SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K/A, Amendment No.1
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:
<TABLE>
<CAPTION>
Total Net
Generation Transmission Distribution Conservation Other Expenditures
---------- ------------ ------------ ------------ ----- ------------
(Dollars in thousands and net of AFUDC and Customer Advances For Construction)
Actual
<S> <C> <C> <C> <C> <C> <C>
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.
</TABLE>
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."
<TABLE>
<CAPTION>
OPERATING STATISTICS
For the Years Ended December 31
1995 1994 1993 1992 1991
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
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.
<TABLE>
<CAPTION>
July 1984 December 1987 Contract
Contract Schedule A Schedule B Schedule C3
__________ __________ __________ ___________
(Dollars in thousands)
<S> <C> <C> <C> <C>
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.
</TABLE>
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 3.2 cents 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.
