SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
For the fiscal year ended December 31, 1994
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
incorporation or organization) Identification No.)
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, 1995, was
$117,969,717.00 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, 1995,
was 4,687,924.
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 18, 1995, to be filed with the
Commission pursuant to Regulation 14A under the Securities Exchange Act
of 1934, is incorporated by reference in Items 10, 11, 12 and 13 of
Part III of this Form 10-K.
PART I
ITEM 1. BUSINESS
THE COMPANY
Green Mountain Power Corporation (the Company) is a public utility
operating company engaged in supplying electrical energy in the State of
Vermont in a territory with an estimated population of 195,000. It
serves approximately 80,500 customers. For the year ended December 31,
1994, the Company's sources of revenue were derived as follows: 33.6%
from residential customers, 31.9% from small commercial and industrial
customers, 20.7% from large commercial and industrial customers, 8.9%
from sales to other utilities, and 4.9% from other sources. For the
same period, the Company's energy resources for retail and requirements
wholesale sales were obtained as follows: 38.7% from hydroelectric
sources (5.8% Company-owned, 0.5% New York Power Authority (NYPA), 29.6%
Hydro-Quebec and 2.8% small power producers), 36.2% from nuclear
generating sources (the Vermont Yankee plant described below), 10.9%
from coal sources, 3.3% from wood, 0.5% from natural gas, and 0.9% from
oil. The remaining 9.5% was purchased on a short-term basis from other
utilities and through the New England Power Pool (NEPOOL). In 1994, the
Company purchased 93.1% 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 520-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. During 1994, the Company also
supplied four firm wholesale customers, including one municipal and two
cooperative utilities 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, 1994, 1993 and 1992, electric
energy sales to International Business Machines Corporation (IBM), the
Company's largest customer, accounted for 13.7%, 13.6% and 13.8%,
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 October 1, 1993, the Company filed a request with the Vermont
Public Service Board (VPSB) to increase retail rates by 8.6%. The
increase was needed primarily to cover the cost of buying power from
independent power producers, the cost of energy efficiency programs, the
cost of plant additions made in the prior two years, and costs incurred
in 1992 and 1993 associated with the Company's response to the
Environmental Protection Agency's (EPA) Remedial
Investigation/Feasibility Study (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% retail rate increase effective June 15,
1994, and a target return on equity for utility operations of 10.5%.
The settlement agreement also provided for the Company's recovery in
rates of $4,200,000 in costs associated with the Pine Street Marsh site.
The agreement was approved by the VPSB on May 13, 1994.
On September 26, 1994, the Company filed a request with the VPSB to
increase retail rates by 13.9%. The increase is 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 (the
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 must be reviewed and approved by the VPSB before it can take
effect.
CONSTRUCTION
The Company's capital requirements result from the need to
construct facilities or to invest in programs to meet anticipated
customer demand for electric service. The policy of the Company is to
increase diversification of its power supply and other resources through
various means, including power purchase and sales arrangements, and
relying on sources that represent relatively small additions to the
Company's mix to satisfy customer requirements. This permits the
Company to meet its financing needs in a flexible, orderly manner.
Planned expenditures for the next five years will be primarily for
distribution and conservation projects.
Capital expenditures over the past three years and forecasted for
the next five years are as follows:
<TABLE>
<CAPTION>
Total Net
Generation Transmission Distribution Conservation Other Expenditures
(Dollars in thousands and net of AFUDC and Customer Advances for Construction)
<S> <C> <C> <C> <C> <C> <C>
Actual
1992 $ 868 $1,766 $7,320 $3,144 $2,925 $16,023
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
Forecasted
1995 $2,785 $1,038 $8,457 $3,698 $5,998 $21,976
1996 2,198 999 8,660 2,499 5,503 19,859
1997 1,299 1,499 8,999 2,444 2,102 16,343
1998 2,278 999 9,212 2,542 2,236 17,267
1999 2,777 999 9,509 2,643 2,137 18,065
</TABLE>
Construction projections are subject to continuing review and may be
revised from time-to-time in accordance with changes in the Company's
financial condition, load forecasts, the availability and cost of labor
and materials, licensing and other regulatory requirements, changing
environmental standards and other relevant factors.
For the period 1992-1994, internally generated funds, after payment
of dividends, provided approximately 56% of total capital requirements
for construction, sinking fund obligations and other requirements.
Internally generated funds provided 84% of such requirements for 1994.
It is expected that funds so generated will provide approximately 90% of
such requirements for the period 1995 through 1999, with the remainder
to be derived through short-term borrowings and the issuance of long-
term debt securities and common and preferred stock.
The Company anticipates issuing $15,000,000 of common stock and
$10,000,000 of first mortgage bonds in 1995. The proceeds will be used
to finance capital projects and to retire short-term debt. 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
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Net System Capability During Peak Month (MW)
Hydro (1)............................................ 179.0 174.9 160.6 161.3 119.6
Lease transmissions.................................. 2.1 3.9 5.7 5.7 9.4
Nuclear (1).......................................... 107.2 109.5 109.6 85.0 67.6
Conventional steam................................... 67.1 92.6 95.0 88.5 114.4
Internal combustion.................................. 60.2 71.0 47.4 52.0 47.7
Combined cycle....................................... 22.6 22.8 21.6 22.6 22.8
---------- ---------- ---------- ---------- ----------
Total capability (MW).............................. 438.2 474.7 439.9 415.1 381.5
Net system peak...................................... 308.3 307.3 314.4 308.5 301.9
---------- ---------- ---------- ---------- ----------
Reserve (MW)......................................... 129.9 167.4 125.5 106.6 79.6
========== ========== ========== ========== ==========
Reserve % of peak.................................... 42.1% 54.5% 39.9% 34.6% 26.4%
Net Production (MWH)
Hydro (1)............................................ 742,088 751,078 641,525 611,658 784,358
Lease transmissions.................................. -- 15,425 58,374 67,600 66,235
Nuclear (1).......................................... 763,690 598,245 665,034 731,582 671,563
Conventional steam................................... 651,105 748,626 762,451 799,781 859,059
Internal combustion.................................. 3,532 2,849 1,504 3,809 1,176
Combined cycle....................................... 37,808 40,966 60,138 104,344 90,825
---------- ---------- ---------- ---------- ----------
Total production...................................2,198,223 2,157,189 2,189,026 2,318,774 2,473,216
Less non-requirements sales to other utilities....... 328,794 271,224 273,087 448,110 587,475
---------- ---------- ---------- ---------- ----------
Production for requirements sales....................1,869,429 1,885,965 1,915,939 1,870,664 1,885,741
Less requirements sales & lease transmissions (MWH)..1,730,497 1,749,454 1,794,986 1,742,308 1,759,393
---------- ---------- ---------- ---------- ----------
Losses and company use (MWH)......................... 138,932 136,511 120,953 128,356 126,348
========== ========== ========== ========== ==========
Losses as a percentage of total production............. 6.32% 6.33% 5.53% 5.54% 5.11%
System load factor (2)................................. 67.7% 68.7% 68.5% 67.9% 69.5%
Sales and Lease Transmissions (MWH)
Residential - GMP.................................... 564,635 541,579 505,234 483,998 500,163
Lease transmissons................................... -- 15,425 58,374 67,600 67,370
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 564,635 557,004 563,608 551,598 567,533
Commercial & industrial - small...................... 604,686 593,560 582,594 571,818 580,562
Commercial & industrial - large...................... 521,400 529,372 539,665 519,201 519,688
Other................................................ 1,146 8,868 6,312 2,770 (4,726)
---------- ---------- ---------- ---------- ----------
Total retail sales and lease transmissions.........1,691,867 1,688,804 1,692,179 1,645,387 1,663,057
Sales to municipals and cooperatives and
other requirements sales........................... 38,630 60,650 102,807 96,921 96,335
---------- ---------- ---------- ---------- ----------
Total requirements sales...........................1,730,497 1,749,454 1,794,986 1,742,308 1,759,392
Other sales for resale............................... 328,794 271,224 273,087 448,110 587,474
---------- ---------- ---------- ---------- ----------
Total sales and lease transmissions................2,059,291 2,020,678 2,068,073 2,190,418 2,346,866
========== ========== ========== ========== ==========
Average Number of Electric Customers
Residential.......................................... 68,811 67,994 67,201 66,406 65,553
Commercial and industrial - small.................... 11,611 11,447 11,245 11,215 11,300
Commercial and industrial - large.................... 24 25 24 24 23
Other................................................ 76 74 73 71 71
---------- ---------- ---------- ---------- ----------
Total.............................................. 80,522 79,540 78,543 77,716 76,947
========== ========== ========== ========== ==========
Average Revenue per KWH (Cents)
Residential including lease revenues................. 9.03 8.94 8.44 8.06 7.54
Lease charges........................................ -- 0.06 0.41 0.26 0.25
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 9.03 9.00 8.85 8.32 7.79
Commercial and industrial - small.................... 8.00 7.97 7.82 7.53 6.99
Commercial and industrial - large.................... 6.02 5.96 5.89 5.72 5.30
Total retail including lease revenues................ 7.96 7.86 7.56 7.29 6.79
Average Use and Revenue Per Residential Customer
Kilowatt hours including lease transmissions......... 8,206 8,192 8,387 8,306 8,658
Revenues including lease revenues.................... $741 $733 $707 $670 $653
(1) See Note K of Notes to Consolidated Financial Statements.
(2) Load factor is based on net system peak and firm MWH
production less off-system losses.
</TABLE>
DEMAND-SIDE MANAGEMENT
The Company has committed itself to the development and
implementation of 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 refocused its energy efficiency programs to
reflect the new realities of greater power supply availability and to
capture efficiencies gained from prior experience with DSM. The shift
in focus reduced the Company's DSM costs in 1994 from $8,100,000 to
$6,400,000.
The framework for DSM developed with the Department also addresses
the need for greater cost-consciousness, not only by deploying DSM in a
more strategic manner, but also by beginning to shift, where
appropriate, more of the cost for DSM towards the customers who will be
receiving the most benefit. These programs are part of the Company's
most recent rate settlement. If such settlement is approved by the
VPSB, the new programs are scheduled to begin operation in April 1995.
The Company exceeded its savings goals by 16% in 1994, after
reducing the scope of the programs, while at the same time strengthening
the economic benefit of these programs and services.
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 1994, the
Company had interruptible/dispatchable power contracts with three major
ski areas, interruptible only contracts with three customers and
dispatchable-only contracts with an additional thirteen customers. The
interruptible portion of the contracts allow the Company to control
power supply capacity charges by reducing the Company's capacity
requirements. During 1994, 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.
Commercial/Industrial Energy Management Services. In 1994, the
Company offered five commercial and industrial energy efficiency
programs to qualifying customers. These programs offered comprehensive
technical assistance to identify cost-effective electric energy
efficiency opportunities which may qualify for financial incentives. In
addition, fuel-switching opportunities were identified for customers,
although no direct financial incentives were provided. Approximately
600 customers participated in these programs in 1994, resulting in an
approximate savings of 12,900 MWh.
Residential Energy Management Services. In 1994, the Company
offered four DSM programs to serve residential customers. The VPSB had
approved these programs in 1991. These programs offer a variety of
services to assist customers to identify and implement appropriate
electric energy strategies or fuel-switching opportunities for their
residences. In the case of electric efficiency improvements, the
Company will also offer various financial incentives for the
installation of such measures. Approximately 8,000 residential
customers participated in these programs in 1994 resulting in an annual
savings of approximately 1,884 MWh, or approximately 18% greater than
projected.
POWER RESOURCES
The Company generated and purchased 1,828,663.8 MWh of energy for
retail and requirements wholesale customers for the twelve months ended
December 31, 1994. The corresponding maximum one-hour integrated demand
during that period was 308.3 MW on January 26, 1994. 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 12/31/94 (a) of Annual Peak
___________________ ___________________
MWh % KW %
WHOLLY OWNED PLANTS
Hydro 108,520.1 5.84 37,216 8.49
Diesel and Gas Turbine 2,026.2 0.11 69,247 15.80
JOINTLY OWNED PLANTS
Wyman #4 4,667.6 0.25 8,254 1.88
Stony Brook I 5,877.6 0.32 8,793 2.01
McNeil 5,800.9 0.31 5,887 1.34
OWNED IN ASSOCIATION W/OTHERS
Vermont Yankee Nuclear (b) 672,945.2 36.21 80,872 18.45
NYPA LEASE TRANSMISSIONS
State of Vermont (NYPA) 9,618.7 0.52 2,088 0.48
LONG-TERM PURCHASES
Hydro-Quebec 550,508.6 29.62 124,408 28.39
Merrimack #2 202,987.3 10.92 30,457 6.95
Stony Brook I 11,409.4 0.61 13,768 3.15
Small Power Producers 107,580.7 5.79 24,024 5.48
SHORT-TERM PURCHASES 176,637.0 9.50 33,208 7.58
___________ _____ _______ _____
Less System Sales Energy (29,915.5)
TOTAL 1,828,663.8 100.00 438,222 100.00
=========== ====== ======= ======
NOTE: (a) Excludes losses on off-system purchases, totaling 40,765
MWh.
(b) Average annual capability associated with the Vermont
Yankee source is adjusted to reflect system sale obligations.
See "Power Resources -- Long-Term Power Sales."
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 520 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 is expected to
be completed by mid-April 1995. Vermont Yankee's next scheduled
refueling is September 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 incurred capital expenditures of approximately
$2,086,000 in 1994, $7,229,000 in 1993 and $10,750,000 in 1992. Vermont
Yankee estimates capital expenditures amounting to approximately
$2,507,000 for 1995.
During the year ended December 31, 1994, the Company utilized
672,945.2 MWh of Vermont Yankee energy to meet 36.2% of its retail and
requirements wholesale sales. The average cost of electricity produced
by the plant in 1994 was 3.8 cents per KWh. In 1994, Vermont Yankee had an
annual capacity factor of 96.1%, compared to 76.9% in 1993 and 83.3% in
1992.
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 1993 is $13,100,000. 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
$6,400,000 at the time of the first loss and $13,800,000 at the time of
a subsequent loss and the NEIL III maximum retroactive assessment is
$8,400,000. 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,
for 30 years. The agreements providing for the operation and support of
the Phase II facilities meet the capital lease accounting requirements
under SFAS 13. At December 31, 1994, the present value of the Company's
obligation was $10,300,000. The Company's projected future minimum
principal payments under the Phase II support agreements are $489,425
for each of the years 1995-1999 and an aggregate of $7,830,817 for the
years 2000-2020.
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, 1994, the capital structure
of such corporations was 41% common equity and 59% long-term debt.
Hydro-Quebec Power Supply Contracts. Under various contracts
approved by the VPSB, the details of which are described in the table
below, the Company purchases capacity and associated energy produced by
the Hydro-Quebec system. Such contracts obligate the Company to pay
certain fixed capacity costs whether or not energy purchases above a
minimum level set forth in the contracts are made. Such minimum energy
purchases must be made whether or not other, less expensive energy
sources might be available. These contracts are intended to complement
the other components in the Company's power supply to achieve the most
economic power-supply mix reasonably available.
<TABLE>
<CAPTION>
July 1984 December 1987 Contract
Contract Schedule A Schedule B Schedule C3
__________ __________ __________ ___________
(Dollars in thousands)
<S> <C> <C> <C> <C>
Capacity Acquired 50 MW 17 MW 68 MW 46 MW
Contact Period 1985-1995 1990-1995 1995-2015 1995-2015
Minimum Energy Purchase 50% 50% 75% 75%
(annual load factor) (1992-1995)
Minimum Energy Charge $3,782 $2,195 $15,231 $10,430
(1994) (1994) (1995-2015)* (1995-2015)*
$2,726 $1,771
(1995) (1995)
Annual Capacity Charge $3,313 $1,684 $16,030 $9,966
(1994) (1994) (1995-2015)* (1995-2015)*
$2,448 $1,237
(1995) (1995)
Average Cost per KWH 2.7 cents 5.3 cents 6.7 cents 6.1 cents
(1994) (1994) (1995-2015)** (1995-2015)**
2.7 cents 4.8 cents
(1995) (1995)
* Estimated average
** Estimated average in nominal dollars, levelized over the period indicated.
</TABLE>
On October 12, 1990, the VPSB granted conditional approval of the
Company's purchases pursuant to the contract with Hydro-Quebec entered
into December 4, 1987: (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. The opponents to the December 1987 contract
(principally the Crees, native peoples living in northern Quebec)
appealed the VPSB's October 1990 order to the Vermont Supreme Court. On
October 2, 1992, the Vermont Supreme Court affirmed the VPSB's October
1990 order. On February 12, 1992, the VPSB issued an order finding that
the Company had complied with substantial conditions imposed by the VPSB
in its October 1990 order and approved the Company's purchase under the
December 1987 contract. In March 1992, the opponents to the December
1987 contract appealed the VPSB'S February 1992 compliance order to the
Vermont Supreme Court. On May 7, 1993, the Vermont Supreme Court
affirmed the VPSB's compliance order approving the Company's purchases
under the December 1987 contract.
The Company anticipates that the Schedule C3 purchases will be
delivered over its entitlement to the NEPOOL/Hydro-Quebec
interconnection (Phase I and Phase II). If such interconnection is
utilized, the Company must forego certain savings associated with other
energy deliveries and capacity arrangements that would benefit the
Company if the interconnection were not utilized for delivery of the
Schedule C3 purchases. The Company believes that the benefits of the
Schedule C3 purchases, if power is delivered over such interconnection,
will offset the value of the foregone savings.
In September 1994, the Company negotiated a renewal of a short-term
"tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec
delivers 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 cents 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. This tertiary energy contract will expire in August
1995. The Company anticipates that purchases of tertiary energy will
extend beyond August 1995, but will end when the Schedule C3 deliveries
begin in November 1995.
On September 27, 1990, the Canadian National Energy Board (NEB)
issued its decision approving the export by Hydro-Quebec pursuant to the
December 1987 contract. The NEB, however, imposed a condition on its
approval: Hydro-Quebec's export license was to be deemed valid so long
as Hydro-Quebec obtained all federal and environmental approvals
required for any of its new hydroelectric generating units advanced in
order to satisfy Hydro-Quebec's contractual obligations. Hydro-Quebec
and the Province of Quebec appealed the imposition of this condition to
the Federal Court of Appeal. In a decision handed down on July 9, 1991,
the Federal Court of Appeal agreed with Hydro-Quebec's assertion that
the NEB has no authority to regulate the construction of hydroelectric
generating units -- a matter that lies exclusively within provincial
jurisdiction under the Canadian Constitution. The Federal Court of
Appeal struck down the challenged NEB license condition and otherwise
affirmed the license. The opponents to the December 1987 contract
appealed the decision of the Federal Court of Appeal to the Supreme
Court of Canada. On February 24, 1994, the Supreme Court of Canada
rendered a decision reversing the judgment of the Federal Court of
Appeal, and reinstated the NEB decision, including the condition that
Hydro-Quebec had objected to.
The December 1987 contract, like the July 1984 contract, calls for
the delivery of system power and is 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 contract. 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 December 1987 contract, over
the November 1995 through October 1999 period. Under this new
arrangement, the Company, in essence, will take delivery of the amounts
of energy as specified in the December 1987 contract, but the associated
fixed costs will be significantly reduced from those specified in the
December 1987 contract.
As part of this arrangement, the Company will purchase $3,000,000
worth of research and development work from Hydro-Quebec over the four-
year period and is obligated to make $7,500,000 cash payment to Hydro-
Quebec in 1995. The Company has the option to purchase up to $1,000,000
worth of additional research and development work. If the Company
exercises its option, the $7,500,000 cash payment will be reduced
accordingly. Hydro-Quebec retains the right to curtail annual energy
deliveries by 13% up to five times, over the 2000 to 2015 period, if
documented drought conditions exist in Quebec.
During the first year of this arrangement, the average cost per KWh
of Schedules B and C3 will be cut from 6.2 cents to 4.2 cents per KWh, a 32% or
$15,000,000 cost reduction. Over the four-year period covered by the
arrangement, unit costs will be lowered from 6.4 cents to 5.2 cents per KWh,
reducing unit costs by 19% and saving $34,500,000 in nominal terms.
In 1994, the Company utilized 356,591.9 MWh of Hydro-Quebec energy
under the July 1984 contract, 77,808.3 MWh under the December 1987
contract Schedule A and 116,108.4 MWh under the tertiary energy contract
to meet 29.6% of its retail and requirements wholesale sales. The
average cost of Hydro-Quebec electricity in 1994 was 3.0 cents per KWh. See
Notes J and K-2 of Notes to Consolidated Financial Statements.
New York Power Authority (NYPA). The Department allocates NYPA
power to the Company who, in turn, delivers the power to its residential
and farm customers. The Company purchased at wholesale 9,618.7 MWh of
NYPA power at an average cost of 1.1 cents per KWh in 1994. 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 1994 - June 1995 0.3
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, 1994, the Company utilized
202,987.3 MWh from the unit to meet 10.9% of its total retail and
requirements wholesale sales. The average cost of electricity from this
unit was 3.2 cents per KWh in 1994. 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 1994, the Company utilized 17,287.0 MWh from this plant to
meet 0.9% of its retail and requirements wholesale sales at an average
cost of 11.0 cents 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 1994. 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 1994, the Company utilized 4,667.6 MWh from this unit to
meet 0.3% of its retail and requirements wholesale sales at an average
cost of 4.3 cents per Kwh, based only on operation, maintenance, and fuel
costs incurred during 1994. 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 1994,
the Company utilized 5,800.9 MWh from this unit to meet 0.3% of its
retail and requirements wholesale sales at an average cost of 6.1 cents per
Kwh, based only on operation, maintenance, and fuel costs incurred
during 1994. 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.
NEW YORK POWER PURCHASES:
Rochester Gas and Electric Corporation. In 1988, the Company
entered into a ten-year contract with Rochester Gas and Electric
Corporation (RG&E) for the purchase of up to 50 MW of firm power and
associated energy. Although the Company has no fixed capacity payments,
it must pay to reserve transmission from the Niagara Mohawk Power
Corporation (Niagara Mohawk) for the 50-MW maximum purchase. Both RG&E
and the Company have the option to terminate the agreement effective
1995.
Pursuant to an agreement with Connecticut Light and Power
Corporation (CL&P) and Bozrah Light and Power Company (Bozrah) that was
finalized in December 1992, the Company exercised the option to
terminate the RG&E agreement and the transmission contract with Niagara
Mohawk that supports it effective October 31, 1995. The Company also
agreed to offer power it obtained from RG&E to CL&P for purchase on a
weekly basis through the remaining term of the RG&E agreement and
terminate a contract under which the Company supplied all of the
electrical requirements of Bozrah, a small electric utility operating in
Gilman, Connecticut. In return, CL&P, which replaced the Company as the
supplier of electricity to Bozrah, assumed responsibility for
approximately 75% of the fixed costs of the transmission contract with
Niagara Mohawk, and provided the Company with up to 50 MW of system
power, to be scheduled on a weekly basis, at a total price expected to
be lower than that provided under the existing RG&E agreement. In
addition, CL&P has offered the Company an option, which may be exercised
in yearly increments starting in July 1994, to purchase up to 50
additional MW of system power for the period July 1995 through December
2004.
The arrangement was approved by FERC effective May 1, 1993. The
reductions in the Company's purchased power and fixed transmission costs
derived from this three-party agreement will more than offset the loss
of revenues associated with the termination of its electricity sales
agreement with Bozrah.
In January 1995, CL&P and the Company signed an amendment to the
agreement to enable the Company to terminate the RG&E agreement in
January 1995, to eliminate the provisions relating to the sale of
capacity and energy by the Company and to provide a price ceiling to
substitute for the RG&E agreement price ceiling as it applies to the
Company's purchase from CL&P. Additionally, contract terms for the
Company's option to purchase up to 50 MW of CL&P system power were
amended to make the power available August 1995-December 2004, and the
Company's deadline for initial elections of said power was extended to
July 31, 1995. Costs associated with this arrangement are as follows:
Charges
1994
Annual Transmission Reservations . . . . . $300,000
Average Cost per kWh . . . . . . . . . . . 3.3 cents (1994)
3.3 cents (1995 estimated)
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, small power producers 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., 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.
In 1994, the Company, through both its direct contracts and the
Vermont Power Exchange, purchased 107,580.7 MWh of small power
production to meet 5.8% of its retail and requirements wholesale sales
at an average cost of 10.2 cents 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 1994, the Company purchased 176,637.0 MWh, 9.5% of the
Company's retail and requirements wholesale sales, at an average cost of
2.5 cents 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 1994, these plants provided 108,520.1 MWh of low-cost energy,
meeting 5.8% of the Company's retail and requirements wholesale sales at
an average cost of 1.0 cents per Kwh, based only on operation, maintenance,
and fuel costs incurred in 1994. 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 1994, the Company's retail and requirements wholesale
sales were provided by the following fuel sources: 38.7% from hydro
(5.8% Company-owned, 0.5% NYPA, 29.6% Hydro-Quebec and 2.8% small power
producers), 36.2% from nuclear, 10.9% from coal, 3.3% from wood, 0.5%
from natural gas, and 0.9% from oil. The remaining 9.5% was purchased
on a short-term basis from other utilities and through NEPOOL.
Vermont Yankee has approximately $133 million 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 $39.3 million 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 1994, Vermont Yankee accumulated
approximately $54 million 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 1994, and, while no assurance can be given,
does not anticipate any such difficulty during 1995. None of the
utilities from which the Company expects to purchase oil- or gas-fired
capacity in 1995 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 contract and
on the spot market from northern West Virginia and southern Pennsylvania
sources. The sponsor of Merrimack advises that, as of February 23,
1995, there was a 72-day supply 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
129,128 tons of wood chips and mill residue and 157,682,000 cubic feet
of gas in 1994. The McNeil plant is forecasting consumption of wood
chips for 1995 to be 120,000 tons and gas consumption of 300,000,000
cubic feet. Burlington Electric Department advises that, as of February
18, 1995, there were 33,904 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.
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 1.5% of operating revenues for 1994.
Late in 1989, the Company began serving a municipal utility,
Northfield Electric Department, under its wholesale tariff. This
customer increased the Company's electricity sales by approximately
23,461 MWh and peak requirements by approximately 6 MW. Revenues in
1994 from Northfield were $1,294,165.
The Company provides transmission service to ten 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 1994.
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 * January 21, 1969 May 1, 1965 - December 31, 1993
Vergennes June 29, 1979 June 1, 1949 - May 31, 1999
Waterbury July 20, 1954 September 1, 1951 - August 31, 2001
* The Company is in the process of relicensing this facility and
anticipates the final FERC license to be issued in 1995. The facility
is currently operating on an annual license.
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 next Integrated Resource Plan, scheduled to be
publised in June 1995, will be developed in a manner consistent with the
Department's Plan. The 1995 Integrated Resource Plan will call 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 total cost of approximately
$49,500,000, including 30 years' 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 is expected to be performed
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.
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
Administrative 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 and 1993, 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 July 31, 1993
(in the total of approximately $4,600,000) 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 both 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, and on May 13, 1994, reflected the Pine Street Marsh
related expenditures referred to above.
In a rate case filed on September 26, 1994, the Company sought
recovery in rates of approximately $2,700,000 in expenses associated
with the Pine Street site. This amount represented the Company's
unrecovered expenditures between August 1993 and June 1994 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 1994 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 of December 31, 1994, such
amounts are approximately $845,000.
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 new 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.
The VPSB and the Department are currently conducting a roundtable
discussion with Vermont utilities, customer groups and other
organizations concerning the potential for expanded retail competition
in Vermont and any structural changes in the industry that will be
required. It is expected that the roundtable will complete its work by
July 1995.
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.
Beginning in the first quarter of 1992, the Company consolidated
four of its wholly owned subsidiaries, including Green Mountain Propane
and Mountain Energy, in its financial statements. The Company's prior
years' financial statements have been restated to reflect this
consolidation. Prior to consolidation, the operations of these
subsidiaries were reported on the equity basis as they were not material
in relation to the consolidated group. Also included in the financial
statements, in equity in earnings of affiliates and non-utility
operations, are the results of the Company's rental water heater
business. None of these activities is regulated by the VPSB.
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 four of the
Company's wholly owned subsidiaries, Green Mountain Propane Gas Company,
Mountain Energy, Inc., GMP Real Estate Corporation, and Lease-Elec, Inc.
(also unregulated). Summarized financial information of the Company's
unregulated activities over the last two years is as follows:
For the years ended December 31
1994 1993
(In thousands)
Revenue . . . . . . . . . . . . . . . $12,031 $11,487
Expense . . . . . . . . . . . . . . . 10,920 11,527
------- ---------
Net Income (Loss) . . . . . . . . . . $ 1,111 ($ 40)
======= =========
EMPLOYEES
The Company had 373 employees, exclusive of temporary employees, as
of December 31, 1994. In addition, subsidiaries of the Company had 59
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 1994 peak
of 308.3 MW occurred on January 26, 1994. 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, 1995:
Name Age
Douglas G. Hyde 52 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 61 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 49 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 46 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 61 Controller since September 1986.
Thomas C. Boucher 40 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 52 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 48 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 57 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 43 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 40 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 50 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 45 Corporate Secretary since December
1993. Assistant Secretary from 1986 to 1993.
Peter H. Zamore 42 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 effective capability of 35.3 MW. It also owns two gas-turbine
generating stations with an aggregate nameplate rating of 59.9 MW and an
estimated effective capability of 60.3 MW. The Company has two diesel
generating stations with an aggregate nameplate rating of 8.0 MW and an
estimated effective capability of 8.4 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 the J. 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, 1994, 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 2,361 miles of overhead lines, 2.4 kV
to 34.5 kV, and about 404 miles of underground cable of 2.4 kV to
34.5 kV. At such date, the Company owned approximately 433,150 kVa of
substation transformer capacity in distribution substations, 156,775 kVa
of transformer capacity in transmission substations and 1,243,450 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 4.2
Gas Berlin, VT Berlin #5 Oil 56.3
Turbine Colchester, VT Gorge #16 Oil 15.2
Jointly Owned Steam Vernon, VT Vermont Yankee Nuclear 90.1(2)
Yarmouth, ME Wyman #4 Oil 7.1
Burlington, VT McNeil Wood 6.6(3)
Combined Ludlow, MA Stony Brook #1 Oil/Gas 30.9(2)
_____
Total Winter Capability 249.9
(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 1994 and 1993:
HIGH LOW
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
1993 First Quarter 35 5/8 31 3/8
Second Quarter 36 1/2 32 5/8
Third Quarter 36 5/8 34 3/8
Fourth Quarter 35 1/8 30 3/4
The number of common stockholders of record as of March 15, 1995
was 6,456.
Quarterly cash dividends were paid as follows for the past two
years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
1994 53 cents 53 cents 53 cents 53 cents
1993 52 1/2 cents 52 1/2 cents 53 cents 53 cents
SELECTED FINANCIAL DATA (In thousands except per share amounts)
Results of operations for the years ended December 31
-----------------------------------------------------
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Operating Revenues........................$148,197 $147,253 $145,240 $143,555 $147,633
Operating Expenses........................ 133,680 132,427 128,828 129,041 133,925
--------- --------- --------- --------- ---------
Operating Income........................ 14,517 14,826 16,412 14,514 13,708
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity.......................... 263 273 186 225 86
Other................................... 3,418 2,360 2,073 2,689 2,037
--------- --------- --------- --------- ---------
Total other income.................... 3,681 2,633 2,259 2,914 2,123
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed funds.................. (539) (357) (202) (131) (394)
Other................................... 7,735 7,185 7,021 7,103 7,259
--------- --------- --------- --------- ---------
Total interest charges................ 7,196 6,828 6,819 6,972 6,865
--------- --------- --------- --------- ---------
Net Income................................ 11,002 10,631 11,852 10,456 8,966
Dividends on Preferred Stock.............. 794 811 831 852 421
--------- --------- --------- --------- ---------
Net Income Applicable to Common Stock..... $10,208 $9,820 $11,021 $9,604 $8,545
========= ========= ========= ========= =========
Common Stock Data
Earnings per share...................... $2.23 $2.20 $2.54 $2.45 $2.29
Cash dividends declared per share....... $2.12 $2.11 $2.08 $2.04 $2.00
Weighted average shares outstanding..... 4,588 4,457 4,345 3,919 3,729
</TABLE>
Financial Condition as of December 31
-------------------------------------
<TABLE>
<CAPTION>
1994 1993 (1) 1992 1991 1990
--------- ---------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Assets
Utility Plant, Net.......................$175,987 $171,411 $164,723 $159,730 $152,370
Other Investments........................ 20,751 22,528 21,700 21,624 19,785
Current Assets........................... 28,798 26,215 28,067 26,778 25,891
Deferred Charges......................... 35,659 33,893 19,012 11,271 10,536
Non-Utility Assets....................... 33,416 28,626 23,716 19,832 11,078
--------- --------- --------- --------- ---------
Total Assets............................$294,611 $282,673 $257,218 $239,235 $219,660
========= ========= ========= ========= =========
Capitalization and Liabilities
Common Stock Equity......................$101,319 $97,149 $92,645 $87,455 $71,942
Redeemable Cumulative Preferred Stock.... 9,135 9,385 9,575 9,825 10,087
Long-Term Debt, Less Current Maturities.. 74,967 79,800 67,644 56,270 60,626
Capital Lease Obligation................. 10,278 11,029 11,950 12,627 12,797
Curent Liabilities....................... 40,441 37,925 30,099 32,893 32,399
Deferred Credits and Other............... 49,434 40,214 33,264 29,694 27,358
Non-Utility Liabilities.................. 9,037 7,171 12,041 10,471 4,451
--------- --------- --------- --------- ---------
Total Capitalization and Liabilities....$294,611 $282,673 $257,218 $239,235 $219,660
========= ========= ========= ========= =========
(1) Certain line items on the 1993 balance sheet have been reclassified for
consistent presentation with the current year.
</TABLE>
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 1994
were $2.23 as compared with $2.20 in 1993. The 1994 earnings represent
an earned return on average common equity of 10.3 percent. In 1993 and
1992, the earned return on equity was 10.3 and 12.2 percent,
respectively.
The 1994 increase in earnings was primarily due to a $722,000 increase
in the earnings of Mountain Energy, Inc., the Company's wholly-owned
subsidiary that invests in electric energy-related development projects,
and a $523,000 increase in earnings of Green Mountain Propane Gas
Company, the Company's wholly-owned propane subsidiary. This increase
was partially offset by an adverse ruling by the Vermont Supreme Court
reversing an order of the Vermont Public Service Board (VPSB) in a 1991
rate decision and the effects of warmer than normal winter weather
during the fourth quarter.
The principal factor contributing to the decrease in 1993 earnings from
1992 was a nearly two-fold increase in purchases of electricity from
independent power producers mandated by federal and state laws.
Operating Revenues and MWH Sales -- Operating revenues and MWH sales
for the years 1994, 1993 and 1992 consisted of:
1994 1993 1992
(Dollars in Thousands)
Operating Revenues:
Retail . . . . . . . . . . . . . $ 131,444 $ 130,061 $ 126,057
Sales for Resale . . . . . . . . 13,521 14,441 17,258
Other . . . . . . . . . . . . . 3,232 2,751 1,925
---------- ---------- ----------
Total Operating Revenues . . . . . $ 148,197 $ 147,253 $ 145,240
========== ========== ==========
Megawatthour Sales:
Retail . . . . . . . . . . . . . 1,691,867 1,688,803 1,692,179
Sales for Resale. . . . . . . . 367,424 331,875 375,894
--------- ---------- ----------
Total Megawatthour Sales . . . . . 2,059,291 2,020,678 2,068,073
========= ========== ==========
Average Number of Customers:
Residential . . . . . . . . . . 68,811 67,994 67,201
Commercial & Industrial . . . . 11,635 11,472 11,269
Other . . . . . . . . . . . . . 76 74 73
------ ------ ------
Total Customers . . . . . . . . . . 80,522 79,540 78,543
====== ====== ======
Differences in operating revenues were due to changes in the following:
1993 1992
to to
1994 1993
(In Thousands)
Operating Revenues:
Retail Rates . . . . . . . . . . . . . . . $1,140 $4,269
Retail Sales Volume . . . . . . . . . . . 244 (265)
Resales and Other Revenues . . . . . . . . (440) (1,991)
------- -------
Increase in Operating Revenues . . . . . . . $ 944 $2,013
======= =======
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.
In 1993, total electricity sales decreased 2.3 percent due principally
to a reduction in wholesale sales. Total operating revenues increased
1.4 percent in 1993 primarily due to a 5.6 percent retail rate increase
that was effective in April 1992. Wholesale revenues declined
16.3 percent in 1993 due principally to the sluggish economy and the
availability of inexpensive, excess power supply in New England.
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 13.7, 13.6 and
13.8 percent of the Company's operating revenues in 1994, 1993 and 1992,
respectively. No other retail customer accounted for more than
one percent of the Company's revenue.
Power Supply Expenses -- Power supply expenses constituted 59.2 percent,
59.7 percent and 58.1 percent of total operating expenses for the years
ended 1994, 1993 and 1992, respectively. These expenses increased by
$190,000 (0.2 percent) in 1994, and by $4.1 million (5.5 percent) in
1993.
Power supply expenses were virtually unchanged in 1994 from 1993.
Power supply expenses increased in 1993 due primarily to a nearly two-
fold increase in purchases of electricity from independent power
producers mandated by federal and state laws.
Other Operating Expenses -- Other operating expenses were virtually
unchanged in 1994 from 1993.
Other operating expenses were virtually unchanged in 1993 from 1992.
Transmission Expenses -- The Company's continuing restructuring of a
series of transmission contracts produced a 3.7 percent decrease in
transmission expenses in 1994.
The Company's restructuring of a series of transmission contracts
produced a 3.0 percent decrease in transmission expenses in 1993.
Maintenance Expenses -- Maintenance expenses increased 2.6 percent in
1994 due principally to a scheduled increase in plant maintenance.
Maintenance expenses decreased 7.3 percent in 1993 due principally to
scheduled increases in various capital projects that had the effect of
reducing activity by Company employees on maintenance projects.
Depreciation and Amortization -- Depreciation and amortization expenses
increased 24.6 percent in 1994 due principally to the amortization of
expenditures related to energy conservation programs and to the Pine
Street Marsh environmental matter (discussed in Note I of the Notes to
Consolidated Financial Statements) and to additional investment in the
Company's distribution facilities.
Depreciation and amortization expenses increased 6.3 percent in 1993,
reflecting continuing additions to the Company's distribution
facilities.
Income Taxes -- The effective federal tax rates for the years 1994, 1993
and 1992 were 25.1 percent, 28.9 percent and 28.8 percent, respectively.
Other Income -- Other income increased 39.8 percent in 1994 due
primarily to an $722,000 increase in earnings of Mountain Energy, Inc.,
and a $523,000 increase in earnings of Green Mountain Propane Gas
Company.
Other income increased 16.6 percent in 1993 due primarily to an increase
in earnings of Mountain Energy, Inc., and to the VPSB's disallowance in
1992 of approximately $400,000 in construction costs sought to be
recovered in a rate case.
Interest Charges -- 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.
Interest charges were virtually unchanged in 1993 from 1992.
Dividends on Preferred Stock -- 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.
Dividends on preferred stock decreased 2.4 percent in 1993 due primarily
to the repurchase by the Company in 1992 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.
Future Outlook -- 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 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 that the demand for electricity in its service
territory will grow by approximately 1.3 percent per year over the next
five years.
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
is expected to be affected by federal and State environmental compliance
requirements.
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.
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 and 1993, 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 July 31, 1993 (in the
total of approximately $4.6 million) for technical consultants and legal
assistance in connection with the Environmental Protection Agency (EPA)
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 both 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, and on May 13, 1994, reflected
the Pine Street Marsh related expenditures referred to above.
In a rate case filed on September 26, 1994, the Company sought recovery
in rates of approximately $2.7 million in expenses associated with the
Pine Street site. This amount represented the Company's unrecovered
expenditures between August 1993 and June 1994 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 in the
case have reached agreement that the full amount of Pine Street costs
reflected in the Company's 1994 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 of December 31, 1994, such
amounts are approximately $845,000.
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 and 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 forecasted 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)
1992 $ 868 $1,766 $7,320 $3,144 $2,925 $16,023
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
Forecasted
1995 $2,785 $1,038 $8,457 $3,698 $5,998 $21,976
1996 2,198 999 8,660 2,499 5,503 19,859
1997 1,299 1,499 8,999 2,444 2,102 16,343
1998 2,278 999 9,212 2,542 2,236 17,267
1999 2,777 999 9,509 2,643 2,137 18,065
Other Cash Requirements -- In 1995, the Company may devote $4 million to
unregulated investments.
Rates -- 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 remedial
investigation/feasibility study 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 above. The agreement was approved by
the VPSB on May 13, 1994.
On September 26, 1994, the Company filed a request with the VPSB to
increase retail rates by 13.9 percent. The increase is 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 must be reviewed and approved by the VPSB
before it can take effect.
Financing and Capitalization -- For the period 1992 through 1994,
internally generated funds, after payment of dividends, provided
approximately 56 percent of total capital requirements for construction,
sinking funds and other requirements. The Company anticipates that for
the period 1995-1999, internally generated funds will provide
approximately 90 percent of total capital requirements.
At December 31, 1994, the Company's capitalization consisted of
53.3 percent common equity, 41.9 percent long-term debt and 4.8 percent
preferred equity. The Company has a comprehensive capital plan to
maintain approximately this balance of common equity, long-term debt and
preferred equity.
The Company anticipates issuing $15 million of common stock and
$10 million of first mortgage bonds in 1995. The proceeds will be used
to finance capital projects and to retire short-term debt.
The rating of the Company's first mortgage bonds was lowered in
September 1994 by Standard & Poor's from "A-" to "BBB+", reflecting
Standard & Poor's assessment that the electric utility industry is
becoming increasingly more competitive. Standard & Poor's changed its
"outlook" of the Company from "negative" to "stable", reflecting
Standard & Poor's recognition of the Company's competitive rates, solid
operations and management, and diverse fuel mix.
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+". On
a positive note, Duff & Phelps concluded that the Company's cost and
rate structure is one of the lowest in New England, the Company's
service territory has experienced minimal exposure to competitive forces
and regulation is not expected to become a factor in the near term and
should lag behind the rest of the nation.
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, 1994, 1993 and 1992 39
Consolidated Statements of Cash Flows for the
Years Ended December 31, 1994, 1993 and 1992 40
Consolidated Balance Sheets as of
December 31, 1994 and 1993 41
Consolidated Capitalization data as of
December 31, 1994 and 1993 43
Notes to Consolidated Financial Statements 44
Report of Independent Public Accountants 66
Schedules
For the Years Ended December 31, 1994, 1993 and 1992:
II Valuation and Qualifying Accounts and Reserves 67
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 80
STATEMENTS OF CONSOLIDATED INCOME
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
<TABLE>
<CAPTION>
1994 1993 1992
----------------- --------------- ---------------
(In thousands except amounts per share)
<S> <C> <C> <C>
Operating Revenues (Note A)..................................... $148,197 $147,253 $145,240
----------------- --------------- ---------------
Operating Expenses
Power Supply (Notes A, B and K)
Vermont Yankee Nuclear Power Corporation................... 30,300 29,785 29,230
Company-owned generation................................... 3,113 3,150 3,804
Purchases from others...................................... 45,777 46,066 41,878
Other operating............................................... 17,296 17,353 17,239
Transmission (Note J)......................................... 10,374 10,775 11,103
Maintenance................................................... 4,465 4,352 4,692
Depreciation and amortization (Note A)........................ 10,683 8,572 8,065
Taxes other than income....................................... 6,277 6,125 5,902
Income taxes (Note G)......................................... 5,395 6,249 6,915
----------------- --------------- ---------------
Total operating expenses................................... 133,680 132,427 128,828
----------------- --------------- ---------------
Operating Income......................................... 14,517 14,826 16,412
----------------- --------------- ---------------
Other Income
Equity in earnings of affiliates and
non-utility operations (Note B)............................ 3,112 2,341 2,178
Allowance for equity funds used during construction (Note A).. 263 273 186
Other income and deductions, net.............................. 306 19 (105)
----------------- --------------- ---------------
Total other income.......................................... 3,681 2,633 2,259
----------------- --------------- ---------------
Income before interest charges............................ 18,198 17,459 18,671
----------------- --------------- ---------------
Interest Charges
Long-term debt................................................ 6,868 6,539 6,542
Other......................................................... 867 646 479
Allowance for borrowed funds used during
construction (Note A)...................................... (539) (357) (202)
----------------- --------------- ---------------
Total interest charges...................................... 7,196 6,828 6,819
----------------- --------------- ---------------
Net Income...................................................... 11,002 10,631 11,852
Dividends on preferred stock.................................... 794 811 831
----------------- --------------- ---------------
Net Income Applicable to Common Stock........................... $10,208 $9,820 $11,021
================= =============== ===============
Common Stock Data (Notes A and C)
Earnings per share............................................ $2.23 $2.20 $2.54
Cash dividends declared per share............................. $2.12 $2.11 $2.08
Weighted average shares outstanding........................... 4,588 4,457 4,345
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOW
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1994 1993 1992
--------- --------- ---------
(In thousands)
<S> <C> <C> <C>
Operating Activities:
Net Income........................................................... $11,002 $10,631 $11,852
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization (Note A)........................... 10,683 8,572 8,065
Dividends from associated companies less equity income (Note B).. 202 254 659
Allowance for funds used during construction (Note A)............ (803) (630) (388)
Deferred purchased power costs (Note A).......................... (524) (6,407) (5,347)
Amortization of purchased power costs (Note A)................... 4,171 3,717 3,825
Deferred income taxes (Note G)................................... 1,585 5,180 3,089
Amortization of gain on sale of property......................... (53) (53) (53)
Amortization of investment tax credits (Note G).................. (283) (283) (284)
Environmental proceedings costs, net (Note I).................... 7,103 (2,472) (2,612)
Changes in:
Special deposits............................................... -- -- 90
Accounts receivable............................................ (426) 2,384 (433)
Accrued utility revenues....................................... 126 (538) (368)
Fuel, materials, and supplies.................................. (473) 53 (113)
Prepayments and other current assets........................... (1,982) 1,069 (1,401)
Accounts payable............................................... (2,327) 513 1,521
Taxes accrued.................................................. 1,044 (418) (315)
Interest accrued............................................... (117) 903 (733)
Other current liabilities...................................... (65) (2,745) 1,175
Other............................................................ 2 (2,620) 97
--------- --------- ---------
Net cash provided by operating activities.......................... 28,865 17,110 18,326
--------- --------- ---------
Investing Activities:
Construction expenditures.......................................... (13,536) (15,949) (15,327)
Conservation expenditures.......................................... (5,433) (7,418) (3,006)
Investment in nonutility property.................................. 254 (5,950) (282)
Special fund for postretirement benefits (Note A).................. -- (601) (56)
--------- --------- ---------
Net cash used in investing activities............................ (18,715) (29,918) (18,671)
--------- --------- ---------
Financing Activities:
Reduction in preferred stock (Note D).............................. (250) (190) (250)
Issuance of common stock (Note C).................................. 3,671 4,077 3,195
Short-term debt, net (Note F)...................................... 1,198 7,402 (2,093)
Sale of first mortgage bonds (Note E).............................. -- 20,000 17,000
Reduction in long-term debt (Note E)............................... (1,800) (8,530) (7,246)
Cash dividends..................................................... (10,504) (10,204) (9,857)
--------- --------- ---------
Net cash provided by (used in) financing activities.............. (7,685) 12,555 749
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... 2,465 (253) 404
Cash and cash equivalents at beginning of year..................... 227 480 76
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $2,692 $227 $480
========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION December 31
<TABLE>
<CAPTION>
1994 1993
--------- ---------
(In thousands)
ASSETS
<S> <C> <C>
Electric Utility
Utility Plant (Notes A, E and I)
Utility plant, at original cost....................$227,991 $214,977
Less accumulated depreciation...................... 69,246 64,226
--------- ---------
Net utility plant................................ 158,745 150,751
Property under capital lease (Note J).............. 10,278 11,029
Construction work in progress...................... 6,964 9,631
--------- ---------
Total utility plant, net......................... 175,987 171,411
--------- ---------
Other Investments
Associated companies, at equity (Notes A,B and I).. 16,684 16,886
Other investments (Note A)......................... 4,067 5,642
--------- ---------
Total other investments.......................... 20,751 22,528
--------- ---------
Current Assets
Cash............................................... 2,113 50
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 15,240 14,814
Accrued utility revenues (Note A).................. 6,012 6,138
Fuel, materials and supplies, at average cost...... 3,314 2,841
Prepayments........................................ 1,796 1,984
Other.............................................. 323 388
--------- ---------
Total current assets............................. 28,798 26,215
--------- ---------
Deferred Charges
Demand side management programs................... 16,172 12,809
Environmental proceedings costs.................... 7,741 5,356
Purchased power costs.............................. 488 4,134
Other.............................................. 11,258 11,594
--------- ---------
Total deferred charges........................... 35,659 33,893
--------- ---------
Non-Utility
Cash and cash equivalents.......................... 579 177
Other current assets............................... 5,716 3,479
Property and equipment............................. 11,329 11,331
Intangible assets.................................. 3,022 3,484
Other assets....................................... 12,770 10,155
--------- ---------
Total non-utility assets......................... 33,416 28,626
--------- ---------
Total Assets...........................................$294,611 $282,673
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
GREEN MOUNTAIN POWER CORPORATION December 31
<TABLE>
<CAPTION>
1994 1993
--------- ---------
(In thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
Electric Utility
Capitalization (See Capitalization Data)
Common Stock Equity (Note C)
Common stock..................................... $15,592 $15,120
Additional paid-in capital....................... 60,378 57,178
Retained Earnings................................ 25,727 25,229
Treasury stock, at cost.......................... (378) (378)
--------- ---------
Total common stock equity...................... 101,319 97,149
Redeemable cumulative preferred stock (Note D)..... 9,135 9,385
Long-term debt, less current maturities (Note E)... 74,967 79,800
--------- ---------
Total capitalization........................... 185,421 186,334
--------- ---------
Capital Lease Obligation (Note J)...................... 10,278 11,029
--------- ---------
Current Liabilities
Current maturuties of long-term debt............... 4,833 1,800
Short-term debt (Note F)........................... 20,214 19,015
Accounts payable, trade, and accrued liabilities... 5,489 8,373
Accounts payable to associated companies (Note B).. 4,860 4,302
Dividends declared................................. 194 199
Customer deposits.................................. 964 1,197
Taxes Accrued...................................... 1,442 397
Interest accrued................................... 1,953 2,070
Other.............................................. 492 572
--------- ---------
Total current liabilities...................... 40,441 37,925
--------- ---------
Deferred Credits
Accumulated deferred income taxes (Note G)......... 22,082 21,001
Unamortized investment tax credits (Note G)........ 5,390 5,672
Other (Note A)..................................... 21,962 13,541
--------- ---------
Total deferred credits......................... 49,434 40,214
--------- ---------
Non-Utility
Current liabilities................................ 918 666
Other liabilities.................................. 8,119 6,505
--------- ---------
Total non-utility liabilities.................. 9,037 7,171
--------- ---------
Total Capitalization and Liabilities...................$294,611 $282,673
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION December 31
Issued and Outstanding
CAPITAL STOCK Authorized 1994 1993 1994 1993
----------- ---------- ---------- --------- ---------
(In thousands)
<S> <C> <C> <C> <C> <C>
Common Stock,$3.33 1/3 par value (Note C)..................10,000,000 4,677,512 4,536,042 $15,592 $15,120
========= =========
-----------------------------------------------------------------------------------------------------------------
Authorized Outstanding
and Issued 1994 1993 1994 1993
----------- ---------- ---------- --------- ---------
(In thousands)
Redeemable Cumulative Preferred Stock,
$100 par value (Note D)
4.75%,Class B, redeemable at
$101 per share........................................ 15,000 3,450 3,900 $345 $390
7%,Class C, redeemable at
$101 per share........................................ 15,000 5,100 5,550 510 555
9.375%,Class D,Series 1,
redeemable at $101 per share.......................... 40,000 12,800 14,400 1,280 1,440
8.625%,Class D,Series 3,
redeemable at $104.793 per share...................... 70,000 70,000 70,000 7,000 7,000
--------- ---------
Total Preferred Stock...................................... $9,135 $9,385
========= =========
LONG-TERM DEBT (Note E) 1994 1993
--------- ---------
(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........................................................................................ 10,800 12,600
10.0% Series due 2004 - Cash sinking fund,$1,700,000
annually........................................................................................ 17,000 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........................................................................................ 4,000 4,000
5.71% Series due 2000............................................................................... 5,000 5,000
6.7% series due 2018................................................................................ 15,000 15,000
--------- ---------
Total Long-term Debt Outstanding...................................................................... 79,800 81,600
Less Current Maturities (due within one year)....................................................... 4,833 1,800
--------- ---------
Total Long-term Debt, Net............................................................................. $74,967 $79,800
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
Notes to Consolidated Financial Statements
A. Significant Accounting Policies
1. System of Accounts
The Company's 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
Vermont Public Service Board (VPSB).
2. Basis of Presentation
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 four of the Company's wholly
owned subsidiaries, Green Mountain Propane Gas Company, Mountain Energy,
Inc., GMP Real Estate Corporation, and Lease-Elec, Inc. (also
unregulated). Summarized financial information is as follows:
For the years ended December 31
1994 1993
(In thousands)
Revenue . . . . . . . . . . . . . . . $12,031 $11,487
Expense. . . . . . . . . . . . . . . . 10,920 11,527
------- ---------
Net Income (Loss) . . . . . . . . . . $ 1,111 ($ 40)
======= =========
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.
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:
1994 1993 1992
(In thousands)
Interest . . . . . . . . . . . . . . . . $7,714 $6,206 $7,683
Income Taxes (Net of refunds) . . . . . $3,088 $1,920 $3,511
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 6.9 percent, 7.2 percent and 8.9 percent for the years
1994, 1993 and 1992, 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,
3.6 percent and 3.5 percent of total depreciable property at the
beginning of the year for 1994, 1993 and 1992, respectively.
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, 1994 deferred charges totaled $35.7 million, consisting
of charges for conservation programs, response and litigation costs
attributable to the Pine Street Marsh site discussed in Note I.1, repair
costs for and relicensing of the Essex hydroelectric facility, repair
costs for the Vergennes hydroelectric facility, Hydro-Quebec power
contract negotiations and support charges, regulatory deferrals of storm
damages, PCB clean-up, regulatory deferrals of rights-of-way
maintenance, costs associated with the 1993 and 1995 scheduled Vermont
Yankee outages, postretirement health care costs, and various other
projects and deferrals.
8. Earnings Per Share
Earnings per share are based upon 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 13.7, 13.6 and 13.8 percent of operating
revenues in 1994, 1993 and 1992, 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 in accordance with methods approved in the rate-setting process.
Net pension costs reflect the following components and assumptions:
1994 1993 1992
(Dollars in thousands)
Service cost-benefits earned during the period . $ 768 $ 748 $ 676
Interest cost on projected benefit obligations . 1,633 1,593 1,466
Actual return on plan assets . . . . . . . . . . (1,296) (3,107) (1,743)
Net amortization and deferral . . . . . . . . . . (906) 1,141 (77)
Adjustment due to actions of regulator . . . . . (174) 337 430
------- ------ ------
Net periodic pension cost funded and recognized . $ 25 $ 712 $ 752
======= ====== ======
Assumptions used to determine pension costs in 1994, 1993 and 1992 were:
Discount rate . . . . . . . . . . . . . . . . 7.5% 8.0% 8.0%
Rate of increase in future compensation levels 5.0% 6.0% 6.0%
Expected long-term rate of return on assets . 9.0% 9.0% 9.0%
The following table sets forth the Plan's funded status as of December 31:
1994 1993 1992
(In thousands)
Actuarial present value of benefit obligations:
Accumulated benefit obligations,
including vested benefits of $18,184,
$16,825 and $15,100, respectively . . . . . $(18,479) ($17,105) ($15,262)
========= ========= =========
Projected benefit obligations for
service rendered to date . . . . . . . . . (21,363) ($21,002) ($19,235)
Plan assets at fair value . . . . . . . . . . . 24,171 23,981 21,167
--------- --------- ---------
Assets in excess of projected
benefit obligations . . . . . . . . . . . . . 2,808 2,979 1,932
Unrecognized net loss (gain) from past
experience different from that assumed . . . (285) (272) 559
Prior service cost not yet recognized in net
periodic pension cost . . . . . . . . . . . . 1,642 1,885 2,028
Unrecognized net asset at transition
being recognized over 16.47 years . . . . . . (1,934) (2,162) (2,391)
Adjustment due to actions of regulator . . . . . (2,231) (2,430) (2,128)
--------- --------- ---------
Prepaid pension cost included in other assets . $ --- $ --- $ ---
========= ========= =========
As of December 31, 1994, the discount rate used to determine the
accumulated benefit obligation was 8.0 percent.
The Company has evaluated the effect of a reduction in the discount rate
and compensation trend rate and has concluded that the net effect of
such changes is insignificant.
The plan assets consist primarily of cash equivalent funds, fixed income
securities and listed equity securities.
The Company also has a supplemental pension plan for certain employees.
Pension costs for the years ended December 31, 1994, 1993 and 1992 were
$381,000, $384,000 and $377,000, 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, 1994 were refinanced using new issue debt rates of interest, which,
on average, are higher than the Company's outstanding rates, the present
value of those obligations would differ from the amounts outstanding on
the December 31, 1994 balance sheet by 3 percent. The Company does not
anticipate a refinancing; however, if such an event were to occur, 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.
On January 1, 1993, the Company adopted the standard on accounting for
postretirement health care and other benefits, SFAS 106, which requires
the Company to use accrual accounting for postretirement benefits other
than pensions. Prior to 1993, the Company recognized the cost of
postretirement health care benefits by recording an amount equivalent to
that which had been allowed in rates. The difference between total cost
and claims paid was accrued on the balance sheet.
The VPSB requires the Company to fund postretirement health care costs.
Accordingly, at December 31, 1993, the Company had deposited
$2.1 million in an investment fund, which is included in other
investments in the accompanying 1993 balance sheet. In January 1994, in
order to maximize the tax deductible contributions that are allowed
under IRS regulations, the Company amended its pension plan and
established separate VEBA trusts for its union and nonunion employees.
At December 31, 1994 all funds available for postretirement health care
benefits, including the $2.1 million previously funded, were deposited
in the VEBA trust.
The Company will seek and expects to receive rate recovery for all
amounts expended for postretirement health care benefits.
Net postretirement benefits costs for 1994 reflect the following
components and assumptions:
1994 1993
(In thousands)
Accumulated postretirement benefit obligation:
Current retirees . . . . . . . . . . . . . . . . . ($ 3,497) ($3,628)
Participants currently eligible . . . . . . . . . (1,863) (2,288)
All others . . . . . . . . . . . . . . . . . . . . (3,785) (4,789)
--------- --------
Total accumulated postretirement benefit obligation . (9,145) (10,705)
Plan assets at fair value . . . . . . . . . . . . . . 3,433 ---
--------- --------
Accumulated postretirement benefit obligation in excess
of plan assets . . . . . . . . . . . . . . . . . . (5,712) (10,705)
Unrecognized transition obligation . . . . . . . . . 6,485 6,845
Unrecognized net loss (gain) . . . . . . . . . . . . (1,777) 538
--------- ---------
Accrued postretirement benefit cost . . . . . . . . . ($ 1,004) ($ 3,322)
========= =========
Net periodic postretirement benefit cost for 1994 includes the following
components:
1994 1993
(In thousands)
Service cost . . . . . . . . . . . . . . . . . . . . $ 407 $ 438
Interest cost . . . . . . . . . . . . . . . . . . . 864 940
Actual return on plan assets . . . . . . . . . . . . (127) ---
Deferred asset gain . . . . . . . . . . . . . . . . (107) ---
Recognition of transition obligation,
net of amortization . . . . . . . . . . . . . . . 361 380
------- -------
Total net periodic postretirement benefit cost $ 1,398 $ 1,758
======= =======
The discount rate used to determine postretirement benefit costs in 1994
was 7.5 percent; the discount rate used to determine the accumulated
postretirement benefit obligation at December 31, 1994 was 8.5 percent.
For measurement purposes, an 11.5 percent annual rate of increase in the
per capita cost of covered benefits was assumed for 1994; 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, 1994 by $1.5 million and the aggregate of the service
and interest components of net periodic postretirement benefit cost for
the year ended December 31, 1994 by $267,000.
13. Deferred Credits
The Company has deferred credits and other long-term liabilities of
$22.0 million, consisting of operating lease equalization, reserves for
damage claims and environmental liabilities and accruals for employee
benefits.
14. Reclassification
Certain line items on the prior year balance sheet 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, 1994 1994 1993
(In thousands)
VELCO - Common . . . . . . . . . 29.5% $ 1,814 $ 1,816
- Preferred . . . . . . . 30.0% 1,418 1,572
------- -------
Total VELCO . . . . . . . . . . 3,232 3,388
Vermont Yankee - Common . . . . 17.9% 9,766 9,745
New England Hydro-Transmission -
Common . . . . . . . . . . 3.18% 1,398 1,408
New England Hydro-Transmission
Electric - Common . . . . . 3.18% 2,288 2,345
------- -------
$16,684 $16,886
======= =======
Undistributed earnings in associated companies totaled $1,089,000 at
December 31, 1994.
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
$7.9 million, $8.0 million and $7.8 million for the years 1994, 1993 and
1992, 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,
1994 1993 1992
(In thousands)
Company's equity in net income . . . . . . . $ 386 $ 406 $ 448
======= ======= =======
Total assets . . . . . . . . . . . . . . . . $69,724 $70,199 $70,821
Less:
Liabilities and long-term debt . . . . . 58,850 58,806 58,889
------- ------- -------
Net assets . . . . . . . . . . . . . . . . . $10,874 $11,393 $11,932
======= ======= =======
Company's equity in net assets . . . . . . . $ 3,232 $ 3,388 $ 3,554
======= ======= =======
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 520 megawatts. Vermont
Yankee's current estimate of decommissioning is approximately $330 million
in 1994 dollars, of which $115 million has been funded. At December 31,
1994, the Company's portion of the net unfunded liability was $37 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 1994, the Company incurred $24.2 million in Vermont
Yankee annual capacity charges, which included $1.6 million for interest
charges. The Company's share of Vermont Yankee's long-term debt at December
31, 1994 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 1993 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 $6.4 million at the
time of the first loss and $13.8 million at the time of a subsequent loss
and the NEIL III maximum retroactive assessment is $8.4 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,
1994 1993 1992
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . . $162,757 $180,145 $175,919
Net income applicable to common stock . 6,588 7,793 7,921
Company's equity in net income . . . . . 1,143 1,425 1,415
Total assets . . . . . . . . . . . . . . . $512,142 $469,770 $438,208
Less:
Liabilities and long-term debt . . . . . 457,669 415,606 383,933
-------- -------- --------
Net assets . . . . . . . . . . . . . . . . $ 54,473 $ 54,164 $ 54,275
======== ======== ========
Company's equity in net assets . . . . . . $ 9,766 $ 9,745 $ 9,731
======== ======== ========
C. Common Stock Equity
The Company maintains a Dividend Reinvestment and Stock Purchase Plan
(DRIP) under which 284,153 shares were reserved and unissued at December
31, 1994. The Company also funds an Employee Savings and Investment
Plan (ESIP). At December 31, 1994, there were 15,556 shares reserved
and unissued under the ESIP.
In May 1993, the Company amended its Articles of Association increasing
the number of authorized shares of common stock from 6,000,000 to
10,000,000.
Changes in common stock equity for the years ended December 31, 1992,
1993 and 1994 are as follows:
<TABLE>
<CAPTION>
Common Stock Treasury Stock
------------------------ Paid-in Retained ------------------------ Stock
Shares Amount Capital Earnings Shares Amount Equity
------ ------ ------- -------- ------ ------ ------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, December 31, 1991............... 4,307,558 $14,359 $50,668 $22,806 15,856 ($378) $87,455
Common Stock Issuance:
DRIP:.................................. 84,637 282 2,251 2,533
ESIP:.................................. 21,342 71 591 662
Net Income............................... 11,852 11,852
Cash Dividends on Capital Stock:
Common Stock -$2.08 per share..... (9,029) (9,029)
Preferred Stock -$4.75 per share..... (22) (22)
-$7.00 per share..... (41) (41)
-$9.375 per share.... (161) (161)
-$8.625 per share.... (604) (604)
------------------------------------------------------------------------------------
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
====================================================================================
</TABLE>
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, $19.9 million of retained earnings were free of restrictions
at December 31, 1994.
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, 1994, $259,000 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:
Purchased and Sinking Fund
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
The 8.625%, Class D, Series 3, preferred stock issued in September 1990
requires no sinking fund.
Under the Restated Articles of Association relating to Redeemable
Cumulative Preferred Stock, the annual aggregate amounts of purchase and
sinking fund requirements for the next five years are $250,000 for 1995
and $1,650,000 for the years 1996 - 1999.
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 $4.793 per share until September
1, 1995; $3.835 per share from September 1, 1995 to 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.
In May 1993, the Company amended its Articles of Association authorizing
a new class of preferred stock, Class E, which may be divided into and
issued in series. No shares of Class E preferred stock were issued as
of December 31, 1994.
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)
1995 . . . . . . . . . . . . . . $4,833 $ --- $4,833
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
Non-Utility
At December 31, 1994, Green Mountain Propane Gas Company, the Company's
propane subsidiary, had long-term debt of $4.5 million, which was
secured by substantially all of the subsidiary's assets. The annual
sinking fund requirements and maturities for the next five years are:
Sinking
Funds Maturities Total
(In thousands)
1995 . . . . . . . . . . . . . $ 600 $ --- $ 600
1996 . . . . . . . . . . . . . 1,000 --- 1,000
1997 . . . . . . . . . . . . . 1,000 --- 1,000
1998 . . . . . . . . . . . . . 1,000 --- 1,000
1999 . . . . . . . . . . . . . --- 900 900
F. Short-term Debt
Utility
At December 31, 1994, the Company had lines of credit with six banks
totaling $39.5 million, with borrowings outstanding of $20.2 million.
Borrowings under these lines of credit are at interest rates ranging
from less than prime to the prime rate. The Company has fee
arrangements on its lines of credit ranging from 1/4 to 3/8 percent and
no compensating balance requirements. These lines of credit are subject
to periodic review and renewal during the year by the various banks.
The weighted average interest rate on borrowings outstanding on December
31, 1994 and December 31, 1993 was 6.4 percent and 3.7 percent,
respectively.
Non-Utility
At December 31, 1994, Green Mountain Propane Gas Company, the Company's
propane subsidiary, had a line of credit with a bank for $2.0 million,
with no borrowings outstanding.
G. Income Taxes
Utility
On January 1, 1993, the Company adopted the standard on accounting for
income taxes, SFAS 109, which requires an asset and liability approach
for financial accounting and reporting for income taxes.
When implementing SFAS 109 the Company created additional deferred tax
assets of $4.8 million and deferred tax liabilities of $5.6 million to
give recognition to certain temporary differences previously not
recognized in the Company's financial statements. These additional
deferred taxes will be collected from or returned to ratepayers in
future periods and, accordingly, the Company recognized a regulatory
liability and regulatory asset related to income taxes of $4.8 million
and $5.6 million, respectively. The implementation of SFAS 109 on
January 1, 1993, and the application of SFAS 109 had no material impact
on the Company's results of operations or cash flows in the twelve
months ended December 31, 1994. Additionally, the Company does not
believe SFAS 109 will significantly impact future results of operations
or cash flows based on current ratemaking policy.
The implementation of SFAS 109 also requires the Company to consider now
the future utilization of deferred tax assets. If there is doubt that
the Company will be able to utilize these future tax benefits, it might
be necessary to establish a valuation allowance. The Company has
concluded that it is not necessary at this time to establish a valuation
allowance. The Company has been in a tax-paying position for
approximately ten years and does not foresee future events that will
alter the Company's capacity to utilize these deductions when intended.
The temporary differences which gave rise to the net deferred tax
liability at December 31, 1994 and December 31, 1993, were as follows:
At December 31, At December 31,
1994 1993
(In thousands)
Deferred Tax Assets
Contributions in aid of construction $ 5,857 $ 5,094
Deferred compensation and
postretirement benefits . . . . . . 2,296 3,387
Alternative minimum tax credit . . . (829) 749
Excess deferred taxes . . . . . . . . 2,089 2,188
Unamortized investment tax credits . 2,277 2,402
Other . . . . . . . . . . . . . . . . 3,352 1,018
------- -------
$15,042 $14,838
======= =======
Deferred Tax Liabilities
Property-related and other . . . . . $26,487 $25,090
Demand side management costs . . . . 6,457 5,841
Unamortized investment tax credits . 5,390 5,672
Reversal of previously flowed-through
tax depreciation . . . . . . . . . 3,499 4,182
AFUDC equity basis adjustment . . . . 680 726
------ ------
42,513 41,511
Net accumulated deferred income tax
(liability) . . . . . . . . . . . . ($27,471) ($26,673)
========= =========
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:
Net change in deferred income tax liability per above table . . . $ (798)
Change in income tax related regulatory assets and liabilities. . 505
Other adjustments . . . . . . . . . . . . . . . . . . . . . . . . 17
-------
Deferred income tax expense for the period . . . . . . . . . . . $ (276)
=======
The components of the provision for income taxes are as follows:
Year Ended December 31,
1994 1993 1992
(In thousands)
Current state income taxes . . . . . . . $ 1,205 $ 134 $ 796
Deferred state income taxes . . . . . . 70 1,225 716
Current federal income taxes . . . . . . 4,466 369 3,007
Deferred federal income taxes . . . . . (63) 4,804 2,678
Investment tax credits -- net . . . . . (283) (284) (284)
------ ------ -----
Total income taxes . . . . . . . . . . . 5,395 6,248 6,913
Amounts included in "Other income" . . . -- 1 2
------ ------ ------
Income taxes charged to operations . . . $5,395 $6,249 $6,915
====== ====== ======
The following table details the components of the provisions for deferred
federal income taxes:
Year Ended December 31,
1994 1993 1992
(In thousands)
Deferred purchase power costs . . . . . $(1,310) $ 985 $ 518
Excess tax depreciation . . . . . . . . 1,387 1,417 1,648
Demand side management . . . . . . . . 1,013 2,090 799
State tax benefit . . . . . . . . . . . 39 (416) (211)
Contributions in aid of construction . (657) (440) (813)
Supplemental benefit plans . . . . . . 26 (198) (46)
Postretirement health care benefits . . 824 (95) (158)
Pine Street . . . . . . . . . . . . . . (1,915) 890 258
Other . . . . . . . . . . . . . . . . . 530 571 683
------- ------ ------
$ (63) $4,804 $2,678
======= ====== ======
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,
1994 1993 1992
(Dollars in thousands)
Income before income tax . . . . . . . $16,398 $16,880 $18,765
Federal statutory rate . . . . . . . . 34% 34% 34%
Computed "expected" federal
income taxes . . . . . . . . . . . . $ 5,575 $ 5,739 $ 6,380
Increase (decrease) in taxes
resulting from:
Tax versus book depreciation . . . . 327 327 357
Dividends received and paid credit . (499) (580) (597)
AFUDC - equity funds . . . . . . . . (89) (93) (63)
Amortization of ITC . . . . . . . . (283) (284) (284)
State tax benefit . . . . . . . . . (433) (462) (514)
Excess deferred taxes . . . . . . . (60) (60) (60)
Other . . . . . . . . . . . . . . . (418) 302 182
-------- ------- -------
Total federal income taxes . . . . . . $ 4,120 $ 4,889 $ 5,401
======== ======= =======
Effective federal income tax rate . . 25.1% 28.9% 28.8%
Non-Utility
The Company's non-utility subsidiaries had accumulated deferred income
taxes of $3.2 million on their balance sheets at December 31, 1994,
largely attributable to property-related transactions.
The components of the provision for income taxes for the non-utility
operations are:
Year Ended December 31,
1994 1993 1992
(In thousands)
State income taxes . . . . . . . . . . $123 $ (58) $(104)
Federal income taxes . . . . . . . . . 444 (224) (314)
Investment tax credits . . . . . . . . (45) (45) (45)
----- ------ ------
Income taxes charged to operations . . $522 $(327) $(463)
===== ====== ======
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 29.0 percent, 34.2 percent and 33.3 percent for the years ended
1994, 1993 and 1992, 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.
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
1993 Quarter Ended
March June Sept. Dec. Total
(Amounts in thousands, except per share)
Operating Revenues . . . . . . $40,751 $33,427 $35,647 $37,428 $147,253
Operating Income . . . . . . . 5,160 2,093 3,075 4,498 14,826
Net Income . . . . . . . . . . 4,302 966 2,051 3,312 10,631
Net Income Applicable to
Common Stock . . . . . . . . 4,099 763 1,848 3,110 9,820
Earnings per Average Share of
Common Stock . . . . . . . . $0.93 $0.17 $0.41 $0.69 $2.20
Weighted Average Number of
Common Shares Outstanding . 4,415 4,442 4,470 4,503 4,457
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 total cost of approximately
$49.5 million, including 30 years' 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 is expected to be performed
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.
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 and 1993, 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 July 31, 1993 (in the
total of approximately $4.6 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 both 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, and on May 13, 1994, reflected the Pine Street Marsh related
expenditures referred to above.
In a rate case filed on September 26, 1994, the Company sought recovery
in rates of approximately $2.7 million in expenses associated with the
Pine Street site. This amount represented the Company's unrecovered
expenditures between August 1993 and June 1994 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 1994 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 of December 31, 1994, such
amounts are approximately $845,000.
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 1995 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, 1994, as follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
(In %) (In MW) (In thousands)
Highgate . . . . . . . . . . 33.8 67.6 $ 9,726 $2,563
McNeil . . . . . . . . . . . 11.0 5.9 $ 8,506 $2,753
Stony Brook (No. 1) . . . . . 8.8 30.2 $10,035 $5,090
Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,376 $1,176
Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 243
(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
1994 Retail Rate Case -- On September 26, 1994, the Company filed a
request with the VPSB to increase retail rates by 13.9 percent. The
increase is 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 have
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 must be reviewed and approved by the VPSB.
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.
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-Quebec, provided for the construction of the second
phase (Phase II) of the interconnection between the New England electric
systems and that of Hydro-Quebec. Phase II expands the Phase I
facilities from 690 megawatts to 2,000 megawatts and provides for
transmission of Hydro-Quebec power from the Phase I terminal in northern
New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II
commenced in 1988 and was completed in late 1990. The Company is
entitled to 3.2 percent of the Phase II power-supply benefits. Total
construction costs for Phase II were approximately $487 million. The
New England participants, including the Company, have contracted to pay
monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs.
As a supporting participant, the Company must make support payments
under thirty-year agreements. These support agreements meet the capital
lease accounting requirements under SFAS 13. At December 31, 1994, the
present value of the Company's obligation is $10.3 million.
Projected future minimum payments under the Phase II support agreements
are as follows:
Year ending December 31,
1995 . . . . . . . . . . . $ 489,425
1996 . . . . . . . . . . . 489,425
1997 . . . . . . . . . . . 489,425
1998 . . . . . . . . . . . 489,425
1999 . . . . . . . . . . . 489,425
Total for 2000-2020 . . . 7,830,817
-----------
$10,277,942
===========
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
Statements of Consolidated 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 1994 follows:
Stony Vermont
Merrimack Brook Yankee
(Dollars in thousands)
Plant capacity . . . . . . . . . . . 320.0 MW 343.0 MW 520.0 MW
Company's share of output . . . . . 8.9% 4.4% 17.3%
Contract period . . . . . . . . . . 1968-1998 (1) (2)
Company's annual share of:
Interest . . . . . . . . . . . . . $ 551 $ 265 $ 1,557
Other debt service . . . . . . . . 302 286 ---
Other capacity . . . . . . . . . . 1,942 405 22,655
------ ------ -------
Total annual capacity . . . . . . . $2,795 $ 956 $24,212
====== ====== =======
Company's share of long-term debt . $ 931 $5,101 $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.
On October 12, 1990, the VPSB granted conditional approval of the
Company's purchases pursuant to the contract with Hydro-Quebec entered
into December 4, 1987: (1) Schedule A -- 17 megawatts 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. The opponents to the December 1987
contract appealed the VPSB's October 1990 order to the Vermont Supreme
Court. On October 2, 1992, the Vermont Supreme Court affirmed the
VPSB's October 1990 order. On February 12, 1992, the VPSB issued an
order finding that the Company had complied with substantial conditions
imposed by the VPSB in its October 1990 order and approved the Company's
purchase under the December 1987 contract. In March 1992, the opponents
to the December 1987 contract appealed the VPSB's February 1992
compliance order to the Vermont Supreme Court. On May 7, 1993, the
Vermont Supreme Court affirmed the VPSB's compliance order approving the
Company's purchases under the December 1987 contract.
The Company anticipates that the Schedule C3 purchases will be delivered
over its entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase I
and Phase II). If such interconnection is utilized, the Company must
forego certain savings associated with other energy deliveries and
capacity arrangements that would benefit the Company if the
interconnection were not utilized for delivery of the Schedule C3
purchases. The Company believes that the benefits of the Schedule C3
purchases, if power is delivered over such interconnection, will offset
the value of the foregone savings.
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. This tertiary energy contract will expire in August
1995. The Company anticipates that purchases of tertiary energy will
extend beyond August 1995, but will end when the Schedule C3 deliveries
begin in November 1995.
On September 27, 1990, the Canadian National Energy Board (NEB) issued
its decision approving the export by Hydro-Quebec pursuant to the
December 1987 contract. The NEB, however, imposed a condition on its
approval: Hydro-Quebec's export license was to be deemed valid so long
as Hydro-Quebec obtained all federal and environmental approvals
required for any of its new hydroelectric generating units advanced in
order to satisfy Hydro-Quebec's contractual obligations. Hydro-Quebec
and the Province of Quebec appealed the imposition of this condition to
the Federal Court of Appeal. In a decision handed down on July 9, 1991,
the Federal Court of Appeal agreed with Hydro-Quebec's assertion that
the NEB has no authority to regulate the construction of hydroelectric
generating units -- a matter that lies exclusively within provincial
jurisdiction under the Canadian Constitution. The Federal Court of
Appeal struck down the challenged NEB license condition and otherwise
affirmed the license. The opponents to the December 1987 contract
appealed the decision of the Federal Court of Appeal to the Supreme
Court of Canada. On February 24, 1994, the Supreme Court of Canada
rendered a decision reversing the judgment of the Federal Court of
Appeal, and reinstated the NEB decision, including the condition that
Hydro-Quebec had objected to.
The December 1987 contract, like the July 1984 contract, calls for the
delivery of system power and is 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 contract. 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. Under this new arrangement, 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 this arrangement, the Company will purchase $3 million worth
of research and development work from Hydro-Quebec over the four-year
period, and is obligated to make a $7.5 million cash payment to Hydro-
Quebec in 1995. The Company has the option to purchase up to $1 million
worth of additional research and development work. If the Company
exercises its option, the $7.5 million cash payment will be reduced
accordingly. Hydro-Quebec retains the right to curtail annual energy
deliveries by 13 percent up to five times, over the 2000 to 2015 period,
if documented drought conditions exist in Quebec.
During the first year of this arrangement, the average cost per
kilowatthour of Schedules B and C3 will be cut from 6.2 to 4.2 cents per
kilowatthour, a 32% or $15 million cost reduction. Over the four-year
period covered by the arrangement, unit costs will be lowered from 6.4
to 5.2 cents per kilowatthour, reducing unit costs by 19 percent and
saving $34.5 million in nominal terms.
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%
(1992-1995)
Minimum Energy Charge . . $3,782 $2,195 $15,231 $10,430
(1994) (1994) (1995-2015)* (1995-2015)*
$2,726 $1,771
(1995) (1995)
Annual Capacity Charge . $3,313 $1,684 $16,030 $9,966
(1994) (1994) (1995-2015)* (1995-2015)*
$2,448 $1,237
(1995) (1995)
Average Cost per KWH . . 2.7 cents 5.3 cents 6.7 cents 6.1 cents
(1994) (1994) (1995-2015)** (1995-2015)**
2.7 cents 4.8 cents
(1995) (1995)
*Estimated average.
**Estimated average in nominal dollars, levelized over the period indicated.
3. Rochester Gas & Electric Purchase
In 1988, the Company entered into a ten-year contract with Rochester Gas
and Electric Corporation (RG&E) for the purchase of up to 50 megawatts
of firm power and associated energy. Although the Company had no fixed
capacity payments, it had to pay to reserve transmission from the
Niagara Mohawk Power Corporation for the 50-megawatt maximum purchase.
Both RG&E and the Company have the option to terminate the contract
effective 1995.
Pursuant to an agreement with Connecticut Light and Power Corporation
(CL&P) and Bozrah Light and Power (Bozrah) that was finalized in
December 1992, the Company exercised the option to terminate the RG&E
agreement and the transmission contract with Niagara Mohawk that
supports it effective October 31, 1995. The Company also agreed to
offer RG&E power to CL&P for purchase on a weekly basis through the
remaining term of the RG&E agreement, terminated a contract under which
the Company supplied all of the electrical requirements of Bozrah, a
small electric utility operating in Gilman, Connecticut. In return,
CL&P, which replaced the Company as the supplier of electricity to
Bozrah, assumed responsibility for approximately 75 percent of the fixed
costs of the transmission contract with Niagara Mohawk, and provided the
Company with up to 50 megawatts of system power, to be scheduled on a
weekly basis, at a total price expected to be lower than that provided
under the existing RG&E contract. In addition, CL&P has offered the
Company an option, which may be exercised in yearly increments starting
in July 1994, to purchase up to 50 additional megawatts of system power
for the period July 1995 through December 2004.
The arrangement was approved by FERC effective May 1, 1993. The
reductions in the Company's purchased power and fixed transmission costs
derived from this three-party agreement will more than offset the loss
of revenues associated with the termination of its electricity sales
contract with Bozrah.
In January 1995, CL&P and the Company signed an amendment to the
contract to enable the Company to terminate the RG&E contract in January
1995, eliminating the provisions relating to the sale of capacity and
energy by the Company and provided a price ceiling to substitute for the
RG&E agreement price ceiling as it applies to the Company's purchase
from CL&P. Additionally, contract terms for the Company's option of
purchasing up to 50 MW of CL&P system power were amended to make the
power available August 1995 - December 2004, and the Company's deadline
for initial elections of said power was extended to July 31, 1995.
Estimated Charges
1994
Annual Transmission Reservations . . . . . . . . . $300,000
Average Cost per KWH . . . . . . . . . . . . . . . 3.3 cents (1994)
3.3 cents (1995)
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, 1994 and 1993, and the related
consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1994. 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, 1994 and 1993, and
the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 1994, in conformity
with generally accepted accounting principles.
As discussed in Notes A and G to the accompanying financial statements,
effective January 1, 1993, the Company changed its method of accounting
for post-retirement benefits other than pensions and income taxes.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
January 31, 1995
Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1994, 1993 and 1992
<TABLE>
<CAPTION>
Additions
Balance at ------------------------------- Balance at
Beginning of Charged to Charged to End of
Description Period Cost & Expense Other Accounts Deductions Period
----------------------------------- ------------- -------------- -------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Pine Street Marsh (1)
1994................................. $684,430 $ -- $ -- $684,430 $0
1993................................. $684,430 $ -- $ -- $ -- $684,430
1992................................. $687,136 $3,678 $ -- $6,384 $684,430
Injuries and Damages
1994................................. $105,660 $35,000 $394,430 (4) $21,370 $513,720
1993................................. ($2,357) $142,000 $ -- $33,983 $105,660
1992................................. ($12,413) $42,000 $ -- $31,944 ($2,357)
Bad Debt Reserve (3)
1994................................. $639,853 $243,974 $53,076 (2) $533,980 $402,923
1993................................. $469,922 $410,000 $89,014 (2) $329,083 $639,853
1992................................. $351,049 $449,475 $44,338 (2) $374,940 $469,922
(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.
(4) Anticipated litigation settlements regarding injury,
wrongful death claims, and retroactive Hydro license fees.
</TABLE>
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 "Nominees for
Director," "Compliance with the Securities Exchange Act," "Executive
Compensation," "Pension Plan Information" and "Security 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
18, 1995. 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 1995.
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 38
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.
<TABLE>
<CAPTION>
ITEM 14(a)(3) EXHIBITS
Incorporated by Reference from
Exhibit SEC Docket OR
Number Exhibit Page Filed Herewith
<S> <C> <C> <C>
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-K 1993
March 8, 1994. (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-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.
10-b-36 Agreement with respect to use of Quebec 10-b-36 33-8164
Interconnection dated as of December 1, 1981,
among participating New England utilities
for use of transmission interconnection
between New England and Hydro-Quebec.
10-b-39 Vermont Participation Agreement for Quebec 10-b-39 33-8164
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
*10-d-14 Severance Agreement with D. G. Whitmore. 10-d-14
*10-d-15 Green Mountain Power Corporation Officer Compensation 10-d-15
Program, Highlights Brochure / Program Document
amended.
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)
16-a Letter from former accountant, Coopers & Lybrand. Form 8-K for
1987 (1-8291)
*23-a-1 Consent of Arthur Anderson & Co.
*27 Financial Data Schedule
____________________
* Filed herewith
</TABLE>
ITEM 14(b)
There were no reports on Form 8-K filed for the quarter ending
December 31, 1994.
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. 33-47985 (filed May 14, 1992):
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 30, 1995
(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 30, 1995
(D. G. Hyde) tee, President, Chief Executive
Officer and Director
/s/C. L. Dutton Vice President, Treasurer and March 30, 1995
(C. L. Dutton) Chief Financial Officer (Principal
Financial Officer)
/s/G. J. Purcell Controller March 30, 1995
(G. J. Purcell) (Principal Accounting Officer)
/s/T. P. Salmon Chairman of the Board and March 30, 1995
(T. P. Salmon) Director
Director
(R. E. Boardman)
/s/N. L. Brue Director March 30, 1995
(N. L. Brue)
/s/W. H. Bruett Director March 30, 1995
(W. H. Bruett)
Director
(M. O. Burns)
Director
(L. E. Chickering)
/s/J. V. Cleary Director March 30, 1995
(J. V. Cleary)
/s/R. I. Fricke Director March 30, 1995
(R. I. Fricke)
/s/E. A. Irving Director March 30, 1995
(E. A. Irving)
/s/M. L. Johnson Director March 30, 1995
(M. L. Johnson)
/s/R. W. Page Director March 30, 1995
(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 31, 1995. 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 38 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 31, 1995 /s/ Arthur Andersen LLP
EXHIBIT 10-d-13
PERSONAL AND CONFIDENTIAL
November 23, 1994
Michael H. Lipson, Esq.
Assistant General Counsel
Green Mountain Power Corporation
P.O. Box 850
South Burlington, VT 05402-0850
Dear Michael:
Green Mountain Power Corporation (the "Company") considers it
essential to the best interests of its shareholders to foster the
continuous employment of key management personnel. In this connection,
the Board of Directors of the Company (the "Board") recognizes that, as
is the case with many publicly held corporations, the possibility of a
change in control may exist and that such possibility, and the
uncertainty and questions which it may raise among management, may
result in the distraction or departure of management personnel to the
detriment of the Company and its shareholders.
The Board has determined that appropriate steps should be taken to
reinforce and encourage the continued attention and dedication of
members of the Company's management, including yourself, to their
assigned duties without distraction in the face of potentially
disturbing circumstances arising from the possibility of a change in
control of the Company, although no such change is known to be
contemplated.
In order to induce you to remain in the employ of the Company and
in consideration of your agreement set forth in Subsection 2(ii) hereof,
the Company agrees that you shall receive the severance benefits set
forth in this letter agreement ("Agreement") in the event your
employment with the Company is terminated subsequent to a "change in
control of the Company" (as defined in Section 2 hereof) under the
circumstances described below.
1. Term of Agreement. This Agreement shall commence on the date
hereof and shall continue in effect through December 31, 1995;
provided, however, that commencing on January 1, 1996 and each
January 1 thereafter, the term of this Agreement shall
automatically be extended for one additional year unless, not
later than September 30 of the preceding year, the Company
shall have given notice that it does not wish to extend this
Agreement; provided, further, if a change in control of the
Company shall have occurred during the original or extended
term of this Agreement, this Agreement shall continue in ef-
fect for a period of at least twenty-four (24) months beyond
the month in which such change in control occurred.
2. Change in Control.
(i) No benefits shall be payable hereunder unless there
shall have been a change in control of the Company, as
set forth below. For purposes of this Agreement, a
"change in control of the Company" shall be deemed to
have occurred if (A) any "person" (as such term is used
in sections 13(d) and 14(d) of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"), other
than a trustee or other fiduciary holding securities
under an employee benefit plan of the Company or a
corporation owned, directly or indirectly, by the
shareholders of the Company in substantially the same
proportions as their ownership of stock of the Company,
is or becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or
indirectly, of securities of the Company representing
25% or more of the combined voting power of the
Company's then outstanding securities (a "25% Holder");
or (B) during any period of two consecutive years (not
including any period prior to the execution of this
Agreement), individuals who at the beginning of such
period constitute the Board of Directors of the Company
(the "Board") and any new director (other than a di-
rector designated by a person who has entered into an
agreement with the Company to effect a transaction
described in clauses (A) or (C) of this Subsection)
whose election by the Board or nomination for election
by the Company's shareholders was approved by a vote of
at least two-thirds (2/3) of the directors then still
in office who either were directors at the beginning of
the period or whose election or nomination for election
was previously so approved, cease for any reason to
constitute a majority of the directors of the Company;
or (C) the shareholders of the Company approve a merger
or consolidation of the Company with any other corpora-
tion, other than a merger or consolidation which would
result in the voting securities of the Company
outstanding immediately prior thereto continuing to
represent (either by remaining outstanding or by being
converted into voting securities of the surviving
entity) at least 80% of the combined voting power of
the voting securities of the Company or such surviving
entity outstanding immediately after such merger or
consolidation, or the shareholders of the Company
approve a plan of complete liquidation of the Company
or an agreement for the sale or disposition by the
Company of all or substantially all the Company's
assets; provided, however, that a change in control of
the Company shall not be deemed to have occurred under
clauses (A) or (C) above if a majority of the
Continuing Directors (as defined below) determine
within five business days after the occurrence of any
event specified in clauses (A) or (C) above that
control of the Company has not in fact changed and it
is reasonably expected that such control of the Company
in fact will not change. Notwithstanding that, in the
case of clause (A) above, the Board shall have made a
determination of the nature described in the preceding
sentence, if there shall thereafter occur any material
change in facts involving, or relating to, the 25%
Holder or to the 25% Holder's relationship to the
Company, including, without limitation, the acquisition
by the 25% Holder of l% or more additional outstanding
voting stock of the Company, the occurrence of such
material change in facts shall result in a new "change
in control of the Company" for the purpose of this
Agreement. In such event, the second immediately
preceding sentence hereof shall be effective. As used
herein, the term "Continuing Director" shall mean any
member of the Board on the date of this Agreement and
any successor of a Continuing Director who is recom-
mended to succeed the Continuing Director by a majority
of Continuing Directors. If, following a change in
control of the Company (as defined in this Agreement),
you are the beneficial owner of two percent or more of
the then-outstanding equity securities of the Company,
or its successor in interest, a majority of the
Continuing Directors may elect, within five business
days after such change in control of the Company, to
terminate any benefits payable to you under this
Agreement after the date of such an election by the
Continuing Directors.
(ii) For purposes of this Agreement, a "potential change in
control of the Company" shall be deemed to have
occurred if (A) the Company enters into an agreement,
the consummation of which would result in the
occurrence of a change in control of the Company, (B)
any person (including the Company) publicly announces
an intention to take or to consider taking actions
which if consummated would constitute a change in
control of the Company; (C) any person, other than a
trustee or other fiduciary holding securities under an
employee benefit plan of the Company or a corporation
owned, directly or indirectly, by the shareholders of
the Company in substantially the same proportion as
their ownership of stock of the Company, becomes the
beneficial owner, directly or indirectly, of securities
of the Company representing 5% or more of the combined
voting power of the Company's then outstanding
securities; or (D) the Board adopts a resolution to the
effect that, for purposes of this Agreement, a poten-
tial change in control of the Company has occurred.
You agree that, subject to the terms and conditions of
this Agreement, in the event of a potential change in
control of the Company, you will remain in the employ
of the Company until the earliest of (i) a date which
is six (6) months from the occurrence of such potential
change in control of the Company, (ii) the termination
by you of your employment by reason of Disability or
Retirement (at your normal retirement age), as defined
in Subsection 3(i), or (iii) the occurrence of a change
in control of the Company.
3. Termination Following Change in Control. If any of the events
described in Subsection 2(i) hereof constituting a change in
control of the Company shall have occurred, you shall be
entitled to the benefits provided in Subsection 4(iii) hereof
upon the subsequent termination of your employment during the
term of this Agreement unless such termination is (A) because
of your death, Disability or Retirement, (B) by the Company
for Cause, or (C) by you other than for Good Reason.
(i) Disability; Retirement. If, as a result of your
incapacity due to physical or mental illness, you shall
have been absent from the full-time performance of your
duties with the Company for six (6) consecutive months,
and within thirty (30) days after written notice of
termination is given you shall not have returned to the
full-time performance of your duties, your employment
may be terminated for "Disability". Termination by the
Company or you of your employment based on "Retirement"
shall mean termination in accordance with the Company's
retirement policy, including early retirement,
generally applicable to its salaried employees or in
accordance with any retirement arrangement established
with your consent with respect to you.
(ii) Cause. Termination by the Company of your employment
for "Cause" shall mean termination upon (A) the willful
and continued failure by you to substantially perform
your duties with the Company (other than any such
failure resulting from your incapacity due to physical
or mental illness or any such actual or anticipated
failure after the issuance of a Notice of Termination,
by you for Good Reason as defined in Subsections 3(iv)
and 3(iii), respectively) after a written demand for
substantial performance is delivered to you by the
Board, which demand specifically identifies the manner
in which the Board believes that you have not
substantially performed your duties, or (B) the willful
engaging by you in conduct which is demonstrably and
materially injurious to the Company, monetarily or
otherwise. For purposes of this Subsection, no act, or
failure to act, on your part shall be deemed "willful"
unless done, or omitted to be done, by you not in good
faith and without reasonable belief that your action or
omission was in the best interest of the Company.
Notwithstanding the foregoing, you shall not be deemed
to have been terminated for Cause unless and until
there shall have been delivered to you a copy of a
resolution duly adopted by the affirmative vote of not
less than three-quarters (3/4) of the entire membership
of the Board at a meeting of the Board called and held
for such purpose (after reasonable notice to you and an
opportunity for you, together with your counsel, to be
heard before the Board), finding that in the good faith
opinion of the Board you were guilty of conduct set
forth above in clauses (A) or (B) of the first sentence
of this Subsection and specifying the particulars
thereof in detail.
(iii) Good Reason. You shall be entitled to terminate your
employment for Good Reason. For purposes of this
Agreement, "Good Reason" shall mean, without your
express written consent, the occurrence after a change
in control of the Company of any of the following
circumstances unless, in the case of paragraphs (A),
(E), (F), (G), or (H), such circumstances are fully
corrected prior to the Date of Termination specified in
the Notice of Termination, as defined in Subsections
3(v) and 3(iv), respectively, given in respect thereof:
(A) the assignment to you of any duties inconsistent
with your status as Assistant General Counsel of
Green Mountain Power Corporation or a
substantial adverse alteration in the nature or
status of your responsibilities from those in
effect immediately prior to the change in
control of the Company;
(B) a reduction by the Company in your annual base
salary as in effect on the date hereof or as the
same may be increased from time-to-time except
for across-the-board salary reductions similarly
affecting all executives of the Company and all
executives of any person in control of the
Company;
(C) the relocation of the Company's principal
executive offices (presently located at Green
Mountain Drive, South Burlington, Vermont) to a
location more than fifty miles distant from the
present location prior to the change in control
of the Company, or the closing thereof, or the
Company's requiring you to be based anywhere
other than within fifty miles of the present
location, except for required travel on the
Company's business to an extent substantially
consistent with your present business travel
obligations;
(D) the failure by the Company, without your consent,
to pay to you any portion of your current
compensation except pursuant to an across-the-
board compensation deferral similarly affecting
all executives of the Company and all executives
of any person in control of the Company;
(E) the failure by the Company to offer you any
compensation plan introduced to other executives
of similar responsibility or any substitute
plans adopted prior to the change in control,
unless an equitable arrangement (embodied in an
ongoing substitute or alternative plan) has been
made with respect to such plan, or the failure
by the Company to continue your participation
therein (or in such substitute or alternative
plan) on a basis not materially less favorable,
both in terms of the amount of benefits provided
and the level of your participation relative to
other participants, as existed at the time of
the change in control;
(F) the failure by the Company to continue to provide
you with benefits substantially similar to those
enjoyed by you under any of the Company's
pension, savings and thrift, group life
insurance, medical, dental or disability plans
in which you were participating at the time of
the change in control of the Company, the taking
of any action by the Company which would
directly or indirectly materially reduce any of
such benefits or deprive you of any material
fringe benefit enjoyed by you at the time of the
change in control of the Company, or the failure
by the Company to provide you with the number of
paid vacation days to which you are entitled on
the basis of years of service with the Company
in accordance with the Company's normal vacation
policy in effect at the time of the change in
control of the Company;
(G) the failure of the Company to obtain a
satisfactory agreement from any successor
company to assume and agree to perform this
Agreement, as contemplated in Section 5 hereof;
or
(H) any purported termination of your employment
which is not effected pursuant to a Notice of
Termination satisfying the requirements of
Subsection (iv) below (and if applicable, the
requirements of Subsection (ii) above); for
purposes of this Agreement, no such purported
termination shall be effective.
Your right to terminate your employment pursuant to
this Subsection shall not be affected by your
incapacity due to physical or mental illness. Your
continued employment shallnot constitute consent to, or
a waiver of rights with respect to, any circumstance
constituting Good Reason hereunder.
(iv) Notice of Termination. Any purported termination of
your employment by the Company or by you shall be
communicated by written Notice of Termination to the
other party hereto in accordance with Section 6 hereof.
For purposes of this Agreement, a "Notice of
Termination" shall mean a notice which shall indicate
the specific termination provision in this Agreement
relied upon and shall set forth in reasonable detail
the facts and circumstances claimed to provide a basis
for termination of your employment under the provision
so indicated.
(v) Date of Termination, etc. "Date of Termination" shall
mean (A) if your employment is terminated for
Disability, thirty (30) days after Notice of
Termination is given (provided that you shall not have
returned to the full-time performance of your duties
during such thirty (30) day period), and (B) if your
employment is terminated pursuant to Subsection (ii) or
(iii) above or for any other reason (other than
Disability), the date specified in the Notice of
Termination (which, in the case of a termination
pursuant to Subsection (ii) above shall not be less
than thirty (30) days, and in the case of a termination
pursuant to Subsection (iii) above shall not be less
than fifteen (15) nor more than sixty (60) days,
respectively, from the date such Notice of Termination
is given); provided that if within fifteen (15) days
after any Notice of Termination (as determined without
regard to this provision), the party receiving such
Notice of Termination notifies the other party that a
dispute exists concerning the termination, the Date of
Termination shall be the date on which the dispute is
finally determined, either by mutual written agreement
of the parties, by a binding arbitration award, or by a
final judgment, order or decree of a court of competent
jurisdiction (which is not appealable or with respect
to which the time for appeal therefrom has expired and
no appeal has been perfected); provided further that
the Date of Termination shall be extended by a notice
of dispute only if such notice is given in good faith
and the party giving such notice pursues the resolution
of such dispute with reasonable diligence.
Notwithstanding the pendency of any such dispute, the
Company will continue to pay you your full compensation
in effect when the notice giving rise to the dispute
was given (including, but not limited to, base salary)
and continue you as a participant in all compensation,
benefit and insurance plans in which you were
participating when the notice giving rise to the
dispute was given, until the dispute is finally
resolved in accordance with this Subsection. Amounts
paid under this Subsection are in addition to all other
amounts due under this Agreement and shall not be
offset against or reduce any other amounts due under
this Agreement except to the extent otherwise provided
in paragraph (E) of Subsection 4(iii).
4. Compensation Upon Termination or During Disability. Following
a change in control of the Company, as defined by Subsection
2(i), upon termination of your employment or during a period
of disability you shall be entitled to the following benefits:
(i) During any period that you fail to perform your full-
time duties with the Company as a result of incapacity
due to physical or mental illness, you shall continue
to receive your base salary at the rate in effect at
the commencement of any such period, together with all
compensation payable to you under any other plan in
effect during such period, until this Agreement is ter-
minated pursuant to Section 3(i) hereof. Thereafter,
or in the event your employment shall be terminated by
the Company or by you for Retirement, or by reason of
your death, your benefits shall be determined under the
Company's retirement, insurance and other compensation
programs then in effect in accordance with the terms of
such programs.
(ii) If your employment shall be terminated by the Company
for Cause or by you other than for Good Reason,
Disability, death or Retirement, the Company shall pay
you your full base salary through the Date of
Termination at the rate in effect at the time Notice of
Termination is given, plus all other amounts to which
you are entitled under any compensation or benefit plan
of the Company at the time such payments are due, and
the Company shall have no further obligations to you
under this Agreement.
(iii) If your employment by the Company shall be terminated
(a) by the Company other than for Cause, Retirement or
Disability or (b) by you for Good Reason, then you
shall be entitled to the benefits provided below:
(A) The Company shall pay you your full base salary
through the Date of Termination at the rate in
effect at the time Notice of Termination is
given, plus all other amounts to which you are
entitled under any compensation or benefit plan
of the Company, at the time such payments are
due, except as otherwise provided below.
(B) In lieu of any further salary payments to you for
periods subsequent to the Date of Termination,
the Company shall pay as severance pay to you a
lump sum severance payment (the "Severance
Payment") equal to 2.99 times your "base
amount," as defined in section 280G of the
Internal Revenue Code of 1986, as amended (the
"Code"). Such base amount shall be determined
in accordance with temporary or final regula-
tions, if any, promulgated under section 280G
of the Code and based upon the advice of the tax
counsel referred to in paragraph (C), below.
(C) The Severance Payment shall be reduced by the
amount of any other payment or the value of any
benefit received or to be received by you in
connection with a change in control of the
Company or your termination of employment
(whether pursuant to the terms of this Agreement
or any other plan, agreement or arrangement with
the Company, any person whose actions result in
a change of control, or any person affiliated
with the Company or such person) unless (i) you
shall have effectively waived your receipt or
enjoyment of such payment or benefit prior to
the date of payment of the Severance Payment,
(ii) in the opinion of tax counsel selected by
the Company's independent auditors and accept-
able to you, and who may rely, without in-
dependent examination, upon the report of an
independent consultant (Compensation Consultant)
engaged in the practice of preparing
compensation studies and rendering advice
concerning compensation issues, such other
payment or benefit does not constitute a
"parachute payment" within the meaning of
section 280G(b)(2) of the Code, or (iii) in the
opinion of such tax counsel who may rely upon
any Compensation Consultant's report, the
Severance Payment (in its full amount or as
partially reduced under this paragraph (C), as
the case may be) plus all other payments or
benefits which constitute "parachute payments"
within the meaning of section 280G(b)(2) of the
Code are reasonable compensation for services
actually rendered, within the meaning of section
280G(b)(4) of the Code or are otherwise not
subject to disallowance as a deduction by reason
of section 280G of the Code. The value of any
non-cash benefit or any deferred payment or
benefit shall be determined by the Company's
independent auditors in accordance with the
principles of sections 280G(d)(3) and (4) of the
Code.
(D) The Company shall pay to you all legal fees and
expenses incurred by you as a result of such
termination (including all such fees and
expenses, if any, incurred in contesting or
disputing any such termination or in seeking to
obtain or enforce any right or benefit provided
by this Agreement or in connection with any tax
audit or proceeding to the extent attributable
to the application of section 4999 of the Code
to any payment or benefit provided hereunder),
such payment to be made at the later of the
times provided in paragraph (E), below or within
five (5) days after your request for payment
accompanied with such evidence of fees and ex-
penses incurred as the Company reasonably may
require.
(E) The payments provided for in paragraphs (B) and
(D), above, shall (except as otherwise provided
therein) be made not later than the fifth day
following the Date of Termination, provided,
however, that if the amounts of such payments,
and the limitation on such payments set forth in
paragraph (C) above, cannot be finally
determined on or before such day, the Company
shall pay to you on such day an estimate, as
determined in good faith by the Company, of the
minimum amount of such payments and shall pay
the remainder of such payments (together with
interest at the rate provided in section
1274(b)(2)(B) of the Code) as soon as the amount
thereof can be determined but in no event later
than the thirtieth day after the Date of
Termination. In the event that the amount of the
estimated payments exceeds the amount
subsequently determined to have been due, such
excess shall constitute a loan by the Company to
you, payable on the fifth day after demand by
the Company (together with interest at the rate
provided in section 1274(b)(2)(B) of the Code).
(F) In the event that any payment or benefit received
or to be received by you in connection with a
change in control of the Company or the
termination of your employment (whether pursuant
to the terms of this Agreement or any other
plan, arrangement or agreement with the Company,
any person whose actions result in a change in
control or any person affiliated with the
Company or such person) (collectively with the
Severance Payments, "Total Payments") would not
be deductible (in whole or part) as a result of
section 280G of the Code by the Company, an
affiliate or other person making such payment or
providing such benefit, the Severance Payments
shall be reduced until no portion of the Total
Payments is not deductible, or the Severance
Payments are reduced to zero. For purposes of
this limitation (i) no portion of the Total
Payments the receipt or enjoyment of which you
shall have effectively waived in writing prior
to the date of payment of the Severance Payments
shall be taken into account, (ii) no portion of
the Total Payments shall be taken into account
which in the opinion of tax counsel selected by
the Company's independent auditors and
acceptable to you does not constitute a
"parachute payment" within the meaning of
section 280G(b)(2) of the Code, (iii) the
Severance Payments shall be reduced only to the
extent necessary so that the Total Payments
(other than those referred to in clauses (i) or
(ii)) in their entirety constitute reasonable
compensation for services actually rendered
within the meaning of section 280G(b)(4) of the
Code or are otherwise not subject to
disallowance as deductions, in the opinion of
the tax counsel referred to in clause (ii); and
(iv) the value of any non-cash benefit or any
deferred payment or benefit included in the
Total Payments shall be determined by the
Company's independent auditors in accordance
with the principles of sections 280G(d)(3) and
(4) of the Code.
(G) If it is established pursuant to a final
determination of a court or an Internal Revenue
Service proceeding that, notwithstanding the
good faith of you and the Company in applying
the terms of this Subsection 4(iii), the
aggregate "parachute payments" paid to or for
your benefit are in an amount that would result
in any portion of such "parachute payments" not
being deductible by reason of section 280G of
the Code, then you shall have an obligation to
pay the Company upon demand an amount equal to
the sum of (1) the excess of the aggregate
"parachute payments" paid to or for your benefit
over the aggregate "parachute payments" that
could have been paid to or for your benefit
without any portion of such "parachute payments"
not being deductible by reason of section 280G
of the Code; and (2) interest on the amount set
forth in clause (1) of this sentence at the rate
provided in section 1274(b)(2)(B) of the Code
from the date of your receipt of such excess
until the date of such payment.
(iv) If your employment shall be terminated (A) by the
Company other than for Cause, Retirement or Disability
or (B) by you for Good Reason, then for a twenty-four
(24) month period after such termination, the Company
shall arrange to provide you with group life,
disability, medical and dental insurance benefits
substantially similar to those which you are receiving
immediately prior to the Notice of Termination.
Benefits otherwise receivable by you pursuant to this
Subsection 4(iv) shall be reduced to the extent
comparable benefits are actually received by you during
the twenty-four (24) month period following your
termination, and any such benefits actually received by
you shall be reported to the Company. If the benefits
provided to you under this Subsection shall result in a
decrease, pursuant to paragraph (E) of Subsection
4(iii), in the Severance Payments and such benefits are
thereafter reduced pursuant to the immediately
preceding sentence, the Company shall, at the time of
such reduction, pay to you the lesser of (a) the amount
of such decrease in the Severance Payments or (b) the
maximum amount which can be paid to you without being,
or causing any other payment to be, nondeductible by
reason of section 280G of the Code.
(v) If your employment shall be terminated (A) by the
Company other than for Cause, Retirement or Disability
or (B) by you for Good Reason, then in addition to the
retirement benefits to which you are entitled under the
Company's Retirement Plan and Supplemental Retirement
Plan or any successor plans thereto, the Company shall
pay you in cash at the time and in the manner provided
in paragraphs (E), (F) and (G) of Subsection 4(iii), a
lump sum equal to the actuarial equivalent of the
excess of (x) the retirement pension (determined as a
straight life annuity commencing at age sixty-five)
which you would have accrued under the terms of the
Company's Retirement Plan and Supplemental Retirement
Plan without regard to any amendment to the Company's
Retirement Plan and Supple-mental Retirement Plan made
subsequent to a change in control of the Company and on
or prior to the Date of Termination, which amendment
adversely affects in any manner the computation of
retirement benefits thereunder, determined as if you
were fully vested thereunder and had accumulated (after
the Date of Termination) twenty-four (24) additional
months of service credit thereunder at your highest
annual rate of compensation during the twelve (12)
months immediately preceding the Date of Termination
over (y) the retirement pension (determined as a
straight life annuity commencing at age sixty-five)
which you had then accrued pursuant to the provisions
of the Company's Retirement Plan and Supplemental
Retirement Plan. For the purposes of this Subsection,
"actuarial equivalent" shall be determined using the
same methods and assumptions utilized under the
Company's Retirement Plan and Supplemental Retirement
Plan immediately prior to the change in control of the
Company.
(vi) You shall not be required to mitigate the amount of
any payment provided for in this Section 4 by seeking
other employment or otherwise, nor shall the amount of
any payment or benefit provided for in this Section 4
be reduced by any compensation earned by you as the
result of employment by another employer, by retirement
benefits, by offset against any amount claimed to be
owed by you to the Company, or otherwise.
(vii) In addition to all other amounts payable to you under
this Section 4, you shall be entitled to receive all
benefits payable to you under the Company's Retirement
Plan, Savings and Thrift Plan, Supplemental Retirement
Plan and any other plan or agreement relating to
retirement benefits.
5. Successors; Binding Agreement.
(i) The Company will require any successor (whether direct
or indirect, by purchase, merger, consolidation or
otherwise) to all or substantially all of the business
and/or assets of the Company to expressly assume and
agree to perform this Agreement in the same manner and
to the same extent that the Company would be required
to perform it if no such succession had taken place.
Failure of the Company to obtain such assumption and
agreement prior to the effectiveness of any such
succession shall be a breach of this Agreement and
shall entitle you to compensation from the Company in
the same amount and on the same terms as you would be
entitled to hereunder if you terminate your employment
for Good Reason following a change in control of the
Company, except that for purposes of implementing the
foregoing, the date on which any such succession
becomes effective shall be deemed the Date of
Termination. As used in this Agreement, "Company"
shall mean the Company as herein before defined and any
successor to its business and/or assets as aforesaid
which assumes and agrees to perform this Agreement by
operation of law, or otherwise.
(ii) This Agreement shall inure to the benefit of and be
enforceable by your personal or legal representatives,
executors, administrators, successors, heirs,
distributees, devisees and legatees. If you should die
while any amount would still be payable to you
hereunder if you had continued to live, all such
amounts, unless otherwise provided herein, shall be
paid in accordance with the terms of this Agreement to
your devisee, legatee or other designee or, if there is
no such designee, to your estate.
6. Subsidiary Corporations. Upon approval of the Board of
Directors of the appropriate wholly-owned subsidiary, this
Agreement shall apply to an executive of any wholly-owned
subsidiary of the Company with the same force and effect as if
said executive were employed directly by the Company. Upon
approval by said subsidiary's Board of Directors, the
executive of the wholly-owned subsidiary shall be entitled to
the same benefits from the Company as those granted to
executives of the Company. For purposes of this Agreement the
transfer of an employee from the Company to any wholly-owned
subsidiary of the Company, or from any wholly-owned subsidiary
to the Company, or from one wholly-owned subsidiary to another
shall not constitute a termination of such employee's
employment. As applied to an executive of a wholly-owned
subsidiary, the duties and obligations of the Company shall,
wherever appropriate, refer to the duties and obligations of
the Company's wholly-owned subsidiary which employs the ex-
ecutive; provided, however, that the Company rather than the
wholly-owned subsidiary shall remain liable to the executive
for payment of benefits due hereunder.
7. Notice. For the purpose of this Agreement, notices and all
other communications provided for in the Agreement shall be in
writing and shall be deemed to have been duly given when
delivered or mailed by United States registered mail, return
receipt requested, postage prepaid, addressed to the
respective addresses set forth on the first page of this
Agreement, provided that all notice to the Company shall be
directed to the attention of the Board with a copy to the
Secretary of the Company, or to such other address as either
party may have furnished to the other in writing in accordance
herewith, except that notice of change of address shall be
effective only upon receipt.
8. Miscellaneous. No provision of this Agreement may be
modified, waived or discharged unless such waiver, modi-
fication, or discharge is agreed to in writing and signed by
you and such officer as may be specifically designated by the
Board. No waiver by either party hereto at any time of any
breach by the other party hereto of, or compliance with, any
condition or provision of this Agreement to be performed by
such other party shall be deemed a waiver of similar or
dissimilar provisions or conditions at the same or at any
prior or subsequent time. This Agreement supersedes any
previous agreements between the Company and you on the matters
herein addressed. No agreements or representations, oral or
otherwise, express or implied, with respect to the subject
matter hereof have been made by either party which are not
expressly set forth in this Agreement. The validity,
interpretation, construction and performance of this Agreement
shall be governed by the laws of the State of Vermont. All
reference to sections of the Exchange Act or the Code shall be
deemed also to refer to any successor provisions to such
sections. Any payments provided for hereunder shall be paid
net of any applicable withholding required under federal,
state or local law. The obligations of the Company under
Section 4 shall survive the expiration of the term of this
Agreement.
9. Validity. The invalidity or unenforceability of any provision
of this Agreement shall not affect the validity or
enforceability of any other provision of this Agreement, which
shall remain in full force and effect.
10. Counterparts. This Agreement may be executed in several
counterparts, each of which shall be deemed to be an original
but all of which together will constitute one and the same
instrument.
11. Arbitration. Any dispute or controversy arising under or in
connection with this Agreement shall be settled exclusively by
arbitration in Burlington, Vermont in accordance with the
rules of the American Arbitration Association then in effect.
Judgment may be entered on the arbitrator's award in any court
having jurisdiction; provided, however, that you shall be
entitled to seek specific performance of your right to be paid
until the Date of Termination during the pendency of any
dispute or controversy arising under or in connection with
this Agreement.
ACKNOWLEDGMENT OF ARBITRATION
The parties hereto understand that this Agreement contains an
agreement to arbitrate. After signing this document, the parties
understand that they will not be able to bring a lawsuit concerning any
dispute that may arise which is covered by the arbitration agreement,
unless it involves a question of constitutional or civil rights.
Instead the parties agree to submit any such dispute to an impartial
arbitrator.
This letter is submitted in duplicate. If it sets forth our
agreement on the subject matter hereof, kindly sign both copies and
return one copy to me within thirty (30) days (after which this offer of
severance benefits will lapse). These letters will then constitute our
agreement on this subject.
By: /s/Thomas P. Salmon
Thomas P. Salmon, Chairman
Board of Directors
Green Mountain Power Corporation
Agreed to this 30th day of November, 1994.
/s/Michael H. Lipson
Michael H. Lipson
EXHIBIT 10-d-14
PERSONAL AND CONFIDENTIAL
November 23, 1994
Mr. David G. Whitmore
General Manager of Administrative Services
Green Mountain Power Corporation
P.O. Box 850
South Burlington, VT 05402-0850
Dear David:
Green Mountain Power Corporation (the "Company") considers it
essential to the best interests of its shareholders to foster the
continuous employment of key management personnel. In this connection,
the Board of Directors of the Company (the "Board") recognizes that, as
is the case with many publicly held corporations, the possibility of a
change in control may exist and that such possibility, and the
uncertainty and questions which it may raise among management, may
result in the distraction or departure of management personnel to the
detriment of the Company and its shareholders.
The Board has determined that appropriate steps should be taken to
reinforce and encourage the continued attention and dedication of
members of the Company's management, including yourself, to their
assigned duties without distraction in the face of potentially
disturbing circumstances arising from the possibility of a change in
control of the Company, although no such change is known to be
contemplated.
In order to induce you to remain in the employ of the Company and
in consideration of your agreement set forth in Subsection 2(ii) hereof,
the Company agrees that you shall receive the severance benefits set
forth in this letter agreement ("Agreement") in the event your
employment with the Company is terminated subsequent to a "change in
control of the Company" (as defined in Section 2 hereof) under the
circumstances described below.
1. Term of Agreement. This Agreement shall commence on the date
hereof and shall continue in effect through December 31, 1995;
provided, however, that commencing on January 1, 1996 and each
January 1 thereafter, the term of this Agreement shall
automatically be extended for one additional year unless, not
later than September 30 of the preceding year, the Company
shall have given notice that it does not wish to extend this
Agreement; provided, further, if a change in control of the
Company shall have occurred during the original or extended
term of this Agreement, this Agreement shall continue in ef-
fect for a period of at least twenty-four (24) months beyond
the month in which such change in control occurred.
2. Change in Control.
(i) No benefits shall be payable hereunder unless there
shall have been a change in control of the Company, as
set forth below. For purposes of this Agreement, a
"change in control of the Company" shall be deemed to
have occurred if (A) any "person" (as such term is used
in sections 13(d) and 14(d) of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"), other
than a trustee or other fiduciary holding securities
under an employee benefit plan of the Company or a
corporation owned, directly or indirectly, by the
shareholders of the Company in substantially the same
proportions as their ownership of stock of the Company,
is or becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or
indirectly, of securities of the Company representing
25% or more of the combined voting power of the
Company's then outstanding securities (a "25% Holder");
or (B) during any period of two consecutive years (not
including any period prior to the execution of this
Agreement), individuals who at the beginning of such
period constitute the Board of Directors of the Company
(the "Board") and any new director (other than a di-
rector designated by a person who has entered into an
agreement with the Company to effect a transaction
described in clauses (A) or (C) of this Subsection)
whose election by the Board or nomination for election
by the Company's shareholders was approved by a vote of
at least two-thirds (2/3) of the directors then still
in office who either were directors at the beginning of
the period or whose election or nomination for election
was previously so approved, cease for any reason to
constitute a majority of the directors of the Company;
or (C) the shareholders of the Company approve a merger
or consolidation of the Company with any other corpora-
tion, other than a merger or consolidation which would
result in the voting securities of the Company
outstanding immediately prior thereto continuing to
represent (either by remaining outstanding or by being
converted into voting securities of the surviving
entity) at least 80% of the combined voting power of
the voting securities of the Company or such surviving
entity outstanding immediately after such merger or
consolidation, or the shareholders of the Company
approve a plan of complete liquidation of the Company
or an agreement for the sale or disposition by the
Company of all or substantially all the Company's
assets; provided, however, that a change in control of
the Company shall not be deemed to have occurred under
clauses (A) or (C) above if a majority of the
Continuing Directors (as defined below) determine
within five business days after the occurrence of any
event specified in clauses (A) or (C) above that
control of the Company has not in fact changed and it
is reasonably expected that such control of the Company
in fact will not change. Notwithstanding that, in the
case of clause (A) above, the Board shall have made a
determination of the nature described in the preceding
sentence, if there shall thereafter occur any material
change in facts involving, or relating to, the 25%
Holder or to the 25% Holder's relationship to the
Company, including, without limitation, the acquisition
by the 25% Holder of l% or more additional outstanding
voting stock of the Company, the occurrence of such
material change in facts shall result in a new "change
in control of the Company" for the purpose of this
Agreement. In such event, the second immediately
preceding sentence hereof shall be effective. As used
herein, the term "Continuing Director" shall mean any
member of the Board on the date of this Agreement and
any successor of a Continuing Director who is recom-
mended to succeed the Continuing Director by a majority
of Continuing Directors. If, following a change in
control of the Company (as defined in this Agreement),
you are the beneficial owner of two percent or more of
the then-outstanding equity securities of the Company,
or its successor in interest, a majority of the
Continuing Directors may elect, within five business
days after such change in control of the Company, to
terminate any benefits payable to you under this
Agreement after the date of such an election by the
Continuing Directors.
(ii) For purposes of this Agreement, a "potential change in
control of the Company" shall be deemed to have
occurred if (A) the Company enters into an agreement,
the consummation of which would result in the
occurrence of a change in control of the Company, (B)
any person (including the Company) publicly announces
an intention to take or to consider taking actions
which if consummated would constitute a change in
control of the Company; (C) any person, other than a
trustee or other fiduciary holding securities under an
employee benefit plan of the Company or a corporation
owned, directly or indirectly, by the shareholders of
the Company in substantially the same proportion as
their ownership of stock of the Company, becomes the
beneficial owner, directly or indirectly, of securities
of the Company representing 5% or more of the combined
voting power of the Company's then outstanding
securities; or (D) the Board adopts a resolution to the
effect that, for purposes of this Agreement, a poten-
tial change in control of the Company has occurred.
You agree that, subject to the terms and conditions of
this Agreement, in the event of a potential change in
control of the Company, you will remain in the employ
of the Company until the earliest of (i) a date which
is six (6) months from the occurrence of such potential
change in control of the Company, (ii) the termination
by you of your employment by reason of Disability or
Retirement (at your normal retirement age), as defined
in Subsection 3(i), or (iii) the occurrence of a change
in control of the Company.
3. Termination Following Change in Control. If any of the events
described in Subsection 2(i) hereof constituting a change in
control of the Company shall have occurred, you shall be
entitled to the benefits provided in Subsection 4(iii) hereof
upon the subsequent termination of your employment during the
term of this Agreement unless such termination is (A) because
of your death, Disability or Retirement, (B) by the Company
for Cause, or (C) by you other than for Good Reason.
(i) Disability; Retirement. If, as a result of your
incapacity due to physical or mental illness, you shall
have been absent from the full-time performance of your
duties with the Company for six (6) consecutive months,
and within thirty (30) days after written notice of
termination is given you shall not have returned to the
full-time performance of your duties, your employment
may be terminated for "Disability". Termination by the
Company or you of your employment based on "Retirement"
shall mean termination in accordance with the Company's
retirement policy, including early retirement,
generally applicable to its salaried employees or in
accordance with any retirement arrangement established
with your consent with respect to you.
(ii) Cause. Termination by the Company of your employment
for "Cause" shall mean termination upon (A) the willful
and continued failure by you to substantially perform
your duties with the Company (other than any such
failure resulting from your incapacity due to physical
or mental illness or any such actual or anticipated
failure after the issuance of a Notice of Termination,
by you for Good Reason as defined in Subsections 3(iv)
and 3(iii), respectively) after a written demand for
substantial performance is delivered to you by the
Board, which demand specifically identifies the manner
in which the Board believes that you have not
substantially performed your duties, or (B) the willful
engaging by you in conduct which is demonstrably and
materially injurious to the Company, monetarily or
otherwise. For purposes of this Subsection, no act, or
failure to act, on your part shall be deemed "willful"
unless done, or omitted to be done, by you not in good
faith and without reasonable belief that your action or
omission was in the best interest of the Company.
Notwithstanding the foregoing, you shall not be deemed
to have been terminated for Cause unless and until
there shall have been delivered to you a copy of a
resolution duly adopted by the affirmative vote of not
less than three-quarters (3/4) of the entire membership
of the Board at a meeting of the Board called and held
for such purpose (after reasonable notice to you and an
opportunity for you, together with your counsel, to be
heard before the Board), finding that in the good faith
opinion of the Board you were guilty of conduct set
forth above in clauses (A) or (B) of the first sentence
of this Subsection and specifying the particulars
thereof in detail.
(iii) Good Reason. You shall be entitled to terminate your
employment for Good Reason. For purposes of this
Agreement, "Good Reason" shall mean, without your
express written consent, the occurrence after a change
in control of the Company of any of the following
circumstances unless, in the case of paragraphs (A),
(E), (F), (G), or (H), such circumstances are fully
corrected prior to the Date of Termination specified in
the Notice of Termination, as defined in Subsections
3(v) and 3(iv), respectively, given in respect thereof:
(A) the assignment to you of any duties inconsistent
with your status as General Manager of
Administrative Services of Green Mountain Power
Corporation or a substantial adverse alteration
in the nature or status of your responsibilities
from those in effect immediately prior to the
change in control of the Company;
(B) a reduction by the Company in your annual base
salary as in effect on the date hereof or as the
same may be increased from time-to-time except
for across-the-board salary reductions similarly
affecting all executives of the Company and all
executives of any person in control of the
Company;
(C) the relocation of the Company's principal
executive offices (presently located at Green
Mountain Drive, South Burlington, Vermont) to a
location more than fifty miles distant from the
present location prior to the change in control
of the Company, or the closing thereof, or the
Company's requiring you to be based anywhere
other than within fifty miles of the present
location, except for required travel on the
Company's business to an extent substantially
consistent with your present business travel
obligations;
(D) the failure by the Company, without your consent,
to pay to you any portion of your current
compensation except pursuant to an across-the-
board compensation deferral similarly affecting
all executives of the Company and all executives
of any person in control of the Company;
(E) the failure by the Company to offer you any
compensation plan introduced to other executives
of similar responsibility or any substitute
plans adopted prior to the change in control,
unless an equitable arrangement (embodied in an
ongoing substitute or alternative plan) has been
made with respect to such plan, or the failure
by the Company to continue your participation
therein (or in such substitute or alternative
plan) on a basis not materially less favorable,
both in terms of the amount of benefits provided
and the level of your participation relative to
other participants, as existed at the time of
the change in control;
(F) the failure by the Company to continue to provide
you with benefits substantially similar to those
enjoyed by you under any of the Company's
pension, savings and thrift, group life
insurance, medical, dental or disability plans
in which you were participating at the time of
the change in control of the Company, the taking
of any action by the Company which would
directly or indirectly materially reduce any of
such benefits or deprive you of any material
fringe benefit enjoyed by you at the time of the
change in control of the Company, or the failure
by the Company to provide you with the number of
paid vacation days to which you are entitled on
the basis of years of service with the Company
in accordance with the Company's normal vacation
policy in effect at the time of the change in
control of the Company;
(G) the failure of the Company to obtain a
satisfactory agreement from any successor
company to assume and agree to perform this
Agreement, as contemplated in Section 5 hereof;
or
(H) any purported termination of your employment
which is not effected pursuant to a Notice of
Termination satisfying the requirements of
Subsection (iv) below (and if applicable, the
requirements of Subsection (ii) above); for
purposes of this Agreement, no such purported
termination shall be effective.
Your right to terminate your employment pursuant to
this Subsection shall not be affected by your
incapacity due to physical or mental illness. Your
continued employment shallnot constitute consent to, or
a waiver of rights with respect to, any circumstance
constituting Good Reason hereunder.
(iv) Notice of Termination. Any purported termination of
your employment by the Company or by you shall be
communicated by written Notice of Termination to the
other party hereto in accordance with Section 6 hereof.
For purposes of this Agreement, a "Notice of
Termination" shall mean a notice which shall indicate
the specific termination provision in this Agreement
relied upon and shall set forth in reasonable detail
the facts and circumstances claimed to provide a basis
for termination of your employment under the provision
so indicated.
(v) Date of Termination, etc. "Date of Termination" shall
mean (A) if your employment is terminated for
Disability, thirty (30) days after Notice of
Termination is given (provided that you shall not have
returned to the full-time performance of your duties
during such thirty (30) day period), and (B) if your
employment is terminated pursuant to Subsection (ii) or
(iii) above or for any other reason (other than
Disability), the date specified in the Notice of
Termination (which, in the case of a termination
pursuant to Subsection (ii) above shall not be less
than thirty (30) days, and in the case of a termination
pursuant to Subsection (iii) above shall not be less
than fifteen (15) nor more than sixty (60) days,
respectively, from the date such Notice of Termination
is given); provided that if within fifteen (15) days
after any Notice of Termination (as determined without
regard to this provision), the party receiving such
Notice of Termination notifies the other party that a
dispute exists concerning the termination, the Date of
Termination shall be the date on which the dispute is
finally determined, either by mutual written agreement
of the parties, by a binding arbitration award, or by a
final judgment, order or decree of a court of competent
jurisdiction (which is not appealable or with respect
to which the time for appeal therefrom has expired and
no appeal has been perfected); provided further that
the Date of Termination shall be extended by a notice
of dispute only if such notice is given in good faith
and the party giving such notice pursues the resolution
of such dispute with reasonable diligence.
Notwithstanding the pendency of any such dispute, the
Company will continue to pay you your full compensation
in effect when the notice giving rise to the dispute
was given (including, but not limited to, base salary)
and continue you as a participant in all compensation,
benefit and insurance plans in which you were
participating when the notice giving rise to the
dispute was given, until the dispute is finally
resolved in accordance with this Subsection. Amounts
paid under this Subsection are in addition to all other
amounts due under this Agreement and shall not be
offset against or reduce any other amounts due under
this Agreement except to the extent otherwise provided
in paragraph (E) of Subsection 4(iii).
4. Compensation Upon Termination or During Disability. Following
a change in control of the Company, as defined by Subsection
2(i), upon termination of your employment or during a period
of disability you shall be entitled to the following benefits:
(i) During any period that you fail to perform your full-
time duties with the Company as a result of incapacity
due to physical or mental illness, you shall continue
to receive your base salary at the rate in effect at
the commencement of any such period, together with all
compensation payable to you under any other plan in
effect during such period, until this Agreement is ter-
minated pursuant to Section 3(i) hereof. Thereafter,
or in the event your employment shall be terminated by
the Company or by you for Retirement, or by reason of
your death, your benefits shall be determined under the
Company's retirement, insurance and other compensation
programs then in effect in accordance with the terms of
such programs.
(ii) If your employment shall be terminated by the Company
for Cause or by you other than for Good Reason,
Disability, death or Retirement, the Company shall pay
you your full base salary through the Date of
Termination at the rate in effect at the time Notice of
Termination is given, plus all other amounts to which
you are entitled under any compensation or benefit plan
of the Company at the time such payments are due, and
the Company shall have no further obligations to you
under this Agreement.
(iii) If your employment by the Company shall be terminated
(a) by the Company other than for Cause, Retirement or
Disability or (b) by you for Good Reason, then you
shall be entitled to the benefits provided below:
(A) The Company shall pay you your full base salary
through the Date of Termination at the rate in
effect at the time Notice of Termination is
given, plus all other amounts to which you are
entitled under any compensation or benefit plan
of the Company, at the time such payments are
due, except as otherwise provided below.
(B) In lieu of any further salary payments to you for
periods subsequent to the Date of Termination,
the Company shall pay as severance pay to you a
lump sum severance payment (the "Severance
Payment") equal to 2.99 times your "base
amount," as defined in section 280G of the
Internal Revenue Code of 1986, as amended (the
"Code"). Such base amount shall be determined
in accordance with temporary or final regula-
tions, if any, promulgated under section 280G
of the Code and based upon the advice of the tax
counsel referred to in paragraph (C), below.
(C) The Severance Payment shall be reduced by the
amount of any other payment or the value of any
benefit received or to be received by you in
connection with a change in control of the
Company or your termination of employment
(whether pursuant to the terms of this Agreement
or any other plan, agreement or arrangement with
the Company, any person whose actions result in
a change of control, or any person affiliated
with the Company or such person) unless (i) you
shall have effectively waived your receipt or
enjoyment of such payment or benefit prior to
the date of payment of the Severance Payment,
(ii) in the opinion of tax counsel selected by
the Company's independent auditors and accept-
able to you, and who may rely, without in-
dependent examination, upon the report of an
independent consultant (Compensation Consultant)
engaged in the practice of preparing
compensation studies and rendering advice
concerning compensation issues, such other
payment or benefit does not constitute a
"parachute payment" within the meaning of
section 280G(b)(2) of the Code, or (iii) in the
opinion of such tax counsel who may rely upon
any Compensation Consultant's report, the
Severance Payment (in its full amount or as
partially reduced under this paragraph (C), as
the case may be) plus all other payments or
benefits which constitute "parachute payments"
within the meaning of section 280G(b)(2) of the
Code are reasonable compensation for services
actually rendered, within the meaning of section
280G(b)(4) of the Code or are otherwise not
subject to disallowance as a deduction by reason
of section 280G of the Code. The value of any
non-cash benefit or any deferred payment or
benefit shall be determined by the Company's
independent auditors in accordance with the
principles of sections 280G(d)(3) and (4) of the
Code.
(D) The Company shall pay to you all legal fees and
expenses incurred by you as a result of such
termination (including all such fees and
expenses, if any, incurred in contesting or
disputing any such termination or in seeking to
obtain or enforce any right or benefit provided
by this Agreement or in connection with any tax
audit or proceeding to the extent attributable
to the application of section 4999 of the Code
to any payment or benefit provided hereunder),
such payment to be made at the later of the
times provided in paragraph (E), below or within
five (5) days after your request for payment
accompanied with such evidence of fees and ex-
penses incurred as the Company reasonably may
require.
(E) The payments provided for in paragraphs (B) and
(D), above, shall (except as otherwise provided
therein) be made not later than the fifth day
following the Date of Termination, provided,
however, that if the amounts of such payments,
and the limitation on such payments set forth in
paragraph (C) above, cannot be finally
determined on or before such day, the Company
shall pay to you on such day an estimate, as
determined in good faith by the Company, of the
minimum amount of such payments and shall pay
the remainder of such payments (together with
interest at the rate provided in section
1274(b)(2)(B) of the Code) as soon as the amount
thereof can be determined but in no event later
than the thirtieth day after the Date of
Termination. In the event that the amount of the
estimated payments exceeds the amount
subsequently determined to have been due, such
excess shall constitute a loan by the Company to
you, payable on the fifth day after demand by
the Company (together with interest at the rate
provided in section 1274(b)(2)(B) of the Code).
(F) In the event that any payment or benefit received
or to be received by you in connection with a
change in control of the Company or the
termination of your employment (whether pursuant
to the terms of this Agreement or any other
plan, arrangement or agreement with the Company,
any person whose actions result in a change in
control or any person affiliated with the
Company or such person) (collectively with the
Severance Payments, "Total Payments") would not
be deductible (in whole or part) as a result of
section 280G of the Code by the Company, an
affiliate or other person making such payment or
providing such benefit, the Severance Payments
shall be reduced until no portion of the Total
Payments is not deductible, or the Severance
Payments are reduced to zero. For purposes of
this limitation (i) no portion of the Total
Payments the receipt or enjoyment of which you
shall have effectively waived in writing prior
to the date of payment of the Severance Payments
shall be taken into account, (ii) no portion of
the Total Payments shall be taken into account
which in the opinion of tax counsel selected by
the Company's independent auditors and
acceptable to you does not constitute a
"parachute payment" within the meaning of
section 280G(b)(2) of the Code, (iii) the
Severance Payments shall be reduced only to the
extent necessary so that the Total Payments
(other than those referred to in clauses (i) or
(ii)) in their entirety constitute reasonable
compensation for services actually rendered
within the meaning of section 280G(b)(4) of the
Code or are otherwise not subject to
disallowance as deductions, in the opinion of
the tax counsel referred to in clause (ii); and
(iv) the value of any non-cash benefit or any
deferred payment or benefit included in the
Total Payments shall be determined by the
Company's independent auditors in accordance
with the principles of sections 280G(d)(3) and
(4) of the Code.
(G) If it is established pursuant to a final
determination of a court or an Internal Revenue
Service proceeding that, notwithstanding the
good faith of you and the Company in applying
the terms of this Subsection 4(iii), the
aggregate "parachute payments" paid to or for
your benefit are in an amount that would result
in any portion of such "parachute payments" not
being deductible by reason of section 280G of
the Code, then you shall have an obligation to
pay the Company upon demand an amount equal to
the sum of (1) the excess of the aggregate
"parachute payments" paid to or for your benefit
over the aggregate "parachute payments" that
could have been paid to or for your benefit
without any portion of such "parachute payments"
not being deductible by reason of section 280G
of the Code; and (2) interest on the amount set
forth in clause (1) of this sentence at the rate
provided in section 1274(b)(2)(B) of the Code
from the date of your receipt of such excess
until the date of such payment.
(iv) If your employment shall be terminated (A) by the
Company other than for Cause, Retirement or Disability
or (B) by you for Good Reason, then for a twenty-four
(24) month period after such termination, the Company
shall arrange to provide you with group life,
disability, medical and dental insurance benefits
substantially similar to those which you are receiving
immediately prior to the Notice of Termination.
Benefits otherwise receivable by you pursuant to this
Subsection 4(iv) shall be reduced to the extent
comparable benefits are actually received by you during
the twenty-four (24) month period following your
termination, and any such benefits actually received by
you shall be reported to the Company. If the benefits
provided to you under this Subsection shall result in a
decrease, pursuant to paragraph (E) of Subsection
4(iii), in the Severance Payments and such benefits are
thereafter reduced pursuant to the immediately
preceding sentence, the Company shall, at the time of
such reduction, pay to you the lesser of (a) the amount
of such decrease in the Severance Payments or (b) the
maximum amount which can be paid to you without being,
or causing any other payment to be, nondeductible by
reason of section 280G of the Code.
(v) If your employment shall be terminated (A) by the
Company other than for Cause, Retirement or Disability
or (B) by you for Good Reason, then in addition to the
retirement benefits to which you are entitled under the
Company's Retirement Plan and Supplemental Retirement
Plan or any successor plans thereto, the Company shall
pay you in cash at the time and in the manner provided
in paragraphs (E), (F) and (G) of Subsection 4(iii), a
lump sum equal to the actuarial equivalent of the
excess of (x) the retirement pension (determined as a
straight life annuity commencing at age sixty-five)
which you would have accrued under the terms of the
Company's Retirement Plan and Supplemental Retirement
Plan without regard to any amendment to the Company's
Retirement Plan and Supple-mental Retirement Plan made
subsequent to a change in control of the Company and on
or prior to the Date of Termination, which amendment
adversely affects in any manner the computation of
retirement benefits thereunder, determined as if you
were fully vested thereunder and had accumulated (after
the Date of Termination) twenty-four (24) additional
months of service credit thereunder at your highest
annual rate of compensation during the twelve (12)
months immediately preceding the Date of Termination
over (y) the retirement pension (determined as a
straight life annuity commencing at age sixty-five)
which you had then accrued pursuant to the provisions
of the Company's Retirement Plan and Supplemental
Retirement Plan. For the purposes of this Subsection,
"actuarial equivalent" shall be determined using the
same methods and assumptions utilized under the
Company's Retirement Plan and Supplemental Retirement
Plan immediately prior to the change in control of the
Company.
(vi) You shall not be required to mitigate the amount of
any payment provided for in this Section 4 by seeking
other employment or otherwise, nor shall the amount of
any payment or benefit provided for in this Section 4
be reduced by any compensation earned by you as the
result of employment by another employer, by retirement
benefits, by offset against any amount claimed to be
owed by you to the Company, or otherwise.
(vii) In addition to all other amounts payable to you under
this Section 4, you shall be entitled to receive all
benefits payable to you under the Company's Retirement
Plan, Savings and Thrift Plan, Supplemental Retirement
Plan and any other plan or agreement relating to
retirement benefits.
5. Successors; Binding Agreement.
(i) The Company will require any successor (whether direct
or indirect, by purchase, merger, consolidation or
otherwise) to all or substantially all of the business
and/or assets of the Company to expressly assume and
agree to perform this Agreement in the same manner and
to the same extent that the Company would be required
to perform it if no such succession had taken place.
Failure of the Company to obtain such assumption and
agreement prior to the effectiveness of any such
succession shall be a breach of this Agreement and
shall entitle you to compensation from the Company in
the same amount and on the same terms as you would be
entitled to hereunder if you terminate your employment
for Good Reason following a change in control of the
Company, except that for purposes of implementing the
foregoing, the date on which any such succession
becomes effective shall be deemed the Date of
Termination. As used in this Agreement, "Company"
shall mean the Company as herein before defined and any
successor to its business and/or assets as aforesaid
which assumes and agrees to perform this Agreement by
operation of law, or otherwise.
(ii) This Agreement shall inure to the benefit of and be
enforceable by your personal or legal representatives,
executors, administrators, successors, heirs,
distributees, devisees and legatees. If you should die
while any amount would still be payable to you
hereunder if you had continued to live, all such
amounts, unless otherwise provided herein, shall be
paid in accordance with the terms of this Agreement to
your devisee, legatee or other designee or, if there is
no such designee, to your estate.
6. Subsidiary Corporations. Upon approval of the Board of
Directors of the appropriate wholly-owned subsidiary, this
Agreement shall apply to an executive of any wholly-owned
subsidiary of the Company with the same force and effect as if
said executive were employed directly by the Company. Upon
approval by said subsidiary's Board of Directors, the
executive of the wholly-owned subsidiary shall be entitled to
the same benefits from the Company as those granted to
executives of the Company. For purposes of this Agreement the
transfer of an employee from the Company to any wholly-owned
subsidiary of the Company, or from any wholly-owned subsidiary
to the Company, or from one wholly-owned subsidiary to another
shall not constitute a termination of such employee's
employment. As applied to an executive of a wholly-owned
subsidiary, the duties and obligations of the Company shall,
wherever appropriate, refer to the duties and obligations of
the Company's wholly-owned subsidiary which employs the ex-
ecutive; provided, however, that the Company rather than the
wholly-owned subsidiary shall remain liable to the executive
for payment of benefits due hereunder.
7. Notice. For the purpose of this Agreement, notices and all
other communications provided for in the Agreement shall be in
writing and shall be deemed to have been duly given when
delivered or mailed by United States registered mail, return
receipt requested, postage prepaid, addressed to the
respective addresses set forth on the first page of this
Agreement, provided that all notice to the Company shall be
directed to the attention of the Board with a copy to the
Secretary of the Company, or to such other address as either
party may have furnished to the other in writing in accordance
herewith, except that notice of change of address shall be
effective only upon receipt.
8. Miscellaneous. No provision of this Agreement may be
modified, waived or discharged unless such waiver, modi-
fication, or discharge is agreed to in writing and signed by
you and such officer as may be specifically designated by the
Board. No waiver by either party hereto at any time of any
breach by the other party hereto of, or compliance with, any
condition or provision of this Agreement to be performed by
such other party shall be deemed a waiver of similar or
dissimilar provisions or conditions at the same or at any
prior or subsequent time. This Agreement supersedes any
previous agreements between the Company and you on the matters
herein addressed. No agreements or representations, oral or
otherwise, express or implied, with respect to the subject
matter hereof have been made by either party which are not
expressly set forth in this Agreement. The validity,
interpretation, construction and performance of this Agreement
shall be governed by the laws of the State of Vermont. All
reference to sections of the Exchange Act or the Code shall be
deemed also to refer to any successor provisions to such
sections. Any payments provided for hereunder shall be paid
net of any applicable withholding required under federal,
state or local law. The obligations of the Company under
Section 4 shall survive the expiration of the term of this
Agreement.
9. Validity. The invalidity or unenforceability of any provision
of this Agreement shall not affect the validity or
enforceability of any other provision of this Agreement, which
shall remain in full force and effect.
10. Counterparts. This Agreement may be executed in several
counterparts, each of which shall be deemed to be an original
but all of which together will constitute one and the same
instrument.
11. Arbitration. Any dispute or controversy arising under or in
connection with this Agreement shall be settled exclusively by
arbitration in Burlington, Vermont in accordance with the
rules of the American Arbitration Association then in effect.
Judgment may be entered on the arbitrator's award in any court
having jurisdiction; provided, however, that you shall be
entitled to seek specific performance of your right to be paid
until the Date of Termination during the pendency of any
dispute or controversy arising under or in connection with
this Agreement.
ACKNOWLEDGMENT OF ARBITRATION
The parties hereto understand that this Agreement contains an
agreement to arbitrate. After signing this document, the parties
understand that they will not be able to bring a lawsuit concerning any
dispute that may arise which is covered by the arbitration agreement,
unless it involves a question of constitutional or civil rights.
Instead the parties agree to submit any such dispute to an impartial
arbitrator.
This letter is submitted in duplicate. If it sets forth our
agreement on the subject matter hereof, kindly sign both copies and
return one copy to me within thirty (30) days (after which this offer of
severance benefits will lapse). These letters will then constitute our
agreement on this subject.
By: /s/Thomas P. Salmon
Thomas P. Salmon, Chairman
Board of Directors
Green Mountain Power Corporation
Agreed to this 30th day of November, 1994.
/s/David G. Whitmore
David G. Whitmore
EXHIBIT 10-d-15
Green Mountain Power Corporation
Compensation Program for Officers
And Certain Key Management Personnel
Highlights Brochure/Program Document
Table of Contents
Page
Preamble 1
Purpose of Program 1
Participants 1
Effective Date 1
Definitions 1
Program Components 3
Base Salary 3
Variable Compensation 4
Determination of Award 7
Variable Compensation Award Payment 7
Program Administration 7
Appendix I
Appendix II
Preamble
This document describes and governs the Compensation Program for
Officers and Certain Key Management Personnel for Green Mountain Power
Corporation ("GMP" or "the Company"). The program is intended to assure
that total compensation is competitive in the marketplace and promotes
the Company's strategic objectives.
Purpose of Program
The purpose of the Compensation Program is to:
o ensure that base compensation compares favorably with regard to
organizations competing for similar talent;
o provide an opportunity for officers and other key management
personnel to share in the success of GMP by linking a portion of
compensation (variable compensation) to corporate performance
results;
o encourage a longer-term view by paying part of an earned variable
compensation award in deferred/restricted stock; and
o foster and reinforce teamwork among officers and other key
management personnel.
Participants
Senior officers of GMP and other key management personnel, as designated
from time to time by the Board of Directors are eligible to participate
in this program. Appendix I to this document, as amended from time to
time, will list eligible participants so designated.
Effective Date
The stock award provisions contained herein shall be effective upon
shareholder and other required regulatory approval. The program is
otherwise effective January 1, 1994.
Definitions
The following definitions pertain to the program.
Circuit Breaker - a performance level below which no variable
compensation will be paid regardless of performance against the
corporate measures. For this program, no awards will be paid unless
earnings, less provision for awards, are greater than dividends paid in
the year for which variable compensation is to be awarded.
Compensation Committee - the Compensation Committee of the Board of
Directors.
Market Average - the average of salaries paid in the marketplace for
positions similar to those at GMP.
Market Range - a range running from 10% below to 10% above the market
average.
Marketplace - Companies that are determined by GMP to be those competing
for similar talent. Depending on the position within GMP, marketplace
companies can be utilities, general industry -- local, regional,
national, or any combination thereof.
Maximum - the maximum or optimal level of corporate performance with
respect to a corporate performance measure. This determination will be
applied separately to each performance measure. No variable
compensation with respect to a performance measure will be paid in
excess of the maximum level indicated.
Compensation Program - the compensation program, which consists of base
salary and the opportunity to earn variable compensation.
Organization Bands - tiers within which management positions are
clustered, to reflect the nature and scope of the jobs, reporting
relationships, and the like.
Peer Companies - a select group of utilities against which GMP's
performance will be measured.
Performance Measure - a critical factor used to measure the success of
the business.
Program Year - GMP's fiscal year.
Restricted Stock Grants - the portion of the variable compensation award
paid to participants in this program in the form of GMP common stock
that will be subject to two restrictions of a five (5) year duration:
(1) no transferability; and (2) forfeiture of the stock upon termination
of employment with the Company (except for retirement, death or
disability). During the five-year restriction period, dividends will be
paid and recipients will have voting rights. The value of restricted
stock is taxable when the restrictions lapse (after five years, or
earlier in the case of the participant's retirement, disability or
death). The restriction period begins on the date the awards are
granted.
Stock Grants - the portion of the variable compensation award paid to
participants in the form of shares of GMP common stock. These shares
are the property of the participant upon grant and may be retained or
sold. Upon grant, shares are subject to current taxation.
Target - the desired level of corporate performance with respect to a
performance measure. This determination will be applied separately for
each performance measure.
Threshold - the acceptable level of corporate performance with respect
to a performance measure. This determination will be applied separately
to each performance measure. No variable compensation with respect to a
performance measure will be paid unless the threshold level is attained.
Total Compensation - an amount comprised of base salary and variable
compensation.
Variable Compensation - compensation that is earned based on the
achievement of corporate performance objectives and that may be paid in
cash, stock grants, or restricted stock grants.
Program Components
The Compensation Program is comprised of two compensation components:
o Base Salary
o Variable Compensation
Base Salary
Each officer or other key management employee is paid a base salary
intended to be competitive with base compensation paid for similar
positions in the marketplace.
Variable Compensation
Each officer or other key management employee is eligible to earn
additional compensation when GMP's performance meets or exceeds various
performance objectives.
Base Salary
Base salaries are intended to provide a competitive rate of fixed
compensation. Base salary levels will be assessed by compiling and
analyzing salary information from various published survey sources on an
annual basis. Survey sources include:
o Mercer Finance, Accounting & Legal Compensation Survey
o Wyatt Top Management Report
o Edison Electric Executive Compensation Survey
Within one year after the adoption of the program, base salaries are
intended to be managed to the market average (in any event, within a
plus or minus 10% range around the market average) as determined from
the survey analysis. The average and the range may or may not change
from year to year depending on movement in the market and, therefore, it
is possible that base salaries may not be increased annually.
Appropriate adjustments will be made in May of each year.
Actual base compensation within the market range will depend on internal
equity, overall scope of responsibilities of the position, recruitment
needs, and significant individual performance variations.
The market ranges have been incorporated into three organization bands
(in lieu of job grades), as set forth in Appendix I, which may be
modified from time to time by direction of the Board or the Chief
Executive Officer. These bands reflect the nature of the positions and
their impact on the organization. Additionally, these bands signify
varying levels of participation in the variable compensation component
of the program. The band assignments are determined on the basis of
survey data and the role of the position.
Variable Compensation
The purpose of the variable compensation component of this program is to
tie compensation directly to the achievement of key corporate-wide
objectives. Awards earned will be paid in cash, stock grants, and
restricted stock as deemed appropriate by the Compensation Committee of
the Board of Directors. The initial variable award payments will be
made as set forth below. This award delivery feature is intended to
motivate participants toward the annual attainment of critical corporate
objectives consistent with the need to manage GMP to achieve longer-term
success.
Variable Compensation Award Opportunities
Each band has a different variable compensation opportunity as noted in
the following table.
Award Table (AT)
Variable Cash Opportunities as a %
Band of Base Salary
Threshold Target Maximum
A 25% 50% 75%
B 17.5% 35% 52.5%
C 12.5% 25% 37.5%
Performance Measures - Establishment
At the beginning of each year, appropriate corporate performance
measures will be determined for purposes of generating the variable
compensation award. These measures are expected to remain in
substantially the same form year-to-year. They may change, however, as
GMP revisits its strategic and operational plans.
The measures are:
o Return on Equity
o Total Shareholder Return
o Rates
o Customer Satisfaction; and
o Reliability
Performance objectives associated with these measures are established
for each fiscal year by the Compensation Committee and reviewed by the
Board of Directors. (See Appendix II for measures and specific
objectives for 1994, and years following, as indicated.)
After the close of each year, the Compensation Committee, with input
from the CEO, will determine the degree to which these performance
objectives were accomplished to determine if variable cash awards are to
be paid. If the threshold level of performance is not met, an award
will not be paid with respect to that specific performance measure.
In addition, the program incorporates a circuit breaker to protect
shareholder investment. The circuit breaker ensures that awards will
not be paid unless earnings, after subtracting the variable awards, are
greater than dividends paid in the year for which variable compensation
is to be awarded.
Performance Measures - Individual Performance Assessment
Individual performance may, on an exceptions basis, be taken into
consideration in determining the final award. However, the maximum
shown in the Award Table cannot be exceeded.
Performance Measures - Weighting
The performance measures will be weighted each year to reflect the
strategic plan and the impact each organization band/position has on
performance. The number of measures used will be limited to ensure that
the significance of the measures will not be diluted (weights less than
10% cannot be used).
The performance measures will be weighted as noted in Appendix II.
Determination of Award
An award will be determined in accordance with the following example.
Assume:
o Participant is in Band B
o Base Salary = $100,000
o Individual Performance = meets expectations
o Circuit Breaker = achieved required level
Performance Performance Award % Adjusted Award %
Measure Weight Results (from AT) Weight Time %
ROE 30% 75% ile 35% 10.5%
TSR
oD&P 15% Threshold 17.5% 2.625%
oSelect 15% Threshold 17.5% 2.625%
Rates 20% 80% ile 35% 7.0%
Customer
Satisfaction 10% 80% 35% 3.5%
Reliability
oSAII 3.3% Threshold 17.5% .583%
oSAIFI 3.3% Threshold 17.5% .583%
oCAIDI 3.3% Threshold 17.5% .583%
Total Award X = 28%
Award = $28,000
Variable Compensation Award Payment
An award earned will be paid in cash and, subject to shareholder and
required regulatory approval, stock grant and restricted stock grant in
accordance with the following schedule:
Band Cash Stock Grant Restricted
Stock
A 1/4 1/4 1/2
B&C 1/3 1/3 1/3
The Compensation Committee may make changes in this schedule, subject to
review by the Board of Directors.
Cash
The cash portion of the award will be paid in a separate check.
Stock Grants
The stock grant portion of the award will be paid in shares of GMP
common stock. The number of shares will be determined by dividing the
portion of the award to be paid in stock by the closing stock price on
the day the Board of Directors authorizes variable compensation payments
(i.e., the annual meeting). The number of shares so determined will be
rounded up to the nearest full share.
Relevant taxes (e.g., federal, FICA, State), based on the cash and stock
grant portions of the award, will be withheld.
Restricted Stock
The grant of restricted stock will be made upon execution of an
agreement between the participant and the Company that will provide, for
a period of five (5) years from the date of the grant, that: (a) the
shares will not be transferable; and (b) the shares will be forfeited
upon termination of employment with GMP, except where the termination of
employment results from retirement, disability or death.
The number of restricted stock shares to be awarded will be determined
as described immediately above with respect to stock grants.
Program Administration
The program will be administered by the Chief Executive Officer with
approval of the Compensation Committee.
The Compensation Committee will review the operation of the program no
less frequently than annually and, as it deems necessary, recommend
appropriate actions to the Board of Directors.
The Board of Directors will have the full power and authority to:
o Interpret the program
o Approve participants
o Act on the CEO's recommendations
o Amend or terminate the Program, subject to required shareholder and
regulatory approval
o Approve the CEO's award
Participation in the program does not confer any right or privilege
regarding continued employment with GMP upon a participant.
Payment of the cash and, subject to required shareholder and regulatory
approval, the stock grant portions, will be made during the second
quarter following the end of the program year.
Participants must be employed on the date the award is paid in order to
receive an award unless the participant has retired, is disabled or is
deceased, or the Compensation Committee determines that the
circumstances under which the participant terminated employment warrant
special consideration.
Payments of variable compensation awards will not affect a participant's
levels of entitlement to participate in other benefit plans unless
expressly stated in documentation for such plans existing as of January
1, 1994.
The program will be administered in accordance with the laws of the
State of Vermont.
Appendix I
Band* Position Role
A President and CEO Strategic
Senior VP & COO
B VP Finance & CFO Strategic
VP Law & Administration
VP External Affairs & Customer Service
VP Planning
General Counsel
C Controller Strategic /
AVP Engineering Tactical
AVP for Organizational Development
AVP Customer Operations
Central & Southern Divisions
AVP Customer Operations Wester
Division
Assistant General Counsel
Assistant Treasurer
General Manager, Administrative Services
*Band A applies generally to the CEO and COO; Band B applies generally
to Vice Presidents and General Counsel; and Band C applies generally to
Assistant Vice Presidents and other key management personnel.
Appendix II
Performance Measures -- Weights
o Return on Equity 30%
o Total Shareholder Return 30%
o Rates 20%
o Customer Satisfaction 10%
o Reliability 10%
Performance Measures -- Objectives
The objectives for 1994 for each of the performance measures are:
o Return on Equity
-- The peer group is the Duff & Phelps 90
-- To achieve threshold performance, GMP's ROE for electric
operations must be equal to or greater than the allowed ROE level,
or equal to or greater than 60% of the peer group
-- Target level is equal to or greater than 75% of the peer group
-- Maximum performance is equal to or greater than 90% of the peer
group
o Total Shareholder Return
-- Performance is measured using two different peer groups: the Duff
& Phelps 90, and a select peer group. The select group includes:
_ Atlantic Energy
_ Bangor-Hydro
_ Black Hills
_ Central Hudson
_ Central Vermont Public Service
_ Eastern Utilities Associates
_ Empire District
_ Idaho Power
_ Minnesota Power & Light
_ Otter Tail Power
-- Total Shareholder Return (TSR) is defined as dividends plus
capital appreciation using a three-year rolling average
-- To achieve threshold performance, GMP's TSR must be in the top
half of the peer group
-- Target performance is equal to or greater than 60% of the peer
group
-- Maximum performance is equal to or greater than 70% of the peer
group
o Rates
-- Performance is measured against 10 New England utilities. They
are:
_ Central Maine Power
_ Bangor-Hydro
_ Public Service of New Hampshire
_ Central Vermont
_ Boston Edison
_ Commonwealth Energy
_ Massachusetts Electric
_ Connecticut Power & Light
_ United Illuminating
_ Narragansett Electric
-- To achieve threshold performance, GMP's rates must be equal to or
lower than 70% of the peer group
-- Target performance is achieved when GMP's rates are equal to or
lower than 80% of peer group
-- Maximum performance is reached when GMP's rates are lowest or
second lowest among the peer group
o Customer Satisfaction
-- Performance is measured using two surveys (i.e.,
Commercial/Industrial, Residential) with respect to the following
aspects of customer satisfaction: reliability of service,
responsiveness to trouble calls, responsiveness to customer
inquiries, accuracy of customers' bills, effectiveness of
telephone communications, effective delivery of DSM services.
-- To achieve threshold performance, 70% or more of customers must
indicate satisfaction
-- Target performance is achieved when 80% or more of customers
indicate satisfaction
-- Maximum performance is reached when 90% or more indicate
satisfaction
o Reliability
-- Performance is measured using three indices:
_ System average interruption index
_ System average interruption frequency index
_ Customer average interruption duration index
-- To reach threshold performance, GMP's performance must improve 5%
or more from that achieved in the previous year
-- Target performance is 10% or greater improvement from the previous
year
-- Maximum performance is 12% or greater improvement from the
previous year
EXHIBIT 23-a-1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated January 31, 1995 included in this
Form 10-K, into the Company's previously filed Registration Statement on
Form S-3, File No. 33-48882, and into the Company's previously filed
Registration Statement on Form S-8, File No. 33-47985.
Boston, Massachusetts
March 30, 1995 /s/ Arthur Andersen LLP
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1994 AND THE RELATED
STATEMENTS OF INCOME AND CASH FLOWS FOR THE TWELVE MONTHS ENDED
DECEMBER 31, 1994 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 175,987
<OTHER-PROPERTY-AND-INVEST> 20,751
<TOTAL-CURRENT-ASSETS> 28,798
<TOTAL-DEFERRED-CHARGES> 35,659
<OTHER-ASSETS> 33,416
<TOTAL-ASSETS> 294,611
<COMMON> 15,592
<CAPITAL-SURPLUS-PAID-IN> 60,000
<RETAINED-EARNINGS> 25,727
<TOTAL-COMMON-STOCKHOLDERS-EQ> 101,319
8,280
855
<LONG-TERM-DEBT-NET> 74,967
<SHORT-TERM-NOTES> 20,214
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 4,833
0
<CAPITAL-LEASE-OBLIGATIONS> 10,278
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 73,865
<TOT-CAPITALIZATION-AND-LIAB> 294,611
<GROSS-OPERATING-REVENUE> 148,197
<INCOME-TAX-EXPENSE> 5,395
<OTHER-OPERATING-EXPENSES> 128,285
<TOTAL-OPERATING-EXPENSES> 133,680
<OPERATING-INCOME-LOSS> 14,517
<OTHER-INCOME-NET> 3,681
<INCOME-BEFORE-INTEREST-EXPEN> 18,198
<TOTAL-INTEREST-EXPENSE> 7,196
<NET-INCOME> 11,002
794
<EARNINGS-AVAILABLE-FOR-COMM> 10,208
<COMMON-STOCK-DIVIDENDS> 9,713
<TOTAL-INTEREST-ON-BONDS> 6,868
<CASH-FLOW-OPERATIONS> 28,865
<EPS-PRIMARY> 2.23
<EPS-DILUTED> 2.23
</TABLE>
