-----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, DvNyUaCH5KHb8HV/85sIut9sbFovN2UHHrsWAMA8Nyhonfn9TRCRjvgJ+euZYJ/2 Nw07qB6LTfzf/e0HEBuJEg== 0000043704-98-000006.txt : 19980330 0000043704-98-000006.hdr.sgml : 19980330 ACCESSION NUMBER: 0000043704-98-000006 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980327 SROS: NYSE 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-K SEC ACT: SEC FILE NUMBER: 001-08291 FILM NUMBER: 98575222 BUSINESS ADDRESS: STREET 1: 25 GREEN MOUNTAIN DR STREET 2: P.O.BOX 850 CITY: SOUTH BURLINGTON STATE: VT ZIP: 05402-0850 BUSINESS PHONE: 8028645731 MAIL ADDRESS: STREET 1: 25 GREEN MOUNTAIN DR STREET 2: P O BOX 850 CITY: SOUTH BURLINGTON STATE: VT ZIP: 05402-0850 10-K 1 SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K _X_ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 ___ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ________________ to __________________ For the fiscal year ended December 31, 1997 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 (I.R.S. Employer Identification No.) incorporation or organization) 25 Green Mountain Drive South Burlington, VT 05403 _________________________________ __________ (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (802) 864-5731 __________________________ Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of each exchange on which registered COMMON STOCK, PAR VALUE NEW YORK STOCK EXCHANGE $3.33-1/3 PER SHARE ________________________________________________________________________ Securities registered pursuant to Section 12 (g) of the Act: None ________________________________________________________________________ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes __X__ No _____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. _X_ The aggregate market value of the voting stock held by non- affiliates of the registrant as of March 13, 1998, was $94,094,396.88 based on the closing price for the Common Stock on the New York Stock Exchange as reported by The Wall Street Journal. The number of shares of Common Stock outstanding on March 13, 1998, was 5,191,415. DOCUMENTS INCORPORATED BY REFERENCE The Company's Definitive Proxy Statement relating to its Annual Meeting of Stockholders to be held on May 21, 1998, to be filed with the Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, is incorporated by reference in Items 10, 11, 12 and 13 of Part III of this Form 10-K. PART I ITEM 1. BUSINESS THE COMPANY Green Mountain Power Corporation (the Company) is a public utility operating company engaged in supplying electrical energy in the State of Vermont in a territory with approximately one quarter of the State's population. It serves approximately 83,000 customers. The Company was incorporated under the laws of the State of Vermont on April 7, 1893. For the year ended December 31, 1997, the Company's sources of revenue were derived as follows: 34.3% from residential customers, 32.7% from small commercial and industrial customers, 21.1% from large commercial and industrial customers, 10.0% from sales to other utilities, and 1.9% from other sources. For the same period, the Company's energy resources for retail and requirements wholesale sales were obtained as follows: 46.9% from hydroelectric sources (6.9% Company-owned, 0.1% New York Power Authority (NYPA), 36.8% Hydro-Quebec and 3.1% small power producers), 36.5% from nuclear generating sources (the Vermont Yankee plant described below), 9.2% from coal sources, 3.3% from wood, 0.9% from natural gas, 0.5% from oil, and 0.3% from wind. The remaining 2.4% was purchased on a short-term basis from other utilities and through the New England Power Pool (NEPOOL). In 1997, the Company purchased 92.7% of the energy required to satisfy its retail and requirements wholesale sales (including energy purchased from Vermont Yankee and under other long-term purchase arrangements). See Note K of Notes to Consolidated Financial Statements. A major source of the Company's power supply is its entitlement to a share of the power generated by the 531-MW Vermont Yankee nuclear generating plant owned and operated by Vermont Yankee Nuclear Power Corporation (Vermont Yankee), in which the Company has a 17.9% equity interest. For information concerning Vermont Yankee, see "Power Resources - Vermont Yankee." The Company participates in NEPOOL, a regional bulk power transmission organization established to assure the reliability and economic efficiency of power supply in the Northeast. The Company's representative to NEPOOL is the Vermont Electric Power Company, Inc. (VELCO), a transmission consortium owned by the Company and other Vermont utilities, in which the Company has a 30% equity interest. As a member of NEPOOL, the Company benefits from increased efficiencies of centralized economic dispatch, availability of replacement power for scheduled and unscheduled outages of its own power sources, sharing of bulk transmission facilities and reduced generation reserve requirements. The principal territory served by the Company comprises an area roughly 25 miles in width extending 90 miles across north central Vermont between Lake Champlain on the west and the Connecticut River on the east. Included in this territory are the cities of Montpelier, Barre, South Burlington, Vergennes and Winooski, as well as the Village of Essex Junction and a number of smaller towns and communities. The Company also distributes electricity in four noncontiguous areas located in southern and southeastern Vermont that are interconnected with the Company's principal service area through the transmission lines of VELCO and others. Included in these areas are the communities of Vernon (where the Vermont Yankee plant is located), Bellows Falls, White River Junction, Wilder, Wilmington and Dover. The Company also supplies at wholesale a portion of the power requirements of several municipalities and cooperatives in Vermont and one utility in another state. The Company is obligated to meet the changing electrical requirements of these wholesale customers, in contrast to the Company's obligation to other wholesale customers, which is limited to specified amounts of capacity and energy established by contract. Major business activities in the Company's service areas include computer assembly and components manufacturing (and other electronics manufacturing), granite fabrication, service enterprises such as government, insurance and tourism (particularly winter recreation), and dairy and general farming. During the years ended December 31, 1997, 1996, and 1995, electric energy sales to International Business Machines Corporation (IBM), the Company's largest customer, accounted for 14.0%, 13.2% and 12.9%, respectively, of the Company's operating revenues in those years. No other retail customer accounted for more than 1.0% of the Company's revenue. Under the present regulatory system, the loss of IBM as a customer of the Company would require the Company to seek rate relief to recover the revenues previously paid by IBM from other customers in an amount sufficient to offset the fixed costs that IBM had been covering through its payments. EMPLOYEES The Company had 321 employees, exclusive of temporary employees, as of December 31, 1997. In addition, subsidiaries of the Company had 48 employees at year end. SEASONAL NATURE OF BUSINESS The Company experiences its heaviest loads in the colder months of the year. Winter recreational activities, longer hours of darkness and heating loads from cold weather usually cause the Company's peak electric sales to occur in December, January or February. The Company's heaviest load in 1997 - 311.5 MW - occurred on December 22, 1997. The Company's retail electric rates are seasonally differentiated. Under this structure, retail electric rates produce average revenues per kilowatt hour during four peak season months (December through March) that are approximately 30% higher than during the eight off-season months (April through November). See "Energy Efficiency - Rate Design."
OPERATING STATISTICS For the Years Ended December 31 1997 1996 1995 1994 1993 ---------- ---------- ---------- ---------- ---------- Net System Capability During Peak Month (MW) Hydro (1)............................................ 180.0 193.8 152.1 179.0 174.9 Lease transmissions.................................. 0.6 0.6 0.3 2.1 3.9 Nuclear (1).......................................... 95.7 95.7 81.9 107.2 109.5 Conventional steam................................... 53.0 52.9 77.8 67.1 92.6 Internal combustion.................................. 64.0 60.7 62.0 60.2 71.0 Combined cycle....................................... 22.1 22.1 22.0 22.6 22.8 Wind................................................. 1.5 -- -- -- -- ---------- ---------- ---------- ---------- ---------- Total capability (MW).............................. 416.9 425.8 396.1 438.2 474.7 Net system peak...................................... 311.5 313.0 297.1 308.3 307.3 ---------- ---------- ---------- ---------- ---------- Reserve (MW)......................................... 105.4 112.8 99.0 129.9 167.4 ========== ========== ========== ========== ========== Reserve % of peak.................................... 33.8% 36.0% 33.3% 42.1% 54.5% Net Production (MWH) Hydro (1)............................................1,073,246 1,192,881 1,043,617 742,088 751,078 Lease transmissions.................................. -- -- -- -- 15,425 Nuclear (1).......................................... 772,030 680,613 682,814 763,690 598,245 Conventional steam................................... 560,504 705,331 673,982 651,105 748,626 Internal combustion.................................. 4,827 2,674 6,646 3,532 2,849 Combined cycle....................................... 104,836 51,162 92,723 37,808 40,966 ---------- ---------- ---------- ---------- ---------- Total production...................................2,515,443 2,632,661 2,499,782 2,198,223 2,157,189 Less non-requirements sales to other utilities....... 524,192 663,175 582,942 328,794 271,224 ---------- ---------- ---------- ---------- ---------- Production for requirements sales....................1,991,251 1,969,486 1,916,840 1,869,429 1,885,965 Less requirements sales & lease transmissions (MWH)..1,870,913 1,814,371 1,760,830 1,730,497 1,749,454 ---------- ---------- ---------- ---------- ---------- Losses and company use (MWH)......................... 120,338 155,115 156,010 138,932 136,511 ========== ========== ========== ========== ========== Losses as a percentage of total production............. 4.78% 5.89% 6.24% 6.32% 6.33% System load factor (2)................................. 71.6% 69.7% 71.2% 67.7% 68.7% Sales and Lease Transmissions (MWH) Residential - GMP.................................... 549,259 557,726 549,296 564,635 541,579 Lease transmissons................................... -- -- -- -- 15,425 ---------- ---------- ---------- ---------- ---------- Total Residential.................................. 549,259 557,726 549,296 564,635 557,004 Commercial & industrial - small...................... 645,331 630,839 608,688 604,686 593,560 Commercial & industrial - large...................... 608,051 584,249 556,278 521,400 529,372 Other................................................ 3,939 2,898 8,855 1,146 8,868 ---------- ---------- ---------- ---------- ---------- Total retail sales and lease transmissions.........1,806,580 1,775,712 1,723,117 1,691,867 1,688,804 Sales to municipals and cooperatives and other requirements sales........................... 64,333 38,659 37,713 38,630 60,650 ---------- ---------- ---------- ---------- ---------- Total requirements sales...........................1,870,913 1,814,371 1,760,830 1,730,497 1,749,454 Other sales for resale............................... 524,192 663,175 582,942 328,794 271,224 ---------- ---------- ---------- ---------- ---------- Total sales and lease transmissions................2,395,105 2,477,546 2,343,772 2,059,291 2,020,678 ========== ========== ========== ========== ========== Average Number of Electric Customers Residential.......................................... 70,671 70,198 69,659 68,811 67,994 Commercial and industrial - small.................... 11,989 11,828 11,712 11,611 11,447 Commercial and industrial - large.................... 23 25 24 24 25 Other................................................ 75 75 76 76 74 ---------- ---------- ---------- ---------- ---------- Total.............................................. 82,758 82,126 81,471 80,522 79,540 ========== ========== ========== ========== ========== Average Revenue per KWH (Cents) Residential including lease revenues................. 11.18 10.87 10.09 9.03 8.94 Lease charges........................................ -- -- -- -- 0.06 ---------- ---------- ---------- ---------- ---------- Total Residential.................................. 11.18 10.87 10.09 9.03 9.00 Commercial and industrial - small.................... 9.10 8.96 8.42 8.00 7.97 Commercial and industrial - large.................... 6.22 6.28 5.86 6.02 5.96 Total retail including lease revenues................ 8.94 8.92 8.36 7.96 7.86 Average Use and Revenue Per Residential Customer Kilowatt hours including lease transmissions......... 7,772 7,945 7,885 8,206 8,192 Revenues including lease revenues.................... $869 $863 $796 $741 $733 (1) See Note K of Notes to Consolidated Financial Statements. (2) Load factor is based on net system peak and firm MWH production less off-system losses.
STATE AND FEDERAL REGULATION General. The Company is subject to the regulatory authority of the Vermont Public Service Board (VPSB), which extends to retail rates, services, facilities, securities issues and various other matters. The separate Vermont Department of Public Service (the Department), created by statute in 1981, is responsible for development of energy supply plans for the State of Vermont (the State), purchases of power as an agent for the State and other general regulatory matters. The VPSB is principally responsible for quasi-judicial proceedings, such as rate proceedings. The Department, through a Director for Public Advocacy, is entitled to participate as a litigant in such proceedings and regularly does so. The Company's rate tariffs are uniform throughout its service area. The Company has entered into two economic development agreements, providing for reduced charges to large customers to be applied only to new load. A third economic development agreement with IBM was part of the rate settlement approved by the VPSB on May 23, 1996. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) - "Results of Operations - Operating Revenues and MWh Sales." The Company's wholesale rate on sales to three wholesale customers is regulated by the Federal Energy Regulatory Commission (FERC). Revenues from sales to these customers were approximately 0.8% of operating revenues for 1997. Late in 1989, the Company began serving a municipal utility, Northfield Electric Department, under its wholesale tariff. This customer increased the Company's electricity sales by approximately 23,406.4 MWh and peak requirements by approximately 5.5 MW. Revenues in 1997 from Northfield were $1,348,962. The Company provides transmission service to twelve customers within the State under rates regulated by the FERC; revenues for such services amounted to less than 1.0% of the Company's operating revenues for 1997. On April 24, 1996, the FERC issued Orders 888 and 889 which among other things required the filing of open access transmission tariffs by electric utilities. See Item 7. MD&A - "Transmission Issues - Federal Open Access Tariff Orders." NEPOOL has proposed a transmission tariff for certain transmission facilities, including certain facilities between New York and New England, that incorporates a load-based method of capacity allocation for NEPOOL transmission facilities. The proposal could reduce the amount of capacity available to the Company from such facilities in the future. See Item 7. MD&A - "Transmission Issues - Proposed NEPOOL Transmission Tariff." By reason of its relationship with Vermont Yankee, VELCO and Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned subsidiary of VELCO, the Company has filed an exemption statement under Section 3(a)(2) of the Public Utility Holding Company Act of 1935, thereby securing exemption from the provisions of such Act, except for Section 9(a)(2) thereof (which prohibits the acquisition of securities of certain other utility companies without approval of the Securities and Exchange Commission). The Securities and Exchange Commission has the power to institute proceedings to terminate such exemption for cause. Licensing. Pursuant to the Federal Power Act, the FERC has granted licenses for the following hydro projects: Project Issue Date Period - ------- ---------- ------ Bolton February 5, 1982 February 5, 1982 - February 4, 2022 Essex March 30, 1995 March 1, 1995 - March 1, 2025 Vergennes June 29, 1979 June 1, 1949 - May 31, 1999 Waterbury July 20, 1954 September 1, 1951 - August 31, 2001 Major project licenses provide that after an initial twenty-year period, a portion of the earnings of such project in excess of a specified rate of return is to be set aside in appropriated retained earnings in compliance with FERC Order #5, issued in 1978. Although the twenty-year periods expired in 1985, 1969 and 1971 in the cases of the Essex, the Vergennes and the Waterbury projects, the amounts appropriated are not material. Department of Public Service Twenty-Year Power Plan. In December 1994, the Department adopted an update of its twenty-year electrical power-supply plan (the Plan) for the State. The Plan includes an overview of statewide growth and development as they relate to future requirements for electrical energy; an assessment of available energy resources; and estimates of future electrical energy demand. The Company's Integrated Resource Plan (IRP) was published in June 1996. It was developed in a manner consistent with the Department's Plan. The Company's 1996 IRP calls for a greater emphasis on distributed utility approaches that can best use the Company's assets, maximize the benefit of energy efficiency programs, and provide customers with the highest quality service. RECENT RATE DEVELOPMENTS On June 16, 1997, the Company filed a request with the VPSB to increase retail rates by 16.7 percent and the target return on common equity from 11.25 percent to 13 percent. The retail rate increase is needed to cover higher power supply costs and the Company's rising cost of capital. For further information regarding recent rate developments, see Item 7. MD&A - "Liquidity and Capital Resources - Rates" and Note I.5 of Notes to Consolidated Financial Statements. COMPETITION AND RESTRUCTURING Electric utilities historically have had exclusive franchises for the retail sale of electricity in specified service territories. Legislative authority has existed since 1941 that would permit Vermont cities, towns and villages to own and operate public utilities. Since that time, no municipality served by the Company has established or, as far as is known to the Company, is presently taking steps to establish, a municipal public utility. In 1987, the Vermont General Assembly enacted legislation that authorized the Department to sell electricity on a significantly expanded basis. Before the new law was passed, the Department's authority to make retail sales had been limited. It could sell at retail only to residential and farm customers and could sell only power that it had purchased from the Niagara and St. Lawrence projects operated by the New York Power Authority. Under the law, the Department can sell electricity purchased from any source at retail to all customer classes throughout the state, but only if it convinces the VPSB and other state officials that the public good will be served by such sales. The Department has made limited additional retail sales of electricity. The Department retains its traditional responsibilities of public advocacy before the VPSB, and electricity planning on a statewide basis. Regulatory and legislative authorities at the federal level and among states across the country, including Vermont, are considering how to restructure the electric industry to facilitate competition for electricity sales at wholesale and retail levels. For further information regarding Competition and Restructuring, See Item 7. MD&A - "Future Outlook." POWER RESOURCES The Company generated, purchased or transmitted 1,954,535.9 MWh of energy for retail and requirements wholesale customers for the twelve months ended December 31, 1997. The corresponding maximum one-hour integrated demand during that period was 311.5 MW on December 22, 1997. This compares to the previous all-time peak of 322.6 MW on December 27, 1989. The following tabulation shows the source of such energy for the twelve-month period and the capacity in the month of the period system peak. See also "Power Resources - Long-Term Power Sales." Net Generated and Net Generated and Purchased in Year Purchased in Month Ended 12/31/97 (a) of Annual Peak ___________________ ___________________ MWh % KW % WHOLLY OWNED PLANTS Hydro 140,754.0 6.9 35,300 8.5 Diesel and Gas Turbine 2,671.7 0.1 61,030 14.6 Searsburg 5,386.7 0.3 1,500 0.4 JOINTLY OWNED PLANTS Wyman #4 3,386.1 0.2 7,030 1.7 Stony Brook I 7,339.2 0.4 7,990 1.9 McNeil 11,075.7 0.5 6,450 1.5 OWNED IN ASSOCIATION W/OTHERS Vermont Yankee Nuclear 748,068.8 36.5 95,680 22.9 NYPA LEASE TRANSMISSIONS State of Vermont (NYPA) 1,541.9 0.1 620 0.1 LONG-TERM PURCHASES Hydro-Quebec 754,280.5 36.8 126,680 30.4 Merrimack #2 189,033.1 9.2 31,820 7.6 Stony Brook I 14,647.2 0.7 14,150 3.4 Small Power Producers 121,938.4 5.9 24,860 6.0 SHORT-TERM PURCHASES 52,185.9 2.4 3,860 1.0 ___________ ____ _______ _____ 2,052,309.2 100.0 Less System Sales Energy (97,773.8) NET OWN LOAD 1,954,535.4 416,970 100.0 =========== ====== ======= ====== (a) Excludes losses on off-system purchases, totaling 36,716 MWh per GA- 35 MWh production report. Vermont Yankee. The Company and Central Vermont Public Service Corporation acted as lead sponsors in the construction of the Vermont Yankee nuclear plant, a boiling-water reactor designed by General Electric Company. The plant, which became operational in 1972, has a generating capacity of 531 MW. Vermont Yankee has entered into power contracts with its sponsor utilities, including the Company, that expire at the end of the life of the unit. Pursuant to its Power Contract, the Company is required to pay 20% of Vermont Yankee's operating expenses (including depreciation and taxes), fuel costs (including charges in respect of estimated costs of disposal of spent nuclear fuel), decommissioning expenses, interest expense and return on common equity, whether or not the Vermont Yankee plant is operating. In 1969, the Company sold to other Vermont utilities a share of its entitlement to the output of Vermont Yankee. Accordingly, those utilities had an obligation to the Company to pay 2.735% of Vermont Yankee's operating expenses, fuel costs, decommissioning expenses, interest expense and return on common equity. As a result of the bankruptcy of one of those utilities, a portion of the entitlement has reverted back to the Company. Accordingly, those utilities have an obligation to the Company to pay 2.338% of Vermont Yankee's operating expenses, fuel costs, decommissioning expenses, interest expense and return on common equity. Vermont Yankee has also entered into capital funds agreements with its sponsor utilities that expire on December 31, 2002. Under its Capital Funds Agreement, the Company is required, subject to obtaining necessary regulatory approvals, to provide 20% of the capital requirements of Vermont Yankee not obtained from outside sources. On April 27, 1989, Vermont Yankee applied to the Nuclear Regulatory Commission (NRC) for an amendment to its operating license to extend the expiration date from December 2007 to March 2012, in order to take advantage of current NRC policy to issue operating licenses for a 40- year term measured from the grant of the operating license. Prior NRC policy, under which the operating license was issued, called for a term of 40 years from the date of the construction permit. On August 22, 1989, the State, opposing the license extension, filed a request for a hearing and petition for leave to intervene, which petition was subsequently granted. On December 17, 1990, the NRC issued an amendment to the operating license extending the expiration date to March 21, 2012, based upon a "no significant hazards" finding by the NRC staff and subject to the outcome of the evidentiary hearing on the State's assertions. On July 31, 1991, Vermont Yankee reached a settlement with the State, and the State filed a withdrawal of its intervention. The proceeding was dismissed on September 3, 1991. In New England, five nuclear units are currently under orders from the NRC not to operate until shown to be in compliance with applicable safety provisions. In December 1996 and August 1997, decisions were made to retire two New England nuclear units, Connecticut Yankee and Maine Yankee, effective immediately, with several years remaining on each license. The NRC's most recently issued Vermont Yankee's Systematic Assessment of Licensee Performance scores are for the period July 16, 1995 to January 18, 1997. Operations, engineering and maintenance were rated good, while plant support was rated superior. These scores are identical to Vermont Yankee's scores for the prior 18 month-period. During periods when Vermont Yankee is unavailable, the Company incurs replacement power costs in excess of those costs that the Company would have incurred for power purchased from Vermont Yankee. Replacement power is available to the Company from NEPOOL and through special contractual arrangements with other utilities. Replacement power costs adversely affect cash flow and, absent deferral, amortization and recovery through rates, would adversely affect reported earnings. Routinely, in the case of scheduled outages for refueling, the VPSB has permitted the Company to defer, amortize and recover these excess replacement power costs for financial reporting and ratemaking purposes over the period until the next scheduled outage. Vermont Yankee has adopted an 18-month refueling schedule. On March 21, 1998, Vermont Yankee began a scheduled refueling outage. In the case of unscheduled outages of significant duration resulting in substantial unanticipated costs for replacement power, the VPSB generally has authorized deferral, amortization and recovery of such costs. Vermont Yankee's current estimate of decommissioning as approved by FERC is approximately $386,000,000, of which $193,000,000 has been funded. At December 31, 1997, the Company's portion of the net unfunded liability was $34,000,000, which it expects will be recovered through rates over Vermont Yankee's remaining operating life. During 1997, the Company incurred $27,200,000 in Vermont Yankee annual capacity charges, which included $1,800,000 for interest charges. The Company's share of Vermont Yankee's long-term debt at December 31, 1997 was $16,000,000. During the year ended December 31, 1997, the Company utilized 748,068.8 MWh of Vermont Yankee energy to meet 36.5% of its retail and requirements wholesale (Rate W) sales. The average cost of Vermont Yankee electricity in 1997 was 4.4 cents per KWh. In 1997, Vermont Yankee had an annual capacity factor of 93.5%, compared to 83.0% in 1996 and 85.0% in 1995. INSURANCE The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Any liability beyond $8.9 billion are indemnified under an agreement with the NRC, but subject to congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing premiums of $79.3 million against each of the 110 reactor units in the United States that are currently subject to the Progam, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is expected to be adjusted at least every five years to reflect inflationary changes. The above insurance now covers all workers employed at nuclear facilities for bodily injury claims. Vermont Yankee had previously purchased a Master Worker insurance policy with limits of $200 million with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee no longer participates in this retrospectively based worker policy and has replaced this policy with the guaranteed cost coverage mentioned above. Vermont Yankee does, however, retain a potential obligation for retrospective adjustments due to past operations of several smaller facilities that did not join the new program. These exposures will cease to exist no later than December 31, 2007. Vermont Yankee's maximum restrospective obligation remains at $3.1 million. The Secondary Financial Protection layer, as referenced above, would be in excess of the Master Worker policy. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover the costs of property damage, decontanmination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available. The maximum potential assessment against Vermont Yankee with respect to NEIL losses arising during the current policy year is $11.0 million. Vermont Yankee's liability for the retrospective premium adjustment for any policy year ceases six years after the end of that policy year unless prior demand has been made. HYDRO-QUEBEC Highgate Interconnection. On September 23, 1985, the Highgate transmission facilities, which were constructed to import energy from Hydro-Quebec in Canada, began commercial operation. The transmission facilities at Highgate include a 225-MW AC-to-DC-to-AC converter terminal and seven miles of 345-kV transmission line. VELCO built and operates the converter facilities, which are jointly owned by a number of Vermont utilities, including the Company. NEPOOL/Hydro-Quebec Interconnection. VELCO and certain other NEPOOL members have entered into agreements with Hydro-Quebec providing for the construction in two phases of a direct interconnection between the electric systems in New England and the electric system of Hydro- Quebec in Canada. The Vermont participants in this project, which has a capacity of 2,000 MW, will derive about 9.0% of the total power-supply benefits associated with the NEPOOL/Hydro-Quebec interconnection. The Company, in turn, receives about one-third of the Vermont share of those benefits. The benefits of the interconnection include access to surplus hydroelectric energy from Hydro-Quebec at a cost below that of the replacement cost of power and energy otherwise available to the New England participants; energy banking, under which participating New England utilities will transmit relatively inexpensive energy to Hydro- Quebec during off-peak periods and will receive equal amounts of energy, after adjustment for transmission losses, from Hydro-Quebec during peak periods when replacement costs are higher; and provision for emergency transfers and mutual backup to improve reliability for both the Hydro- Quebec system and the New England systems. Phase I. The first phase (Phase I) of the NEPOOL/Hydro-Quebec Interconnection consists of transmission facilities having a capacity of 690 MW that traverse a portion of eastern Vermont and extend to a converter terminal located in Comerford, New Hampshire. These facilities entered commercial operation on October 1, 1986. VETCO was organized to construct, own and operate those portions of the transmission facilities located in Vermont. Total construction costs incurred by VETCO for Phase I were $47,850,000. Of that amount, VELCO provided $10,000,000 of equity capital to VETCO through sales of VELCO preferred stock to the Vermont participants in the project. The Company purchased $3,100,000 of VELCO preferred stock to finance the equity portion of Phase I. The remaining $37,850,000 of construction cost was financed by VETCO's issuance of $37,000,000 of long-term debt in the fourth quarter of 1986 and the balance of $850,000 was financed by short-term debt. Under the Phase I contracts, each New England participant, including the Company, is required to pay monthly its proportionate share of VETCO's total cost of service, including its capital costs, as well as a proportionate share of the total costs of service associated with those portions of the transmission facilities constructed in New Hampshire by a subsidiary of New England Electric System. Phase II. Agreements executed in 1985 among the Company, VELCO and other NEPOOL members and Hydro-Quebec provided for the construction of the second phase (Phase II) of the interconnection between the New England Electric System and that of Hydro-Quebec. Phase II expands the Phase I facilities from 690 MW to 2,000 MW, and provides for transmission of Hydro-Quebec power from the Phase I terminal in northern New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II commenced in 1988 and was completed in late 1990. The Phase II facilities commenced commercial operation November 1, 1990, initially at a rating of 1,200 MW, and increased to a transfer capability of 2,000 MW in July 1991. The Hydro-Quebec-NEPOOL Firm Energy Contract provides for the import of economical Hydro-Quebec energy into New England. The Company is entitled to 3.2% of the Phase II power-supply benefits. Total construction costs for Phase II were approximately $487,000,000. The New England participants, including the Company, have contracted to pay monthly their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. As a supporting participant, the Company must make support payments under 30-year agreements. These support agreements meet the capital lease accounting requirements under SFAS 13. At December 31, 1997, the present value of the Company's obligation was $8,300,000. The Company's projected future minimum payments under the Phase II support agreements are $463,450 for each of the years 1998-2002 and an aggregate of $6,024,845 for the years 2003-2020. The Phase II portion of the project is owned by New England Hydro- Transmission Electric Company, Inc. and New England Hydro-Transmission Corporation, subsidiaries of New England Electric System, in which certain of the Phase II participating utilities, including the Company, own equity interests. The Company owns approximately 3.2% of the equity of the corporations owning the Phase II facilities. During construction of the Phase II project, the Company, as an equity sponsor, was required to provide equity capital. At December 31, 1997, the capital structure of such corporations was 39.0% common equity and 61.0% long-term debt. See Note J of Notes to Consolidated Financial Statements. At times, the Company requests that portions of its power deliveries from Hydro-Quebec and other sources be routed through New York. The Company's ability to do so could be adversely affected by the proposed tariff that NEPOOL has filed with the FERC. A reduction of the Company's allocation of capacity on transmission interfaces with New York could adversely affect the Company's ability to import power to Vermont from outside New England which would impact the Company's power costs in the future. See Item 7. MD&A - "Transmission Issues" and Note J of Notes to Consolidated Financial Statements. Hydro-Quebec Power Supply Contracts. Under an arrangement negotiated in January 1996, the Company received cash payments from Hydro-Quebec of $3,000,000 in 1996 and $1,100,000 in 1997. In accordance with such arrangement, the Company will shift certain transmission requirements and make certain minimum payments for periods in which power is not purchased. In addition, in November 1996, the Company entered into a Memorandum of Understanding with Hydro-Quebec under which Hydro-Quebec paid $8,000,000 to the Company in exchange for certain power purchase elections. See Item 7. MD&A - "Power Supply Expenses" and Notes J and K-2 of Notes to Consolidated Financial Statements. In 1997, the Company utilized 405,383.2 MWh under Schedule B, 276,031.2 MWh under Schedule C3, and 72,866.1 MWh under the tertiary energy contract to meet 36.8% of its retail and requirements wholesale sales. The average cost of Hydro-Quebec electricity in 1997 was 3.7 cents per KWh. New York Power Authority (NYPA). The Department allocates NYPA power to the Company which, in turn, delivers the power to its residential and farm customers. The Company purchased at wholesale 1,541.9 MWh to meet 0.1% of its retail and requirements wholesale sales of NYPA power at an average cost of 0.7 cents per KWh in 1997. Under the allocation currently made by NYPA of NYPA power to states neighboring New York, residential and farm customers in the Company's service territory will be entitled to 0.3 MW annually. Merrimack Unit #2. Merrimack Unit #2 is a coal-fired steam plant of 320.0 MW capacity located in Bow, New Hampshire, and owned by Northeast Utilities. The Company is entitled to 28.48 MW of capacity and related energy from the unit under a 30-year contract expiring May 1, 1998. During the year ended December 31, 1997, the Company utilized 189,033.1 MWh from the unit to meet 9.2% of its total retail and requirements wholesale sales. The average cost of electricity from this unit was 3.4 cents per KWh in 1997. See Note K-1 of Notes to Consolidated Financial Statements. Stony Brook I. The Massachusetts Municipal Wholesale Electric Company (MMWEC) is principal owner and operator of Stony Brook, a 352.0- MW combined-cycle intermediate generating station located in Ludlow, Massachusetts, which commenced commercial operation in November 1981. The Company entered into a Joint Ownership Agreement with MMWEC dated as of October 1, 1977, whereby the Company acquired an 8.8% ownership share of the plant, entitling the Company to 31.0 MW of capacity. In addition to this entitlement, the Company has contracted for 14.2 MW of capacity for the life of the Stony Brook I plant, for which it will pay a proportionate share of MMWEC's share of the plant's fixed costs and variable operating expenses. The three units that comprise Stony Brook I are primarily oil-fired. Two of the units are also capable of burning natural gas. The natural gas system at the plant was modified in 1985 to allow two units to operate simultaneously on natural gas. During 1997, the Company utilized 21,986.4 MWh from this plant to meet 1.1% of its retail and requirements wholesale sales at an average cost of 9.5 cents (purchased power). See Note I-4 and K-1 of Notes to Consolidated Financial Statements. Wyman Unit #4. The W. F. Wyman Unit #4, which is located in Yarmouth, Maine, is an oil-fired steam plant with a capacity of 620 MW. The construction of this plant was sponsored by Central Maine Power Company. The Company has a joint-ownership share of 1.1% (6.8 MW) in the Wyman #4 unit, which began commercial operation in December 1978. During 1997, the Company utilized 3,386.1 MWh from this unit to meet 0.2% of its retail and requirements wholesale sales at an average cost of 4.7 per kWh, based only on operation, maintenance, and fuel costs incurred during 1997. See Note I-4 of Notes to Consolidated Financial Statements. McNeil Station. The J. C. McNeil station, which is located in Burlington, Vermont, is a wood chip and gas-fired steam plant with a capacity of 53.0 MW. The Company has an 11% or 5.9 MW interest in the J. C. McNeil plant, which began operation in June 1984. During 1997, the Company utilized 11,075.7 MWh from this unit to meet 0.5% of its retail and requirements wholesale sales at an average cost of 5.2 cents per kWh, based only on operation, maintenance, and fuel costs incurred during 1997. In 1989, the plant added the capability to burn natural gas on an as-available/interruptible service basis. See Note I-4 of Notes to Consolidated Financial Statements. Small Power Production. The VPSB has adopted rules that implement for Vermont the purchase requirements established by federal law in the Public Utility Regulatory Policies Act of 1978 (PURPA). Under the rules, qualifying facilities have the option to sell their output to a central state purchasing agent under a variety of long- and short-term, firm and non-firm pricing schedules, each of which is based upon the projected Vermont composite system's power costs which would be required but for the purchases from small producers. The state purchasing agent assigns the energy so purchased, and the costs of purchase, to each Vermont retail electric utility based upon its pro rata share of total Vermont retail energy sales. Utilities may also contract directly with producers. The rules provide that all reasonable costs incurred by a utility under the rules will be included in the utilities' revenue requirements for ratemaking purposes. Currently, the state purchasing agent, Vermont Electric Power Producers, Inc. (VEPPI), is authorized to seek 150 MW of power from qualifying facilities under PURPA, of which the Company's current pro rata share would be approximately 32.7% or 49.1 MW. The rated capacity of the qualifying facilities currently selling power to VEPPI is approximately 74 MW. These facilities were all online by the spring of 1993, and no other projects are under development. The Company does not expect any new projects to come online in the foreseeable future because the excess capacity in the region has eliminated the need for and value of additional qualifying facilities. In 1997, the Company, through both its direct contracts and VEPPI, purchased 121,938.4 MWh of qualifying facilities production to meet 5.9% of its retail and requirements wholesale sales at an average cost of 10.7 cents per KWh. Short-Term Opportunity Purchases and Sales. The Company has made arrangements with several utilities in New England and New York under which the Company may make purchases or sales of utility system power on short notice and generally for brief periods of time when it appears economic to do so. Opportunity purchases are arranged when it is possible to purchase power from another utility for less than it would cost the Company to generate the power with its own sources. Purchases also help the Company save on replacement power costs during an outage of one of its base load sources. Opportunity sales are arranged when the Company has surplus energy available at a price that is economic to other regional utilities at any given time. The sales are arranged based on forecasted costs of supplying the incremental power necessary to serve the sale. Prices are set so as to recover all of the forecasted fuel or production costs and to recover some if not all associated capacity costs. During 1997, the Company purchased 52,185.9 MWh, meeting 2.4% of the Company's retail and requirements wholesale sales, at an average cost of 2.7 cents per kWh. NEPOOL. As a participant of NEPOOL, through VELCO, the Company takes advantage of pool operations with central economic dispatch of participants' generating plants, pooling of transmission facilities and economy and emergency exchange of energy and capacity. The NEPOOL agreement also imposes obligations on the Company to maintain a generating capacity reserve as set by NEPOOL, but which is lower than the reserve which would be required if the Company were not a NEPOOL participant. Company Hydroelectric Power. The Company wholly owns and operates eight hydroelectric generating facilities located on river systems within its service area, the largest of which has a generating output of 8.8 MW. In 1997, these plants provided 140,754 MWh of low-cost energy, meeting 6.9% of the Company's retail and requirements wholesale sales at an average cost of 4.2 cents per kWh, based on total embedded costs. See "State and Federal Regulation - Licensing." VELCO. The Company, together with six other Vermont electric distribution utilities, owns VELCO. Since commencing operation in 1958, VELCO has transmitted power for its owners in Vermont, including power from NYPA and other power contracted for by Vermont utilities. VELCO also purchases bulk power for resale at cost to its owners, and as a member of NEPOOL, represents all Vermont electric utilities in pool arrangements and transactions. See Note B of Notes to Consolidated Financial Statements. Long-Term Power Sales. In 1986, the Company entered into an agreement for the sale to United Illuminating of 23 MW of capacity produced by the Stony Brook I combined-cycle plant for a 12-year period commencing October 1, 1986. The agreement provides for the recovery by the Company of all costs associated with the capacity and energy sold. Fuel. During 1997, the Company's retail and requirements wholesale sales were provided by the following fuel sources: 46.9% from hydro (6.9% Company-owned, 0.1% NYPA, 36.8% Hydro-Quebec and 3.1% small power producers), 36.5% from nuclear, 9.2% from coal, 3.3% from wood, 0.9% from natural gas, 0.5% from oil, and 0.3% from wind. The remaining 2.4% was purchased on a short-term basis from other utilities and through NEPOOL. Vermont Yankee has approximately $133,000,000 of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow Vermont Yankee to cancel or postpone deliveries until actually needed. Vermont Yankee has a contract with the United States Department of Energy (DOE) for the permanent disposal of spent nuclear fuel. Under the terms of this contract, in exchange for the one-time fee discussed below and a quarterly fee of 1 mil per KWh of electricity generated and sold, the DOE agrees to provide disposal services when a facility for spent nuclear fuel and other high-level radioactive waste is available, which is required by contract to be prior to January 31, 1998. The actual date for these disposal services is expected to be delayed many years. The DOE contract obligates Vermont Yankee to pay a one-time fee of approximately $39,300,000 for disposal costs for all spent fuel discharged through April 7, 1983. Although such amount has been collected in rates from the Vermont Yankee participants, Vermont Yankee has elected to defer payment of the fee to the DOE as permitted by the DOE contract. The fee must be paid no later than the first delivery of spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1996, Vermont Yankee accumulated approximately $78,000,000 in an irrevocable trust to be used exclusively for defeasing this obligation at some future date, provided the DOE complies with the terms of the aforementioned contract. The Company does not maintain long-term contracts for the supply of oil for the oil-fired peaking unit generating stations wholly owned by it (80 MW). The Company did not experience difficulty in obtaining oil for its own units during 1997, and, while no assurance can be given, does not anticipate any such difficulty during 1998. None of the utilities from which the Company expects to purchase oil- or gas-fired capacity in 1997 has advised the Company of grounds for doubt about maintenance of secure sources of oil and gas during the year. Coal for Merrimack #2 is presently being purchased under a long- term contract from Balley Mine in western Pennsylvania and occasionally on the spot market from northern West Virginia and southern Pennsylvania sources. Wood for the McNeil plant is furnished to the Burlington Electric Department from a variety of sources under short-term contracts ranging from several weeks' to six months' duration. The McNeil plant used 249,662 tons of wood chips and mill residue and 34,629,000 cubic feet of gas in 1997. The McNeil plant is forecasting consumption of wood chips for 1998 to be 200,000 tons and gas consumption of 136,000,000 cubic feet. The Stony Brook combined-cycle generating station is capable of burning either natural gas or oil in two of its turbines. Natural gas is supplied to the plant subject to its availability. During periods of extremely cold weather, the supplier reserves the right to discontinue deliveries to the plant in order to satisfy the demand of its residential customers. The Company assumes for planning and budgeting purposes that the plant will be supplied with gas during the months of April through November, and that it will run solely on oil during the months of December through March. The plant maintains an oil supply sufficient to meet approximately one-half of its annual needs. Wind Project. The Company's 20 years of research and development work in wind generation was recognized in 1993 when the Company was selected by the DOE and the Electric Power Research Institute (EPRI) to build a commercial scale wind-powered facility. The Company was awarded $3,500,000 by the DOE and EPRI to provide partial funding for the wind project. The overall cost of the project, located in the southern Vermont town of Searsburg , is estimated to be $11,000,000. The eleven wind turbines have a rating of 6 MW and were commissioned July 1, 1997. The Company is a utility leader in wind power research. The Company's extensive wind resource database shows that wind power is technically feasible and is becoming economically viable at other sites within Vermont. Several years of wind turbine operation at Mt. Equinox, Vermont, has provided the Company with valuable knowledge about the effects of icing and extreme cold on the performance of wind turbines, and the necessary adaptations for these conditions. The Searsburg wind project affords an opportunity to employ turbines that are of an advanced design and larger scale than the Mt. Equinox turbines. The economies of scale and advanced technology inherent in these turbines offer a more competitive and reliable source of power than earlier designs. First-hand knowledge about these turbines in Vermont's climatic conditions will enable the Company to make intelligent and timely decisions about this power resource, which can be installed in increments that closely match the need for power. Furthermore, the project's size and northerly location will boost the commercialization of wind power by deploying a new model of turbines in sufficient quantities to obtain statistically valid operations and maintenance data, which will be shared with other utilities. Finally, information related to the siting, permitting, and possible impacts on the natural environment will also be documented and shared with the industry and the public. The Company estimates that the wind project will cause rates to rise less than one-half of 1% in the first several years of the project. Early in the next century, however, the Company projects that electricity from wind energy will cost less than comparable power from other sources. Over the life of the project, the average cost of electricity from the wind farm, which provides electricity at times of peak demand for the Company, is expected to be competitive with the cost of alternatives in the market. In 1997, the plant provided 5,387 MWh, meeting 0.3% of the Company's retail and requirements wholesale sales. ENERGY EFFICIENCY In 1997, the Company continued to focus its energy efficiency services on lost opportunity programs which encouraged customers to install energy efficient equipment when they are planning to replace or buy new equipment. This strategy, along with careful management, has helped the Company to further reduce its cost-per-kilowatthour saved by 10% below its costs in 1996. The current cost of saving per kilowatthour is approximately 2 cents which is a 56% reduction in costs since 1992. In 1997, the Company's energy efficiency programs saved 8,633 MWH, 64% above targeted savings for the year. During the past five years, the Company's efficiency programs have achieved a cumulative savings of 71,217 megawatthours. In 1997, the Company worked with other Vermont utilities and the Department to develop a set of statewide energy efficiency programs. This effort should reduce the cost of delivering these programs and provide a more standardized service to customers throughout the State. In 1997, the Company spent approximately $1,900,000 on energy efficiency programs, approximately 1.2% of retail revenue. Rate Design. The Company seeks to design rates to encourage the shifting of electrical use from peak hours to off-peak hours. Since 1976, the Company has offered optional time-of-use rates for residential and commercial customers. Currently, approximately 2,500 of the Company's residential customers continue to be billed on the original 1976 time-of-use rate basis. In 1987, the Company received regulatory approval for a rate design that permitted it to charge prices for electric service that reflected as accurately as possible the cost burden imposed by each customer class. The Company's rate design objectives are to provide a stable pricing structure and to accurately reflect the cost of providing electric services. This rate structure helps to achieve these goals. Since inefficient use of electricity increases its cost, customers who are charged prices that reflect the cost of providing electrical service have real incentives to follow the most efficient usage patterns. Included in the VPSB's order approving this rate design was a requirement that the Company's largest customers be charged time-of-use rates on a phased-in basis by 1994. At year end December 31, 1997, approximately 1,350 of the Company's largest customers, comprising 48% of retail revenues, continue to receive service on mandatory time-of-use rates. In May 1994, the Company filed its current rate design with the VPSB. The parties, including the Department, IBM and a low-income advocacy group, entered into a settlement that was approved by the VPSB on December 2, 1994. Under the settlement, the revenue allocation to each rate class was adjusted to reflect class-by-class cost changes since 1987, the differential between the winter and summer rates was reduced, the customer charge was increased for most classes, and usage charges were adjusted to be closer to the associated marginal costs. No rate redesign has taken place since the VPSB Order issued on December 2, 1994. Dispatchable and Interruptible Service Contracts. In 1997, the Company had interruptible/dispatchable power contracts with three major ski areas, interruptible-only contracts with five customers and dispatchable-only contracts with an additional twenty-four customers. The interruptible portion of the contracts allow the Company to control power supply capacity charges by reducing the Company's capacity requirements. During 1997, the Company did not request any interruptions due to the surplus capacity in the region. The dispatchable portion of the contracts allows customers to purchase electricity during times designated by the Company when low cost power is available. The customer's demand during these periods is not considered in calculating the monthly billing. This program enables the Company and the customers to benefit from load control. The Company shifts load from its high cost peak periods while the customer uses inexpensive power at a time when its use provides maximum value. These programs are available by tariff for qualifying customers. CONSTRUCTION AND CAPITAL REQUIREMENTS The Company's capital expenditures for 1994 through 1996 and projection for 1997 are set forth in Item 7. MD&A - "Liquidity and Capital Resources-Construction." Construction projections are subject to continuing review and may be revised from time-to-time in accordance with changes in the Company's financial condition, load forecasts, the availability and cost of labor and materials, licensing and other regulatory requirements, changing environmental standards and other relevant factors. For the period 1995-1997, internally generated funds, after payment of dividends, provided approximately 62% of total capital requirements for construction, sinking fund obligations and other requirements. Internally generated funds provided 129% of such requirements for 1997. The Company anticipates that for 1998, internally generated funds will provide approximately 48% of total capital requirements for regulated operations, the remainder to be derived from bank loans. In connection with the foregoing, see Item 7. MD&A - "Liquidity and Capital Resources." ENVIRONMENTAL MATTERS The Company has been notified by the Environmental Protection Agency (EPA) that it is one of several potentially responsible parties for clean up at the Pine Street marsh site in Burlington, Vermont. For information regarding the Pine Street Marsh and other environmental matters see Item 7. MD&A - "Environmental Matters" and Note I-2 of Notes to Consolidated Financial Statements. UNREGULATED BUSINESSES The Company has had a plan of diversification into unregulated businesses that complements the Company's basic utility operations. The diversification plan has involved the establishment of several subsidiaries. For information regarding unregulated businesses, see Item 7. MD&A- "Future Outlook - Unregulated Businesses." EXECUTIVE OFFICERS Executive Officers of the Company as of March 27, 1998: Name Age Nancy R. Brock 42 Chief Corporate Strategic Planning Officer since March, 1998. Prior to joining the Company, she was Chief Financial Officer of SAL, Inc., 1997; and Senior Vice President and Chief Financial Officer for the Chittenden Corporation from 1988 to 1996. Christopher L. Dutton 49 President, Chief Executive Officer and Chairman of the Executive Committee of the Corporation since August 1997. Vice President, Finance and Administration, Chief Financial Officer and Treasurer from 1995 to 1997. Vice President and General Counsel from 1993 to January 1995. Vice President, General Counsel and Corporate Secretary from 1989 to 1993. Robert J. Griffin 41 Controller since October 7, 1996. Manager of General Accounting from 1990 to 1996. Richard B. Hieber 59 Senior Vice President and Chief Operating Officer since August 1997. Vice President, Electric Operations and Engineering from 1996 to 1997. Prior to joining the Company, he was President and Chief Executive Officer of Stone & Webster Management Consultants, Inc. from 1992 to 1996 and Senior Vice President from 1991 to 1992. Donna S. Laffan 48 Corporate Secretary since December 1993. Assistant Secretary from 1986 to 1993. John J. Lampron 53 Assistant Treasurer since July 1991. Prior to joining the Company, he was employed by Public Service Company of New Hampshire as an Assistant Vice President from 1982 to 1990. Michael H. Lipson 53 General Counsel since August 1997. Assistant General Counsel from 1990 to 1997. Prior to joining the Company, he was a partner with Miller, Eggleston and Rosenberg Ltd. Craig T. Myotte 43 Assistant Vice President-Engineering and Operations since 1994. Assistant Vice President-Operations and Maintenance from 1991 to 1994. Edwin M. Norse 52 Vice President, Chief Financial Officer and Treasurer since August 1997. Vice President and General Manager, Energy Resources and Sales from 1995 to 1997. Vice President, Chief Financial Officer and Treasurer from 1986 to January 1995. President-Green Mountain Propane Gas Company from October 1993 to June 1996. Walter S. Oakes 51 Assistant Vice President-Customer Operations since June 1994. Assistant Vice President-Human Resources from August 1993 to June 1994. Assistant Vice President- Corporate Services from 1988 to 1993. Mary G. Powell 37 Vice President, Human Resources and Organizational Development since March, 1998. Prior to joining the Company, she was Senior Vice President, Human Resources and Senior Vice President Community Banking, Senior Vice President Human Resources Administration, and Vice president of Human Resources for KEYCORP from October 1992 to March 1998. Stephen C. Terry 55 Senior Vice President, Corporate Development since August, 1997. Vice President and General Manager, Retail Energy Services from 1995 to 1997. Vice President- External Affairs from 1991 to January 1995. Jonathan H. Winer 46 President of Mountain Energy, Inc. since March 1997. Vice President and Chief Operating Officer of Mountain Energy, Inc. from 1989 to March 1997. Robert C. Young 60 Assistant Vice President-Customer Operations since 1994. Assistant Vice President-Operations and Engineering from 1992 to 1994. Director of Engineering from August 1991 to December 1992. Director of Special Projects from August 1991 to March 1992. Prior to joining the Company, he was employed by the Burlington Electric Department for thirty-two years, including sixteen years as General Manager. Officers are elected by the Board of Directors of the Company, Mountain Energy, Inc., or Green Mountain Resources, Inc., as appropriate, for one-year terms and serve at the pleasure of such boards of directors. ITEM 2. PROPERTY GENERATING FACILITIES The Company's Vermont properties are located in five areas and are interconnected by transmission lines of VELCO and New England Power Company. The Company wholly owns and operates eight hydroelectric generating stations with a total nameplate rating of 36.1 MW and an estimated claimed capability of 35.7 MW. It also owns two gas-turbine generating stations with an aggregate nameplate rating of 59.9 MW and an estimated aggregate claimed capability of 73.2 MW. The Company has two diesel generating stations with an aggregate nameplate rating of 8.0 MW and an estimated aggregate claimed capability of 8.6 MW. The Company has a wind generating facility with a name plate rating of 6.1 MW. The Company also owns 17.9% of the outstanding common stock, and is entitled to 17.6624% (93.8 MW of a total 531 MW) of the capacity, of Vermont Yankee, a 1.1% (6.8 MW of a total 620 MW) joint-ownership share of the Wyman #4 plant located in Maine, an 8.8% (31.0 MW of a total 352 MW) joint-ownership share of the Stony Brook I intermediate units located in Massachusetts and an 11% (5.9 MW of a total 53 MW) joint- ownership share of the J. C. McNeil wood-fired steam plant located in Burlington, Vermont. See Item 1. Business - "Power Resources" for plant details and the table hereinafter set forth for generating facilities presently available. TRANSMISSION AND DISTRIBUTION The Company had, at December 31, 1997, approximately 1.5 miles of 115 kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 miles of 44 kV and 265.4 miles of 34.5 kV transmission lines. Its distribution system includes about 2,399 miles of overhead lines of 2.4 kV to 34.5 kV, and about 445 miles of underground cable of 2.4 kV to 34.5 kV. At such date, the Company owned approximately 153,275 kVa of substation transformer capacity in transmission substations, 446,050 kVa of substation transformer capacity in distribution substations and 1,070,604 kVa of transformers for step-down from distribution to customer use. The Company owns 33.8% of the Highgate transmission intertie, a 225-MW converter and transmission line utilized to transmit power from Hydro-Quebec. The Company also owns 29.5% of the common stock and 30% of the preferred stock of VELCO, which operates a high-voltage transmission system interconnecting electric utilities in the State of Vermont. PROPERTY OWNERSHIP The principal wholly-owned plants of the Company are located on lands owned in fee by the Company. Water power and floodage rights are controlled through ownership of the necessary land in fee or under easements. Transmission and distribution facilities which are not located in or over public highways are, with minor exceptions, located either on land owned in fee or pursuant to easements which, in nearly all cases, are perpetual. Transmission and distribution lines located in or over public highways are so located pursuant to authority conferred on public utilities by statute, subject to regulation by state or municipal authorities. INDENTURE OF FIRST MORTGAGE The Company's interests in substantially all of its properties and franchises are subject to the lien of the mortgage securing its First Mortgage Bonds. GENERATING FACILITIES OWNED The following table gives information with respect to generating facilities presently available in which the Company has an ownership interest. See also Item 1. Business - "Power Resources." Winter Capability Type Location Name Fuel MW(1) ---- -------- ---- ---- --------- Wholly Owned Hydro Middlesex, VT Middlesex #2 Hydro 3.3 Marshfield, VT Marshfield #6 Hydro 4.9 Vergennes, VT Vergennes #9 Hydro 2.1 W. Danville, VT W. Danville #15 Hydro 1.1 Colchester, VT Gorge #18 Hydro 3.3 Essex Jct., VT Essex #19 Hydro 7.8 Waterbury, VT Waterbury #22 Hydro 5.0 Bolton, VT DeForge #1 Hydro 7.8 Diesel Vergennes, VT Vergennes #9 Oil 4.2 Essex Jct., VT Essex #19 Oil 4.4 Gas Berlin, VT Berlin #5 Oil 56.6 Turbine Colchester, VT Gorge #16 Oil 16.1 Wind Searsburg, VT Wind 1.2 Jointly Owned Steam Vernon, VT Vermont Yankee Nuclear 93.8(2) Yarmouth, ME Wyman #4 Oil 7.1 Burlington, VT McNeil Wood 6.6(3) Combined Ludlow, MA Stony Brook #1 Oil/Gas 31.0(2) _____ Total Winter Capability 256.3 (1) Winter capability quantities are used since the Company's peak usage occurs during the winter months. Some unit ratings are reduced in the summer months due to higher ambient temperatures. Capability shown includes capacity and associated energy sold to other utilities. (2) For a discussion of the impact of various power supply sales on the availability of generating facilities, see Item 1. Business - "Power Resources - Long-Term Power Sales." (3) The Company's entitlement in McNeil is 5.8 MW. However, the Company receives up to 6.6 MW as a result of other owners' losses on this system. CORPORATE HEADQUARTERS For a discussion of the Company's operating lease for its Corporate Headquarters building, see Note I-3 of Notes to Consolidated Financial Statements. ITEM 3. LEGAL PROCEEDINGS See the discussion Item 7. MD&A - "Environmental Matters" concerning a notice received by the Company in 1982 under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Outstanding shares of the Common Stock are listed and traded on the New York Stock Exchange under the symbol "GMP". The following tabulation shows the high and low sales prices for the Common Stock on the New York Stock Exchange during 1997 and 1996: HIGH LOW 1996 First Quarter $29 1/8 $26 7/8 Second Quarter 27 7/8 22 7/8 Third Quarter 26 3/8 23 1/2 Fourth Quarter 25 1/8 22 3/4 1997 First Quarter 25 1/4 22 5/8 Second Quarter 24 5/8 22 3/8 Third Quarter 26 1/4 18 7/8 Fourth Quarter 19 1/4 17 9/16 The number of common stockholders of record as of March 11, 1998 was 7,883. Quarterly cash dividends were paid as follows during the past two years: First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- 1996 53 cents 53 cents 53 cents 53 cents 1997 53 cents 53 cents 27.5 cents 27.5 cents Dividend Policy - On September 17, 1997, the Company's Board of Directors announced a reduction in the quarterly dividend from $.053 per share to $0.275 per share on the Company's common stock. Historically, the Company has based its dividend policy on the continued validity of three assumptions: The ability to achieve earnings growth, the receipt of an allowed rate of return that accurately reflects the Company's cost of capital, and the retention of its exclusive franchise. The Company's common stock dividend payout has ranged from 94 to 103 percent of earnings over the past five years. The Company's revised dividend policy, which incorporates a target payout ratio of 60 to 70 percent, reflects the greater risks facing the Company as a result of the changing environment of the electric utility industry. This policy contemplates a target payout that is in line with industry trends and is comparable to that of other companies in the utility industry. The policy assumes fair and appropriate ratemaking. However, the VPSB's recent rate Order, if unchanged, will require the Company to reassess the current dividend level. See Item 7. MD&A "Future Outlook - Competition and Restructuring" and Note C of Notes to Consolidated Financial Statements for discussion of limitations on dividends.
ITEM 6. SELECTED FINANCIAL DATA (In thousands except per share amounts) Results of operations for the years ended December 31 - ----------------------------------------------------- 1997 1996 1995 1994 1993 --------- --------- --------- --------- --------- Operating Revenues........................$179,323 $179,009 $161,544 $148,197 $147,253 Operating Expenses........................ 163,808 162,882 146,249 133,680 132,427 --------- --------- --------- --------- --------- Operating Income........................ 15,515 16,127 15,295 14,517 14,826 --------- --------- --------- --------- --------- Other Income AFUDC - equity.......................... 357 175 27 263 273 Other................................... 1,216 3,055 3,607 3,418 2,360 --------- --------- --------- --------- --------- Total other income.................... 1,573 3,230 3,634 3,681 2,633 --------- --------- --------- --------- --------- Interest Charges AFUDC - borrowed funds.................. (315) (468) (547) (539) (357) Other................................... 7,965 7,866 7,973 7,735 7,185 --------- --------- --------- --------- --------- Total interest charges................ 7,650 7,398 7,426 7,196 6,828 --------- --------- --------- --------- --------- Net Income................................ 9,438 11,959 11,503 11,002 10,631 Dividends on Preferred Stock.............. 1,433 1,010 771 794 811 --------- --------- --------- --------- --------- Net Income Applicable to Common Stock..... $8,005 $10,949 $10,732 $10,208 $9,820 ========= ========= ========= ========= ========= Common Stock Data Earnings per share...................... $1.57 $2.22 $2.26 $2.23 $2.20 Cash dividends declared per share....... $1.61 $2.12 $2.12 $2.12 $2.11 Weighted average shares outstanding..... 5,112 4,933 4,747 4,588 4,457 Financial Condition as of December 31 - ------------------------------------- 1997 1996 1995 1994 1993 --------- --------- --------- --------- --------- Assets Utility Plant, Net.......................$196,720 $189,853 $181,999 $175,987 $171,411 Other Investments........................ 21,997 20,634 20,248 20,751 22,528 Current Assets........................... 29,125 30,901 30,216 28,798 26,215 Deferred Charges......................... 35,831 43,224 42,951 35,659 33,893 Non-Utility Assets....................... 42,060 39,927 37,868 33,416 28,626 --------- --------- --------- --------- --------- Total Assets............................$325,733 $324,539 $313,282 $294,611 $282,673 ========= ========= ========= ========= ========= Capitalization and Liabilities Common Stock Equity......................$114,377 $111,554 $106,408 $101,319 $97,149 Redeemable Cumulative Preferred Stock.... 17,735 19,310 8,930 9,135 9,385 Long-Term Debt, Less Current Maturities.. 93,200 94,900 91,134 74,967 79,800 Capital Lease Obligation................. 8,342 9,006 9,778 10,278 11,029 Curent Liabilities....................... 25,286 21,037 32,629 40,441 37,925 Deferred Credits and Other............... 53,723 54,968 52,041 49,434 40,214 Non-Utility Liabilities.................. 13,070 13,764 12,362 9,037 7,171 --------- --------- --------- --------- --------- Total Capitalization and Liabilities....$325,733 $324,539 $313,282 $294,611 $282,673 ========= ========= ========= ========= =========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS This section presents management's assessment of Green Mountain Power Corporation's (the Company) financial condition and the principal factors having an impact on the results of its operations. This discussion should be read in conjunction with the consolidated financial statements and notes thereto contained in this annual report. This section contains forward-looking statements as defined under the securities laws. Actual results could differ materially from those projected. This section, particularly under "Future Outlook - Competition and Restructuring" and "Risk Factors," lists some of the reasons why results could differ materially from those projected. EARNINGS SUMMARY Earnings per average share of common stock in 1997 were $1.57 as compared with $2.22 in 1996 and $2.26 in 1995. The 1997 earnings represent an earned return on average common equity of 7.1 percent. The earned return on average common equity in 1996 was 10.0 percent and 10.3 percent in 1995. The 1997 decrease in earnings was primarily due to diminished results by two of the Company's wholly-owned subsidiaries. Mountain Energy, Inc., the Company's subsidiary that has invested in energy generation and energy and wastewater efficiency projects, earned $1.2 million less in 1997 than in 1996, primarily due to operating losses incurred by Micronair, LLC, a company in which Mountain Energy acquired a 71 percent interest in 1997, and a decline in rates paid for power generated by one of the California wind facilities in which it has invested. Green Mountain Resources Inc.'s (GMRI) loss in 1997 was $1.4 million greater than the loss in 1996 due primarily to the development costs of its investment in Green Mountain Energy Resources L.L.C. (GMER), the retail energy company in which the Company sold a 67 percent interest to an affiliate of the Sam Wyly family during the third quarter of 1997. Subsequently, the Wyly family affiliate invested an additional $10 million in GMER, increasing its ownership percentage to 74.3 percent. The 1996 decrease in earnings was primarily due to increased mandatory purchases of power from independent power producers resulting from greater production from in-state hydroelectric plants and unusually warm weather in December 1996 that adversely affected the Company's electric operating revenues and sales of propane by the Company's wholly-owned subsidiary, Green Mountain Propane Gas Company. FUTURE OUTLOOK Competition and Restructuring -- The electric utility business is being subjected to rapidly increasing competitive pressures stemming from a combination of trends, including the presence of surplus generating capacity, a disparity in electric rates among and within various regions of the country, improvements in generation efficiency, increasing demand for customer choice, and new regulations and legislation intended to foster competition. To date, this competition has been most prominent in the bulk power market, in which non-utility generators have significantly increased their market share. Electric utilities historically have had exclusive franchises for the retail sale of electricity in specified service territories. As a result, competition for retail customers has been limited to: (i) competition with alternative fuel suppliers, primarily for heating and cooling; (ii) competition with customer-owned generation; and (iii) direct competition among electric utilities to attract major new facilities to their service territories. These competitive pressures have led the Company and other utilities to offer, from time to time, special discounts or service packages to certain large customers. In states across the country, including the New England states, there has been an increasing number of proposals to allow retail customers to choose their electricity suppliers, with incumbent utilities required to deliver that electricity over their transmission and distribution systems (also known as "retail wheeling"). Increased competitive pressure in the electric utility industry may restrict the Company's ability to charge energy prices high enough to recover embedded costs, such as the cost of purchased power obligations or of generation facilities owned by the Company. The amount by which such costs might exceed market prices is commonly referred to as "stranded costs." Regulatory and legislative authorities at the federal level and among states across the country, including Vermont, are considering how to facilitate competition for electricity sales at the wholesale and retail levels. On October 24, 1994, the Vermont Public Service Board (VPSB) and the Vermont Department of Public Service (the Department) convened a "Roundtable on Competition and the Electric Industry," consisting of representatives of affected parties. On July 17, 1995, a subgroup of the Roundtable agreed on a set of 14 principles intended to guide the debate in Vermont concerning competition. These principles, among other things, call for exploration of the potential for retail competition, honoring of past utility commitments incurred under regulation, protection for low income customers, and continued exploration of renewable resources, energy efficiency and environmental protections. On September 14, 1995, Governor Dean of Vermont announced his desire to provide for competition and a restructuring of the electric utility industry. The Governor's announcement included proposed legislative adoption of restructuring principles, a VPSB proceeding to address the issue, the submission by Vermont electric utilities of detailed plans by May 1, 1996, and implementation of restructuring by the beginning of 1998. In response to a Department petition, the VPSB opened a proceeding on utility industry restructuring by order dated October 17, 1995. On December 29, 1995, the Company released its proposed restructuring plan, calling for corporate separation into a regulated company for transmission and distribution functions and an unregulated company for generation and sales functions. On October 16, 1996, the VPSB issued a Draft Report and Order which proposed the commencement of competitive retail sales of electricity in early 1998, while distribution and transmission functions would remain subject to regulation. The Company and other parties responded to the Draft Report and Order in November 1996, and the VPSB issued its Final Report and Order on December 31, 1996 (Final Report). The Final Report indicated that Vermont investor-owned utilities may be required to divide their competitive retail and regulated distribution and transmission functions into separate corporate subsidiaries in order to achieve a functional separation of regulated and unregulated businesses, and envisioned competition for all customer classes to be completed by the end of 1998. In view of this potential change in structure as well as the unknown relative level of competition each corporation may face, the Company cannot predict the future cost or availability of capital for the new subsidiary corporations, except to the extent that it has already created a functionally-separate retail marketing affiliate, GMER. See Management's Discussion and Analysis of Financial Condition and Results of Operations - "Unregulated Businesses - - Green Mountain Resources, Inc." Furthermore, most of the assets of the Company are encumbered by a lien of the Company's First Mortgage Indenture. The Company cannot predict with certainty at this time the cost and feasibility of obtaining approval from the existing bondholders, to the extent that it is determined that such approvals are necessary, in order to achieve functional separation. The Final Report proposed an approach that takes into account multiple factors that the VPSB believes will "create the opportunity for full recovery of stranded costs provided they are legitimate, verifiable, otherwise recoverable, prudently incurred and non- mitigable," but the Final Report also stated the VPSB's belief that "an opportunity for full recovery must be explicitly tied to successful mitigation." The Final Report further provided that, where a utility has successfully mitigated its stranded costs, the opportunity should exist for substantial or full recovery of stranded costs when the magnitude of the post-mitigation stranded costs, among other things, allows for rates that are comparable to regional rates. The Final Report proposed that allowed stranded cost recovery be accomplished through the use of a non-bypassable access charge, or Competitive Transition Charge (CTC), collected by the regulated distribution company. The Final Report also endorsed the securitization of stranded costs through the assignment of CTC receipts as a means of achieving lower-cost financing and supported legislative action to achieve these savings. In early 1997, the Company, Central Vermont Public Service Corporation (CVPS), representatives of the Governor of Vermont and the Department negotiated a Memorandum of Understanding (MOU) that outlined agreed-upon positions among the parties relative to the recovery of stranded costs, distribution company rates, corporate unbundling and societal benefit programs. In early April 1997, the Vermont Senate passed Senate Bill No. 62 (S. 62), an electric utility restructuring bill, which requires passage by the Vermont House of Representatives and signature by the Governor before becoming law. This bill was opposed by the Company and other utilities in Vermont in the legislative session that ended in June 1997. S. 62 establishes several goals, including the conflicting objectives that stranded costs be shared equally between utilities and customers and that the continuing financial integrity of the utility be preserved. Under S. 62, full retail competition in Vermont would have started in October 1998 and the VPSB was given considerable discretion to weigh various potentially conflicting objectives, including the two objectives set forth above, in deciding the extent to which and manner under which a utility can recover stranded costs. S. 62 also provides: (1) that utilities must either divest unregulated enterprises or "functionally separate" them from regulated business activities; (2) an incentive for the early closing and decommissioning of the Vermont Yankee nuclear power plant; (3) that any retail electricity provider in Vermont shall have "ownership" of sufficient tradable renewable energy credits as defined in S. 62; (4) that the VPSB may order performance-based regulation for distribution functions if it finds that departure from cost-of-service regulation is in the public interest; (5) for the provision of out placement service and severance pay for utility employees adversely affected by restructuring, with such costs shared equally by the utility and its customers; and (6) that if a utility has received some above-market cost recovery and then the utility is acquired, the VPSB is to determine how much, if at all, the value of the acquired company was enhanced by the recovery of above-market costs and thereafter determine how the enhanced value should be shared equitably between the acquired utility's shareholders and customers. The Company has strenuously opposed the enactment of S. 62 into law principally because its stranded cost sharing provisions would jeopardize the Company's financial viability. The ability of the Company to apply accounting standards that recognize the economic effect of rate regulation and record regulatory assets and liabilities would be significantly challenged by the proposed enactment of S. 62. In the event that the criteria for applying Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71) are no longer met, the Company would be required to write-off a material amount of its regulatory assets. More significantly, the Company would be required to record its best estimate of the loss resulting from the equal sharing between the Company and its customers of the portion of stranded costs represented by above-market purchase power obligations. These obligations result from contracts for power entered into by the Company to meet its obligation to serve its retail customers. Such losses could impact the Company's credit rating, dividend policy and financial viability. In mid-April 1997, the Vermont House of Representatives indicated through its Speaker that there was insufficient time in the legislative session (which ended in June 1997) to act upon a utility restructuring bill. S. 62 was not considered by the Vermont House of Representatives in the 1997 legislative session. However, along with other proposed bills, it is being considered by the House of Representatives during the 1998 session. On July 28, 1997, the Speaker of the House named an eleven member non-standing committee to consider reform of the Vermont Electric Utility Regulatory System. In mid-October 1997, the Chair of the Committee reported that the Committee did not recommend that the Vermont Legislature consider legislation during the 1998 session to allow customer choice at this time. Nevertheless, proposed electric utility- related legislation, which the House has taken no action on, consists of the following: (1) H. 663, which would create performance-based regulation, but not provide for competitive retail sales of electricity; (2) H. 701, which would mirror most of the terms of the MOU but would not provide reasonable stranded cost recovery for the Company; and (3) H. 675, which also would mirror most of the terms of the MOU but would confer jurisdiction on the VPSB to provide for stranded cost recovery as a ratemaking function. There is no assurance that any restructuring legislation will be enacted by the Vermont General Assembly in its 1998 session that is scheduled to adjourn mid-April 1998 or, if legislation is enacted, that it will be consistent with the terms of the Final Report. The Company has stated its position that if legislation is enacted that threatens the Company's financial integrity, it will pursue all remedies available to it under law. Risk Factors -- The major risk factors for the Company arising from electric industry restructuring, including risks pertaining to the recovery of stranded costs, are: (i) regulatory and legal decisions; (ii) the market price of power; and (iii) the amount of market share retained by the Company. There can be no assurance that a final restructuring plan ordered by the VPSB, the courts, or through legislation will include a CTC or other mechanism that would allow for full recovery of stranded costs and include a fair return on those costs as they are being recovered. If laws are enacted or regulatory decisions are made that do not offer an adequate opportunity to recover stranded costs, the Company believes it has compelling legal arguments to challenge such laws or decisions. The largest category of the Company's stranded costs are future costs under long-term power purchase contracts. The Company intends to pursue compliance with the steps outlined in the Final Report and aggressively to pursue mitigation efforts in order to maximize its recovery of these costs. The magnitude of stranded costs for the Company is largely dependent upon the future market price of power. The Company has discussed various market price scenarios with interested parties for the purpose of identifying stranded costs. Preliminary market price assumptions, which are likely to change, have resulted in estimates of the Company's stranded costs of between $265 million and $1.1 billion. If retail competition is implemented in Vermont, there will be an impact on the Company's revenues from electricity sales. However, the Company is unable to predict at this time the extent of this impact. GMER, the Company's affiliate, is expected to participate in the residential and small commercial and industrial customer market in Vermont at such time when restructuring occurs. The Company has agreed not to compete against GMER in the retail energy business for a period of seven years. The Company, itself or through another marketing affiliate, may elect to endeavor to retain and attract larger commercial customers in a competitive retail environment, but neither its relative prospects or the margins it will realize on any such sales can be estimated at this time. Historically, electric utility rates have been based on a utility's cost of service. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. SFAS 71 requires regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. As described in Note A.2 in the Notes to Consolidated Financial Statements, the Company complies with the provisions of SFAS 71. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact would be an extraordinary, non- cash charge to operations of an amount that could be material. Factors that could give rise to the discontinuance of SFAS 71 include (1) increasing competition that restricts the Company's ability to charge prices to recover specific costs and (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. (See Note I of the Notes to Consolidated Financial Statements.) The Company believes that the provisions of the Final Report, if implemented, would meet the criteria for continuing application of SFAS 71 as to those costs for which recovery is permitted. S. 62, however, would not meet the criteria for the continuing application of SFAS 71. Under SFAS 5, Accounting for Contingencies, the enactment of S. 62 or other restructuring legislation or order containing comparable provisions on stranded cost recovery would also require the Company to immediately estimate and record losses, on an undiscounted basis, for any discretionary above market power purchase contracts and other costs which are not probable of recovery from customers, to the extent that those costs are estimable. The Company is unable to predict what form enacted legislation will take, and it cannot predict if or to what extent SFAS 71 will continue to be applicable in the future. Members of the staff of the Securities and Exchange Commission have raised questions concerning the continued applicability of SFAS 71 to certain other electric utilities facing restructuring. On July 24, 1997, the Emerging Issues Task Force of the Financial Accounting Standards Board indicated that utilities should immediately discontinue application of SFAS 71 for those business segments which will become unregulated, if the utility has a final plan in place for transition to competition. To the extent that the discontinued segment has assets secured in arrangements such as a CTC, those assets would continue to be accounted for under SFAS 71. SFAS 121, Accounting for the Impairment of Long Lived Assets, which was implemented by the Company on January 1, 1996, requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues be revalued based upon future cash flows. SFAS 121 requires that a rate-regulated enterprise recognize an impairment loss for regulatory assets which are no longer probable of recovery. As of December 31, 1997, based upon the regulatory environment within which the Company currently operates, no impairment loss was incurred. Competitive influences or regulatory developments may impact this status in the future. The Company cannot predict whether restructuring legislation enacted by the Vermont General Assembly or any subsequent report or actions of, or proceedings before, the VPSB or the Vermont General Assembly would have a material adverse effect on the Company's operations, financial condition or credit ratings. The Company's failure to recover a significant portion of its purchased power costs, or to retain and attract customers in a competitive environment, would likely have a material adverse effect on the Company's business, including its operating results, cash flows and ability to pay dividends at current levels. For a discussion of a major risk factor arising from Vermont regulatory treatment of the Company's recent rate filing, see Note I of the Notes to Consolidated Financial Statements. Unregulated Businesses -- The following is a discussion of the Company's unregulated enterprises. Mountain Energy, Inc., which has invested in energy generation and energy and waste water efficiency projects, earned $142,000 in 1997, compared to net income of $1.32 million in 1996. The 1997 decrease in earnings was due primarily to start-up operating losses incurred by Micronair, LLC. and a decline in rates paid for power generated by one of its wind facilities in California. The 1997 results contributed 3 cents of earnings per share to the Company's consolidated results as compared to 27 cents in 1996. Since its formation in 1989, Mountain Energy has invested more than $20 million in ten operating energy projects, including two California wind projects, hydroelectric projects in California and New Hampshire, a gas cogeneration facility in Illinois and energy efficiency installations in Maine, New York, New Jersey, Massachusetts and Hawaii. In 1997, Mountain Energy broadened its investment portfolio by acquiring an initial 35 percent ownership interest in Micronair, LLC, which owns certain patent rights to a wastewater treatment system that provides an innovative and efficient solution to the biosolids disposal issues facing the United States. The Micronairr system enhances both the processing and energy efficiency at wastewater facilities, virtually eliminating biosolids as a byproduct. Mountain Energy increased its ownership interest in Micronair to 71 percent at the end of 1997. Green Mountain Propane Gas Company (GMPG), which sells propane gas at retail in Vermont and New Hampshire, experienced a $136,000 loss in 1997 as compared to a $335,000 loss in 1996. The loss in 1997 was due primarily to a decrease in propane sales caused by warmer than normal weather in early 1997. In 1997 and 1996, the losses incurred by GMPG reduced the Company's consolidated earnings by 3 cents and 7 cents, respectively, per share of common stock. On February 20, 1998, GMPG and the Company entered into a sales agreement with VGS Propane, LLC for the sale of all GMPG assets. The sale was completed on March 16, 1998. See Note I of the Notes to Consolidated Financial Statements. The loss in 1996 was due primarily to strong competition, low margins due to significant wholesale price fluctuations, increased producer pipeline restrictions beginning in November 1996 and warmer than normal weather in December 1996. The Company's unregulated rental water heater business earned $381,000 in 1997, a slight increase from 1996's net income of $379,000. The 1997 and 1996 results contributed 7 and 8 cents of earnings, respectively, per share to the Company's consolidated results. Green Mountain Resources, Inc., which was formed in April 1996 to explore opportunities in competitive retail energy markets, experienced a loss of $2.0 million in 1997 that was $1.4 million greater than its loss of $579,000 in 1996, due primarily to the development costs of its investment in GMER. On August 6, 1997, the Company and the Sam Wyly family announced that their affiliates will jointly own GMER, a Delaware limited liability company of which GMRI was the sole owner. GMER is competing in the emerging consumer retail energy market starting in California where customers are able to choose their electricity supplier as of March 31, 1998. GMER has created retail brands of electricity and natural gas that will be sold to consumers who care about the environment in competitive markets across the nation. An affiliate of the Sam Wyly family, Green Funding I, L.L.C. (the Investor), entered into an Operating Agreement with GMRI governing the ownership of GMER. Pursuant to the terms of the Operating Agreement, the Investor initially agreed to invest up to $30 million in GMER in exchange for an equity interest of 67 percent while GMRI contributed certain assets and business development concepts in exchange for an equity interest of 33 percent in GMER. Subsequently, the Investor agreed to invest an additional $10 million in GMER, increasing its ownership percentage to 74.3 percent. These ownership interests may be reduced further if GMER warrants and options issued to GMER management and consultants are exercised. GMRI's ownership percentage of GMER will be further diluted if the Investor and/or third parties contribute additional capital to GMER and GMRI does not make pro rata additional capital contributions at such time. GMRI received a payment of $4 million from GMER at the closing as reimbursement for certain development expenses incurred. Pursuant to the terms of the Operating Agreement, funds provided by the Investor will be used to pay future GMER development expenses and operating costs. GMRI is not obligated to fund future development costs, and the Operating Agreement provides that GMRI will not be allocated operating losses from GMER, thus limiting the Company's shareholders' future financial risk while preserving their opportunity to participate in the success of GMER. In addition, the Company and the Investor have agreed that neither the Company nor the Investor will compete against GMER in the retail energy business for a period of seven years. Douglas G. Hyde, a director, President and Chief Executive Officer of the Company, resigned those positions with the Company effective August 6, 1997 in order to become the President and Chief Executive Officer of GMER. Thomas C. Boucher, Vice President, Energy Resources and Planning; Kevin W. Hartley, Vice President, Marketing; Karen K. O'Neill, Vice President, Organizational Development; and Peter H. Zamore, General Counsel of the Company, resigned those offices in order to join Mr. Hyde as members of the GMER management team. In 1996, GMRI, together with subsidiaries of Hydro-Quebec, Consolidated Natural Gas Corporation and Noverco, Inc., participated in the retail sales of energy in pilot programs in New Hampshire and Massachusetts through Green Mountain Energy Partners L.L.C. (GMEP). In 1997, Consolidated Natural Gas and Noverco withdrew from the pilot program. GMRI has concluded its participation in the Massachusetts pilot, but will continue participating through May 31, 1998 in the New Hampshire pilot program which was designed to test the viability of retail electric competition by providing customer choice in the purchase of electricity. In January 1998, Hydro-Quebec withdrew from the pilot program. RESULTS OF OPERATIONS Operating Revenues and MWh Sales--Operating revenues and megawatthour (MWh) sales for the years 1997, 1996 and 1995 consisted of: 1997 1996 1995 ---- ---- ---- (Dollars in Thousands) Operating Revenues: Retail . . . . . . . . . . . . . $ 158,790 $ 154,916 $ 140,676 Sales for Resale . . . . . . . . 17,847 20,667 17,541 Other . . . . . . . . . . . . . 2,686 3,426 3,327 --------- --------- --------- Total Operating Revenues . . . . . $ 179,323 $ 179,009 $ 161,544 ========= --------- --------- Megawatthour Sales: Retail . . . . . . . . . . . . . 1,806,580 1,775,711 1,723,117 Sales for Resale . . . . . . . . 588,525 701,835 620,655 --------- --------- --------- Total Megawatthour sales . . . 2,395,105 2,477,546 2,343,772 ========= ========= ========= Average Number of Customers: Residential . . . . . . . . . . 70,671 70,198 69,659 Commercial & Industrial . . . . 12,012 11,853 11,736 Other . . . . . . . . . . . . . 75 75 76 ------ ------ ------ Total Customers . . . . . . . . . . 82,758 82,126 81,471 ====== ====== ====== Differences in operating revenues were due to changes in the following: 1996 1995 to to 1997 1996 ---- ---- (In Thousands) Operating Revenues: Retail Rates . . . . . . . . . . . . . . . $ 1,161 $ 9,654 Retail Sales Volume . . . . . . . . . . . 2,713 4,586 Resales and Other Revenues . . . . . . . . (3,560) 3,225 ------- ------- Increase in Operating Revenues . . . . . . . $ 314 $17,465 ======= ======= In 1997, total electricity sales decreased 3.3 percent due principally to a decrease in wholesale sales caused by a reduction in low-margin, off-system sales. Sales of electricity to residential customers was negatively impacted by winter temperatures in the first quarter of 1997 that were substantially warmer than normal. Total operating revenues were virtually unchanged in 1997. Total retail revenues increased 2.5 percent in 1997 primarily due to an increase in sales of electricity to the Company's small commercial and industrial customers resulting from modest customer growth and an increase in sales to IBM. The increase in retail revenues was nearly offset by a 13.6 percent decrease in wholesale revenues caused by a reduction in low-margin, off-system sales, which had a minimal impact on earnings and a 21.6 percent decrease in other operating revenues caused by a one-time adjustment in 1996 to account for higher charges under a transmission and interconnection agreement between CVPS and the Company. In 1996, total electricity sales increased 5.7 percent due principally to an increase in electricity consumption by the Company's commercial and industrial customers and regional market conditions that allowed the Company to buy electricity and to resell it to other utilities at prices slightly higher than the purchase price. Total operating revenues increased 10.8 percent in 1996 primarily due to retail rate increases of 9.25 percent and 5.25 percent that went into effect in June 1995 and June 1996, respectively, and the increase in electricity sales mentioned above. Total retail revenues increased 10.1 percent in 1996 primarily due to the retail rate increases mentioned above. Wholesale revenues increased 17.8 percent in 1996 primarily due to the regional market conditions mentioned above. IBM, the Company's single largest customer, operates manufacturing facilities in Essex Junction, Vermont. IBM's electricity requirements for its main plant and an adjacent plant accounted for 14.0, 13.2 and 12.9 percent of the Company's operating revenues in 1997, 1996 and 1995, respectively. No other retail customer accounted for more than one percent of the Company's revenue. In February 1995, the Company and IBM entered into an Economic Development Agreement (EDA I) that governed the prices to be paid by IBM at its Essex Junction facility for incremental electric usage during 1995, 1996 and 1997. The contract, intended to promote growth in IBM's operations and create jobs in the Company's service area, applied only to that portion of IBM's load that exceeded its 1994 consumption level. Most of IBM's electric usage is billed under the Company's tariff rate. The EDA I price, although lower than the Company's tariff rate, exceeded the Company's marginal costs of providing this incremental electric service to IBM. The VPSB approved the EDA I in June 1995. Prior to the expiration of the EDA I on December 31, 1997, the Company and IBM negotiated a new, similar EDA (EDA II). The agreement has most of the features of the EDA I, including use of the 1994 base to determine incremental load and pricing above the Company's marginal costs. A separate pricing provision applies to load above 1997 levels. The Company expects the VPSB to approve EDA II as presented in early 1998. The Company believes that the EDA I and EDA II benefit the Company because the agreements encourage the incremental purchase of electricity by IBM at a price above the Company's marginal cost of providing such incremental service. Power Supply Expenses -- Power supply expenses constituted 61.3 percent, 61.5 percent and 60.1 percent of total operating expenses for the years 1997, 1996 and 1995, respectively. These expenses increased by $120,000 (0.1 percent) in 1997 and by $12.3 million (14.0 percent) in 1996. Total power supply expenses were slightly higher in 1997, although the cost of several individual sources were significantly different from their costs in 1996. Power supply expenses from Vermont Yankee increased 7.3 percent in 1997 primarily due to the deferral in 1996 and the amortization in 1997 of costs associated with a scheduled refueling outage. Company-owned generation expenses increased 60.0 percent in 1997 primarily due to the increased usage of Company-owned plants necessitated by the outage of certain nuclear power plants in the region. These increases were nearly offset by a 6.2 percent decrease in power supply expenses from other resources primarily due to the recognition of $8 million received from Hydro-Quebec under a Memorandum of Understanding entered into in 1996 (as described below) consistent with a VPSB accounting order dated December 31, 1996. (This accounting treatment was subsequently changed. See below.) During 1994, the Company negotiated an arrangement with Hydro- Quebec that reduces the cost impacts associated with the purchase of Schedules B and C3 under the 1987 Contract over the November 1995 through October 1999 period (the July 1994 Agreement). Under the July 1994 Agreement, the Company, in essence, will take delivery of the amounts of energy as specified in the 1987 Contract, but the associated fixed costs will be significantly reduced from those specified in the 1987 Contract. As part of the July 1994 Agreement, the Company is obligated to purchase $4 million (in 1994 dollars) worth of research and development work from Hydro-Quebec over the four-year period, and made a $6.5 million (in 1994 dollars) cash payment to Hydro-Quebec in 1995. Hydro- Quebec retains the right to curtail annual energy deliveries by 10 percent up to five times, over the 2000 to 2015 period, if documented drought conditions exist in Quebec. Under an arrangement negotiated in January 1996, the Company received cash payments from Hydro-Quebec of $3.0 million in 1996 and $1.1 million in 1997. Consistent with allowed ratemaking treatment, the $3.0 million payment reduced purchase power expense by $1.75 million in 1996; the balance of the payment reduced power costs in 1997. The $1.1 million payment reduces purchase power expense ratably over the period beginning June 1997 and ending May 1998. An Order issued by the VPSB in March 1998 requires the Company instead to amortize the $1.1 million over a four-year period. (See Note I of the Notes to Consolidated Financial Statements.) The 1996 arrangement requires the Company to shift up to 40 megawatts of its Schedule C3 deliveries to an alternate transmission path, and use the associated portion of the NEPOOL/Hydro-Quebec interconnection facilities to purchase power for the period from September 1996 through June 2001 at prices that vary based upon conditions in effect when the purchases are made. The 1996 arrangement also provides for minimum payments by the Company to Hydro-Quebec for periods in which power is not purchased under the arrangement. Although the level of benefits to the Company will depend on various factors, the Company estimates that the 1996 arrangement will provide a minimum benefit of $1.8 million on a net present value basis. Under a separate agreement executed on December 5, 1997, Hydro- Quebec provided a cash payment of $8.0 million to the Company in 1997. In return for this payment, the Company is providing Hydro-Quebec with the choice of selecting one of two alternatives by April 1, 1998, described below: Alternative A: For the period commencing November 1, 1997 and effective through the remaining term of the 1987 Contract, which expires in 2015, Hydro-Quebec can exercise an option to purchase up to 105,000 MWh on an annual basis, at energy prices established in accordance with the 1987 Contract, for an amount of energy equivalent to the Company's firm capacity entitlements in the 1987 Contract. The cumulative amount of energy purchased over the remaining term of the 1987 Contract shall not exceed 1,900,000 MWh. Hydro-Quebec may not exercise its annual rights to purchase power in the amounts specified under an arrangement made in November 1996 during those years in which Hydro-Quebec exercises its rights to curtail energy deliveries in accordance with the July 1994 Agreement. Alternative B: For the period commencing November 1, 1997 and effective through the remaining term of the 1987 Contract, Hydro-Quebec can exercise an option to purchase up to 52,500 MWh on an annual basis, at energy prices established in accordance with the 1987 Contract, for an amount of energy equivalent to the Company's firm capacity entitlements in the 1987 Contract. The cumulative amount of energy purchased over the remaining term of the 1987 Contract shall not exceed 950,000 MWh. Unlike Alternative A, Hydro-Quebec's option to curtail energy deliveries pursuant to the July 1994 Agreement can be exercised in addition to the purchase option under Alternative B. Finally, for the period commencing January 1, 1998 and effective though the remaining term of the 1987 Contract under Alternative B, Hydro-Quebec can exercise an option on an annual basis to purchase up to 600,000 MWh at the 1987 Contract energy price. Hydro-Quebec can purchase no more than 200,000 MWh in any given year. Under modifications agreed to by Hydro-Quebec and the Company, Hydro-Quebec has until April 1, 1998 to elect either Alternative A or B. (See Note K of the Notes to Consolidated Financial Statements). Notwithstanding the December 31, 1996 accounting order, the VPSB ordered a change in accounting treatment in an Order released on March 2, 1998. The Company intends to appeal or request reconsideration of this decision. (See Note I of the Notes to Consolidated Financial Statements.) Power supply expenses increased in 1996 primarily due to higher costs for power purchased from Hydro-Quebec, increases in mandatory purchases from independent power producers and purchases of additional power to service increased electricity sales. Vermont Yankee's operating expenses for 1996 exceeded the level of such expenses incurred during 1995 by approximately $1.3 million, of which approximately $230,000 was allocated to the Company. In 1996, Vermont Yankee elected to accelerate certain safety and management related projects intended to improve efficiency of the plant and assure compliance with Nuclear Regulatory Commission regulations and the facility's operating license. Other Operating Expenses -- Other operating expenses decreased 4.7 percent in 1997 primarily due to an increase in work performed on behalf of GMRI, effectively reducing payroll and overhead expenses for the Company. Additionally, the organizational changes attributable to the creation of GMER resulted in fewer Company employees, causing a reduction in payroll expense. Other operating expenses decreased 2.8 percent in 1996 primarily due to a decrease in salaries resulting from a reduction in the workforce and to a decrease in medical insurance claims experienced by the Company. Transmission Expenses - Transmission expenses increased 2.7 percent in 1997 primarily due to higher tariffs under a new operating agreement with New England Power Company. Transmission expenses increased 9.7 percent in 1996 primarily due to higher tariff rates under a transmission and interconnection agreement between CVPS and the Company discussed below. This increase was offset to a large extent by revenues generated by the same transmission and interconnection agreement. In August 1996, the Company received a bill totaling approximately $1.9 million from CVPS for service at certain transmission interconnections that are the subject of a 1993 transmission and interconnection agreement between the Company and CVPS. The bill covered the period October 1993 through June 1996. In September 1996, the Company charged approximately $700,000 of the CVPS invoice to transmission rent expense and deferred the remaining charges. The Company paid the CVPS billing but sought relief under the agreement's arbitration clause on the ground, among others, that substantial portions of the bill, inclusive of interest, were not properly chargeable under the agreement. The Company submitted a bill totaling approximately $500,000 to CVPS for its services under the same transmission and interconnection agreement, and credited this amount to transmission services in September 1996. CVPS disputed a portion of the amount billed by the Company, but paid the bill. On December 31, 1996, the Company received an accounting order from the VPSB permitting amounts deferred under the transmission and interconnection agreement to be expensed over the remaining eleven years of the agreement subject to review in future rate cases. In February 1998, following arbitration, the Company received $428,000 from CVPS, in resolution of each of the parties' claims under this agreement. Management sought to recover in rates (by inclusion in ratebase) the 13-month average balance of the charges from CVPS net of amounts recovered in prior rate orders of the costs of transmission under this agreement, revenues that the Company received under the agreement for providing service to CVPS, and the approximate amount of the arbitration award. The amount sought in the rate case was approximately $747,000. Management received ratemaking treatment for these costs in an Order released by the VPSB on March 2, 1998. Maintenance Expenses - Maintenance expenses increased 7.2 percent in 1997 and 6.0 percent in 1996 primarily due to scheduled increases in plant maintenance. Depreciation and Amortization - Depreciation and amortization expenses were virtually unchanged in 1997. Depreciation and amortization expenses increased 15.3 percent in 1996 primarily due to the amortization of expenditures related to energy conservation programs and the Pine Street Barge Canal site environmental matter (See Note I of the Notes to Consolidated Financial Statements) and to the depreciation of expenditures related to additional investment in the Company's distribution facilities. Income Taxes -- The effective federal income tax rates for the years 1997, 1996 and 1995 were 32.8 percent, 27.2 percent and 25.3 percent, respectively. The increase in 1997 income taxes is primarily due to an increase in taxable income, an increase in the combined federal and state income tax rate and an increase in the reserve for unaudited income tax years. Other Income - Other income decreased 51.3 percent in 1997 primarily due to diminished results by two of the Company's wholly-owned subsidiaries. Mountain Energy, Inc., the Company's subsidiary that invests in energy generation and energy and waste water efficiency projects, earned $1.2 million less in 1997 primarily due to start-up operating losses incurred by Micronair LLC, a company in which Mountain Energy bought a 71 percent interest in 1997, and a decline in rates paid for power generated by one of the California wind facilities in which it has invested. GMRI's loss in 1997 was $1.4 million greater than the loss in 1996 due primarily to the development costs of its investment in GMER, the retail energy company in which the Company sold a controlling interest to an affiliate of the Sam Wyly family during the third quarter of 1997. Other income decreased 11.1 percent in 1996 primarily due to a $579,000 loss experienced by GMRI. The impact of the GMRI loss on consolidated earnings was diminished to a large extent by offsetting payments received by the Company from GMEP for work performed on its behalf. Dividends on Preferred Stock - Dividends on preferred stock increased 41.8 percent in 1997 and 31.0 percent in 1996 primarily due to the issuance of 120,000 shares of the Company's 7.32 percent, Class E, Series 1 preferred stock in October 1996. Interest Charges - Interest charges increased 3.4 percent in 1997 primarily due to an increase in long-term interest related to the sale of $10 million and $4 million of the Company's first mortgage bonds in November and December 1996, respectively. This increase was partially offset by a decrease in interest charges related to a lower amount of short-term debt outstanding during the year. Interest charges were virtually unchanged in 1996. An increase in interest charges related to a higher amount of long-term debt outstanding during the year and a decrease in the allowance for funds used during construction were slightly more than offset by a reduction in interest charges related to a lower amount of short-term debt outstanding during the year. TRANSMISSION ISSUES Federal Open Access Tariff Orders -- On April 24, 1996, the Federal Energy Regulatory Commission (FERC) issued Orders 888 and 889 which, among other things, required the filing of open access transmission tariffs by electric utilities, and the functional separation by utilities of their transmission operations from power marketing operations. Order 888 also supports the full recovery of legitimate and verifiable wholesale power costs previously incurred under federal or state regulation. On July 9, 1996, the Company filed with the FERC the non- discriminatory open access tariffs required by Order 888 and subsequent modifications to the tariff. The tariff defined the Company's transmission system to include subtransmission facilities owned by the Company including Phase I and Phase II facilities and the Company's entitlement to facilities owned by VELCO. The Company's tariffs included charges related to the use of the VELCO transmission system by customers. Other Vermont utilities required to make filings with the FERC under Order 888 followed the same course of action. On July 17, 1997, the FERC approved the Company's Open Access Transmission Tariff, and on August 30, 1997 the Company filed its compliance refund report. In accordance with Order 889, the Company has also functionally separated its transmission operations and filed with the FERC a code of conduct for its transmission operations. The Company is currently revising the Code of Conduct in response to a FERC Order respecting it issued on November 3, 1997. The Company does not anticipate any material adverse effects or loss of wholesale customers due to the FERC orders mentioned above. Proposed NEPOOL Transmission Tariff -- Under an allocation agreement among VELCO, Northeast Utilities and New England Power Corporation (the Three-Party Agreement), VELCO currently has 14 percent of the capacity of transmission facilities between New England, New York and Canada. VELCO's capacity for such transmission facilities is allocated among Vermont electric utilities, including the Company. The Company's ability to use these delivery paths has been adversely impacted by a proposed NEPOOL open access tariff (NEPOOL Fourth Supplement to Amendment 33) on file with the FERC. Under the tariff as filed, transmission capability or transfer capacity between New York and New England will no longer be allocated in a manner consistent with the Three-Party Agreement. Instead, rights to the transfer capacity will be made more generally available to the market subject to certain contingencies related to NEPOOL generation availability and accounting for the delivery of various grandfathered contracts. Efforts by the Company and other VELCO members to negotiate with NEPOOL participants for the preservation of rights to deliver long-term firm contracts necessary to serve native load on these delivery routes were unsuccessful. Consequently, on November 18, 1997 VELCO filed with the FERC on behalf of the Vermont utilities (including the Company) a motion to intervene and seeking summary judgment with respect to the NEPOOL filing of the Fourth Supplement filing or the VELCO filing. The Company and other Vermont utilities have argued inter alia that the Fourth Supplement was a proposal to terminate the Vermont utilities existing and future rights under the Three Party Agreement allocating the New York and New England transmission ties and, specifically, the PV20 tie with the New York Power Authority (NYPA). ENVIRONMENTAL MATTERS Public concern for the environment has resulted in increased government regulation of the licensing and operation of electric generation, transmission and distribution facilities. The electric industry typically uses or generates a range of potentially hazardous products in its operations. The Company must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. The Company maintains an environmental compliance and monitoring program that includes employee training, regular inspection of Company facilities, research and development projects, waste handling and spill prevention procedures and other activities. Subject to developments concerning the Pine Street Barge Canal site described below, the Company believes that it is in substantial compliance with such requirements, and no material complaints concerning compliance by the Company with present environmental protection regulations are outstanding. 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. The Company has been notified by the Environmental Protection Agency (EPA) that it is one of several potentially responsible parties (PRPs) for cleanup of the Pine Street Barge Canal site in Burlington, Vermont, where coal tar and other industrial materials were deposited. From the late 19th century until 1967, gas was manufactured at the Pine Street Barge Canal site by a number of enterprises, including the Company. In 1990, the Company was one of the 14 parties that agreed to pay a total of $945,000 of the EPA's past response costs under a Consent Decree. The Company remains a PRP for other past, ongoing and future response costs. In November 1992, the EPA proposed a cleanup plan estimated by the EPA to cost $47 million. In June 1993, the EPA withdrew this cleanup plan in response to public concern about the plan and its cost. The cost of any future cleanup plan, the magnitude of unresolved EPA cost recovery claims, and the Company's share of such costs are uncertain at this time. Since 1994, the EPA has established a coordinating council, with representatives of the PRPs, environmental and community groups, the City of Burlington and the State of Vermont presided over by a neutral facilitator. The council has determined, by consensus, what additional studies were appropriate for the site, and is addressing the question of additional response activities. The EPA, the State of Vermont and other parties have entered into two consent orders for completion of appropriate studies. Work is continuing under the second of those orders. Most recently, on September 23, 1997, the council reached tentative agreement on a key component of the proposed remedy for the Pine Street site, namely, placement of an underwater sand/silt cap on areas of the canal and wetland sediments, combined with long-term monitoring to ensure effectiveness of the cap and to ensure that groundwater does not reach Lake Champlain, adjacent to the site. The EPA has estimated the costs of this remedy at between $6 to $10 million, subject to change. In addition, the council is exploring supplemental projects in and around the site and Burlington as part of a larger plan to improve environmental conditions in the vicinity. On December 1, 1994, the Company and two other PRPs, New England Electric System (NEES) and Vermont Gas Systems (VGS), entered into a confidential settlement agreement with the State of Vermont, the City of Burlington and nearly all other landowner PRPs under which, subject to certain qualifications, the liability of those landowner PRPs for future Superfund response costs would be limited and specified. On December 1, 1994, the Company entered into a confidential agreement with VGS compromising contribution and cost recovery claims of each party and contractual indemnity claims of the Company arising from the 1964 sale of the manufactured gas plant to VGS. In March 1996, the Company and NEES entered into a confidential agreement compromising past and future contribution and cost recovery claims of both parties relating to response costs. In December 1997, the Company and Southern Union Co. entered into a confidential settlement agreement compromising past and future contribution and cost recovery claims of both parties relating to response costs. The Company has received payment of the full amount provided for in the settlement. In January 1998, the Company and UGI Utilities, Inc. entered into a confidential settlement agreement compromising past and future contribution and cost recovery claims of both parties relating to response costs. The Company has received payment of the initial amount provided for in the settlement. The EPA has advised the Company that it has incurred substantial unrecovered response sums at the site which, together with interest the EPA alleges may be payable, amount to approximately $11.0 million. The Company has not yet received a formal demand for these sums. The Company will vigorously dispute the EPA's recovery of such costs, which include substantial sums for studies and other activities that were not reasonably necessary and were not undertaken consistent with legal and regulatory requirements. Further, the Company's agreements with certain PRP's will reduce the extent to which it may bear these past response costs. Consequently, the Company is not able at this time to predict with certainty whether, or the extent to which, it will be required to pay such past response costs. In December 1991, the Company brought suit against eight previous insurers seeking recovery of unrecovered past costs, cost of defense and indemnity against future liabilities associated with environmental problems at the site. Discovery in the case, which was previously subject to a stay, is complete. The Company has reached confidential settlements with the defendants in this litigation; several such settlements are in the final stages of documentation. The Company has deferred amounts received from third parties, under confidential settlements, pending resolution of the Company's ultimate liability with respect to the site and rate recognition of that liability. Although the cost of the coordinating council's tentative remediation plan, described above, is not expected to approach the EPA's earlier estimate of remediation costs for its original clean-up plan, the current EPA estimate is subject to change. Since the Company believes it may prevail with respect to some of the EPA's unrecovered response costs, the Company is unable to predict at this time the magnitude of any liability resulting from potential claims for the costs to investigate and remediate the site, or the likely disposition or magnitude of claims the Company may have against others, including its insurers, except to the extent described above. Through rate cases filed in 1991, 1993, 1994, and 1995, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Barge Canal site. Specifically, the Company proposed rate recognition of its unrecovered expenditures incurred between January 1, 1991 and June 30, 1995 (in the total of approximately $8.7 million) for technical consultants and legal assistance in connection with the EPA's enforcement action at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for the Pine Street Barge Canal site related costs, the Company and the Department reached agreements in these cases that the full amount of the Pine Street Barge Canal site costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB in those proceedings reflected the Pine Street Barge Canal site related expenditures referred to above. The Company proposed in the rate filing made on June 16, 1997 recovery of an additional $3.0 million in such expenditures. In an Order released March 2, 1998, the VPSB suspended the amortization of expenditures associated with the Pine Street Barge Canal 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 Barge Canal site, taking into account recoveries from insurance carriers and other PRP's, should be "shared" between customers and shareholders of the Company. As of December 31, 1997, total expenditures for the Pine Street Barge Canal site were $13.4 million, inclusive of the $11.7 million referred to above. An authoritative accounting standard, Statement of Position (SOP) 96-1, has been issued by the accounting profession addressing environmental remediation obligations. This SOP is effective for years beginning in 1997, and addresses, among other things, regulatory benchmarks that are likely triggers of the accrual of estimated losses, the costs included in the measurement, including incremental costs of remediation efforts such as post-remediation monitoring and long-term operation and maintenance costs and costs of compensation and related benefits of employees devoting time to the remediation. This SOP, adopted by the Company in January 1997, as required, did not have a material adverse effect on the Company's financial position or results of operations. Clean Air Act -- Because the Company purchases most of its power supply from other utilities, it does not anticipate that it will incur any material direct cost increases as a result of the Federal Clean Air Act or proposals to make more stringent regulations under that Act. Furthermore, only one of its power supply purchase contracts, which expires in early 1998, relates to a generating plant that is likely to be affected by the acid rain provisions of this legislation. Overall, approximately 10 percent of the Company's committed electricity supply (a contract to purchase coal-fired generation that expires in early 1998) is expected to be affected by federal and state environmental compliance requirements. LIQUIDITY AND CAPITAL RESOURCES Construction -- The Company's capital requirements result from the need to construct facilities or to invest in programs to meet anticipated customer demand for electric service. If restructuring does occur, the Company will reassess its capital expenditures for generation and other projects and the terms of financing thereof. Capital expenditures over the past three years and projected for 1998 are as follows: Total Net Actual Generation Transmission Distribution Conservation Other Expenditures - ------ ---------- ------------ ------------ ------------ ----- ------------ (Dollars in thousands and net of AFUDC and Customer Advances For Construction) 1995 $2,696 $1,067 $8,935 $4,152 $2,969 $19,819 1996 6,287* 528 8,422 3,090 3,511 21,838 1997 3,462* 986 9,680 2,094 3,291 19,513 Forecasted 1998 $1,283 $501 $8,681 $2,500 $9,221 $22,186 *Includes $4.978 and $2.868 million for wind project in 1996 and 1997, respectively. Rates -- On June 16, 1997, the Company filed a request with the VPSB to increase retail rates by 16.7 percent ($26 million in additional annual revenues) and the target return on common equity from 11.25 percent to 13 percent. Initial hearings before the VPSB began November 3, 1997. The VPSB allowed the intervention of various other parties. In August 1997, several groups, including the Vermont Public Interest Research Group (VPIRG), demanded that the VPSB appoint an independent counsel to advocate against recovery of Hydro-Quebec power costs by the Company. The VPSB issued an order appointing an "independent investigator," described as a person or persons who will perform a rigorous and impartial analysis of the Company's actions with respect to its power supply options, including the Hydro-Quebec contract. On November 7, 1997, the VPSB selected a firm, MSB Energy Associates, Inc. (MSB) to undertake the tasks. In testimony filed with the VPSB on October 17, 1997, the Department asked the VPSB to find the Company's negotiation, execution and decision to "lock in" the contract with Hydro-Quebec to be imprudent and uneconomic. The Department had supported the contract in the period 1989-1991 after completing its own analysis, based on substantially the same information that was available to the Company. The VPSB in 1990, 1991, 1992 and 1994 issued orders that determined the contract to be needed to supply electricity to Vermont customers, economically beneficial to the State and an appropriate part of the Company's legally-required least-cost integrated resource plan. On October 31, 1997, the Company filed with the VPSB Objections and a Motion to Strike relating to the Hydro Quebec contract testimony and requested that the VPSB schedule oral argument on the motion prior to November 17, 1997. The grounds for the motion were that the VPSB had previously decided the issues sought to be relitigated. The VPSB heard argument on the motion on November 14, 1997 and ruled against the Company, but granted the Company leave to renew the motion. The Company did so in its post-hearing briefs. In its testimony, submitted in late 1997, MSB was critical of the Company's power supply decision-making in 1991, and recommended a steep disallowance of the Hydro-Quebec power costs, in excess of $10 million per year. During the rebuttal phase of the rate case, the Company showed that MSB was not independent and did not present "rigorous analysis" as the VPSB had ordered. MSB's presentation adopted the testimony of the Department's principal witnesses as well as theories espoused by a professional expert retained by IBM and MSB failed to present its own analysis showing that, based on any information possessed or available to the Company during the critical summer and fall of 1991, the long-term Hydro-Quebec contract was uneconomic. The Company filed a motion to strike the MSB testimony and to impose sanctions upon MSB for submitting testimony without any good faith factual or legal basis. The VPSB struck several portions of MSB's testimony forming the core of their arguments on imprudence, based on legal or contract interpretation, on the ground that MSB had no qualifications to present this testimony. Briefs in the case on non-Hydro-Quebec issues were filed January 30, 1998; the Hydro-Quebec briefs were filed on February 2; all reply briefs were filed on February 6. In its final submissions, the Company reduced the requested increase to 14.4 percent ($22 million in additional annual revenues) due to changed estimates of costs to be incurred in the rate year. On March 2, 1998, the VPSB released a decision in the rate case. The Order granted a $5.6 million increase in annual revenue in response to the Company's request for a $22 million increase in annual revenue. The Company is exploring all legal and regulatory remedies open to it to challenge the VPSB's decision. The VPSB's ruling, if not changed, would have a significant adverse impact on the Company's reported financial condition and 1998 results of operations and, depending on future proceedings to be conducted by the VPSB, could impact the Company's credit rating, dividend policy and financial viability. See Note I of the Notes to Consolidated Financial Statements for a complete discussion. Dividend Policy -- On September 17, 1997, the Company's Board of Directors announced a reduction in the quarterly dividend from $0.53 per share to $0.275 per share on the Company's common stock. Historically, the Company has based its dividend policy on the continued validity of three assumptions: The ability to achieve earnings growth, the receipt of an allowed rate of return that accurately reflects the Company's cost of capital, and the retention of its exclusive franchise. The Company's common stock dividend payout has ranged from 94 to 103 percent of earnings over the past five years. The Company's revised dividend policy, which incorporates a target payout ratio of 60 to 70 percent, reflects the greater risks facing the Company as a result of the changing environment of the electric utility industry. This policy contemplates a target payout that is in line with industry trends and is comparable to that of other companies in the utility industry. The policy assumes fair and appropriate ratemaking. However, the VPSB's recent rate Order, if unchanged, will require the Company to reassess the current dividend level. Financing and Capitalization -- For the period 1995 through 1997, internally generated funds, after payment of dividends, provided approximately 62 percent of total capital requirements for construction, sinking funds and other requirements. The Company anticipates that for 1998, internally generated funds will provide approximately 48 percent of total capital requirements for regulated operations. At December 31, 1997, the Company's capitalization consisted of 50.4 percent common equity, 41.8 percent long-term debt and 7.8 percent preferred equity. The Company has a comprehensive capital plan to increase the equity component of its capital structure. In May 1997, the rating of the Company's first mortgage bonds by Standard & Poor's was upgraded from "BBB+" to "A-," reflecting Standard & Poor's revised assessment of the ultimate recovery risk of the senior secured debt of utilities. The Company's corporate credit rating remains at "BBB+." The preferred stock rating remains at "BBB." In March 1998, Standard & Poor's placed the Company's credit ratings on Creditwatch with negative implications in reaction to what they characterize as an adverse ruling by the VPSB regarding the Company's rate increase request. The rating of the Company's first mortgage bonds by Duff & Phelps remains at "BBB+." The ratings of the Company's preferred stock remains at "BBB." In March 1998, Duff & Phelps placed the Company's credit ratings on Rating Watch - Down in reaction to what they characterize as a negative outcome in the Company's rate increase request decided by the VPSB. The rating of the Company's first mortgage bonds by Moody's Investment Services remains at "Baa2." The rating of the Company's preferred stock remains at "baa3." In March 1998, Moody's changed its rating outlook for the Company to negative and indicated the Company's credit ratings were pressured in reaction to what they characterize as a negative order from the VPSB regarding the Company's rate increase request. See Note F of the Notes to Consolidated Financial Statements for a discussion of the bank credit facilities available to the Company. See Note I of the Notes to Consolidated Financial Statements for a discussion of the VPSB rate order. Year 2000 Computer Compliance - The Company utilizes software and related technologies throughout its businesses that will be affected by the date change in the year 2000. The Company is in the process of implementing new customer service and financial systems which are year 2000 compliant. An internal study is currently underway to determine the full scope and related costs to insure that the Company's systems continue to meet its internal needs and those of its customers. Maintenance or modification costs will be expensed as incurred, while the costs of new software will be capitalized and amortized over the software's useful life. These expenditures may be significant and continue through the year 2000. The Company expects to have achieved compliance with year 2000 requirements for its financial and operating systems by June 30, 1999. Failure to comply by January 1, 2000 would have a material adverse effect on the Company's operations. 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. MANAGEMENT CHANGES The Company's Board of Directors elected Christopher L. Dutton as President and Chief Executive Officer and a director of the Company effective August 6, 1997. Mr. Dutton has served as Chief Financial Officer of the Company since 1995. He joined the Company in 1984 and served as Vice President and General Counsel before being named Chief Financial Officer of the Company. On October 6,1997, the Company's Board of Directors elected the following officers: Richard B. Hieber, Senior Vice President and Chief Operating Officer; Michael H. Lipson, General Counsel; Edwin M. Norse, Vice President and Chief Financial Officer and Treasurer; and Stephen C. Terry, Senior Vice President, Corporate Development. Jonathan H. Winer will continue to serve as President of the Company's subsidiary, Mountain Energy, Inc., and will assume new responsibilities as part of the Company's senior management. On February 9, 1998, the Company's Board of Directors elected the following officers: Mary G. Powell, Vice President Human Resources and Organizational Development, and Nancy R. Brock, Chief Corporate Strategic Planning Officer. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA GREEN MOUNTAIN POWER CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES Page Financial Statements Consolidated Statements of Income For the Years Ended December 31, 1997, 1996 and 1995 43 Consolidated Statements of Cash Flows For the Years Ended December 31, 1997, 1996 and 1995 44 Consolidated Balance Sheets as of December 31, 1997 and 1996 45-46 Consolidated Capitalization Data as of December 31, 1997 and 1996 47 Notes to Consolidated Financial Statements 48-69 Quarterly Financial Information 59-60 Report of Independent Public Accountants 70 Schedules For the Years Ended December 31, 1997, 1996 and 1995: II Valuation and Qualifying Accounts and Reserves 71 All other schedules are omitted as they are either not required, not applicable or the information is otherwise provided. Consents and Reports of Independent Public Accountants Arthur Andersen LLP 70 & 82
CONSOLIDATED STATEMENTS OF INCOME GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31 1997 1996 1995 ----------------- --------------- --------------- (In thousands, except amounts per share) Operating Revenues.............................................. $179,323 $179,009 $161,544 ----------------- --------------- --------------- Operating Expenses Power Supply Vermont Yankee Nuclear Power Corporation................... 32,817 30,596 30,222 Company-owned generation................................... 5,327 3,330 3,786 Purchases from others...................................... 62,222 66,320 53,915 Other operating............................................... 16,780 17,615 18,120 Transmission................................................. 11,122 10,833 9,874 Maintenance................................................... 4,785 4,463 4,210 Depreciation and amortization................................. 16,359 16,280 14,116 Taxes other than income....................................... 7,205 6,982 6,428 Income taxes.................................................. 7,191 6,463 5,578 ----------------- --------------- --------------- Total operating expenses................................... 163,808 162,882 146,249 ----------------- --------------- --------------- Operating Income......................................... 15,515 16,127 15,295 ----------------- --------------- --------------- Other Income Equity in earnings of affiliates and non-utility operations..................................... 427 2,880 3,513 Allowance for equity funds used during construction........... 357 175 27 Other income and deductions, net.............................. 789 175 94 ----------------- --------------- --------------- Total other income.......................................... 1,573 3,230 3,634 ----------------- --------------- --------------- Income before interest charges............................ 17,088 19,357 18,929 ----------------- --------------- --------------- Interest Charges Long-term debt................................................ 7,274 6,872 6,546 Other......................................................... 691 994 1,427 Allowance for borrowed funds used during construction............................................ (315) (468) (547) ----------------- --------------- --------------- Total interest charges...................................... 7,650 7,398 7,426 ----------------- --------------- --------------- Net Income...................................................... 9,438 11,959 11,503 Dividends on preferred stock.................................... 1,433 1,010 771 ----------------- --------------- --------------- Net Income Applicable to Common Stock........................... $8,005 $10,949 $10,732 ================= =============== =============== Common Stock Data Earnings per share............................................ $1.57 $2.22 $2.26 Cash dividends declared per share............................. $1.61 $2.12 $2.12 Weighted average shares outstanding........................... 5,112 4,933 4,747 The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS GREEN MOUNTAIN POWER CORPORATION December 31 1997 1996 --------- --------- (In thousands) ASSETS Utility Plant Utility plant, at original cost....................$265,441 $248,135 Less accumulated depreciation...................... 87,689 81,286 --------- --------- Net utility plant................................ 177,752 166,849 Property under capital lease....................... 8,342 9,006 Construction work in progress...................... 10,626 13,998 --------- --------- Total utility plant, net......................... 196,720 189,853 --------- --------- Other Investments Associated companies, at equity ................... 15,860 15,769 Other investments ................................. 6,137 4,865 --------- --------- Total other investments.......................... 21,997 20,634 --------- --------- Current Assets Cash............................................... 118 238 Accounts receivable, customers and others, less allowance for doubtful accounts............. 17,365 17,733 Accrued utility revenues........................... 6,505 6,662 Fuel, materials and supplies, at average cost...... 3,261 3,621 Prepayments........................................ 1,563 2,206 Other.............................................. 313 441 --------- --------- Total current assets............................. 29,125 30,901 --------- --------- Deferred Charges Demand side management programs.................... 13,692 16,409 Environmental proceedings costs.................... 8,441 7,991 Purchased power costs.............................. 4,283 9,163 Other.............................................. 9,415 9,661 --------- --------- Total deferred charges........................... 35,831 43,224 --------- --------- Non-Utility Cash and cash equivalents.......................... 153 511 Other current assets............................... 11,501 3,979 Property and equipment............................. 10,784 11,226 Intangible assets.................................. 2,116 2,555 Equity investment in energy-related businesses..... 12,824 12,494 Other assets....................................... 4,682 9,162 --------- --------- Total non-utility assets......................... 42,060 39,927 --------- --------- Total Assets...........................................$325,733 $324,539 ========= ========= The accompanying notes are an integral part of these consolidated financial statements. GREEN MOUNTAIN POWER CORPORATION December 31 1997 1996 --------- --------- (In thousands) CAPITALIZATION AND LIABILITIES Capitalization (See Capitalization Data) Common Stock Equity Common stock..................................... $17,318 $16,790 Additional paid-in capital....................... 70,720 68,226 Retained earnings................................ 26,717 26,916 Treasury stock, at cost.......................... (378) (378) --------- --------- Total common stock equity...................... 114,377 111,554 Redeemable cumulative preferred stock.............. 17,735 19,310 Long-term debt, less current maturities ........... 93,200 94,900 --------- --------- Total capitalization........................... 225,312 225,764 --------- --------- Capital Lease Obligation .............................. 8,342 9,006 --------- --------- Current Liabilities Current maturuties of long-term debt............... 1,700 3,034 Short-term debt.................................... 2,616 1,016 Accounts payable, trade, and accrued liabilities... 6,828 6,140 Accounts payable to associated companies........... 7,661 6,621 Dividends declared................................. 350 381 Customer deposits.................................. 721 689 Taxes accrued...................................... 2,843 986 Interest accrued................................... 1,311 1,382 Other.............................................. 1,256 788 --------- --------- Total current liabilities...................... 25,286 21,037 --------- --------- Deferred Credits Accumulated deferred income taxes.................. 23,501 26,726 Unamortized investment tax credits................. 4,542 4,825 Other.............................................. 25,680 23,417 --------- --------- Total deferred credits......................... 53,723 54,968 --------- --------- Non-Utility Current liabilities................................ 1,119 1,752 Other liabilities.................................. 11,951 12,012 --------- --------- Total non-utility liabilities.................. 13,070 13,764 --------- --------- Total Capitalization and Liabilities...................$325,733 $324,539 ========= ========= The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31 1997 1996 1995 --------- --------- --------- (In thousands) Operating Activities: Net Income........................................................... $9,438 $11,959 $11,503 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization.................................... 16,359 16,280 14,116 Dividends from associated companies less equity income........... (90) 254 660 Allowance for funds used during construction..................... (672) (643) (574) Deferred purchased power costs................................... (331) (5,917) (12,935) Amortization of purchased power costs............................ 5,212 5,187 6,036 Deferred income taxes............................................ (2,715) 1,937 3,715 Amortization of investment tax credits........................... (282) (282) (283) Environmental proceedings costs, net............................. (2,123) (1,720) (1,351) Conservation expenditures........................................ (2,411) (3,207) (3,960) Changes in: Accounts receivable............................................ 368 347 (2,841) Accrued utility revenues....................................... 156 (139) (510) Fuel, materials and supplies................................... 359 (309) 2 Prepayments and other current assets........................... (6,749) (354) 1,562 Accounts payable............................................... 1,728 221 2,191 Taxes accrued.................................................. 1,856 415 (871) Interest accrued............................................... (71) (465) (106) Other current liabilities...................................... (164) 1,065 (22) Other............................................................ 6,635 1,738 (95) --------- --------- --------- Net cash provided by operating activities.......................... 26,503 26,367 16,237 --------- --------- --------- Investing Activities: Construction expenditures.......................................... (16,409) (17,541) (15,314) Investment in non-utility property................................. 218 (2,203) (6,121) --------- --------- --------- Net cash used in investing activities............................ (16,191) (19,744) (21,435) --------- --------- --------- Financing Activities: Issuance of preferred stock........................................ -- 12,000 -- Reduction in preferred stock....................................... (1,575) (1,620) (205) Issuance of common stock........................................... 3,023 4,642 4,404 Short-term debt, net............................................... 1,600 (7,400) (11,799) Issuance of long-term debt......................................... -- 14,000 25,917 Reduction in long-term debt........................................ (4,201) (16,201) (4,833) Cash dividends..................................................... (9,637) (11,455) (10,818) --------- --------- --------- Net cash provided by (used in) financing activities.............. (10,790) (6,034) 2,666 --------- --------- --------- Net increase (decrease) in cash and cash equivalents............... (478) 589 (2,532) Cash and cash equivalents at beginning of year..................... 749 160 2,692 --------- --------- --------- Cash and Cash Equivalents at End of Year............................... $271 $749 $160 ========= ========= ========= The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED CAPITALIZATION DATA GREEN MOUNTAIN POWER CORPORATION December 31 Issued and Outstanding CAPITAL STOCK Authorized 1997 1996 1997 1996 ----------- ---------- ---------- --------- --------- (In thousands) Common Stock,$3.33 1/3 par value (Note C)....................... 10,000,000 5,195,432 5,037,143 $17,318 $16,790 ========= ========= ----------------------------------------------------------------------------------------------------------------- Outstanding Authorized Issued 1997 1996 1997 1996 ---------- ----------- ---------- ---------- --------- --------- (In thousands) Redeemable Cumulative Preferred Stock, $100 par value (Note D) 4.75%,Class B, redeemable at $101 per share..................................... 15,000 15,000 2,700 2,850 $270 $285 7%,Class C, redeemable at $101 per share..................................... 15,000 15,000 4,650 4,650 465 465 9.375%,Class D,Series 1, redeemable at $101 per share....................... 40,000 40,000 8,000 9,600 800 960 8.625%,Class D,Series 3, redeemable at $101.919 per share................... 70,000 70,000 42,000 56,000 4,200 5,600 7.32%,Class E,Series 1,.............................. 200,000 120,000 120,000 120,000 12,000 12,000 --------- --------- Total Preferred Stock................................... $17,735 $19,310 ========= ========= LONG-TERM DEBT (Note E) 1997 1996 --------- --------- (In thousands) First Mortgage Bonds 6.84% Series due 1997......................................................................................$ -- $1,334 7% Series due 1998......................................................................................... 3,000 3,000 5.71% Series due 2000...................................................................................... 5,000 5,000 6.21% Series due 2001...................................................................................... 8,000 8,000 6.29% Series due 2002...................................................................................... 8,000 8,000 6.41% Series due 2003...................................................................................... 8,000 8,000 10.0% Series due 2004 - Cash sinking fund,$1,700,000 annually............................................................................................... 11,900 13,600 7.05% Series due 2006...................................................................................... 4,000 4,000 7.18% Series due 2006...................................................................................... 10,000 10,000 6.7% Series due 2018....................................................................................... 15,000 15,000 9.64% Series due 2020...................................................................................... 9,000 9,000 8.65% Series due 2022 - Cash sinking fund,commences 2012................................................... 13,000 13,000 --------- --------- Total Long-term Debt Outstanding............................................................................. 94,900 97,934 Less Current Maturities (due within one year).............................................................. 1,700 3,034 --------- --------- Total Long-term Debt, Net.................................................................................... $93,200 $94,900 ========= ========= The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements A. SIGNIFICANT ACCOUNTING POLICIES 1. The Company. Green Mountain Power Corporation (the Company) is an investor-owned energy services company located in Vermont that serves one-quarter of its population. The most significant portion of the Company's net income is derived from its regulated electric utility operation, which purchases and generates electric power and distributes it to 83,200 retail and wholesale customers. Two of the Company's wholly-owned subsidiaries (which are not regulated by the Vermont Public Service Board (VPSB)) are Green Mountain Propane Gas Company (GMPG), which supplies propane to 10,000 customers in Vermont and New Hampshire, and Mountain Energy, Inc., which has invested in energy generation and energy and waste water efficiency projects across the United States. In 1996, the Company's wholly-owned, unregulated subsidiary, Green Mountain Resources, Inc. (GMRI), was created to participate in the emerging retail energy market. The results of these subsidiaries, the Company's unregulated rental water heater program and its other unregulated wholly-owned subsidiaries (GMP Real Estate Corporation and Lease-Elec, Inc.) are included in earnings of affiliates and non-utility operations in the Other Income section of the Consolidated Statements of Income. Summarized financial information is as follows: For the years ended December 31, 1997 1996 ---- ---- (In thousands) Revenues . . . . . . . . . . . . . . . $11,842 $11,997 Expenses. . . . . . . . . . . . . . . . 13,439 11,207 -------- ------- Net Income . . . . . . . . . . . . . . $(1,597) $ 790 ======== ======= In 1997, the Company and an affiliate of the Sam Wyly family announced that they will jointly own Green Mountain Energy Resources L.L.C. (GMER), a Delaware limited liability company in which GMRI was the sole owner. GMER is competing in the emerging retail energy market starting in California where customers are able to choose their electricity supplier as of March 31, 1998. See Management's Discussion and Analysis of Financial Condition and Results of Operations - Future Outlook - Unregulated Businesses for a complete discussion. The Company carries its investments in various associated companies - -- Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Vermont Electric Power Company, Inc. (VELCO), New England Hydro-Transmission Corporation, and New England Hydro-Transmission Electric Company -- at equity. 2. Basis of Presentation The Company's utility operations, including accounting records, rates, operations and certain other practices of its electric utility business, are subject to the regulatory authority of the Federal Energy Regulatory Commission (FERC) and the VPSB. The accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises in accordance with Statement of Financial Accounting Standards (SFAS) 71, Accounting for Certain Types of Regulation. Under SFAS 71, the Company is permitted to account for certain transactions in accordance with permitted regulatory treatment. As such, regulators may permit incurred costs, typically treated as expenses, to be deferred and recovered in future revenues. Conditions that give rise to the discontinuance of SFAS 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs, and (2) a change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. In the event that the Company no longer meets the criteria under SFAS 71, the Company would be required to write off related regulatory assets and liabilities. SFAS 121, Accounting for the Impairment of Long Lived Assets, which became effective for the Company January 1, 1996, requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based upon future cash flows. SFAS 121 requires that a rate-regulated enterprise recognize an impairment loss for regulatory assets which are no longer probable of recovery. As of December 31, 1997, based upon the regulatory environment within which the Company currently operates, no impairment loss need be recorded under SFAS 121. Competitive influences or regulatory developments may impact this status in the future. See Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of electric utility restructuring which may impact the Company's application of SFAS 71 and 121, and Note I of the Notes to Consolidated Financial Statements. 3. Statements of Cash Flows. The following amounts of interest (net of amounts capitalized) and income taxes were paid for the years ending December 31: 1997 1996 1995 ---- ---- ---- (In thousands) Interest . . . . . . . . . . . . . . . . $7,800 $8,104 $7,940 Income Taxes (Net of refunds) . . . . . 5,853 3,727 2,949 4. Utility Plant. The cost of plant additions includes all construction-related direct labor and materials, as well as indirect construction costs, including the cost of money (Allowance for Funds Used During Construction or AFUDC). The costs of renewals and betterments of property units are capitalized. The costs of maintenance, repairs and replacements of minor property items are charged to maintenance expense. The costs of units of property removed from service, net of removal costs and salvage, are charged to accumulated depreciation. 5. Depreciation. The Company provides for depreciation on the straight-line method based on the cost and estimated remaining service life of the depreciable property outstanding at the beginning of the year and adjusted for salvage value and cost of removal of the property. The annual depreciation provision was approximately 3.6 percent of total depreciable property at the beginning of each year 1997, 1996 and 1995. 6. Operating Revenues. Operating revenues consist principally of sales of electric energy. The Company records accrued utility revenues, based on estimates of electric service rendered and not billed at the end of an accounting period, in order to match revenues with related costs. 7. Deferred Charges. In a manner consistent with authorized or expected ratemaking treatment, the Company defers and amortizes certain replacement power, maintenance and other costs associated with the Vermont Yankee nuclear plant. In addition, the Company accrues and amortizes other replacement power expenses to reflect more accurately its cost of service to better match revenues and expenses consistent with regulatory treatment. The Company defers and amortizes costs associated with its investment in the demand side management program. At December 31, 1997, other deferred charges totaled $9.4 million, consisting of repair costs for the Essex and Vergennes hydroelectric facilities, regulatory deferrals of storm damages, rights-of-way maintenance, regulatory proceedings expenses, unamortized debt expense, preliminary survey and investigation charges, transmission interconnection charges and various other projects and deferrals. 8. Earnings Per Share. Earnings per share are based on the weighted average number of shares of common stock outstanding during each year. In March 1997, the Financial Accounting Standards Board issued a new accounting standard, Statement of Financial Accounting Standards No. 128, Earnings per Share (SFAS 128). SFAS 128, effective for financial statements issued for annual periods ending after December 15, 1997, replaces the definition of primary earnings per share, calculated in accordance with the provisions of APB 15, with a new calculation, basic earnings per share. Fully diluted earnings per share, now called diluted earnings per share, is still required. Since the Company has not issued any potentially dilutive securities, both calculations are the same. 9. Major Customers. The Company had one major retail customer, IBM, metered at two locations, that accounted for 14.0, 13.2 and 12.9 percent of operating revenues in 1997, 1996 and 1995, respectively. 10. Pension and Retirement Plans. The Company has a defined benefit pension plan covering substantially all of its employees. The retirement benefits are based on the employees' level of compensation and length of service. The Company's policy is to fund all accrued pension costs. The Company records annual expense based on amounts funded in accordance with methods approved in the rate-setting process. Net pension costs reflect the following components and assumptions: 1997 1996 1995 ---- ---- ---- (Dollars in thousands) Service cost-benefits earned during the period . $ 720 $ 689 $ 687 Interest cost on projected benefit obligations . 2,069 1,912 1,671 Actual return on plan assets . . . . . . . . . . (6,339) (4,383) (6,447) Net amortization and deferral . . . . . . . . . . 3,432 1,756 4,232 Effect of voluntary retirement program . . . . . --- 416 765 Adjustment due to actions of regulator . . . . . 126 (366) (878) ------ ------ ------- Net periodic pension cost funded and recognized . $ 8 $ 24 $ 30 ====== ====== ======= Assumptions used to determine pension costs and the related benefit obligation in 1997, 1996 and 1995 were: Discount rate . . . . . . . . . . . . . . . . 7.25% 8.0% 8.0% Rate of increase in future compensation levels 4.5% 5.0% 5.0% Expected long-term rate of return on assets . 9.0% 9.0% 9.0% The following table sets forth the plan's funded status as of December 31: 1997 1996 1995 ---- ---- ---- (In thousands) Actuarial present value of benefit obligations: Accumulated benefit obligations, including vested benefits of $24,231, $21,146 and $19,107, respectively . . . . ($25,717) ($21,376) ($19,431) ========= ========= ========= Projected benefit obligations for service rendered to date . . . . . . . . ($28,630) ($25,615) ($21,974) Plan assets at fair value . . . . . . . . . . 35,773 31,286 28,685 --------- --------- --------- Assets in excess of projected benefit obligations . . . . . . . . . . . . 7,143 5,671 6,711 Unrecognized net gain from past experience different from that assumed . . (5,962) (4,734) (5,188) Prior service cost not yet recognized in net periodic pension cost . . . . . . . . . . . 1,247 1,474 1,506 Unrecognized net asset at transition being recognized over 16.47 years . . . . . (1,249) (1,477) (1,706) Adjustment due to actions of regulator . . . . (1,179) (934) (1,323) -------- -------- ------- Prepaid pension cost included in other assets $ --- $ --- $ --- ======== ======== ======= The plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities. The Company also has a supplemental pension plan for certain employees. Pension costs for the years ended December 31, 1997, 1996 and 1995 were $456,000, $494,000 and $397,000, respectively, under this plan. This plan is funded in part through insurance contracts. 11. Postretirement Health Care Benefits. The Company provides certain health care benefits for retired employees and their dependents. Employees become eligible for these benefits if they reach normal retirement age while working for the Company. The Company accrues the cost of these benefits during the service life of covered employees. Accrued postretirement health care expenses are recovered in rates if those expenses are funded. In order to maximize the tax deductible contributions that are allowed under IRS regulations, the Company amended its pension plan to establish a 401-h sub-account and separate VEBA trusts for its union and non-union employees. The plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities. Net postretirement benefits costs reflect the following components and assumptions: 1997 1996 1995 ---- ---- ---- (In thousands) Accumulated postretirement benefit obligation: Current retirees . . . . . . . . . . . . ($ 6,412) ($ 4,563) ($ 4,594) Participants currently eligible . . . . (483) (772) (681) All others . . . . . . . . . . . . . . . (4,151) (3,837) (3,384) --------- --------- --------- Total accumulated postretirement benefit obligation . . . . . . . . . . . . . . . (11,046) (9,172) (8,659) Plan assets at fair value . . . . . . . . . 7,893 6,327 5,465 --------- --------- -------- Accumulated postretirement benefit obligation in excess of plan assets . . (3,153) (2,845) (3,194) Unrecognized prior service cost . . . . . . (805) (867) (929) Unrecognized transition obligation . . . . 5,278 5,630 5,982 Unrecognized net gain . . . . . . . . . . . (1,400) (1,879) (1,687) -------- -------- -------- Prepaid (accrued) postretirement benefit cost . . . . . . . . . . . . . . . . . . $ (80) $ 39 $ 172 ======== ======== ======== Net periodic postretirement benefit cost includes the following components: 1997 1996 1995 ---- ---- ---- (In thousands) Service cost . . . . . . . . . . . . . . . . $ 228 $ 247 $ 224 Interest cost . . . . . . . . . . . . . . . 763 698 697 Actual return on plan assets . . . . . . . . (1,566) (870) (586) Deferred asset gain. . . . . . . . . . . . . 1,028 407 264 Recognition of transition obligation, net of amortization . . . . . . . . . . . 261 245 234 ------- ------- ------- Total net periodic postretirement benefit cost . . . . . . . . . . . . . $ 714 $ 727 $ 833 ======= ======= ======= Assumptions used to determine postretirement benefit costs and the related benefit obligation were: 1997 1996 1995 ---- ---- ---- Discount rate to determine postretirement benefit costs . . . . . . . . . . . . . . 8.0% 8.0% 8.5% Discount rate to determine postretirement benefit obligation . . . . . . . . . . . . 7.25% 8.0% 8.5% Expected long-term rate of return on assets. 8.5% 8.5% 7.5% For measurement purposes, a 5.8 percent annual rate of increase in the per capita cost of covered benefits was assumed for 1997; the rate was assumed to decrease gradually to 5.0 percent by the year 2001 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed health care cost trend rate by one percentage point would increase the accumulated postretirement benefit obligation as of December 31, 1997 by $1.7 million and the aggregate of the service and interest components of net periodic postretirement benefit cost for the year ended December 31, 1997 by $156,000. 12. Fair Value of Financial Instruments. If the first mortgage bonds and preferred stock outstanding at December 31, 1997 were refinanced using new issue debt rates of interest, which, on average, are lower than the Company's outstanding rates, the present value of those obligations would differ from the amounts outstanding on the December 31, 1997 balance sheet by 4 percent. In the event of such a refinancing, there would be no gain or loss, inasmuch as under established regulatory precedent, any such difference would be reflected in rates and have no effect upon income. 13. Deferred Credits. At December 31, 1997, the Company had other deferred credits and long-term liabilities of $25.7 million, consisting of operating lease equalization, reserves for damage claims and environmental liabilities and accruals for employee benefits. 14. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions that affect assets and liabilities, the disclosure of contingent assets and liabilities, and revenues and expenses. Actual results could differ from those estimates. B. INVESTMENTS IN ASSOCIATED COMPANIES The Company accounts for investments in the following companies by the equity method: Percent Ownership Investment in Equity at December 31, 1997 December 31, -------------------- -------------------- 1997 1996 ---- ---- (In thousands) VELCO - Common . . . . . . . . . 29.5% $ 1,833 $ 1,834 - Preferred . . . . . . . 30.0% 961 1,118 -------- ------- Total VELCO . . . . . . . . . . 2,794 2,952 Vermont Yankee - Common . . . . 17.9% 9,701 9,768 New England Hydro-Transmission - Common . . . . . . . . . . 3.18% 1,063 1,205 New England Hydro-Transmission Electric - Common . . . . . 3.18% 1,811 1,891 ------- ------- $15,369 $15,816 ======= ======= Undistributed earnings in associated companies totaled $632,000 at December 31, 1997. VELCO. 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 other electric utilities, and under these agreements bills all costs, including interest on debt and a fixed return on equity, to the State and others using the system. The Company's purchases of transmission services from VELCO were $7.6 million, $7.7 million and $7.6 million for the years 1997, 1996 and 1995, respectively. Pursuant to VELCO's Amended Articles of Association, the Company is entitled to approximately 30 percent of the dividends distributed by VELCO. The Company has recorded its equity in earnings on this basis and also is obligated to provide its proportionate share of the equity capital requirements of VELCO through continuing purchases of its common stock, if necessary. Summarized financial information for VELCO is as follows: December 31, ------------------------ 1997 1996 1995 ---- ---- ---- (In thousands) Company's equity in net income . . . . . . . $ 354 $ 383 $ 377 ======= ======= ======= Total assets . . . . . . . . . . . . . . . . $70,566 $74,065 $71,668 Less: Liabilities and long-term debt . . . . . 61,162 64,159 61,238 ------ ------- ------- Net assets . . . . . . . . . . . . . . . . . $9,404 $ 9,906 $10,430 ====== ======= ======= Company's equity in net assets . . . . . . . $2,794 $ 2,952 $ 3,089 ====== ======= ======= Vermont Yankee. The Company is responsible for 17.7 percent of Vermont Yankee's expenses of operations, including costs of equity capital and estimated costs of decommissioning, and is entitled to a similar share of the power output of the nuclear plant, which has a net capacity of 531 megawatts. Vermont Yankee's current estimate of decommissioning costs is approximately $386 million, of which $193 million has been funded. At December 31, 1997, the Company's portion of the net unfunded liability was $34 million, which it expects will be recovered through rates over Vermont Yankee's remaining operating life. As a sponsor of Vermont Yankee, the Company also is obligated to provide 20 percent of capital requirements not obtained by outside sources. During 1997, the Company incurred $28.5 million in Vermont Yankee annual capacity charges, which included $1.9 million for interest charges. The Company's share of Vermont Yankee's long-term debt at December 31, 1997 was $16.2 million. The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Any liability beyond $8.9 billion is indemnified under an agreement with the Nuclear Regulatory Commission, but subject to congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing premiums of $79.3 million against each of the 110 reactor units in the United States that are currently subject to the Program, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is expected to be adjusted at least every five years to reflect inflationary changes. The above insurance now covers all workers employed at nuclear facilities for bodily injury claims. Vermont Yankee had previously purchased a Master Worker insurance policy with limits of $200 million with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee no longer participates in this retrospectively based worker policy and has replaced this policy with the guaranteed cost coverage mentioned above. Vermont Yankee does, however, retain a potential obligation for retrospective adjustments due to past operations of several smaller facilities that did not join the new program. These exposures will cease to exist no later than December 31, 2007. Vermont Yankee's maximum retrospective obligation remains at $3.1 million. The Secondary Financial Protection layer, as referenced above, would be in excess of the Master Worker policy. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available. The maximum potential assessment against Vermont Yankee with respect to NEIL losses arising during the current policy year is $11.0 million. Vermont Yankee's liability for the retrospective premium adjustment for any policy year ceases six years after the end of that policy year unless prior demand has been made. Summarized financial information for Vermont Yankee is as follows: December 31, -------------------------- 1997 1996 1995 ---- ---- ---- (In thousands) Earnings: Operating revenues . . . . . . . . . . . $173,106 $181,715 $180,437 Net income applicable to common stock . 6,834 6,985 6,790 Company's equity in net income . . . . . 1,244 1,232 1,171 Total assets . . . . . . . . . . . . . . . $610,024 $565,000 $531,293 Less: Liabilities and long-term debt . . . . . 555,735 510,202 477,350 -------- -------- -------- Net assets . . . . . . . . . . . . . . . . $ 54,289 $ 54,798 $ 53,943 ======== ======== ======== Company's equity in net assets . . . . . . $ 9,701 $ 9,768 $ 9,631 ======== ======== ======== C. COMMON STOCK EQUITY The Company maintains a Dividend Reinvestment and Stock Purchase Plan (DRIP) under which 388,508 shares were reserved and unissued at December 31, 1997. The Company also funds an Employee Savings and Investment Plan (ESIP). At December 31, 1997, there were 123,198 shares reserved and unissued under the ESIP. During 1995, the Company's Board of Directors, with subsequent approval of the Company's common shareholders, adopted the Compensation Program for Officers and Certain Key Management Personnel. The program links a portion of the officers and key management personnels' compensation to corporate performance results. Participants are entitled to receive cash and restricted and unrestricted stock grants in predetermined proportions. Participants who receive restricted stock are entitled to receive dividends and have voting rights but assumption of full beneficial ownership is contingent upon two restrictions of a five year duration, including no transferability and forfeiture of the stock upon termination of employment with the Company. Participants who receive unrestricted stock assume full beneficial ownership upon grant and may retain or sell such shares. During 1997, 10,956 shares of common stock were awarded under this program. At December 31, 1997, there were 20,083 shares reserved and unissued under the Compensation Program. Changes in common stock equity for the years ended December 31, 1995, 1996 and 1997 are as follows:
Common Stock Treasury Stock ------------------------ Paid-in Retained ------------------------ Stock Shares Amount Capital Earnings Shares Amount Equity ------ ------ ------- -------- ------ ------ ------ (Dollars in thousands) BALANCE, December 31, 1994............... 4,677,512 $15,592 $60,378 $25,727 15,856 ($378) $101,319 Common Stock Issuance: DRIP................................... 125,046 417 2,731 3,148 ESIP................................... 36,012 120 829 949 Compensation Program: Restricted Shares.................... 8,100 27 182 209 Stock Grant.......................... 3,826 12 86 98 Net Income............................... 11,503 11,503 Cash Dividends on Capital Stock: Common Stock -$2.12 per share..... (10,047) (10,047) Preferred Stock -$4.75 per share..... (15) (15) -$7.00 per share..... (36) (36) -$9.375 per share.... (116) (116) -$8.625 per share.... (604) (604) ------------------------------------------------------------------------------------ BALANCE, December 31, 1995............... 4,850,496 16,168 64,206 26,412 15,856 (378) 106,408 Common Stock Issuance: DRIP................................... 149,968 500 3,188 3,688 ESIP................................... 29,644 99 668 767 Compensation Program: Restricted Shares.................... 2,392 8 59 67 Stock Grant.......................... 4,643 15 105 120 Net Income............................... 11,959 11,959 Cash Dividends on Capital Stock: Common Stock -$2.12 per share..... (10,445) (10,445) Preferred Stock -$4.75 per share..... (14) (14) -$7.00 per share..... (35) (35) -$9.375 per share.... (101) (101) -$8.625 per share.... (543) (543) -$7.32 per share..... (317) (317) ------------------------------------------------------------------------------------ BALANCE, December 31, 1996............... 5,037,143 16,790 68,226 26,916 15,856 (378) 111,554 Common Stock Issuance: DRIP................................... 120,631 402 2,182 2,584 ESIP................................... 26,702 89 507 596 Compensation Program: Restricted Shares.................... 6,190 21 119 140 Stock Grant.......................... 4,766 16 92 108 Net Income............................... 9,438 9,438 Cash Dividends on Capital Stock: Common Stock -$2.12 per share..... (8,204) (8,204) Preferred Stock -$4.75 per share..... (13) (13) -$7.00 per share..... (33) (33) -$9.375 per share.... (86) (86) -$8.625 per share.... (423) (423) -$7.32 per share..... (878) (878) Other-Preferred Stock Issuance Expense... (406) (406) ------------------------------------------------------------------------------------ BALANCE, December 31, 1997............... 5,195,432 $17,318 $70,720 $26,717 15,856 ($378) $114,377 ====================================================================================
Dividend Restrictions. Certain restrictions on the payment of cash dividends on common stock are contained in the Company's indenture relating to long-term debt and in the Restated Articles of Association. Under the most restrictive of such provisions, $17.5 million of retained earnings were free of restrictions at December 31, 1997. The properties of the Company include several hydroelectric projects licensed under the Federal Power Act, with license expiration dates ranging from 1999 to 2025. At December 31, 1997, $350,000 of retained earnings had been appropriated as excess earnings on hydroelectric projects as required by Section 10(d) of the Federal Power Act. D. PREFERRED STOCK The holders of the preferred stock are entitled to specific voting rights with respect to certain types of corporate actions. They are also entitled to elect the smallest number of directors necessary to constitute a majority of the Board of Directors in the event of preferred stock dividend arrearages equivalent to or exceeding four quarterly dividends. Similarly, the holders of the preferred stock are entitled to elect two directors in the event of a default in any purchase or sinking fund requirements provided for any class of preferred stock. Certain classes of preferred stock are subject to annual purchase or sinking fund requirements. The sinking fund requirements are mandatory. The purchase fund requirements are mandatory, but holders may elect not to accept the purchase offer. The redemption or purchase price to satisfy these requirements may not exceed $100 per share plus accrued dividends. All shares redeemed or purchased in connection with these requirements must be canceled and may not be reissued. The annual purchase and sinking fund requirements for certain classes of preferred stock are as follows: Purchase and Sinking Fund 8.625%, Class D, Series 3 . . September 1 14,000 Shares 4.75%, Class B . . . . . . . . December 1 450 Shares 7%, Class C . . . . . . . . . December 1 450 Shares 9.375%, Class D, Series 1 . . December 1 1,600 Shares Under the Restated Articles of Association relating to Redeemable Cumulative Preferred Stock, the annual aggregate amount of purchase and sinking fund requirements for the next five years are $1,650,000 for each of the years 1998-1999, $1,640,000 for 2000 and $235,000 for 2001- 2002. Certain classes of preferred stock are redeemable at the option of the Company or, in the case of voluntary liquidation, at various prices on various dates. The prices include the par value of the issue plus any accrued dividends and a redemption premium. The redemption premium for Class B, C and D, Series 1, is $1.00 per share. The redemption premium for the Class D, Series 3, is $1.919 per share until September 1, 1998; and $0.916 per share from September 1, 1998 to September 1, 1999, after which there is no redemption premium. E. LONG-TERM DEBT Utility. Substantially all of the property and franchises of the Company are subject to the lien of the indenture under which first mortgage bonds have been issued. The annual sinking fund requirements (excluding amounts that may be satisfied by property additions) and long-term debt maturities for the next five years are: Sinking Funds Maturities Total ------- ---------- ----- (In thousands) 1998 . . . . . . . . . . . . . .$1,700 $3,000 $4,700 1999 . . . . . . . . . . . . . . 1,700 --- 1,700 2000 . . . . . . . . . . . . . . 1,700 5,000 6,700 2001 . . . . . . . . . . . . . . 1,700 8,000 9,700 2002 . . . . . . . . . . . . . . 1,700 8,000 9,700 Non-Utility. At December 31, 1997, Green Mountain Propane Gas Company, the Company's propane subsidiary, had long-term debt of $1,900,000, which was secured by substantially all of the subsidiary's assets, and Mountain Energy, Inc., the Company's subsidiary that invests in energy generation and energy and wastewater efficiency projects, had unsecured long-term debt of $1,583,330. The annual sinking fund requirements and maturities for the next three years are: Sinking Funds Maturities Total ------- ---------- ----- (In thousands) 1998 . . . . . . . . . . . . . $1,167 $ --- $1,167 1999 . . . . . . . . . . . . . 167 900 1,067 2000 . . . . . . . . . . . . . 83 1,166 1,249 F. SHORT-TERM DEBT Utility. On August 12, 1997, the Company entered into a revolving credit agreement in the amount of $45 million with three banks, which replaces a portion of its lines of credit. At December 31, 1997, there were no borrowings outstanding under this revolving credit agreement. At December 31, 1997, the Company had lines of credit with two banks totaling $8.0 million, with borrowings outstanding of $2.6 million. Borrowings under these lines of credit are at interest rates based on various market rates and are generally less than the prime rate. The Company has fee arrangements on its lines of credit ranging from 0 to 1/8 percent and no compensating balance requirements. These lines of credit are subject to periodic review and renewal during the year by the various banks. The weighted average interest rate on borrowings outstanding at December 31, 1997 and December 31, 1996 was 7.0 percent and 5.7 percent, respectively. Non-Utility. At December 31, 1997, Green Mountain Propane Gas Company, the Company's propane subsidiary, had a line of credit with a bank for $750,000, with $400,000 outstanding. G. INCOME TAXES Utility. The Company accounts for income taxes using an asset and liability approach. This approach accounts for deferred income taxes by applying statutory rates in effect at year end to the differences between the book and tax bases of assets and liabilities. The regulatory assets and liabilities represent taxes that will be collected from or returned to customers through rates in future periods. As of December 31, 1997 and 1996, the net regulatory assets were $1,704,000 and $1,194,000, respectively. The temporary differences which gave rise to the net deferred tax liability at December 31, 1997 and December 31, 1996, were as follows: At December 31, At December 31, 1997 1996 --------------- --------------- (In thousands) Deferred Tax Assets Contributions in aid of construction $ 7,946 $ 7,094 Deferred compensation and post-retirement benefits . . . . . . 3,199 2,944 Alternative minimum tax credit . . . 15 (552) Other . . . . . . . . . . . . . . . . 3,212 2,719 ------- ------- 14,372 12,205 ------- ------- Deferred Tax Liabilities Property-related and other . . . . . 31,864 29,359 Demand side management costs . . . . 4,775 5,856 Deferred purchased power costs . . . 1,234 3,716 -------- -------- 37,873 38,931 -------- -------- Net accumulated deferred income tax liability . . . . . . . . . . . . . ($23,501) ($26,726) ========= ========= The following table reconciles the change in the net accumulated deferred income tax liability to the deferred income tax expense included in the income statement for the period: Year Ended December 31, -------------------------- 1997 1996 1995 ---- ---- ---- (In thousands) Net change in deferred income tax liability per above table . . . . . . . . . ($3,225) $1,434 $3,210 Change in income tax related regulatory assets and liabilities. . . . . . . . . . . 509 504 503 Change in alternative minimum tax credit . . 567 109 168 IRS audit adjustment, 1989 - 1990 . . . . . . -- -- 255 -------- ------ ------ Deferred income tax expense for the period . ($2,149) $2,047 $4,136 ======== ====== ====== The components of the provision for income taxes are as follows: Year Ended December 31, ---------------------------- 1997 1996 1995 ---- ---- ---- (In thousands) Current federal income taxes . . . . . . $7,355 $3,708 $ 1,359 Current state income taxes . . . . . . . 2,267 990 365 ------ ------ ------- Total current income taxes. . . . . . 9,622 4,698 1,724 ------ ------ ------- Deferred federal income taxes . . . . . (1,623) 1,588 3,239 Deferred state income taxes . . . . . . (526) 459 897 ------- ----- ----- Total deferred income taxes. . . . . . (2,149) 2,047 4,136 ------- ----- ----- Investment tax credits -- net . . . . . (282) (282) (282) ------ ------- ------- Income taxes charged to operations . . . $7,191 $6,463 $5,578 ====== ======= ======= Total federal income taxes differ from the amounts computed by applying the statutory tax rate to income before taxes. The reasons for the differences are as follows: Year Ended December 31, ------------------------- 1997 1996 1995 ---- ---- ---- (Dollars in thousands) Income before income tax . . . . . . . $16,630 $18,422 $17,081 Federal statutory rate . . . . . . . . 34.5% 34% 34% Computed "expected" federal income taxes . . . . . . . . . . . . $ 5,737 $ 6,263 $ 5,808 Increase (decrease) in taxes resulting from: Tax versus book depreciation . . . . 349 327 327 Dividends received and paid credit . (575) (524) (616) AFUDC - equity funds . . . . . . . . (123) (59) (9) Amortization of ITC . . . . . . . . (282) (282) (282) State tax benefit . . . . . . . . . (601) (493) (429) Excess deferred taxes . . . . . . . (60) (60) (60) Taxes attributable to subsidiaries . 682 (140) (401) Tax reserve . . . . . . . . . . . . 270 (101) (3) Other . . . . . . . . . . . . . . . 53 83 (19) ------ ------ ------- Total federal income taxes . . . . . . $5,450 $5,014 $4,316 ====== ====== ======= Effective federal income tax rate . . 32.8% 27.2% 25.3% Non-Utility. The Company's non-utility subsidiaries had accumulated deferred income taxes of $7.1 million on their balance sheets at December 31, 1997, largely attributable to property-related transactions. The components of the provision for the income tax/(benefit) for the non-utility operations are: Year Ended December 31, ----------------------------- 1997 1996 1995 ---- ---- ---- (In thousands) State income taxes . . . . . . . . . . $ 78 $154 $165 Federal income taxes . . . . . . . . . (1,071) 207 613 Investment tax credits . . . . . . . . (45) (45) (45) -------- ------ ------ Income tax (benefit)/provision charged to operations. . . . . . . . . . . . . $(1,038) $ 316 $ 733 ======== ====== ====== The effective federal income tax rates for the non-utility operations were 37.0 percent, 22.4 percent, and 29.7 percent for the years ended December 31, 1997, 1996 and 1995, respectively. The increase in 1997 income taxes is primarily due to an increase in taxable income, an increase in the combined federal and state income tax rate and an increase in the reserve for unaudited income tax years. H. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The following quarterly financial information, in the opinion of management, includes all adjustments necessary to a fair statement of results of operations for such periods. Variations between quarters reflect the seasonal nature of the Company's business and the timing of rate changes. 1997 Quarter Ended ------------------ March June Sept. Dec. Total ----- ---- ----- ---- ----- (Amounts in thousands, except per share) Operating Revenues . . . . . . $ 47,204 $42,682 $43,574 $45,863 $179,323 Operating Income . . . . . . . 4,251 2,991 4,542 3,731 15,515 Net Income . . . . . . . . . . 3,315 1,230 3,371 1,522 9,438 Net Income Applicable to Common Stock . . . . . . . . 2,941 856 3,022 1,186 8,005 Earnings per Average Share of Common Stock . . . . . . . . $0.58 $0.17 $0.59 $0.23 $1.57 Weighted Average Number of Common Shares Outstanding . 5,044 5,096 5,138 5,168 5,112 1996 Quarter Ended ------------------ March June Sept. Dec. Total ----- ---- ----- ---- ----- (Amounts in thousands, except per share) Operating Revenues . . . . . . $ 48,415 $40,467 $44,423 $45,704 $179,009 Operating Income . . . . . . . 5,073 1,859 4,419 4,776 16,127 Net Income . . . . . . . . . . 4,065 1,024 3,474 3,396 11,959 Net Income Applicable to Common Stock . . . . . . . . 3,875 834 3,315 2,925 10,949 Earnings per Average Share of Common Stock . . . . . . . . $0.80 $0.17 $0.67 $0.58 $2.22 Weighted Average Number of Common Shares Outstanding . 4,860 4,911 4,959 5,003 4,933 I. COMMITMENTS AND CONTINGENCIES 1. Industry Restructuring. The electric utility business is being subjected to rapidly increasing competitive pressures stemming from a combination of trends, including the presence of surplus generating capacity, a disparity in electric rates among and within various regions of the country, improvements in generation efficiency, increasing demand for customer choice, and new regulations and legislation intended to foster competition. For a complete discussion, see Management's Discussion and Analysis of Financial Condition and Results of Operations - "Future Outlook". 2. Environmental Matters. Public concern for the environment has resulted in increased government regulation of the licensing and operation of electric generation, transmission and distribution facilities. The electric industry typically uses or generates a range of potentially hazardous products in its operations. The Company must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. The Company maintains an environmental compliance and monitoring program that includes employee training, regular inspection of Company facilities, research and development projects, waste handling and spill prevention procedures and other activities. Subject to developments concerning the Pine Street Barge Canal site described below, the Company believes that it is in substantial compliance with such requirements, and no material complaints concerning compliance by the Company with present environmental protection regulations are outstanding. 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. The Company has been notified by the Environmental Protection Agency (EPA) that it is one of several potentially responsible parties (PRPs) for cleanup of the Pine Street Barge Canal site in Burlington, Vermont, where coal tar and other industrial materials were deposited. From the late 19th century until 1967, gas was manufactured at the Pine Street Barge Canal site by a number of enterprises, including the Company. In 1990, the Company was one of the 14 parties that agreed to pay a total of $945,000 of the EPA's past response costs under a Consent Decree. The Company remains a PRP for other past, ongoing and future response costs. In November 1992, the EPA proposed a cleanup plan estimated by the EPA to cost $47 million. In June 1993, the EPA withdrew this cleanup plan in response to public concern about the plan and its cost. The cost of any future cleanup plan, the magnitude of unresolved EPA cost recovery claims, and the Company's share of such costs are uncertain at this time. Since 1994, the EPA has established a coordinating council, with representatives of the PRPs, environmental and community groups, the City of Burlington and the State of Vermont presided over by a neutral facilitator. The council has determined, by consensus, what additional studies were appropriate for the site, and is addressing the question of additional response activities. The EPA, the State of Vermont and other parties have entered into two consent orders for completion of appropriate studies. Work is continuing under the second of those orders. Most recently, on September 23, 1997, the council reached tentative agreement on a key component of the proposed remedy for the Pine Street site, namely, placement of an underwater sand/silt cap on areas of the canal and wetland sediments, combined with long-term monitoring to ensure effectiveness of the cap and to ensure that groundwater does not reach Lake Champlain, adjacent to the site. The EPA has estimated the costs of this remedy at between $6 to $10 million, subject to change. In addition, the council is exploring supplemental projects in and around the site and Burlington as part of a larger plan to improve environmental conditions in the vicinity. On December 1, 1994, the Company, and two other PRPs, New England Electric System (NEES) and Vermont Gas Systems (VGS), entered into a confidential settlement agreement with the State of Vermont, the City of Burlington and nearly all other landowner PRPs under which, subject to certain qualifications, the liability of those landowner PRPs for future Superfund response costs would be limited and specified. On December 1, 1994, the Company entered into a confidential agreement with VGS compromising contribution and cost recovery claims of each party and contractual indemnity claims of the Company arising from the 1964 sale of the manufactured gas plant to VGS. In March 1996, the Company and NEES entered into a confidential agreement compromising past and future contribution and cost recovery claims of both parties relating to response costs. In December 1997, the Company and Southern Union Co. entered into a confidential settlement agreement compromising past and future contribution and cost recovery claims of both parties relating to response costs. The Company has received payment of the full amount provided for in the settlement. In January 1998, the Company and UGI Utilities, Inc. entered into a confidential settlement agreement compromising past and future contribution and cost recovery claims of both parties relating to response costs. The Company has received payment of the initial amount provided for in the settlement. The EPA has advised the Company that it has incurred substantial unrecovered response sums at the site which, together with interest the EPA alleges may be payable, amounts to approximately $11.0 million. The Company has not yet received a formal demand for these sums. The Company will vigorously dispute the EPA's recovery of such costs, which include substantial sums for studies and other activities that were not reasonably necessary and were not undertaken consistent with legal and regulatory requirements. Further, the Company's settlement agreements with certain PRP's will reduce the extent to which it may bear these past response costs. Consequently, the Company is not able at this time to predict with certainty whether, or the extent to which it will be required to pay such past response costs. In December 1991, the Company brought suit against eight previous insurers seeking recovery of unrecovered past costs, cost of defense and indemnity against future liabilities associated with environmental problems at the site. Discovery in the case, which was previously subject to a stay, is complete. The Company has reached confidential settlements with the defendants in this litigation; several such settlements are in the final stages of documentation. The Company has deferred amounts received from third parties, under confidential settlements, pending resolution of the Company's ultimate liability with respect to the site and rate recognition of that liability. Although the cost of the coordinating council's tentative remediation plan, described above, is not expected to approach EPA's earlier estimate of remediation costs for its original clean-up plan, because the current EPA estimate is subject to change, and because the Company believes it may prevail with respect to some of the EPA's unrecovered response costs, the Company is unable to predict at this time the magnitude of any liability resulting from potential claims for the costs to investigate and remediate the site, or the likely disposition or magnitude of claims the Company may have against others, including its insurers, except to the extent described above. Through rate cases filed in 1991, 1993, 1994 and 1995, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Barge Canal site. Specifically, the Company proposed rate recognition of its unrecovered expenditures incurred between January 1, 1991 and June 30, 1995 (in the total of approximately $8.7 million) for technical consultants and legal assistance in connection with the EPA's enforcement action at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for the Pine Street Barge Canal site related costs, the Company and the Vermont Department of Public Service (the Department) reached agreements in these cases that the full amount of the Pine Street Barge Canal site costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB in those proceedings reflected the Pine Street Barge Canal site related expenditures referred to above. The Company proposed, in a rate filing made on June 16, 1997 recovery of an additional $3.0 million in such expenditures. In an Order released March 2, 1998, the VPSB suspended the amortization of expenditures associated with the Pine Street Barge Canal 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 of the Pine Street Barge Canal, taking into account recoveries from insurance carriers and other PRP's, should be shared between customers and shareholders of the Company. As of December 31, 1997, total expenditures for the Pine Street Barge Canal site were $13.4 million, inclusive of the $11.7 million referred to above. An authoritative accounting standard, Statement of Position (SOP) 96-1, has been issued by the accounting profession addressing environmental remediation obligations. This SOP is effective for years beginning in 1997, and addresses, among other things, regulatory benchmarks that are likely triggers of the accrual of estimated losses, the costs included in the measurement, including incremental costs of remediation efforts such as post-remediation monitoring and long-term operation and maintenance costs and costs of compensation and related benefits of employees devoting time to the remediation. This SOP, adopted by the Company in January 1997, as required, did not have a material adverse effect on the Company's financial position or results of operations, due to current ratemaking treatment. Should a change in the Company's historical ratemaking occur this conclusion could change. 3. Operating Leases. The Company has an operating lease for its corporate headquarters building and two of its service center buildings, including related real estate. This lease has a base term of 25 years, ending June 30, 2009, with renewal options aggregating another 25 years. The annual lease charges will total $983,000 for each of the years 1998 through 2008 and $574,000 for 2009. The Company has options to purchase the buildings at fair market value at the end of the base term and at the end of each renewal period. 4. Jointly-Owned Facilities. The Company had joint-ownership interests in electric generating and transmission facilities at December 31, 1997, as follows: Ownership Share of Utility Accumulated Interest Capacity Plant Depreciation --------- -------- ------- ------------ (In %) (In MW) (In thousands) Highgate . . . . . . . . . . 33.8 67.6 $10,592 $3,309 McNeil . . . . . . . . . . . 11.0 5.9 $ 8,633 $3,613 Stony Brook (No. 1) . . . . . 8.8 31.0 $10,039 $6,348 Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,384 $1,384 Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 431 (1) Neutral conductor for NEPOOL/Hydro-Quebec Interconnection The Company's share of expenses for these facilities is reflected in the Consolidated Statements of Income. Each participant in these facilities must provide for its own financing. 5. Rate Matters. On June 16, 1997, the Company filed a request with the VPSB to increase retail rates by 16.7 percent ($26 million in additional annual revenues) and the target return on common equity from 11.25 percent to 13 percent. Initial hearings before the VPSB began November 3, 1997. The VPSB allowed the intervention of various other parties. In August 1997, several groups, including the Vermont Public Interest Research Group (VPIRG), demanded that the VPSB appoint an independent counsel to advocate against recovery of Hydro-Quebec power costs by the Company. The VPSB issued an order appointing an "independent investigator," described as a person or persons who will perform a rigorous and impartial analysis of the Company's actions with respect to its power supply options, including the Hydro-Quebec contract. On November 7, 1997, the VPSB selected a firm, MSB Energy Associates, Inc. (MSB) to undertake the tasks. In testimony filed with the VPSB on October 17, 1997, the Department asked the VPSB to find the Company's negotiation, execution and decision to "lock in" the contract with Hydro-Quebec to be imprudent and uneconomic. The Department had supported the contract in the period 1989-1991 after completing its own analysis, based on substantially the same information that was available to the Company. The VPSB in 1990, 1991, 1992 and 1994 issued orders that determined the contract to be needed to supply electricity to Vermont customers, economically beneficial to the State and an appropriate part of the Company's legally-required least-cost integrated resource plan. On October 31, 1997, the Company filed with the VPSB Objections and a Motion to Strike relating to the Hydro Quebec contract testimony and requested that the VPSB schedule oral argument on the motion prior to November 17, 1997. The grounds for the motion were that the VPSB had previously decided the issues sought to be relitigated. The VPSB heard argument on the motion on November 14, 1997 and ruled against the Company, but granted the Company leave to renew the motion. The Company did so in its post-trial briefs. In its testimony, submitted in late 1997, MSB was critical of the Company's power supply decision-making in 1991, and recommended a steep disallowance of the Hydro-Quebec power costs, in excess of $10 million per year. During the rebuttal phase of the rate case, the Company showed that, MSB was not independent and did not present "rigorous analysis" as the VPSB had ordered. MSB's presentation adopted the testimony of the Department's principal witnesses as well as theories espoused by a professional expert retained by IBM and MSB failed to present its own analysis showing that, based on any information possessed or available to the Company during the critical summer and fall of 1991, the long-term Hydro-Quebec contract was uneconomic. The Company filed a motion to strike the MSB testimony and to impose sanctions upon MSB for submitting testimony without any good faith factual or legal basis. The VPSB struck several portions of MSB's testimony forming the core of their arguments on imprudence, based on legal or contract interpretation, on the ground that MSB had no qualifications to present this testimony. Briefs in the case on non-Hydro-Quebec issues were filed January 30, 1998; the Hydro-Quebec briefs were filed on February 2; all reply briefs were filed on February 6. In its final submissions, the Company reduced the requested increase to 14.4 percent due to changed estimates of costs to be incurred in the rate year. 6. Subsequent Events. On March 2, 1998, the VPSB released its Order in the Company's pending rate case. The VPSB ordered the Company's rates increased by 3.61 percent, increasing annual revenues by $5.6 million. The Company had sought in its final submissions to the VPSB an increase of $22 million in revenue to cover increased cost of service. Approximately $11 million of the reduction of the Company's revenue request resulted primarily from the VPSB's modification of the Company's calculation of rate base, the exclusion of future capital projects from rate base, various cost of service reductions in areas of payroll and operations and maintenance, and a reduction in the requested allowed return on equity from 13 percent to 11.25 percent. More significantly, the VPSB denied the recovery by the Company of $5.48 million in costs related to its long-term Hydro-Quebec power contract. The decision stated that the Company had been imprudent in locking-into the power contract in August 1991 and that the contract power would not be used and useful to utility customers to the extent that power costs, after accounting for the imprudence disallowance, were in excess of current estimates of market prices for power. Unless the Order is modified, the Company must accrue its estimate of the loss related to these imprudence and used and useful disallowances. The Order discussed the VPSB's policies of disallowing the recovery of imprudent expenditures and power contract purchases that it determines not to be used and useful. However, the Order also stated that the methodologies and measures used in this rate case were provisional and applicable in the current proceeding only. The VPSB went on to state that it will schedule subsequent proceedings to examine the appropriate methodologies for measuring the effects of imprudence and calculating the portion of the contract that is not used and useful. If the VPSB were to apply the methodologies and measures used in the Order (or similar methodologies and measures) to future power contract costs, notwithstanding its statement that it will reexamine such matters, the Company would be required under Statement of Financial Accounting Standards No. 5 to record an expense of approximately $180 million based on the estimated future market price of power used by the VPSB in its Order. However, the Company will not be able to estimate the loss to be recorded, if any, until the reconsideration and appeal processes and such subsequent proceedings are completed. Furthermore, if the VPSB's ruling, that above-market Hydro-Quebec power contract costs are not used and useful and should be shared equally between ratepayers and shareholders, is not modified, then the Company's rates may be set, effectively, on a basis other than its costs to provide service. This would require the Company to discontinue the application of Statement of Financial Accounting Standards No. 71, resulting in the write-off of regulatory assets and liabilities with a charge to earnings, as an extraordinary item. As of December 31, 1997, the Company had approximately $15 million of net regulatory assets on its balance sheet. In addition to the Hydro-Quebec power contract disallowances described above, the Order also requires the Company to create a deferred credit for $9.1 million of payments received by the Company in 1997 pursuant to two arrangements with Hydro-Quebec that were designed to decrease the costs of the contract power. The Order, contrary to the VPSB's prior Accounting Order dated December 31, 1996, now requires the Company to amortize this deferred credit over the remaining lives of the related power contracts. Unless the current Order is modified, the Company would be required to expense approximately $8.6 million previously recognized in earnings related to the $9.1 million. In response to the Order, the rating agencies that rate the Company's fixed income securities have placed the Company's credit ratings on their rating watch or rating outlook with negative or down implications. The Company is exploring all legal and regulatory remedies open to it to challenge the VPSB decision, including requesting reconsideration from the VPSB and a direct appeal to the Vermont Supreme Court. The Company believes that the decisions set forth in the Order are inaccurate factually and incorrect legally. The VPSB's ruling, if not changed, would have a significant impact on the Company's reported financial condition and 1998 results of operations and, depending on the outcome of future proceedings to be conducted by the VPSB, could impact the Company's credit ratings, dividend policy and financial viability. On February 20, 1998, the Company and GMPG entered into a sales agreement with VGS Propane, LLC, for the sale of all GMPG assets which had a net book value of $8.1 million at December 31, 1997. This sale is not expected to have a material impact on the Company's results of operations. 7. Deferred Charges Not Included in Rate Base. The Company has incurred and deferred approximately $3.1 million in costs for tree trimming, storm damage and regulatory commission work. Currently, the Company amortizes such costs based on historical averages and does not receive a return on amounts deferred. Management expects to seek and receive ratemaking treatment for these costs in future filings. In early January 1998, Vermont and much of the Northeast experienced a severe ice storm which resulted in approximately $2.5 million of storm damage costs which will also be deferred. Management will seek and expects to receive a return on these costs as discussed above. 8. Other Legal Matters. The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material effect on the financial position or the results of operations of the Company. J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT Agreements executed in 1985 among the Company, VELCO and other NEPOOL members and Hydro-Quebec provided for the construction of the second phase (Phase II) of the interconnection between the New England electric systems and that of Hydro-Quebec. Phase II expands the Phase I facilities from 690 megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec power from the Phase I terminal in northern New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II commenced in 1988 and was completed in late 1990. The Company is entitled to 3.2 percent of the Phase II power-supply benefits. Total construction costs for Phase II were approximately $487 million. The New England participants, including the Company, have contracted to pay monthly their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. As a supporting participant, the Company must make support payments under thirty-year agreements. These support agreements meet the capital lease accounting requirements under SFAS 13. At December 31, 1997, the present value of the Company's obligation is $8.3 million. Projected future minimum payments under the Phase II support agreements are as follows: Year ending December 31, 1998 . . . . . . . . . . . $ 463,450 1999 . . . . . . . . . . . 463,450 2000 . . . . . . . . . . . 463,450 2001 . . . . . . . . . . . 463,450 2002 . . . . . . . . . . . 463,450 Total for 2003-2020 . . . 6,024,845 ---------- $8,342,095 ========== The Phase II portion of the project is owned by New England Hydro- Transmission Electric Company and New England Hydro-Transmission Corporation, subsidiaries of New England Electric System, in which certain of the Phase II participating utilities, including the Company, own equity interests. The Company holds approximately 3.2 percent of the equity of the corporations owning the Phase II facilities. K. LONG-TERM POWER PURCHASES 1. Unit Purchases. Under long-term contracts with various electric utilities in the region, the Company is purchasing certain percentages of the electrical output of production plants constructed and financed by those utilities. Such contracts obligate the Company to pay certain minimum annual amounts representing the Company's proportionate share of fixed costs, including debt service requirements (amounts necessary to retire the principal of and to pay the interest on the portion of the related long-term debt ascribed to the Company) whether or not the production plants are operating. The cost of power obtained under such long-term contracts, including payments required to be made when a production plant is not operating, is reflected as "Power Supply Expenses" in the accompanying Consolidated Statements of Income. Information (including estimates for the Company's portion of certain minimum costs and ascribed long-term debt) with regard to significant purchased power contracts of this type in effect during 1997 follows: Stony Vermont Merrimack Brook Yankee --------- ----- ------- (Dollars in thousands) Plant capacity . . . . . . . . . . . 320.0 MW 352.0 MW 531.0 MW Company's share of output . . . . . 8.9% 4.4% 17.7% Contract period . . . . . . . . . . 1968-1998 (1) (2) Company's annual share of: Interest . . . . . . . . . . . . . $ 645 $ 221 $ 1,850 Other debt service . . . . . . . . 371 319 --- Other capacity . . . . . . . . . . 1,939 387 25,328 ------ ------ ------- Total annual capacity . . . . . . . $2,955 $ 927 $27,178 ====== ====== ======= Company's share of long-term debt . $ 894 $4,241 $16,220 ====== ====== ======= (1) Life of plant estimated to be 1981 - 2006. (2) License for plant operations expires in 2012. 2. Hydro-Quebec System Power Purchases. Under various contracts, the details of which are described in the table below, the Company purchases capacity and associated energy produced by the Hydro-Quebec system. Such contracts obligate the Company to pay certain fixed capacity costs whether or not energy purchases above a minimum level set forth in the contracts are made. Such minimum energy purchases must be made whether or not other, less expensive energy sources might be available. These contracts are intended to complement the other components in the Company's power supply to achieve the most economic power-supply mix reasonably available. The Company's current purchases pursuant to the contract with Hydro-Quebec entered into December 4, 1987 (the 1987 Contract) are as follows: (1) Schedule B -- 68 megawatts of firm capacity and associated energy to be delivered at the Highgate interconnection for twenty years beginning in September 1995; and (2) Schedule C3 -- 46 megawatts of firm capacity and associated energy to be delivered at interconnections to be determined at any time for 20 years, which began in November 1995. During 1994, the Company negotiated an arrangement with Hydro- Quebec that reduces the cost impacts associated with the purchase of Schedules B and C3 under the 1987 Contract, over the November 1995 through October 1999 period (the July 1994 Agreement). Under the July 1994 Agreement, the Company, in essence, will take delivery of the amounts of energy as specified in the 1987 Contract, but the associated fixed costs will be significantly reduced from those specified in the 1987 Contract. As part of the July 1994 Agreement, the Company is obligated to purchase $4 million (in 1994 dollars) worth of research and development work from Hydro-Quebec over the four-year period, and made a $6.5 million (in 1994 dollars) cash payment to Hydro-Quebec in 1995. Hydro- Quebec retains the right to curtail annual energy deliveries by 10 percent up to five times, over the 2000 to 2015 period, if documented drought conditions exist in Quebec. During the first year of the July 1994 Agreement (the period from November 1995 through October 1996), the average cost per kilowatt-hour of Schedules B and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a 34 percent (or $16 million) cost reduction. Over the period from November 1996 through December 2000 and accounting for the cash payments to Hydro-Quebec, the combined unit costs will be lowered from 6.6 to 5.9 cents per kilowatthour, reducing unit costs by 10 percent and saving $20.7 million in nominal terms. All of the Company's contracts with Hydro-Quebec call for the delivery of system power and are not related to any particular facilities in the Hydro-Quebec system. Consequently, there are no identifiable debt-service charges associated with any particular Hydro- Quebec facility that can be distinguished from the overall charges paid under the contracts. A summary of the Hydro-Quebec contracts, including the July 1994 Agreement, but excluding the January and November 1996 arrangements (described below) including historic and projected charges for the years indicated, follows: The 1987 Contract Schedule B Schedule C3 ---------- ----------- (Dollars in thousands) Capacity Acquired . . . . 68 MW 46 MW Contract Period . . . . . 1995-2015 1995-2015 Minimum Energy Purchase (annual load factor) . . 75% 75% Annual Energy Charge . . $10,555 $7,188 (1997) (1997) $14,999 $10,347 (1998-2015)* (1998-2015)* Annual Capacity Charge . . $14,018 $1,913 (1997) (1997) $17,135 $11,320 (1998-2015)* (1998-2015)* Average Cost per KWH . . 6.1 cents 3.3 cents (1997) ** (1997)** 7.0 cents 6.7 cents (1998-2015)*** (1998-2015)*** * Estimated average. ** Excludes amortization of payments to Hydro-Quebec for the July 1994 Agreement. ***Estimated average in nominal dollars, levelized over the period indicated. Includes amortization of payments to Hydro-Quebec for the July 1994 Agreement. Under an arrangement negotiated in January 1996 (the January 1996 Agreement), Hydro-Quebec provided a cash payment to the Company of $3.0 million in 1996 and provided an additional cash payment of $1.1 million in 1997. In return, the Company has agreed, under certain circumstances, to shift up to 40 megawatts of the Schedule C3 deliveries from the NEPOOL/Hydro-Quebec interconnection facilities to alternate transmission paths, using the freed-up transmission path for an incremental purchase. The Company will purchase an annual minimum quantity of energy for the Company's use or resale for the period of September 1996 through June 2001. The purchase price will vary based upon conditions in effect when the purchases are made, or on the resale conditions at the time. Should the Company not satisfy its obligation to purchase the quantity of energy in any calendar year, it must pay a cancellation fee or rollover its residual purchase obligation into the succeeding calendar year period. Although the level of benefits to the Company will depend on various factors, the Company estimates that the January 1996 Agreement will provide a minimum benefit of $1.8 million on a net present value basis. During 1997, the Company purchased or sold to others, 51.4 percent of the minimum purchase obligation for that year. The Company will not rollover the balance of purchase obligations into 1998, but instead will pay a cancellation fee. Under an agreement executed on December 5, 1997, Hydro-Quebec provided a cash payment of $8.0 million to the Company in 1997. In return for this payment, the Company is providing Hydro-Quebec with the choice of selecting one of two alternatives by April 1, 1998, described below: Alternative A: For the period commencing November 1, 1997 and effective through the remaining term of the 1987 Contract, which expires in 2015, Hydro-Quebec can exercise an option to purchase up to 105,000 MWh on an annual basis, at energy prices established in accordance with the 1987 Contract, for an amount of energy equivalent to the Company's firm capacity entitlements in the 1987 Contract. The cumulative amount of energy purchased over the remaining term of the 1987 Contract may not exceed 1,900,000 MWh. Hydro-Quebec may not exercise its annual rights to purchase power in the amounts specified under an arrangement made in November 1996 during those years in which Hydro-Quebec exercises its rights to curtail energy deliveries in accordance with the July 1994 Agreement. Alternative B: For the period commencing November 1, 1997 and effective through the remaining term of the 1987 Contract, Hydro-Quebec can exercise an option to purchase up to 52,500 MWh on an annual basis, at energy prices established in accordance with the 1987 Contract, for an amount of energy equivalent to the Company's firm capacity entitlements in the 1987 Contract. The cumulative amount of energy purchased over the remaining term of the 1987 Contract shall not exceed 950,000 MWh. Unlike Alternative A, Hydro-Quebec's option to curtail energy deliveries pursuant to the July 1994 Agreement can be exercised in addition to the purchase option under Alternative B. Finally, for the period commencing January 1, 1998 and effective though the remaining term of the 1987 Contract under Alternative B, Hydro-Quebec can exercise an option on an annual basis to purchase up to 600,000 MWh at the 1987 Contract energy price. Hydro-Quebec can purchase no more than 200,000 MWh in any given year. Under modifications agreed to by Hydro-Quebec and the Company, Hydro-Quebec has until April 1, 1998 to elect either Alternative A or B. Consistent with an accounting order from the VPSB issued on December 31, 1996, the $8.0 million payment was recognized in income in 1997. However, it was necessary to change the accounting treatment subsequently based on an order issued by the VPSB in March 1998, resulting in the amortization of the $8 million over the life of the contract. The Company intends to appeal or request reconsideration of this decision. (See Note I of the Notes to Consolidated Financial Statements.) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Green Mountain Power Corporation: We have audited the accompanying consolidated balance sheets and capitalization data of Green Mountain Power Corporation (a Vermont corporation) as of December 31, 1997 and 1996, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note I.6, on March 2, 1998, the Company received a rate order from the Vermont Public Service Board (the VPSB) allowing for a $5.6 million increase in annual revenue in response to the Company's request for a $22 million increase in annual revenue. The Company is exploring all legal and regulatory remedies open to it to challenge the correctness of the VPSB's decision. The VPSB's ruling, if not changed, would have a significant adverse impact on the company's reported financial condition and 1998 results of operations and, depending on future proceedings to be conducted by the VPSB, could impact the Company's financial viability. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Green Mountain Power Corporation as of December 31, 1997 and 1996, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. /s/ ARTHUR ANDERSEN LLP Boston, Massachusetts February 2, 1998 (except with respect to the matter discussed in Note I.6, as to which the date is March 2, 1998) Schedule II GREEN MOUNTAIN POWER CORPORATION VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 1997, 1996 and 1995
Additions Balance at ------------------------------- Balance at Beginning of Charged to Charged to End of Description Period Cost & Expenses Other Accounts Deductions Period - ----------------------------------- ------------- -------------- -------------- ------------- ------------- Injuries and Damages 1997................................. $237,892 $427,546 $ -- $1,653 $663,785 1996................................. $103,301 $572,000 $ -- $437,409 $237,892 1995................................. $513,720 $38,000 $ -- $448,419 $103,301 Bad Debt Reserve (2) 1997................................. $498,024 $637,010 $173,899 (1) $815,528 $493,405 1996................................. $417,684 $677,272 $72,344 (1) $669,276 $498,024 1995................................. $402,923 $371,564 $48,696 (1) $405,499 $417,684 (1) Represents collection of accounts previously written off. (2) Includes non-utility bad debt reserve.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEMS 10, 11, 12 & 13 Certain information regarding executive officers called for by Item 10, "Directors and Executive Officers of the Registrant," is furnished under the caption, "Executive Officers" in Item 1 of Part I of this Report. The other information called for by Item 10, as well as that called for by Items 11, 12, and 13, "Executive Compensation," "Security Ownership of Certain Beneficial Owners and Management" and "Certain Relationships and Related Transactions," will be set forth under the captions "Election of Directors," "Board Compensation, Other Relationship, Meetings and Committees," "Section 16(a) Beneficial Ownership Reporting Compliance," "Executive Compensation," "Compensation Committee Report on Executive Compensation," "Performance Graphs," "Pension Plan Information" and "Securities Ownership of Certain Beneficial Owners and Management" in the Company's definitive proxy statement relating to its annual meeting of stockholders to be held on May 15, 1997. Such information is incorporated herein by reference. Such proxy statement pertains to the election of directors and other matters. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A in April 1997. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K A report on Form 8-K was filed on March 12, 1998 setting forth the financial and accounting implications for the Company resulting from the Vermont Public Service Board's Order in the Company's rate case. Filed Herewith On Page Item 14(a)(1). The financial statements and financial 42 statement schedules of the Company are listed on the Index to financial statements set forth in Item 8 hereof.
ITEM 14 (a) (3). EXHIBITS Incorporated by Reference from Exhibit SEC Docket or Number Exhibit Page Filed Herewith - ------- ----------------------------------------------- ------- ------------------- 3-a Restated Articles of Association, as certified 3-a Form 10-K 1993 June 6, 1991. (1-8291) 3-a-1 Amendment to 3-a above, dated as of May 20, 1993. 3-a-1 Form 10-K 1993 (1-8291) 3-a-2 Amendment to 3-a above, dated as of October 11, 1996. 3-a-2 Form 10-Q Sept. 1996 (1-8291) 3-b By-laws of the Company, as amended 3-b Form 10-K 1996 February 10, 1997. (1-8291) 4-b-1 Indenture of First Mortgage and Deed of Trust 4-b 2-27300 dated as of February 1, 1955. 4-b-2 First Supplemental Indenture dated as of 4-b-2 2-75293 April 1, 1961. 4-b-3 Second Supplemental Indenture dated as of 4-b-3 2-75293 January 1, 1966. 4-b-4 Third Supplemental Indenture dated as of 4-b-4 2-75293 July 1, 1968. 4-b-5 Fourth Supplemental Indenture dated as of 4-b-5 2-75293 October 1, 1969. 4-b-6 Fifth Supplemental Indenture dated as of 4-b-6 2-75293 December 1, 1973. 4-b-7 Seventh Supplemental Indenture dated as 4-a-7 2-99643 August 1, 1976. 4-b-8 Eighth Supplemental Indenture dated as of 4-a-8 2-99643 December 1, 1979. 4-b-9 Ninth Supplemental Indenture dated as of 4-b-9 2-99643 July 15, 1985. 4-b-10 Tenth Supplemental Indenture dated as of 4-b-10 Form 10-K 1989 June 15, 1989. (1-8291) 4-b-11 Eleventh Supplemental Indenture dated as of 4-b-11 Form 10-Q Sept September 1, 1990. 1990 (1-8291) 4-b-12 Twelfth Supplemental Indentrue dated as of 4-b-12 Form 10-K 1991 March 1, 1992. (1-8291) 4-b-13 Thirteenth Supplemental Indenture dated as of 4-b-13 Form 10-K 1991 March 1, 1992. (1-8291) 4-b-14 Fourteenth Supplemental Indenture dated as of 4-b-14 Form 10-K 1993 November 1, 1993. (1-8291) 4-b-15 Fifteenth Supplemental Indenture dated as of 4-b-15 Form 10-K 1993 November 1, 1993. (1-8291) 4-b-16 Sixteenth Supplemental Indenture dated as of 4-b-16 Form 10-K 1995 December 1, 1995. (1-8291) 4-b-17 Revised form of Indenture as filed as an Exhibit 4-b-17 Form 10-Q Sept. 1995 to Registration Statement No. 33-59383. (1-8291) *4-b-18 Credit Agreement by and among Green Mountain Power 4-b-18 The Bank of Nova Scotia, State Street Bank and Trust Company, Fleet National Bank, and Fleet National Bank, as Agent 10-a Form of Insurance Policy issued by Pacific 10-a 33-8146 Insurance Company, with respect to indemnification of Directors and Officers. 10-b-1 Firm Power Contract dated September 16, 1958, 13-b 2-27300 between the Company and the State of Vermont and supplements thereto dated September 19, 1958; November 15, 1958; October 1, 1960 and February 1, 1964. 10-b-2 Power Contract, dated February 1, 1968, between 13-d 2-34346 the Company and Vermont Yankee Nuclear Power Corporation. 10-b-3 Amendment, dated June 1, 1972, to Power Contract 13-f-1 2-49697 between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-3 Amendment, dated April 15, 1983, to Power 10-b-3(a) 33-8164 (a) Contract between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-3 Additional Power Contract, dated 10-b-3(b) 33-8164 (b) February 1, 1984,between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-4 Capital Funds Agreement, dated February 1, 13-e 2-34346 1968, between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-5 Amendment, dated March 12, 1968, to Capital 13-f 2-34346 Funds Agreement between the Company and Vermont Yankee Nuclear Power Corporation. 10-b-6 Guarantee Agreement, dated November 5, 1981, 10-b-6 2-75293 of the Company for its proportionate share of the obligations of Vermont Yankee Nuclear Power Corporation under a $40 million loan arrangement. 10-b-7 Three-Party Power Agreement among the Company, 13-i 2-49697 VELCO and Central Vermont Public Service Corporation dated November 21, 1969. 10-b-8 Amendment to Exhibit 10-b-7, dated June 1, 1981. 10-b-8 2-75293 10-b-9 Three-Party Transmission Agreement among the 13-j 2-49697 Company, VELCO and Central Vermont Public Service Corporation, dated November 21, 1969. 10-b-10 Amendment to Exhibit 10-b-9, dated June 1, 1981. 10-b-10 2-75293 10-b-12 Unit Purchase Contract dated February 10, 1968, 13-h 2-34346 between the Company and Vermont Electric Power Company, Inc., for purchase of "Merrimack" power from Public Service Company of New Hampshire. 10-b-14 Agreement with Central Maine Power Company et 5.16 2-52900 al, to enter into joint ownership of Wyman plant, dated November 1, 1974. 10-b-15 New England Power Pool Agreement as amended to 4.8 2-55385 November 1, 1975. 10-b-16 Bulk Power Transmission Contract between the 13-v 2-49697 Company and VELCO dated June 1, 1968. 10-b-17 Amendment to Exhibit 10-b-16, dated June 1, 1970. 13-v-i 2-49697 10-b-20 Power Sales Agreement, dated August 2, 1976, as 10-b-20 33-8164 amended October 1, 1977, and related Transmission Agreement, with the Massachusetts Municipal Wholesale Electric Company. 10-b-21 Agreement dated October 1, 1977, for Joint 10-b-21 33-8164 Ownership, Construction and Operation of the MMWEC Phase I Intermediate Units, dated October 1, 1977. 10-b-28 Contract dated February 1, 1980, providing for 10-b-28 33-8164 the sale of firm power and energy by the Power Authority of the State of New York to the Vermont Public Service Board. 10-b-30 Bulk Power Purchase Contract dated April 7, 10-b-32 2-75293 1976, between VELCO and the Company. 10-b-33 Agreement amending New England Power Pool 10-b-33 33-8164 Agreement dated as of December 1, 1981, providing for use of transmission inter- connection between New England and Hydro-Quebec. 10-b-34 Phase I Transmission Line Support Agreement 10-b-34 33-8164 dated as of December 1, 1981, and Amendment No. 1 dated as of June 1, 1982, between VETCO and participating New England utilities for construction, use and support of Vermont facilities of transmission interconnection between New England and Hydro-Quebec. 10-b-35 Phase I Terminal Facility Support Agreement 10-b-35 33-8164 dated as of December 1, 1981, and Amendment No. 1 dated as of June 1, 1982, between New England Electric Transmission Corporation and participating New England utilities for construction, use and support of New Hampshire facilities of transmission interconnection between New England and Hydro-Quebec. 10-b-36 Agreement with respect to use of Quebec 10-b-36 33-8164 Interconnection dated as of December 1, 1981, among participating New England utilities for use of transmission interconnection between New England and Hydro-Quebec. 10-b-39 Vermont Participation Agreement for Quebec 10-b-39 33-8164 Interconnection dated as of July 15, 1982, between VELCO and participating Vermont utilities for allocation of VELCO's rights and obligations as a participating New England utility in the transmission inter- connection between New England and Hydro-Quebec. 10-b-40 Vermont Electric Transmission Company, Inc. 10-b-40 33-8164 Capital Funds Agreement dated as of July 15, 1982, between VETCO and VELCO for VELCO to provide capital to VETCO for construction of the Vermont facilities of the transmission inter-connection between New England and Hydro-Quebec. 10-b-41 VETCO Capital Funds Support Agreement dated as 10-b-41 33-8164 of July 15, 1982, between VELCO and partici- pating Vermont utilities for allocation of VELCO's obligation to VETCO under the Capital Funds Agreement. 10-b-42 Energy Banking Agreement dated March 21, 1983, 10-b-42 33-8164 among Hydro-Quebec, VELCO, NEET and parti- cipating New England utilities acting by and through the NEPOOL Management Committee for terms of energy banking between participating New England utilities and Hydro-Quebec. 10-b-43 Interconnection Agreement dated March 21, 1983, 10-b-43 33-8164 between Hydro-Quebec and participating New England utilities acting by and through the NEPOOL Management Committee for terms and conditions of energy transmission between New England and Hydro-Quebec. 10-b-44 Energy Contract dated March 21, 1983, between 10-b-44 33-8164 Hydro-Quebec and participating New England utilities acting by and through the NEPOOL Management Committee for purchase of surplus energy from Hydro-Quebec. 10-b-45 Firm-Power Agreement dated as of October 5, 1982, 10-b-45 33-8164 between Ontario Hydro and Vermont Department of Public Service. 10-b-46 Sales Agreement, dated January 20, 1983, between 10-b-46 33-8164 Central Maine Power Company and the Company for excess power. 10-b-48 Sales Agreement, dated February 1, 1983, 10-b-48 33-8164 between Niagara Mohawk and Vermont Electric Power Company for purchase of energy. 10-b-50 Agreement for Joint Ownership, Construction and 10-b-50 33-8164 Operation of the Highgate Transmission Interconnection, dated August 1, 1984, between certain electric distribution companies, including the Company. 10-b-51 Highgate Operating and Management Agreement, 10-b-51 33-8164 dated as of August 1, 1984, among VELCO and Vermont electric-utility companies, including the Company. 10-b-52 Allocation Contract for Hydro-Quebec Firm Power 10-b-52 33-8164 dated July 25, 1984, between the State of Vermont and various Vermont electric utilities, including the Company. 10-b-53 Highgate Transmission Agreement dated as of 10-b-53 33-8164 August 1, 1984, between the Owners of the Project and various Vermont electric distribution companies. 10-b-54 Lease and Sublease Agreement dated June 1, 1984, 10-b-54 33-8164 between Burlington Associates and the Company. 10-b-55 Ground Lease Agreement dated June 1, 1984, 10-b-55 33-8164 between GMP Real Estate Corporation and Burlington Associates. 10-b-56 Assignment of Lease and Agreement, dated June 1, 10-b-56 33-8164 1984, from Burlington Associates to Teachers Insurance and Annuity Association of America. 10-b-57 Mortgage dated June 1, 1984, from GMP Real Estate 10-b-57 33-8164 Corporation, Mortgagor, to Teachers Insurance and Annuity Association of America, Mortgagee. 10-b-58 Lease and Operating Agreement dated June 28,1985, 10-b-58 33-8164 between the State of Vermont and the Company. 10-b-59 Service Contract dated June 28, 1985, between the 10-b-59 33-8164 State of Vermont and the Company. 10-b-61 Agreements entered in connection with Phase II 10-b-61 33-8164 of the NEPOOL/Hydro-Quebec + 450 KV HVDC Transmission Interconnection. 10-b-62 Agreement between UNITIL Power Corp. and the 10-b-62 33-8164 Company to sell 23 MW capacity and energy from Stony Brook Intermediate Combined Cycle Unit. 10-b-63 Sales Agreement dated as of June 20, 1986, 10-b-63 33-8164 between the Company and UNITIL Power Corp. for sale of system power. 10-b-64 Sales Agreement dated as of June 20, 1986, 10-b-64 33-8164 between the Company and Fitchburg Gas and Electric Light Company for sale of 10 MW capacity and energy from the Vermont Yankee plant. 10-b-65 Sales Agreement dated September 18, 1985, 10-b-65 Form 10-K 1991 between the Company and Fitchburg Gas and (1-8291) Electric Light Company for the sale of system power. 10-b-66 Sales Agreement dated January 1, 1987, between 10-b-66 Form 10-K 1991 the Company and Bozrah Light and Power (1-8291) Company for sale of power. 10-b-67 Sales Agreement dated August 31, 1987, amending 10-b-67 Form 10-K 1992 the agreement dated June 20, 1986, between (1-8291) the Company and UNITIL Power Corp. for sale of system power. 10-b-68 Firm Power and Energy Contract dated December 4, 10-b-68 Form 10-K 1992 1987, between Hydro-Quebec and participating (1-8291) Vermont utilities, including the Company, for the purchase of firm power for up to thirty years. 10-b-69 Firm Power Agreement dated as of October 26, 1987, 10-b-69 Form 10-K 1992 between Ontario Hydro and Vermont Department of (1-8291) Public Service. 10-b-70 Firm Power and Energy Contract dated as of 10-b-70 Form 10-K 1992 February 23, 1987, between the Vermont Joint (1-8291) Owners of the Highgate facilities and Hydro- Quebec for up to 50 MW of capacity. 10-b-70 Amendment to 10-b-70. 10-b-70(a) Form 10-K 1992 (a) (1-8291) 10-b-71 Interconnection Agreement dated as of 10-b-71 Form 10-K 1992 February 23, 1987, between the Vermont Joint (1-8291) Owners of the Highgate facilities and Hydro-Quebec. 10-b-72 Participation Agreement dated as of April 1, 1988, 10-b-72 Form 10-Q between Hydro-Quebec and participating Vermont June 1988 utilities, including the Company, implementing (1-8291) the purchase of firm power for up to 30 years under the Firm Power and Energy Contract dated December 4, 1987 (previously filed with the Company's Annual Report on Form 10-K for 1987, Exhibit Number 10-b-68). 10-b-72 Restatement of the Participation Agreement filed 10-b-72(a) Form 10-K 1988 (a) as Exhibit 10-b-72 on Form 10-Q for June 1988. (1-8291) 10-b-73 Agreement dated as of May 1, 1988, between 10-b-73 Form 10-Q Rochester Gas and Electric Corporation and the Sept. 1988 Company,implementing the Company's purchase of up (1-8291) to 50 MW of electric capacity and associated energy. 10-b-74 Agreement dated as of November 1, 1988, between 10-b-74 Form 10-Q for the Company and Fitchburg Gas and Electric Light Sept. 1988 Company,for sale of electric capacity and (1-8291) associated energy. 10-b-74 Amendment to Exhibit 10-b-74. 10-b-74(a) Form 10-Q (a) Sept 1989 (1-8291) 10-b-75 Allocation Agreement dated as of March 25, 1988, 10-b-75 Form 10-Q between Ontario Hydro and the State of Vermont, Sept. 1988 for firm power and associated energy from (1-8291) Ontario Hydro. 10-b-77 Firm Power and Energy Contract dated December 29, 10-b-77 Form 10-K 1988 1988, between Hydro-Quebec and participating (1-8291) Vermont utilities, including the Company, for the purchase of up to 54 MW of firm power and energy. 10-b-78 Transmission Agreement dated December 23, 1988, 10-b-78 Form 10-K 1988 between the Company and Niagara Mohawk Power (1-8291) Corporation (Niagara Mohawk), for Niagara Mohawk to provide electric transmission to the Company from RochesterGas and Electric and Central Hudson Gas and Electric. 10-b-79 Lease Agreement dated November 1, 1988, between 10-b-79 Form 10-K 1988 the Company and International Business Machines (1-8291) Corporation (IBM) for the lease to IBM of the gas turbines and associated facilities located on land adjacent to IBM's Essex Junction, Vermont, plant. 10-b-80 Sales Agreement dated January 1, 1989, between 10-b-80 Form 10-K 1988 the Company and Public Service of New Hampshire (1-8291) (PSNH)for PSNH to purchase electric capacity from the Company. 10-b-81 Sales Agreement dated May 24, 1989, between 10-b-81 Form 10-Q the Town of Hardwick, Hardwick Electric Department June 1989 and the Company for the Company to purchase (1-8291) all of the output of Hardwick's generation and transmission sources and to provide Hardwick with all-requirements energy and capacity except for that provided by the Vermont Department of Public Service or Federal Preference Power. 10-b-82 Sales Agreement dated July 14, 1989, between 10-b-82 Form 10-Q Northfield Electric Department and the Company June 1989 for the Company to purchase all of the output (1-8291) of Northfield's generation and transmission sources and to provide Northfield with all- requirements energy and capacity except for that provided by the Vermont Department of Public Service or Federal Preference Power. 10-b-83 Power Purchase and Operating Agreement dated as 10-b-83 Form 10-Q of April 20, 1990, between CoGen Lime Rock, June 1990 Inc., and the Company for the production of (1-8291) energy to meet customer needs. 10-b-84 Capacity, Transmission and Energy Service 10-b-84 Form 10-K 1992 Agreement dated December 23, 1992, between (1-8291) the Company and Connecticut Light and Power Company (CL&P) for CL&P to supply power to Bozrah Light and Power Company. Management contracts or compensatory plans or arrangements required to be filed as exhibits to this form 10-K pursuant to Item 14(c). 10-c Contract dated as of October 15, 1983, between 10-c 33-8164 the Company and Thomas V. O'Connor, Jr. 10-c-1 Amendment dated as of March 31, 1988, to an 10-c-1 Form 10-Q agreement between the Company and March 1988 Thomas V. O'Connor, Jr (1-8291) 10-d-1b Green Mountain Power Corporation Second Amended 10-d-1b Form 10-K 1993 and Restated Deferred Compensation Plan for (1-8291) Directors. 10-d-1c Green Mountain Power Corporation Second Amended 10-d-1c Form 10-K 1993 and Restated Deferred Compensation Plan for (1-8291) Officers. 10-d-1d Amendment No. 93-1 to the Amended and Restated 10-d-1d Form 10-K 1993 Deferred Compensation Plan for Officers. (1-8291) 10-d-1e Amendment No. 94-1 to the Amended and Restated 10-d-1e Form 10-Q Deferred Compensation Plan for Officers. June 1994 (1-8291) 10-d-2 Green Mountain Power Corporation Medical Expense 10-d-2 Form 10-K 1991 Reimbursement Plan. (1-8291) 10-d-4 Green Mountain Power Corporation Officer 10-d-4 Form 10-K 1991 Insurance Plan. (1-8291) 10-d-4a Green Mountain Power Corporation Officers' 10-d-4a Form 10-K 1990 Insurance Plan as amended. (1-8291) 10-d-5a Severance Agreements with D. G. Hyde, E. M. Norse, 10-d-5a Form 10-K 1990 C. L. Dutton, S. C. Terry and T.C. Boucher. (1-8291) 10-d-6 Severance Agreements with W. S. Oakes, 10-d-6 Form 10-K 1988 and J. H. Winer. (1-8291) 10-d-6a Restatement of 10-d-6 above. 10-d-6a Form 10-K 1990 (1-8291) 10-d-7 Severance Agreement with K. K. O'Neill. 10-d-7 Form 10-K 1990 (1-8291) 10-d-8 Green Mountain Power Corporation Officers' 10-d-8 Form 10-K 1990 Supplemental Retirement Plan. (1-8291) 10-d-9 Severance Agreement with C. T. Myotte. 10-d-9 Form 10-Q June 1991 (1-8291) 10-d-10 Severance Agreement with J. J. Lampron. 10-d-10 Form 10-K 1991 (1-8291) 10-d-13 Severance Agreement with M. H. Lipson. 10-d-13 Form 10-K 1994 (1-8291) 10-d-14 Severance Agreement with D. G. Whitmore. 10-d-14 Form 10-K 1994 (1-8291) 10-d-15a Green Mountain Power Corporation Compensation Program 10-d-15a Form 10-Q for Officers and Key Management Personnel as amended Sept. 1995 August 8, 1995 (1-8291) *10-d-15b Green Mountain Power Corporation Compensation Program 10-d-15b for Officers and Key Management Personnel as amended August 4, 1997 10-d-16 Severance Agreement with R. C. Young 10-d-16 Form 10-Q March 1995 (1-8291) 10-d-17 Severance Agreement with P. H. Zamore 10-d-17 Form 10-Q March 1995 (1-8291) 10-d-18 Severance Agreement with R. B. Hieber 10-d-18 Form 10-K 1996 (1-8291) 10-d-19 Severance Agreement with R. J. Griffin 10-d-19 Form 10-K 1996 (1-8291) 10-d-20 Severance Agreement with K. W. Hartley 10-d-20 Form 10-K 1996 (1-8291) 21 Subsidiaries of the Registrant 21 Form 10-K 1996 (1-8291) *23-a-1 Consent of Arthur Andersen LLP *24 Power of Attorney *27 Financial Data Schedule ____________________ * Filed herewith
ITEM 14(b) A report on Form 8-K was filed on March 12, 1998 setting forth the financial and accounting implications for the Company resulting from the Vermont Public Service Board's Order in the Company's rate case. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. GREEN MOUNTAIN POWER CORPORATION By: /s/ Christopher L. Dutton _________________________ Christopher L. Dutton, President and Chief Executive Officer Date: March 26, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. SIGNATURE TITLE DATE --------- ----- ---- /s/ Christopher L. Dutton President and Director March 26, 1998 Christopher L. Dutton (Principal Executive Officer) /s/ Edwin M. Norse Vice President, Treasurer and March 26, 1998 Edwin M. Norse Chief Financial Officer (Principal Financial Officer) /s/ Robert J. Griffin Controller March 26, 1998 Robert J. Griffin (Principal Accounting Officer) *Thomas P. Salmon Chairman of the Board *Nordahl L. Brue ) *William H. Bruett ) *Merrill O. Burns ) *Lorraine E. Chickering ) *John V. Cleary ) Directors *Richard I. Fricke ) *Euclid A. Irving ) *Martin L. Johnson ) *Ruth W. Page ) *By: /s/ Christopher L. Dutton_ March 26, 1998 Christopher L. Dutton (Attorney - in - Fact) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Green Mountain Power Corporation: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements of Green Mountain Power Corporation included in this Form 10-K and have issued our report thereon dated February 2, 1998. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index on page 42 of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements, and in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. Boston, Massachusetts February 2, 1998 /s/ Arthur Andersen LLP EX-1 2 Exhibit 4-b-18 Execution Copy CREDIT AGREEMENT by and among GREEN MOUNTAIN POWER CORPORATION, THE BANK OF NOVA SCOTIA, STATE STREET BANK AND TRUST COMPANY, FLEET NATIONAL BANK, and FLEET NATIONAL BANK, AS AGENT $60,000,000 Dated as of August 12, 1997 TABLE OF CONTENTS Paragraph Heading Page 1. DEFINITIONS..............................................1 1.1 Defined Terms 1.2 Other Definitional provisions............................1 PRELIMINARY MATTERS..................................... 2. AMOUNT AND TERMS OF LOANS...............................10 2.1 Tranche A Loans ........................................10 2.2 Tranche B Loans ........................................10 2.3 Procedure for Borrowings................................11 2.4 Notes...................................................14 2.5 Voluntary Reductions of the Aggregate Commitments; Termination................................15 (a) Voluntary Reductions...............................15 (b) General............................................15 2.6 Prepayments and Payment of Loans........................16 (a) Voluntary Prepayments..............................16 (b) Mandatory Repayments...............................16 (c) Prepayments of Bid Rate Loans......................16 2.7 Conversion Options......................................16 (a) Conversion of Pro Rata Loans.......................16 (b) Continuation of Pro Rata Loans.....................17 (c) Restrictions on Conversion.........................17 and Continuation of Bid Rate Loans................17 2.8 Interest Rate and Payment Dates for Loans...............17 (a) Interest Rates for All Loans Prior to Maturity.....17 (b) Overdue Amounts....................................17 (c) General............................................17 2.9 Substituted Interest Rate ..............................18 2.10 Illegality..............................................18 2.11 Increased Costs ........................................19 2.12 Indemnity...............................................20 2.13 Use of Proceeds.........................................21 2.14 Capital Adequacy........................................21 2.15 Extension of Termination Date ..........................21 2.16 Notice of Costs; Substitution of Banks .................22 2.17 Regulatory Approvals....................................23 2.18 Increase of Commitments.................................23 3. FEES: PAYMENTS .........................................23 3.1 Commitment and Facility Fees............................23 3.2 Fees of the Agent ......................................24 3.3 Computation of Interest and Fees .......................24 3.4 Pro Rata Treatment and Application of Principal Payments................................................24 4. REPRESENTATIONS AND WARRANTIES..........................24 4.1 Subsidiary .............................................24 4.2 Corporate Existence and Power...........................25 4.3 Corporate Authority.....................................25 4.4 Binding Agreement.......................................25 4.5 Litigation..............................................25 4.6 No Conflicting Agreements...............................25 4.7 Taxes ..................................................26 4.8 Financial Statements....................................26 4.9 Compliance with Applicable Laws.........................26 4.10 Governmental Regulations................................27 4.11 Property................................................27 4.12 Federal Reserve Regulations.............................27 4.13 No Misrepresentation....................................27 4.14 Pension Plans...........................................27 4.15 Public Utility Holding Company Act......................27 4.16 Approvals...............................................27 4.17 Regulatory Investigations...............................28 4.18 No Adverse Change or Event..............................28 5. CONDITIONS OF BORROWING - FIRST BORROWING ..............28 5.1 Evidence of Corporate Action............................28 5.2 Notes ..................................................28 5.3 Approval of Special Counsel.............................28 5.4 Opinion of Counsel to the Company ......................28 5.5 Fees ...................................................28 5.6 VPSB Approval ..........................................29 6. CONDITIONS OF BORROWING-ALL BORROWINGS .................29 6.1 Compliance..............................................29 6.2 Loan Closings ..........................................29 6.3 Approval of Counsel ....................................29 6.4 Borrowing Request.......................................29 6.5 Other Documents ........................................29 7. AFFIRMATIVE COVENANTS ..................................29 7.1 Corporate Existence ....................................30 7.2 Taxes ..................................................30 7.3 Insurance...............................................30 7.4 Payment of Indebtedness and Performance of Obligations..30 7.5 Observance of Legal Requirements; ERISA ................30 7.6 Financial Statements and Other Information..............30 7.7 Inspection..............................................32 8. NEGATIVE COVENANTS .....................................32 8.1 Funded Debt.............................................32 8.2 Liens ..................................................32 8.3 Mergers and Consolidations .............................33 8.4 Sale of Property........................................33 8.5 Dividends; Distributions................................33 8.6 Guaranties..............................................33 8.7 Amendment of Charter or By-Laws.........................33 8.8 Funded Debt to Capitalization Test......................34 9. EVENTS OF DEFAULT.......................................34 10. THE AGENT ..............................................36 10.1 Appointment.............................................36 10.2 Delegation of Duties, Etc...............................36 10.3 Indemnification.........................................36 10.4 Exculpatory Provisions..................................37 10.5 Agent in its Individual Capacity........................37 10.6 Knowledge of Default....................................37 10.7 Resignation of Agent ...................................38 10.8 Requests to the Agent ..................................38 11. NOTICES ................................................38 11.1 Manner of Delivery .....................................38 11.2 Distribution of Copies..................................40 11.3 Notices by the Agent or a Bank..........................40 12. RIGHT OF SET-OFF ......................................40 13. AMENDMENTS, WAIVERS, AND CONSENTS.......................41 14. OTHER PROVISIONS........................................41 14.1 No Waiver of Rights by the Banks .......................41 14.2 Headings, Plurals ......................................42 14.3 Counterparts............................................42 14.4 Severability............................................42 14.5 Integration.............................................42 14.6 Sales and Participations in Loans and Notes; Successors and Assigns; Survival of Representations and Warranties.............42 14.7 Applicable Law..........................................43 14.8 Interest................................................44 14.9 Accounting Terms and Principles.........................44 14.10 Waiver of Trial by Jury.................................44 14.11 Consent to Jurisdiction.................................44 14.12 Service of Process .....................................44 14.13 No Limitation on Service or Suit .......................45 14.14 Incorporated Provisions ................................ 15. OTHER OBLIGATIONS OF THE COMPANY .......................45 15.1 Taxes and Fees .........................................45 15.2 Expenses................................................45 16. EFFECTIVE DATE..........................................45 EXHIBITS EXHIBIT A Commitments EXHIBIT B Applicable Margins/Percentages for Facility Fee EXHIBIT C Form of Borrowing Request EXHIBIT D Form of Bid Borrowing Notice EXHIBIT E Form of Bid EXHIBIT F Form of Notice to Agent EXHIBIT G-1 Form of Notes EXHIBIT G-2 Form of Bid Rate Note EXHIBIT H Form of Commitment Extension Request EXHIBIT I List of Subsidiaries EXHIBIT J Form of Opinion of Special Counsel EXHIBIT K Form of Opinion of Counsel to the Company CREDIT AGREEMENT CREDIT AGREEMENT, dated as of August 12, 1997, among GREEN MOUNTAIN POWER CORPORATION, a Vermont corporation (the "Company"), the Signatory Banks hereto (each, a "Bank" and, collectively, the "Banks"), and FLEET NATIONAL BANK, as agent hereunder (in such capacity, the "Agent"). 1. DEFINITIONS. 1.1 Defined Terms. As used in this Agreement, terms defined in the paragraph above have the meanings therein indicated, and the following terms have the following meanings: "Accountants": Arthur Andersen LLP, or such other firm of certified public accountants of recognized national standing selected by the Company. "Affected Loan": as defined in paragraph 2.9. "Affected Principal Amount": (i) in the event that the Company shall fail for any reason to borrow a Loan constituting a Eurodollar Rate Loan after it shall have delivered a Borrowing Request to the Agent, an amount equal to the principal amount of such Eurodollar Rate Loan; (ii) in the event that the right of the Company to have a Eurodollar Rate Loan outstanding hereunder shall be suspended or shall terminate for any reason prior to the last day of the Interest Period applicable thereto, an amount equal to the principal amount of such Eurodollar Rate Loan; and (iii) in the event that the Company shall prepay or repay all or any part of the principal amount of a Eurodollar Rate Loan prior to the last day of the Interest Period applicable thereto, an amount equal to the principal amount so prepaid or repaid. "Affiliate": a Person that directly or indirectly, or through one or more intermediaries, controls or is controlled by or is under common control with another Person. The term "control" means possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise. "Agent's Fees": as defined in paragraph 3.2. "Aggregate Commitments": the sum of the Commitments set forth in Exhibit A as the same may be reduced pursuant to paragraph 2.5 or increased pursuant to paragraph 2.18. "Aggregate Tranche A Commitments": the sum of the Tranche A Commitments set forth in Exhibit A, as the same may be reduced pursuant to paragraph 2.5 or increased pursuant to paragraph 2.18. "Aggregate Tranche B Commitments": the sum of the Tranche B Commitments set forth in Exhibit A, as the same may be reduced pursuant to paragraph 2.5 or increased pursuant to paragraph 2.18. "Agreement": this Credit Agreement, as same may be amended, supplemented or otherwise modified from time to time. "Alternate Base Rate": the higher of (a) the annual rate of interest publicly announced from time to time by the Agent at the Agent's head office as its "base rate" and (b) one-half of one percent (1/2%) above the Federal Funds Effective Rate. "Alternate Base Rate Loans": Loans (or any portion thereof) at such time as they (or such portions) are made or are being maintained at a rate of interest based upon the Alternate Base Rate. "Applicable Lending Office": as to any Bank, such Bank's Domestic Lending Office or Eurodollar Lending Office, as the case may be. "Applicable Margin": the additional rate per annum to be added to the interest rate at which each Loan is made determined by reference to Exhibit B hereto based upon the Debt Rating of the Company. "Authorized Signatory": the president, any vice president, the treasurer, the secretary, or any other duly authorized officer of the Company acceptable to Agent. "Bank" or "Banks": the signatory Banks to this Credit Agreement and any other bank or lender that becomes a signatory hereto pursuant to paragraph 2.18. "Bid Borrowing": any Borrowing of Bid Rate Loans having the same Interest Period from one or more of the Banks on a given date, consisting, collectively of all Bid Rate Loans made or to be made by the Banks on such date. "Bid Rate Loans": Loans (or any portion thereof) at such time as they (or such portions) are made or are being maintained pursuant to paragraph 2.3(b). "Bid Rate Note": as defined in paragraph 2.4. "Borrowing": a Borrowing of additional principal amounts pursuant to paragraph 2.3 consisting of simultaneous Loans of the same Type made by each Bank. "Borrowing Request": as defined in paragraph 2.3. "Borrowing Date": any date specified in a Borrowing Request delivered pursuant to paragraphs 2.1 and 2.2 as a date on which the Company requests the Banks to make Loans hereunder. "Business Day": for all purposes other than as set forth in clause (ii) below, (i) any day other than a Saturday, Sunday or other day on which commercial banks located in New York City or Boston are authorized or required by law or other governmental actions to close and (ii) with respect to all notices and determinations in connection with, and payments of principal and interest on Eurodollar Loans, any day which is a Business Day described in clause (i) above and which is also a day on which dealings in foreign currency and exchange and Eurodollar funding between banks may be carried on in London, New York City and Boston. "Code": the Internal Revenue Code of 1986, as the same may be amended from time to time, or any successor thereto, and the rules and regulations issued hereunder, as from time to time in effect. "Commitment": in respect of any Bank, such Bank's undertaking to make Loans to the Company, subject to the terms and conditions hereof, in an aggregate outstanding principal amount equal to but not exceeding the amount set forth next to the name of such Bank on Exhibit A under the heading "Total Commitment", as the same may be reduced pursuant to paragraph 2.5 or increased pursuant to paragraph 2.18. "Commitment Extension Request": a request duly executed by an Authorized Signatory substantially in the form of Exhibit H. "Commitment Percentage": as to any Bank, the percentage set forth opposite the name of such Bank on Exhibit A under the heading "Commitment Percentage". "Commonly Controlled Entity": an entity, whether or not incorporated, which is under common control with the Company within the meaning of Section 414(b) or 414(c) of the Code. "Consolidated": the Company and its Subsidiaries taken as a whole. "Conversion Date": the date on which a Loan of one Type is converted to a Loan of another Type or continued as a Loan of the same Type. "Debt Rating": the public debt rating of the Company's senior secured indebtedness according to Standard & Poor's Corporation or Moody's Investor Service; in the event that neither Standard & Poor's Corporation or Moody's Investor Service have a public debt rating for the Company, the Company shall be deemed to have no Debt Rating. "Designated Documents": the Company's 1996 Form 10-K and the Company's quarterly report on Form 10-Q for the fiscal quarter ended March 31, 1997. "Dollars" and "$": dollars in lawful currency of the United States of America. "Domestic Lending Office": as to any Bank, initially the office of such Bank designated as such on the signature page hereof, and thereafter such other office in the United States as reported by such Bank to the Agent, that shall be making or maintaining Alternate Base Rate Loans or Bid Rate Loans. "Effective Date": as defined in paragraph 16. "Environmental Law": Any and all federal, state, local and foreign statutes, laws, regulations, ordinances, rules, judgments, orders, decrees, permits, concessions, grants, franchises, licenses, agreements or other governmental restrictions relating to the environment (but not including zoning and similar land use laws and regulations which have no Material Adverse Effect on the Company) or to emissions, discharges, releases or threatened releases of pollutants, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes into the environment, including, without limitation, ambient air, surface water, ground water or land, or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, chemicals or industrial, toxic or hazardous substances or wastes. "Environmental Notice": any summons, citation, directive, information request, notice of potential responsibility, notice of violation or deficiency, order, claim, complaint, investigation, proceeding, judgment, letter or other communication, written or oral, actual or threatened, from the United States Environmental Protection Agency or other federal, state or local agency or authority, or any other entity or individual, public or private, concerning any intentional or unintentional act or omission which involves management of hazardous substances or wastes on or off any property owned or leased by the Company or any Subsidiary or Affiliate of the Company; the imposition of any Lien on such property; and any alleged violation of or responsibility under Environmental Laws. "ERISA": the Employee Retirement Income Security Act of 1974, as amended from time to time, and the rules and regulations issued hereunder, as from time to time in effect. "Eurodollar Lending Office": as to any Bank, initially the office of such Bank designated as such on the signature page hereof, and thereafter such other office as reported by such Bank to the Agent, that shall be making or maintaining Eurodollar Rate Loans. "Eurodollar Rate": with respect to any Interest Period applicable to any Eurodollar Rate Loan, the rate per annum determined by dividing (i) the rate per annum (rounded to the next highest 1/100 of 1%) at which Dollar deposits are offered by major banks to major banks in immediately available funds in the London interbank eurodollar market as determined by the Agent at or about 11:00 a.m. (London time) for delivery on the day that is two (2) Business Days prior to the first day of such Interest Period, in an amount comparable to the amount of the Eurodollar Rate Loan of FNB to which such Interest Period shall apply and for a period equal to such Interest Period, by (ii) one minus the aggregate of the maximum rates (expressed as a decimal) of reserves (including, without limitation, basic, supplemental, marginal and emergency reserves) for "Eurocurrency liabilities" of member banks of the Federal Reserve System as prescribed under Regulation D of the Board of Governors of the Federal Reserve System. The Eurodollar Rate shall be adjusted automatically on and as of the effective date of any change in such reserve rate for Eurocurrency liabilities. Each determination by the Agent of the Eurodollar Rate shall be presumed to be correct in the absence of manifest error. All interest based on the Eurodollar Rate shall be calculated on the basis of a 360-day year for the actual number of days elapsed. "Eurodollar Rate Loans": Loans (or any portions thereof) at such time as they (or such portions) are made or being maintained at a rate of interest based upon the Eurodollar Rate. "Event of Default": any of the events specified in paragraph 9, provided that any requirement for the giving of notice, the lapse of time, or both, has been satisfied. "Federal Funds Effective Rate": the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System arranged by federal funds brokers on such day, as published for the prior day by the Federal Reserve Bank of Boston. "First Mortgage Bonds": the Company's First Mortgage Bonds as set forth in the Company's 1996 Form 10-K filed on March 29, 1997 with the Securities and Exchange Commission. "FNB": Fleet National Bank, a national banking association. "Facility Fee": as defined in paragraph 3.1. "Financial Statements": as defined in paragraph 4.8. "Funded Debt": all obligations of the Company evidenced by bonds, debentures, notes or other similar instruments (including, without limitation, preferred stock not issued and outstanding as of the date hereof that has maturities within the term of this Agreement) and all other evidences of indebtedness of the Company (including, without limitation, debt with initial maturities of less than one (1) year ("Short-Term Funded Debt"), and any other instrument or arrangement which would be treated as indebtedness under GAAP, including, without limitation, capitalized leases but excluding trade obligations and normal accruals, including accounts payable, in the ordinary course of business not yet due and payable, or with respect to which the Company is contesting in good faith the amount or validity thereof by appropriate proceedings and then only to the extent that the Company has set aside on its books adequate reserves therefor in accordance with GAAP and such contest does not have a Material Adverse Effect). "GAAP": generally accepted accounting principles from time to time followed by companies engaged in a business similar to that of the Company, except as otherwise required by any applicable rules, regulations or orders of the VPSB, or other public regulatory authority having jurisdiction over the accounts of the Company; provided that the Company may at any time contest or controvert in good faith the validity or applicability to the Company of any such rule, regulation or order; and provided, further, that the federal income tax liability of the Company may be computed as if the Company were filing separate returns notwithstanding the fact that it may file consolidated returns as part of an affiliated group. "Governmental Body": any nation or government, any state or other political subdivision thereof, any entity exercising executive, legislative, judicial, regulatory or administrative functions, of, or pertaining to, government, and any court or arbitrator. "Interest Payment Date": (a) as to any Alternate Base Rate Loan, the last day of each March, June, September and December commencing on the first such day to occur after such Loan is made or any Eurodollar Rate Loan is converted to an Alternate Base Rate Loan, and the date each Alternate Base Rate Loan is paid in full, (b) as to any Eurodollar Rate Loan in respect of which the Company has selected an Interest Period of one, two or three months, the last day of such Interest Period, and (c) as to any Eurodollar Rate Loan having an Interest Period of six months, the last day and, in addition, the numerically corresponding day (or, if there is no numerically corresponding day, the last day) in the calendar month that is three months after the first day, of such Interest Period and (d) as to any Bid Rate Loan, the last day of each applicable Interest Period. "Interest Period": (a) with respect to any Eurodollar Rate Loan comprising the same Borrowing: (i) initially, the period commencing on, as the case may be, the Borrowing Date or a Conversion Date with respect to such Eurodollar Rate Loan, and ending one, two, three or six months thereafter, as selected by the Company in its irrevocable Borrowing Request as provided in paragraph 2.3 or its irrevocable notice of conversion as provided in paragraph 2.7; and (ii) thereafter, each period commencing on, as the case may be, the Borrowing Date or a Conversion Date with respect to such Eurodollar Rate Loan and ending one, two, three or six months thereafter, as selected by the Company in its irrevocable notice of conversion as provided in paragraph 2.7; and (b) with respect to any Bid Rate Loan, a period commencing on the date of the making of such Loan and ending on the maturity date specified therefor in accordance with paragraph 2.3(b)(i)(D). (c) All of the foregoing provisions relating to Interest Periods set forth in paragraphs (a) and (b) above are subject to the following: (i) if any Interest Period pertaining to a Eurodollar Rate Loan or a Bid Rate Loan comprising the same Borrowing would otherwise end on a day which is not a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless the result of such extension would be to carry such Interest Period into another calendar month, in which event such Interest Period shall end on the immediately preceding Business Day; (ii) if, with respect to the conversion of any Loan, the Company shall fail to give due notice as provided in paragraph 2.7 for such Loan, such Loan shall be automatically converted to an Alternate Base Rate Loan upon the expiration of the Interest Period with respect thereto; (iii) any Interest Period pertaining to a Eurodollar Rate Loan or a Bid Rate Loan that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of a calendar month; (iv) the Company shall select Interest Periods relating to Eurodollar Rate Loans so as not to have more than twelve different Interest Periods relating to Eurodollar Rate Loans outstanding at any one time; and (v) the Company shall select Interest Periods pertaining to Eurodollar Rate Loans such that, on the date the mandatory repayment is required to be made under paragraph 2.6(b), the outstanding principal amount of all Alternate Base Rate Loans, Bid Rate Loans and Eurodollar Rate Loans with Interest Periods ending on the date of such payment shall equal the aggregate principal amount of the Loans required to be repaid on such date. "Lien: any mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or other), or preference, priority or other security agreement or security interest of any kind or nature whatsoever (including, without limitation, any conditional sale or other title retention agreement, any financing lease having substantially the same economic effect as any of the foregoing, and the filing of any financing statement under the Uniform Commercial Code or comparable law of any jurisdiction). "Loan Documents": collectively, this Agreement and the Notes and any document and instrument executed and/or delivered in connection herewith or therewith. "Loan": a Loan made pursuant to paragraph 2.1 or 2.2. "Majority Banks": at any time when no Loans are outstanding, Banks having at least 66 2/3% of the Aggregate Commitments; at any time when Loans are outstanding, Banks holding at least 66 2/3% of the outstanding Loans. "Material Adverse Change": a material adverse change in the business, assets, liabilities, condition (financial or otherwise), results of operations or business prospects of (a) the Company or (b) the Company and its Subsidiaries "taken as a whole" which would reasonably be expected to render the Company unable to perform its obligations under the Loan Documents. The term "Material Adverse Change" shall include, without limitation, any change in any law, regulation, treaty or directive or in the interpretation or application thereof by any Governmental Body, including without limitation, the VPSB, charged with the administration thereof or compliance by the Company with any request or directive from any Governmental Body, including without limitation, the VPSB, the result of which would have a Material Adverse Effect. "Material Adverse Effect": (a) with respect to any Person (including, without limitation, the Company), any materially adverse effect on such Person's business, assets, liabilities, condition (financial or otherwise), results of operations or business prospects, (b) with respect to a group of Persons "taken as a whole" (including, without limitation, the Company and its Subsidiaries), any materially adverse effect on such Persons' business, assets, liabilities, financial conditions, results of operations or business prospects taken as a whole on, where appropriate, a consolidated basis in accordance with GAAP and (c) with respect to any Loan Document, any adverse effect, WHETHER OR NOT MATERIAL, on the binding nature, validity or enforceability thereof as an obligation of the Company. "Multiemployer Plan": a Plan which is a multiemployer plan as defined in Section 4001 (a)(3) of ERISA. "Non-Consenting Bank": as defined in paragraph 2.15. "Notes": as defined in paragraph 2.4. "PBGC": the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA, or any Governmental Body succeeding to the functions thereof. "Person": an individual, partnership, corporation, limited liability company, limited liability partnership, business trust, joint stock company, trust, unincorporated association, joint venture, Governmental Body or any other entity of whatever nature. "Plan": any pension plan which is covered by Title IV of ERISA and in respect of which the Company or a Commonly Controlled Entity is an "employer" as defined in Section 3(5) of ERISA. "Pro Rata Loans": Loans (or any portion thereof) at such time as they (or such portions) are made or are being maintained pursuant to paragraph 2.3(a). "Property": all types of real, personal, tangible, intangible or mixed property. "Regulation D": Regulation D of the Board of Governors of the Federal Reserve System, as amended from time to time. "Replacement Bank": as defined in paragraph 2.15. "Reportable Event": any event described in Section 4043(b) of ERISA, other than an event with respect to which the 30-day notice requirement has been waived. "Special Counsel": Gadsby & Hannah LLP, or such other firm selected by the Agent. "Subsidiary": any corporation a majority of the voting shares of which are at the time owned by the Company or by other subsidiaries of the Company or by the Company and other subsidiaries of the Company. "Taxes": any present or future income, stamp or other taxes, levies, imposts, duties, fees, assessments, deductions, withholdings, or other like charges, now or hereafter imposed, levied, collected, withheld, or assessed by any Governmental Body. "Termination Date": the Tranche A Termination Date and/or the Tranche B Termination Date, as applicable. "Total Capitalization": the sum of (a) all outstanding capital stock of the Company plus (b) Funded Debt. "Tranche A Commitment": in respect of any Bank, such Bank's undertaking to make Tranche A Loans to the Company, subject to the terms and conditions hereof, in an aggregate outstanding principal amount equal to but not exceeding the amount set forth next to the name of such Bank on Exhibit A under the heading "Tranche A Commitment", as the same may be reduced pursuant to paragraph 2.5 or increased pursuant to paragraph 2.18. "Tranche A Loans": Loans made pursuant to paragraph 2.1. "Tranche A Note": a promissory note made by the Company in favor of the Banks evidencing Loans made pursuant to paragraph 2.1, substantially in the form of Exhibit G-1 or G-2 hereto. "Tranche A Termination Date": the date which is three hundred sixty four (364) days after the Effective Date or any date subsequent thereto resulting from an extension of the Tranche A Termination Date pursuant to paragraph 2.15. "Tranche B Commitment": in respect of any Bank, such Bank's undertaking to make Tranche B Loans to the Company, subject to the terms and conditions hereof, in an aggregate outstanding principal amount equal to but not exceeding the amount set forth next to the name of such Bank on Exhibit A under the heading "Tranche B Commitment", as the same may be reduced pursuant to paragraph 2.5 or increased pursuant to paragraph 2.18. "Tranche B Loans": Loans made pursuant to paragraph 2.2. "Tranche B Note": a promissory note made by the Company in favor of the Banks evidencing Loans made pursuant to paragraph 2.2, substantially in the form of Exhibit G-1 or G-2 hereto. "Tranche B Termination Date": the date which is the third (3rd) anniversary of the Effective Date or any date subsequent thereto resulting from an extension of the Tranche B Termination Date pursuant to paragraph 2.15. "Type": Loans made hereunder as Alternate Base Rate Loans, Eurodollar Rate Loans or Bid Rate Loans, as the case may be. "VPSB": the Vermont Public Service Board. 1.2 Other Definitional Provisions. (a) All terms defined in this Agreement shall have the meanings given such terms herein when used in any certificate, opinion or other document made or delivered pursuant hereto or thereto, unless otherwise defined therein. All terms defined in this Agreement and not defined in paragraph 1.1 shall have the respective meanings given them in the text of this Agreement. (b) As used herein and in any certificate or other document made or delivered pursuant hereto or thereto, accounting terms relating to the Company not defined in paragraph 1.1, and accounting terms partly defined in paragraph 1.1, to the extent not defined, shall have the respective meanings given to them under GAAP. (c) The words "hereof", "herein", "hereto" and "hereunder" and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and paragraph, schedule and exhibit references contained herein shall refer to paragraphs hereof or schedules or exhibits hereto unless otherwise expressly provided herein. The word "or" shall not be exclusive. 2. AMOUNT AND TERMS OF LOANS. 2.1 Tranche A Loans. (a) Generally. Subject to the terms and conditions of this Agreement, each Bank severally agrees to make Tranche A Loans to the Company from time to time on and after the Effective Date to, but excluding, the Tranche A Termination Date, provided that the aggregate unpaid principal amount of all Tranche A Loans due to each Bank at any one time shall not exceed an amount equal to such Bank's Tranche A Commitment, and provided further that the aggregate unpaid principal amount of the Tranche A Loans at any one time outstanding shall not exceed the lesser of (i) the Aggregate Tranche A Commitments and (ii) the aggregate outstanding principal balance of all Tranche A Loans permitted to be outstanding hereunder after giving effect to the mandatory repayments required to be made under paragraph 2.6(b). During the period from the Effective Date to the Tranche A Termination Date, the Company may borrow, repay and reborrow hereunder, and may convert all or any part of the Tranche A Loans from one Type to another Type or continue all or any part of the Tranche A Loans as the same Type in accordance with and subject to the terms and provisions hereof. In the event the Company elects to extend the scheduled maturity of the Tranche A Loans in accordance with paragraph 2.15 hereof, during the period from and after the Tranche A Termination Date to the extended Tranche A Termination Date, the Company may prepay the Tranche A Loans and may convert all or any part of the Tranche A Loans from one Type to Tranche A Loans of another Type or continue all or any part of the Tranche A Loans as the same Type, all in accordance with and subject to the terms and provisions hereof. (b) Pro Rata Loans. Upon the terms and subject to the conditions of this Agreement, each Bank agrees to make, from time to time during the period from the Effective Date through the Tranche A Termination Date, Pro Rata Loans to the Company. The aggregate unpaid principal amount of all Tranche A Pro Rata Loans made by each Bank shall not exceed at any one time an amount equal to such Bank's Tranche A Commitment, and the aggregate unpaid principal amount of the Tranche A Loans at any one time outstanding shall not exceed the lesser of (i) the Aggregate Tranche A Commitments and (ii) the aggregate outstanding principal balance of all Tranche A Loans permitted to be outstanding hereunder after giving effect to the mandatory repayments required to be made under paragraph 2.6(b). Subject to the terms and conditions of this Agreement, the Tranche A Pro Rata Loans may, at the option of the Company, be made as, and from time to time continued as or converted into, Alternate Base Rate or Eurodollar Rate Loans of any permitted Type, or any combination thereof. (c) Bid Rate Loans. Upon the terms and subject to the conditions of this Agreement, each Bank may, in response to each request for Tranche A Bid Rate Loans, submit one or more bids to make Tranche A Bid Rate Loans as provided in paragraph 2.3(b). Each Bank shall have sole and absolute discretion whether to submit any such bid or bids and is not under any obligation so to do. 2.2 Tranche B Loans. (a) Generally. Subject to the terms and conditions of this Agreement, each Bank severally agrees to make Tranche B Loans to the Company from time to time on and after the Effective Date to, but excluding, the Tranche B Termination Date, provided that the aggregate unpaid principal amount of all Tranche B Loans due to each Bank at any one time shall not exceed an amount equal to such Bank's Tranche B Commitment, and provided further that the aggregate unpaid principal amount of the Tranche B Loans at any one time outstanding shall not exceed the lesser of (i) the Aggregate Tranche B Commitments and (ii) the aggregate outstanding principal balance of all Tranche B Loans permitted to be outstanding hereunder after giving effect to the mandatory repayments required to be made under paragraph 2.6(b). During the period from the Effective Date to the Tranche B Termination Date, the Company may borrow, repay and reborrow hereunder, and may convert all or any part of the Tranche B Loans from one Type to another Type or continue all or any part of the Tranche B Loans as the same Type in accordance with and subject to the terms and provisions hereof. In the event the Company elects to extend the scheduled maturity of the Tranche B Loans in accordance with paragraph 2.15 hereof, during the period from and after the Tranche B Termination Date to the extended Tranche B Termination Date, the Company may prepay the Tranche B Loans and may convert all or any part of the Tranche B Loans from one Type to Tranche B Loans of another Type or continue all or any part of the Tranche B Loans as the same Type, all in accordance with and subject to the terms and provisions hereof. (b) Pro Rata Loans. Upon the terms and subject to the conditions of this Agreement, each Bank agrees to make, from time to time during the period from the Effective Date through the Tranche B Termination Date, Pro Rata Loans to the Company. The aggregate unpaid principal amount of all Tranche B Pro Rata Loans made by each Bank shall not exceed at any one time an amount equal to such Bank's Tranche B Commitment, and the aggregate unpaid principal amount of the Tranche B Loans at any one time outstanding shall not exceed the lesser of (i) the Aggregate Tranche B Commitments and (ii) the aggregate outstanding principal balance of all Tranche B Loans permitted to be outstanding hereunder after giving effect to the mandatory repayments required to be made under paragraph 2.6(b). Subject to the terms and conditions of this Agreement, the Tranche B Pro Rata Loans may, at the option of the Company, be made as, and from time to time continued as or converted into, Alternate Base Rate or Eurodollar Rate Loans of any permitted Type, or any combination thereof. (c) Bid Rate Loans. Upon the terms and subject to the conditions of this Agreement, each Bank may, in response to each request for Tranche B Bid Rate Loans, submit one or more bids to make Tranche B Bid Rate Loans as provided in paragraph 2.3(b). Each Bank shall have sole and absolute discretion whether to submit any such bid or bids and is not under any obligation so to do. 2.3 Procedure for Borrowings. (a) With respect to Pro Rata Loans, the Company may effect a Borrowing on any Business Day occurring on or after the Effective Date by giving the Agent an irrevocable telephonic (to be promptly confirmed in writing) or written notice of borrowing (each, a "Borrowing Request" in the form of Exhibit C) (which Borrowing Request must be received by the Agent (a) prior to 10:00 a.m., Boston time, two Business Days prior to the requested Borrowing Date, if the Company is requesting that Eurodollar Rate Loans be made as part of such Borrowing, and (b) prior to 10:00 a.m., Boston time, one Business Day prior to the requested Borrowing Date, if the Company is requesting that Alternate Base Rate Loans be made as part of such Borrowing), specifying (i) the amount to be borrowed, (ii) the requested Borrowing Date, (iii) whether such Borrowing is to consist of Eurodollar Rate Loans, Alternate Base Rate Loans or a combination thereof, and (iv) if the Loans are to be Eurodollar Rate Loans, the length of the initial Interest Period for each thereof. Each Borrowing shall be in an aggregate principal amount equal to or greater than $500,000 or, if less, the undrawn balance of the Aggregate Tranche A or Tranche B Commitments, as the case may be. The principal amount of each Bank's Tranche A Loan or Tranche B Loan made on a Borrowing Date shall be in an amount equal to such Bank's Tranche A Commitment Percentage or Tranche B Commitment Percentage, as the case may be, of the Loans made on such Borrowing Date. Subject to the provisions of paragraphs 2.8 and 2.9, Loans may be Alternate Base Rate Loans or Eurodollar Rate Loans, or any combination thereof. Upon receipt of each Borrowing Request from the Company, the Agent shall promptly notify each Bank thereof (such notice to be promptly confirmed in writing). Each Bank will make the amount of its Commitment Percentage of each Borrowing available to the Agent for the account of the Company at the office of the Agent set forth in paragraph 11.1, in the case of Eurodollar Rate Loans, not later than 12:00 noon, Boston time, and in the case of Alternate Base Rate Loans, not later than 11:00 a.m., Boston time, on the Borrowing Date requested by the Company, in funds immediately available to the Agent at such office. Amounts so made available to the Agent on a Borrowing Date will, subject to the satisfaction of the terms and conditions of this Agreement as determined by the Agent, be made immediately available on such date to the Company by the Agent at the office of the Agent specified in paragraph 11.1 by crediting the account of the Company on the books of such office with the aggregate of said amounts, in like funds as received by the Agent. Unless the Agent shall have received prior notice from a Bank (by telephone or otherwise, such notice to be promptly confirmed by telex, telecopy or other writing) that such Bank will not make available to the Agent such Bank's pro rata share of the Loans requested by the Company, the Agent may assume that such Bank has made such share available to the Agent on such Borrowing Date in accordance with this paragraph, provided that such Bank received notice of the proposed borrowing from the Agent, and the Agent may, in reliance upon such assumption, make available to the Company on such Borrowing Date a corresponding amount. If and to the extent such Bank shall not have so made such pro rata share available to the Agent on such Borrowing Date, such Bank shall pay to the Agent on demand an amount equal to the product of (i) the average computed for the period referred to in clause (iii) below, of the weighted average interest rate paid by the Agent for federal funds acquired by the Agent during each day included in such period, times (ii) the amount of such Bank's Commitment Percentage of such Loans, times (iii) a fraction, the numerator of which is the number of days that elapse from and including such Borrowing Date to the date on which the amount of such Bank's Commitment Percentage of such Loans shall become immediately available to the Agent, and the denominator of which is 365. If such Bank shall pay to the Agent such amount, such amount so paid shall constitute such Bank's Loan as part of such Loans for purposes of this Agreement, which Loan shall be deemed to have been made by such Bank on the date such amount is so paid, but without prejudice to the Company's rights against such Bank. If and to the extent such Bank shall not have so made such pro rata share available to the Agent within three (3) days following such Borrowing Date, the Company shall pay to the Agent forthwith on demand (but without duplication) an amount equal to such Bank's Commitment Percentage of such Loans, together with interest thereon for each day from the date such amount is made available to the Company until the date such amount is paid to the Agent, at the applicable interest rate for such Loans as set forth in paragraph 2.8. Such payment by the Company, however, shall be without prejudice to its rights against such Bank. (b) With respect to Bid Rate Loans: (i) The Company shall give each Bank a request for a Bid Borrowing which, at the Company's option, shall be by telephone, telex or telecopy, no later than 10:00 a.m. on the requested date for such Bid Borrowing (a "Bid Borrowing Date"). No more than three Bid Borrowings may be requested for any day. Such request (other than a telephonic request) shall be submitted in the form of Exhibit D and each request shall specify (A) the requested date of such Bid Borrowing, which shall be a Business Day, (B) the principal amount of such Bid Borrowing, which shall be equal to $500,000 or any multiple of $500,000, (C) the extent to which such Bid Borrowing is to be applied on the requested date of such Bid Borrowing to prepay Loans pursuant to paragraph 2.6, and (D) the maturity date (which shall be a Business Day (1) no earlier than one day and no later than 180 days, after the requested date of such Bid Borrowing and (2) no later than the applicable Termination Date) of Bid Rate Loans to be made pursuant to such Bid Borrowing. (ii) Each Bank may, in its sole and absolute discretion, submit, by telephone, telex or telecopy, to the Company no later than 11:00 a.m. on the Bid Borrowing Date, not more than two bids for Bid Rate Loans in response to a request for a Bid Borrowing. Each bid (other than a telephonic bid) shall be submitted in the form of Exhibit E, and each bid shall (A) identify the Bank making such bid, (B) identify the Bid Borrowing to which such bid relates, (C) specify the fixed rate of interest per annum (computed on the basis of a 360-day year and for the actual number of days elapsed and expressed in decimals to 1/10,000 of 1%) that such Bank is willing to offer for a Bid Rate Loan to be made as part of such Bid Borrowing, and (D) specify the maximum and minimum principal amount of the Bid Rate Loan such Bank is willing to make at such rate as part of such Bid Borrowing, which amount may exceed such Bank's Tranche A Commitment or Tranche B Commitment, as the case may be, at such time. All bids of a Bank with respect to Bid Borrowings to be made at the same time must be submitted by such Bank at the same time. No such bid may contain qualifying, conditional or similar language or contain proposed terms other than those specified in this paragraph (ii). Each such bid shall be irrevocable and may not be modified except to correct a manifest error therein that has not been relied upon by the Company. (iii) Not later than 12:00 p.m. on the Bid Borrowing Date, the Company shall telephonically notify (which telephonic notice shall be promptly confirmed in writing by facsimile in substantially the form of Exhibit F) each of the Banks that submitted an accepted bid with respect to the applicable Bid Borrowing (which notice shall be irrevocable except, with respect to notices that have not yet been relied upon by any Bank, in the case of manifest error) that such bids were accepted and shall identify such bids and the respective amounts thereof so accepted. Concurrently with the notification to the Banks of any accepted bids, the Company shall notify the Agent in substantially the form of Exhibit F, and shall identify (A) the Bank making such Loan, (B) the date of the Loan, (C) the amount of the Loan and (D) the terms of the Loan. Each bid that the Company has not notified the Banks by such time that it is accepting shall be deemed to have been rejected. The Company may accept or reject any bid in whole or in part; provided, however, that (A) the Company may not accept bids to the extent that, after giving effect thereto, the aggregate unpaid principal amount of all Tranche A Loans or Tranche B Loans of all of the Banks at such time would exceed the aggregate amount of the Tranche A Commitments or Tranche B Commitments, as the case may be, of all of the Banks at such time, (B) the aggregate principal amount of bids accepted with respect to any Bid Borrowing may not exceed the principal amount specified for such Bid Borrowing in the request therefor, and (C) the aggregate principal amount of any bid by any Bank accepted with respect to a Bid Borrowing may not exceed the maximum, nor be less than the minimum, aggregate principal amount thereof specified in such Bank's response to the request for such Bid Borrowing. (iv) Not later than 1:00 p.m. on the date of each Bid Borrowing, each Bank that has had accepted all or part of any bid made by it with respect to such Bid Borrowing shall wire transfer the amount of the Bid Rate Loan or Loans to be made by such Bank as part of such Bid Borrowing to the Company's account with the Agent, in Dollars immediately available. (v) Bid Borrowings shall be disbursed by the Agent not later than 2:00 p.m. on the date specified therefor in the following order: (A) first, to be applied by the Agent to repay Bid Rate Loans maturing or matured as of the date of such Bid Borrowing, (B) second, to be applied by the Agent to prepay Loans as specified in paragraph 2.03(b)(i)(C) and for which payments a notice of prepayment shall have been duly given in accordance with paragraph 2.6 and (C) third, by credit to an account of the Company at the Agent's Office or in such other manner as may have been specified in the applicable notice and as shall be acceptable to the Agent, in each case in Dollars immediately available to the Company or the appropriate Bank, as the case may be. (vi) Each Bid Borrowing shall be deemed a reduction of the unused Tranche A Commitments and then, to the extent that there are no unused Tranche A Commitments, a reduction of the unused Tranche B Commitments, of each Bank in an amount equal to such Bank's pro-rata share (determined in accordance with their respective Tranche A Commitments or Tranche B Commitments, as the case may be,) of the aggregate amounts of Bid Rate Loans made pursuant to such Bid Borrowing, whether or not such Bank shall have made any Bid Rate Loan, and notwithstanding the amount of any Bid Rate Loan made by such Bank, as a part of such Bid Borrowing. The unused Tranche A Commitment or Tranche B Commitment, as the case may be, of each Bank shall, upon repayment of a Bid Rate Loan not later than the applicable Termination Date, be reinstated in the amount of the corresponding reduction effected pursuant to the preceding sentence. (vii) If (A) (1) the Company shall, on a Bid Borrowing Date, fail to accept bids in an aggregate amount sufficient to repay the Bid Rate Loans maturing or matured as of such day, or (2) if bids submitted in response to a request for a Bid Borrowing are in an aggregate amount insufficient to pay the Bid Rate Loan or Loans maturing or matured as of the day of such Bid Borrowing and (B) Bid Rate Loans maturing on such day shall not otherwise be repaid on such day, the Company shall, unless it provides written notice to the Agent to the contrary by 11:00 a.m. on such day, be deemed to have duly requested Alternate Base Rate Loans to be made on such date in an amount sufficient to repay the balance of such maturing and matured Bid Rate Loans. (viii) The parties may, by agreement among the Company, the Agent and each of the Banks, adopt in writing alternative procedures (including alternative time schedules) for requesting, offering and consummating Bid Rate Loans. 2.4 Notes. Loans made by each Bank with respect to Alternate Base Rate Loans and Eurodollar Rate Loans shall be evidenced by a promissory note of the Company, substantially in the form of Exhibit G- 1, and with respect to Bid Rate Loans shall be evidenced by a promissory note of the Company substantially in the form of Exhibit G-2 (a "Bid Rate Note"), all with appropriate insertions therein (as endorsed and as amended or otherwise modified from time to time, a "Note" and, collectively, the "Notes"), payable to the order of such Bank and representing the obligation of the Company to pay the aggregate unpaid principal amount of all Loans made by such Bank, with interest thereon as prescribed or determined herein. Each Bank is hereby authorized to record the date and amount of each Loan made by such Bank and the other information applicable thereto, and each payment or prepayment of principal of, such Loan, on the applicable grid (and any continuations thereof) annexed to and constituting a part of its Note. No failure to so record or any error in so recording shall affect the obligation of the Company to repay such Loans, with interest thereon, as herein provided. Each Note shall (a) be dated the date the initial Loans are made, (b) be stated to mature on the Tranche A Termination Date or Tranche B Termination Date, as the case may be, and (c) bear interest for the period from and including the date thereof on the unpaid principal amount thereof from time to time outstanding at the applicable interest rate per annum determined as provided herein. 2.5 Voluntary Reductions of the Aggregate Commitments: Termination. (a) Voluntary Reductions. During the period from the Effective Date to the Tranche A Termination Date and the Tranche B Termination Date, as the case may be, the Company shall have the right, upon at least two Business Days' prior written notice to the Agent, to reduce permanently the Aggregate Tranche A Commitments or Tranche B Commitments, as the case may be, in whole at any time, or in part from time to time, without premium or penalty, provided that (i) each partial reduction of such Aggregate Commitments shall be in an amount equal to at least $500,000 or such amount plus a whole multiple of $500,000, and (ii) such Aggregate Commitments shall not be reduced to an amount less than the aggregate principal balance of the Tranche A Loans or the Tranche B Loans, as the case may be, outstanding on the date of such reduction (after giving effect to reductions in such balance made on such date). Upon such Aggregate Commitments being permanently reduced to zero prior to such Termination Date and upon payment in full of such Loans and all other sums due hereunder and under such Notes, this Agreement shall be deemed terminated with respect to the Tranche A Loans or the Tranche B Loans, or both, as the case may be, except to the extent that any provisions hereof expressly survive such payment. (b) General. Reductions of the Aggregate Commitments under clause (a) above shall reduce each Bank's Commitment pro rata according to the Commitment Percentage of such Bank. The Agent shall promptly notify each Bank of each reduction in the Aggregate Commitments under clause (a) above upon its receipt of notice thereof, and remit to each Bank its pro rata share of any accompanying prepayments of the Loans according to the outstanding principal balance of the Loans. Simultaneously with each reduction of the Aggregate Commitments under this paragraph 2.5, the Company shall prepay the Loans in the amount, if any, by which the aggregate unpaid principal balance of the Loans exceeds the amount of the Aggregate Commitments as so reduced. If any prepayment is made under this paragraph 2.5 with respect to any Eurodollar Rate Loans, in whole or in part, prior to the last day of the applicable Interest Period with respect thereto, the Company agrees that it shall indemnify the Banks in accordance with paragraph 2.12. After giving effect to any prepayment with respect to Eurodollar Rate Loans, no Eurodollar Rate Loans made (whether as a result of Borrowing or a conversion) on the same date and having the same Interest Period shall be outstanding in an aggregate principal amount of less than $500,000. 2.6 Prepayments and Payment of Loans. (a) Voluntary Prepayments. The Company may, at its option, prepay Alternate Base Rate Loans or Eurodollar Rate Loans in whole or in part, without premium or penalty, subject to its obligation to indemnify provided in paragraph 2.12 (in the case of Eurodollar Rate Loans), at any time and from time to time upon at least one Business Day's prior irrevocable written notice to the Agent, specifying the amount to be prepaid, and the date and amount of prepayment. Upon receipt of such notice, the Agent shall promptly notify each Bank thereof. Any such notice shall be irrevocable and the amount specified in such notice shall be due and payable on the date specified therein, together with accrued interest to the date of such payment on the amount being prepaid. Prepayments shall be in an aggregate principal amount of at least $500,000 or, if less, the outstanding principal balance of the applicable Notes, provided, however, that after giving effect to any such prepayment, no Eurodollar Rate Loans made (whether as the result of Borrowing or a conversion) on the same date and having the same Interest Period shall be outstanding in an aggregate principal amount of less than $500,000. (b) Mandatory Repayment. On each Termination Date, as may be extended in accordance with the terms of paragraph 2.15 hereof, the Company shall repay in full the aggregate principal balance of all Tranche A Loans and Tranche B Loans, as the case may be, outstanding on such date, together with accrued interest on such amount to such date and any Facility Fees, Agent's Fees or other amounts owing hereunder or under the Notes. (c) Prepayments of Bid Rate Loans. Bid Rate Loans may not be prepaid. 2.7 Conversion Options. (a) Conversion of Pro Rata Loans. The Company may elect from time to time to convert Eurodollar Rate Loans to Alternate Base Rate Loans by giving the Agent at least one Business Day's prior notice of such election (in substantially the form of Borrowing Request attached hereto as Exhibit C), specifying the amount to be so converted, provided, that any such conversion of Eurodollar Rate Loans shall only be made on the last day of the Interest Period applicable thereto. In addition, in the absence of an Event of Default, the Company may elect from time to time to convert Alternate Base Rate Loans to Eurodollar Rate Loans, by giving the Agent at least two Business Day's prior irrevocable notice of such election, specifying the amount to be so converted and the Interest Period selected, provided that any such conversion of Alternate Base Rate Loans to Eurodollar Rate Loans shall only be made on a Business Day. The Agent shall promptly provide the Banks with notice of any such election. Loans may be converted pursuant to this paragraph 2.7, in whole or in part, provided that conversions of Alternate Base Rate Loans to Eurodollar Rate Loans or Eurodollar Rate Loans to Alternate Base Rate Loans shall be in an aggregate principal amount of at least $500,000. After giving effect to any such conversion, no Eurodollar Rate Loans made (whether as the result of a borrowing or a conversion) on the same date and having the same Interest Period shall be outstanding in an aggregate principal amount of less than $500,000. A conversion of a Loan in accordance with this paragraph 2.7 shall not require the Company to comply with the conditions to Borrowing set forth in paragraph 6. (b) Continuation of Pro Rata Loans. Any Eurodollar Rate Loans may be continued as such upon the expiration of any Interest Period with respect thereto by the Company's giving irrevocable written notice (in substantially the form of Borrowing Request attached hereto as Exhibit C) to the Agent of its intention to do so two Business Days prior to the last day of such Interest Period, specifying the new Interest Period therefor, provided, however, that (i) if the Company shall fail to give notice as provided above, the relevant Eurodollar Rate Loan shall convert to an Alternate Base Rate Loan immediately upon the expiration of the then current Interest Period with respect thereto, (ii) any Eurodollar Rate Loans that are being continued as such shall be in an aggregate principal amount of at least $500,000 and (iii) no Eurodollar Rate Loans may be continued as such when any Event of Default has occurred and is continuing, but shall be automatically converted to an Alternate Base Rate Loan on the last day of the Interest Period with respect thereto during which the Agent obtained knowledge of such Event of Default. The Agent shall notify the Banks promptly upon obtaining knowledge that an automatic conversion will occur pursuant to clause (iii) hereof. (c) Restrictions on Conversion and Continuation of Bid Rate Loans. Bid Rate Loans may not be converted or continued, except as required under paragraph 2.11(b). 2.8 Interest Rate and Payment Dates for Loans. (a) Interest Rates for Loans Prior to Maturity. (i) Loans made as Alternate Base Rate Loans shall bear interest for the period from and including the date thereof, or, in the case of a Loan that has been converted from a Eurodollar Rate Loan, from the Conversion Date thereof, until maturity or until converted into Eurodollar Rate Loans, on the unpaid principal amount thereof at the Alternate Base Rate, and (ii) Loans made as Eurodollar Rate Loans shall bear interest for each Interest Period with respect thereto on the unpaid principal amount thereof at the applicable rate of interest per annum based on the Eurodollar Rate for each such Interest Period plus the Applicable Margin for such period based on the Debt Rating of the Company, provided that if the Company has no Debt Rating, the Applicable Margin shall be the highest rate per annum applicable to such Loans during the relevant period and (iii) Loans made as Bid Rate Loans shall bear interest in accordance with paragraph 2.3(b). Any change in the Applicable Margin with respect to any Loans resulting from a change in the Debt Rating of the Company shall be effective as of the opening of business on the day of the change in the Debt Rating of the Company. (b) Overdue Amounts. If any amounts payable hereunder shall not be paid when due (whether at the stated maturity thereof, by acceleration, notice of intention to prepay or otherwise), such overdue amounts shall bear interest payable on demand at a rate per annum equal to 2% above the (i) Alternate Base Rate for Alternate Base Rate Loans at such time from the date of such nonpayment until paid in full, and whether before or after the entry of any judgment thereon, (ii) sum of the Eurodollar Rate plus the Applicable Margin for Eurodollar Rate Loans, from the date of such nonpayment until the end of the Interest Period with respect thereto and whether before or after the entry of any judgment thereon and (iii) Bid Rate for Bid Rate Loans, from the date of such nonpayment until the end of the Interest Period with respect thereto and whether before or after the entry of any judgment thereon. (c) General. Interest on the Loans shall be payable in arrears on each Interest Payment Date and upon payment (including prepayment) in full thereof; provided, however, that after an Event of Default has occurred and is continuing, interest on all Loans shall be payable on demand made from time to time. At no time shall the interest rate payable on the Loans, together with the Agent's Fees, the Facility Fee and all other fees and amounts payable hereunder and under the Notes, to the extent that any of the same are construed to constitute interest, exceed the maximum rate of interest permitted by law. The Company acknowledges that to the extent interest payable on the Loans is based upon the Alternate Base Rate, such Rate is only one of the bases for computing interest on loans made by the Banks, and by basing interest payable upon the Loans upon the Alternate Base Rate, the Banks have not committed to charge, and the Company has not in any way bargained for, interest based on a lower or the lowest rate at which the Banks may now or in the future make loans to other borrowers. 2.9 Substituted Interest Rate. In the event that the Agent shall have reasonably determined in good faith (which determination shall be conclusive and binding upon the Company) that by reason of circumstances affecting the London interbank eurodollar market, (i) either adequate and reasonable means do not exist for ascertaining a Eurodollar Rate applicable pursuant to paragraph 2.8(a), or (ii) any Bank shall have notified the Agent that it has reasonably determined in good faith (which determination shall be conclusive and binding on the Company) that the Eurodollar Rate will not adequately and fairly reflect the cost to such Bank of making or maintaining its funding of a Eurodollar Rate Loan with respect to (a) a proposed Loan that the Company has requested be made as a Eurodollar Rate Loan, or (b) a Eurodollar Rate Loan that will result from the requested conversion of any Loan into a Eurodollar Rate Loan (any such Loan being herein called an "Affected Loan"), the Agent shall promptly notify the Company and the Banks (by telephone or otherwise) of such determination no later than 10:00 a.m. (Boston time) one Business Day prior to the requested Borrowing Date for such Affected Loan, or the requested Conversion Date of such Loan, as the case may be. If the Agent shall give such notice, the Company may by no later than 11:00 a.m. (Boston time) on the same Business Day, (i) cancel the Borrowing Request with respect to such Affected Loan or request that such Affected Loan be made as an Alternate Base Rate Loan or as a Bid Rate Loan in accordance with paragraph 2.3 hereof or (ii) cancel its request to convert to an Affected Loan or request that any Loan that was to have been converted to an Affected Loan be converted to an Alternate Base Rate Loan or a Bid Rate Loan in accordance with paragraph 2.3 hereof. Until such notice has been withdrawn by the Agent (by notice to the Company promptly upon the Agent having been notified by such Bank that circumstances would no longer render any Loan an Affected Loan) no further Affected Loans shall be made and Company shall not have the right to convert any Loan to an Affected Loan. 2.10 Illegality. Notwithstanding any provision hereof to the contrary, if any change in any law, regulation, treaty or directive, or in the interpretation or application thereof, shall make it unlawful for any Bank to make or maintain Eurodollar Rate Loans as contemplated by this Agreement, (a) the commitment of such Bank hereunder to make Eurodollar Rate Loans or to convert Alternate Base Rate Loans to Eurodollar Rate Loans or to continue Eurodollar Rate Loans as such shall forthwith be suspended and (b) such Bank's Loans then outstanding as Eurodollar Rate Loans shall be converted to Alternate Base Rate Loans on the last day of the then current Interest Period applicable thereto, or within such earlier period as required by law. If the commitment of any Bank with respect to Eurodollar Rate Loans is suspended pursuant to this paragraph 2.10 and it shall once again become legal for such Bank to make or maintain its funding of Eurodollar Rate Loans, such Bank's commitment to make or maintain such Eurodollar Rate Loans shall be reinstated. Each Bank agrees to promptly notify the Company and the Agent upon learning of any change referred to above, as well as of any reinstatement of its ability to make and maintain Eurodollar Rate Loans as contemplated by this Agreement. 2.11 Increased Costs. (a) Regulatory Changes. In the event that any change in any law, regulation, treaty or directive or in the interpretation or application thereof by any Governmental Body charged with the administration thereof or compliance by any Bank with any request or directive from any central bank or other Governmental Body (a "Regulatory Change"): (i) subjects any Bank to any tax of any kind whatsoever with respect to any Eurodollar Rate Loan or its obligations under this Agreement to make Eurodollar Rate Loans, or changes the basis of taxation of payments to such Bank of principal, interest or any other amount payable hereunder in respect of its Eurodollar Rate Loans (except for imposition of, or change in the rate of, tax on the overall net income of such Bank); (ii) imposes, modifies or makes applicable any reserve, special deposit, compulsory loan, assessment or similar requirement against assets held by, or deposits of, or advances or loans by, or other credit committed or extended by, or any other acquisition of funds by, any office of such Bank in respect of its Eurodollar Rate Loans which is not otherwise included in the determination of a Eurodollar Rate; or (iii) imposes on such Bank any other condition with respect to Loans hereunder or the Commitments; and the result of any of the foregoing is to increase the cost to such Bank of making, renewing, converting or maintaining its Eurodollar Rate Loans, or to reduce any amount receivable in respect of its Eurodollar Rate Loans, then, in any such case, the Company shall promptly pay to such Bank, upon its demand, any additional amounts necessary to compensate such Bank for such additional cost or reduction in such amount receivable. A statement setting forth the calculations of any additional amounts payable pursuant to the foregoing sentence submitted by a Bank to the Company shall be presumed to be correct absent manifest error. (b) Automatic Conversion. A Bank's Bid Rate Loans of any Type shall be converted into Alternate Base Rate Loans (in the case of clause (i) below, on the last day such Bank may lawfully continue to maintain Loans of that Type, and, in the case of clause (ii) below, on the day determined by such Bank to be the last Business Day before the effective date of the applicable restriction) if: (i) at any time such Bank determines that any Regulatory Change makes it unlawful for such Bank to maintain any Bid Rate Loan of that Type, or to comply with its obligations hereunder in respect thereof; or (ii) such Bank determines that, by reason of any Regulatory Change, such Bank is restricted, directly or indirectly, in the amount that it may hold of (A) a category of liabilities that includes deposits by reference to which, or on the basis of which, the interest rate applicable to Bid Rate Loans of that Type is directly or indirectly determined, or (B) the category of assets that includes Bid Rate Loans of that Type. (c) Treatment of Converted Loans. If, as a result of paragraph 2.11(b), any Loan of any Bank that would otherwise be maintained as a Bid Rate Loan of any Type for any Interest Period is instead converted into an Alternate Base Rate Loan, then, such Loan shall be treated as being a Bid Rate Loan of such Type for such Interest Period for all purposes of this Agreement (including the timing, application and proration among the Banks of interest payments, conversions and prepayments) except for the calculation of the interest rate borne by such Loan. The Agent shall promptly notify the Company and each Bank of the existence or occurrence of any condition or circumstance specified in Section 2.11(b)(i), and each Bank shall promptly notify the Company and the Agent of the existence or occurrence of any condition or circumstances specified in Sections 2.11(b)(ii) applicable to such Bank's Loans, but the failure by the Agent or such Bank to give any such notice shall not affect such Bank's rights hereunder. 2.12 Indemnity. Notwithstanding anything contained herein to the contrary, if the Company shall fail to borrow on a Borrowing Date after it shall have given a Borrowing Request, to the extent only that such Borrowing Request includes Eurodollar Loans or Bid Rate Loans, or if the right of the Company to have Eurodollar Rate Loans or Bid Rate Loans outstanding hereunder shall be suspended or terminated in accordance with the provisions of this Agreement prior to the last day of the Interest Period applicable thereto, or if, while a Eurodollar Rate Loan or Bid Rate Loan is outstanding, any repayment or prepayment of the principal amount of such Eurodollar Rate Loan or Bid Rate Loan is made for any reason (including, without limitation, as a result of acceleration or illegality) on a date which is prior to the last day of the Interest Period applicable thereto, the Company agrees to indemnify each Bank against, and to pay on demand directly to such Bank, an amount, if greater than zero, equal to (i) with respect to Eurodollar Rate Loans, A x (B - C) x D - 365 where: "A" equals the Affected Principal Amount; "B" equals the Eurodollar Rate (expressed as a decimal), as the case may be, applicable to such Eurodollar Rate Loan; "C" equals the applicable Eurodollar Rate (expressed as a decimal), as the case may be, in effect on the date of such failure to borrow, termination, prepayment or repayment, based on the applicable rates offered or bid, as the case may be, on such date (or, if no such rate is determinable on such date, the rate or rates offered or bid, as the case may be, determinable on the date closest thereto), for deposits in an amount equal approximately to the Affected Principal Amount with an Interest Period equal approximately to the period commencing on the first day of such Remaining Interest Period and ending on the last day of such Remaining Interest Period or ending on the last day of the applicable Interest Payment Period, as the case may be, as determined by the Bank; "D" equals the number of days from and including the first day of the Remaining Interest Period to but excluding the last day of such Remaining Interest Payment Period; and (ii) with respect to both Eurodollar Rate Loans and Bid Rate Loans, any additional amounts necessary to compensate such Bank for such additional cost or reduction in such amount receivable and any other out-of-pocket loss or expense (including any internal processing charge customarily charged by such Bank) suffered by such Bank in liquidating deposits prior to maturity in amounts which correspond to the proposed borrowing, prepayment or repayment. The determination by each Bank of the amount of any such loss or expense shall be presumed to be correct absent manifest error. 2.13 Use of Proceeds. The proceeds of the Loans shall be used for working capital and other general corporate purposes. 2.14 Capital Adequacy. If either (i) the introduction of, or any change or phasing in of, any law or regulation or in the interpretation thereof by any Governmental Body charged with the administration thereof or (ii) compliance with any directive, guideline or request from any central bank or Governmental Body (whether or not having the force of law) promulgated or made after the date hereof (but including, in any event, any law, rule, regulation, interpretation, directive, guideline or request contemplated by the report dated July 1988 entitled "International Convergence of Capital Measurement and Capital Standards" issued by the Basle Committee on Banking Regulations and Supervisory Practices) affects or would affect the amount of capital required or expected to be maintained by a Bank (or any lending office of such Bank) or any corporation directly or indirectly owning or controlling such Bank (or any lending office of such Bank) and such Bank shall have determined that such introduction, change or compliance has or would have the effect of reducing the rate of return on such Bank's capital or the asset value to such Bank of any Loan made by such Bank as a consequence, directly or indirectly, of its obligations to make and maintain the funding of Loans hereunder to a level below that which such Bank could have achieved but for such introduction, change or compliance (after taking into account such Bank's policies regarding capital adequacy) by an amount deemed by such Bank to be material, then, upon demand by such Bank, the Company shall promptly pay to such Bank such additional amount or amounts as shall be sufficient to compensate such Bank for such reduction on the rate of return. Each Bank shall calculate such amount or amounts payable to it under this paragraph 2.14 in a manner consistent with the manner in which it shall calculate similar amounts payable to it by other borrowers having provisions in their credit agreements comparable to this paragraph 2.14. Each Bank agrees to provide the Company with a certificate setting forth a description of any such amount in respect of which it seeks payment under this paragraph 2.14. Each Bank's determination of such amount or amounts that will compensate such Bank for such reductions shall be presumed correct absent manifest error. 2.15 Extension of Termination Date. With respect to Tranche A Loans, the Company may, pursuant to a Commitment Extension Request in the form of Exhibit H delivered to the Agent and each Bank not less than 75 days prior to the then scheduled Termination Date, request each Bank to extend its Commitment for an additional three-hundred sixty-four (364) day period expiring on the 364th day of such period (or, if such date is not a Business Day, on the immediately preceding Business Day). With respect to Tranche B Loans, the Company may request each Bank to extend its Commitment on no more than two (2) occasions pursuant to a Commitment Extension Request delivered to the Agent and each Bank not less than 75 days prior to the first and second anniversaries of the date hereof for additional one-year periods expiring on the fourth and fifth anniversaries of the date hereof, respectively (or, if such date is not a Business Day, on the next succeeding Business Day). Each of the Banks shall, within 45 days of receipt of a Commitment Extension Request from the Company, provide the Company with a non-binding preliminary indication regarding whether such Bank is likely to consent to the extension of its Commitment. If all Banks consent to the extension of their respective Commitments, which consents shall be given no less than 30 days prior to the then scheduled applicable Termination Date, by signing and returning an original copy of the Commitment Extension Request attached hereto as Exhibit H, such Termination Date shall be so extended, and each Bank hereby agrees that the Agent may amend this Agreement and any other Loan Document to the extent necessary to effectuate such extension without the necessity of obtaining any such Bank's signature, the provisions of paragraph 13 to the contrary notwithstanding. In the event that less than all of the Banks consent to an extension of their respective Commitments, such Termination Date shall not be extended, unless the Company designates another bank reasonably satisfactory to the Banks willing so to extend such Termination Date, or one or more of the signatory Banks elect to increase its or their Commitments to the amount of the Commitment of the nonconsenting Bank (any such other bank, including any signatory Bank, to the extent of, and with respect to such an increase in its Commitment, being herein called a "Replacement Bank"), to assume the Commitment and obligations of such nonconsenting Bank or Banks (each, a "Nonconsenting Bank") with respect to its Loans, and to purchase the outstanding Note of such nonconsenting Bank and such Nonconsenting Bank's rights with respect to its Loans, without recourse or warranty, for a purchase price equal to the outstanding principal balance of the Note of such Nonconsenting Bank, plus all interest accrued thereon and all other amounts owing to such Nonconsenting Bank hereunder. Upon such assumption and purchase by a Replacement Bank, and provided that the Banks (excluding the Nonconsenting Banks and each Replacement Bank) have consented to the Commitment Extension Request prior to the then scheduled Termination Date, (i) such Termination Date shall be so extended, (ii) each such Replacement Bank shall be deemed to be a "Bank" for purposes of this Agreement, and (iii) each Nonconsenting Bank shall cease to be a "Bank" for all purposes of this Agreement (except with respect to its rights hereunder to be reimbursed for costs and expenses, and to indemnification with respect to, matters attributable to events, acts or conditions occurring prior to such assumption and purchase) and shall no longer have any obligations hereunder. Each Bank will use its best efforts to respond promptly to any Commitment Extension Request, provided that no Bank's failure to so respond shall create any claim against it or have the effect of extending such applicable Termination Date. 2.16 Notice of Costs: Substitution of Banks. Each Bank will notify the Company of any event that will entitle such Bank to compensation under paragraphs 2.11 and 2.14 as promptly as practicable, but in any event within 45 days after an officer of the Bank responsible for matters concerning this Agreement has knowledge of such event. If such Bank fails to give such notice, such Bank shall only be entitled to such compensation for the period commencing on the date of the giving of such notice. Each Bank shall use its best efforts to avoid the need to give a notice under paragraph 2.11 or 2.14 by designating a different Applicable Lending Office outside of the United States if such designation would avoid the need to give such notice and will not, in the sole opinion of such Bank, be disadvantageous to such Bank. In the event the Company receives such notice or is otherwise required under the provisions of paragraphs 2.11 or 2.14 to make payments in a material amount to any Bank, the Company may, so long as no Event of Default shall have occurred and be continuing, elect to substitute such Bank as a party to this Agreement; provided that, concurrently with such substitution, (i) the Company shall pay that Bank all principal, interest and fees and other amounts (including without limitation, amounts, if any, owed under paragraph 2.11, 2.12 or 2.14) owed to such Bank through such date of termination, (ii) another commercial bank satisfactory to the Company and the Agent (or if the Agent is also the Bank to be substituted, the successor Agent) shall agree, as of such date, to become a Bank (whether by assignment or amendment) for all purposes under this Agreement and to assume all obligations of the Bank to be substituted as of such date, and (iii) all documents, supporting materials and fees necessary, in the judgment of the Agent (or if the Agent is also the Bank to be substituted, the successor Agent) to evidence the substitution of such Bank shall have been received and approved by the Agent as of such date. 2.17 Regulatory Approvals. (a) Anything herein to the contrary notwithstanding, if the Company has not received all required approvals in connection with the Tranche B Loans from the VPSB on or prior to the Effective Date or within 120 days after the Effective Date, all Loans made hereunder shall be deemed to be Tranche A Loans and the Tranche A Loan Aggregate Commitments shall be equal to the amount of the Total Commitments as set forth on Exhibit A. (b) Anything herein to the contrary notwithstanding, if the Company has not received all required approvals in connection with the Tranche B Loans from the VPSB on or prior to the Effective Date but receives such approvals on or prior to that date which is 120 days from the Effective Date, from and after the tenth (10th) Business Day after receipt by the Banks of such approvals, paragraph 2.17(a) shall no longer apply and the Tranche A Loan Aggregate Commitments and the Tranche B Loan Aggregate Commitments shall be as set forth on Exhibit A. 2.18 Increase of Commitments. So long as the Company has received all required approvals in connection with the Tranche B Loans, the Company may, at its option, obtain Loans from any bank or other institutional lender (including a Bank) so long as the Aggregate Tranche A Commitments shall not at any time exceed $20,000,000 and the Aggregate Tranche B Commitments shall not at any time exceed $40,000,000 and that as a condition precedent to any such Loans, any such bank or other institutional lender that is not a Bank (i) shall be subject to the prior written approval of the Agent, which approval shall not be unreasonably withheld or delayed, and (ii) shall become a party to this Agreement as a "Bank", as defined herein, and thereafter shall be deemed to be a "Bank" for purposes of this Agreement. Each such Loan shall be made pro rata as between Tranche A Loans and Tranche B Loans such that one-third (1/3) shall be applied as a Tranche A Loan and two-thirds (2/3) shall be applied as a Tranche B Loan. 3. FEES; PAYMENTS. 3.1 Facility Fee. The Company agrees to pay to the Agent for the account of the Banks a fee (the "Facility Fee") equal to the rate per annum determined by reference to Exhibit B hereto based upon the Debt Rating of the Company multiplied by the Aggregate Commitment, which Facility Fee shall be payable in arrears on the last day of each March, June, September and December of each year, commencing on the first such date following the Effective Date and continuing until the later of the applicable Termination Date or the date all sums due hereunder and under the Tranche A Notes or Tranche B Notes, as the case may be, are paid in full; provided that if the Company has no Debt Rating, the Facility Fee shall be determined at the highest rate per annum for the relevant period set forth on Exhibit B. 3.2 Fees of the Agent. The Company agrees to pay to the Agent for its own account, such fees (the "Agent's Fees") for its services hereunder in such amounts and at such times as previously agreed upon by the Company and the Agent. 3.3 Computation of Interest and Fees. (a) Interest in respect of Alternate Base Rate Loans and all other fees payable by the Company hereunder shall be calculated on the basis of a 365-day year (or 366-day year in a leap year) for the actual number of days elapsed. Interest in respect of Eurodollar Rate Loans and Bid Rate Loans and the Facility Fee shall be calculated on the basis of a 360-day year for the actual number of days elapsed. Any change in the interest rate on a Loan resulting from a change in the Alternate Base Rate or Eurodollar Rate shall become effective as of the opening of business on the day on which such change shall become effective. The Agent shall, as soon as practicable, notify the Company and the Banks of the effective date and the amount of each such change but failure of the Agent to do so shall not in any manner affect the obligation of the Company to pay interest on the Loans in the amounts and on the dates required. (b) Each determination of the Alternate Base Rate or the Eurodollar Rate by the Agent pursuant to any provision of this Agreement shall be presumed to be correct absent manifest error. 3.4 Pro Rata Treatment and Application of Principal Payments. Each Borrowing by the Company from the Banks, any conversion of Loans from one Type to the same or another Type, and any reduction of the Aggregate Commitments of the Banks, shall be made pro rata according to the Commitment Percentage of each Bank. All payments (including prepayments) to be made by the Company on account of principal and interest on Loans comprising the same Borrowing shall be made pro rata according to the outstanding principal amount of each Bank's Loans. All payments by the Company on all Loans shall be made without set-off or counterclaim and shall be made prior to 12:00 noon, Boston time, on the date such payment is due, to the Agent for the account of the Banks at the Agent's office specified in paragraph 11.1, in each case in lawful money of the United States of America and in immediately available funds, and, as between the Company and the Banks, any payment by the Company to the Agent for the account of the Banks shall be deemed to be payment by the Company to the Banks; provided, however, that any payment received by the Agent on any Business Day after 12:00 noon shall be deemed to have been received on the immediately succeeding Business Day. The Agent shall distribute such payments to the Banks promptly upon receipt in like funds as received. If any payment hereunder or on any Note becomes due and payable on a day other than a Business Day, the maturity thereof shall be extended to the next succeeding Business Day (unless, in the case of Eurodollar Loans, the result of such extension would be to extend such payment into another calendar month, in which event such payment shall be made on the immediately preceding Business Day) and, with respect to payments of principal, interest thereon shall be payable at the then applicable rate during such extension. 4. REPRESENTATIONS AND WARRANTIES. In order to induce the Agent and the Banks to enter into this Agreement, the Company hereby represents and warrants to the Agent and to each Bank that: 4.1 Subsidiary. The Company has the Subsidiaries set forth in Exhibit I. The shares of each corporate Subsidiary owned by the Company are duly authorized, validly issued, fully paid and non-assessable and are owned free and clear of any Liens, except Liens permitted by paragraph 8.2. 4.2 Corporate Existence and Power. 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 its Property and to carry on its business as now conducted. The Company is in good standing and duly qualified to do business in each jurisdiction in which the failure to so qualify would have a Material Adverse Effect. 4.3 Corporate Authority. The Company has full corporate power and authority to enter into, execute, deliver and carry out the terms of this Agreement and to make the borrowings contemplated hereby, to execute, deliver and carry out the terms of the Notes and to incur the obligations provided for herein and therein, all of which have been duly authorized by all necessary corporate action on its part and are in full compliance with its Charter and By-Laws. No consent or approval of, or exemption by, shareholders or any Governmental Body is required to authorize, or is required in connection with the execution, delivery and performance of, this Agreement and the Notes, or is required as a condition to the validity or enforceability of this Agreement and the Notes, except for the approval of the VPSB referred to in paragraph 5.6. 4.4 Binding Agreement. This Agreement constitutes, and the Notes, when issued and delivered pursuant hereto for value received, will constitute, the valid and legally binding obligations of the Company enforceable against the Company in accordance with their respective terms, except as such enforceability may be limited by equitable principles and by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the rights of creditors generally. 4.5 Litigation. Except for the matters set forth in the Designated Documents, and except for the retail rate increase request filed by the Company with the VPSB on June 16, 1997, there are no actions, suits or arbitration proceedings (whether or not purportedly on behalf of the Company or any Subsidiary) pending or to the knowledge of the Company threatened against the Company or any Subsidiary, or maintained by the Company or any Subsidiary, in law or in equity before any Governmental Body which, if decided adversely to the Company or such Subsidiary, would have a Material Adverse Effect upon the Company after giving effect to reserves reflected in the Financial Statements or the footnotes thereto. There are no proceedings pending or to the knowledge of the Company threatened against the Company which call into question the validity and enforceability of this Agreement or the Notes. 4.6 Non Conflicting Agreements. Except for the matters set forth in the Designated Documents, the Company is not in default under any agreement to which it is a party or by which it or any of its Property is bound, the effect of which would have a Material Adverse Effect upon the Company. No provision of the Charter or By-Laws of the Company, and no provision of any existing mortgage, indenture contract, agreement, statute (including, without limitation, any applicable usury or similar law), rule, regulation, judgment, decree or order binding on the Company or any Subsidiary could in any way prevent the execution, delivery or carrying out of the terms of this Agreement and the Notes, and the taking of any such action will not constitute a default under, or result in the creation or imposition of, or obligation to create, any Lien not permitted by paragraph 8.2 upon the Property of the Company pursuant to the terms of any such mortgage, indenture, contract or agreement. 4.7 Taxes. The Company has filed or caused to be filed all tax returns material to the Company required by law to be filed, and has paid, or has made adequate provision for the payment of, all taxes shown to be due and payable on said returns or in any assessments made against it. No tax liens have been filed and no claims are being asserted with respect to such taxes which are required by GAAP to be reflected in the Financial Statements and are not so reflected therein. The Internal Revenue Service has audited and settled upon, or the applicable statutes of limitation have run upon, all Federal income tax returns of the Company through the tax year ended December 31, 1990, and, to the extent required by GAAP, the results of all such audits are reflected in the Financial Statements. The charges, accruals and reserves on the books of the Company with respect to all taxes are considered by the management of the Company to be adequate, and the Company knows of no unpaid assessment which is due and payable against the Company which would have a Material Adverse Effect, except such thereof as are being contested in good faith and by appropriate proceedings diligently conducted and for which adequate reserves have been set aside in accordance with GAAP. 4.8 Financial Statements. The Company heretofore delivered to each Bank (i) copies of the Consolidated Balance Sheets at December 31, 1996 and December 31, 1995, and the related Consolidated Statements of Income, Cash Flows and Capitalization Data for the years ended December 31, 1996, 1995 and 1994 and (ii) copies of the Consolidated quarterly reports of the Company and its Subsidiaries as of June 30, 1996, September 30, 1996 and March 31, 1997, each containing a Consolidated balance sheet and Consolidated statements of income and cash flows of the Company and its Subsidiaries (the statements in (i) and (ii) above being sometimes referred to herein as the "Financial Statements"). The financial statements set forth in (i) above were audited and reported on by the Accountants on January 31, 1997, and the financial statements set forth in (ii) above were prepared by the Company. The Financial Statements fairly present the Consolidated financial condition and the Consolidated results of operations of the Company and its Subsidiaries as of the dates and for the periods indicated therein, and have been prepared in conformity with GAAP. Except (a) as reflected in the financial statements specified in (i) above or in the footnotes thereto, or (b) as otherwise disclosed to the Banks in a writing specifically referring to this paragraph 4.8, neither the Company nor any Subsidiary has any obligation or liability of any kind (whether fixed, accrued, contingent, unmatured or otherwise) which is material to the Company and its Subsidiaries on a Consolidated basis and which, in accordance with GAAP, should have been shown on such financial statements and were not, other than those incurred in the ordinary course of their respective businesses since December 31, 1996. Since December 31, 1996, each of the Company and each Subsidiary has conducted its business only in the ordinary course, and as of the Effective Date there has been no adverse change in the financial condition, Property, operations or prospects of the Company and its Subsidiaries which is material to the Company and its Subsidiaries on a Consolidated basis. 4.9 Compliance with Applicable Laws. Except as set forth in the Designated Documents, neither the Company nor any Subsidiary is in default with respect to any judgment, order, writ, injunction, decree or decision of any Governmental Body applicable to the Company or such Subsidiary which default would have a Material Adverse Effect upon the Company. Except as set forth in the Designated Documents, each of the Company and each Subsidiary is complying in all material respects with all applicable material statutes and regulations of all Governmental Bodies, including ERISA and all Environmental Laws, a violation of which would have a Material Adverse Effect upon the Company. 4.10 Governmental Regulations. The Company is not an "Investment Company" as such term is defined in the Investment Company Act of 1940, as amended. 4.11 Property. The Company has good and marketable title to all of its Property, title to which is material to the Company, subject to no Lien, except as permitted by paragraph 8.2. 4.12 Federal Reserve Regulations. The Company is not engaged principally, or as one of its important activities, in the business of extending credit for the purpose of purchasing or carrying any margin stock within the meaning of Regulation U of the Board of Governors of the Federal Reserve System, as amended. No part of the proceeds of the Loans will be used (i) to purchase or carry any such margin stock, (ii) to extend credit to others for the purpose of purchasing or carrying any margin stock, (iii) for a purpose which violates the provisions of Regulations G, U and X of the Board of Governors of the Federal Reserve System, as amended, or (iv) for a purpose which violates any other applicable law, rule or regulation of any Governmental Body. Not more than 25% of the value of the aggregate of the assets of the Company subject to the provisions of this Agreement is represented by margin stock within the meaning of said Regulation U. 4.13 No Misrepresentation. No representation or warranty contained herein and no certificate or report furnished or to be furnished by the Company in connection with the transactions contemplated hereby, contains or will contain a misstatement of material fact, or omits or will omit to state a material fact required to be stated in order to make the statements herein or therein contained not misleading in the light of the circumstances under which made. 4.14 Pension Plans. Each Plan, and to the best of the Company's knowledge each Multiemployer Plan, established or maintained by the Company and its Subsidiaries, is in material compliance with the applicable provisions of ERISA and the Code, and the Company and its Subsidiaries have filed all material reports required to be filed with respect to each such Plan by ERISA and the Code. The Company and its Subsidiaries have met all requirements with respect to funding the Plans imposed by ERISA or the Code. Since the effective date of ERISA, there have not been, nor are there now existing, any events or conditions which would permit any Plan and to the best of the Company's knowledge any Multiemployer Plan to be terminated under circumstances which would cause the lien provided under Section 4068 of ERISA to attach to the Property of the Company or any of its Subsidiaries. Since the effective date of ERISA, no reportable event as defined in Title IV of ERISA, which constitutes grounds for the termination of any Plan and to the best of the Company's knowledge any Multiemployer Plan, has occurred and no Plan or any related trust has been terminated in whole or in part which would have a Material Adverse Effect. 4.15 Public Utility Holding Company Act. The Company is a public utility holding company under the Public Utility Holding Company Act of 1935, as amended, (the "Public Utility Act") and each of its Subsidiaries are "subsidiaries" of a "holding company" under the Public Utility Act. The Company and its Subsidiaries have filed an exemption statement under Section 3(a)(2) of the Public Utility Act and is therefore exempt from the provisions of the Public Utility Act, except for Section 9(a)(2) thereof (which prohibits the acquisition of securities of certain other utility companies without approval of the Securities and Exchange Commission). 4.16 Approvals. Except for the regulatory approval of the VPSB with respect to the Tranche B Loan, the Company has obtained all authorizations, approvals or consents of and made all filings or registrations with all Governmental Bodies as are necessary to be obtained or made by the Company for the execution, delivery or performance by the Company of this Agreement or the Notes and all such authorizations, approvals and consents are in full force and effect. 4.17 Regulatory Investigations. The VPSB is not currently conducting and has not conducted within the five (5) year period immediately preceding the date hereof, an investigation of the Company or any of its Subsidiaries, other than an investigation conducted by the VPSB in its routine general supervisory role of the Company as a public utility company. 4.18 No Adverse Change or Event. Since December 31, 1996, no change in the business, assets, liabilities, condition (financial or otherwise), results of operations or business prospects of the Company has occurred, and no event has occurred or failed to occur, that has had or would reasonably be expected to have, either alone or in conjunction with all other such changes, events and failures, a Material Adverse Effect on (a) the Company or (b) any Loan Document. Such an adverse change may have occurred, and such an event may have occurred or failed to occur, at any particular time notwithstanding the fact that at such time no default or Event of Default shall have occurred and be continuing. 5. CONDITIONS OF BORROWING -- FIRST BORROWING. In addition to the requirements set forth in paragraph 6, the obligations of the Banks to make the first Loans on the initial Borrowing Date are subject to the fulfillment of the following conditions precedent: 5.1 Evidence of Corporate Action. The Agent shall have received a certificate, dated the EffectiveDate, of the Secretary or an Assistant Secretary of the Company (i) attaching a true and complete copy of the resolutions of its Board of Directors and of all documents evidencing other necessary corporate action (in form and substance satisfactory to the Agent and to Special Counsel) taken by the Company to authorize this Agreement, the Notes and the borrowings hereunder, (ii) attaching a true and complete copy of the Charter and the By-Laws of the Company, and (iii) setting forth the incumbency of the officer or officers of the Company who sign this Agreement and the Notes, including therein a signature specimen of such officer or officers, together with a certificate of the Secretary of State of Vermont as to the good standing of, and the payment of franchise taxes therein by, the Company, together with such other documents as the Agent or Special Counsel shall reasonably require. 5.2 Notes. The Agent shall have received and be in possession of the Notes executed by the duly authorized officer or officers of the Company. 5.3 Approval of Special Counsel. All legal matters incident to the making of the first Loans on the initial Borrowing Date shall be satisfactory to Special Counsel, and the Agent shall have received from Special Counsel an opinion addressed to the Banks and to the Agent, dated the Effective Date, substantially in the form of Exhibit J. 5.4 Opinion of Counsel to the Company. The Agent shall have received the opinion of Sheehey Brue Gray & Furlong P.C., counsel to the Company, or its successor, if any, addressed to the Banks and to the Agent, dated the Effective Date, substantially in the form of Exhibit K. 5.5 Fees. The fees of Special Counsel shall have been paid. 5.6 VPSB Approval. Subject to paragraph 2.17, the Agent shall have received true copies for each Bank of the order or orders of the VPSB approving this Agreement in the form executed and delivered to the Agent by the Company and each Bank with no material changes to this Agreement. Such approval shall be final and shall no longer be subject to appeal, shall be in full force and effect, shall be in form and substance satisfactory to the Agent and Special Counsel. In addition, the Agent shall have received a certificate of the Secretary of the Company to the effect that no other consents, approvals or licenses are necessary in connection with the borrowings hereunder. 6. CONDITIONS OF BORROWING -- ALL BORROWINGS. The obligations of the Banks to make all Loans hereunder on each Borrowing Date are subject to the fulfillment of the following conditions precedent: 6.1 Compliance. On each Borrowing Date, and after giving effect to the Loans to be made on such date (a) the Company and each Subsidiary shall be in compliance with all of the terms, covenants and conditions of this Agreement, (b) there shall exist no Event of Default, (c) the representations and warranties contained in this Agreement, or otherwise in writing made by the Company in connection herewith shall be true and correct in all material respects with the same effect as though such representations and warranties had been made on such Borrowing Date (except such thereof as specifically refer to an earlier date) and (d) no event shall have occurred or failed to occur, that has had or would reasonably be expected to have, either alone or in conjunction with all other such events and failures, a Material Adverse Effect since the date of the last Borrowing Date, and the Agent shall have received a certificate in the form of Exhibit C attached hereto (with respect to Pro Rata Loans) or in the form of Exhibit F attached hereto (with respect to Bid Rate Loans), dated the Borrowing Date, and signed on behalf of the Company by a duly authorized officer of the Company, to the same effect as all of the foregoing matters. 6.2 Loan Closings. All documents required by paragraphs 5 and 6 of this Agreement to be executed and/or delivered to the Agent on or before the applicable Borrowing Date shall have been executed and delivered at the office of the Agent set forth in paragraph 11 on or before such Borrowing Date. 6.3 Approval of Counsel. All legal matters in connection with the making of each Loan on Borrowing Date shall be reasonably satisfactory to such counsel with whom the Agent may deem it necessary to consult. 6.4 Borrowing Request. The Agent shall have received a Borrowing Request. 6.5 Other Documents. The Agent shall have received such other documents as the Agent shall reasonably require. 7. AFFIRMATIVE COVENANTS. The Company covenants and agrees that on and after the Effective Date until the later of the termination of the Commitments or the payment in full of the Notes and the performance by the Company of all other obligations of the Company hereunder, unless the Agent shall otherwise consent in writing as provided in paragraph 13, the Company will: 7.1 Corporate Existence. Maintain its corporate existence, in good standing in the jurisdiction of its incorporation or organization and in each other jurisdiction in which the character of the Property owned or leased by it therein or the transaction of its business makes such qualification necessary, except as otherwise expressly permitted hereunder. 7.2 Taxes. Pay and discharge when due all taxes, assessments and governmental charges and levies upon the Company, and upon the income, profits and Property of the Company, which if unpaid would have a Material Adverse Effect or become a Lien not permitted under paragraph 8.2, unless and to the extent only that such taxes, assessments, charges and levies, (a) shall be contested in good faith and by appropriate proceedings diligently conducted by the Company, provided that such reserve or other appropriate provision, if any, as shall be required in accordance with GAAP shall have been made therefor, or (b) are not in the aggregate material to the financial condition, Property or operations of the Company. 7.3 Insurance. Maintain insurance with financially sound insurance carriers on such of its Property in such amounts, subject to such deductibles and self-insured amounts and against such risks as is customarily maintained by similar businesses, including, without limitation, public liability, workers' compensation and employee fidelity insurance. 7.4 Payment of Indebtedness and Performance of Obligations. Pay and discharge promptly as and when due all lawful indebtedness, obligations and claims for labor, materials and supplies or otherwise (including, without limitation, Funded Debt) which, if unpaid, would (a) have a Material Adverse Effect, or (b) become a Lien not permitted by paragraph 8.2, provided that the Company shall not be required to pay and discharge or cause to be paid and discharged any such indebtedness, obligation or claim so long as the validity thereof shall be contested in good faith and by appropriate proceedings diligently conducted by the Company, and further provided that such reserve or other appropriate provision as shall be required in accordance with GAAP shall have been made therefor. 7.5 Observance of Legal Requirements: ERISA. Observe and comply, and cause each Subsidiary to observe and comply, in all material respects with all laws (including ERISA and all Environmental Laws), ordinances, orders, judgments, rules, regulations, certifications, franchises, permits, licenses, directions and requirements of all Governmental Bodies, which now or at any time hereafter may be applicable to the Company or such Subsidiary, a violation of which would have a Material Adverse Effect upon the Company, except such thereof as shall be contested in good faith and by appropriate proceedings diligently conducted by the Company or such Subsidiary, provided that such reserve or other appropriate provision, if any, as shall be required in accordance with GAAP shall have been made therefor. 7.6 Financial Statements and Other Information. Furnish to the Agent and the Banks: (a) as soon as available, but in no event more than 90 days after the close of each fiscal year of the Company, copies of its audited Consolidated Balance Sheet and the related audited Consolidated Statements of Income, Shareholders' Equity and Changes in Financial Position for such fiscal year setting forth in each case in comparative form the corresponding figures for the preceding fiscal year all reported by the Accountants which report shall state that said financial statements fairly present the financial position and results of operations of the Company as at the end of and for such fiscal year except as specifically stated therein, as of and through the end of such fiscal year, prepared in accordance with GAAP and accompanied by a report with respect thereto of the Accountants, together with a certificate signed on behalf of the Company by the principal financial officer thereof to the effect that having read this Agreement, and based upon an examination which in the opinion of such officer was sufficient to enable such officer to make an informed statement, (x) such statements fairly present the financial position and results of the operations of the Company and its Subsidiaries on a Consolidated basis to the best of such officer's knowledge, and (y) nothing came to such officer's attention which caused such officer to believe that an Event of Default has occurred, or if an Event of Default has occurred, stating the facts with respect thereto and whether the same has been cured prior to the date of such certificate, and, if not, what action is proposed to be taken with respect thereto; (b) as soon as available, but in no event more than 45 days after the close of each quarter (except the last quarter) of each fiscal year of the Company a Consolidated Balance Sheet and Consolidated Statements of Income and Changes in Financial Position of the Company and its Subsidiaries as of and through the end of such quarter, together with a certificate signed on behalf of the Company by the principal financial officer thereof to the effect that having read this Agreement, and based upon an examination which in the opinion of such officer was sufficient to enable such officer to make an informed statement, (x) such statements fairly present the financial position and results of the operations of the Company and its Subsidiaries on a Consolidated basis to the best of such officer's knowledge, and (y) nothing came to such officer's attention which caused such officer to believe that an Event of Default has occurred, or if an Event of Default has occurred, stating the facts with respect thereto and whether the same has been cured prior to the date of such certificate, and, if not, what action is proposed to be taken with respect thereto; (c) prompt notice if: (x) any obligation of the Company (other than its obligations under this Agreement or the Notes) for a payment in excess of $500,000 of any Funded Debt is not paid when due or within any grace period for the payment thereof or is declared or shall become due and payable prior to its stated maturity, or (y) to the knowledge of any Authorized Signatory of the Company there shall occur and be continuing an event which constitutes, or which with the giving of notice or the lapse of time, or both, would constitute an event of default under any agreement with respect to Funded Debt of the Company (including this Agreement); (d) prompt written notice in the event that (i) the Company or any Subsidiary shall fail to make any payments when due and payable under any Plan or Multiemployer Plan, or (ii) the Company or any Subsidiary shall receive notice from the Internal Revenue Service or the Department of Labor that the Company or such Subsidiary shall have failed to meet the minimum funding requirements of any Plan or Multiemployer Plan, including therewith a copy of such notice; (e) promptly upon becoming available, copies of all regular, periodic or special reports or other material which may be filed with or delivered by the Company to the Securities and Exchange Commission, or any other Governmental Body succeeding to the functions thereof; (f) prompt written notice in the event the Debt Rating of the Company shall change or the Company shall have no Debt Rating; (g) prompt written notice and a copy of any Environmental Notice excluding, however, any such Environmental Notices relating to the Pine Street Marsh site in Burlington, Vermont (the "Pine Street Site") if the effect of such Environmental Notice (i) does not change the status of the Pine Street Site as it exists as of the date hereof as it relates to the Company and (ii) would not have a Material Adverse Effect; (h) a certificate of the Company, dated the date of each such annual report or quarterly report required pursuant to paragraphs 7.6(a) and (b), and signed on behalf of the Company by the President, chief financial officer, chief accounting officer or Treasurer, which sets forth all relevant calculations needed to determine whether the Company is in compliance with paragraph 8.8 hereof, which calculations are based on the most recent fiscal quarter required to be supplied pursuant to paragraphs 7.6(a) and (b); and (i) such other information and reports relating to the affairs of the Company and its Subsidiaries, as the Agent or any Bank at any time or from time to time may reasonably request. 7.7 Inspection. Permit representatives of the Agent or any Bank to visit the offices of the Company, to examine the books and records thereof and to make copies or extracts therefrom, and to discuss the affairs of the Company with the officers, including the financial officers, thereof, at reasonable times, at reasonable intervals and with reasonable prior notice. 8. NEGATIVE COVENANTS. The Company covenants and agrees that from the Effective Date until the later of the termination of the Commitments or the payment in full of the Notes and the performance by the Company of all other obligations of the Company hereunder, unless the Agent shall otherwise consent in writing as provided in paragraph 13, the Company will not: 8.1 Funded Debt. Create, incur, assume, guarantee or suffer to exist any Short-Term Funded Debt (excluding the Loans) in excess of $8,000,000, individually or in the aggregate, excluding, however, the Company's payment obligations meeting the capital lease accounting requirements under SFAS 13 pursuant to certain thirty-year support agreements among the Company, VELCO and other New England Power Pool members and Hydro-Quebec in connection with the construction of the second phase of the interconnection between the New England electric systems and that of Hydro-Quebec, or unless the same is permitted or allowed in connection with the provisions of the First Mortgage Bonds specifically relating to restrictions on Funded Debt, which provisions are incorporated by reference herein as if fully set forth herein. 8.2 Liens. Create, incur, assume or suffer to exist any Lien upon any of its Property, whether now owned or hereafter acquired, to secure any indebtedness or other obligation unless the same is permitted or allowed in connection with the First Mortgage Bonds, the provisions of which specifically relating to restrictions on Liens are incorporated by reference herein as if fully set forth herein, and except for the following: (i) materialmens', mechanics', suppliers', tax and other like liens arising in the ordinary course of business securing obligations which are not overdue, or if overdue are being contested in good faith by appropriate proceedings and then only to the extent that the Company has set aside on its books adequate reserves therefor in accordance with GAAP and such contest does not have a Material Adverse Effect; liens arising in connection with workers' compensation, unemployment insurance, and appeal and release bonds, and other liens incident to the conduct of business or the operation of property and assets and not incurred in connection with the obtaining of any advance or credit and which Liens do not, or would not, have a Material Adverse Effect; (ii) Liens arising out of judgments or awards against the Company with respect to which at the time an appeal or proceeding for review is being prosecuted in good faith and with respect to which there shall have been secured a stay of execution pending such appeal or preceding for review and which Liens do not, or would not, have a Material Adverse Effect; (iii) Liens upon Property of the Company to secure debt or other obligations owing by the Company to the United States, the State of Vermont or any agencies or instrumentalities of either thereof in connection with the financing or other furnishing of the respective property by the respective government, agency or instrumentality and which liens do not or would not, have a Material Adverse Effect; (iv) Liens arising by reason of the terms of contracts to which the Company is a party relative to the joint ownership of generation and/or transmission facilities and which Liens do not, or would not, have a Material Adverse Effect; and (v) any other Liens not in excess of $500,000 in the aggregate. 8.3 Mergers and Consolidations. Except with the prior written consent of the Majority Banks, consolidate with or merge into any other Person. 8.4 Sale of Property. Except with the prior written consent of the Majority Banks, sell, lease or otherwise dispose of any significant part of its Property (including, without limitation, the right to receive income), except (i) in the ordinary course of business and (ii) obsolete or worn out Property which is no longer used or useful to the Company. 8.5 Dividends; Distributions. Declare or pay any dividends (other than dividends payable in shares of common stock of the Company) on, or make any other distribution in respect of, any shares of any class of capital stock of the Company, or apply any of its property or assets to, or set aside any sum for, the payment, purchase, redemption or other acquisition or retirement of, any shares of any class of capital stock of the Company, if, after giving effect to such dividend or other distribution, the result of such dividend or other distribution would have a Material Adverse Effect. 8.6 Guaranties. Except as set forth in the Financial Statements, the Company shall not guarantee, endorse or otherwise in any way become or be responsible for obligations of any other Person (including without limitation any officer, director, employee or stockholder of the Company) in excess of $500,000 in the aggregate, whether by agreement to purchase the indebtedness of any other Person or through the purchase of goods, supplies or services, or maintenance of working capital or other balance sheet covenants or conditions, or by way of stock purchase, capital contribution, advance or loan for the purpose of paying or discharging any indebtedness or obligation of such other Person or otherwise, unless the same is permitted or allowed in connection with the provisions of the First Mortgage Bonds specifically relating to the same, which provisions are incorporated by reference herein as if fully set forth herein. 8.7 Amendment of Charter or By-Laws. The Company shall not amend its Charter or By-Laws or change its fiscal year end if the result of any such amendment or change in its fiscal year end would adversely affect or otherwise impair the rights and remedies of the Banks hereunder or under any other Loan Document. 8.8 Funded Debt to Capitalization Test. Permit the total amount of Funded Debt to exceed fifty-five percent (55%) of Total Capitalization. 9. EVENTS OF DEFAULT. The following shall each constitute an Event of Default hereunder: (a) the failure of the Company to pay any amounts (i) of principal due hereunder or under the Notes when such amounts are due or declared due, or (ii) any other amounts, including interest and fees, due hereunder or under the Notes within five (5) Business Days after such amounts are due or declared due, in any case whether at stated maturity by acceleration or otherwise; (b) the failure of the Company to observe or perform any covenant or agreement contained in paragraph 8 and, with respect to paragraph 8.2 only, such failure shall have continued unremedied for a period of five (5) Business Days after the Company knows, or should have known, of such default; or (c) the failure of the Company to observe or perform any other term, covenant, or agreement contained in this Agreement and such failure shall have continued unremedied for a period of 10 days after written notice, specifying such failure and requiring it to be remedied, shall have been given to the Company by the Agent; or (d) any material representation or warranty made herein or in any certificate, report, or notice delivered or to be delivered by the Company pursuant hereto, shall prove to have been incorrect in any material respect when made; or (e) if the Company shall default (as principal or guarantor, surety or other obligor) in the payment of any principal of, or premium, if any, or interest on any Funded Debt in excess of $1,000,000 (other than its obligations under this Agreement and the Notes), or with respect to any of the terms of any evidence of such indebtedness or of any agreement relating thereto, and such default shall entitle the holder of such indebtedness to accelerate the maturity thereof, unless, in the case of any non-payment default, such default has been affirmatively waived by or on behalf of the holder of such indebtedness; or (f) the Company shall (i) make an assignment for the benefit of creditors, (ii) admit in writing its inability to pay its debts as they become due or generally fail to pay its debts as they become due, (iii) file a voluntary petition in bankruptcy, (iv) become insolvent (however such insolvency shall be evidenced), (v) file any petition or answer seeking for itself any reorganization, arrangement, composition, readjustment of debt, liquidation or dissolution or similar relief under any present or future statute, law or regulation of any jurisdiction, (vi) petition or apply to any tribunal for any trustee, receiver, custodian, liquidate or fiscal agent for any substantial part of its Property, (vii) be the subject of any proceeding referred to in clause (vi) above or an involuntary bankruptcy petition filed against it which remains undischarged for a period of 60 days, (viii) file any answer admitting or not contesting the material allegations of any such petition filed against it, or of any order, judgment or decree approving such petition in any such proceeding, (ix) seek, approve, consent to, or acquiesce in any such proceeding, or in the appointment of any trustee, receiver, custodian, liquidate, or fiscal agent for it, or any substantial part of its Property, or an order is entered appointing any such trustee, receiver, custodian, liquidator or fiscal agent and such order remains in effect for 60 days, (x) take any formal action for the purpose of effecting any of the foregoing or looking to the liquidation or dissolution of the Company or (xi) suspend or discontinue its business (except as otherwise expressly permitted herein); or (g) an order for relief is entered under the United States bankruptcy laws or any other decree or order is entered by a court having jurisdiction (i) adjudging the Company a bankrupt or insolvent, or (ii) approving as properly filed a petition seeking reorganization, liquidation, arrangement, adjustment or composition of or in respect of the Company under the United States bankruptcy laws or any other applicable Federal or state law, or (iii) appointing a trustee, receiver, custodian, liquidator, or fiscal agent (or other similar official) of the Company or of any substantial part of its Property, or (iv) ordering the winding up or liquidation of the affairs of the Company; or (h) judgments or decrees against the Company in excess of $3,000,000 (unless such judgment or decree is insured and the insurer has admitted liability) or for an aggregate amount in excess of $6,000,000 (whether or not insured) shall remain unpaid, unstayed on appeal, undischarged, unbonded or undismissed for a period of 30 days; or (i) any fact or circumstance, including any Reportable Event as defined in Title IV of ERISA, at a time when there exists an underfunding of the Plan in an amount in excess of $500,000, which constitutes grounds for the termination of any Plan by the PBGC or for the appointment of a trustee to administer any Plan, shall have occurred and be continuing for a period of 30 days; or (j) the occurrence of a Material Adverse Change. Upon the occurrence and during the continuance of an Event of Default under this paragraph 9, the Agent, upon the request of the Majority Banks, shall notify the Company that the Commitments have been terminated and that the Notes, all accrued interest thereon and all other amounts owing under this Agreement are immediately due and payable, provided that upon the occurrence of an event specified in paragraphs 9(f) or 9(g), the Commitments shall automatically terminate and the Notes (with accrued interest thereon) and all other amounts owing under this Agreement shall become immediately due and payable without notice to the Company. Except for any notice expressly provided for in this paragraph 9, the Company hereby expressly waives any presentment, demand, protest, notice of protest or other notice of any kind. The Company hereby further expressly waives and covenants not to assert any appeasement, valuation, stay, extension, redemption or similar laws, now or at any time hereafter in force which might delay, prevent or otherwise impede the performance or enforcement of this Agreement or the Notes. In the event that the unpaid principal balance of the Notes, all accrued interest thereon and all other amounts owing under this Agreement shall have been declared due and payable pursuant to the provisions of this paragraph 9, the Agent may, and, upon (i) the request of the Majority Banks and (ii) the providing by all of the Banks to the Agent of an indemnity in form and substance satisfactory to the Agent in accordance with paragraph 10.3 against all expenses and liabilities shall, proceed to enforce the rights of the holders of the Notes by suit in equity, action at law and/or other appropriate proceedings, whether for payment or the specific performance of any covenant or agreement contained in this Agreement or the Notes. The Agent shall be justified in failing or refusing to take any action hereunder and under the Notes unless it shall be indemnified to its satisfaction by the Banks pro rata according to the aggregate outstanding principal balance of the Notes against any and all liabilities and expenses which may be incurred by it by reason of taking or continuing to take any such action. In the event that the Agent, having been so indemnified, or not being indemnified to its satisfaction, shall fail or refuse so to proceed, any Bank shall be entitled to take such action as it shall deem appropriate to enforce its rights hereunder and under its Notes, with the consent of the Banks, it being understood and intended that no one or more of the holders of the Notes shall have any right to enforce payment thereof except as provided in this paragraph 9 and in paragraph 12. If an Event of Default shall have occurred and shall be continuing, the Agent may, and at the request of the Majority Banks shall, notify the Company (by telephone or otherwise) that all or such lesser amount as the Majority Banks shall designate of the outstanding Eurodollar Rate Loans automatically shall be converted to Alternate Base Rate Loans, in which event such Eurodollar Rate Loans automatically shall be converted to Alternate Base Rate Loans on the date such notice is given. If such notice is given, notwithstanding anything in paragraph 2.7 to the contrary, no Alternate Base Rate Loan may be converted to a Eurodollar Rate Loan if an Event of Default has occurred and is continuing at the time the Company shall notify the Agent of its election to so convert. 10. THE AGENT. The Banks and the Agent agree by and among themselves that: 10.1 Appointment. FNB is hereby irrevocably designated the Agent by each of the other Banks to perform such duties on behalf of the other Banks and itself, and to have such powers, as are set forth herein and as are reasonably incidental thereto. 10.2 Delegation of Duties; Etc. The Agent may execute any duties and perform any powers hereunder by or through agents or employees, and shall be entitled to consult with legal counsel and any accountant or other professional selected by it. Any action taken or omitted to be taken or suffered in good faith by the Agent in accordance with the opinion of such counsel or accountant or other professional shall be full justification and protection to the Agent. 10.3 Indemnification. The Banks agree to indemnify the Agent in its capacity as such, to the extent not reimbursed by the Company, pro rata according to their respective Commitments as of the Effective Date, from and against any and all claims, liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Agent in any way relating to or arising out of this Agreement or the Notes or any action taken or omitted to be taken or suffered in good faith by the Agent hereunder or thereunder, provided that no Bank shall be liable for any portion of any of the foregoing items resulting from the gross negligence or willful misconduct of the Agent. Without limitation of the foregoing, each Bank agrees to reimburse the Agent promptly for its pro-rata share of any reasonable out-of-pocket expenses (including counsel fees) incurred by the Agent in connection with the preparation, execution, administration or enforcement of, or legal advice in respect of rights or responsibilities under, this Agreement and the Notes, to the extent that the Agent, having sought reimbursement for such expenses from the Company, is not promptly reimbursed by the Company. Any reference herein and in any document executed in connection herewith, to the Banks providing an indemnity in form and substance satisfactory to the Agent prior to the Agent taking any action hereunder shall be satisfied by the Banks executing an agreement confirming their agreement to promptly indemnify the Agent in accordance with this paragraph 10.3. 10.4 Exculpatory Provisions. Neither Agent, nor any of its officers, directors, employees or agents, shall be liable for any action taken or omitted to be taken or suffered by it or them hereunder or under the Notes, or in connection herewith or therewith, including without limitation any action taken or omitted to be taken in connection with any telephonic communication pursuant to paragraph 2.3(b) hereof, except that the Agent shall be liable for its own gross negligence or willful misconduct. The Agent shall not be liable in any manner for the effectiveness, enforceability, collectibility, genuineness, validity or the due execution of this Agreement or the Notes, or for the due authorization, authenticity or accuracy of the representations and warranties contained herein or in any other certificate, report, notice, consent, opinion, statement, or other document furnished or to be furnished hereunder, and the Agent shall be entitled to rely upon any of the foregoing believed by it to be genuine and correct and to have been signed and sent or made by the proper Person. The Agent shall not be under any duty or responsibility to any Bank to ascertain or to inquire into the performance or observance by the Company or any Subsidiary of any of the provisions hereof or of the Notes or of any document executed and delivered in connection herewith or therewith. Each other Bank expressly acknowledges that the Agent has not made any representations or warranties to it and that no act taken by the Agent shall be deemed to constitute any representation or warranty by the Agent to any other Bank. Each Bank acknowledges that it has taken and will continue to take such action and has made and will continue to make such investigation as it deems necessary to inform itself of the affairs of the Company and each Subsidiary, and each Bank acknowledges that it has made and will continue to make its own independent investigation of the creditworthiness and the business and operations of the Company and its Subsidiaries, and that, in entering into this Agreement, and in agreeing to make its Loans, it has not relied and will not rely upon any information or representations furnished or given by the Agent or any other Bank. 10.5 Agent in its Individual Capacity. With respect to its Loans and any renewals, extensions or deferrals of the payment thereof and any Note issued to or held by it, the Agent shall have the same rights and powers hereunder as any Bank, and may exercise the same as though it were not the Agent, and the term "Bank" or "Banks" shall, unless the context otherwise requires, include the Agent in its individual capacity. FNB and its affiliates may accept deposits from, lend money to, act as trustee or other fiduciary in connection with transactions involving, and otherwise engage in any business with the Company and its affiliates and any Person who may do business with or own securities of the Company or any affiliate of the Company, all as if FNB were not the Agent hereunder and without any obligation to account or report therefor to any Bank. 10.6 Knowledge of Default. It is expressly understood and agreed that the Agent shall be entitled to assume that no Event of Default has occurred and is continuing, unless the officers of the Agent who are responsible for matters concerning this Agreement shall have actual knowledge of such occurrence or shall have been notified in writing by a Bank that such Bank considers that an Event of Default has occurred and is continuing and specifying the nature thereof. In the event the Agent shall have acquired actual knowledge of any Event of Default, it shall promptly give notice thereof to the Banks. 10.7 Resignation of Agent. If at any time the Agent deems it advisable, in its sole discretion, it may submit to each of the Banks a written notification of its resignation as Agent under this Agreement, such resignation to be effective on the earlier to occur of (a) the forty-fifth (45th) day after the date of such notice or (b) the date upon which a successor Agent accepts its appointment as successor Agent. If the Agent resigns hereunder, the Company shall have the right to appoint, with the prior written approval of the Banks, which approval shall not be unreasonably withheld, a successor Agent hereunder, provided, however that upon the occurrence and during the continuance of an Event of Default, the Banks shall have the right to appoint such successor Agent hereunder. The successor Agent shall be a commercial bank or other financial institution organized under the laws of the United States of America or of any State thereof and having a combined capital and surplus of at least $100,000,000. Upon the acceptance of any appointment as Agent hereunder by a successor Agent, such successor Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the Agent hereunder, and the retiring Agent shall be discharged from any further duties and obligations under this Agreement. The Company and the Banks agree to execute such documents as shall be necessary to effect such appointment. After the retiring Agent's resignation or removal hereunder, the provisions of this paragraph 10 shall inure to its benefit as to any actions taken or omitted to be taken by it while the Agent under this Agreement. If at any time hereunder there shall not be a duly appointed and acting Agent, the Company agrees to make each payment due hereunder and under the Notes directly to the Banks entitled thereto. 10.8 Requests to the Agent. Whenever the Agent is authorized and empowered hereunder on behalf of the Banks to give any approval or consent, or to make any request, or to take any other action on behalf of the Banks, the Agent shall be required to give such approval or consent, or to make such request or to take such other action only when so requested in writing by the Majority Banks subject, however, to the provisions of paragraph 13. 11. NOTICES. 11.1 Manner of Delivery. Except as otherwise specifically provided herein, all notices and demands shall be in writing and shall be mailed by certified mail return receipt requested or sent by telegram, telecopy or telex or delivered in person, and all statements, reports, documents, consents, waivers, certificates and other papers required to be delivered hereunder shall be mailed by first-class mail or delivered in person, in each case to the respective parties to this Agreement as follows: if to the Company, to: Green Mountain Power Corporation 25 Green Mountain Drive South Burlington, Vermont 05403 Attention: John J. Lampron Telephone: (802) 864-5731 Telecopy: (802) 865-9974 with a copy to: Michael G. Furlong, Esq. Sheehey Brue Gray & Furlong P.C. 30 Main Street P.O. Box 66 Burlington, Vermont 05402 Telephone: (802) 864-9891 Telecopy: (802) 864-6815 if to the Agent, to: Fleet National Bank One Federal Street Boston, Massachusetts 02211 Attention: Robert Lanigan, Director Telephone: (617) 346-0576 Telecopy: (617) 346-0580 with a copy to: Peter S. Johnson, Esq. Gadsby & Hannah LLP 225 Franklin Street Boston, MA 02110 Telephone: (617) 345-7052 Telecopy: (617) 345-7050 if to the Banks, to: Fleet National Bank One Federal Street Boston, Massachusetts 02211 Attention: Robert Lanigan, Director Telephone: (617) 346-0576 Telecopy: (617) 346-0580 with a copy to: Peter S. Johnson, Esq. Gadsby & Hannah LLP 225 Franklin Street Boston, MA 02110 Telephone: (617) 345-7052 Telecopy: (617) 345-7050 The Bank of Nova Scotia 101 Federal Street, 16th Floor Boston, MA 02110 Attention: Stephen Foley, Relationship Manager Telephone: (617) 737-6318 Telecopy: (617) 951-2177 State Street Bank and Trust Company 225 Franklin Street Boston, MA 02110 Attention: Lise Anne Boutiette, Vice President Telephone: (617) 664-3262 Telecopy: (617) 664-6527 or to such other Person or address as a party hereto shall designate to the other parties hereto from time to time in writing forwarded in like manner. Any notice or demand given in accordance with the provisions of this paragraph 11.1 shall be effective when received and any consent, waiver or other communication given in accordance with the provisions of this paragraph 11.1 shall be conclusively deemed to have been received by a party hereto and to be effective on the day on which delivered to such party at its address specified above or, if sent by first class mail, on the third Business Day after the day when deposited in the mail, postage prepaid, and addressed to such party at such address, provided that a notice of change of address shall be deemed to be effective when actually received. 11.2 Distribution of Copies. Whenever the Company is required to deliver any statement, report, document, certificate or other paper (other than Borrowing Request or a notice to convert under paragraph 2.7) to the Agent, the Company shall simultaneously deliver a copy thereof to each Bank. 11.3 Notices by the Agent or a Bank. In the event that the Agent or any Bank takes any action or gives any consent or notice provided for by this Agreement, notice of such action, consent or notice shall be given forthwith to all the Banks by the Agent or the Bank taking such action or giving such consent or notice, provided that the failure to give any such notice shall not invalidate any such action, consent or notice in respect of the Company. 12. RIGHT OF SET-OFF. Regardless of the adequacy of any collateral, upon the occurrence and during the continuance of any Event of Default, each Bank is hereby expressly and irrevocably authorized by the Company at any time and from time to time, without notice to the Company, to set-off, appropriate, and apply all moneys, securities and other Property and the proceeds thereof now or hereafter held or received by or in transit to such Bank from or for the account of the Company, whether for safekeeping, pledge, transmission, collection or otherwise, and also upon any and all deposits (general and special), account balances and credits of the Company with such Bank at any time existing against any and all obligations of the Company to the Banks and to each of them arising under this Agreement and the Notes, and the Company shall continue to be liable to each Bank for any deficiency with interest at the rate or rates set forth in subparagraph 2.8(b). Each of the Banks agrees with each other Bank that (a) if an amount to be set off is to be applied to any obligations of the Company to such Bank, other than obligations evidenced by the Notes held by such Bank, such amount shall be applied ratably to such other obligations and to the obligations evidenced by all such Notes held by such Bank and (b) if such Bank shall receive from the Company, whether by voluntary payment, exercise of the right of setoff, counterclaim, cross action, enforcement of the claim evidenced by the Notes held by such Bank by proceedings against the Company at law or in equity or by proof thereof in bankruptcy, reorganization, liquidation, receivership or similar proceedings, or otherwise, and shall retain and apply to the payment of the Note or Notes held by such Bank any amount in excess of its ratable portion of the payments received by all of the Banks with respect to the Notes held by all of the Banks, such Bank will make such disposition and arrangements with the other Banks with respect to such excess, either by way of distribution, pro tanto assignment of claims, subrogation or otherwise as shall result in each Bank receiving in respect of the Notes held by each Bank, its proportionate payment as contemplated by this Agreement; provided that if all or any part of such excess payment is thereafter recovered from such Bank, such disposition and arrangements shall be rescinded and the amount restored to the extent of such recovery, but without interest. 13. AMENDMENTS, WAIVERS AND CONSENTS. Except as otherwise expressly set forth herein, with the written consent of the Majority Banks, the Agent shall, subject to the provisions of this paragraph 13, from time to time enter into agreements amendatory or supplemental hereto with the Company for the purpose of changing any provisions of this Agreement or the Notes, or changing in any manner the rights of the Banks, the Agent or the Company hereunder and thereunder, or waiving compliance with any provision of this Agreement or consenting to the non-compliance thereof. Notwithstanding the foregoing, the consent of all of the Banks shall be required with respect to any amendment, waiver or consent (i) changing the Aggregate Commitments or the Commitment of any Bank or (ii) changing the maturity of any Loan, or the rate of interest of, time or manner of payment of interest on or principal of, or the principal amount of any Loan, or the amount, time or manner of payment of any fees hereunder, or modifying this paragraph 13. Any such amendment or supplemental agreement, waiver or consent shall apply equally to each of the Banks and shall be binding on the Company and all of the Banks and the Agent. Any waiver or consent shall be for such period and subject to such conditions or limitations as shall be specified therein, but no waiver or consent shall extend to any subsequent or other Event of Default, or impair any right or remedy consequent thereupon. In the case of any waiver or consent, the rights of the Company, the Banks and the Agent under this Agreement and the Notes shall be otherwise unaffected. Nothing contained herein shall be deemed to require the Agent to obtain the consent of any Bank with respect to any change in the amount or terms of payment of the Agent's Fees. The Company shall be entitled to rely upon the provisions of any such amendatory or supplemental agreement, waiver or consent if it shall have obtained any of the same in writing from the Agent who therein shall have represented that such agreement, waiver or consent has been authorized in accordance with the provisions of this paragraph 13. 14. OTHER PROVISIONS. 14.1 No Waiver of Rights by the Banks. No failure on the part of the Agent or of any Bank to exercise, and no delay in exercising, any right or remedy hereunder or under the Notes shall operate as a waiver thereof, except as provided in paragraph 13, nor shall any single or partial exercise by the Agent or any Bank of any right, remedy or power hereunder or under the Notes preclude any other or future exercise thereof, or the exercise of any other right, remedy or power. The rights, remedies and powers provided herein and in the Notes are cumulative and not exclusive of any other rights, remedies or powers which the Agent or the Banks or any holder of a Note would otherwise have. Notice to or demand on the Company in any circumstance in which the terms of this Agreement or the Notes do not require notice or demand to be given shall not entitle the Company to any other or further notice or demand in similar or other circumstances or constitute a waiver of the rights of the Agent or any Bank or the holder of any Note to take any other or further action in any circumstances without notice or demand. 14.2 Headings; Plurals. Paragraph and subparagraph headings have been inserted herein for convenience only and shall not be construed to be a part of this Agreement. Unless the context otherwise requires, words in the singular number include the plural, and words in the plural include the singular. 14.3 Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be an original and all of which shall constitute one agreement. It shall not be necessary in making proof of this Agreement or of any document required to be executed and delivered in connection herewith or therewith to produce or account for more than one counterpart. 14.4 Severability. Every provision of this Agreement and the Notes is intended to be severable, and if any term or provision hereof or thereof shall be invalid, illegal or unenforceable for any reason, the validity, legality and enforceability of the remaining provisions hereof or thereof shall not be affected or impaired thereby, and any invalidity, illegality or unenforceability in any jurisdiction shall not affect the validity, legality or enforceability of any such term or provision in any other jurisdiction. 14.5 Integration. All exhibits to this Agreement shall be deemed to be a part of this Agreement. This Agreement, the exhibits hereto and the Notes embody the entire agreement and understanding between the Company, the Agent and the Banks with respect to the subject matter hereof and thereof and supersede all prior agreements and understandings between the Company, the Agent and the Banks with respect to the subject matter hereof and thereof. 14.6 Sales and Participations in Loans and Notes: Successors and Assigns: Survival of Representations and Warranties. (a) Each Bank shall have the right with the prior written consent of the Company (which consent shall not be unreasonably withheld or delayed), upon written notice to the Agent and the Company to sell, assign, transfer or negotiate all or any part but not less than $5,000,000) of the Loans and the Notes and its Commitment to one or more commercial banks or other financial institutions including, without limitation, the Banks. In the case of any sale, assignment, transfer or negotiation of all or any such part of the Loans and the Notes authorized under this paragraph 14.6 (a), the assignee or transferee shall have, to the extent of such sale, assignment, transfer or negotiation, the same rights, benefits and obligations as it would if it were a Bank hereunder and a holder of such Note, including, without limitation, (x) the right to approve or disapprove of actions which in accordance with the terms hereof, require the approval of the Majority Banks and (y) the obligation to fund Loans directly to the Agent pursuant to paragraph 2.2. (b) Notwithstanding paragraph 14.6 (a), each Bank may grant participations in all or any part of its Loans and its Notes to one or more commercial banks, insurance companies or other financial institutions, pension funds or mutual funds; provided that (i) any such disposition shall not, without the prior written consent of the Company, require the Company to file a registration statement with the Securities and Exchange Commission or apply to qualify the Loans and the Notes under the blue sky laws of any state and (ii) the holder of any such participation, other than an Affiliate of such Bank, shall not have any rights or obligations hereunder and shall not be entitled to require such Bank to take or omit to take any action hereunder except action directly affecting the extension of the maturity of any portion of the principal amount of, or interest on, the Loan allocated to such participation, or a reduction of the principal amount of, or the rate of interest payable on, such Loans. Notwithstanding the foregoing provisions of this paragraph 14.6, each Bank may at any time and from time to time sell, assign, transfer, or negotiate all or any part of the Loans to any Affiliate of such Bank; provided that an Affiliate to whom such disposition has been made shall not be considered a "Bank", and the assigning Bank shall be considered not to have disposed of any Loans so assigned for purposes of determining the Majority Banks under any provision hereof, but such Affiliate shall otherwise be considered a "Bank", and the assigning Bank shall otherwise be considered to have disposed of any Loans so assigned, for purposes hereof, including, without limitation, paragraphs 3.1 and 12 hereof. In addition, notwithstanding anything to the contrary contained in this paragraph 14.6, any Bank may at any time and from time to time assign all or any portion of its rights under this Agreement with respect to its Loans, its Commitments and its Notes to a Federal Reserve Bank. No such assignment shall release the assignor Bank from its obligations hereunder. No Bank shall, as between the Company and such Bank, be relieved of any of its obligations hereunder as a result of granting participations in all or any part of the Loans and the Notes of such Bank or other obligations owed to such Bank. This Agreement shall be binding upon and inure to the benefit of the Banks, the Agent and the Company and their respective successors and assigns. All covenants, agreements, warranties and representations made herein, and in all certificates or other documents delivered in connection with this Agreement by or on behalf of the Company shall survive the execution and delivery hereof and thereof, and all such covenants, agreements, representations and warranties shall inure to the respective successors and assigns of the Banks and the Agent whether or not so expressed. The Agent shall maintain a copy of each assignment delivered to it and a register or similar list for the recordation of the names and addresses of the Banks and the Commitment Percentages of the Banks and the principal amount of the Loans and the Notes assigned from time to time. The entries in such register shall be conclusive, in the absence of manifest error and provided that any required consent of the Company has been obtained, and the Company, the Agent and the Banks may treat each Person whose name is recorded in such register as a Bank hereunder for all purposes of this Agreement. Upon each such recordation, the assigning Bank agrees to pay to the Agent a registration fee in the sum of Two Thousand Five Hundred Dollars ($2,500). 14.7 Applicable Law. This Agreement and the Notes are being delivered in and are intended to be performed in The Commonwealth of Massachusetts and shall be construed and enforceable in accordance with, and be governed by, the internal laws of The Commonwealth of Massachusetts without regard to its principles of conflict of laws. 14.8 Interest. At no time shall the interest rate payable on the Notes, together with the Facility Fee and the Agent's Fees, to the extent same are construed to constitute interest, exceed the maximum rate of interest permitted by law. The Company acknowledges that to the extent interest payable on the Notes is based on the Alternate Base Rate, such Rate is only one of the bases for computing interest on loans made by the Banks, and by basing interest payable on the Notes on the Alternate Base Rate, the Banks have not committed to charge, and the Company has not in any way bargained for, interest based on a lower or the lowest rate at which the Banks may now or in the future make loans to other borrowers. 14.9 Accounting Terms and Principles. All accounting terms not herein defined by being capitalized shall be interpreted in accordance with GAAP, unless the context otherwise expressly requires. 14.10 WAIVER OF TRIAL BY JURY. THE COMPANY HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVES (TO THE FULLEST EXTENT PERMITTED OR NOT PROHIBITED BY APPLICABLE LAW) ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION ARISING OUT OF, UNDER OR IN CONNECTION WITH THE LOAN DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED THEREIN. FURTHER, THE COMPANY HEREBY ACKNOWLEDGES THAT NO REPRESENTATIVE OF THE AGENT OR THE BANKS OR COUNSEL TO THE AGENT OR THE BANKS HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT THE AGENT OR THE BANKS WOULD NOT, IN THE EVENT OF SUCH LITIGATION, SEEK TO ENFORCE SUCH WAIVER. THE COMPANY ACKNOWLEDGES THAT THE AGENT AND THE BANKS HAVE BEEN INDUCED TO ENTER INTO THE LOAN DOCUMENTS BY, INTER ALIA, THE PROVISIONS OF THIS PARAGRAPH. 14.11 CONSENT TO JURISDICTION. THE COMPANY HEREBY IRREVOCABLY SUBMITS TO THE JURISDICTION OF ANY COURT OF THE COMMONWEALTH OF MASSACHUSETTS OR ANY FEDERAL COURT SITTING IN THE COMMONWEALTH OF MASSACHUSETTS OVER ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THE LOAN DOCUMENTS. THE COMPANY HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED OR NOT PROHIBITED BY APPLICABLE LAW, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH COURT AND ANY CLAIM THAT ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. THE COMPANY HEREBY AGREES THAT A FINAL JUDGMENT IN ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH A COURT, AFTER ALL APPROPRIATE APPEALS, SHALL BE CONCLUSIVE AND BINDING UPON IT. 14.12 SERVICE OF PROCESS. PROCESS MAY BE SERVED IN ANY SUIT, ACTION, COUNTERCLAIM OR PROCEEDING OF THE NATURE REFERRED TO IN PARAGRAPH 14.11 BY MAILING COPIES THEREOF BY REGISTERED OR CERTIFIED MAIL, POSTAGE PREPAID, RETURN RECEIPT REQUESTED, TO THE ADDRESS OF THE COMPANY SET FORTH IN PARAGRAPH 11.1 OR TO ANY OTHER ADDRESS OF WHICH THE COMPANY SHALL HAVE GIVEN WRITTEN NOTICE TO THE AGENT. THE COMPANY HEREBY AGREES THAT SUCH SERVICE (I) SHALL BE DEEMED IN EVERY RESPECT EFFECTIVE SERVICE OF PROCESS UPON IT IN ANY SUCH SUIT, ACTION, COUNTERCLAIM OR PROCEEDING, AND (II) SHALL TO THE FULLEST EXTENT PERMITTED OR NOT PROHIBITED BY APPLICABLE LAW, BE TAKEN AND HELD TO BE VALID PERSONAL SERVICE UPON AND PERSONAL DELIVERY TO IT. 14.13 NO LIMITATION ON SERVICE OR SUIT. NOTHING IN THE LOAN DOCUMENTS, OR ANY MODIFICATION, WAIVER, OR AMENDMENT THERETO, SHALL AFFECT THE RIGHT OF THE AGENT OR ANY BANK TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR LIMIT THE RIGHT OF THE AGENT OR ANY BANK TO BRING PROCEEDINGS AGAINST THE COMPANY IN THE COURTS OF ANY OTHER JURISDICTION OR JURISDICTIONS. 15. OTHER OBLIGATIONS OF THE COMPANY. 15.1 Taxes and Fees. Should any tax (other than a tax based upon the net income of any Bank), recording or filing fee become payable in respect of this Agreement or the Notes or any amendment, modification or supplement hereof or thereof, the Company agrees to pay the same together with any interest or penalties thereon and agrees to hold the Agent and the Banks harmless with respect thereto. 15.2 Expenses. Whether or not the transactions contemplated by this Agreement shall be consummated, the Company agrees to pay the reasonable out-of-pocket expenses of the Agent (including the reasonable fees and expenses of counsel to the Agent and, without limitation, Special Counsel) in connection with the preparation, reproduction, execution and delivery of this Agreement and the Notes and the other exhibits annexed hereto (in such case, with respect to the Special Counsel, in accordance with the letter previously delivered to the Company by the Special Counsel) and any modifications, waivers, consents or amendments hereto and thereto, and the Company further agrees to pay the reasonable out-of-pocket expenses of the Agent and the Banks (including the reasonable fees and expenses of their respective counsel) incurred in connection with the interpretation and enforcement of any provision of this Agreement or collection under the Notes, whether or not suit is instituted. 16. EFFECTIVE DATE. This Agreement shall be effective at such time (specified in writing by the Agent to the Company and the Banks) (the "Effective Date") as executed counterparts of this Agreement have been delivered to the Agent by the Company and each Bank. [remainder of page intentionally left blank] IN WITNESS WHEREOF, the parties have caused this Agreement to be duly executed as of the date first written above. GREEN MOUNTAIN POWER CORPORATION By: /s/ Edwin M. Norse Title: Vice President, Chief Financial Officer and Treasurer Domestic Lending Office: FLEET NATIONAL BANK, Office listed in paragraph 11.1 Individually and as Agent Eurodollar Lending Office: Office listed in paragraph 11.1 By: /s/ Robert A. Lanigan Title: Director Domestic Lending Office: THE BANK OF NOVA SCOTIA Office listed in paragraph 11.1 Eurodollar Lending Office: By: /s/ Stephen F. Foley Office listed in paragraph 11.1 Title: Relationship Manager Domestic Lending Office: STATE STREET BANK AND TRUST COMPANY Office listed in paragraph 11.1 Eurodollar Lending Office: By: /s/ Lise Anne Boutiette Office listed in paragraph 11.1 Title: Vice President EXHIBIT A COMMITMENT Tranche A Loan Tranche B Loan Total Commitment Bank Commitment* Commitment* Commitment* Percentage* THE BANK OF NOVA $5,000,000 $10,000,000 $15,000,000 33 1/3% SCOTIA STATE STREET BANK $5,000,000 $10,000,000 $15,000,000 33 1/3% AND TRUST COMPANY FLEET NATIONAL BANK $5,000,000 $10,000,000 $15,000,000 33 1/3% AGGREGATE $15,000,000 $30,000,000 $45,000,000 100% COMMITMENTS * The Aggregate Tranche A Loan Commitments, Aggregate Tranche B Loan Commitments and the Aggregate Total Commitments may be increased pursuant to paragraph 2.18 of the Agreement and, consequently, the Commitment Percentage may change accordingly. EXHIBIT B SCHEDULE I Green Mountain Power Corporation Pricing Grid Tranche B Loans* Pricing Senior Secured LIBOR Margin** Facility Fee** All-in LIBOR Level Rating Cost** I >=A-/A3 or better 25.0 10.0 35.0 II =BBB+/Baa1 27.5 12.5 40.0 III =BBB/Baa2 35.0 15.0 50.0 IV =BBB-/Baa3 57.5 17.5 75.0 V =A-/A3 or better 26.5 8.5 35.0 II =BBB+/Baa1 30.0 10.0 40.0 III =BBB/Baa2 37.5 12.5 50.0 IV =BBB-/Baa3 60.0 15.0 75.0 V EX-2 3 Exhibit 10-d-15b Green Mountain Power Corporation Compensation Program for Officers And Certain Key Management Personnel - 1998 - Highlights Brochure/Program Document Table of Contents Page Preamble 1 Purpose of Program 1 Participants 1 Effective Date 1 Definitions 1 Program Components 3 Base Salary 4 Variable Compensation 4 Determination of Award 6 Variable Compensation Award Payment 7 Program Administration 8 Appendix I Appendix II Preamble This document describes and governs the Compensation Program for Officers and Certain Key Management Personnel for Green Mountain Power Corporation ("GMP" or "the Company"). The program is intended to assure that total compensation is competitive in the marketplace and promotes the Company's strategic objectives. Purpose of Program The purpose of the Compensation Program is to: . ensure that base compensation compares favorably with regard to organizations competing for similar talent; . provide an opportunity for officers and other key management personnel to share in the success of GMP by linking a portion of compensation (variable compensation) to corporate performance results; . encourage a longer-term view by paying part of an earned variable compensation award in deferred/restricted stock; and . foster and reinforce teamwork among officers and other key management personnel. Participants Senior officers of GMP and other key management personnel, as designated from time to time by the Board of Directors are eligible to participate in this program. Appendix I to this document, as amended from time to time, will list eligible participants so designated. Effective Date The stock award provisions contained herein shall be effective upon shareholder and other required regulatory approval. The program is otherwise effective January 1, 1994. Definitions The following definitions pertain to the program. Circuit Breaker - a performance level below which no variable compensation will be paid regardless of performance against the corporate measures. For this program, no awards will be paid unless taking into account provision for awards, the dividend payout ratio is equal to or less than 65 percent of earnings. Compensation Committee - the Compensation Committee of the Board of Directors. Market Average - the average of salaries paid in the marketplace for positions similar to those at GMP. Market Range - a range running from 10% below to 10% above the market average. Marketplace - Companies that are determined by GMP to be those competing for similar talent. Depending on the position within GMP, marketplace companies can be utilities, general industry -- local, regional, national, or any combination thereof. Maximum - the maximum or optimal level of corporate performance with respect to a corporate performance measure. This determination will be applied separately to each performance measure. No variable compensation with respect to a performance measure will be paid in excess of the maximum level indicated. Compensation Program - the compensation program, which consists of base salary and the opportunity to earn variable compensation. Organization Bands - tiers within which management positions are clustered, to reflect the nature and scope of the jobs, reporting relationships, and the like. Peer Companies - a select group of utilities against which GMP's performance will be measured. Performance Measure - a critical factor used to measure the success of the business. Program Year - GMP's fiscal year. Related Company - an entity wholly or partly owned by GMP (directly or indirectly), employment with which the Board of Directors has determined should qualify for the vesting of restricted stock grants. Restricted Stock Grants - the portion of the variable compensation award paid to officers in the form of GMP common stock that will be subject to two restrictions of a five (5) year duration: (1) no transferability; and (2) forfeiture of the stock upon termination of employment with the Company or with a Related Company (except for retirement, death, disability or termination from employment in circumstances entitling the participant to the benefits payable under Paragraph 4 of a certain Letter Agreement between said participant and the Company that concerns a change in control of the Company, or under a similar change in control agreement between the participant and a Related Company, or in the event of termination of employment with the Company or a Related Company by the employer without cause or by the employee with good reason. The terms "cause" and "good reason" shall have the meanings ascribed to them in the aforesaid Letter Agreement for participants employed by the Company, or the meanings ascribed to them I any employment agreements between the participant and a Related company in the case of a participant employed by a Related Company). During the five-year restriction period, dividends will be paid and officers will have voting rights. The value of restricted stock is taxable when the restrictions lapse (after five years, or earlier in the case of the officer's retirement, disability or death). The restriction period begins on the date the awards are granted. Stock Grants - the portion of the variable compensation award paid to participants in the form of shares of GMP common stock. These shares are the property of the participant upon grant and may be retained or sold. Upon grant, shares are subject to current taxation. Target - the desired level of corporate performance with respect to a performance measure. This determination will be applied separately for each performance measure. Threshold - the acceptable level of corporate performance with respect to a performance measure. This determination will be applied separately to each performance measure. No variable compensation with respect to a performance measure will be paid unless the threshold level is attained. Total Compensation - an amount comprised of base salary and variable compensation. Variable Compensation - compensation that is earned based on the achievement of corporate performance objectives and that may be paid in cash, stock grants, or restricted stock grants. Program Components The Compensation Program is comprised of two compensation components: . Base Salary . Variable Compensation Base Salary Each officer or other key management employee is paid a base salary intended to be competitive with base compensation paid for similar positions in the marketplace. Variable Compensation Each officer or other key management employee is eligible to earn additional compensation when GMP's performance meets or exceeds various performance objectives. Base Salary Base salaries are intended to provide a competitive rate of fixed compensation. Base salary levels will be assessed by compiling and analyzing salary information from various published survey sources on an annual basis. Survey sources include: . Mercer Finance, Accounting & Legal Compensation Survey . Wyatt Top Management Report . Edison Electric Executive Compensation Survey Within one year after the adoption of the program, base salaries are intended to be managed to the market average (in any event, within a plus or minus 10% range around the market average) as determined from the survey analysis. The average and the range may or may not change from year to year depending on movement in the market and, therefore, it is possible that base salaries may not be increased annually. Appropriate adjustments will be made in May of each year. Actual base compensation within the market range will depend on internal equity, overall scope of responsibilities of the position, recruitment needs, and significant individual performance variations. The market ranges have been incorporated into three organization bands (in lieu of job grades), as set forth in Appendix I, which may be modified from time to time by direction of the Board or the Chief Executive Officer. These bands reflect the nature of the positions and their impact on the organization. Additionally, these bands signify varying levels of participation in the variable compensation component of the program. The band assignments are determined on the basis of survey data and the role of the position. Variable Compensation The purpose of the variable compensation component of this program is to tie compensation directly to the achievement of key corporate-wide objectives. Awards earned will be paid in cash, stock grants, and restricted stock as deemed appropriate by the Compensation Committee of the Board of Directors. The initial variable award payments will be made as set forth below. This award delivery feature is intended to motivate participants toward the annual attainment of critical corporate objectives consistent with the need to manage GMP to achieve longer-term success. Variable Compensation Award Opportunities Each band has a different variable compensation opportunity as noted in the following table. Award Table (AT) Band Variable Cash Opportunities as a % of Base Salary Threshold Target Maximum A 25% 50% 75% B 17.5% 35% 52.5% C 12.5% 25% 37.5% Note: Percentages are prorated for performance that falls between threshold and maximum levels. Performance Measures - Establishment At the beginning of each year, appropriate corporate performance measures will be determined for purposes of generating the variable compensation award. These measures are expected to remain in substantially the same form year-to-year. They may change, however, as GMP revisits its strategic and operational plans. Moreover, the Board of Directors may consider whether to constrain awards to threshold award levels in light of earnings and/or total shareholder return performance. The measures are: . Return on Equity . Total Shareholder Return . Rates . Customer Satisfaction; and . Reliability Performance objectives associated with these measures are established for each fiscal year by the Compensation Committee and reviewed by the Board of Directors. (See Appendix II for measures and specific objectives for 1994, and years following, as indicated.) After the close of each year, the Compensation Committee, with input from the CEO, will determine the degree to which these performance objectives were accomplished to determine if variable cash awards are to be paid. If the threshold level of performance is not met, an award will not be paid with respect to that specific performance measure. In addition, the program incorporates a circuit breaker to protect shareholder investment. The circuit breaker ensures that awards will not be paid unless earnings, after subtracting the variable awards, are greater than dividends paid in the year for which variable compensation is to be awarded. Performance Measures - Individual Performance Assessment - Individual performance may, on an exceptions basis, be taken into consideration in determining the final award. However, the maximum shown in the Award Table cannot be exceeded. Performance Measures - Weighting - The performance measures will be weighted each year to reflect the strategic plan and the impact each organization band/position has on performance. The number of measures used will be limited to ensure that the significance of the measures will not be diluted (weights less than 10% cannot be used). The performance measures will be weighted as noted in Appendix II. Determination of Award An award will be determined in accordance with the following example. Assume: . Participant is in Band B . Base Salary = $100,000* . Individual Performance = meets expectations . Circuit Breaker = achieved required level Performance Performance Award % Adjusted Award % Measure Weight Results (from AT) Weight Time % ROE 30% 75% ile 35% 10.5% TSR . D&P 15% Threshold 17.5% 2.625% . Select 15% Threshold 17.5% 2.625% Rates 20% 80% ile 35% 7.0% Customer Satisfaction 10% 80% 35% 3.5% Reliability . SAII 3.3% Threshold 17.5% .583% . SAIFI 3.3% Threshold 17.5% .583% . CAIDI 3.3% Threshold 17.5% .583% Total Award % = 28% Award = $28,000 * Base salary in effect as of December 31 of the year for which the award will be made. Variable Compensation Award Payment An award earned will be paid in cash and, subject to shareholder and required regulatory approval, stock grant and restricted stock grant in accordance with the following schedule: Band Cash Stock Grant Restricted Stock A 1/4 1/4 1/2 B&C 1/3 1/3 1/3 The Compensation Committee may make changes in this schedule, subject to review by the Board of Directors. Cash The cash portion of the award will be paid in a separate check. Stock Grants The stock grant portion of the award will be paid in shares of GMP common stock. The number of shares will be determined by dividing the portion of the award to be paid in stock by the closing stock price on the day the Board of Directors authorizes variable compensation payments (i.e., the annual meeting). The number of shares so determined will be rounded up to the nearest full share. Relevant taxes (e.g., federal, FICA, State), based on the cash and stock grant portions of the award, will be withheld. Restricted Stock The grant of restricted stock will be made upon execution of an agreement between the participant and the Company that will provide, for a period of five (5) years from the date of the grant, that: (a) the shares will not be transferable; and (b) the shares will be forfeited upon termination of employment with GMP or with a Related Company, except where the termination of employment results from retirement, disability, death, or occurs in circumstances entitling the participant to the benefits payable under Paragraph 4 of a certain Letter Agreement between said participant and the Company that concerns a change in control of the Company, or under a similar change in control agreement between the participant and a Related Company, or in the event of termination of employment with the Company or a Related Company by the employer without cause or by the employee with good reason. The terms "cause" and "good reason" shall have the meanings ascribed to them in the aforesaid Letter Agreement for participants employed by the Company, or the meanings ascribed to them in any employment agreements between the participant and a Related Company in the case of a participant employed by a Related Company. The number of restricted stock shares to be awarded will be determined as described immediately above with respect to stock grants. Program Administration The Program will be administered by the Chief Executive Office with approval of the Compensation Committee The Board of Directors may consider whether to make awards above threshold award levels in light of earnings and/or total shareholder return performance. The Board of Directors will have the full power and authority to: . Interpret the program . Approve participants . Act on the CEO's recommendations . Amend or terminate the Program, subject to required shareholder and regulatory approval . Approve the CEO's award Participation in the program does not confer any right or privilege regarding continued employment with GMP upon a participant. Payment of the cash and, subject to required shareholder and regulatory approval, the stock grant portions, will be made during the second quarter following the end of the program year. Participants must be employed on the date the award is paid in order to receive an award unless the participant has retired, is disabled, is deceased, has been terminated from employment in circumstances entitling the participant to the benefits payable under Paragraph 4 of a certain Letter Agreement between said participant and the Company that concerns a change in control of the Company, or the Compensation Committee determines that the circumstances under which the participant terminated employment warrant special consideration. Payments of variable compensation awards will not affect a participant's levels of entitlement to participate in other benefit plans unless expressly stated in documentation for such plans existing as of January 1, 1994. The program will be administered in accordance with the laws of the State of Vermont. Appendix I (revised February 9, 1998) Band* Position Role A President and CEO Strategic B VP, CFO and Treasurer Strategic Senior Vice President and COO Senior Vice President - Corporate Development General Counsel VP, Human Resources and Organizational Development C Controller Strategic/Tactical AVP Engineering Chief Corporate Strategic Planning Officer AVP Customer Operations Central & Southern Divisions AVP Customer Operations Western Division Assistant General Counsel Assistant Treasurer General Manager, Administrative Services *Band A applies generally to the CEO and COO; Band B applies generally to Vice Presidents and General Counsel; and Band C applies generally to Assistant Vice Presidents and other key management personnel. Appendix II Performance Measures -- Weights . Return on Equity 30% . Total Shareholder Return 30% . Rates 20% . Customer Satisfaction 10% . Reliability 10% Performance Measures -- Objectives For the performance year 1997, no awards shall be made above the threshold award levels unless: (a) total shareholder return, as defined below, is at or above the threshold performance level; and (b) earnings per share, adjusted for award payments hereunder, are $2.25 or more. No adjustment in the level of any award for individual performance may be made if such adjustment would cause earnings per share to decline below $2.25 for 1997. The objectives for 1997 for each of the performance measures are: . Return on Equity --The peer group shall be the utilities that comprise the EEI 100 Index. The consolidated ROE's of the utilities that comprise the EEI 100 Index, acquired from any reasonable source of such data, shall be used to determine the extent to which the objectives have been met. --To achieve threshold performance, GMP's ROE for electric operations for the calendar year must be equal to or greater than the allowed ROE level, or its consolidated ROE must be equal to or greater than the consolidated ROE of 60% of the utilities in the peer group. --Target level is reached when GMP's consolidated ROE is equal to or greater than 75% of the peer group utilities' consolidated ROE. --Maximum performance is reached when GMP's consolidated ROE is equal to or greater than 90% of the peer group utilities' consolidated ROE. . Total Shareholder Return --Performance is measured using two different peer groups: the utilities in the EEI 100 Index, and a select peer group. The select group includes: . Atlantic Energy . Boston Edison . Commonwealth Energy . Central Hudson Gas & Electric . Central Maine Power . Central Vermont Public Service . Delmarva Power & Light . Eastern Utilities Associates . Empire District Electric . Idaho Power . Montana Power . Orange & Rockland Utilities . Rochester Gas & Electric . St. Joe Power & Light . United Illuminating --Total Shareholder Return (TSR) is defined as dividends plus capital appreciation using a three-year rolling average. --To achieve threshold performance, GMP's TSR must be in the top half of the peer group. --Target performance is equal to or greater than 60% of the peer group. --Maximum performance is equal to or greater than 70% of the peer group. . Rates --Performance is measured against 10 New England utilities. They are: . Central Maine Power . Bangor-Hydro . Public Service of New Hampshire . Central Vermont . Boston Edison . Commonwealth Energy . Massachusetts Electric . Connecticut Power & Light . United Illuminating . Narragansett Electric --To achieve threshold performance, GMP's rates must be equal to or lower than 70% of the peer group. --Target performance is achieved when GMP's rates are equal to or lower than 80% of peer group. --Maximum performance is reached when GMP's rates are lowest or second lowest among the peer group. . Customer Satisfaction --Performance is measured using two surveys (i.e., Commercial/Industrial, Residential) with respect to the following aspects of customer satisfaction: reliability of service, responsiveness to trouble calls, responsiveness to customer inquiries, accuracy of customers' bills, effectiveness of telephone communications, effective delivery of DSM services. --To achieve threshold performance, 70% or more of customers must indicate satisfaction. --Target performance is achieved when 80% or more of customers indicate satisfaction. --Maximum performance is reached when 90% or more indicate satisfaction. . Reliability --Performance is measured using three indices: . System average interruption index (SAIDI) . System average interruption frequency index (SAIFI) . Customer average interruption duration index (CAIDI) . SAIDI --To reach threshold performance, GMP's performance must improve be 89 minutes or less for 1998. --To reach target performance, GMP's performance must be 86 minutes or less for 1998 --To reach maximum performance, GMP's performance must be 84 minutes or less for 1998. . SAIFI --To reach threshold performance, GMP's performance must be 1.09 outages or less for 1998. --To reach target performance, GMP's performance must be 1.06 outages or less for 1998. --To reach maximum performance, GMP's performance must be 1.03 outages or less for 1998. . CAIDI --To reach threshold performance, GMP's performance must be 80 minutes or less for 1998 --To reach target performance, GMP's performance must be 78 minutes or less for 1998. --To reach maximum performance, GMP's performance must be 77 minutes or less for 1998. EX-3 4 Exhibit 23-a-1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 2, 1998 included in this Form 10-K into the Company's previously filed Registration Statements on Form S-3, File Nos. 33-58411 and 33-59383, and into the Company's previously filed Registration Statements on Form S-8, File Nos. 33-58413 and 33-60511. Boston, Massachusetts March 27, 1998 /s/ Arthur Andersen LLP EX-4 5 Exhibit 24 POWER OF ATTORNEY We, the undersigned directors of Green Mountain Power Corporation, hereby severally constitute Christopher L. Dutton, Edwin M. Norse, and Michael H. Lipson, and each of them singly, our true and lawful attorney with full power of substitution, to sign for us and in our names in the capacities indicated below, the Annual Report on Form 10-K of Green Mountain Power Corporation for the fiscal year ended December 31, 1997, and generally to do all such things in our name and behalf in our capacities as directors to enable Green Mountain Power Corporation to comply with the provisions of the Securities Exchange Act of 1934, as amended, all requirements of the Securities and Exchange Commission, and all requirements of any other applicable law or regulation, hereby ratifying and confirming our signatures as they may be signed by our said attorney, to said Annual Report. SIGNATURE TITLE DATE - --------- ----- ---- _/s/ Christopher L. Dutton President and Director February 9, 1998 Christopher L. Dutton (Principal Executive Officer) _/s/ Thomas P. Salmon______ Thomas P. Salmon Chairman of the Board February 9, 1998 _/s/ Nordahl L. Brue_______ Nordahl L. Brue Director February 9, 1998 _/s/ William H. Bruett_____ William H. Bruett Director February 9, 1998 _/s/ Merrill O. Burns______ Merrill O. Burns Director February 9, 1998 _ Lorraine E. Chickering Director _/s/ John V. Cleary________ John V. Cleary Director February 9, 1998 _/s/ Richard I. Fricke_____ Richard I. Fricke Director February 9, 1998 _/s/ Euclid A. Irving______ Euclid A. Irving Director February 9, 1998 _/s/ Martin L. Johnson_____ Martin L. Johnson Director February 9, 1998 _/s/ Ruth W. Page__________ Ruth W. Page Director February 9, 1998 EX-27 6
UT This schedule contains summary financial information extracted from the consolidated Balance Sheet as of December 31, 1997 and the related Consolidated Statements of Income and Cash Flows for the twelve months ended December 31, 1997, and is qualified in its entirety by reference to such financial statements. 1,000 12-MOS DEC-31-1997 DEC-31-1997 PER-BOOK 196,720 21,997 29,125 35,831 42,060 325,733 17,318 70,342 26,717 114,377 5,000 12,735 93,200 2,616 0 0 1,700 0 8,342 0 87,763 325,733 179,323 7,191 156,617 163,808 15,515 1,573 17,088 7,650 9,438 1,433 8,005 8,204 7,274 26,503 1.57 1.57
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