-----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, HanZMzeE8A8j6uRKR9IbYkRzgWBwn+T0PyFsM/tltaG7LSfqpPm4c8YVeX0inRIi eFPMyDYDF6uXLKyn6amiTA== 0000043704-96-000006.txt : 19960401 0000043704-96-000006.hdr.sgml : 19960401 ACCESSION NUMBER: 0000043704-96-000006 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960329 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: 1934 Act SEC FILE NUMBER: 001-08291 FILM NUMBER: 96541017 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 FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1995 SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K For the fiscal year ended December 31, 1995 Commission file number 1-8291 _X_ Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 [Fee Required] ___ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 [No Fee Required] For the transition period from ________________ to __________________ 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 nonaffiliates of the registrant as of March 15, 1996, was $132,671,421.00 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 15, 1996, was 4,868,676. DOCUMENTS INCORPORATED BY REFERENCE The Company's Definitive Proxy Statement relating to its Annual Meeting of Stockholders to be held on May 16, 1996, 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 1 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 an estimated population of 198,000. It serves approximately 81,500 customers. For the year ended December 31, 1995, the Company's sources of revenue were derived as follows: 33.6% from residential customers, 31.0% from small commercial and industrial customers, 19.7% from large commercial and industrial customers, 10.6% from sales to other utilities, and 5.1% from other sources. For the same period, the Company's energy resources for retail and requirements wholesale sales were obtained as follows: 46.4% from hydroelectric sources (5.8% Company-owned, 0.1% New York Power Authority (NYPA), 37.9% Hydro-Quebec and 2.6% small power producers), 30.4% from nuclear generating sources (the Vermont Yankee plant described below), 10.2% from coal sources, 3.3% from wood, 1.5% from natural gas, and 0.7% from oil. The remaining 7.5% was purchased on a short-term basis from other utilities and through the New England Power Pool (NEPOOL). In 1995, 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 535-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, 1995, 1994 and 1993, electric energy sales to International Business Machines Corporation (IBM), the Company's largest customer, accounted for 12.9%, 13.7% and 13.6%, respectively, of the Company's operating revenues in those years. No other retail customer accounted for more than one percent of the Company's revenue. RECENT RATE DEVELOPMENTS On September 26, 1994, the Company filed a request with the Vermont Public Service Board (VPSB) to increase retail rates by 13.9%. The increase was needed primarily to cover the rising cost of existing power sources, the cost of new power sources the Company has secured to replace power supply that will be lost in the near future, and the cost of energy efficiency programs the Company has implemented for its customers. The Company, the Vermont Department of Public Service (Department), and the other parties in the proceeding reached a settlement agreement providing for a 9.25% retail rate increase effective June 15, 1995, and a target return on equity of 11.25%. The agreement was approved by the VPSB on June 9, 1995. On September 15, 1995, the Company filed a request with the VPSB to increase retail rates by 12.7%. The increase is needed to cover higher power supply costs, to support additional investment in plant and equipment, to fund expenses associated with the Pine Street Marsh site, and to cover higher costs of capital. The Company and the Department reached a settlement agreement providing for a 5.25% retail rate increase effective June 1, 1996, and a target return on equity for utility operations of 11.25%. The settlement was based on a newly negotiated arrangement with Hydro-Quebec that will result in a reduction of the Company's power supply costs below that which was anticipated, allowing the Company to reduce the amount of its rate request. The rate settlement must be reviewed and approved by the VPSB before it can take effect. 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. The policy of the Company is to increase diversification of its power supply and other resources through various means, including power purchase and sales arrangements, and relying on sources that represent relatively small additions to the Company's mix to satisfy customer requirements. This permits the Company to meet its financing needs in a flexible, orderly manner. Planned expenditures for the next five years will be primarily for distribution and conservation projects. Capital expenditures over the past three years and forecasted for the next five years are as follows:
Total Net Generation Transmission Distribution Conservation Other Expenditures ---------- ------------ ------------ ------------ ----- ------------ (Dollars in thousands and net of AFUDC and Customer Advances For Construction) Actual 1993 $1,747 $1,605 $9,093 $8,136 $2,937 $23,518 1994 2,540 1,415 7,902 6,388 1,815 20,060 1995 2,696 1,067 8,935 4,152 2,824 19,674 Forecasted 1996 $9,530* $569 $8,496 $2,754 $6,601 $27,950 1997 899 999 8,745 2,444 3,861 16,948 1998 1,978 999 8,872 2,742 3,591 18,182 1999 2,478 999 9,084 2,643 4,895 20,099 2000 2,478 999 9,084 2,543 2,897 18,001 *Includes $8.771 million projected for wind project.
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 1993-1995, internally generated funds, after payment of dividends, provided approximately 59% of total capital requirements for construction, sinking fund obligations and other requirements. Internally generated funds provided 58% of such requirements for 1995. It is expected that funds so generated will provide approximately 73% of such requirements for the period 1996 through 2000, with the remainder to be derived through short-term borrowings and the issuance of long- term debt securities and common and preferred stock. In December 1995, the Company sold $24,000,000 of its first mortgage bonds in three components -- $8,000,000 at an interest rate of 6.21% that will mature in 2001, $8,000,000 at an interest rate of 6.29% that will mature in 2002, and $8,000,000 at an interest rate of 6.41% that will mature in 2003. A portion of the proceeds of the sale was used to reduce short-term bank loans outstanding and the remainder has allowed the Company to refund preexisting long-term debt. During 1995, the Company took several steps toward enhancing its financial flexibility. The Company filed a shelf registration statement with the SEC that allows for the periodic sale to the public of its common stock, first mortgage bonds and unsecured notes. As of December 31, 1995, $26,000,000 was available under such registration statement. Additionally, the Company established medium-term note programs that allow for the sale of secured and unsecured debt. The Company anticipates issuing approximately $10,000,000 of common stock and $10,000,000 of first mortgage bonds in 1996. The proceeds will be used to retire short-term debt and for other corporate purposes. The amount and timing of such issuances will depend upon the financial condition of the Company, prevailing market conditions and other relevant factors. In connection with the foregoing, see Management's Financial Analysis in Item 7 herein and the material appearing under the caption "Power Resources."
OPERATING STATISTICS For the Years Ended December 31 1995 1994 1993 1992 1991 ---------- ---------- ---------- ---------- ---------- Net System Capability During Peak Month (MW) Hydro (1)............................................ 152.1 179.0 174.9 160.6 161.3 Lease transmissions.................................. 0.3 2.1 3.9 5.7 5.7 Nuclear (1).......................................... 81.9 107.2 109.5 109.6 85.0 Conventional steam................................... 77.8 67.1 92.6 95.0 88.5 Internal combustion.................................. 62.0 60.2 71.0 47.4 52.0 Combined cycle....................................... 22.0 22.6 22.8 21.6 22.6 ---------- ---------- ---------- ---------- ---------- Total capability (MW).............................. 396.1 438.2 474.7 439.9 415.1 Net system peak...................................... 297.1 308.3 307.3 314.4 308.5 ---------- ---------- ---------- ---------- ---------- Reserve (MW)......................................... 99.0 129.9 167.4 125.5 106.6 ========== ========== ========== ========== ========== Reserve % of peak.................................... 33.3% 42.1% 54.5% 39.9% 34.6% Net Production (MWH) Hydro (1)............................................1,043,617 742,088 751,078 641,525 611,658 Lease transmissions.................................. -- -- 15,425 58,374 67,600 Nuclear (1).......................................... 682,814 763,690 598,245 665,034 731,582 Conventional steam................................... 673,982 651,105 748,626 762,451 799,781 Internal combustion.................................. 6,646 3,532 2,849 1,504 3,809 Combined cycle....................................... 92,723 37,808 40,966 60,138 104,344 ---------- ---------- ---------- ---------- ---------- Total production...................................2,499,782 2,198,223 2,157,189 2,189,026 2,318,774 Less non-requirements sales to other utilities....... 582,942 328,794 271,224 273,087 448,110 ---------- ---------- ---------- ---------- ---------- Production for requirements sales....................1,916,840 1,869,429 1,885,965 1,915,939 1,870,664 Less requirements sales & lease transmissions (MWH)..1,760,830 1,730,497 1,749,454 1,794,986 1,742,308 ---------- ---------- ---------- ---------- ---------- Losses and company use (MWH)......................... 156,010 138,932 136,511 120,953 128,356 ========== ========== ========== ========== ========== Losses as a percentage of total production............. 6.24% 6.32% 6.33% 5.53% 5.54% System load factor (2)................................. 71.2% 67.7% 68.7% 68.5% 67.9% Sales and Lease Transmissions (MWH) Residential - GMP.................................... 549,296 564,635 541,579 505,234 483,998 Lease transmissons................................... -- -- 15,425 58,374 67,600 ---------- ---------- ---------- ---------- ---------- Total Residential.................................. 549,296 564,635 557,004 563,608 551,598 Commercial & industrial - small...................... 608,688 604,686 593,560 582,594 571,818 Commercial & industrial - large...................... 556,278 521,400 529,372 539,665 519,201 Other................................................ 8,855 1,146 8,868 6,312 2,770 ---------- ---------- ---------- ---------- ---------- Total retail sales and lease transmissions.........1,723,117 1,691,867 1,688,804 1,692,179 1,645,387 Sales to municipals and cooperatives and other requirements sales........................... 37,713 38,630 60,650 102,807 96,921 ---------- ---------- ---------- ---------- ---------- Total requirements sales...........................1,760,830 1,730,497 1,749,454 1,794,986 1,742,308 Other sales for resale............................... 582,942 328,794 271,224 273,087 448,110 ---------- ---------- ---------- ---------- ---------- Total sales and lease transmissions................2,343,772 2,059,291 2,020,678 2,068,073 2,190,418 ========== ========== ========== ========== ========== Average Number of Electric Customers Residential.......................................... 69,659 68,811 67,994 67,201 66,406 Commercial and industrial - small.................... 11,712 11,611 11,447 11,245 11,215 Commercial and industrial - large.................... 24 24 25 24 24 Other................................................ 76 76 74 73 71 ---------- ---------- ---------- ---------- ---------- Total.............................................. 81,471 80,522 79,540 78,543 77,716 ========== ========== ========== ========== ========== Average Revenue per KWH (Cents) Residential including lease revenues................. 10.09 9.03 8.94 8.44 8.06 Lease charges........................................ -- -- 0.06 0.41 0.26 ---------- ---------- ---------- ---------- ---------- Total Residential.................................. 10.09 9.03 9.00 8.85 8.32 Commercial and industrial - small.................... 8.42 8.00 7.97 7.82 7.53 Commercial and industrial - large.................... 5.86 6.02 5.96 5.89 5.72 Total retail including lease revenues................ 8.36 7.96 7.86 7.56 7.29 Average Use and Revenue Per Residential Customer Kilowatt hours including lease transmissions......... 7,885 8,206 8,192 8,387 8,306 Revenues including lease revenues.................... $796 $741 $733 $707 $670 (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.
DEMAND-SIDE MANAGEMENT The Company develops and implements demand-side management (DSM) programs as part of its long-term resource strategy. These programs are aimed at improving the match between customer needs and the Company's ability to supply those needs at a reasonable cost. Energy conservation, load management and efficient electric use are central to these program efforts and provide the means for controlling operating expenses and requirements for additional capital investment. With more efficient electric consumption, the use of existing resources can be optimized. DSM program components, energy conservation, load-management and efficient electric use also provide customers with options and choices with respect to their use and cost of electric service. In 1994, the Company focused its energy efficiency activities on phasing out programs that were no longer cost effective in light of reduced electricity market prices. In 1995, the Company entered into an agreement to work with the Department to design new programs and to refine other, continuing programs. During the summer of 1995, the Company developed and implemented these program modifications and new programs. The most innovative of the new programs is targeted for the Company's customers in the Mad River Valley of Central Vermont. A growing load there and limited transmission and distribution capacity in the area provided an ideal opportunity to direct energy efficiency efforts where short-term benefits from avoided transmission and distribution costs (as opposed to longer term avoided generation costs) are high. The Company, in the Mad River Valley, also can test the ability of energy efficiency programs to reduce local area demand peaks in a limited time. The programs offered in the Mad River Valley include a residential retrofit program, a residential new construction assessment-fee program, and two commercial and industrial retrofit programs, one targeting large customers and the other targeting small customers. The Company also invested in 1995 in the promotion of efficient, environmentally-friendly electro-technologies. We believe that energy efficiency means more than just conservation. In many cases, efficient electrical technologies are the optimum technology. Most activities were centered around heat pumps, which are under-utilized in Vermont. A series of seminars for local building designers, contractors, and equipment vendors were held to familiarize them with this technology to help invigorate a local infrastructure to support the technology. All of the Company's other programs are "lost opportunity" programs, in which energy efficient measures are undertaken when cost- effective and when the failure to install a program would mean that the opportunity to do so is, for all practical purposes, lost. The Company provides a comprehensive set of commercial, industrial and residential programs that are substantially lower in cost than the retrofit programs offered several years ago. In part because of the shift away from retrofit programs, and in part because of a general push for greater administrative efficiencies in delivering DSM programs, the Company reduced its staff from approximately 25 full time employees to 18. Administrative improvements and program design changes have allowed the Company to combine, for example, the jobs of program managers of the commercial and industrial new construction and equipment replacements program into one manager who oversees both programs. In 1995, the Company spent approximately $3,700,000 on energy efficiency programs, approximately 2.8% of retail revenue. Efficient technologies installed in 1995 saved approximately 9,200 Mwh per year. In 1995, the Company began to broaden its range of energy services beyond energy-efficiency programs supported by regulated utility operations. Over time, the Company anticipates a gradual but steady transition of some energy efficiency services away from regulated activities paid for by all customers to more energy efficiency services paid for by the customers who use them. Rate Design. The Company seeks to design rates to encourage the shifting of electrical use from 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 depends on fair pricing to keep customers satisfied and to make predictable the customer use of its power supply so that it can keep control of its costs. 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. Approximately 1,400 of the Company's largest customers, comprising 48% of retail revenues, were successfully converted to time-of-use rates. In May 1994, the Company filed a new rate design case 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. Dispatchable and Interruptible Service Contracts. In 1995, the Company had interruptible/dispatchable power contracts with three major ski areas, interruptible only contracts with two customers and dispatchable-only contracts with an additional eighteen customers. The interruptible portion of the contracts allow the Company to control power supply capacity charges by reducing the Company's capacity requirements. During 1995, 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 at the energy only cost of the rate. The customers' demand during these periods is not considered in calculating the monthly billing. This program provides customers with discretionary use of portions of their load the opportunity to maximize their energy value and at the same time the Company is able to retain customer load requirements that might otherwise be met through alternative means. These programs are available by tariff for qualifying customers. Ripple Load-Management System. The Company has operated a remote- control load-management facility since 1976. This facility, referred to as a "Ripple" system, allows the Company, from a central signaling point, to switch off temporarily certain electrical appliances in customers' homes that have a storage capacity, such as water heaters and thermal storage heaters, thereby eliminating electric loads at discreet times. The Company's present Ripple system consists of approximately 7,000 installed signal receivers, a central processing station and four signal injection stations. Approximately 25% of the Company's eligible customers are participating in this load-control program, which allows the Company to reduce system load by four to five MW. POWER RESOURCES The Company generated, purchased or transmitted 1,853,890.7 MWh of energy for retail and wholesale customers for the twelve months ended December 31, 1995. The corresponding maximum one-hour integrated demand during that period was 297.1 MW on February 6, 1995. 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 Year Purchased in Month Ended 12/31/95 (a) of Annual Peak ___________________ ___________________ MWh % KW % WHOLLY OWNED PLANTS Hydro 110,503.1 5.8 35,300 8.9 Diesel and Gas Turbine 2,445.5 0.1 70,970 17.9 JOINTLY OWNED PLANTS Wyman #4 4,037.1 0.2 7,040 1.8 Stony Brook I 12,164.5 0.6 7,590 1.9 McNeil 9,051.2 0.5 6,830 1.7 OWNED IN ASSOCIATION W/OTHERS Vermont Yankee Nuclear 582,087.7 30.4 81,940 20.7 NYPA LEASE TRANSMISSIONS State of Vermont (NYPA) 1,743.6 0.1 250 0.1 LONG-TERM PURCHASES Hydro-Quebec 724,080.2 37.9 99,090 25.0 Merrimack #2 194,709.2 10.2 31,220 7.9 Stony Brook I 23,613.5 1.2 14,520 3.7 Small Power Producers 105,038.1 5.5 24,340 6.1 SHORT-TERM PURCHASES 143,063.6 7.5 16,990 4.3 ___________ ____ _______ _____ Less System Sales Energy (58,646.6) TOTAL 1,853,890.7 100.00 396,080 100.00 =========== ====== ======= ====== NOTE: (a) Excludes losses on off-system purchases, totaling 62,553 MWh. 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 535 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 2.735% of its entitlement to the output of Vermont Yankee. Accordingly, those utilities have 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. 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 of Vermont, 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 until 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 of Vermont's assertions. On July 31, 1991, Vermont Yankee reached a settlement with the State of Vermont, and the State filed a withdrawal of its intervention. The proceeding was dismissed on September 3, 1991. 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 16, 1995, Vermont Yankee began a scheduled refueling outage which ended May 3, 1995. Vermont Yankee's next scheduled refueling is August 1996. 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 is approximately $347,000,000, of which $141,000,000 has been funded. At December 31, 1995, the Company's portion of the net unfunded liability was $36,000,000, 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% of capital requirements not obtained by outside sources. During 1995, the Company incurred $27,700,000 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, 1995 was $13,100,000. Vermont Yankee incurred capital expenditures of approximately $2,191,000 in 1995, $2,086,000 in 1994 and $7,229,000 in 1993. Vermont Yankee estimates capital expenditures amounting to approximately $13,691,000 for 1996. During the year ended December 31, 1995, the Company utilized 582,087.7 MWh of Vermont Yankee energy to meet 30.4% of its retail and requirements wholesale sales. The average cost of electricity produced by the plant in 1995 was 4.7 per KWh. In 1995, Vermont Yankee had an annual capacity factor of 85.0%, compared to 96.1% in 1994 and 76.9% in 1993. The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8,900,000,000. Any liability beyond $8,900,000,000 is indemnified under an agreement with the NRC, but subject to Congressional approval. The first $200,000,000 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 $8,700,000,000 per incident by assessing retrospective premiums of $79,300,000 against each of the 110 reactor units in the United States that are currently subject to the Program, limited to a maximum assessment of $10,000,000 per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. The above insurance covers all workers employed at nuclear facilities prior to January 1, 1988, for bodily injury claims. Vermont Yankee has purchased a master worker insurance policy with limits of $200,000,000 with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee's estimated contingent liability for a retrospective premium on the master worker policy as of December 1995 is $3,100,000. The secondary financial protection program referenced above provides coverage in excess of the Master Worker policy. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL II and NEIL III) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II and III are subject to retroactive assessments if losses exceed the accumulated funds available. The maximum potential assessment against Vermont Yankee with respect to NEIL II losses arising during the current policy year is $14,000,000 and the NEIL III maximum retroactive assessment is $7,000,000. 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 200-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. On February 11, 1995, the transmission facilities maximum capability was upgraded from 200 MW to 225 MW. 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% 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. Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned subsidiary of VELCO, 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 to be 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, 1995, the present value of the Company's obligation was $9,800,000. The Company's projected future minimum payments under the Phase II support agreements are $488,924 for each of the years 1996-2000 and an aggregate of $7,333,867 for the years 2001-2020. 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, 1995, the capital structure of such corporations was 38% common equity and 62% long-term debt. Hydro-Quebec Power Supply Contracts. Under various contracts approved by the VPSB, 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.
July 1984 December 1987 Contract Contract Schedule A Schedule B Schedule C3 __________ __________ __________ ___________ (Dollars in thousands) Capacity Acquired 50 MW 17 MW 68 MW 46 MW Contact Period 1985-1995 1990-1995 1995-2015 1995-2015 Minimum Energy Purchase 50% 50% 75% 75% (annual load factor) Annual Energy Charge $3,091 $1,798 $2,468 $1,317 (1995) (1995) (1995) (1995) $14,967 $10,324 (1996-2015)* (1996-2015)* Annual Capacity Charge $2,367 $1,195 $3,482 $821 (1995) (1995) (1995) (1995) $16,731 $10,484 (1996-2015)* (1996-2015)* Average Cost per KWH 3.0 5.5 5.9 4.0 (1995) (1995) (1995) (1995) 6.7 6.1 (1996-2015)** (1996-2015)** * Estimated average ** Estimated average in nominal dollars, levelized over the period indicated.
The Company's purchases pursuant to the contract with Hydro-Quebec entered into December 4, 1987, are as follows: (1) Schedule A -- 17 MW of firm capacity and associated energy to be delivered at the Highgate interconnection for five years beginning 1990; (2) Schedule B -- 68 MW of firm capacity and associated energy to be delivered at the Highgate interconnection for twenty years beginning in September 1995; and (3) Schedule C3 -- 46 MW of firm capacity and associated energy to be delivered at interconnections to be determined at a later time for 20 years beginning in November 1995. At present, the Schedule C3 purchases are being delivered over the Company's entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase I and Phase II). By use of the interconnection for Schedule C3 or other power transactions, the Company foregoes certain savings associated with other power deliveries for NEPOOL that would take place if the interconnection were not utilized for firm purchases. (Please also see description of the 1996 arrangement described below). In September 1994, the Company negotiated a renewal of a short-term "tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec delivers up to 61 MW of capacity and energy to the Company over the NEPOOL/Hydro-Quebec interconnection. The electricity purchased under this tertiary contract is priced at less than 2.5 per KWh. The benefits realized by the Company from this favorably priced electricity will be greater than those associated with deliveries foregone by the Company otherwise available over the NEPOOL/Hydro-Quebec interconnection. The most recent tertiary energy contract will expire in August 1996. The Company anticipates that purchases of tertiary energy will extend beyond August 1996, but these purchases will be subject to the availability of the Hydro-Quebec/New England interconnection. 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 $3,000,000 (in 1994 dollars) worth of research and development work from Hydro-Quebec over the four-year period, and made a $7,500,000 (in 1994 dollars) cash payment to Hydro-Quebec in 1995. The Company has exercised an option to purchase $1,000,000 worth of additional research and development work and the $7,500,000 cash payment was reduced accordingly. Hydro-Quebec retains the right to curtail annual energy deliveries by 10% 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 KWh of Schedules B and C3 combined will be cut from 6.4 to 4.2 per KWh, a 34% (or $16,000,000) cost reduction. Over the four-year period covered by the arrangement, combined unit costs will be lowered from 6.4 to 5.3 per KWh, reducing unit costs by 18% and saving $34,100,000 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. Under an arrangement negotiated in January 1996, Hydro-Quebec will provide cash payments to the Company of $3,000,000 in 1996 and $1,100,000 in 1997. In response, the Company will shift up to 40 megawatts of the 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 of 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 agreement. 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 $1,800,000, net present value. In 1995, the Company utilized 190,779.7 MWh of Hydro-Quebec energy under the July 1984 contract, 52,816.4 MWh under the December 1987 contract Schedule A, 99,017.5 Mwh under Schedule B, 49,036.0 Mwh under Schedule C3, and 332,430.6 MWh under the tertiary energy contract to meet 37.9% of its retail and requirements wholesale sales. The average cost of Hydro-Quebec electricity in 1995 was 3.8 per KWh. See Notes J and K-2 of Notes to Consolidated Financial Statements. New York Power Authority (NYPA). The Department allocates NYPA power to the Company who, in turn, delivers the power to its residential and farm customers. The Company purchased at wholesale 1,743.6 MWh to meet 0.1% of its retail and requirements wholesale sales of NYPA power at an average cost of 1.1 per KWh in 1995. Under the allocation currently made by NYPA of NYPA power to states neighboring New York, the amount of such power delivered to residential and farm customers in the Company's service territory will be as follows: Entitlements to Customers in the Company's Period Service Territory (MW) ------ ------------------------- July 1995 - June 1996 0.3 July 1996 - June 1997 0.3 July 1997 - June 1998 0.3 Merrimack Unit #2. Merrimack Unit #2 is a coal-fired steam plant of 356-MW capacity located in Bow, New Hampshire, and owned by Northeast Utilities. The Company is entitled to 30.457 MW of capacity and related energy from the unit under a 30-year contract terminating May 1, 1998. During the year ended December 31, 1995, the Company utilized 194,709.2 MWh from the unit to meet 10.2% of its total retail and requirements wholesale sales. The average cost of electricity from this unit was 3.0 per KWh in 1995. 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 a 343.0-MW combined- cycle intermediate generating station -- Stony Brook I -- 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 30.2 MW of capacity. In addition to this entitlement, the Company has contracted for 13.8 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 1995, the Company utilized 35,778.0 MWh from this plant to meet 1.8% of its retail and requirements wholesale sales at an average cost of 5.4 per Kwh, the portion of these costs attributable to the 30.2 MW joint ownership share are based only on operation, maintenance, and fuel costs incurred in 1995. See Note I-3 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 619 MW. The construction of this plant was sponsored by Central Maine Power Company. The Company has a joint-ownership share of 1.1% (7.1 MW) in the Wyman #4 unit, which began commercial operation in December 1978. During 1995, the Company utilized 4,037.1 MWh from this unit to meet 0.2% of its retail and requirements wholesale sales at an average cost of 4.4 per Kwh, based only on operation, maintenance, and fuel costs incurred during 1995. See Note I-3 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 53.6 MW. The Company has an 11% or 5.9 MW interest in the J. C. McNeil plant, which began operation in June 1984. During 1995, the Company utilized 9,051.2 MWh from this unit to meet 0.5% of its retail and requirements wholesale sales at an average cost of 4.6 per Kwh, based only on operation, maintenance, and fuel costs incurred during 1995. In 1989, the plant added the capability to burn natural gas on an as-available/interruptible service basis. See Note I-3 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 Power Exchange, Inc. (VPEX), 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 32.4% or 48.7 MW. The rated capacity of the qualifying facilities currently selling power to VPEX 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 and value for additional qualifying facilities. The Company and some utilities and producers have formed Vermont Electric Power Producers, Inc. (VEPPI) to be the purchasing agent for electricity produced by qualifying facilities in Vermont. VEPPI and three other entities have sought VPSB approval to succeed VPEX. In late 1995, the VPSB's Hearing Examiner recommended that VEPPI be selected to perform this function for a five-year term that will begin in 1996. The VPSB has accepted this recommendation. The Company estimates that purchasing agent operations under VEPPI will save the Company about $70,000 per year. In 1995, the Company, through both its direct contracts and the Vermont Power Exchange, purchased 105,038.1 MWh of qualifying facilities production to meet 5.5% of its retail and requirements wholesale sales at an average cost of 10.4 per KWh. Short-Term Opportunity Purchases and Sales. The Company has made arrangements with several utilities in New England and New York whereby 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. The price is set so as to recover the forecasted fuel and capacity costs. During 1995, the Company purchased 143,063.6 MWh, 7.5% of the Company's retail and requirements wholesale sales, at an average cost of 2.4 per KWh under such arrangements. 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 the Pool, but which is lower than the reserve which would be required if the Company were not a Pool participant. Company Hydroelectric Power. The Company wholly owns and operates eight hydroelectric generating facilities, the largest of which has a generating output of 8.8 MW, located on river systems within its service area. In 1995, these plants provided 110,503.1 MWh of low-cost energy, meeting 5.8% of the Company's retail and requirements wholesale sales at an average cost of 0.7 per Kwh, based only on operation, maintenance, and fuel costs incurred in 1995. See "State and Federal Regulation." 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. The Company has entered into agreements for a unit sale of power to Fitchburg Gas and Electric Light Company of 10 MW of Vermont Yankee capacity and associated energy from September 1, 1990 through October 31, 1996. In 1986, the Company entered into an agreement for the sale to UNITIL 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 1995, the Company's retail and requirements wholesale sales were provided by the following fuel sources: 46.4% from hydro (5.8% Company-owned, 0.1% NYPA, 37.9% Hydro-Quebec and 2.6% small power producers), 30.4% from nuclear, 10.2% from coal, 3.3% from wood, 1.5% from natural gas, and 0.7% from oil. The remaining 7.5% 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 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 1995, Vermont Yankee accumulated approximately $66,000,000 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 1995, and, while no assurance can be given, does not anticipate any such difficulty during 1996. None of the utilities from which the Company expects to purchase oil- or gas-fired capacity in 1996 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 by 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. The sponsor of Merrimack advises that, as of March 11, 1996, there were 154,000 tons of coal at the plant. 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 196,626 tons of wood chips and mill residue and 130,703,000 cubic feet of gas in 1995. The McNeil plant is forecasting consumption of wood chips for 1996 to be 150,000 tons and gas consumption of 300,000,000 cubic feet. Burlington Electric Department advises that, as of February 24, 1996, there were 17,550 tons of wood chips in inventory for the McNeil plant. 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. FUTURE POWER RESOURCES 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 United States Department of Energy (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, which will be located in the southern Vermont towns of Searsburg and Readsboro, is estimated to be $10,100,000. The Company estimates that it will spend approximately $8,700,000 on this project in 1996. The new wind facility will consist of eleven wind turbines and will generate 6 MW of electricity. In May 1995, the Company filed an application with the VPSB seeking a Certificate of Public Good for the wind project. In late January 1996, a hearing officer for the VPSB recommended that the Company be awarded the Certificate of Public Good to allow the Company to construct its proposed wind facility in Searsburg. The Company hopes to begin construction in the spring of 1996 and to have the facility in operation by year end. The Company has selected Zond Development Corporation of Tehachapi, California, to supply the wind turbines. Zond will install eleven 550 kilowatt wind turbines (model Z-40) at the Searsburg site. The wind turbines were developed by Zond in conjunction with the DOE Value Engineered Turbine project. The Z-40 currently is the largest wind turbine commercially produced in the United States. 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 offers 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 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 percent 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. STATE AND FEDERAL REGULATION General. The Company is subject to the regulatory authority of the VPSB, which extends to retail rates, services, facilities, securities issues and various other matters. The separate Vermont Department of Public Service, created by statute in 1981, is responsible for development of energy supply plans for 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. Vermont law pertaining to rate proceedings of the Company provides that the rates as filed become final and effective seven months after suspension of the filed rates (which can occur within 45 days of filing) if the VPSB fails to act on the permanent rate request by that time. Once filed, a request for permanent rate relief may not be amended or supplemented except upon approval of the VPSB after hearing. The VPSB must consider an application for and, in appropriate circumstances, order temporary rate relief pending a decision. If the VPSB fails to act on an application for temporary rate relief within 30 days, or within 45 days after suspension of the permanent rate request, the temporary rates take effect. If temporary relief is ordered, revenues recovered are subject to refund. 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 is part of the rate settlement currently before the VPSB referenced above. The Company's wholesale rate on sales to four wholesale customers is regulated by the FERC. Revenues from sales to these customers were approximately 0.9% of operating revenues for 1995. 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 22,777 MWh and peak requirements by approximately 6 MW. Revenues in 1995 from Northfield were $1,263,265. 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% of the Company's operating revenues for 1995. By reason of its relationship with Vermont Yankee, VELCO and VETCO, the Company has filed an exemption statement under Section 3(a)(2) of the Public Utility Holding Company Act, 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 of Vermont. 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 was published in June 1995. It was developed in a manner consistent with the Department's Plan. The 1995 Integrated Resource Plan calls for a greater emphasis on distributed utility approaches that can best use the Company's assets, maximize the benefit of demand-side management programs, and provide customers with the highest quality service. ENVIRONMENTAL MATTERS In recent years, public concern for the physical environment has brought about increased government regulation of the licensing and operation of electric generation, transmission and distribution facilities. The Company must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. Subject to the results of developments discussed below concerning the Pine Street Marsh site in Burlington, Vermont, 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. Because the regulations and requirements under existing legislation have not been fully promulgated (and, when promulgated, are subject to revision), because permits and licenses when issued may be conditional or may be subject to renewal and because additional legislation may be adopted in the future, the Company cannot presently forecast the costs or other effects which environmental regulation may ultimately have upon its existing and proposed facilities and operations. In 1982, the United States Environmental Protection Agency (EPA) notified the Company that the EPA, pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), was considering spending public funds to investigate and take corrective action involving claimed releases of allegedly hazardous substances at a site identified as the Pine Street Marsh in Burlington, Vermont. On part of this site was located a manufactured-gas facility owned and operated by a number of separate enterprises, including the Company, from the late 19th century to 1967. In its notice, the EPA stated that the Company may be a "potentially responsible party" (PRP) under CERCLA from which reimbursement of costs of investigation and of corrective action may be sought. On February 23, 1988, the Company received a Special Notice letter from the EPA stating that the letter constituted a formal demand for reimbursement of costs, including interest thereon, that were incurred and were expected to be incurred in response to the environmental problems at the site. On December 5, 1988, the EPA brought suit against the Company, New England Electric System, and Vermont Gas Systems, Inc. in the United States District Court for the District of Vermont seeking reimbursement for costs it incurred in conducting activities in 1985 to remove allegedly hazardous substances from the site, and requested a declaratory judgment that the Company and the other defendants are liable for all costs that have been incurred since the removal and that continue to be incurred in responding to claims of releases or threatened releases from the Maltex Pond Area -- the portion of the site where the removal action occurred. The complaint specifically alleged that the EPA expended at least $741,000 during the 1985 removal action and sought interest on this amount from the date the funds were expended and costs of litigation, including attorneys' fees. The Company entered a cross-claim against New England Electric System and third-party claims against UGI Corporation, Southern Union Corporation, the State of Vermont, and an individual property owner at the site for recovery of its response costs and for contribution. Fourth-party defendants subsequently were joined. In July 1990, the Company and other parties signed a proposed Consent Decree settling the removal action litigation. All 14 settling defendants contributed to the aggregate settlement amount of $945,000. Individual contributions were treated as confidential under the proposed Consent Decree. On December 26, 1990, upon the unopposed motion of the United States, the Consent Decree was entered by the Court. During the summer and fall of 1989, the EPA conducted the initial phase of the Remedial Investigation (RI) and commenced the Feasibility Study (FS) relating to the site. In the fall of 1990 and in 1991, the EPA conducted a second phase of RI work and studied the treatability of soils and groundwater at the site. In the fall of 1991, the EPA responded favorably to a request from the Company and other PRPs to participate in informal discussions on the EPA's ongoing investigation and evaluation of the site, and invited the Company and other interested parties to share technical information and resources with the EPA that might assist it in evaluating remedial options. On November 6, 1992, the EPA released its final RI/FS and announced a proposed remedy with an estimated present value total cost of approximately $47,000,000. This amount included 30 years' estimated operation and maintenance costs, with a net present value of approximately $26,400,000. The EPA's preferred remedy called for construction of a Containment/Disposal Facility (CDF) over a portion of the site. The CDF would have consisted of subsurface vertical barriers and a low permeability cap, with collection trenches and hydraulic control system to capture groundwater and prevent its migration outside of the CDF. Collected groundwater would have been treated and discharged or stored and disposed of off-site. The proposed remedy also would have required construction of new wetlands to replace those that would be destroyed by construction of the CDF and a long-term monitoring program. On or before May 15, 1993, the PRP group in which the Company participated submitted extensive comments to the EPA opposing the proposed remedy. In response to an earlier request from the EPA, the PRP group also submitted a detailed analysis of an alternative remedy anticipated to cost approximately $20,000,000. In early June, in response to overwhelming negative comment, the EPA withdrew its proposed remedy and announced that it would work with all interested parties in developing a new proposal. Since then, the EPA has established a coordinating council, with representatives of PRPs, environmental groups, and government agencies, and presided over by a neutral facilitator. The council is charged with determining what additional studies may be appropriate for the site and also is planning to eventually address additional response activities. In July 1994, the Company, New England Electric System (NEES), and Vermont Gas Systems, Inc. (VGS), entered into an Administrative Order by Consent, with the EPA, pursuant to which these PRPs are conducting certain additional studies that have been agreed to by the coordinating council. These studies constitute the first phase of action the council has decided on to fill data gaps at the site. A second phase, including tasks carried over from the first phase, additional field studies and preparation of an addendum feasibility study was begun during 1995 by the same parties under a second Order. The EPA has not required reimbursement for its past RI/FS study costs as a condition to allowing the PRPs to conduct these additional studies. The EPA has previously advised the Company that ultimately it will seek to hold the Company and the PRPs liable for such costs. These costs have been estimated to be at least $4,500,000, but the Company has sufficient reserves on its balance sheet to cover such costs. On December 1, 1994, the Company, NEES and VGS entered into a confidential agreement with the State, the City of Burlington and nearly all other landowner PRPs under which 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, and also entered into a confidential agreement with NEES for funding of work under the Order. In December 1991, the Company brought suit against several previous insurers seeking recovery of unrecovered past costs and indemnity against future liabilities associated with environmental problems at the site. Discovery in the case is largely complete, with the exception of expert discovery, which was stayed by the magistrate pending the resolution of Summary Judgment Motions filed by the Company. In August 1994, the Magistrate granted the Company's Motion for Summary Judgment with respect to defense costs against one defendant and denied it against another defendant. The United States District Judge affirmed those orders on September 30, 1994. The Company has reached confidential settlements with two of the defendants in its insurance litigation. One of these defendants provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 to 1984. These policies were in place in 1982 when the EPA first notified the Company that it might be a potentially responsible party at the Pine Street Marsh site. The other defendant provided the Company with second layer excess liability coverage for a seven-month period in 1976. The Company has deferred amounts received from third parties pending resolution of the Company's ultimate liability with respect to the site and rate recognition of that liability. The Company is unable to predict at this time the magnitude of any liability resulting from potential claims for the costs of the RI/FS or the performance of any remedial action, 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 and 1994, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its unrecovered expenditures between January 1991 and June 30, 1994 (in the total of approximately $7,300,000) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street Marsh related costs, the Company and the Vermont Department of Public Service (the Department) reached agreements in these cases that the full amount of Pine Street Marsh costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, on May 13, 1994, and on June 5, 1995, reflected the Pine Street Marsh related expenditures referred to above. In a rate case filed on September 15, 1995, the Company sought recovery in rates of approximately $1,300,000 in expenses associated with the Pine Street site. This amount represented the Company's unrecovered expenditures between July 1994 and June 1995 for technical consultants and legal assistance in connection with 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 Pine Street related costs (and whether recovery or non-recovery of past costs and any insurance proceeds is relevant to such issue), the parties to the case have reached agreement that the full amount of Pine Street costs reflected in the Company's 1995 rate case should be recovered in rates. This agreement is currently pending before the VPSB. Management expects to seek and (assuming treatment consistent with the previous regulatory treatment set forth above) receive ratemaking treatment for unreimbursed costs incurred beyond the amounts for which ratemaking treatment has been received. COMPETITION The Company serves a fixed area of Vermont under a VPSB franchise. Except as noted below, the Company's electric business is substantially free from competition for retail customers from other electric utilities, municipalities and other public agencies in its franchise area, as mandated by the VPSB. The Company, however, competes with other providers of energy for the home-heating market. Wood stoves, oil-burning furnaces and natural gas represent the principal alternatives to electric heat for customers in the Company's service territory. Fluctuations in the price of fossil fuels, especially oil and natural gas, affect the Company's position in the home-heating market. 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 facilitate competition for electricity sales at the wholesale and retail levels. On October 24, 1994, the VPSB and the Department convened a "Roundtable on Competition and the Electric Industry," consisting of representatives of utilities (including the Company), customers, environmental groups and other affected parties. On July 17, 1995, a subgroup of the Roundtable agreed on a set of fourteen 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 utility industry. The Governor's announcement included proposed legislative adoption of restructuring principles in 1996, a VPSB proceeding to address the issue, filing by Vermont electric utilities of detailed plans by May 1, 1996, and implementation of restructuring by the end of 1997. 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. Increased competitive pressure in the electric utility industry may restrict the Company's ability to charge prices high enough to recover embedded costs and may lead to changes in the manner in which rates are set by regulators from cost-based regulation to a different form of regulation that approximates market conditions -- in which prices charged could be higher or lower than the Company's costs. BUSINESS DEVELOPMENT The Company has a plan of diversification into energy-related businesses intended to complement the Company's basic utility enterprise. These businesses are conducted through two subsidiaries, Green Mountain Propane Gas Company and Mountain Energy, Inc., and the Company's unregulated rental water heater activities. The Company plans to limit such diversification to 20% of the Company's consolidated revenue. The Company consolidates the balance sheet of four of its wholly owned subsidiaries, Green Mountain Propane Gas Company, Mountain Energy, Inc., GMP Real Estate Corporation, and Lease-Elec, Inc. Included in equity in earnings of affiliates and non-utility operations in the Other Income section of the Statements of Consolidated Income are the results of operations of the Company's rental water heater program which is not regulated by the VPSB, and the four unregulated wholly owned subsidiaries named above. Summarized financial information of the Company's unregulated activities over the last three years is as follows: For the years ended December 31 1995 1994 1993 ---- ---- ---- (In thousands) Revenue . . . . . . . . . . . . . . . $11,905 $12,031 $11,487 Expense . . . . . . . . . . . . . . . 10,416 10,920 11,527 ------- ------- --------- Net Income (Loss) . . . . . . . . . . $ 1,489 $ 1,111 ($ 40) ======= ======= ========= EMPLOYEES The Company had 350 employees, exclusive of temporary employees, as of December 31, 1995. In addition, subsidiaries of the Company had 50 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 1995 peak of 297.1 MW occurred on February 6, 1995. 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 discussion -- Demand-Side Management -- Rate Design. EXECUTIVE OFFICERS Executive Officers of the Company as of March 31, 1996: Name Age Douglas G. Hyde 53 President, Chief Executive Officer and Chairman of the Executive Committee of the Corporation since 1993. Executive Vice President, Chief Operating Officer and Director from 1989 to 1993. Executive Vice President and Director of the Corporation from 1986 to 1989. A. Norman Terreri 62 Executive Vice President and Chief Operating Officer since January 1995. Senior Vice President and Chief Operating Officer from 1993 to 1995. Senior Vice President from 1984 to 1993. President - Mountain Energy, Inc. since December 1989. Edwin M. Norse 50 Vice President and General Manager, Energy Resources and Sales since January 1995. Vice President, Chief Financial Officer and Treasurer from 1986 to January 1995. President-Green Mountain Propane Gas Company since October 1993. Christopher L. Dutton 47 Vice President, Finance and Administration, Chief Financial Officer and Treasurer since January 1995. Vice President and General Counsel from 1993 to January 1995. Vice President, General Counsel and Corporate Secretary from 1989 to 1993. General Counsel and Corporate Secretary from 1984 to 1989. Glenn J. Purcell 62 Controller since September 1986. Thomas C. Boucher 41 Vice President, Energy Resources and Planning since January 1995. Vice President- Corporate Planning from 1994 to 1995. Vice President, Financial Planning from 1992 to 1994. Assistant Vice President-Energy Planning from 1986 to 1992. Stephen C. Terry 53 Vice President and General Manager, Retail Energy Services since January 1995. Vice President-External Affairs from 1991 to January 1995. Assistant Vice President- Corporate Relations from 1986 to 1991. Walter S. Oakes 49 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. Robert C. Young 58 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. Karen K. O'Neill 44 Assistant Vice President-Human Resources and Organizational Development since January 1995. Assistant General Counsel from 1989 to 1995. Senior Attorney from 1988 to 1989. Craig T. Myotte 41 Assistant Vice President-Engineering and Operations since 1994. Assistant Vice President-Operations and Maintenance from 1991 to 1994. Director-System Operations from 1986 to 1991. John J. Lampron 51 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. Donna S. Laffan 46 Corporate Secretary since December 1993. Assistant Secretary from 1986 to 1993. Peter H. Zamore 43 General Counsel since January 1995. Prior to joining the Company, he was a partner at the law firm of Sheehey Brue Gray & Furlong, P.C. from 1984 to 1995. Officers are elected by the Board of Directors for one-year terms and serve at the pleasure of the Board 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 36.4 MW and an estimated claimed capability of 35.7 MW. It also owns two gas-turbine generating stations with an aggregate nameplate rating of 63.0 MW and an estimated aggregate claimed capability of 72.8 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 also owns 17.9% of the outstanding common stock, and is entitled to 17.265% (90.1 MW) of the capacity of Vermont Yankee, a 1.1% (7.1 MW) joint-ownership share of the Wyman #4 plant located in Maine, a 8.8% (30.2 MW) joint-ownership share of the Stony Brook I intermediate units located in Massachusetts and an 11% (5.8 MW) joint-ownership share of theJ. C. McNeil wood-fired steam plant located in Burlington, Vermont. (See "Power Resources" under Item 1 above for plant details and the table hereinafter set forth for generating facilities presently available). TRANSMISSION AND DISTRIBUTION The Company had, at December 31, 1995, 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 included about 2,374 miles of overhead lines, 2.4 kV to 34.5 kV, and about 418 miles of underground cable of 2.4 kV to 34.5 kV. At such date, the Company owned approximately 435,550 kVa of substation transformer capacity in distribution substations, 156,775 kVa of transformer capacity in transmission substations and 1,154,161 kVa of transformers for stepdown from distribution to customer use. The Company owns 33.8% of the Highgate transmission intertie, a 200-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 "Power Resources" in Item 1. 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 57.1 Turbine Colchester, VT Gorge #16 Oil 15.7 Jointly Owned Steam Vernon, VT Vermont Yankee Nuclear 91.7(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 253.1 (1) Winter capability quantities are used since the Company's peak usage occurs during the winter months. Some units are derated for the summer months. 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 "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-2 of Notes to Consolidated Financial Statements. ITEM 3. LEGAL PROCEEDINGS See the discussion under "Environmental Matters" in Item 1 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. The following tabulation shows the high and low sales prices for the Common Stock on the New York Stock Exchange during 1995 and 1994: HIGH LOW ---- --- 1995 First Quarter 28 1/4 24 7/8 Second Quarter 27 24 3/4 Third Quarter 27 1/8 23 7/8 Fourth Quarter 28 5/8 27 3/4 1994 First Quarter 31 1/4 27 1/2 Second Quarter 30 23 3/4 Third Quarter 27 3/8 23 3/8 Fourth Quarter 28 1/8 23 7/8 The number of common stockholders of record as of March 15, 1996 was 8,601. Quarterly cash dividends were paid as follows for the past two years: First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- 1995 53 cents 53 cents 53 cents 53 cents 1994 53 cents 53 cents 53 cents 53 cents
ITEM 6. SELECTED FINANCIAL DATA (In thousands except per share amounts) Results of operations for the years ended December 31 - ----------------------------------------------------- 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- Operating Revenues........................$161,544 $148,197 $147,253 $145,240 $143,555 Operating Expenses........................ 146,249 133,680 132,427 128,828 129,041 --------- --------- --------- --------- --------- Operating Income........................ 15,295 14,517 14,826 16,412 14,514 --------- --------- --------- --------- --------- Other Income AFUDC - equity.......................... 27 263 273 186 225 Other................................... 3,607 3,418 2,360 2,073 2,689 --------- --------- --------- --------- --------- Total other income.................... 3,634 3,681 2,633 2,259 2,914 --------- --------- --------- --------- --------- Interest Charges AFUDC - borrowed funds.................. (547) (539) (357) (202) (131) Other................................... 7,973 7,735 7,185 7,021 7,103 --------- --------- --------- --------- --------- Total interest charges................ 7,426 7,196 6,828 6,819 6,972 --------- --------- --------- --------- --------- Net Income................................ 11,503 11,002 10,631 11,852 10,456 Dividends on Preferred Stock.............. 771 794 811 831 852 --------- --------- --------- --------- --------- Net Income Applicable to Common Stock..... $10,732 $10,208 $9,820 $11,021 $9,604 ========= ========= ========= ========= ========= Common Stock Data Earnings per share...................... $2.26 $2.23 $2.20 $2.54 $2.45 Cash dividends declared per share....... $2.12 $2.12 $2.11 $2.08 $2.04 Weighted average shares outstanding..... 4,747 4,588 4,457 4,345 3,919 Financial Condition as of December 31 - ------------------------------------- 1995 1994 1993 1992 1991 --------- --------- --------- --------- --------- Assets Utility Plant, Net.......................$181,999 $175,987 $171,411 $164,723 $159,730 Other Investments........................ 20,248 20,751 22,528 21,700 21,624 Current Assets........................... 30,216 28,798 26,215 28,067 26,778 Deferred Charges......................... 42,951 35,659 33,893 19,012 11,271 Non-Utility Assets....................... 37,868 33,416 28,626 23,716 19,832 --------- --------- --------- --------- --------- Total Assets............................$313,282 $294,611 $282,673 $257,218 $239,235 ========= ========= ========= ========= ========= Capitalization and Liabilities Common Stock Equity......................$106,408 $101,319 $97,149 $92,645 $87,455 Redeemable Cumulative Preferred Stock.... 8,930 9,135 9,385 9,575 9,825 Long-Term Debt, Less Current Maturities.. 91,134 74,967 79,800 67,644 56,270 Capital Lease Obligation................. 9,778 10,278 11,029 11,950 12,627 Curent Liabilities....................... 32,629 40,441 37,925 30,099 32,893 Deferred Credits and Other............... 52,041 49,434 40,214 33,264 29,694 Non-Utility Liabilities.................. 12,362 9,037 7,171 12,041 10,471 --------- --------- --------- --------- --------- Total Capitalization and Liabilities....$313,282 $294,611 $282,673 $257,218 $239,235 ========= ========= ========= ========= =========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Earnings Summary -- Earnings per average share of common stock in 1995 were $2.26 as compared with $2.23 in 1994. The 1995 earnings represent an earned return on average common equity of 10.3 percent. In both 1994 and 1993, the earned return on average common equity was also 10.3 percent. The 1995 increase in earnings was primarily due to higher retail revenues resulting from a 9.25 percent retail rate increase that went into effect in June 1995, increased sales of electricity to the Company's commercial and industrial customers, and a $557,000 increase in the earnings of Mountain Energy, Inc., the Company's wholly-owned subsidiary that invests in electric energy generation and efficiency projects. The principal factor contributing to the increase in 1994 was a $722,000 increase in earnings of Mountain Energy, Inc. and a $523,000 increase in earnings of Green Mountain Propane Gas Company, the Company's wholly- owned propane subsidiary. Operating Revenues and MWH Sales -- Operating revenues and MWH sales for the years 1995, 1994 and 1993 consisted of: 1995 1994 1993 ---- ---- ---- (Dollars in Thousands) Operating Revenues: Retail . . . . . . . . . . . . . $ 140,676 $ 131,444 $ 130,061 Sales for Resale . . . . . . . . 17,541 13,521 14,441 Other . . . . . . . . . . . . . 3,327 3,232 2,751 ---------- ---------- ---------- Total Operating Revenues . . . . . $ 161,544 $ 148,197 $ 147,253 ========== ========== ========== Megawatthour Sales: Retail . . . . . . . . . . . . . 1,723,117 1,691,867 1,688,803 Sales for Resale . . . . . . . . 620,655 367,424 331,875 --------- --------- --------- Total Megawatthour Sales . . . . . 2,343,772 2,059,291 2,020,678 ========= ========= ========= Average Number of Customers: Residential . . . . . . . . . . 69,659 68,811 67,994 Commercial & Industrial . . . . 11,736 11,635 11,472 Other . . . . . . . . . . . . . 76 76 74 ------ ------ ------ Total Customers . . . . . . . . . . 81,471 80,522 79,540 ====== ====== ====== Differences in operating revenues were due to changes in the following: 1994 1993 to to 1995 1994 ---- ---- (In Thousands) Operating Revenues: Retail Rates . . . . . . . . . . . . . . . $ 6,619 $1,140 Retail Sales Volume . . . . . . . . . . . 2,613 244 Resales and Other Revenues . . . . . . . . 4,115 (440) ------- ------- Increase in Operating Revenues . . . . . . . $13,347 $ 944 ======= ======= In 1995, total electricity sales increased 13.8 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 9.0 percent in 1995 primarily due to a 9.25 percent retail rate increase that went into effect in June 1995 and the increase in electricity sales mentioned above. Total retail revenues increased 7.0 percent in 1995 primarily due to the 9.25 percent retail rate increase mentioned above. Wholesale revenues increased 29.7 percent in 1995 primarily due to the regional market conditions mentioned above. In 1994, total electricity sales increased 1.9 percent due principally to colder than normal winter weather in the first quarter and warmer than normal summer weather. Total operating revenues increased 0.6 percent in 1994 due principally to a 2.9 percent rate increase that was effective in June 1994. Wholesale revenues decreased 6.4 percent in 1994 due principally to the greater availability of low-cost energy in New England, which drove down wholesale prices. IBM, the Company's single largest customer, operates manufacturing facilities in Essex Junction. IBM's electricity requirements for its main plant and an adjacent plant accounted for 12.9, 13.7 and 13.6 percent of the Company's operating revenues in 1995, 1994 and 1993, respectively. No other retail customer accounted for more than one percent of the Company's revenue. Power Supply Expenses -- Power supply expenses constituted 60.1 percent, 59.2 percent and 59.7 percent of total operating expenses for the years ended 1995, 1994 and 1993, respectively. These expenses increased by $8.7 million (11.0 percent) in 1995 and by $190,000 (0.2 percent) in 1994. Power supply expenses increased in 1995 as the Company produced and purchased additional power to service increased electricity sales. Power supply expenses were virtually unchanged in 1994 from 1993. Other Operating Expenses -- Other operating expenses increased 4.8 percent in 1995 primarily due to an increase in rent expense and expenses relating to customer-focused research. Other operating expenses were virtually unchanged in 1994 from 1993. Transmission Expenses -- Transmission expenses decreased 4.8 percent in 1995 primarily due to cost reduction measures implemented by VELCO. The Company's restructuring of a series of transmission contracts produced a 3.7 percent decrease in transmission expenses in 1994. Maintenance Expenses -- Maintenance expenses decreased 5.7 percent in 1995 primarily due to cost containment measures implemented by the Company. Maintenance expenses increased 2.6 percent in 1994 due principally to a scheduled increase in plant maintenance. Depreciation and Amortization -- Depreciation and amortization expenses increased 32.1 percent in 1995 primarily due to the amortization of expenditures related to energy conservation programs and the Pine Street Marsh environmental matter and insurance litigation (discussed in Note I of the Notes to Consolidated Financial Statements) and to additional investment in the Company's utility plant. Depreciation and amortization expenses increased 24.6 percent in 1994 for the same reasons. Income Taxes -- The effective federal tax rates for the years 1995, 1994 and 1993 were 25.3 percent, 25.1 percent and 28.9 percent, respectively. Other Income -- Other income decreased 1.3 percent in 1995 primarily due to a decrease in the allowance for equity funds used during construction resulting from lower average construction work in progress balances and an increase in short-term debt outstanding during the year and a $389,000 decrease in earnings experienced by Green Mountain Propane Gas Company, the Company's wholly-owned propane subsidiary. These decreases were partially offset by a $557,000 increase in earnings of Mountain Energy, Inc. Additionally, other income in 1994 benefited from a one- time increase of $162,000 resulting from a Vermont Supreme Court ruling overturning a Vermont Public Service Board (VPSB) decision disallowing certain DSM costs. Other income increased 39.8 percent in 1994 due primarily to a $722,000 increase in earnings of Mountain Energy, Inc., and a $523,000 increase in earnings of Green Mountain Propane Gas Company. Interest Charges -- Interest charges increased 3.2 percent in 1995 primarily due to interest charges related to an increase in short-term debt outstanding during 1995. These charges were partially offset by a reduction in interest charges related to a decrease in long-term debt outstanding during 1995. Interest charges increased 5.4 percent in 1994 due primarily to interest charges related to the sale of $20 million of first mortgage bonds in November 1993 and to an increase in short-term debt outstanding during 1994. Dividends on Preferred Stock -- Dividends on preferred stock decreased 2.9 percent in 1995 due primarily to the repurchase by the Company in 1994 of the following preferred stock: 450 shares of 4.75 percent, Class B; 450 shares of 7 percent, Class C, and 1,600 shares of 9.375 percent, Class D, Series 1. Dividends on preferred stock decreased 2.1 percent in 1994 due primarily to the repurchase by the Company in 1993 of the following preferred stock: 300 shares of 4.75 percent, Class B and 1,600 shares of 9.375 percent, Class D, Series 1. Future Outlook -- 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 VPSB and the Vermont Department of Public Service (the Department) convened a "Roundtable on Competition and the Electric Industry," consisting of representatives of utilities (including the Company), customers, environmental groups and other affected parties. On July 17, 1995, a subgroup of the Roundtable agreed on a set of fourteen 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 utility industry. The Governor's announcement included proposed legislative adoption of restructuring principles in 1996, a VPSB proceeding to address the issue, filing by Vermont electric utilities of detailed plans by May 1, 1996, and implementation of restructuring by the end of 1997. 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. Increased competitive pressure in the electric utility industry may restrict the Company's ability to charge prices high enough to recover embedded costs and may lead to changes in the manner in which rates are set by regulators from cost-based regulation to a different form of regulation that approximates market conditions -- in which prices charged could be higher or lower than the Company's costs. 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 legislation. Furthermore, only one of its power supply purchase contracts, which expires in 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 1998) is expected to be affected by federal and State environmental compliance requirements. The Company continues to implement conservation programs to mitigate the increasing demand for electricity. The Company is reviewing its future conservation plans in light of various factors, including competition, changing avoided electricity costs, its experience and increased effectiveness in delivering conservation programs, and its total resource mix. Even with continued existing conservation programs, the Company anticipates, assuming normal weather, that the demand for electricity in its service territory will grow by approximately 1.2 percent per year over the next five years. The Company regularly reviews rates and forecasts costs. As these forecasts change, the Company will seek changes in rates that will enable it to recover operating costs. 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. Diversification -- The Company has a plan of diversification into energy-related businesses intended to complement the Company's basic utility enterprise. The Company plans to limit diversification to 20 percent of the Company's consolidated revenue. Mountain Energy, Inc. performed well in 1995, producing an after-tax profit of $1.38 million, an increase of $557,000 from 1994, and contributed 29 cents of earnings per share to the Company's consolidated earnings. During the year, Mountain Energy made new, long-term investments totaling $4.4 million in a New England hydroelectric facility and in energy-efficiency projects in New England, California, New York and New Jersey. Mountain Energy has now invested almost $16 million in nine different projects, eight of which are renewable-energy related. The Company's cash investment in Mountain Energy at December 31, 1995 was $10.7 million. Environmental Matters -- In recent years, public concern for the physical environment has brought about increased government regulation of the licensing and operation of electric generation, transmission and distribution facilities. 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 the results of developments discussed in Note I.1 of Notes to Consolidated Financial Statements concerning the Pine Street Marsh site in Burlington, Vermont, 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. Through rate cases filed in 1991, 1993 and 1994, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its unrecovered expenditures between January 1991 and June 30, 1994 (a total of approximately $7.3 million) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street Marsh related costs, the Company and the Department reached agreements in these cases that the full amount of Pine Street Marsh costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, on May 13, 1994, and on June 5, 1995, reflected the Pine Street Marsh related expenditures referred to above. In a rate case filed on September 15, 1995, the Company sought recovery in rates of approximately $1.3 million in expenses associated with the Pine Street site. This amount represented the Company's unrecovered expenditures between July 1994 and June 1995 for technical consultants and legal assistance in connection with 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 Pine Street related costs (and whether recovery or non-recovery of past costs and any insurance proceeds is relevant to such issue), the parties to the case have reached agreement that the full amount of Pine Street costs reflected in the Company's 1995 rate case should be recovered in rates. This agreement is currently pending before the VPSB. Management expects to seek and (assuming treatment consistent with the previous regulatory treatment set forth above) receive ratemaking treatment for unreimbursed costs incurred beyond the amounts for which ratemaking treatment has been received. As is more fully set forth in Note I.1 of Notes to Consolidated Financial Statements, the Company is unable to predict at this time the magnitude of liability that may be imposed on it resulting from potential claims for the cost of studies undertaken by the EPA or performance of any remedial action in connection with the Pine Street Marsh site. The Company is one of several parties that the EPA has identified as potentially responsible for the cost of studying and remedying the results of releases of allegedly hazardous substances at the site. The Company will continue to pursue claims against other responsible parties seeking to ensure that they contribute appropriately to reimburse the Company for any costs incurred. In December 1991, the Company brought suit against several previous insurers seeking recovery of unrecovered past costs and indemnity against future liabilities associated with environmental problems at the site. Discovery in the case is largely complete, with the exception of expert discovery which was stayed by the magistrate pending the resolution of Summary Judgment Motions filed by the Company. In August 1994, the Magistrate granted the Company's Motion for Summary Judgment with respect to defense costs against one defendant and denied it against another defendant. The United States District Judge affirmed those orders on September 30, 1994. The Company has reached confidential settlements with two of the defendants in its insurance litigation. One of these defendants provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 to 1984. These policies were in place in 1982 when the EPA first notified the Company that it might be a potentially responsible party at the Pine Street Marsh site. The other defendant provided the Company with second layer excess liability coverage for a seven-month period in 1976. 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. The policy of the Company is to increase diversification of its power supply and other resources through various means, including power purchase and sales arrangements and relying on sources that represent relatively small additions to the Company's mix to satisfy customer requirements. This permits the Company to meet its financing needs in a flexible, orderly manner. Planned expenditures over the next five years will be primarily for distribution and conservation projects. Capital expenditures over the past three years and projected for the next five years are as follows: Total Net Actual Generation Transmission Distribution Conservation Other Expenditures - ------ ---------- ------------ ------------ ------------ ----- ------------ (Dollars in thousands and net of AFUDC and Customer Advances For Construction) 1993 $1,747 $1,605 $9,093 $8,136 $2,937 $23,518 1994 2,540 1,415 7,902 6,388 1,815 20,060 1995 2,696 1,067 8,935 4,152 2,824 19,674 Forecasted 1996 $9,530* $569 $8,496 $2,754 $6,601 $27,950 1997 899 999 8,745 2,444 3,861 16,948 1998 1,978 999 8,872 2,742 3,591 18,182 1999 2,478 999 9,084 2,643 4,895 20,099 2000 2,478 999 9,084 2,543 2,897 18,001 *Includes $8.771 million projected for wind project. Other Cash Requirements -- In 1996, the Company may devote $3 million to unregulated investments. Rates -- On September 26, 1994, the Company filed a request with the VPSB to increase retail rates by 13.9 percent. The increase was needed primarily to cover the rising cost of existing power sources, the cost of new power sources the Company has secured to replace power supply that will be lost in the near future, and the cost of energy efficiency programs the Company has implemented for its customers. The Company, the Department, and the other parties in the proceeding reached a settlement agreement providing for a 9.25 percent retail rate increase effective June 15, 1995, and a target return on equity of 11.25 percent. The agreement was approved by the VPSB on June 9, 1995. On September 15, 1995, the Company filed a request with the VPSB to increase retail rates by 12.7 percent. The increase is needed to cover higher power supply costs, to support additional investment in plant and equipment, to fund expenses associated with the Pine Street site, and to cover higher costs of capital. The Company and the Department reached a settlement agreement providing for a 5.25 percent retail rate increase effective June 1, 1996, and a target return on equity for utility operations of 11.25 percent. The settlement was based on a newly negotiated agreement with Hydro-Quebec that will result in a reduction of the Company's power supply costs below that which was anticipated, allowing the Company to reduce the amount of its rate request. The rate settlement must be reviewed and approved by the VPSB before it can take effect. Financing and Capitalization -- For the period 1993 through 1995, internally generated funds, after payment of dividends, provided approximately 59 percent of total capital requirements for construction, sinking funds and other requirements. The Company anticipates that for the period 1996-2000, internally generated funds will provide approximately 73 percent of total capital requirements. In December 1995, the Company sold $24 million of its first mortgage bonds in three components -- $8 million at an interest rate of 6.21 percent that will mature in 2001, $8 million at an interest rate of 6.29 percent that will mature in 2002, and $8 million at an interest rate of 6.41 percent that will mature in 2003. A portion of the proceeds of the sale was used to reduce short-term bank loans outstanding and the remainder has allowed the Company to refund preexisting long-term debt. At December 31, 1995, the Company's capitalization consisted of 49.7 percent common equity, 46.1 percent long-term debt and 4.2 percent preferred equity. The Company has a comprehensive capital plan to increase the equity component of its capital structure. During 1995, the Company took several steps toward enhancing its financial flexibility. The Company filed a shelf registration statement with the SEC which allows for the periodic sale to the public of its common stock, first mortgage bonds and unsecured notes. On December 31, 1995, $26 million was available under such registration statement. Additionally, the Company established a medium-term note program which allows for the sale of secured and unsecured debt. The Company anticipates issuing approximately $10 million of common stock and $10 million of first mortgage bonds in 1996. The proceeds will be used to retire short-term debt and for other corporate purposes. The rating of the Company's first mortgage bonds by Standard & Poor's remains at "BBB+." Standard & Poor's "outlook" of the Company remains "stable." The rating of the Company's first mortgage bonds was lowered in January 1995 by Duff & Phelps from "A" to "A-", reflecting Duff & Phelps' assessment that the electric utility industry is becoming increasingly more competitive and that the Company is highly dependent on purchased power resulting in escalating fixed payment obligations. The rating of the Company's preferred stock was also lowered from "A-" to "BBB+." Duff & Phelps, however, concluded that the Company's cost and rate structure is one of the lowest in New England. The Company's first mortgage bonds were rated publically for the first time by Moody's Investor Service in August 1995. Moody's assigned a "Baa2" rating reflecting the Company's relatively small size, its financial profile after adjustments for purchased power obligations, and expected continuation of a high dividend payout ratio. Moody's noted the Company's low rates in the Northeast region, its limited need for external financing of construction expenditures, and its prospective benefits resulting from a renegotiated arrangement with Hydro-Quebec. Moody's assigned an outlook of "stable" for the Company. See Note F of Notes to Consolidated Financial Statements for a discussion of bank lines of credit available to the Company. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA GREEN MOUNTAIN POWER CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES Page Financial Statements Statements of Consolidated Income For the Years Ended December 31, 1995, 1994 and 1993 41 Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 42 Consolidated Balance Sheets as of December 31, 1995 and 1994 43-44 Consolidated Capitalization data as of December 31, 1995 and 1994 45 Notes to Consolidated Financial Statements 46-66 Report of Independent Public Accountants 67 Schedules For the Years Ended December 31, 1995, 1994 and 1993: II Valuation and Qualifying Accounts and Reserves 68 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 81
CONSOLIDATED STATEMENTS OF INCOME GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31 1995 1994 1993 ----------------- --------------- --------------- (In thousands, except amounts per share) Operating Revenues (Note A)..................................... $161,544 $148,197 $147,253 ----------------- --------------- --------------- Operating Expenses Power Supply (Notes A, B and K) Vermont Yankee Nuclear Power Corporation................... 30,222 30,300 29,785 Company-owned generation................................... 3,786 3,113 3,150 Purchases from others...................................... 53,915 45,777 46,066 Other operating............................................... 18,120 17,296 17,353 Transmission (Note J)......................................... 9,874 10,374 10,775 Maintenance................................................... 4,210 4,465 4,352 Depreciation and amortization (Note A)........................ 14,116 10,683 8,572 Taxes other than income....................................... 6,428 6,277 6,125 Income taxes (Note G)......................................... 5,578 5,395 6,249 ----------------- --------------- --------------- Total operating expenses................................... 146,249 133,680 132,427 ----------------- --------------- --------------- Operating Income......................................... 15,295 14,517 14,826 ----------------- --------------- --------------- Other Income Equity in earnings of affiliates and non-utility operations (Note B)............................ 3,513 3,112 2,341 Allowance for equity funds used during construction (Note A).. 27 263 273 Other income and deductions, net.............................. 94 306 19 ----------------- --------------- --------------- Total other income.......................................... 3,634 3,681 2,633 ----------------- --------------- --------------- Income before interest charges............................ 18,929 18,198 17,459 ----------------- --------------- --------------- Interest Charges Long-term debt................................................ 6,546 6,868 6,539 Other......................................................... 1,427 867 646 Allowance for borrowed funds used during construction (Note A)...................................... (547) (539) (357) ----------------- --------------- --------------- Total interest charges...................................... 7,426 7,196 6,828 ----------------- --------------- --------------- Net Income...................................................... 11,503 11,002 10,631 Dividends on preferred stock.................................... 771 794 811 ----------------- --------------- --------------- Net Income Applicable to Common Stock........................... $10,732 $10,208 $9,820 ================= =============== =============== Common Stock Data (Notes A and C) Earnings per share............................................ $2.26 $2.23 $2.20 Cash dividends declared per share............................. $2.12 $2.12 $2.11 Weighted average shares outstanding........................... 4,747 4,588 4,457 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 1995 1994 1993 --------- --------- --------- (In thousands) Operating Activities: Net Income........................................................... $11,503 $11,002 $10,631 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization (Note A)........................... 14,116 10,683 8,572 Dividends from associated companies less equity income (Note B).. 660 202 254 Allowance for funds used during construction (Note A)............ (574) (803) (630) Deferred purchased power costs (Note A).......................... (12,935) (536) (6,432) Amortization of purchased power costs (Note A)................... 6,036 4,178 3,723 Deferred income taxes (Note G)................................... 3,715 1,585 5,180 Amortization of gain on sale of property......................... (53) (53) (53) Amortization of investment tax credits (Note G).................. (283) (283) (283) Environmental proceedings costs, net (Note I).................... (1,351) 7,103 (2,472) Changes in: Accounts receivable............................................ (2,841) (426) 2,384 Accrued utility revenues....................................... (510) 126 (538) Fuel, materials and supplies................................... 2 (473) 53 Prepayments and other current assets........................... 1,562 (1,982) 1,069 Accounts payable............................................... 2,191 (2,327) 513 Taxes accrued.................................................. (871) 1,044 (418) Interest accrued............................................... (106) (117) 903 Other current liabilities...................................... (22) (65) (2,745) Other............................................................ (42) 2,436 (1,883) --------- --------- --------- Net cash provided by operating activities.......................... 20,197 31,294 17,828 --------- --------- --------- Investing Activities: Construction expenditures.......................................... (15,314) (13,536) (15,949) Conservation expenditures.......................................... (3,960) (6,388) (8,136) Investment in non-utility property................................. (6,121) (1,220) (5,950) Special fund for postretirement benefits (Note A).................. -- -- (601) --------- --------- --------- Net cash used in investing activities............................ (25,395) (21,144) (30,636) --------- --------- --------- Financing Activities: Reduction in preferred stock (Note D).............................. (205) (250) (190) Issuance of common stock (Note C).................................. 4,404 3,671 4,077 Short-term debt, net (Note F)...................................... (11,799) 1,198 7,402 Issuance of long-term debt (Note E) ............................... 25,917 -- 20,000 Reduction in long-term debt (Note E)............................... (4,833) (1,800) (8,530) Cash dividends..................................................... (10,818) (10,504) (10,204) --------- --------- --------- Net cash provided by (used in) financing activities.............. 2,666 (7,685) 12,555 --------- --------- --------- Net increase (decrease) in cash and cash equivalents............... (2,532) 2,465 (253) Cash and cash equivalents at beginning of year..................... 2,692 227 480 --------- --------- --------- Cash and Cash Equivalents at End of Year............................... $160 $2,692 $227 ========= ========= ========= The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS GREEN MOUNTAIN POWER CORPORATION December 31 1995 1994 --------- --------- (In thousands) ASSETS Electric Utility Utility Plant (Notes A, E and I) Utility plant, at original cost....................$239,291 $227,991 Less accumulated depreciation...................... 75,797 69,246 --------- --------- Net utility plant................................ 163,494 158,745 Property under capital lease (Note J).............. 9,778 10,278 Construction work in progress...................... 8,727 6,964 --------- --------- Total utility plant, net......................... 181,999 175,987 --------- --------- Other Investments Associated companies, at equity (Notes A,B and I).. 16,024 16,684 Other investments (Note A)......................... 4,224 4,067 --------- --------- Total other investments.......................... 20,248 20,751 --------- --------- Current Assets Cash............................................... 84 2,113 Accounts receivable, customers and others, less allowance for doubtful accounts............. 18,081 15,240 Accrued utility revenues (Note A).................. 6,523 6,012 Fuel, materials and supplies, at average cost...... 3,312 3,314 Prepayments........................................ 1,890 1,796 Other.............................................. 326 323 --------- --------- Total current assets............................. 30,216 28,798 --------- --------- Deferred Charges Demand side management programs................... 18,367 18,560 Environmental proceedings costs (Note I)........... 7,893 7,741 Purchased power costs.............................. 8,433 1,534 Other.............................................. 8,258 7,824 --------- --------- Total deferred charges........................... 42,951 35,659 --------- --------- Non-Utility Cash and cash equivalents.......................... 76 579 Other current assets............................... 4,055 5,716 Property and equipment............................. 11,478 11,329 Intangible assets.................................. 2,580 3,022 Equity investment in energy-related businesses..... 10,999 10,199 Other assets....................................... 8,680 2,571 --------- --------- Total non-utility assets......................... 37,868 33,416 --------- --------- Total Assets...........................................$313,282 $294,611 ========= ========= The accompanying notes are an integral part of these consolidated financial statements. GREEN MOUNTAIN POWER CORPORATION December 31 1995 1994 --------- --------- (In thousands) CAPITALIZATION AND LIABILITIES Electric Utility Capitalization (See Capitalization Data) Common Stock Equity (Note C) Common stock..................................... $16,168 $15,592 Additional paid-in capital....................... 64,206 60,378 Retained Earnings................................ 26,412 25,727 Treasury stock, at cost.......................... (378) (378) --------- --------- Total common stock equity...................... 106,408 101,319 Redeemable cumulative preferred stock (Note D)..... 8,930 9,135 Long-term debt, less current maturities (Note E)... 91,134 74,967 --------- --------- Total capitalization........................... 206,472 185,421 --------- --------- Capital Lease Obligation (Note J)...................... 9,778 10,278 --------- --------- Current Liabilities Current maturuties of long-term debt............... 7,833 4,833 Short-term debt (Note F)........................... 8,416 20,214 Accounts payable, trade, and accrued liabilities... 5,529 5,489 Accounts payable to associated companies (Note B).. 7,011 4,860 Dividends declared................................. 194 194 Customer deposits.................................. 816 964 Taxes Accrued...................................... 571 1,442 Interest accrued................................... 1,847 1,953 Other.............................................. 412 492 --------- --------- Total current liabilities...................... 32,629 40,441 --------- --------- Deferred Credits Accumulated deferred income taxes (Note G)......... 25,292 22,082 Unamortized investment tax credits (Note G)........ 5,107 5,390 Other (Note A)..................................... 21,642 21,962 --------- --------- Total deferred credits......................... 52,041 49,434 --------- --------- Non-Utility Current liabilities................................ 1,124 918 Other liabilities.................................. 11,238 8,119 --------- --------- Total non-utility liabilities.................. 12,362 9,037 --------- --------- Total Capitalization and Liabilities...................$313,282 $294,611 ========= ========= 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 1995 1994 1995 1994 ----------- ---------- ---------- --------- ------- (In thousands) Common Stock,$3.33 1/3 par value (Note C)................... 10,000,000 4,850,496 4,677,512 $16,168 $15,592 ========= ======= ---------------------------------------------------------------------------------------------------------------- Outstanding Authorized Issued 1995 1994 1995 1994 ---------- ----------- ---------- ---------- --------- ------- (In thousands) Redeemable Cumulative Preferred Stock, $100 par value (Note D) 4.75%,Class B, redeemable at $101 per share....................................... 15,000 15,000 3,000 3,450 $300 $345 7%,Class C, redeemable at $101 per share....................................... 15,000 15,000 5,100 5,100 510 510 9.375%,Class D,Series 1, redeemable at $101 per share......................... 40,000 40,000 11,200 12,800 1,120 1,280 8.625%,Class D,Series 3, redeemable at $103.835 per share..................... 70,000 70,000 70,000 70,000 7,000 7,000 Class E................................................ 200,000 -- -- -- -- -- --------- ------- Total Preferred Stock..................................... $8,930 $9,135 ========= ======== LONG-TERM DEBT (Note E) 1995 1994 --------- ------- (In thousands) First Mortgage Bonds 5 1/8% Series due 1996....................................................................................... $3,000 $3,000 7% Series due 1998........................................................................................... 3,000 3,000 10.7% Series due 2000 - Cash sinking fund,$1,800,000 annually................................................................................................. 9,000 10,800 10.0% Series due 2004 - Cash sinking fund,$1,700,000 annually................................................................................................. 15,300 17,000 9.64% Series due 2020........................................................................................ 9,000 9,000 8.65% Series due 2022 - Cash sinking fund,commences 2012..................................................... 13,000 13,000 6.84% Series due 1997 - Cash sinking fund,$1,333,000 annually................................................................................................. 2,667 4,000 5.71% Series due 2000........................................................................................ 5,000 5,000 6.7% Series due 2018......................................................................................... 15,000 15,000 6.21% Series due 2001........................................................................................ 8,000 -- 6.29% Series due 2002........................................................................................ 8,000 -- 6.41% Series due 2003........................................................................................ 8,000 -- --------- ------- Total Long-term Debt Outstanding............................................................................... 98,967 79,800 Less Current Maturities (due within one year)................................................................ 7,833 4,833 --------- -------- Total Long-term Debt, Net...................................................................................... $91,134 $74,967 ========= ======== 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-third of its population. The most significant portion of the Company's net income is derived from its electric utility operations, which purchases and generates electric power and distributes it to 82,000 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, which supplies propane to 10,000 customers in Vermont and New Hampshire, and Mountain Energy, Inc., which invests in electric generation and energy conservation projects across the United States. 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 1995 1994 ---- ---- (In thousands) Revenue . . . . . . . . . . . . . . . $11,905 $12,031 Expense. . . . . . . . . . . . . . . . 10,416 10,920 ------- ------- Net Income . . . . . . . . . . . . . . $ 1,489 $ 1,111 ======= ======= 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. In the event that the Company no longer meets the criteria under SFAS 71, the Company would be required to writeoff related regulatory assets and liabilities. SFAS 121, Accounting for the Impairment of Long Lived Assets, which becomes 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 the amount of costs excluded from recovery. Based upon the regulatory environment within which the Company currently operates, the Company does not expect that SFAS 121 will have a material impact on the Company's financial position or results of operations. Therefore, the Company believes that its use of regulatory accounting under SFAS 71 remains appropriate. 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: 1995 1994 1993 ---- ---- ---- (In thousands) Interest . . . . . . . . . . . . . . . . $7,940 $7,714 $6,206 Income Taxes (Net of refunds) . . . . . $2,949 $3,088 $1,920 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. AFUDC represents the composite interest and equity costs of capital funds used to finance construction. AFUDC, a non-cash item, is recognized as a cost of "Utility Plant" with offsetting credits to "Other Income" and "Interest Charges." This is in accordance with established regulatory ratemaking practice under which a utility is permitted a return on, and the recovery of, these capital costs through their ultimate inclusion in rate base and in the provisions for depreciation. When Construction Work in Progress (CWIP) is included in rate base and the utility is recovering the cost of financing this construction through rates, no AFUDC is included in the cost of such construction. The VPSB generally allows CWIP in rate base for short-term construction projects and projects for which completion is imminent. AFUDC, which is compounded semi-annually, was calculated using weighted average rates of 6.6 percent, 6.9 percent and 7.2 percent for the years 1995, 1994 and 1993, respectively. 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. The annual depreciation provision was approximately 3.6 percent of total depreciable property at the beginning of each year 1995, 1994 and 1993. 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. At December 31, 1995, other deferred charges totaled $11.6 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, 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. 9. Major Customers The Company had one major retail customer, IBM, metered at two locations, that accounted for 12.9, 13.7 and 13.6 percent of operating revenues in 1995, 1994 and 1993, 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 pension costs accrued. 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: 1995 1994 1993 ---- ---- ---- (Dollars in thousands) Service cost-benefits earned during the period . $ 687 $ 768 $ 748 Interest cost on projected benefit obligations . 1,671 1,633 1,593 Actual return on plan assets . . . . . . . . . . (6,447) (1,296) (3,107) Net amortization and deferral . . . . . . . . . . 4,232 (906) 1,141 Effect of voluntary retirement program . . . . . 765 --- --- Adjustment due to actions of regulator . . . . . (878) (174) 337 ------- ------- ------ Net periodic pension cost funded and recognized . $ 30 $ 25 $ 712 ======= ======= ====== Assumptions used to determine pension costs and the related benefit obligation in 1995, 1994 and 1993 were: Discount rate . . . . . . . . . . . . . . . . 8.0% 7.5%* 8.0% Rate of increase in future compensation levels 5.0% 5.0% 6.0% Expected long-term rate of return on assets . 9.0% 9.0% 9.0% *The discount rate used to determine the accumulated benefit obligation was 8.0%. The following table sets forth the Plan's funded status as of December 31: 1995 1994 1993 ---- ---- ---- (In thousands) Actuarial present value of benefit obligations: Accumulated benefit obligations, including vested benefits of $19,107, $18,184 and $16,825, respectively . . . . . ($19,431) ($18,479) ($17,105) ========= ========= ========= Projected benefit obligations for service rendered to date . . . . . . . . . ($21,974) ($21,363) ($21,002) Plan assets at fair value . . . . . . . . . . . 28,685 24,171 23,981 --------- --------- --------- Assets in excess of projected benefit obligations . . . . . . . . . . . . . 6,711 2,808 2,979 Unrecognized net gain from past experience different from that assumed . . . (5,188) (285) (272) Prior service cost not yet recognized in net periodic pension cost . . . . . . . . . . . . 1,506 1,642 1,885 Unrecognized net asset at transition being recognized over 16.47 years . . . . . . (1,706) (1,934) (2,162) Adjustment due to actions of regulator . . . . . (1,323) (2,231) (2,430) --------- --------- --------- Prepaid pension cost included in other assets . $ --- $ --- $ --- ========= ========= ========= The plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities. In 1995, the Company offered a Voluntary Retirement Incentive Option to its employees which was accepted by 24 eligible participants. This program, which is funded by the pension plan, resulted in an increase in the projected benefit obligation of $765,000 as of December 31, 1995. The cost of the Option will be expensed when additional funding is made to the pension trust. The Company also has a supplemental pension plan for certain employees. Pension costs for the years ended December 31, 1995, 1994 and 1993 were $397,000, $381,000 and $384,000, respectively, under this plan. This plan is supported through insurance contracts. 11. Fair Value of Financial Instruments If the first mortgage bonds and preferred stock outstanding at December 31, 1995 were refinanced using new issue debt rates of interest, which, on average, are lower than the Company's outstanding rates, the present value of those obligations would differ from the amounts outstanding on the December 31, 1995 balance sheet by 10 percent. In the event of such a refinancing, there would be no gain or loss, inasmuch as under established regulatory precedent, any such difference would be reflected in rates and have no effect upon income. 12. Postretirement Health Care Benefits The Company provides certain health care benefits for retired employees and their dependents. Employees become eligible for these benefits if they reach normal retirement age while working for the Company. The Company accrues the cost of these benefits during the service life of covered employees. Accrued postretirement health care expenses are recovered in rates if those expenses are funded. In order to maximize the tax deductible contributions that are allowed under IRS regulations, the Company amended its pension plan to establish a 401-h subaccount and established separate VEBA trusts for its union and non-union employees. The plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities. Net postretirement benefits costs for 1995 reflect the following components and assumptions: 1995 1994 1993 ---- ---- ---- (In thousands) Accumulated postretirement benefit obligation: Current retirees . . . . . . . . . . . . ($ 4,594) ($ 3,497) ($3,628) Participants currently eligible . . . . (681) (1,863) (2,288) All others . . . . . . . . . . . . . . . (3,384) (3,785) (4,789) --------- --------- -------- Total accumulated postretirement benefit obligation . . . . . . . . . . . . . . . (8,659) (9,145) (10,705) Plan assets at fair value . . . . . . . . . 5,465 3,433 --- --------- --------- -------- Accumulated postretirement benefit obligation in excess of plan assets . . (3,194) (5,712) (10,705) Unrecognized prior service cost . . . . . . (929) --- --- Unrecognized transition obligation . . . . 5,982 6,485 6,845 Unrecognized net gain . . . . . . . . . . . (1,687) (1,777) 538 -------- --------- --------- Prepaid (Accrued) postretirement benefit cost . . . . . . . . . . . . . . . . . . $ 172 ($ 1,004) ($ 3,322) ======== ========= ========= Net periodic postretirement benefit cost for 1995 includes the following components: 1995 1994 1993 (In thousands) Service cost . . . . . . . . . . . . . . . . $ 224 $ 407 $ 438 Interest cost . . . . . . . . . . . . . . . 697 864 940 Actual return on plan assets . . . . . . . . (586) (127) --- Deferred asset loss/(gain) . . . . . . . . . 264 (107) --- Recognition of transition obligation, net of amortization . . . . . . . . . . . 234 361 380 ------- ------- ------- Total net periodic postretirement benefit cost . . . . . . . . . . . . . $ 833 $ 1,398 $ 1,758 ======= ======= ======= Assumptions used to determine postretirement benefit costs and the related benefit obligation were: 1995 1994 1993 ---- ---- ---- Discount rate to determine postretirement benefit costs . . . . . . . . . . . . . . 8.5% 7.5% 8.0% Discount rate to determine postretirement benefit obligation . . . . . . . . . . . . 8.5% 8.5% 8.0% Expected long-term rate of return on assets 7.5% 7.5% 9.0% For measurement purposes, a 6.2 percent annual rate of increase in the per capita cost of covered benefits was assumed for 1995; 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, 1995 by $1.4 million and the aggregate of the service and interest components of net periodic postretirement benefit cost for the year ended December 31, 1995 by $200,000. 13. Deferred Credits The Company has other deferred credits and long-term liabilities of $21.6 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. 15. Reclassification Certain items on the prior years' financial statements have been reclassified for consistent presentation with the current year. B. Investments in Associated Companies The Company accounts for investments in the following companies by the equity method: Investment in Equity Percent Ownership December 31, at December 31, 1995 1995 1994 -------------------- ---- ---- (In thousands) VELCO - Common . . . . . . . . . 29.5% $ 1,811 $ 1,814 - Preferred . . . . . . . 30.0% 1,278 1,418 ------- ------- Total VELCO . . . . . . . . . . 3,089 3,232 Vermont Yankee - Common . . . . 17.9% 9,631 9,766 New England Hydro-Transmission - Common . . . . . . . . . . 3.18% 1,296 1,398 New England Hydro-Transmission Electric - Common . . . . . 3.18% 2,008 2,288 ------- ------- $16,024 $16,684 ======= ======= Undistributed earnings in associated companies totaled $666,000 at December 31, 1995. 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, $7.9 million and $8.0 million for the years 1995, 1994 and 1993, 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, 1995 1994 1993 ---- ---- ---- (In thousands) Company's equity in net income . . . . . . . $ 377 $ 386 $ 406 ======= ======= ======= Total assets . . . . . . . . . . . . . . . . $71,668 $69,724 $70,199 Less: Liabilities and long-term debt . . . . . 61,238 58,850 58,806 ------- ------- ------- Net assets . . . . . . . . . . . . . . . . . $10,430 $10,874 $11,393 ======= ======= ======= Company's equity in net assets . . . . . . . $ 3,089 $ 3,232 $ 3,388 ======= ======= ======= Vermont Yankee The Company is responsible for 17.3 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 535 megawatts. Vermont Yankee's current estimate of decommissioning is approximately $347 million, of which $141 million has been funded. At December 31, 1995, the Company's portion of the net unfunded liability was $36 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 1995, the Company incurred $27.7 million in Vermont Yankee annual capacity charges, which included $1.8 million for interest charges. The Company's share of Vermont Yankee's long-term debt at December 31, 1995 was $13.1 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 retrospective 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 to be adjusted at least every five years to reflect inflationary changes. The above insurance covers all workers employed at nuclear facilities prior to January 1, 1988, for bodily injury claims. Vermont Yankee has 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's estimated contingent liability for a retrospective premium on the master worker policy as of December 1995 is $3.1 million. The secondary financial protection program referenced above provides coverage in excess of the Master Worker policy. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL II and NEIL III) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II and III are subject to retroactive assessments if losses exceed the accumulated funds available. The maximum potential assessment against Vermont Yankee with respect to NEIL II losses arising during the current policy year is $14.0 million and the NEIL III maximum retroactive assessment is $7.0 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, 1995 1994 1993 ---- ---- ---- (In thousands) Earnings: Operating revenues . . . . . . . . . . . $180,437 $162,757 $180,145 Net income applicable to common stock . 6,790 6,588 7,793 Company's equity in net income . . . . . 1,171 1,143 1,425 Total assets . . . . . . . . . . . . . . . $531,293 $512,142 $469,770 Less: Liabilities and long-term debt . . . . . 477,350 457,669 415,606 -------- -------- -------- Net assets . . . . . . . . . . . . . . . . $ 53,943 $ 54,473 $ 54,164 ======== ======== ======== Company's equity in net assets . . . . . . $ 9,631 $ 9,766 $ 9,745 ======== ======== ======== C. Common Stock Equity The Company maintains a Dividend Reinvestment and Stock Purchase Plan (DRIP) under which 659,107 shares were reserved and unissued at December 31, 1995. The Company also funds an Employee Savings and Investment Plan (ESIP). At December 31, 1995, there were 29,544 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. 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 1995, 11,926 shares of common stock were awarded. At December 31, 1995, there were 38,074 shares reserved and unissued under the Compensation Program. Changes in common stock equity for the years ended December 31, 1993, 1994 and 1995 are as follows:
Common Stock Treasury Stock ------------------------ Paid-in Retained ------------------------ Stock Shares Amount Capital Earnings Shares Amount Equity ------ ------ ------- -------- ------ ------ ------ (Dollars in thousands) BALANCE, December 31, 1992............... 4,413,537 $14,712 $53,510 $24,801 15,856 ($378) $92,645 Common Stock Issuance: DRIP................................... 86,974 290 2,586 2,876 ESIP................................... 35,531 118 1,082 1,200 Net Income............................... 10,631 10,631 Cash Dividends on Capital Stock: Common Stock -$2.11 per share..... (9,396) (9,396) Preferred Stock -$4.75 per share..... (19) (19) -$7.00 per share..... (38) (38) -$9.375 per share.... (146) (146) -$8.625 per share.... (604) (604) ------------------------------------------------------------------------------------ BALANCE, December 31, 1993............... 4,536,042 15,120 57,178 25,229 15,856 (378) 97,149 Common Stock Issuance: DRIP................................... 109,959 367 2,472 2,839 ESIP................................... 31,511 105 728 833 Net Income............................... 11,002 11,002 Cash Dividends on Capital Stock: Common Stock -$2.12 per share..... (9,713) (9,713) Preferred Stock -$4.75 per share..... (18) (18) -$7.00 per share..... (38) (38) -$9.375 per share.... (131) (131) -$8.625 per share.... (604) (604) ------------------------------------------------------------------------------------ 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 ====================================================================================
Dividend Restrictions Certain restrictions on the payment of cash dividends on common stock are contained in the indentures relating to long-term debt and in the Restated Articles of Association. Under the most restrictive of such provisions, $20.3 million of retained earnings were free of restrictions at December 31, 1995. The properties of the Company include several hydroelectric projects licensed under the Federal Power Act, with license expiration dates ranging from 1993 to 2022. At December 31, 1995, $302,000 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 the placement of restrictions on 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 is $1,650,000. All of the 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 $3.835 per share until September 1, 1996; $2.877 per share from September 1, 1996 to September 1, 1997; $1.919 per share from September 1, 1997 to September 1, 1998; and $0.916 per share from September 1, 1998 to September 1, 1999, after which there is no redemption premium. No shares of Class E preferred stock were issued as of December 31, 1995. 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) 1996 . . . . . . . . . . . . . . $4,833 $3,000 $7,833 1997 . . . . . . . . . . . . . . 3,500 1,334 4,834 1998 . . . . . . . . . . . . . . 3,500 3,000 6,500 1999 . . . . . . . . . . . . . . 3,500 --- 3,500 2000 . . . . . . . . . . . . . . 1,700 6,800 8,500 Non-Utility At December 31, 1995, Green Mountain Propane Gas Company, the Company's propane subsidiary, had long-term debt of $3,900,000, which was secured by substantially all of the subsidiary's assets, and Mountain Energy, Inc., the Company's subsidiary that invests in electric energy generation and efficiency projects, had unsecured long-term debt of $1,916,667. The annual sinking fund requirements and maturities for the next five years are: Sinking Funds Maturities Total ------- ---------- ----- (In thousands) 1996 . . . . . . . . . . . . . $1,167 $ --- $1,167 1997 . . . . . . . . . . . . . 1,167 --- 1,167 1998 . . . . . . . . . . . . . 1,167 --- 1,167 1999 . . . . . . . . . . . . . 167 900 1,067 2000 . . . . . . . . . . . . . 83 1,167 1,250 F. Short-term Debt Utility At December 31, 1995, the Company had lines of credit with six banks totaling $40.0 million, with borrowings outstanding of $8.4 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 1/8 to 1/4 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 on December 31, 1995 and December 31, 1994 was 6.3 percent and 6.4 percent, respectively. Non-Utility At December 31, 1995, Green Mountain Propane Gas Company, the Company's propane subsidiary, had a line of credit with a bank for $1.5 million, with $150,000 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, 1995 and 1994, the net regulatory assets were $690,000 and $187,000, respectively. The temporary differences which gave rise to the net deferred tax liability at December 31, 1995 and December 31, 1994, were as follows: At December 31, At December 31, 1995 1994 --------------- --------------- (In thousands) Deferred Tax Assets Contributions in aid of construction $ 6,361 $ 5,857 Deferred compensation and postretirement benefits . . . . . . 2,931 2,296 Alternative minimum tax credit . . . (661) (829) Excess deferred taxes . . . . . . . . 1,990 2,089 Unamortized investment tax credits . 2,151 2,277 Other . . . . . . . . . . . . . . . . 2,982 3,352 ------- ------- $15,754 $15,042 ======= ======= Deferred Tax Liabilities Property-related and other . . . . . $28,009 $26,314 Demand side management costs . . . . 6,685 6,457 Deferred purchased power costs . . . 2,901 174 Reversal of previously flowed-through tax depreciation . . . . . . . . . 2,816 3,499 AFUDC equity basis adjustment . . . . 635 680 -------- -------- 41,046 37,124 -------- -------- Net accumulated deferred income tax liability . . . . . . . . . . . . . ($25,292) ($22,082) ========= ========= 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 End December 31, 1995 1994 1993 ---- ---- ---- (In thousands) Net change in deferred income tax liability per above table . . . . . . . . . $3,210 $1,080 $4,677 Change in income tax related regulatory assets and liabilities. . . . . . . . . . . 503 505 503 Change in alternative minimum tax credit . . 168 (1,578) 444 IRS audit adjustment, 1989 - 90 . . . . . . . 255 --- 405 ------ ------ ------ Deferred income tax expense for the period . $4,136 $ 7 $6,029 ====== ====== ====== The components of the provision for income taxes are as follows: Year Ended December 31, 1995 1994 1993 ---- ---- ---- (In thousands) Current state income taxes . . . . . . . $ 365 $ 1,205 $ 134 Deferred state income taxes . . . . . . 897 70 1,225 Current federal income taxes . . . . . . 1,359 4,466 369 Deferred federal income taxes . . . . . 3,239 (63) 4,804 Investment tax credits -- net . . . . . (282) (283) (284) ------- ------- ------- Total income taxes . . . . . . . . . . . 5,578 5,395 6,248 Amounts included in "Other income" . . . -- -- 1 ------ ------ ------ Income taxes charged to operations . . . $5,578 $5,395 $6,249 ====== ====== ====== The following table details the components of the provisions for deferred federal income taxes: Year Ended December 31, 1995 1994 1993 ---- ---- ---- (In thousands) Deferred purchased power costs . . . . $2,351 $(1,310) $ 985 Excess tax depreciation . . . . . . . . 1,652 1,387 1,417 Demand side management . . . . . . . . 197 1,013 2,090 State tax benefit . . . . . . . . . . . (304) 39 (416) Contributions in aid of construction . (435) (657) (440) Supplemental benefit plans . . . . . . (266) 26 (198) Postretirement health care benefits . . (281) 824 (95) Pine Street . . . . . . . . . . . . . . (191) (1,915) 890 Other . . . . . . . . . . . . . . . . . 516 530 571 ------ ------- ------ Total deferred federal income taxes . . $3,239 $ (63) $4,804 ====== ======= ====== 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, 1995 1994 1993 ---- ---- ---- (Dollars in thousands) Income before income tax . . . . . . . $17,081 $16,398 $16,880 Federal statutory rate . . . . . . . . 34% 34% 34% Computed "expected" federal income taxes . . . . . . . . . . . . $ 5,808 $ 5,575 $ 5,739 Increase (decrease) in taxes resulting from: Tax versus book depreciation . . . . 327 327 327 Dividends received and paid credit . (616) (499) (580) AFUDC - equity funds . . . . . . . . (9) (89) (93) Amortization of ITC . . . . . . . . (282) (283) (284) State tax benefit . . . . . . . . . (429) (433) (462) Excess deferred taxes . . . . . . . (60) (60) (60) Taxes attributable to subsidiaries . (401) (268) 156 Other . . . . . . . . . . . . . . . (22) (150) 146 -------- -------- ------- Total federal income taxes . . . . . . $ 4,316 $ 4,120 $ 4,889 ======== ======== ======= Effective federal income tax rate . . 25.3% 25.1% 28.9% Non-Utility The Company's non-utility subsidiaries had accumulated deferred income taxes of $3.2 million on their balance sheets at December 31, 1995, largely attributable to property-related transactions. The components of the provision for income taxes for the non-utility operations are: Year Ended December 31, 1995 1994 1993 ---- ---- ---- (In thousands) State income taxes . . . . . . . . . . $165 $123 $ (58) Federal income taxes . . . . . . . . . 613 444 (224) Investment tax credits . . . . . . . . (45) (45) (45) ----- ----- ------ Income taxes charged to operations . . $733 $522 $(327) ===== ===== ====== Total federal income taxes differ from the amounts computed by applying the statutory rate to income before taxes, primarily attributable to state tax benefits. The effective federal income tax rates for the non-utility operations were 29.7 percent, 29.0 percent and 34.2 percent for the years ended December 31, 1995, 1994 and 1993, respectively. 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. 1995 Quarter Ended March June Sept. Dec. Total ----- ---- ----- ---- ----- (Amounts in thousands, except per share) Operating Revenues . . . . . . $40,023 $37,127 $39,781 $44,613 $161,544 Operating Income . . . . . . . 4,482 2,770 3,826 4,217 15,295 Net Income . . . . . . . . . . 3,227 1,992 3,071 3,213 11,503 Net Income Applicable to Common Stock . . . . . . . . 3,033 1,798 2,877 3,024 10,732 Earnings per Average Share of Common Stock . . . . . . . . $0.65 $0.38 $0.60 $0.63 $2.26 Weighted Average Number of Common Shares Outstanding . 4,680 4,721 4,771 4,815 4,747 1994 Quarter Ended March June Sept. Dec. Total ----- ---- ----- ---- ----- (Amounts in thousands, except per share) Operating Revenues . . . . . . $40,611 $33,603 $36,684 $37,299 $148,197 Operating Income . . . . . . . 4,892 1,872 3,243 4,510 14,517 Net Income . . . . . . . . . . 4,040 1,237 2,653 3,072 11,002 Net Income Applicable to Common Stock . . . . . . . . 3,841 1,038 2,454 2,875 10,208 Earnings per Average Share of Common Stock . . . . . . . . $0.85 $0.23 $0.54 $0.61 $2.23 Weighted Average Number of Common Shares Outstanding . 4,537 4,564 4,605 4,644 4,588 I. Commitments and Contingencies 1. Environmental Matters In 1982, the United States Environmental Protection Agency (EPA) notified the Company that the EPA, pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), was considering spending public funds to investigate and take corrective action involving claimed releases of allegedly hazardous substances at a site identified as the Pine Street Marsh in Burlington, Vermont. On part of this site was located a manufactured-gas facility owned and operated by a number of separate enterprises, including the Company, from the late 19th century to 1967. In its notice, the EPA stated that the Company may be a "potentially responsible party" (PRP) under CERCLA from which reimbursement of costs of investigation and of corrective action may be sought. On February 23, 1988, the Company received a Special Notice letter from the EPA stating that the letter constituted a formal demand for reimbursement of costs, including interest thereon, that were incurred and were expected to be incurred in response to the environmental problems at the site. On December 5, 1988, the EPA brought suit against the Company, New England Electric System, and Vermont Gas Systems, Inc. in the United States District Court for the District of Vermont seeking reimbursement for costs it incurred in conducting activities in 1985 to remove allegedly hazardous substances from the site, and requested a declaratory judgment that the Company and the other defendants are liable for all costs that have been incurred since the removal and that continue to be incurred in responding to claims of releases or threatened releases from the Maltex Pond Area -- the portion of the site where the removal action occurred. The complaint specifically alleged that the EPA expended at least $741,000 during the 1985 removal action and sought interest on this amount from the date the funds were expended and costs of litigation, including attorneys' fees. The Company entered a cross-claim against New England Electric System and third-party claims against UGI Corporation, Southern Union Corporation, the State of Vermont, and an individual property owner at the site for recovery of its response costs and for contribution. Fourth-party defendants subsequently were joined. In July 1990, the Company and other parties signed a proposed Consent Decree settling the removal action litigation. All 14 settling defendants contributed to the aggregate settlement amount of $945,000. Individual contributions were treated as confidential under the proposed Consent Decree. On December 26, 1990, upon the unopposed motion of the United States, the Consent Decree was entered by the Court. During the summer and fall of 1989, the EPA conducted the initial phase of the Remedial Investigation (RI) and commenced the Feasibility Study (FS) relating to the site. In the fall of 1990 and in 1991, the EPA conducted a second phase of RI work and studied the treatability of soils and groundwater at the site. In the fall of 1991, the EPA responded favorably to a request from the Company and other PRPs to participate in informal discussions on the EPA's ongoing investigation and evaluation of the site, and invited the Company and other interested parties to share technical information and resources with the EPA that might assist it in evaluating remedial options. On November 6, 1992, the EPA released its final RI/FS and announced a proposed remedy with an estimated present value total cost of approximately $47.0 million. This amount included 30 years' estimated operation and maintenance costs, with a net present value of approximately $26.4 million. The EPA's preferred remedy called for construction of a Containment/Disposal Facility (CDF) over a portion of the site. The CDF would have consisted of subsurface vertical barriers and a low permeability cap, with collection trenches and hydraulic control system to capture groundwater and prevent its migration outside of the CDF. Collected groundwater would have been treated and discharged or stored and disposed of off-site. The proposed remedy also would have required construction of new wetlands to replace those that would be destroyed by construction of the CDF and a long-term monitoring program. On or before May 15, 1993, the PRP group in which the Company participated submitted extensive comments to the EPA opposing the proposed remedy. In response to an earlier request from the EPA, the PRP group also submitted a detailed analysis of an alternative remedy anticipated to cost approximately $20 million. In early June, in response to overwhelming negative comment, the EPA withdrew its proposed remedy and announced that it would work with all interested parties in developing a new proposal. Since then, the EPA has established a coordinating council, with representatives of PRPs, environmental groups, and government agencies, and presided over by a neutral facilitator. The council is charged with determining what additional studies may be appropriate for the site and also is planning to eventually address additional response activities. In July 1994, the Company, New England Electric System (NEES), and Vermont Gas Systems, Inc. (VGS), entered into an Administrative Order by Consent, with the EPA, pursuant to which these PRPs are conducting certain additional studies that have been agreed to by the coordinating council. These studies constitute the first phase of action the council has decided on to fill data gaps at the site. A second phase, including tasks carried over from the first phase, additional field studies and preparation of an addendum feasibility study was begun during 1995 by the same parties under a second Order. The EPA has not required reimbursement for its past RI/FS study costs as a condition to allowing the PRPs to conduct these additional studies. The EPA has previously advised the Company that ultimately it will seek to hold the Company and the PRPs liable for such costs. These costs have been estimated to be at least $4.5 million, but the Company has sufficient reserves on its balance sheet to cover such costs. On December 1, 1994, the Company, NEES and VGS entered into a confidential agreement with the State, the City of Burlington and nearly all other landowner PRPs under which 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, and also entered into a confidential agreement with NEES for funding of work under the Order. In December 1991, the Company brought suit against several previous insurers seeking recovery of unrecovered past costs and indemnity against future liabilities associated with environmental problems at the site. Discovery in the case is largely complete, with the exception of expert discovery, which was stayed by the magistrate pending the resolution of Summary Judgment Motions filed by the Company. In August 1994, the Magistrate granted the Company's Motion for Summary Judgment with respect to defense costs against one defendant and denied it against another defendant. The United States District Judge affirmed those orders on September 30, 1994. The Company has reached confidential settlements with two of the defendants in its insurance litigation. One of these defendants provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 to 1984. These policies were in place in 1982 when the EPA first notified the Company that it might be a potentially responsible party at the Pine Street Marsh site. The other defendant provided the Company with second layer excess liability coverage for a seven-month period in 1976. The Company has deferred amounts received from third parties pending resolution of the Company's ultimate liability with respect to the site and rate recognition of that liability. The Company is unable to predict at this time the magnitude of any liability resulting from potential claims for the costs of the RI/FS or the performance of any remedial action, 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 and 1994, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its unrecovered expenditures between January 1991 and June 30, 1994 (in the total of approximately $7.3 million) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street Marsh related costs, the Company and the Vermont Department of Public Service (the Department) reached agreements in these cases that the full amount of Pine Street Marsh costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, on May 13, 1994, and on June 5, 1995, reflected the Pine Street Marsh related expenditures referred to above. In a rate case filed on September 15, 1995, the Company sought recovery in rates of approximately $1.3 million in expenses associated with the Pine Street site. This amount represented the Company's unrecovered expenditures between July 1994 and June 1995 for technical consultants and legal assistance in connection with 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 Pine Street related costs (and whether recovery or non-recovery of past costs and any insurance proceeds is relevant to such issue), the parties to the case have reached agreement that the full amount of Pine Street costs reflected in the Company's 1995 rate case should be recovered in rates. This agreement is currently pending before the VPSB. Management expects to seek and (assuming treatment consistent with the previous regulatory treatment set forth above) receive ratemaking treatment for unreimbursed costs incurred beyond the amounts for which ratemaking treatment has been received. 2. 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 1996 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. 3. Jointly-Owned Facilities The Company had joint-ownership interests in electric generating and transmission facilities at December 31, 1995, as follows: Ownership Share of Utility Accumulated Interest Capacity Plant Depreciation --------- -------- ------- ------------ (In %) (In MW) (In thousands) Highgate . . . . . . . . . . 33.8 67.6 $ 9,730 $2,816 McNeil . . . . . . . . . . . 11.0 5.9 $ 8,555 $2,981 Stony Brook (No. 1) . . . . . 8.8 30.2 $10,039 $5,520 Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,376 $1,234 Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 306 (1) Neutral conductor for NEPOOL/Hydro-Quebec Interconnection The Company's share of expenses for these facilities is reflected in the Statements of Consolidated Income. Each participant in these facilities must provide for its own financing. 4. Rate Matters 1995 Retail Rate Case -- On September 15, 1995, the Company filed a request with the VPSB to increase retail rates by 12.7 percent. The increase is needed to cover higher power supply costs, to support additional investment in plant and equipment, to fund expenses associated with the Pine Street site, and to cover higher costs of capital. The Company and the Department reached a settlement agreement providing for a 5.25 percent retail rate increase effective June 1, 1996, and a target return on equity for utility operations of 11.25 percent. The settlement was based on a newly negotiated agreement with Hydro-Qu bec that will result in a reduction of the Company's power supply costs below that which was anticipated, allowing the Company to reduce the amount of its rate request. The rate settlement must be reviewed and approved by the VPSB before it can take effect. 1994 Retail Rate Case -- On September 24, 1994, the Company filed a request with the VPSB to increase retail rates by 13.9 percent. The increase was needed primarily to cover the rising cost of existing power sources, the cost of new power sources the Company has secured to replace power supply that will be lost in the near future, and the cost of energy efficiency programs the Company has implemented for its customers. The Company, the Department and the other parties reached a settlement agreement providing for a 9.25 percent retail rate increase effective June 15, 1995, and a target return on equity for utility operations of 11.25 percent. The agreement was approved by the VPSB on June 9, 1995. 1993 Retail Rate Case -- On October 1, 1993, the Company filed a request with the VPSB to increase retail rates by 8.6 percent. The increase was needed primarily to cover the cost of buying power from independent power producers, the cost of energy conservation programs, the cost of plant additions made in the past two years, and costs incurred in 1992 and 1993 associated with the Company's response to the EPA's RI/FS and proposed remedy at the Pine Street Marsh site and with the Company's litigation against its previous insurers seeking recovery of past costs incurred and indemnity against future liabilities in connection with the site. On January 28, 1994, the Company and the other parties in the proceeding reached a settlement agreement providing for a 2.9 percent retail rate increase effective June 15, 1994, and a target return on equity for utility operations of 10.5 percent. The settlement agreement also provided for the Company's recovery in rates of $4.2 million in costs associated with the Pine Street Marsh site, as described herein above. The agreement was approved by the VPSB on May 13, 1994. 1991 Retail Rate Case -- On July 19, 1991, the Company filed a request with the VPSB to increase retail rates by 9.96 percent to cover power supply cost increases expected in 1992; the costs of upgrading and maintaining the Company's generation, transmission and distribution facilities; expenditures associated with the Company's conservation programs; and higher employee pension and health care costs. In orders dated April 2, 1992 and May 21, 1992, the VPSB approved an increase of 5.6 percent, or approximately $6.6 million, effective April 2, 1992. The Department appealed the VPSB orders challenging, among other rulings, the VPSB's acceptance of the Company's method of treating accumulated depreciation and certain Vermont Yankee-related power costs. The Company filed a cross-appeal contending, among other things, that the VPSB had erred in reducing ratebase relating to certain demand-side management (DSM) program cost projections that had been made in the Company's prior rate case. On April 22, 1994, the Vermont Supreme Court affirmed in part and reversed in part the VPSB orders. The Court overturned the VPSB's decision disallowing certain DSM costs. The impact of this portion of the Court's ruling resulted in the Company's other income since April 1992 being increased by $162,000. On the other hand, the Court overturned the VPSB decision in the Company's favor on an issue involving the method of treating accumulated depreciation, and on the inclusion of one item of Vermont Yankee's capital projections in power costs. The overall impact of the Court's ruling resulted in a reduction of $840,000 in the Company's revenues in 1994. 5. 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-Qu bec, provided for the construction of the second phase (Phase II) of the interconnection between the New England electric systems and that of Hydro-Qu bec. Phase II expands the Phase I facilities from 690 megawatts to 2,000 megawatts and provides for transmission of Hydro-Qu bec 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, 1995, the present value of the Company's obligation is $9.8 million. Projected future minimum payments under the Phase II support agreements are as follows: Year ending December 31, 1996 . . . . . . . . . . . $ 488,924 1997 . . . . . . . . . . . 488,924 1998 . . . . . . . . . . . 488,924 1999 . . . . . . . . . . . 488,924 2000 . . . . . . . . . . . 488,924 Total for 2001-2020 . . . 7,333,867 ---------- $9,778,487 ========== 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 1995 follows: Stony Vermont Merrimack Brook Yankee --------- ----- ------- (Dollars in thousands) Plant capacity . . . . . . . . . . . 320.0 MW 343.0 MW 535.0 MW Company's share of output . . . . . 8.9% 4.4% 17.3% Contract period . . . . . . . . . . 1968-1998 (1) (2) Company's annual share of: Interest . . . . . . . . . . . . . $ 606 $ 245 $ 1,840 Other debt service . . . . . . . . 329 296 --- Other capacity . . . . . . . . . . 1,759 406 25,899 ------ ------ ------- Total annual capacity . . . . . . . $2,694 $ 947 $27,739 ====== ====== ======= Company's share of long-term debt . $ 919 $4,825 $13,121 ====== ====== ======= (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 approved by the VPSB, 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 purchases pursuant to the contract with Hydro-Quebec entered into December 4, 1987 are as follows: (1) Schedule A -- 17 megawatts (MW) of firm capacity and associated energy to be delivered at the Highgate interconnection for five years beginning 1990; (2) 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 (3) Schedule C3 -- 46 megawatts of firm capacity and associated energy to be delivered at interconnections to be determined at a later time for 20 years beginning in November 1995. At present, the Schedule C3 purchases are being delivered over the Company's entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase I and Phase II). By use of the interconnection for Schedule C3 or other power transactions, the Company foregoes certain savings associated with other power deliveries for NEPOOL that would take place if the interconnection were not utilized for firm purchases. (Please also see description of the 1996 arrangement described below). In September 1994, the Company negotiated a renewal of a short-term "tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec delivers up to 61 megawatts of capacity and energy to the Company over the NEPOOL/Hydro-Quebec interconnection. The electricity purchased under this tertiary contract is priced at less than 2.5 cents per kilowatthour. The benefits realized by the Company from this favorably priced electricity will be greater than those associated with deliveries foregone by the Company otherwise available over the NEPOOL/Hydro-Quebec interconnection. The most recent tertiary energy contract will expire in August 1996. The Company anticipates that purchases of tertiary energy will extend beyond August 1996, but these purchases will be subject to the availability of the Hydro-Quebec/New England interconnection. 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 $3 million (in 1994 dollars) worth of research and development work from Hydro-Quebec over the four-year period, and made a $7.5 million (in 1994 dollars) cash payment to Hydro-Qu bec in 1995. The Company has exercised an option to purchase $1 million worth of additional research and development work and the $7.5 million cash payment was reduced accordingly. 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 kilowatthour of Schedules B and C3 combined will be cut from 6.4 to 4.2 cents per kilowatthour, a 34 percent (or $16 million) cost reduction. Over the four-year period covered by the arrangement, combined unit costs will be lowered from 6.4 to 5.3 cents per kilowatthour, reducing unit costs by 18 percent and saving $34.1 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-Qu bec 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 1996 arrangement, follows: July 1984 December 1987 Contract Contract Schedule A Schedule B Schedule C3 --------- ---------- ---------- ----------- (Dollars in thousands) Capacity Acquired . . . . 50 MW 17 MW 68 MW 46 MW Contract Period . . . . . 1985-1995 1990-1995 1995-2015 1995-2015 Minimum Energy Purchase (annual load factor) . . 50% 50% 75% 75% Annual Energy Charge . . $3,091 $1,798 $2,468 $1,317 (1995) (1995) (1995) (1995) $14,967 $10,324 (1996-2015)* (1996-2015)* Annual Capacity Charge . $2,367 $1,195 $3,482 $821 (1995) (1995) (1995) (1995) $16,731 $10,484 (1996-2015)* (1996-2015)* Average Cost per KWH . . 3.0 5.5 5.9 4.0 (1995) (1995) (1995) (1995) 6.7 6.1 (1996-2015)** (1996-2015)** *Estimated average. **Estimated average in nominal dollars, levelized over the period indicated. Under an arrangement negotiated in January 1996, Hydro-Quebec will provide cash payments to the Company of $3.0 million in 1996 and $1.1 million in 1997. In response, the Company will shift up to 40 megawatts of the 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 of 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 agreement. 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, net present value. 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, 1995 and 1994, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 1995. 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. 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, 1995 and 1994, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Boston, Massachusetts January 29, 1996
Schedule II GREEN MOUNTAIN POWER CORPORATION VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 1995, 1994 and 1993 Additions Balance at ------------------------------- Balance at Beginning of Charged to Charged to End of Description Period Cost & Expenses Other Accounts Deductions Period - ----------------------------------- ------------- -------------- -------------- ------------- ------------- Pine Street Marsh (1) 1995................................. $0 $ -- $ -- $ -- $0 1994................................. $684,430 $ -- $ -- $684,430 $0 1993................................. $684,430 $ -- $ -- $ -- $684,430 Injuries and Damages 1995................................. $513,720 $38,000 $ -- $448,419 $103,301 1994................................. $105,660 $35,000 $394,430 $21,370 $513,720 1993................................. ($2,357) $142,000 $ -- $33,983 $105,660 Bad Debt Reserve (3) 1995................................. $402,923 $371,564 $48,696 (2) $405,499 $417,684 1994................................. $639,853 $243,974 $53,076 (2) $533,980 $402,923 1993................................. $469,922 $410,000 $89,014 (2) $329,083 $639,853 (1) See Note I-1 of the Notes to Consolidated Financial Statements. (2) Represents collection of accounts previously written off. (3) 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," "Compliance with the Securities Exchange Act," "Executive Compensation," "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 16, 1996. 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 1996. PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K Filed Herewith On Page -------- Item 14(a)(1). The financial statements and financial 40 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-b By-laws of the Company, as amended 3-b Form 10-Q Sept. 1995 May 18, 1995. (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 of 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 December 1, 1995. 4-b-17 Revised form of Indenture as filed as an Exhibit 4-a-17 Form 10-Q Sept. 1995 to Registration Statement No. 33-59383. (1-8291) 4-c Debenture Indenture dated as of August 1, 1967 4-c 2-75293 (6 5/8% Debentures due August 1, 1992). 4-c-1 First Supplemental Indenture dated as of 4-c-1 2-49697 August 1, 1969, amending Exhibit 4-c above. 4-d Debenture Indenture dated as of October 1, 1969 4-d 2-75293 (8 7/8% Debentures due October 1, 1994). 4-e Debenture Indenture dated as of December 1, 1976 4-d 2-99643 (9 3/8% Debentures due December 1, 1996). 4-f Debenture Indenture dated as of August 1, 1983 4-f Form 10K 1992 (12 5/8% Debentures due August 1, 1998). (1-8291) 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. 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 Inter-connection 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 betweenNiagara 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-76 Agreement dated as of October 1, 1988, between 10-b-76 Form 10-K 1988 the Company and Central Hudson Gas & Electric (1-8291) Corporation for the Company to purchase up to 50 MW of capacity and associated energy. 10-b-76 Transmission agreement dated February 28, 1989, 10-b-76(a) Form 10-K 1988 (a) between the Company and Consolidated Edison (1-8291) Company of New York, Inc. (Con Edison), that Con Edison will provide electric transmission to the Company from Central Hudson Gas & Electric Company. 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-1a Green Mountain Power Corporation Amended and 10-d-1a Form 10-Q Restated Deferred Compensation Plans for March 1990 Directors and Officers. (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-3 Green Mountain Power Corporation Management 10-d-3 Form 10-K 1991 Incentive 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 J. V. Cleary, D. G. Hyde, 10-d-5a Form 10-K 1990 A. N. Terreri, E. M. Norse, T. V. O'Connor, Jr., (1-8291) C. L. Dutton, G. J. Purcell, S. C. Terry and T. C. Boucher. 10-d-6 Severance Agreements with W. S. Oakes, E. L. Shlatz 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-11 Severance Agreement with D. R. Stroupe 10-d-11 Form 10-Q Sept 1992 (1-8291) 10-d-12 Green Mountain Power Corporation Officer Compensation 10-d-12 Form 10-Q Program, Highlights Brouchure / Program Document. June 1994 (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-15 Green Mountain Power Corporation Officer Compensation 10-d-15 Form 10-K 1994 Program, Highlights Brochure / Program Document (1-8291) amended. 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-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-e-2 Agreement dated as of May 26, 1988, between the 10-e-2 Form 10-K for Company and Thomas P. Salmon, Chairman of the Board. 1988 (1-8291) *12 Computation of Ratio of Earnings to Fixed Charges 16-a Letter from former accountant, Coopers & Lybrand. Form 8-K for 1987 (1-8291) *23-a-1 Consent of Arthur Andersen LLP *27 Financial Data Schedule * Filed herewith
ITEM 14(b) There were no reports on Form 8-K filed for the quarter ending December 31, 1995. OTHER MATTERS For the purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into registrant's Registration Statement on Form S-8 No. 33-58413 (filed April 4, 1995): Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. 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/ D. G. Hyde Date: March 29, 1996 (D. G. Hyde, President and Chief Executive Officer) 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/ D. G. Hyde Chairman of the Executive Commit- March 29, 1996 (D. G. Hyde) tee, President, Chief Executive Officer and Director /s/ C. L. Dutton Vice President, Treasurer and March 29, 1996 (C. L. Dutton) Chief Financial Officer (Principal Financial Officer) /s/ G. J. Purcell Controller March 29, 1996 (G. J. Purcell) (Principal Accounting Officer) /s/ T. P. Salmon Chairman of the Board and March 29, 1996 (T. P. Salmon) Director /s/ R. E. Boardman Director March 29, 1996 (R. E. Boardman) /s/ N. L. Brue Director March 29, 1996 (N. L. Brue) /s/ W. H. Bruett Director March 29, 1996 (W. H. Bruett) Director (M. O. Burns) /s/ L. E. Chickering Director March 29, 1996 (L. E. Chickering) /s/ J. V. Cleary Director March 29, 1996 (J. V. Cleary) /s/ R. I. Fricke Director March 29, 1996 (R. I. Fricke) /s/ E. A. Irving Director March 29, 1996 (E. A. Irving) /s/ M. L. Johnson Director March 29, 1996 (M. L. Johnson) /s/ R. W. Page Director March 29, 1996 (R. W. Page) 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 January 29, 1996. 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 40 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 January 29, 1996 /s/ Arthur Andersen LLP EX-1 2 EXHIBIT 4-B-16 EXHIBIT 4-b-16 GREEN MOUNTAIN POWER CORPORATION to UNITED STATES TRUST COMPANY OF NEW YORK [successor to The Chase Manhattan Bank (National Association), successor to The Chase National Bank of the City of New York], Trustee ________________ SIXTEENTH SUPPLEMENTAL INDENTURE Dated as of December 1, 1995 _________________ Supplemental to Indenture of First Mortgage and Deed of Trust Dated as of February 1, 1955 _________________ This is a Security Agreement relating to Personal Property as well as a Mortgage upon Real Estate and Other Property This SIXTEENTH SUPPLEMENTAL INDENTURE dated as of December 1, 1995 made by GREEN MOUNTAIN POWER CORPORATION, as debtor (its Federal Tax Number being 03-0127430), a corporation duly organized and existing under the laws of the State of Vermont (hereinafter sometimes called the "Company"), whose mailing address and address of its chief executive office is 25 Green Mountain Drive, South Burlington, Vermont 05403, party of the first part, and UNITED STATES TRUST COMPANY OF NEW YORK [successor to The Chase Manhattan Bank (National Association), successor to The Chase National Bank of the City of New York], as Trustee and secured party (its Federal Tax number being 13-5459866), a corporation existing under the laws of the State of New York and having its principal corporate trust office at 114 West 47th Street, New York, New York 10036 (hereinafter sometimes called the "Trustee"), party of the second part. WHEREAS, the Company has heretofore executed and delivered an Indenture of First Mortgage and Deed of Trust dated as of February 1, 1955 (herein sometimes called the "Original Indenture"), to secure, as provided herein, its bonds (in the Original Indenture and herein called the "Bonds"), to be designated generally as its "First Mortgage Bonds", and to be issued in one or more series as provided in the Original Indenture; WHEREAS, the Company has heretofore executed and delivered a First Supplemental Indenture dated as of April 1, 1961, a Second Supplemental Indenture dated as of January 1, 1966, a Third Supplemental Indenture dated as of July 1, 1968, a Fourth Supplemental Indenture dated as of October 1, 1969, a Fifth Supplemental Indenture dated as of December 1, 1973, a Sixth Supplemental Indenture dated as of June 1, 1975, a Seventh Supplemental Indenture dated as of August 1, 1976, an Eighth Supplemental Indenture dated as of December 1, 1979, a Ninth Supplemental Indenture dated as of July 15, 1985, a Tenth Supplemental Indenture dated as of June 15, 1989, an Eleventh Supplemental Indenture dated as of September 1, 1990, a Twelfth Supplemental Indenture dated as of March 1, 1992, a Thirteenth Supplemental Indenture dated as of March 1, 1992, a Fourteenth Supplemental Indenture dated as of November 1, 1993 and a Fifteenth Supplemental Indenture dated as of November 1, 1993 supplementing and modifying the Original Indenture, each of which Supplemental Indentures provided for, among other things, the creation of a new series of First Mortgage Bonds; WHEREAS, pursuant to the Original Indenture, as heretofore supplemented and modified, there have been executed, authenticated, delivered and issued and there are now outstanding First Mortgage Bonds of series and in principal amounts as follows: Issued and Title Outstanding ----- ----------- First Mortgage Bonds, 5 1/8% Series due 1996 . . . . 3,000,000 First Mortgage Bonds, 7% Series due 1998 . . . . . . 3,000,000 First Mortgage Bonds, 10.7% Series due 2000 . . . . 9,000,000 First Mortgage Bonds, 10.0% Series due 2004 . . . . 15,300,000 First Mortgage Bonds, 9.64% Series due 2020 . . . . 9,000,000 First Mortgage Bonds, 8.65% Series due 2022 . . . . 13,000,000 First Mortgage Bonds, 6.84% Series due 1997 . . . . 2,667,000 First Mortgage Bonds, 5.71% Series due 2000 . . . . 5,000,000 First Mortgage Bonds, 6.70% Series due 2018 . . . . 15,000,000 WHEREAS, the Board of Directors of the Company has established a new series of Bonds to be designated "First Mortgage Bonds, Secured Medium- Term Notes, Series A" (herein sometimes called the "Series A Notes"), each of which may also bear the descriptive title "Series A Note", and has authorized an issue of up to Fifty Million Dollars ($50,000,000) principal amount thereof, and the Company has complied or will comply with all provisions required to issue additional Bonds provided for in the Original Indenture; WHEREAS, the Company desires to execute and deliver this Sixteenth Supplemental Indenture, in accordance with the provisions of the Original Indenture, for the purposes, among others, of (a) further assuring, conveying, mortgaging and assigning unto the Trustee certain additional property acquired by the Company, (b) providing for the creation of a new series of Bonds, designating the series to be created and specifying the form and provisions of the Bonds of such series and (c) adding to the Original Indenture, as supplemented and modified, other covenants and agreements to be hereafter observed by the Company (the Original Indenture, as heretofore supplemented and modified and as hereby supplemented and modified, being herein sometimes called the "Indenture"); and WHEREAS, all acts and proceedings required by law and by the Restated Articles of Association and By-laws of the Company necessary to secure the payment of the principal of, premium, if any, and interest on the Series A Notes, to make the Series A Notes to be issued hereunder, when executed by the Company, authenticated and delivered by the Trustee and duly issued, the valid, binding and legal obligations of the Company, and to constitute the Indenture a valid and binding mortgage for the security of all of the Bonds, in accordance with its and their terms, have been done and taken; and the execution and delivery of this Sixteenth Supplemental Indenture have been in all respects duly authorized: NOW, THEREFORE, THIS SIXTEENTH SUPPLEMENTAL INDENTURE WITNESSETH, that in order to secure the payment of the principal of, premium, if any, and interest on all Bonds at any time issued and outstanding under the Indenture, according to their tenor, purport and effect, to confirm the lien of the Indenture upon the mortgaged property mentioned therein including any and all property purchased, constructed or otherwise acquired by the Company since the date of execution of the Original Indenture and to secure the performance and observance of all the covenants and conditions herein and in the Bonds and in the Indenture contained, to declare the terms and conditions upon and subject to which the Series A Notes are and are to be issued and secured, and held, and for and in consideration of the premises and of the mutual covenants herein contained and of the purchase and acceptance of the Series A Notes by the holders thereof, and of the sum of Ten Dollars ($10) duly paid to the Company by the Trustee, at or before the ensealing and delivery hereof, and for other valuable consideration, the receipt whereof is hereby acknowledged, the Company has executed and delivered this Sixteenth Supplemental Indenture, and by these presents, does grant, bargain, sell, alien, remise, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto United States Trust Company of New York, as Trustee, and to its successors in trust and to its and their successors and assigns forever, all and singular the property, rights, privileges and franchises (other than excepted property) of the character described in the Granting Clauses of the Original Indenture now owned of record or otherwise by the Company, whether or not constructed or acquired since the date of execution of the Original Indenture or which may hereafter be constructed or acquired by it, including, without limiting the generality of the foregoing, the property in Vermont, Massachusetts and Maine described in Article Five hereof, but subject to all exceptions, reservations and matters of the character therein referred to, and expressly excepting and excluding from the lien and operation of the Indenture all properties of the character specifically excepted by Paragraphs B through H of Granting Clause VII of the Original Indenture, to the extent contemplated thereby, and all property heretofore released or otherwise disposed of pursuant to the provisions of the Indenture. TO HAVE AND TO HOLD all of the property, real, personal and mixed, and all and singular the lands, properties, estates, rights, franchises, privileges and appurtenances hereby granted, bargained, sold, aliened, remised, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed or intended so to be, unto the Trustee and its successors in the trust and to its and their successors and assigns, forever. BUT IN TRUST, NEVERTHELESS, for the equal and proportionate use, benefit, security and protection of those who from time to time shall hold the Bonds and coupons, or any of them, authenticated and delivered under the Indenture, and duly issued by the Company, without any discrimination, preference or priority of any one Bond or coupon over any other by reason of priority in the time of issue, sale or negotiation thereof or otherwise, except as provided in Section 12.28 of the Original Indenture, so that, subject to said Section 12.28, each and all of said Bonds and coupons shall have the same right, lien, and privilege under the Indenture, and shall be equally and proportionately secured by the Indenture (except as any sinking and improvement fund, depreciation fund or other fund established in accordance with the provisions of the Indenture may afford additional security for the Bonds of any particular series), with the same effect as if all the Bonds and coupons had been issued, sold and negotiated simultaneously on the date of the delivery of the Original Indenture. It is hereby covenanted, declared and agreed by and between the parties hereto that all Bonds and coupons, if any, are to be authenticated, delivered and issued, and that all property subject or to become subject to the Indenture is to be held, subject to the further covenants, conditions, uses and trusts set forth in the Indenture, and the Company for itself and its successors or assigns does hereby covenant and agree to and with the Trustee and its successor or successors in such trust, for the benefit of those who shall hold said Bonds, or coupons, or any of them, as follows: ARTICLE I SERIES A NOTES AND CERTAIN PROVISIONS RELATING THERETO SECTION 1.01. Terms of the Series A Notes. There shall be hereby established a series of Bonds, known as and entitled "First Mortgage Bonds, Secured Medium-Term Notes, Series A" (herein sometimes called the "Series A Notes"), each of which may also bear the descriptive title "Series A Note". The aggregate principal amount of the Series A Notes shall be limited to $50,000,000. The terms and form of each issue of Series A Notes shall be established by a resolution of the Board and set forth in an officers' certificate delivered to the Trustee prior to the Trustee's authentication and delivery of such issue of Series A Notes. Such officers' certificate shall set forth: (1) the title of such issue of Series A Notes (which shall distinguish such issue of Series A Notes from Bonds of any other series and from any other issue of Series A Notes issued hereunder); (2) any limit upon the aggregate principal amount of such issue of Series A Notes which may be authenticated and delivered under this Sixteenth Supplemental Indenture (except for Series A Notes authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Series A Notes of such issue and except for any Series A Notes which are deemed never to have been authenticated and delivered hereunder); (3) the Person to whom any interest on a Series A Notes of such issue shall be payable, if other than the Person in whose name that Series A Note is registered at the close of business on the regular record date for such interest; (4) the date or dates on which the principal of the Series A Notes of such issue is payable; (5) the rate or rates at which the Series A Notes of such issue shall bear interest, if any, the date or dates from which such interest shall accrue, the interest payment dates on which any such interest shall be payable and the regular record date for any interest payable on any interest payment date; (6) the place or places where the principal of and any premium and interest on the Series A Notes of such issue shall be payable; (7) the period or periods within which the price or prices at which and the terms and conditions upon which Series A Notes of such issue may be redeemed, in whole or in part, at the option of the Company; (8) the obligation, if any, of the Company to redeem or purchase Series A Notes of such issue pursuant to any sinking fund or analogous provision or at the option of a Bondholder and the period or periods within which, the price or prices at which and the terms and conditions upon which Series A Notes of such issue shall be redeemed or purchased, in whole or in part, pursuant to such obligation; (9) if other than denominations of $1,000 and any integral multiple thereof, the denominations in which Series A Notes of such issue shall be issuable; (10) the currency, currencies or currency units in which payment of the principal of and any premium and interest on any Series A Notes of the issue shall be payable; (11) if the amount of payments of principal of or any premium or interest on any Series A Notes of such issue may be determined with reference to an index, the manner in which such amounts shall be determined; (12) if the principal of or any premium or interest on any Series A Notes of such issue is to be payable, at the election of the Company or a Bondholder, in one or more currencies or currency units other than that or those in which the Series A Notes are stated to be payable, the currency, currencies or currency units in which payment of the principal of and any premium and interest on Series A Notes of such issue as to which such election is made shall be payable, and the periods within which and the terms and conditions upon which such election is to be made; (13) if other than the principal amount thereof, the portion of the principal amount of the Series A Notes of such issue which shall be payable upon declaration of acceleration of the maturity thereof; (14) if and as applicable, that the Series A Notes of such issue shall be issuable in whole or in part in the form of one or more global securities and, in such case, the depositary or depositaries for such global securities and any circumstances in which any such global security may be transferred to, and registered and exchange for Series A Notes registered and exchange for Series A Notes registered in the name of, a Person other than the depositary for such global security or a nominee thereof, and in which any such transfer may be registered; and (15) any other terms of such issue (which terms shall not be inconsistent with the provisions of the Indenture or this Sixteenth Supplemental Indenture). Series A Notes shall be transferable upon the surrender thereof for cancellation, together with a written instrument of transfer in a form approved by the registrar, duly executed by the registered owner or by his duly authorized attorney, at the office of the Company in the Borough of Manhattan, The City of New York. As permitted by the provisions of Section 3.10 of the Original Indenture and upon payment at the option of the Company of a sum sufficient to reimburse it for any stamp tax or other governmental charges as provided in Section 3.11 of the Original Indenture, but without payment of any other charge, Series A Notes may be exchanged for other Series A Notes of different authorized denominations of like aggregate principal amount. SECTION 1.02 Conditions to Issuance of Series A Notes. Series A Notes may be issued by the Company from time to time and shall be authenticated by the Trustee from time to time subject to the satisfaction of the conditions set forth in Article Five of the Indenture. ARTICLE II PRINCIPAL AMOUNT PRESENTLY TO BE OUTSTANDING SECTION 2.01. The total aggregate principal amount of First Mortgage Bonds of the Company issued and outstanding and presently to be issued and outstanding under the provisions of and secured by the Indenture will be up to One Hundred Twenty-Four Million, Nine Hundred Sixty-Seven Thousand Dollars ($124,967,000), namely, Three Million Dollars ($3,000,000) principal amount of First Mortgage Bonds, 5 1/8% Series due 1996, Three Million Dollars ($3,000,000) principal amount of First Mortgage Bonds, 7% Series due 1998, Nine Million Dollars ($9,000,000) principal amount of First Mortgage Bonds, 10.7% Series due 2000, Fifteen Million Three Hundred Thousand Dollars ($15,300,000) principal amount of First Mortgage Bonds, 10.00% Series due 2004, Nine Million Dollars ($9,000,000) principal amount of First Mortgage Bonds, 9.64% Series due September 1, 2020, Thirteen Million Dollars ($13,000,000) principal amount of First Mortgage Bonds, 8.65% Series due 2022, Two Million Six Hundred Sixty-Seven Thousand Dollars ($2,667,000) principal amount of First Mortgage Bonds, 6.84% Series due 1997, Fifteen Million Dollars ($15,000,000) principal amount of First Mortgage Bonds, 6.70% Series due 2018, Five Million Dollars ($5,000,000) principal amount of First Mortgage Bonds, 5.71% Series due 2000, and up to Fifty Million Dollars ($50,000,000) principal amount of Series A Notes to be issued upon compliance by the Company with the provisions of Sections 5.02 and 5.03 and/or 5.04 and/or 5.05 of the Original Indenture. ARTICLE III MODIFICATIONS AND AMENDMENTS SECTION 3.01. So long as any of the Series A Notes shall remain outstanding, Article One of the Original Indenture is hereby modified by adding a new Section 1.43 which shall read as follows: "Section 1.43. The term "Business Day" shall mean any day other than a Saturday, Sunday or other day on which banks located in The City of New York, or Burlington, Vermont or any other city in which the principal corporate trust office of the Trustee is located (if such office is not located in The City of New York) are authorized or required by law to be closed and, if any Series A Note shall be issued and outstanding which shall bear a floating rate of interest calculated with respect to LIBOR, each day on which dealings or deposits in U.S. dollars are not transacted in the London interbank market." SECTION 3.02. Pursuant to clause (i) of Section 18.01 of the Original Indenture, the modification of the Original Indenture effected by Section 3.01 of this Sixteenth Supplemental Indenture shall take effect without the consent of the holders of any of the Bonds at the time outstanding, notwithstanding any of the provisions of Section 18.02 of the Original Indenture. SECTION 3.03. Section 3.02 of the Original Indenture is hereby modified by (i) adding, after the words, "series to be created and" the words "either (a)", (ii) adding, after the words "forms, terms and provisions thereof" the words "or (b) authorizing the Board, by resolution thereof, to specify the forms, terms and provisions thereof", and (iii) deleting the words "of Directors" the last time they appear therein so that the said section shall read as follows: SECTION 3.02. Bonds Issuable in Series. The Bonds may be of different series and, except for the Bonds of the 1985 Series, may have such terms and provisions hereinafter permitted, as shall be created by and set forth in a supplemental indenture, designating the series to be created and either (a) specifying the forms, terms and provisions thereof or (b) authorizing the Board, by resolution thereof, to specify the forms, terms and provisions thereof; and may be so created and issued when duly authorized by resolution of the Board without further action of the Stockholders of the Company. SECTION 3.04. Section 3.04 of the Original Indenture is hereby replaced in its entirety, so that the said section shall read as follows: SECTION 3.04. Terms of Additional Bonds. The Bonds of each issue of each series (subject, as to Bonds of the 1985 Series, to the provisions of Article Four), shall bear such date or dates, shall be payable at such place or places, shall mature on such date or dates, shall bear interest, if at all, at such rate or rates payable in such installments and on such dates, and may be redeemable or repayable before maturity at such price or prices and upon such terms and conditions, as shall be (a) determined by the Board, (b) appropriately expressed in the Bonds of such issue or set forth in a supplemental indenture creating such series, and (c) set forth in an officers' certificate setting forth the terms authorized by the Board resolutions. The Board shall, at the time of the creation of any particular series of Bonds or at any time thereafter, make, and the Bonds of such series may contain or refer to or be entitled to the benefit of, any provisions not inconsistent with the terms hereof, including, without limitation, (a) provision for the payment of the principal of and/or the interest on the Bonds of such series without deduction for specified taxes, assessments or other governmental charges; and/or (b) provision for refunding or reimbursing to the holders of the Bonds of such series specified taxes, assessments or other governmental charges, but the obligation of the Company to refund or reimburse any such taxes, assessments or other governmental charges need not be made a part of the indebtedness secured hereby; and/or (c) provision to the extent permitted by law for the exchange or conversion of the Bonds of such series for or into new Bonds issuable hereunder or a different series and/or shares of stock of the Company and/or other securities; and/or (d) provision for sinking, amortization, improvement, depreciation, renewal, maintenance, replacement or other analogous funds; and/or (e) provision limiting the aggregate principal amount of the Bonds of such series; all as the Board may determine and fix. All Bonds of the same series having the same date of maturity shall be identical as to rate of interest and terms of redemption if redeemable. All coupon Bonds of any one series shall be dated the same date. SECTION 3.05. Section 5.02(C) of the Original Indenture is hereby modified by replacing the entire text of such section after the words "executed by the Company," with the words "providing for the series of Bonds designated as required by Subsection B of this Section, if such series is a new series, and if such indenture supplemental hereto shall authorize the Board to establish the form, terms and provisions of the Bonds of such series, a resolution of the Board establishing the form, terms and provisions of the Bonds of such series the authentication and delivery of which are being requested in the accompanying written order of the Company.", so that the said section shall read as follows: C. An indenture supplemental hereto, duly authorized and executed by the Company, providing for the series of Bonds designated as required by Subsection B of this Section, if such series is a new series, and if such indenture supplemental hereto shall authorize the Board to establish the form, terms and provisions of the Bonds of such series, a resolution of the Board establishing the form, terms and provisions of the Bonds of such series the authentication and delivery of which are being requested in the accompanying written order of the Company. SECTION 3.06. Pursuant to clause (g) of Section 18.01 of the Original Indenture, the modifications of the Original Indenture effected by Sections 3.02, 3.03, 3.04 and 3.05 of this Sixteenth Supplemental Indenture shall take effect without the consent of the holders of any of the Bonds at the time outstanding, notwithstanding any of the provisions of Section 18.02 of the Original Indenture. ARTICLE IV MISCELLANEOUS SECTION 4.01. This Sixteenth Supplemental Indenture is executed and shall be construed as an indenture supplemental to the Original Indenture, and shall form a part thereof, and the Original Indenture, as heretofore supplemented and modified and hereby supplemented and modified, is hereby confirmed. Except to the extent inconsistent with the express terms hereof, all of the provisions, terms, covenants and conditions of the Original Indenture, as supplemented and modified, shall be applicable to the Series A Notes to the same extent as if specifically set forth herein. All terms used in this Sixteenth Supplemental Indenture shall be taken to have the same meanings as in the Original Indenture, except in cases where the context clearly indicates otherwise. SECTION 4.02. All recitals in this Sixteenth Supplemental Indenture are made by the Company only and not by the Trustee; and all of the provisions contained in the Original Indenture, as supplemented and modified, in respect of the rights, privileges, immunities, powers and duties of the Trustee shall be applicable in respect hereof as fully and with like effect as if set forth herein in full. SECTION 4.03. This Sixteenth Supplemental Indenture may be executed in several counterparts, and each of such counterparts shall for all purposes be deemed to be an original, and all such counterparts, or as many of them as the Company and the Trustee shall preserve undestroyed, shall together constitute but one and the same instrument. SECTION 4.04. Although this Sixteenth Supplemental Indenture is dated for convenience and for the purpose of reference as of December 1, 1995, the actual date or dates of execution by the Company and by the Trustee are as indicated by their respective acknowledgments hereto annexed. ARTICLE V SCHEDULE OF PROPERTY ACQUIRED BY GREEN MOUNTAIN POWER CORPORATION AND NOT HERETOFORE SPECIFICALLY DESCRIBED IN THE INDENTURE (1) TRANSMISSION LINES ADDITIONS TO PROPERTY AS DESCRIBED IN ORIGINAL INDENTURE All of the transmission lines and equipment located in the State of Vermont in several cities and towns consisting of approximately 274.5 miles of overhead lines, including necessary crossarms, guys and insulators. 1.5 miles is rated at 115 KV, 9.4 miles is rated at 69 KV, 5.4 miles is rated at 44 KV, and 258.4 miles is rated at 34.5 KV. (2) DISTRIBUTION ADDITIONS TO PROPERTY AS DESCRIBED IN ORIGINAL INDENTURE All the distribution lines and equipment located in the State of Vermont in several cities and towns consisting of approximately 2,379 miles of overhead lines including necessary crossarms, guys, insulators, appurtenances, and line transformers and about 415 miles of underground cable. The Company's property includes approximately 880,824 kVa of transformer capacity and approximately 83,202 customers' metering. It is estimated that at least 80 percent of the above-mentioned lines are located upon public highways. With respect to such parts of the lines as are located upon private property, the Company has the necessary permits, rights in lands or easements enabling it to maintain said lines which said permits, rights in land or easements are part of the property hereby conveyed. DISTRIBUTION LINES NEW 16J2 LINE In order to meet capacity needs caused by improvements made at St. Michael's College, a new circuit was built between the Gorge substation #18 and St. Michael's College. (3) PRODUCTION EQUIPMENT UPGRADE PLANT #1 RACK RAKER - BOLTON FALLS, VERMONT The Company owns and operates a Hydro Plant in Bolton, VT. Between 1993 and 1994, the Company installed an automated rack raker system. This system will reduce the plant's downtime which will increase its overall productivity. (4) GENERAL PLANT REPLACE SCADA (Supervisory Control and Data Acquisition) MASTER STATION - COLCHESTER, VERMONT The Company owns and operates a service center in Colchester, VT. Between 1993 and 1994, a new enhanced SCADA Master Station was installed to replace an obsolete master station. The new SCADA system provides improved communication capabilities. (5) SUBSTATIONS IBM TRANSFER TRIP The Company owns and operates substation #86 at the IBM facility in Essex Jct., VT. Between 1993 and 1994, a fiber optic transfer trip was installed to improve reliability and productivity. IN WITNESS WHEREOF, Green Mountain Power Corporation has caused this Indenture to be signed in its corporate name and behalf, by Christopher L. Dutton, Vice President, Chief Financial Officer and Treasurer of the Company in that behalf duly authorized, and its corporate seal to be hereunto affixed and attested by its Secretary, and United States Trust Company of New York in token of its acceptance of the trust hereby created has caused this Indenture to be signed in its corporate name and behalf by one of its Assistant Vice Presidents, and its corporate seal to be hereunto affixed and attested by its Secretary or its Assistant Secretary, on the dates indicated by their respective acknowledgments hereto annexed, but as of the day and year first above written. GREEN MOUNTAIN POWER CORPORATION By: /s/Christopher L. Dutton ------------------------------- Christopher L. Dutton Vice President, Chief Financial Officer and Treasurer Attest: /s/Donna S. Laffan - ------------------------- Donna S. Laffan Corporate Secretary Signed, sealed and delivered on behalf of GREEN MOUNTAIN POWER CORPORATION in the presence of: /s/Penny J. Collins ----------------------- Name: Penny J. Collins /s/Bonnie V. Fairbanks -------------------------- Name: Bonnie V. Fairbanks CORPORATE SEAL UNITED STATES TRUST COMPANY OF NEW YORK By: /s/Louis P. Young --------------------- Louis P. Young Vice President Attest: /s/Christine Collins - ---------------------------- Christine Collins Assistant Vice President Signed, sealed and delivered on behalf of UNITED STATES TRUST COMPANY OF NEW YORK in the presence of: /s/Patricia Stermer ----------------------- Name: Patricia Stermer /s/John Guiliano -------------------- Name: John Guiliano CORPORATE SEAL STATE OF VERMONT ) ) SS.: COUNTY OF CHITTENDEN ) On this 11th day of December, A.D. 1995, before me, a Notary Public in and for said County in said State aforesaid, duly commissioned and acting as such, appeared Christopher L. Dutton, personally known to me and known by me to be the person who executed the within and foregoing instrument in the name and on behalf of Green Mountain Power Corporation, who, being by me duly sworn, did depose and say that he is the Vice President, Chief Financial Officer and Treasurer of Green Mountain Power Corporation, one of the corporations described in and that executed the said instrument, and he acknowledged said instrument so executed to be his free act and deed and the free act and deed of said corporation, and on oath stated that said instrument was signed and sealed by him as agent and in behalf of said corporation by authority of its Board of Directors, and that the seal affixed to said instrument is the corporate seal of said corporation. Witness my hand and official seal the day and year aforesaid. /s/Donna S. Laffan -------------------------------------- Name: Donna S. Laffan Notary Public NOTARIAL SEAL State of Vermont Commission Expires: February 10, 1999 STATE OF NEW YORK ) ) SS.: COUNTY OF NEW YORK ) On this 11th day of December, A.D. 1995, before me, a Notary Public in and for said County in said State aforesaid, duly commissioned and acting as such, appeared Louis P. Young, personally known to me and known by me to be the person who executed the within and foregoing instrument in the name and on behalf of United States Trust Company of New York, who, being by me duly sworn, did depose and say that he is a Vice President of United States Trust Company of New York, one of the corporations described in and that executed the said instrument, and he acknowledged said instrument so executed to be his free act and deed and the free act and deed of said corporation, and on oath stated that said instrument was signed and sealed by him on behalf of said corporation by authority of its By-Laws, and that the seal affixed to said instrument is the corporate seal of said corporation. Witness my hand and official seal the day and year aforesaid. /s/Christine C. Collins --------------------------------- Name: Christine Collins Notary Public NOTARIAL SEAL State of New York Qualified in Bronx County County Commission Expires: March 30, 1996 Notary Number: 03-4624735 EX-2 3 EXHIBIT 12 Exhibit 12
Green Mountain Power Corporation Computation of Ratio of Earnings to Fixed Charges Year Ended December 31, Period Ended December 31, 1995 --------------------------------------------- Three Months Twelve Months 1994 1993 1992 1991 1990 -------------------------------------- --------------------------------------------- (Dollars in thousands) Earnings: Net earnings $3,154 $11,242 $11,052 $10,764 $12,296 $10,260 $9,090 Income taxes 1,387 6,310 5,917 5,922 6,451 5,795 4,691 Fixed charges 2,454 9,777 9,777 9,370 9,332 9,303 9,373 -------------------------------------- --------------------------------------------- Total earnings $6,995 $27,329 $26,746 $26,056 $28,079 $25,358 $23,154 ====================================== ============================================= Fixed Charges: Interest $2,036 $8,047 $8,043 $7,590 $7,518 $7,517 $7,600 Amortization of debt premium and discount 35 140 138 102 85 48 44 Interest portion of rental payments 383 1,590 1,596 1,678 1,729 1,738 1,729 -------------------------------------- --------------------------------------------- Total fixed charges $2,454 $9,777 $9,777 $9,370 $9,332 $9,303 $9,373 ====================================== ============================================= Ratio of earnings to fixed charges 2.85 2.80 2.74 2.78 3.01 2.73 2.47 ====================================== =============================================
EX-3 4 EXHIBIT 23-A-1 Exhibit 23-a-1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated January 29, 1996 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 29, 1996 /s/ Arthur Andersen LLP EX-27 5
UT This schedule contains summary financial information extracted from the consolidated balance sheet as of December 31, 1995 and the related Consolidated Statements of Income and Cash Flows for the twelve months ended December 31, 1995 and is qualified in its entirety by reference to such financial statements. 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 181,999 20,248 30,216 42,951 37,868 313,282 16,168 63,828 26,412 106,408 8,120 810 91,134 8,416 0 0 7,833 0 9,778 0 80,783 313,282 161,544 5,578 140,671 146,249 15,295 3,634 18,929 7,426 11,503 771 10,732 10,047 6,546 20,197 2.26 2.26
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