-----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, JrgQygh5z8RtZeCVKv4qUkdHNna3GocT5VWTGu6A3hGxgt52ldB2bTY0le6QjfZE PLq6KrHr8XOgtTves3FDiw== 0000043704-01-500009.txt : 20010511 0000043704-01-500009.hdr.sgml : 20010511 ACCESSION NUMBER: 0000043704-01-500009 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010331 FILED AS OF DATE: 20010510 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: SEC FILE NUMBER: 001-08291 FILM NUMBER: 1628633 BUSINESS ADDRESS: STREET 1: 163 ACORN LANE STREET 2: P.O.BOX 850 CITY: COLCHESTER STATE: VT ZIP: 05446 BUSINESS PHONE: 8028645731 MAIL ADDRESS: STREET 1: 25 GREEN MOUNTAIN DR STREET 2: P O BOX 850 CITY: SOUTH BURLINGTON STATE: VT ZIP: 05403 10-Q 1 sec_form10q.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 MARCH 31, 2001 -------------- 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 MAY 2, 2001 - --------------------------- ------------------------------- $3.33 1/3 PAR VALUE 5,623,848 GREEN MOUNTAIN POWER CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES AT AND FOR THE THREE MONTHS ENDED MARCH 31, 2001 AND 2000 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 Exhibits and Reports on Form 8-K 23 The accompanying notes are an integral part of the consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED COMPARATIVE INCOME STATEMENTS UNAUDITED ---------- THREE MONTHS ENDED MARCH 31 2001 2000 -------- -------- In thousands, except per share data OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $74,796 $67,712 -------- -------- OPERATING EXPENSES Power Supply Vermont Yankee Nuclear Power Corporation. . . . . . . . . . 8,044 8,060 Company-owned generation. . . . . . . . . . . . . . . . . . 2,376 1,204 Purchases from others . . . . . . . . . . . . . . . . . . . 44,016 36,646 Other operating. . . . . . . . . . . . . . . . . . . . . . . 3,368 3,627 Transmission . . . . . . . . . . . . . . . . . . . . . . . . 3,459 3,483 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 1,457 1,626 Depreciation and amortization. . . . . . . . . . . . . . . . 3,689 4,167 Taxes other than income. . . . . . . . . . . . . . . . . . . 1,988 2,027 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 1,824 2,259 -------- -------- Total operating expenses. . . . . . . . . . . . . . . . . 70,221 63,099 -------- -------- OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 4,575 4,613 -------- -------- OTHER INCOME Equity in earnings of affiliates and non-utility operations. 550 624 Allowance for equity funds used during construction. . . . . 14 62 Other income (deductions), net . . . . . . . . . . . . . . . (27) 185 -------- -------- TOTAL OTHER INCOME (DEDUCTIONS) . . . . . . . . . . . . . 537 871 -------- -------- INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 5,112 5,484 -------- -------- INTEREST CHARGES Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 1,547 1,661 Other interest . . . . . . . . . . . . . . . . . . . . . . . 478 144 Allowance for borrowed funds used during construction. . . . (62) (40) -------- -------- TOTAL INTEREST CHARGES. . . . . . . . . . . . . . . . . . 1,963 1,765 -------- -------- INCOME BEFORE PREFERRED DIVIDENDS AND. . . . . . . . . . . . 3,149 3,719 DISCONTINUED OPERATIONS Dividends on preferred stock . . . . . . . . . . . . . . . . 235 270 -------- -------- Income from continuing operations. . . . . . . . . . . . . . 2,914 3,449 Net income from discontinued segment operations . . . . . . . . . . . . . . . . . . . . . . . . . - - Loss on disposal, including provisions for operating losses during phaseout period. . . . . . . . . . . - - -------- -------- NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 2,914 $ 3,449 ======== ======== Common stock data Basic earnings per share . . . . . . . . . . . . . . . . . . $ 0.52 $ 0.63 Diluted earnings per share . . . . . . . . . . . . . . . . . 0.51 0.63 Cash dividends declared per share. . . . . . . . . . . . . . $ 0.14 $ 0.14 Weighted average common shares outstanding-basic . . . . . . 5,588 5,437 Weighted average common shares outstanding-diluted . . . . . 5,741 5,437 CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Balance - beginning of period. . . . . . . . . . . . . . . . $ 493 $10,344 Net Income . . . . . . . . . . . . . . . . . . . . . . . . . 3,149 3,719 Cash Dividends-redeemable cumulative preferred stock . . . . (235) (270) Cash Dividends-common stock. . . . . . . . . . . . . . . . . (768) (747) -------- -------- Balance - end of period. . . . . . . . . . . . . . . . . . . $ 2,639 $13,046 ======== ========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31 2001 2000 -------------- -------- OPERATING ACTIVITIES: In thousands Net income before preferred dividends . . . . . . . . . . . $ 3,149 $ 3,719 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization . . . . . . . . . . . . . . 3,689 4,167 Dividends from associated companies less equity income. . 41 (111) Allowance for funds used during construction. . . . . . . (76) (102) Amortization of purchased power costs . . . . . . . . . . 1,015 1,500 Deferred income taxes . . . . . . . . . . . . . . . . . . (173) 447 Deferred revenues . . . . . . . . . . . . . . . . . . . . 7,218 7,163 Deferred purchased power costs. . . . . . . . . . . . . . 551 54 Accrued purchase power contract option call . . . . . . . (1,580) - Deferred arbitration costs. . . . . . . . . . . . . . . . 61 (457) Environmental and conservation deferrals, net . . . . . . (840) (542) Changes in: Accounts receivable . . . . . . . . . . . . . . . . . . (2,821) (1,836) Accrued utility revenues. . . . . . . . . . . . . . . . 214 (50) Fuel, materials and supplies. . . . . . . . . . . . . . 926 18 Prepayments and other current assets. . . . . . . . . . 1,122 1,487 Accounts payable. . . . . . . . . . . . . . . . . . . . (5,138) 611 Accrued income taxes payable and receivable . . . . . . 1,868 1,997 Other current liabilities . . . . . . . . . . . . . . . 1,063 (1,671) Other . . . . . . . . . . . . . . . . . . . . . . . . . . (755) 1,297 -------------- -------- Net cash provided by continuing operations. . . . . . . . 9,532 17,691 Net change in discontinued segment. . . . . . . . . . . . - (320) -------------- -------- Net cash provided by operating activities . . . . . . . . 9,532 17,371 INVESTING ACTIVITIES: Construction expenditures . . . . . . . . . . . . . . . . . (2,350) (1,852) Investment in nonutility property . . . . . . . . . . . . . (46) (44) -------------- -------- Net cash used in investing activities . . . . . . . . . . (2,397) (1,896) -------------- -------- FINANCING ACTIVITIES: Issuance of common stock. . . . . . . . . . . . . . . . . . 461 301 Investment in certificate of deposit, pledged for revolver. (245) - Power supply option obligation. . . . . . . . . . . . . . . 370 - Short-term debt, net. . . . . . . . . . . . . . . . . . . . (6,600) (7,900) Cash dividends. . . . . . . . . . . . . . . . . . . . . . . (1,003) (1,017) -------------- -------- Net cash used in financing activities . . . . . . . . . . (7,017) (8,616) -------------- -------- Net increase(decrease) in cash and cash equivalents . . . . 119 6,859 Cash and cash equivalents at beginning of period. . . . . . 341 696 -------------- -------- Cash and cash equivalents at end of period. . . . . . . . . $ 460 $ 7,555 ============== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid year-to-date for: Interest (net of amounts capitalized) . . . . . . . . . . $ 1,354 $ 1,029 Income taxes, net . . . . . . . . . . . . . . . . . . . . - -
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 MARCH 31, DECEMBER 31, 2001 2000 2000 -------- -------- -------- In thousands ASSETS UTILITY PLANT Utility plant, at original cost . . . . . . . $291,034 $285,071 $291,107 Less accumulated depreciation . . . . . . . . 111,877 105,490 110,273 -------- -------- -------- Net utility plant . . . . . . . . . . . . . . 179,157 179,581 180,834 Property under capital lease. . . . . . . . . 6,449 7,038 6,449 Construction work in progress . . . . . . . . 8,567 5,310 7,389 -------- -------- -------- Total utility plant, net. . . . . . . . . . 194,173 191,929 194,672 -------- -------- -------- OTHER INVESTMENTS Associated companies, at equity . . . . . . . 14,332 14,653 14,373 Other investments . . . . . . . . . . . . . . 6,485 5,990 6,357 -------- -------- -------- Total other investments . . . . . . . . . . 20,817 20,643 20,730 -------- -------- -------- CURRENT ASSETS Cash and cash equivalents . . . . . . . . . . 460 7,514 341 Certficate of deposit, pledged as collateral. 15,681 - 15,437 Accounts receivable, customers and others, less allowance for doubtful accounts of $463, $398, and $463 . . . . . . . . . . 25,186 20,339 22,365 Accrued utility revenues. . . . . . . . . . . 6,880 7,019 7,093 Fuel, materials and supplies, at average cost 3,130 3,272 4,056 Prepayments . . . . . . . . . . . . . . . . . 1,375 1,591 2,525 Income tax receivable . . . . . . . . . . . . - - 1,613 Other . . . . . . . . . . . . . . . . . . . . 249 217 222 -------- -------- -------- Total current assets. . . . . . . . . . . . 52,961 39,952 53,652 -------- -------- -------- DEFERRED CHARGES Demand side management programs . . . . . . . 6,363 7,158 6,358 Purchased power costs . . . . . . . . . . . . 41,692 11,281 11,789 Pine Street Barge Canal . . . . . . . . . . . 12,370 8,700 12,370 Other . . . . . . . . . . . . . . . . . . . . 15,901 17,456 15,519 -------- -------- -------- Total deferred charges. . . . . . . . . . . 76,326 44,595 46,036 -------- -------- -------- NON-UTILITY Cash and cash equivalents . . . . . . . . . . - 41 - Other current assets. . . . . . . . . . . . . 8 8 8 Property and equipment. . . . . . . . . . . . 251 253 252 Business segment held for disposal. . . . . . - 9,797 - Other assets. . . . . . . . . . . . . . . . . 862 1,306 1,258 -------- -------- -------- Total non-utility assets. . . . . . . . . . 1,121 11,405 1,518 -------- -------- -------- TOTAL ASSETS. . . . . . . . . . . . . . . . . . $345,398 $308,524 $316,608 ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION CONSOLIDATED BALANCE SHEETS UNAUDITED --------- AT MARCH 31, DECEMBER 31, 2001 2000 2000 --------- --------- --------- 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 5,617,116, 5,463,948 and 5,582,552) . . . . . . $ 18,723 $ 18,215 $ 18,608 Additional paid-in capital . . . . . . . . . . . 73,668 72,766 73,321 Retained earnings. . . . . . . . . . . . . . . . 2,639 13,046 493 Treasury stock, at cost (15,856 shares). . . . . (378) (378) (378) --------- --------- --------- Total common stock equity. . . . . . . . . . . 94,652 103,649 92,044 Redeemable cumulative preferred stock. . . . . . 12,560 12,795 12,560 Long-term debt, less current maturities. . . . . 72,100 81,800 72,100 --------- --------- --------- Total capitalization . . . . . . . . . . . . . 179,312 198,244 176,704 --------- --------- --------- CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 6,449 7,038 6,449 --------- --------- --------- CURRENT LIABILITIES Current maturities of preferred stock. . . . . . 235 1,640 235 Current maturities of long-term debt . . . . . . 9,700 6,700 9,700 Short-term debt. . . . . . . . . . . . . . . . . 8,900 - 15,500 Accounts payable, trade and accrued liabilities. 4,566 6,814 7,755 Accounts payable to associated companies . . . . 6,561 7,057 8,510 Dividends declared . . . . . . . . . . . . . . . 229 285 229 Customer deposits. . . . . . . . . . . . . . . . 753 351 696 Purchased power call option liability. . . . . . 6,696 - 8,276 Interest accrued . . . . . . . . . . . . . . . . 1,753 1,883 1,150 Energy East power supply obligation. . . . . . . 15,789 - 15,419 Deferred revenues. . . . . . . . . . . . . . . . 7,218 7,163 - Other. . . . . . . . . . . . . . . . . . . . . . 1,532 6,127 874 --------- --------- --------- Total current liabilities. . . . . . . . . . . 63,932 38,020 68,344 --------- --------- --------- DEFERRED CREDITS SFAS 133 liability . . . . . . . . . . . . . . . 31,517 - - Accumulated deferred income taxes. . . . . . . . 25,541 25,718 25,644 Unamortized investment tax credits . . . . . . . 3,625 3,907 3,695 Pine Street Barge Canal site cleanup . . . . . . 11,140 8,985 11,554 Other. . . . . . . . . . . . . . . . . . . . . . 20,565 26,612 20,901 --------- --------- --------- Total deferred credits . . . . . . . . . . . . 92,388 65,222 61,794 --------- --------- --------- COMMITMENTS AND CONTINGENCIES NON-UTILITY Liabilities of discontinued segment, net . . . . 3,317 - 3,317 --------- --------- --------- Total non-utility liabilities. . . . . . . . . 3,317 - 3,317 --------- --------- --------- TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $345,398 $308,524 $316,608 ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. GREEN MOUNTAIN POWER CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2001 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 2000 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. Historically we have charged our customers higher rates for billing cycles in December through March and lower rates for the remaining months. These are called seasonally differentiated rates. In order to eliminate the impact of the seasonally differentiated rates, we defer some of the revenues from those four months and account for them in later periods when we have lower revenues or higher costs. By deferring certain revenues we are able to better match our revenues to our costs. On March 31, 2001 and 2000, there was deferred revenue of $7.2 million. These deferred revenues are accreted into revenue throughout the current year. Seasonal rates will be eliminated in April 2001, which is expected to generate approximately $6.0 million in additional cash flow in 2001 that can be used to offset increased costs during 2001, 2002 and 2003. See the discussion under "Commitments and Contingencies - Retail Rate Cases" for further information. 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", formerly known as Mountain Energy, Inc.); Green Mountain Propane Gas Company Limited ("GMPG"); GMP Real Estate Corporation; and Green Mountain Resources, Inc. ("GMRI"). On June 30, 1999, we decided to sell the assets of NWR, and report 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 (excluding NWR) and the rental water heater program are included 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") Percent ownership: 17.9% common
Three months ended March 31 2001 2000 ------- ------- (in thousands) Gross Revenue. . . . . $40,964 $40,692 Net Income Applicable. 1,550 1,744 to Common Stock Equity in Net Income . 273 314
On October 15, 1999, the owners of VY accepted a bid from AmerGen Energy Company for the VY generating plant, intending to complete the sale before December 2000. AmerGen and the Vermont Department of Public Service ("DPS" or the "Department") negotiated a revised offer in November 2000, which was subsequently dismissed as insufficient by the VPSB in February 2001. Entergy Nuclear Inc. has also made an offer, secured by a bond which has been approved by the VPSB, and two other companies have indicated they would participate in an auction, if held. The plant is likely to be sold at auction, the terms and conditions of which are unknown at this time. If the plant is auctioned, then the Company would continue equity ownership of VY until sold, and would enter into a power supply agreement with the new plant owners. 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 March 31 2001 2000 ------ ------ (in thousands) Gross Revenue . . . . $7,170 $6,715 Net Income. . . . . . 243 273 Equity in Net Income. 55 84
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("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 March 31, 2001, our total expenditures related to the Pine Street site since 1982 were approximately $23.9 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 awaiting 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 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 On May 8, 1998, we filed a request with the VPSB to increase our retail rates by 12.93 percent due to higher power costs, the cost of the January 1998 ice storm, and investments in new plant and equipment (the "1998 rate case"). The Company reached a final settlement agreement with the Department in the 1998 rate case during November 2000. The final settlement agreement contains the following provisions: * The Company receives 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 are set at levels that recover the Company's Hydro-Quebec VJO contract costs, effectively ending the regulatory disallowances experienced by the Company over the past three years; * The Company agrees 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 all or substantially all of its short-term credit facilities with long-term debt or equity financing; * Seasonal rates will be eliminated in April 2001, which is expected to generate approximately $6.0 million in additional cash flow in 2001 that can be utilized to offset potential increased costs during 2001, 2002 and 2003; * The Company agrees 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; and * The Company agrees to withdraw its Vermont Supreme Court appeal of the VPSB's Order in the Company's 1997 rate case. On January 23, 2001, the VPSB Order (the "Settlement Order") approved the Company's settlement with the Department, with two additional conditions: * The VPSB Order requires the Company and its customers to 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 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 cumulative amount of power purchased or called to purchase by Hydro-Quebec under option B, is approximately 432,000 MWh. Approximately $6.6 million is currently being provided annually in rates to cover the net cost of 9701 calls by Hydro-Quebec, and is recognized ratably over 2001. The Company recognized $1.7 million in expense during the quarter ended March 31, 2001 to reflect these estimated costs. A regulatory asset of $4.9 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 and/or amounts previously recorded, the excess cost would be immediately charged against earnings. No charge for excess cost was required during the first quarter of 2001. The Company has purchased power sufficient to fulfill the 9701 option calls for this summer, and no charges in excess of amounts provided in rates or previously recorded are anticipated for the remainder of 2001. 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. It is possible our estimate of future power supply costs could differ materially from actual results. During 1999, the Company had accrued expected losses for 2000 for disallowed Hydro-Quebec power supply contracts pursuant to VPSB orders. Results for the three months ended March 31, 2000 do not reflect any disallowed Hydro-Quebec power supply costs. If the 1999 accruals, consistent with generally accepted accounting principles, had not been made, power supply costs would have been $1.9 million higher for the three months ended March 31, 2000. POWER SUPPLY AND TRANSMISSION Company-owned generation expenses increased $1.2 million in the first quarter of 2001 compared with the same period in 2000 primarily due to the higher cost of fuels and the unavailability of unique replacement equipment connecting Vermont's transmission system to that of New York. The lack of such equipment required running generation to support system reliability. The Company has requested reimbursement of its costs of running its units for system reliability from the Independent System Operator of New England ("ISO"). The Company recorded a regulatory asset and reduced Company-owned generation expense by $1.0 million, representing incremental fuel and operation and maintenance costs due from ISO. If the ISO were to reject a portion of the Company's costs, the Company believes it could recover these costs from ratepayers under the Settlement Order. A FERC ruling in December 2000 required ISO to revise its installed capability ("ICAP") deficiency charge of $0.17 per kw month to $8.75 per kw month retroactive to August 1, 2000. On January 10, 2001, FERC stayed its order "to ensure that bills for past periods will not be assessed until the Commission has considered the pending requests for rehearing, which, if successful, would then require extensive refunds and surcharges." On March 6, 2001, FERC issued an Order on Rehearing in which it partly reversed itself on the ICAP charge. Although the FERC first concluded that a $8.75 charge is reasonable and that the charge would remain in place until the ISO supports an acceptable superseding proposal, the FERC then concluded that reinstating the $8.75 would have a large cost impact. As a result, the $0.17 per kW month charge was reinstated from August 1, 2000 until April 1, 2001. The FERC allowed the $8.75 charge to become effective on April 1, 2001 until the effective date of any superseding charge that the FERC might accept. On March 16, 2001, an ISO participant filed a request for re-hearing the FERC's March 6, 2001 Order on Rehearing. The request asks for a reversal of the lowered ICAP charge for the period from August 1, 2000 until April 1, 2001. If the lowered ICAP charge is increased to $8.75 per kw month for the period from August 1, 2000 to March 31, 2001, then the Company would be required to pay ISO approximately $1.4 million. Also, in March 2001, a federal court issued a stay preventing reinstatement of the $8.75 charge, after sixteen New England utilities and energy companies protested the increased penalty. The U.S. Court of Appeals for the First Circuit in Boston is tentatively scheduled to hear oral arguments from the utilities and FERC on May 8, 2001, according to the court order. Management cannot determine the ultimate impact of these actions at this time. The Company has purchased ICAP associated with 2001 obligations for its 9701 arrangement with Hydro-Quebec at an average price of approximately $4 per MWh. The Company has also arranged to purchase 50 percent of its anticipated 9701 ICAP needs during 2002 at an average cost of $2.60 per MWh. As of March 31, 2001, the Company had deferred a total of $4.6 million, its share of arbitration costs related to the pursuit of claims against Hydro-Quebec arising from its suspension of deliveries during and after the 1998 ice storm. The Company has received an accounting order from the VPSB providing for the deferral of these charges, subject to final determination in a future rate proceeding. On April 17, 2001, an Arbitration Tribunal issued its decision in the arbitration brought by a group of Vermont electric companies and municipal utilities, known as the Vermont Joint Owners (VJO), against Hydro-Quebec for its failure to deliver electricity pursuant to the VJO/Hydro-Quebec power supply contract during the 1998 ice storm. The Company is a member of the VJO. In its award, the Arbitration Tribunal agreed partially with Hydro-Quebec and partially with the VJO. In the split decision, (i) the VJO/Hydro-Quebec power supply contract remains in effect and Hydro-Quebec is required to continue to provide capacity and energy to the Company under the terms of the VJO contract, which expires in 2015 and (ii) Hydro-Quebec is required to return certain capacity payments to the VJO. Any proceeds ultimately received would reduce related deferred assets. We believe it is probable that the arbitration costs, should they exceed any recovery from the arbitration decision, will ultimately be recovered in rates. 4. SEGMENTS AND RELATED INFORMATION The Company has two reportable segments, the electric utility and NWR. 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, 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, 1999, we classified NWR's net assets and liabilities as "Business Segment Held for Sale", reflecting the Company's intent to sell NWR's assets. Previously, investment in NWR appeared as a separate caption, "Equity Investment in Energy Related Business" in the nonutility section of the consolidated balance sheet. During 2000, the Company recorded losses of $6.5 million, or $1.19 per share to reflect revised estimates and actual sales of most of NWR's energy generation and energy efficiency assets. The provisions for loss from discontinued operations reflect the Company's most recent estimate. The ultimate loss remains subject to the consummation of the sale or other disposition of NWR's remaining assets and liabilities, primarily waste-water treatment projects, and could exceed amounts recorded. Results of operations for NWR are now reported under "Loss on disposal of discontinued segment, net of applicable income taxes". Provisions for loss on disposal are reported under "Loss on disposal of discontinued segment, net of applicable income taxes". Segment information compared with the Company's results includes the following:
Three months ended March 31 2001 2000 ------- ------- In thousands, except per share data External revenues Electric utility. . . . . . . . . . $74,796 $67,712 NWR segment . . . . . . . . . . . . 35 97 Net income (loss) from operations Electric utility. . . . . . . . . . $ 2,914 $ 3,449 NWR segment . . . . . . . . . . . . - - ------- ------- Consolidated net income (loss) . . . $ 2,914 $ 3,449 ======= ======= Basic earnings (loss) per share Discontinued operations . . . . . $ - $ - Continuing operations . . . . . . 0.52 0.63 Diluted earnings per share Discontinued operations . . . . . - - Continuing operations . . . . . . $ 0.51 $ 0.63
5. NEW ACCOUNTING STANDARD - SFAS 133 In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities. SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in 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. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, as amended by SFAS 137, is effective for the Company beginning the first quarter of 2001. SFAS 133 must be applied to (a) derivative instruments and (b) either all derivative instruments embedded in hybrid contracts or those embedded instruments that were issued, acquired, or substantively modified on or after January 1, 1998 or January 1, 1999 (as elected by the Company). The Company's 9701 arrangement with Hydro-Quebec that grants Hydro-Quebec an option to call for energy deliveries at prices currently below estimated future market rates through 2015 is a derivative under SFAS 133. We sometimes use future contracts (derivatives) to hedge forecasted wholesale sales of electric power, including the 9701 arrangement. The Company also has a power purchase and supply agreement with Morgan Stanley Capital Group, Inc. ("MS") to hedge the fair value of fossil fuel prices that is a derivative under 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 effects 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 March 31, 2001, the Company had a regulatory asset of approximately $31.5 million related to the derivatives discussed above. The Company believes that the regulatory asset is probable of recovery. The regulatory asset is based on current estimates of future market prices that are likely 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. 6. 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 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 March 31 2001 2000 ------ ------ In thousands Net income. . . . . . . . . . . . . . . $2,914 $3,449 Preferred stock dividend requirement. . 235 270 ------ ------ Net income applicable to common stock. . . . . . . . . . . . . . . . $3,149 $3,719 ====== ====== Average number of common shares-basic . 5,588 5,437 Dilutive effect of stock options. . . . 153 - Anti-dilutive stock options . . . . . . - - ------ ------ Average number of common shares-diluted 5,741 5,437 ====== ======
GREEN MOUNTAIN POWER CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS MARCH 31, 2001 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. 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 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 (loss) per share of Common Stock Three months ended March 31 2001 2000 ----- ----- Utility business . . . $0.50 $0.60 Unregulated businesses 0.02 0.03 ----- ----- Earnings(loss) from: . 0.52 0.63 Continuing operations Discontinued segment . 0.00 0.00 ----- ----- Basic earnings (loss) per share . . $0.52 $0.63 ===== =====
UTILITY BUSINESS The Company recorded basic earnings per share from utility operations of $0.50 in the quarter ended March 31, 2001, compared with utility earnings of $0.60 per share in the first quarter of 2000. Increased retail revenues resulting from a 3.42 percent rate increase approved by the Vermont Public Service Board ("VPSB") on January 23, 2001 (the "Settlement Order") were more than offset by higher power supply costs to serve customers. The Company has previously accrued losses for disallowed Hydro-Quebec power supply costs pursuant to VPSB orders. Results for the three months ended March 31, 2000 do not reflect any disallowed Hydro-Quebec power supply costs. If these accruals, consistent with generally accepted accounting principles, had not been made in prior periods, power supply costs would have been $1.9 million higher for the three months ended March 31, 2000. Power supply costs were also higher in the first quarter of 2001 due to increased regional energy prices, reduced availability of some Company hydroelectric generation capacity, energy purchases to cover potential shortages due to transmission system operating requirements, and scheduled increases in our long-term power supply contract with MS. UNREGULATED BUSINESSES Earnings from unregulated businesses included in results from continuing operations for the three months ended March 31, 2001 were slightly lower than during the same period in 2000. A financial summary for these businesses, excluding NWR, follows:
Three months ended March 31 2001 2000 ----- ----- In thousands Revenue. . . $ 259 $ 262 Expense. . . 125 125 ----- ----- Net Income . $ 134 $ 137 ===== =====
DISCONTINUED SEGMENT OPERATIONS As of June 30, 1999, the Company decided to sell or dispose of NWR, a wholly owned subsidiary that invested in energy generation, energy efficiency and wastewater treatment businesses. Its results are reported separately after income (loss) from continuing operations. NWR's operating loss for the three months ended March 31, 2001 has been previously recognized as provision for operating loss during phase-out period. The ultimate loss remains subject to the sale or other disposition of NWR's remaining assets and liabilities, primarily waste-water treatment projects, and could exceed amounts recorded. Most of NWR's energy generation and energy efficiency assets have been sold. The operating loss for the three months ended March 31, 2001 would have been approximately $486,000 compared with a loss of $879,000 for the same period a year ago. OPERATING REVENUES AND MWH SALES Our revenues from operations, megawatthour ("MWh") sales and average number of customers for the three months ended March 31, 2001 and 2000 are summarized below:
Three months ended March 31 2001 2000 ---------- ---------- (dollars in thousands) Operating revenues Retail. . . . . . . . $ 51,953 $ 49,550 Sales for Resale. . . 21,838 17,300 Other . . . . . . . . 1,005 862 ---------- ---------- Total Operating Revenues. $ 74,796 $ 67,712 ========== ========== MWh sales-Retail. . . . . 520,771 520,222 MWh sales for Resale. . . 638,096 567,685 ---------- ---------- Total MWh Sales . . . . . 1,158,867 1,087,907 ========== ==========
Average Number of Customers Three months ended March 31 2001 2000 ------ ------ Residential . . . . . . . 73,149 72,165 Commercial and Industrial 12,933 12,574 Other . . . . . . . . . . 65 64 ------ ------ Total Number of Customers. . 86,147 84,803 ====== ======
REVENUES Revenues from operations in the first quarter of 2001 increased 10.5 percent or $7.1 million compared with the same period in 2000. Operating revenues result from retail and wholesale sales of electricity. Retail revenues in the first quarter of 2001 were $2.4 million or 4.8 percent higher compared with the same period in 2000, reflecting a 3.42 percent rate increase effective January 2001, and a 0.1 percent increase in retail MWh sales. Sales of electricity increased by 1.6 percent to small commercial and industrial customers, and decreased by 2.0 percent to residential customers and 1.1 percent to lower margin industrial customers during the first quarter of 2001 compared with the same period in 2000. We sell wholesale electricity to others for resale. Our revenue from wholesale sales of electricity increased $4.5 million in the first quarter of 2001 compared with the same period in 2000. The increase was due primarily to increased sales under a power purchase and supply agreement between the Company and MS, and increased sales under various arrangements with Hydro-Quebec. Under the MS agreement, we sell power to MS at predefined operating and pricing parameters. MS then sells to us, at a predefined price, power sufficient to serve pre-established load requirements. OPERATING EXPENSES POWER SUPPLY EXPENSES - THREE MONTHS ENDED MARCH 31, 2001 Power supply expenses increased 18.6 percent or $8.5 million in the first quarter of 2001 over the same period in 2000. Power supply expenses at Vermont Yankee ("VY") decreased 0.2% or $16,000 during the first quarter of 2001 compared with the first quarter of 2000. A proposed sale of the generating plant is discussed under Part I, Item 2, "Investment in Associated Companies". Company-owned generation expenses increased $1.2 million in the first quarter of 2001 compared with the same period in 2000 primarily due to the higher cost of fuels and the unavailability of unique replacement equipment connecting Vermont's transmission system to that of New York. The lack of replacement equipment required running generation to support system reliability. The Company has requested reimbursement of its costs of running its units for system reliability from the Independent System Operator of New England ("ISO"). The Company recorded a regulatory asset and reduced Company-owned generation expense by $1.0 million, representing incremental fuel and operation and maintenance costs due from ISO. The cost of power that we purchased from other companies increased 16.5 percent or $7.4 million in the first quarter of 2001 compared with the same period in 2000. This was primarily due to power supply costs for increased wholesale electric sales of $4.5 million to replace power sold to Hydro-Quebec under a previous arrangement ("9701"), to buy energy that could potentially have been curtailed due to transmission system operating requirements, and for power sold to MS under the power purchase and supply agreement. Power supply costs were also higher during the first quarter of 2001 compared with the same period in 2000 due to higher energy clearing prices in the New England market, the unavailability of hydroelectric capacity that is estimated to have cost the Company an additional $850,000, and scheduled increases in the cost of power under our long-term contract with MS. 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 first quarter of 2001, Hydro-Quebec exercised its purchase option for delivery of 134,592 MWh during the months of June, July and August of 2001. The Settlement Order approved by the VPSB includes revenues in 2001 sufficient to provide for net costs of replacing power purchased by Hydro-Quebec of approximately $6.6 million annually. The Company recognized $1.7 million in expense during the quarter ended March 31, 2001 to reflect these estimated costs. A regulatory asset of $4.9 million was established for the remaining estimated difference between the option exercise price and the expected cost of replacement power for 2000 to be recovered during 2001. If the estimated costs of power purchased to supply Hydro-Quebec option calls exceed amounts recovered in rates and/or amounts previously recorded, the excess cost would be immediately charged against earnings. No charge for excess cost was required during the first quarter of 2001. The Company has purchased power sufficient to fulfill the 9701 calls for this summer, and no charges in excess of amounts provided in rates or previously recorded are anticipated for the remainder of 2001. The net cost of power to supply all 9701 option calls during 2001 is estimated at approximately $8.4 million. It is possible our estimate of future power supply costs could differ materially from actual results. Both the 9701 arrangement and the 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 March 31, 2001, the Company had a regulatory asset of approximately $31.5 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. OTHER OPERATING EXPENSES Other operating expenses decreased 7.2 percent or $259,000 in the first quarter of 2001 compared with the same period in 2000. The reduction reflects decreased amortization due to the write-off of state regulatory commission costs coincident with the Settlement Order. TRANSMISSION EXPENSES Transmission expenses decreased by approximately $24,000 or 0.7% for the three months ended March 31, 2001 compared with the same period in 2000. Congestion charges recorded in the first quarter of 2001 and 2000 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. The Company is unable to predict the magnitude or duration of future congestion charge allocations, but amounts could be material. DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization expenses decreased $478,000 or 11.5 percent during the first quarter of 2001 compared with the same period in 2000. The reduction is primarily due to decreased amortization of demand side management assets. TAXES OTHER THAN INCOME TAXES Other taxes decreased 1.9 percent or $39,000 in the first quarter of 2001 compared with the same period in 2000, reflecting payroll tax decreases that were partially offset by gross revenue tax increases. INCOME TAXES Income taxes decreased $435,000 in the first quarter of 2001 compared with the same period in 2000 due to a decrease in pretax book income for core electric operations. OTHER INCOME Other income for the three months ended March 31, 2001 decreased approximately $334,000 or 38.3 percent compared with the same period in 2000 due primarily to decreases in capitalized interest costs and decreased earnings from subsidiaries. INTEREST CHARGES Interest charges increased 11.24 percent or $198,000 in the first quarter of 2001 over the same period in 2000 primarily due to costs associated with the revolving lines of credit discussed under "Liquidity and Capital Resources". LIQUIDITY AND CAPITAL RESOURCES In the three months ended March 31, 2001, we spent $2.8 million principally for expansion and improvements of our transmission and distribution plant. We expect to spend an additional $13.0 million during the remainder of 2001. On June 21, 2000, we renewed a revolving credit agreement with Fleet National Bank and Citizens Bank of Massachusetts (the "Fleet Agreement"). The Fleet Agreement is for a period of 364 days, will expire on June 20, 2001, and is secured by granting the banks a second priority mortgage, lien and security interest in the collateral pledged under the Company's first mortgage bond indenture. We had no borrowings outstanding on the Fleet Agreement at March 31, 2001. On September 20, 2000, we established a $15.0 million revolving credit agreement with KeyBank National Association ("KeyBank"). The agreement will expire on September 19, 2001. Pursuant to a one year power supply option agreement between the Company and Energy East Corporation ("EE"), EE made a payment of $15.0 million to the Company. In exchange, the Company gave EE an option to purchase energy from certain wholly owned production facilities, for a period not to exceed 15 years, if the funds are not returned to EE upon request after September 2001. The Company was required to invest the funds provided by EE in a certificate of deposit at KeyBank pledged by the Company to secure the repayment of the Keybank revolving credit facility. At March 31, 2001, there was $8.9 million outstanding on the KeyBank revolving credit agreement. The Company anticipates that it will secure financing that replaces some or all of its expiring facilities during 2001 and that amounts financed will be sufficient to meet our forecasted borrowing requirements during 2001. The credit ratings of the Company's securities are: Fitch Moody's Standard & Poor's ----- ------- ------------------- First mortgage bonds BBB Baa2 BBB Preferred stock BBB- baa3 BB During the first quarter of 2001, Moody's Investors Service and Fitch upgraded the Company's first mortgage bond and preferred stock ratings. The rating actions reflected the rating agencies' earnings and cash flow expectations for the Company following the Settlement Order. Standard & Poor's has favorably changed its outlook, which already rated the first mortgage bonds at investment grade, relative to the ratings direction for the Company. COMPETITION AND RESTRUCTURING The electric utility business is experiencing rapid and substantial changes. These changes are the result of the following trends: * Disparity in electric rates among and within various regions of the country; * Improvements in generation efficiency; * Alternative energy sources; * Increasing demand for customer choice; * The deregulation of the energy market and the establishment of an independent system operator; and * The contemplated restructuring of the Vermont electric industry to introduce competition. 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. NUCLEAR DECOMMISSIONING The staff of the SEC has questioned certain current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in financial statements. In response to these questions, the Financial Accounting Standards Board had agreed to review the accounting for closure and removal costs, including decommissioning. We do not believe that changes in such accounting, if required, would have an adverse effect on the results of operations due to our current and future ability to recover decommissioning costs through rates. EFFECTS OF INFLATION Financial statements are prepared in accordance with generally accepted accounting principles and report operating results in terms of historic costs. This method of 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. 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.
At March 31, 2001 Fair value Market risk ------------------- ------------- In thousands Highest long position . $ 86,993 $ 8,699 Highest short position. $ 116,841 $ 11,684 Average position(short) $ (29,848) $ (2,985)
PART II ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K The following filings on Form 8-K were filed by the Company on the topics and dates indicated: April 17, 2001 Form 8-K announced the decision reached by the arbitration tribunal in the Company's arbitration with Hydro-Quebec regarding ice-storm related delivery failure. The arbitration tribunal decided the VJO/Hydro-Quebec power supply contract remains in effect and Hydro-Quebec is required to continue to provide capacity and energy to the Company under the terms of the VJO contract, which expires in 2015, and Hydro-Quebec is required to return certain capacity payments to the Company. May 1, 2001 Form 8-K announced the upgrade in credit rating by Fitch. Fitch upgraded credit ratings for the company's first mortgage bonds from BB+ to BBB, and preferred stock from B+ to BBB- following the favorable rate order approved by the VPSB in January 2001. ------ 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: May 10, 2001 /s/ NANCY ROWDEN BROCK ------------------------- Nancy Rowden Brock, Vice President, Chief Financial Officer, Secretary, and Treasurer Date: May 10, 2001 /s/ROBERT J. GRIFFIN ---------------------- Robert J. Griffin, Controller -----END PRIVACY-ENHANCED MESSAGE-----