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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