermont Public Service Corporation. The Company receives annual revenues of approximately $4.0 million from its customers in Rockingham. Should Rockingham create a municipal system, the Company would vigorously pursue its right to receive just compensation from Rockingham. Such compensation would include full reimbursement for Company assets, if acquired, and full reimbursement of any other costs associated with the loss of customers in Rockingham, to assure that our remaining customers do not subsidize a Rockingham municipal utility. NEW ACCOUNTING STANDARDS See Part I-Item 1, Note 6, "New Accounting Standards" for more information on the adoption of new accounting standards and the impact, or lack thereof, on the Company's financial position and operating results. EFFECTS OF INFLATION Financial statements are prepared in accordance with generally accepted accounting principles and report operating results in terms of historic costs. This accounting provides reasonable financial statements but does not always take inflation into consideration. As rate recovery is based on these historical costs and known and measurable changes, the Company is able to receive some rate relief for inflation. It does not receive immediate rate recovery relating to fixed costs associated with Company assets. Such fixed costs are recovered based on historic figures. Any effects of inflation on plant costs are generally offset by the fact that these assets are financed through long-term debt. MARKET RISK A sensitivity analysis has been prepared to estimate the exposure to the market price risk of our electricity commodity positions. Assumptions used in the Blacks-Scholes model include a risk free rate of 5.02 percent, locked in forward commitment prices for 2002 and 2003, a forward market price averaging approximately $60 per MWh for periods beyond 2003 with an average of approximately 60,000 MWh per year. Under an accounting order issued by the VPSB, changes in the fair value of derivatives are not recognized in earnings until the derivative positions are settled. Our daily net commodity position consists of purchased electric capacity. The table below presents market risk, estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in prices. Actual prices may differ materially from the table.
Commodity Price Risk At June 30, 2002 Fair Value Market Risk --------------- ------------ (in thousands) Net short position $ 33,694 $ 2,341
GREEN MOUNTAIN POWER CORPORATION -------------------------------- JUNE 30,2002 ------------ PART II - OTHER INFORMATION --------------------------- ITEM 1. Legal Proceedings See Notes 3, 4 and 5 of Notes to Consolidated Financial Statements ITEM 2. Changes in Securities NONE ITEM 3. Defaults Upon Senior Securities NONE ITEM 4. Submission of Matters to a Vote of Security Holders At the Annual Shareholders Meeting held May 16, 2002, one item was voted upon by Shareholders. Shareholders elected the nominees listed below as Directors of the Company, with votes cast as indicated. Elizabeth A. Bankowski, votes for, 4,834,640; withheld authority, 174,615; abstentions, 683,412. William H. Bruett, votes for, 4,955,998; withheld authority, 53,257; abstentions, 683,412. David R. Coates, votes for, 4,953,316; withheld authority, 55,939; abstentions, 683,412. Directors continuing in office were Nordahl L. Brue, Merrill O. Burns, Lorraine E. Chickering, John V. Cleary, Christopher L. Dutton, and Euclid A. Irving. Thomas P. Salmon retired as Director and Chairman of the Board at the conclusion of the Annual Shareholders Meeting. ITEM 5. Other Information NONE ITEM 6. (A) EXHIBITS ---------- Exhibit 10-b-90 Purchase Power Agreement between Entergy Nuclear Vermont Yankee LLC and Vermont Yankee Nuclear Power Corporation is attached and incorporated by reference herein. Exhibit 10-b-91 First Amendment to Purchase Power Agreement, Exhibit 10-b-90 is attached and incorporated by reference herein. (B) REPORTS ON FORM 8-K --------------- The following filings on Form 8-K were filed by the Company on the topics and dates indicated: May 16, 2002 Form 8-K announced the election of Nordahl Brue as Chairman of the Board of Directors of the Company, replacing the retiring Thomas P. Salmon. June 27, 2002 Form 8-K announced the dismissal of Arthur Andersen as the Company's independent public accountants, with no disagreements cited. July 17, 2002 Form 8-K announced the engagement of Deloitte & Touche LLP as the Company's independent certifying public accountants. July 31, 2002 Form 8-K announced the completion of the sale of Vermont Yankee's nuclear generating plant to Entergy. GREEN MOUNTAIN POWER CORPORATION -------------------------------- 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. GREEN MOUNTAIN POWER CORPORATION --------------------------------------- (Registrant) Date: August 14, 2002 /s/Christopher L. Dutton -------------------------- Christopher L. Dutton, Chief Executive Officer and President Date: August 14, 2002 /s/Robert J. Griffin ---------------------- Robert J. Griffin, (as Principal Financial Officer) Controller and Treasurer EX-10.B.90 3 doc2.txt PURCHASE POWER AGREEMENT WITH ENTERGY 28 10Qdraft.doc -- SEC EXHIBIT 10.B.90 Exhibit B to 2001 Amendatory Agreement POWER PURCHASE AGREEMENT BETWEEN ENTERGY NUCLEAR VERMONT YANKEE, LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION POWER PURCHASE AGREEMENT This POWER PURCHASE AGREEMENT entered into this 6th day of September, 2001, by and between Entergy Nuclear Vermont Yankee, LLC, a Delaware limited liability company having a principal place of business at 440 Hamilton Avenue, White Plains, NY 10601 (hereinafter referred to as "Seller"), and Vermont Yankee Nuclear Power Corporation, a Vermont corporation having its principal place of business at 185 Old Ferry Road, Brattleboro, Vermont 05301, (hereinafter referred to as "Vermont Yankee" or "Company"). WHEREAS, concurrently with the execution of this Agreement, Seller and Vermont Yankee are entering into a Purchase and Sale Agreement (the "P&S Agreement") of even date herewith, under which Vermont Yankee agrees to sell and Seller agrees to purchase, on the terms and subject to the conditions set forth therein, the Vermont Yankee Nuclear Power Plant, as described therein (the "Facility"), and certain related assets, and to assume certain liabilities and obligations; and WHEREAS, the consummation of the purchase of the Facility under the P&S Agreement (the "Closing") is subject to, among other things, the execution, delivery and effectiveness of this Agreement between Seller and Vermont Yankee, NOW THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the Parties agree as follows: CONDITION PRECEDENT It is a condition precedent to the obligations of Seller and Vermont Yankee under the P&S Agreement that the Closing shall have occurred and that all regulatory approvals required for this Agreement's initial effectiveness shall have been obtained. The Parties have agreed in the P&S Agreement to use Commercially Reasonable Efforts (as defined in the P&S Agreement) to obtain all such regulatory approvals. DEFINITIONS When used with initial capitalization, whether in the singular or the plural, the following terms shall have the meanings set forth below. "Agreement": This document, including its appendices, as amended from time to --------- time. "Actual Monthly Energy": The total amount of Energy produced at the Facility ----------------------- that is reported by Seller to ISO-NE for the calendar month being billed. - "Adjustment Factor": Defined in Article 8(b). ------------------ "Affiliate": Has the meaning set forth in Rule 12b-2 of the General Rules and --------- Regulations under the Securities Exchange Act of 1934, as amended. "Base Price": The purchase price expressed in $/Mwh as set forth in Schedule D ----------- for the applicable month. "Billing Date": Each date on which the Seller renders a bill to Vermont Yankee ------------- pursuant to Article 7(c). "Business Day": Means any day other than Saturday, Sunday and any day on which ------------- banking institutions in the State of Vermont are authorized by law or other governmental action to close. "Capability Audit": The procedure used pursuant to the NEPOOL Agreement to ----------------- determine the Summer Net Capability and the Winter Net Capability of the --- Facility as currently set forth in the NEPOOL standards. --- "Closing Date": Has the meaning defined in the P&S Agreement. ------------- "Company's Entitlement": The percentage entitlement of the Facility Product ---------------------- allocated to the Company pursuant to this Agreement, which is equal to the sum -- of the Sub-Entitlements and, when applicable, as adjusted pursuant to Article 8(b) for Uprates. "Energy": The actual hourly electricity production of the Facility reduced for ------ Station Service Use, transformer losses and generator lead losses, where such electric energy is delivered at the Delivery Point in the form of 3-phase, 60 cycle, alternating current at a nominal voltage of 345,000 volts. "Delivery Point": The point which is the Facility's interconnection with NEPOOL -------------- PTF and which is designated as the "Producer Delivery Point", as indicated on the diagram attached hereto as Schedule A. "Delivery Term": Has the meaning set forth in Article 4(a). -------------- "Facility": The Vermont Yankee Nuclear Power Station, a 540 MW nuclear powered -------- generating unit located in Vernon, Vermont. "Facility Product": The Energy, Installed Capability and all other associated ----------------- ancillary services and NEPOOL products, including without limitation, reactive power, for which a NEPOOL market exists or is established and in operation during the term of this Agreement, actually produced by, or available from, the Facility in any hour. "FERC": The Federal Energy Regulatory Commission, and any successor thereto. ---- "Good Utility Practices": Means any of the practices, methods and activities ------------------------ approved by a significant portion of the electric utility industry in the United - States as good practices applicable to nuclear generating facilities of similar design, size and capacity during the relevant time period or any of the practices, methods or activities which, in the exercise of reasonable judgment by a prudent nuclear operator in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, expedition and applicable law and assuring safety and protection of the public. Good Utility Practices are not intended to be limited to the optimal practices, methods or acts to the exclusion of all others, but rather to be practices, methods or acts generally accepted in the electric utility industry. "Installed Capability": The Winter Net Capability during the Winter Period and --------------------- the Summer Net Capability during the Summer Period. "ISO-NE": The Independent System Operator of New England provided for in the ------ NEPOOL Agreement, or its successor. - "Market Price" As of a Billing Date, the sum of (a) the actual average hourly ------------- NEPOOL spot clearing price for electric energy for all hours of the 12 month period immediately prior to such Billing Date as published by ISO-NE on its website (www.iso-ne.com) (or some other ISO-NE source mutually acceptable to Vermont Yankee and Seller) plus (b) the actual clearing price for Installed Capability for all hours of the 12 month period (or such shorter period as may be practicable if such price is not published for a full 12 month period at the time of calculation) immediately prior to such Billing Date as published by ISO-NE, stated is $/MWh. In the event there is no clearing price for Installed Capability, the Market Price shall be the product of (x) the amount set forth in clause (a) of the preceding sentence and (y) 110%. In all cases, if NEPOOL and/or ISO-NE implement a two settlement system for the energy market, the hourly NEPOOL spot clearing price for electric energy will be replaced by the clearing price for electric energy in the Day-Ahead Market Settlement, as defined in the NEPOOL Agreement, if a Day-Ahead Market Settlement exists; otherwise, it will be the Real-Time Clearing Price for electric energy in the Real-Time Market, both as defined in the Restated NEPOOL Agreement, if a Day-Ahead Market Settlement does not exist. If NEPOOL and/or ISO-NE implements a Congestion Management System, the hourly NEPOOL spot clearing price for electric energy will be replaced by Nodal Energy Prices in NEPOOL applicable to the Facility. "Maximum Monthly Amount": The monthly amounts set forth on Schedule B. ------------------------ "Monthly NEPOOL Clearing Price": The average hourly NEPOOL spot clearing price ------------------------------ for electric energy for a given month as published by ISO-NE in accordance with NEPOOL Standards. "NEPOOL": The New England Power Pool, established by the NEPOOL Agreement, or ------ its successor. "NEPOOL Agreement": The agreement establishing NEPOOL, dated September 1, 1971, ---------------- as amended by the Restated NEPOOL Agreement filed with FERC on December 31, 1996, as finally approved by FERC and as further amended and restated from time to time. "NEPOOL Standards": All rules and regulations of NEPOOL or ISO-NE, including ----------------- without limitation all Criteria, Rules and Standards (CRS), NEPOOL Automated - Billing System Procedures (NABS), Operating Procedures (OP), and Market Rules - (MR) issued or adopted by NEPOOL, ISO-NE and its satellite agencies, or their - successors, in each case as amended from time to time and all successor - regulations, rules and standards. - "NRC": The Nuclear Regulatory Commission, and any successor thereto. --- "Party: Seller or Company and its respective successors or assigns. ----- "PTF" or"Pool Transmission Facilities": Have the meaning set forth in the --------------------------------------- NEPOOL Agreement. ---- "RFO 25": The refueling outage number RFO 25 for the Facility currently ------- scheduled to commence in October 2005, including the refueling of the Facility ------ and the performance of certain maintenance, inspection and other work in connection therewith. "Reconciliation Factor": Defined in Article 7(b). ---------------------- "Sub-Entitlement": The percentage entitlement allocated to each Sub-Purchaser --------------- of the Facility Product as set forth in Schedule C. "Sub-Purchasers": Collectively, the entities listed in Schedule C that are -------------- purchasing a portion of the Company Entitlement from Vermont Yankee, and --- "Sub-Purchaser" shall mean, individually, each such entity listed in Schedule C. --- "Station Service Use": All of the Energy and other Facility Product recognized -------------------- by NEPOOL used on-site to operate the Facility, including cooling tower operations. "Summer Net Capability (Capability)": The Maximum Claimed Capability, as ------------------------------------- defined in NEPOOL Market Rules and Procedures, Section 11, of the Facility ----- during the Summer Period, expressed in kilowatts, and as determined by ---- Capability Audit, exclusive of the capacity required for Station Service Use. ---- "Summer Period" shall have the meaning set forth in the NEPOOL Market Rules and -------------- Procedures, Section 11. "Uprate": Has the meaning set forth in Article 8(a). ------ "Winter Net Capability (Capability)": The Maximum Claimed Capability, as ------------------------------------- defined in NEPOOL Market Rules and Procedures, Section 11, of the Facility ----- during the Winter Period, expressed in kilowatts, and as determined by ---- Capability Audit, exclusive of the capacity required for Station Service Use. ---- "Winter Period" shall have the meaning set forth in the NEPOOL Market Rules and -------------- Procedures, Section 11. Purchase and Sale of Facility Product; Sub-Entitlements; Maintenance and Capability Audits Seller agrees to sell and to deliver and Company agrees to purchase, and to accept delivery of, Company's Entitlement at the Delivery Point during the Delivery Term, for resale to the Sub-Purchasers. Title to and risk of loss with regard to the Facility Product to be purchased by the Company hereunder shall transfer from Seller to the Company at the Delivery Point. Seller shall be responsible for any costs or charges imposed on or associated with the Product or its delivery of the Product up to the Delivery Point. Company shall be responsible for any costs or charges imposed on or associated with the Product or its receipt at and from the Delivery Point. Seller shall have the right to sell to third parties any portion of the Facility Product not included in Company's Entitlement. Seller shall use Good Utility Practices in all aspects of the management and ----------------------- operation of the Facility. Seller shall use commercially reasonable efforts to maintain the Facility's Installed Capability at the level demonstrated by the most recent Capability Audit as of the date of the P&S Agreement and use its commercially reasonable efforts to make Facility Product available to Company on an ongoing basis, it being understood that Seller shall not be required to contract for, or make arrangements to obtain, Facility Product or any other product from any source other than the Facility in order to fulfill its obligations hereunder, and, subject to the foregoing, shall not be liable for any damages if Facility Product is not available; provided, however, that if applicable NEPOOL Standards or, in Seller's reasonable judgment, the physical operation of the Facility requires Seller to withhold from Vermont Yankee a specific quantity of ancillary services or Energy, then Seller may withhold such amount of those products at no cost and will provide the remaining amounts to Vermont Yankee and provided that at no time will Seller be required by this Agreement to change the Facility's operation, to operate the Facility beyond its normal rated capabilities, or change the Mwh output in order to provide ancillary services. If for any reason Seller does not generate power at the Facility, Seller has no obligation to sell or deliver to Vermont Yankee the Company's Entitlement or to obtain replacement power. Periodically after the Closing Date, Seller shall undergo Capability Audits pursuant to NEPOOL Standards to demonstrate and audit the Summer Net Capability and/or the Winter Net Capability of the Facility. The Capability Audit shall be performed pursuant to NEPOOL Standards or standards mutually agreed to by the Parties if NEPOOL ceases to establish such standards. Seller agrees to provide to Company the results of the demonstrations and audits (NX-17s and supporting material). Prior to making an Uprate as provided in Article 8(a), Seller agrees that it will cause the Facility to be operated within the current configuration of the Facility and the thermal limitations of 1593 megawatts thermal that is currently applicable to the Facility under its NRC Operating License. Seller shall schedule maintenance activities in accordance with NEPOOL Standards, ISO-NE requirements and the requirements of any other entity with authority over the Facility's maintenance. In order to allow the Company and the Sub-Purchasers or their assignees ample time to make alternative arrangements, as soon as practically possible, Seller shall provide, by telephone or telecopy to Company's designated agent, advance notice of planned maintenance activities, planned outages, unplanned outages or any other event that reasonably could be expected to affect output of Facility Product, to reduce the Facility's capacity or to result in any downrating and to the extent reasonably practicable shall coordinate such events with the Company and the Sub-Purchasers or their assignees. Company shall reimburse Seller for transmission charges, if any, as assessed by the ISO-NE, NEPOOL or Vermont Electric Power Company, Inc. for the transmission of Energy from the Delivery Point to the Company Delivery Point, as those points are indicated on Schedule A. ----------- Term, Regulatory Approvals, Early Termination The obligations of the Parties under this Agreement shall commence with the first hour of the day that is the Closing Date and, subject to the termination provisions set forth in this Agreement, shall continue through 2400 Eastern Standard Time or Eastern Daylight Savings Time, as applicable, on March 21, 2012 (the "Delivery Term"). Provisions of this Agreement shall remain in effect after termination hereof to the extent necessary or appropriate to give full effect thereto, including Article 9 and provisions necessary to provide for final billings, billing adjustments, and payments. Notwithstanding any provision hereof to the contrary, Seller may permanently retire the Facility upon six (6) months prior written notice to Company (unless notice of that duration is not commercially feasible under the circumstances, in which case Seller shall give such notice as is commercially feasible under the circumstances). This agreement will terminate at the time specified in such notice, subject to the last sentence of clause (a) above. Company has the option to negotiate with Seller for a mutually agreeable release from all or part of the Company's obligations to purchase power hereunder first for an effective date no earlier than February 28, 2005 and again for any remaining balance effective no earlier than December 31, 2007 (each an "Exercise Date") by giving written notice to Seller at least 180 days prior to the applicable Exercise Date, specifying the amount of Energy in portions that correspond to individual Sub-Entitlements it desires to terminate. During such 180 day period, the parties shall negotiate in good faith the terms of such mutually agreeable release. The effectiveness of any release entered into pursuant to this Article 4(c) shall be subject to the receipt by the Company and the Seller of any necessary regulatory approvals, which shall be obtained at each Party's own expense. Purchase Price for Facility Product Company shall pay Seller monthly (on a $/Mwh basis) for the Company's Entitlement a purchase price determined according to the following formula: TMPt = (CEt x BPt x AMEt) + (CPt (CEt x Dt)) where: CEt = Company's Entitlement for the month (t) in percent, as adjusted pursuant to Article VIII. TMPt = Total payment price due in month (t). BPt = The Base Price for the applicable month in $/Mwh. AMEt = The Actual Monthly Energy (up to but not to exceed the Maximum Monthly Amount set forth on Schedule B, as adjusted) in the month (t) expressed in megawatthours. Dt = Actual Monthly Energy for the month (t) in excess of the Maximum Monthly Amount. CPt = Monthly NEPOOL Clearing Price for the month (t). provided, however, that beginning on the first Billing Date after the end of the - ----------------- RFO 25 refueling outage (i.e., approximately October 2005) and on each Billing Date thereafter, if the Market Price as of the end of the month to which the bill to be rendered on such Billing Date relates is less than 95% of the Base Price for such month (as determined by reference to the table in Schedule D hereto), then the Base Price for such month to be used in the above formula shall be adjusted to be an amount equal to such Market Price multiplied by 105% (but the Base Price as adjusted hereby for any month shall not in any event exceed the relevant Base Price for such month set forth in Schedule D hereto). Notwithstanding any future practice of NEPOOL (or any other or successor pooling or market arrangement in the New England region) that may create separate stated prices for Energy, Installed Capability or any other associated ancillary services, including without limitation, reactive power, Vermont Yankee shall not be required to pay charges for such products or services separate from or in addition to the purchase price set forth in Article 5(a) (as from time to time adjusted as provided therein) despite any such future practice. Dispatch Seller shall make the Facility available for dispatch by ISO-NE. Seller, or its agent, shall submit all bids for the Facility to the ISO-NE such that the Facility will be dispatched in all hours in a given month at its full capacity as a self-scheduled unit. Each Party shall comply with all NEPOOL Standards applicable to it. Seller shall promptly submit this Agreement into the ISO-NE market system and shall file all other required forms to ISO-NE with a copy to Company's designated agent. Seller's and Company's respective designated agents shall mutually agree to any revision to the existing ISO-NE NX-12B Forms to be submitted to ISO-NE in accordance with the provisions of the NEPOOL Agreement and NEPOOL Standards. Whenever Company's system or the systems with which it is directly interconnected experience an emergency, as designated by the affected utility, or whenever it is necessary to aid in the restoration of service on the systems with which Company or a Sub-Purchaser is directly or indirectly interconnected, or, whenever requested by ISO-NE, Seller or its designee shall curtail or interrupt the delivery of all or a portion of the production of electricity at the Facility provided such curtailment or interruption shall continue only for as long as reasonably necessary to deal with the emergency. Whenever Seller's Facility experiences an emergency, Seller or its designee shall have the right to curtail or interrupt all or a portion of Seller's obligation hereunder, provided such curtailment or interruption shall continue only for so long as reasonably necessary to deal with the emergency, and provided Seller promptly notifies Company's designated agent of the occurrence of such an emergency. Billing, Meter Reading; Financial Assurance Seller shall deliver Company's Entitlement to the Delivery Point. Seller is responsible for maintaining metering and telemetering equipment at the Facility, as follows. The metering equipment shall be capable of registering and recording instantaneous and time-differentiated electric energy and other related data from the Facility, and shall comply with the requirements of NEPOOL's Standards as may be issued or revised from time to time. The telemetering shall be capable of transmitting such data to such reasonable location(s) specified by Company or its designated agent. The Company represents and warrants that as of the Closing Date the metering and telemetering equipment at the Facility will meet the requirements of this Article 7(a). Each day, Seller shall be required to provide Company's designated agent with hourly-integrated megawatt hour readings for each hour of the previous day. Seller shall record hourly meter readings and log sheets and, upon the request of Company or its designated agent, provide copies of daily meter recordings and log sheets by electronic means with hard copy back up. All metering equipment installed shall be routinely tested in accordance with Good Utility Practices. ------------ --------- Any meter tested and found to register within one-half of one percent (0.5%) of the comparative standard mutually agreed upon by Seller and the Company shall be considered correct and accurate. If at any time, any metering equipment is found to be defective or inaccurate, Seller shall cause such metering equipment to be made accurate or replaced at Seller's expense. Company shall have the right to request meter testing for accuracy at any time with reasonable advance notice. If such testing shows that tested meters are accurate within one-half of one percent (0.5%), then Company shall be responsible for the costs of such testing. If such testing shows a greater discrepancy, then Seller shall be responsible for the costs of such testing. Notwithstanding clause (c) below, in such event, a billing adjustment shall be made by Seller correcting all measurements made by the defective meter for either: (i) the actual period during which inaccurate measurements were made, if such period is determinable to the mutual satisfaction of Company or its designated agent and Seller; or (ii) if such period is not determinable, for a period equal to one-half the time elapsed since the prior test, but in no event greater than six months (the "Reconciliation Factor"). Seller shall submit, by telecopy or other agreeable same day delivery mechanism, an invoice for all applicable Article 5 charges to Company within 10 days after the end of each calendar month, and such invoice shall include the time and date of the meter readings. This invoice shall include such reasonable detail to enable Company to determine the basis for the charges of such month. Seller and Company agree to provide additional information reasonably requested by the other Party as necessary for billing purposes or data verification. Invoices may be rendered on an estimated basis. Each invoice shall be subject to adjustment for any errors in arithmetic, computing, estimating or otherwise. Seller and Company shall include any such invoicing adjustments as promptly as practicable. All payments shown to be due on such invoice, except amounts in dispute, shall be due and payable by wire transfer per instructions on the invoice on or before the later of the twentieth (20th) day of each month, or the tenth (10th) day after receipt by the Company of the invoice or, if such day is not a Business Day, then on the next Business Day (the "Due Date"). Any undisputed amounts unpaid after the Due Date shall bear interest at a rate equal to the Prime Rate (as published in The Wall Street Journal) then in effect on the Due Date, compounded on a monthly basis. Company may dispute all or any part of any invoice by written notification to Seller. All amounts paid by Company which are subsequently determined to have been improperly invoiced by Seller under this Agreement shall be subject to refund with interest at a rate equal to the Prime Rate (as published in The Wall Street Journal) then in effect on the Due Date, compounded on a monthly basis. The Company may, in good faith, dispute the correctness of any invoice or any adjustment to an invoice, rendered under this Agreement or adjust any invoice for any arithmetic or computational error within twelve (12) months of the date the invoice, or adjustment to an invoice, was rendered. In the event an invoice or portion thereof, or any other claim or adjustment arising hereunder, is disputed, payment of the undisputed portion of the invoice shall be required to be made when due, with notice of the objection given to the other party. Any invoice dispute or invoice adjustment shall be in writing and shall state the basis for the dispute or adjustment. Payment of the disputed amount shall not be required until the dispute is resolved. Upon resolution of the dispute, any required payment shall be made within two (2) Business Days of such resolution along with interest accrued at the Prime Rate (as published in The Wall Street Journal), compounded on a monthly basis. Seller shall keep complete and accurate records and meter readings of its operations and shall maintain such data for a period of at least one (1) year after invoice for the final billing is rendered. Company shall have the right at its own expense, upon five (5) business days prior notice, during normal business hours, to examine and inspect all such records and meter readings in so far as may be necessary for the purpose of ascertaining the reasonableness and accuracy of all relevant data, estimates or statements of charges submitted to it hereunder but shall not impair or interfere with the operation of the Facility owned by Seller. If Seller is unable, at its sole discretion, to obtain such comprehensive financial information as is reasonably required to evaluate creditworthiness with respect to Vermont Yankee, including but not limited to, annual reports containing audited consolidated financial statements and other information obtained through the public domain, Vermont Yankee shall upon thirty (30) days written notice deliver such financial information to Seller. Upon the commercially reasonable request of Vermont Yankee, Seller shall use commercially reasonable efforts to protect the confidentiality of the information disclosed hereunder. If Seller has commercially reasonable grounds for insecurity (determined in accordance with commercial standards as used in Section 2-609 of the Vermont Uniform Commercial Code) concerning the ability of one or more of the Sub-Purchasers to pay for its Sub-Entitlement for any billing period, then Seller may provide Vermont Yankee with written notices requesting adequate assurance ("Adequate Assurance") of due performance of the payment obligations of such Sub-Purchaser(s) for the respective portions of the Company's Entitlement. Upon receipt of such notice, Vermont Yankee shall have fifteen (15) Business Days to provide such Adequate Assurance to Seller. Uprating Uprate Power. At any time during the Delivery Term, Seller may notify Vermont - ------------- Yankee in writing that Seller intends to make capital improvements or related adjustments to operating parameters, set points, instruments and procedures to increase the Installed Capability or Energy output of the Facility (an "Uprate"). Such notice shall contain: (i) the estimated increase in Installed Capability, Energy associated with the Uprate (the "Uprate Power"); and (ii) an estimated date by which Seller would be able to begin generating Uprate Power. After providing the notice required by this Article 8(a), Seller will have the right but not the obligation to complete the Uprate. Uprate Calculation. Seller will arrange for a Capability Audit to be conducted - ------------------- before, if necessary, and after the Uprate is completed to determine the actual increase in Installed Capability attributable to the Uprate. Based upon the results of these audits, Seller will reduce the Company Entitlement as follows: The post-Uprate Company Entitlement equals (i) Adjustment Factor times (ii) the pre-Uprate Company Entitlement. Adjustment Factor = (y/x) Where x = Capability Audit results after Uprate, and y = Capability Audit results immediately preceding the Uprate, both being determined in the same season. Entitlement to Uprate Power. The Uprate Power attributable to any Uprate shall - ---------------------------- be calculated as set forth above and shall be Seller's power. Any Uprates shall reduce the Company's Entitlement in the manner and to the extent set forth in Article 8(b). Limitation of Liability; Indemnification; Insurance; Relationship of Parties Notwithstanding clause (b) below or any other provision of this Agreement to the contrary, neither Company nor Seller nor their respective officers, directors, agents, employees, parent, subsidiaries or affiliates or their officers, directors, agents or employees shall be liable or responsible to the other Party or its parent, subsidiaries, affiliates, officers, directors, agents, employees, successors or assigns, or their respective insurers, for incidental, indirect, exemplary, punitive or consequential damages, connected with or resulting from performance or non-performance of this Agreement, or anything done in connection therewith including, without limitation, claims in the nature of lost revenues, income or profits (other than payments expressly required and properly due under this Agreement), and increased expense of, reduction in or loss of power generation production or equipment used therefor, irrespective of whether such claims are based upon breach of warranty, tort (including negligence, whether of Seller, Company or others), strict liability, contract, operation of law or otherwise, but excluding acts of gross negligence or willful misconduct. Each Party (the "Indemnifying Party") shall defend, indemnify and save the other Party (the "Indemnified Party"), its officers, directors, agents, employees and Affiliates and their respective officers, directors, agents and employees harmless from and against any and all claims, liabilities, demands, judgments, losses, costs, expenses (including reasonable attorneys' fees), suits, or damages arising from or out of any event, circumstance, act or incident first occurring or existing during the period when control and title to Facility Product is vested in such Party as provided in Article 3(a). Each Party shall indemnify, defend and hold harmless the other Party against any Governmental Charges for which such Party is responsible under Article 18. Each Party shall maintain appropriate insurance coverage at its sole expense. The rights, obligations and protections afforded by clauses (a) and (b) above shall survive the termination, expiration or cancellation of this Agreement, and shall apply to the full extent permitted by law. Nothing in this Agreement shall be construed as creating any relationship between the Parties other than that of independent contractors for the sale and purchase of Facility Product. Except as set forth herein, there is no warranty of merchantability or fitness for a particular purpose, and any and all implied warranties are disclaimed. Miscellaneous Provisions The Parties hereto agree that time shall be of the essence of this Agreement. This Agreement may not be modified or amended except in writing signed by or on behalf of both Parties by their duly authorized officers, and if applicable, after obtaining any required regulatory approvals. It shall be the responsibility of Seller to take all necessary actions to satisfy any regulatory requirements that may be imposed on Seller by any statute, rule or regulation or FERC - accepted regional agreement concerning the sale of Facility Product to the Company hereunder. Company shall cooperate with Seller and provide information or such other assistance, without cost to Company, as may be reasonably necessary for Seller to satisfy regulatory requirements relating specifically and only to the sale of Facility Product. Seller shall cooperate with Company and provide information or such other assistance, without cost to Seller, as may be reasonably necessary for Company to satisfy regulatory requirements relating specifically and only to the purchase of Facility Product. Notwithstanding clause (c) above, Seller agrees to provide, at no cost to Company, all necessary forms, data, and other information reasonably requested of Company by ISO-NE, NEPOOL, or any governmental or regulatory agency or authority having jurisdiction. The Parties acknowledge and agree that the sales hereunder constitute "forward-contracts" within the meaning of the United States Bankruptcy Code. This Agreement (including the exhibits, schedules and any written supplements hereto), constitutes the entire agreement between the Parties relating to the subject matter. This Agreement shall be considered for all purposes as prepared through the joint efforts of the Parties and shall not be construed against one Party or the other as a result of the preparation, substitution, submission or other event of negotiation, drafting or executing hereof. This Agreement shall not impart any rights enforceable by any third party (other than a permitted successor or assignee bound to this Agreement or the Sub-Purchasers and their assigns). Any provision declared or rendered unlawful by any applicable court of law or regulatory agency or deemed unlawful because of a statutory change or deemed to be not in compliance, with the NEPOOL Agreement the NEPOOL Standards or the ISO-NE Standards, whether because of changes therein or otherwise, including but not limited to a change in the commercial structure of the ISO-NE market from a single pool-wide market clearing price to a system that utilizes a geographic or location pricing differentiation approach, or a move to a multi-settlement approach (i.e. day ahead energy market clearing price, real time or hour ahead energy market clearing price), (individually or collectively, such events referred to as "Regulatory Event") will not otherwise affect the remaining lawful obligations that arise under this Agreement; and provided, further, that if a Regulatory Event occurs, the Parties shall use their commercially reasonable efforts to reform this Agreement in order to give effect to the original intention of the Parties. The term "including" when used in this Agreement shall be by way of example only and shall not be considered in any way to be in limitation. The headings used herein are for convenience and reference purposes only. All indemnity and audit rights shall survive the termination of this Agreement for twelve (12) months. This Agreement shall be binding on each Party's successors and permitted assigns. Assignment Neither Party shall assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent may be withheld in the exercise of its sole discretion; provided, however, Seller may, without the consent of the Vermont Yankee (and without relieving itself from liability hereunder), (i) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements, or (ii) transfer or assign this Agreement to an affiliate of Seller, which affiliate's creditworthiness is equal to or higher than that of Seller, or (iii) transfer or assign this Agreement to an entity which is succeeding to all or substantially all of the assets of Seller; provided, however, that in each such case, Seller shall not be relieved of its obligations hereunder and any such assignee shall agree in writing to be bound by the terms and conditions hereof. Force Majeure If either Party is rendered wholly or partly unable to perform its obligations under this Agreement because of a Force Majeure event, that Party shall be excused from whatever performance is affected by the Force Majeure event to the extent so affected, provided that the non-performing Party shall: (i) provide prompt notice to the other Party of the occurrence of the Force Majeure event giving an estimation of its expected duration and the probable impact on the performance of its obligations hereunder and submitting good and satisfactory evidence of the existence of the Force Majeure event; (ii) exercise all commercially reasonable efforts to continue to perform its obligations hereunder; (iii) expeditiously take commercially reasonable action to correct or cure the Force Majeure event and submit good and satisfactory evidence that it is making all commercially reasonable efforts to correct or cure the Force Majeure event; (iv) exercise all commercially reasonable efforts to mitigate or limit damages to the other Party to the extent such action shall not adversely effect its own interests; and (v) provide prompt notice to the other Party of the cessation of the Force Majeure event; and provided, further, that the Party not claiming Force Majeure shall be excused from performance hereunder for the duration of such Force Majeure event. "Force Majeure" means the failure or imminent threat of failure of facilities or equipment, flood, freeze, earthquake, storm, fire, lighting, other acts of God, epidemic, war, acts of a public enemy, riot, civil disturbance or disobedience, strike, lockout, work stoppages, other industrial disturbance or dispute, sabotage, restraint by court order or other public authority, and action or non-action by, or failure or inability to obtain the necessary authorizations or approvals from, any governmental agency or authority, which by the exercise of due diligence such Party could not reasonably have been expected to avoid and by exercise of due diligence its effect can not be overcome. Nothing contained herein shall be construed so as to require the Parties to settle any strike, lockout, work stoppage or any industrial disturbance or dispute in which it may be involved, or to seek review of or take an appeal from any administrative or judicial action. In no event shall the lack of funds or an inability to obtain funds or any action by governmental authority that disallows, prevents or limits the recovery through rates of all or any portion of the charges imposed by this Agreement be a Force Majeure event. A Force Majeure event shall not be based on (i) the loss of the Company's or any Sub-Purchaser's markets; (ii) the Company's or any Sub-Purchaser's inability to economically use or resell the Facility Product purchased hereunder; or (iii) the Seller's ability to sell the Facility Product at a greater price than that provided hereunder. Default "Event of Default" shall mean, in relation to a Party (the "Defaulting Party"): the failure to make, when due, any payment required pursuant to this Agreement - -------------------------------------------------------------------------------- if such failure is not remedied within three (3) Business Days after written - -------------------------------------------------------------------------------- notice; - ------- any representation or warranty made by such Party herein is false or misleading - -------------------------------------------------------------------------------- in any material respect when made or when deemed made; - --------------------------------------------------------------- the failure by a Party to perform any material covenant or obligation set forth - -------------------------------------------------------------------------------- in this Agreement (except to the extent constituting a separate Event of - -------------------------------------------------------------------------------- Default), if such failure is not remedied within three (3) Business Days after - -------------------------------------------------------------------------------- written notice; - ---------------- such Party becomes Bankrupt; or - ----------------------------------- subject to Article 11(a) such Party consolidates or amalgamates with, or merges - -------------------------------------------------------------------------------- with or into, or transfers all or substantially all of its assets to, another - -------------------------------------------------------------------------------- entity and, at the time of such consolidation, amalgamation, merger or transfer, - -------------------------------------------------------------------------------- the resulting, surviving or transferee entity fails to assume all the - ------------------------------------------------------------------------------- obligations of such Party under this Agreement to which it or its predecessor - -------------------------------------------------------------------------------- was a party by operation of law or pursuant to an agreement reasonably - -------------------------------------------------------------------------------- satisfactory to the other Party. - ------------------------------------ Upon an Event of Default, upon written notice to the Defaulting Party, the Non-Defaulting Party may resort to all remedies available at law or in equity, including, without limitation: (i) the termination of this Agreement; (ii) specific performance of the provisions of this Agreement; (iii) the recovery of actual damages; and/or (iv) the right to suspend performance hereunder; provided, however, in no event shall any such suspension continue for longer than ten (10) Business Days. In the event the Seller seeks damages hereunder, the measure of damages shall be calculated by determining all amounts potentially owing between the Parties, calculating the net present value thereof, and deducting the net present value of the potential resale value of all Facility Product to be delivered hereunder, all calculations to be made in a commercially reasonable basis. In the event the Company seeks damages hereunder, the measure of damages shall be calculated by determining the difference between the net present value of the purchase price for Facility Product to be delivered hereunder calculated pursuant to Article 5 and the net present value of the cost of power required to replace Facility Product to be delivered hereunder. Governing Law, Dispute Resolution The interpretation and performance of this Agreement shall be in accordance with, and controlled by the law, of the State of Vermont, notwithstanding its conflicts of law principles. If any dispute, disagreement, claim or controversy exists between Seller and Company arising out of or relating to this Agreement, such disputed matter shall be submitted to a committee comprised of one designated agent of each Party. Such committee shall be instructed to attempt to resolve the matter within twenty (20) days thereafter. If Company's and Seller's designees do not agree upon a decision within thirty (30) days after the submission of the matter to them, either Party may institute formal legal proceedings. WAIVER The failure of either Party to require compliance with any provision of this Agreement shall not affect that Party's right to later enforce the same. It is agreed that the waiver by either Party of performance of any of the terms of this Agreement, or of any breach thereof or any default hereunder, must be in writing and signed by the Party from whom waiver is sought, and shall not be held or deemed to be a waiver by that Party of any subsequent failure to perform the same, or any other term or condition of this Agreement, or of any breach thereof or any default hereunder. COMPANY REPRESENTATIONS AND WARRANTIES. The Company hereby represents and warrants to the Seller as follows: (a) Organization; Qualification. The Company is a corporation duly organized, validly existing and in good standing under the laws of the State of Vermont and has all requisite corporate power and authority to own, lease, and operate its properties and to carry on its business as is now being conducted. The Company here heretofore made available to the Seller complete and correct copies of its Articles of Association and Bylaws as currently in effect. (b) Authority. The Company has full corporate power and authority to execute and deliver this Agreement and to consummate the transactions contemplated hereby. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly and validly authorized by all necessary corporate action required on the part of the Company and no other corporate proceedings on the part of the Company are necessary to authorize this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by the Company, and assuming that this Agreement constitutes a valid and binding agreement of the Seller and subject to obtaining all necessary regulatory approvals, constitutes the legal, valid, and binding agreement of the Company, enforceable against the Company in accordance with its terms. (c) Consents and Approvals; No Violation. Neither the execution and delivery by the Company of this Agreement nor the consummation of the transactions contemplated hereby or thereby will (i) conflict with or result in the breach or violation of any provision of the Articles of Association or Bylaws of the Company, (ii) violate any constitution, statute, regulation, rule, injunction, judgment, order, decree, ruling, charge, license or other restriction of any governmental authority to which the Company or any of its property is subject, which violation, individually or in the aggregate, would have a material adverse effect on the Company's ability to perform its obligations under this Agreement, (iii) result in a default (or give rise to any right of termination, cancellation or acceleration) under any of the terms, conditions or provisions of any material note, bond, mortgage, indenture, license, agreement or other instrument or obligation to which the Company is a party, except for such defaults (or rights of termination, cancellation or acceleration) as to which requisite waivers or consents have been obtained or which would not, individually or in the aggregate, have a material adverse effect on the Company's ability to perform its obligations under this Agreement, or (iv) constitute violations of any order, writ, injunction, decree, statute, rule or regulation applicable to the Company, or any of its assets, which violation, individually or in the aggregate, would have a material adverse effect on the Company's ability to perform its obligations under this Agreement. (d) No declaration, filing or registration with, or notice to, or authorization consent or approval of any governmental authority is necessary for the consummation by the Company of the transactions contemplated hereby which has not already been obtained or will not be obtained on or prior to the Closing Date. (e) The Company is not Bankrupt and there are no proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming Bankrupt. (f) There is not pending or, to its knowledge, threatened against it or any of the Sub-Purchasers any legal proceedings that could materially adversely affect its ability to perform its obligations under this Agreement. NOTICE Except as otherwise provided herein, any notice, invoice or other communication which is required or permitted by this Agreement shall be in writing and delivered by personal service, telecopy, overnight delivery or mailed certified or registered first class mail, postage prepaid, properly addressed as follows: a) In the case of Company to: Vermont Yankee Nuclear Power Corporation 185 Old Ferry Road P.O. Box 7002 Brattleboro, Vermont 05302-7002 Telecopy No: 802-258-2128 b) In the case of Seller to: Entergy Nuclear Vermont Yankee, LLC 440 Hamilton Avenue White Plains, NY 10601 Telecopy No: 914-272-3205 Another address or addressee may be specified in a notice duly given as provided. Each notice, invoice or other communication which shall be mailed, delivered or transmitted in the manner described above shall be deemed sufficiently given and received for all purposes at such time as it is delivered to the addressee (with return receipt, the delivered receipt, the affidavit of the messenger or with respect to a telecopy, the answer back, being deemed conclusive evidence of such delivery) or at such time as delivery is refused by the addressee upon presentation. GOVERNMENTAL CHARGES Each Party shall use reasonable efforts to implement the provisions of and to administer this Agreement in accordance with the intent of the parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts. Seller shall pay or cause to be paid all taxes imposed by any government authority ("Governmental Charges") on or with respect to the Facility Product arising prior to the Delivery Point. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Facility Product at and from the Delivery Point (other than ad valorem, franchise or income taxes which are related to the sale of the Facility Product and are, therefore, the responsibility of the Seller). In the event Seller is required by law or regulation to remit or pay Governmental Charges which are Buyer's responsibility hereunder, Buyer may deduct the amount of any such Governmental Charges from the sums due to Seller under Article 5 of this Agreement. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under the law. CONFIDENTIALITY Except as otherwise required by law or for implementation of this Agreement, the Parties must keep confidential the transaction undertaken pursuant hereto; provided, however, that Vermont Yankee may disclose such information to its Sub-Purchasers as required to implement the resale of Facility Product, and the Sub-Purchasers may disclose the same to any entities to which they may seek to resell such Facility Product ("Third-Party Purchasers"), provided that any such Third-Party Purchaser shall agree to be bound by this confidentiality provision. Any information provided by either Party to the other Party or to a Sub-Purchaser or any such Third-Party Purchasers pursuant to this Agreement and labeled "CONFIDENTIAL" will be used by the receiving Party solely in connection with the purposes of this Agreement and will not be disclosed by the receiving Party to any third party, except as herein provided or with the providing Party's consent. This Article 19 of this Agreement will not prevent either Party from providing any confidential information received from the other Party to any court in accordance with a proper discovery request or in response to the reasonably request of any governmental agency with jurisdiction to regulate or investigate the disclosing Party's affairs, provided that, if feasible, the disclosing Party will give prior notice to the other Party of such disclosure and, if so requested by such other Party, will have used all reasonably efforts to oppose or resist the requested disclosure, as appropriate under the circumstances, or to otherwise make such disclosure, as appropriate, under the circumstances, or to otherwise make such disclosure pursuant to a protective order or other similar arrangement for confidentiality. SELLER'S MARKET-BASED POWER SALES TARIFF This Agreement is made under the authority of Seller's Market-Based Power Sales Tariff, as accepted for filing by FERC. Nevertheless, unless provisions of that Tariff are specifically incorporated herein by reference, this Agreement controls the terms of the transactions hereunder. IN WITNESS WHEREOF the Parties have executed this Agreement as of the date first written above. ENTERGY NUCLEAR VERMONT YANKEE, LLC By: s/Michael R. Kansler ---------------------- Name: Michael R. Kansler Title: Senior Vice President and Chief Operating Officer VERMONT YANKEE NUCLEAR POWER CORPORATION By: s/Ross P. Barkhurst --------------------- Ross P. Barkhurst President and Chief Executive Officer SCHEDULE A ---------- [Diagram of Delivery Points] SCHEDULE B ---------- Maximum Monthly Amount* (in Mwh) - ------------------ January 383,805 February 359,391 March 383,373 April 370,526 May 378,074 June 357,103 July 375,765 August 366,677 September 357,773 October 380,189 November 371,181 December 383,742 * The maximum figure for any month affected by a refueling outage will be reduced by an amount equal to 510 times the actual number of hours that the Facility produces no Energy due to such refueling outage. If Seller completes an Uprate, Schedule B amounts, including the refueling outage adjustment as noted above, shall be increased by multiplying the amount by the fraction (x / y) as x and y are defined in Article 8(b). SCHEDULE C ---------- Original Sub-Purchasers: Portion -------------- ------- Central Vermont Public Service Corporation 35.0% Green Mountain Power Corporation 20.0% New England Power Company 22.5% The Connecticut Light and Power Company 9.5% Central Maine Power Company 4.0% Public Service Company of New Hampshire 4.0% Cambridge Electric Light Company 2.5% Western Massachusetts Electric Company 2.5% -------- Company's Entitlement 100.0%
SCHEDULE D Base Prices - $/Mwh Low PPA ----------- -------------------------------- 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Jan 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 45.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Feb 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 45.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Mar. 30.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 45.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Apr. 30.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- May. 30.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- June 30.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- July 55.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Aug. 55.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Sept 49.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Oct. 49.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Nov. 49.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Dec. 49.0 42.0 42.8 39.5 39.0 40.0 41.0 42.0 43.0 44.0 - ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
EX-10.B.91 4 doc3.txt AMENDMENT TO ENTERGY PPA 48 LIBC/1487366.4 LIBC/1487366.4 SEC EXHIBIT 10.B.91 FIRST AMENDMENT TO POWER PURCHASE AGREEMENT BETWEEN ENTERGY NUCLEAR VERMONT YANKEE, LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION FIRST AMENDMENT TO POWER PURCHASE AGREEMENT This FIRST AMENDMENT TO POWER PURCHASE AGREEMENT (the "Amendment") is entered into this 7th day of May, 2002, by and between Entergy Nuclear Vermont Yankee, LLC, a Delaware limited liability company having a principal place of business at 440 Hamilton Avenue, White Plains, NY 10601, and Vermont Yankee Nuclear Power Corporation, a Vermont corporation having its principal place of business at 185 Old Ferry Road, Brattleboro, Vermont 05301. WHEREAS, the parties hereto have entered into a Power Purchase Agreement on September 6, 2001 (the "Original Power Purchase Agreement"); WHEREAS, on March 4, 2002, in connection with Docket No. 6545 before the State of Vermont Public Service Board, the parties hereto and certain other parties entered into a Memorandum of Understanding Among Entergy Nuclear Vermont Yankee, LLC, Vermont Yankee Nuclear Power Corporation, Central Vermont Public Service Corporation, Green Mountain Power Corporation and the Vermont Department of Public Service (the "MOU"); WHEREAS, pursuant to the MOU the parties hereto agreed to amend the terms of the Original Power Purchase Agreement; and WHEREAS, capitalized terms used in this Amendment shall have the meanings ascribed to them in the Original Power Purchase Agreement. NOW THEREFORE, in consideration of these premises, the mutual agreements set forth herein and other good and valuable consideration, and intending to be legally bound, the parties agree as follows: 1. AMENDMENT OF ARTICLE 2(T). The second sentence of Article 2(t) of the ---------------------------- Original Power Purchase Agreement is modified to read as follows: "In the event there is no clearing price for Installed Capability, the Market Price shall be the product of (x) the amount set forth in clause (a) of the preceding sentence and (y) 110% (or such other percentage mutually acceptable to Vermont Yankee and the Seller to accurately reflect the price of Installed Capability)". All other provisions of Article 2(t) remain unchanged. 2. AMENDMENT TO ARTICLE 5(A). The proviso in Article 5(a) is amended ---------------------------- by deleting the words "after the end of the RFO 25 refueling outage (i.e., approximately October 2005)" and inserting in lieu thereof the words "after the beginning of the RFO 25 refueling outage, but in any event no later than November 1, 2005,". 3. EFFECT ON OTHER PROVISIONS OF THE ORIGINAL POWER PURCHASE AGREEMENT. -------------------------------------------------------------------- Except as modified by this First Amendment, the provisions of the Original Power Purchase Agreement remain in full force and effect. IN WITNESS WHEREOF the parties hereto have executed this Amendment as of the date first written above. ENTERGY NUCLEAR VERMONT YANKEE, LLC By: /s/Jerry W. Velverton -------------------- Name: Jerry W. Velverton Title: President and CEO VERMONT YANKEE NUCLEAR POWER CORPORATION By: /s/Bruce W. Wiggett ----------------------- Name: Bruce W. Wiggett Title: Senior Vice President of Finance and Administration -----END PRIVACY-ENHANCED MESSAGE-----