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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
_X_ Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934 [Fee Required]
For the fiscal year ended December 31, 1993
___ 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 __________________
Commission file number 1-8291
GREEN MOUNTAIN POWER CORPORATION
_____________________________________________
(Exact name of registrant as specified in its charter)
Vermont 03-0127430
___________________________ _____________________________
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
incorporation or organization)
25 Green Mountain Drive
South Burlington, VT 05403
_________________________________ __________
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (802) 864-5731
___________________
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each exchange on which registered
COMMON STOCK, PAR VALUE NEW YORK STOCK EXCHANGE
$3.33-1/3 PER SHARE
________________________________________________________________________
Securities registered pursuant to Section 12 (g) of the Act: None
________________________________________________________________________
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days. Yes
__X__ No _____
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. ___
The aggregate market value of the voting stock held by
nonaffiliates of the registrant as of March 18, 1994, was
$138,239,725.00 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 18, 1994,
was 4,532,450.
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 19, 1994, 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 79,500 customers. For the year ended December 31, 1993, the
Company's sources of revenue were derived as follows: 33.2% from
residential and lease customers, 31.6% from small commercial and industrial
customers, 21.1% from large commercial and industrial customers, 9.6% from
sales to other utilities, and 4.5% from other sources. For the same
period, the Company's energy resources for retail and requirements
wholesale sales were obtained as follows: 42.5% from hydroelectric sources
(6.6% Company-owned, 1.6% New York Power Authority ("NYPA"), 28.6% Hydro-
Quebec and 5.7% small power producers), 28.5% from nuclear generating
sources (the Vermont Yankee plant described below), 14.8% from coal
sources, 1.1% from natural gas, 0.7% from oil and 0.4% from wood. The
remaining 12.0% was purchased on a short-term basis from other utilities
and through the New England Power Pool ("NEPOOL"). In 1993, the Company
purchased 91.8% 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
Note: Included in the energy sales and operating statistics described in
this Annual Report on Form 10-K are NYPA lease transmissions. For
information concerning NYPA lease transmissions, see "Power Resources - New
York Power Authority."
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 1993, the Company also supplied six firm wholesale
customers, including four municipal and two cooperative utilities in
Vermont and two utilities in other states. 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, 1993, 1992 and 1991, electric
energy sales to International Business Machines Corporation ("IBM"), the
Company's largest customer, accounted for 13.6%, 13.8% and 13.0%,
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 is 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 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 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 transmission, distribution and
conservation projects.
Capital expenditures over the past three years and forecasted for the
next five years are as follows:
Total Net
Generation Transmission Distribution Conservation Other Expenditures
(Dollars in thousands and net of AFUDC and Customer Advances for Construction)
Actual
1991 $ 2,038 $ 1,682 $ 7,628 $ 2,269 $ 2,564 $ 16,181
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
Forecasted
1994 $ 709 $ 829 $ 7,849 $ 6,975 $ 3,618 $ 19,980
1995 7,567 999 7,132 6,776 2,402 24,876
1996 1,978 1,499 7,301 6,497 2,251 19,526
1997 1,579 999 7,386 5,867 2,386 18,217
1998 1,579 999 7,386 5,430 2,386 17,780
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 1991-1993, internally generated funds, after payment of
dividends, provided approximately 47% of total capital requirements for
construction, sinking fund obligations and other requirements, including
working capital. Internally generated funds provided 46% of such
requirements for 1993. It is expected that funds so generated will provide
approximately 67% of such requirements for the period 1994 through 1998,
with the remainder to be derived through short-term borrowings and the
issuance of senior securities and common stock.
In November 1993, the Company sold $20 million of its first mortgage
bonds in two components: $15 million that will mature in 2018 and $5
million that will mature in 2000. The 2018 and 2000 bonds will bear
interest at the rates of 6.7% and 5.71%, respectively. The proceeds from
the sale of such bonds were used to refinance existing debt, to finance
construction and conservation expenditures, and for other corporate
purposes.
The Company anticipates issuing additional shares of its common stock
in 1994. The amount and timing of such issuance 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
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
Net System Capability During Peak Month (MW)
Hydro (1)............................................ 174.9 160.6 161.3 119.6 121.4
Lease transmissions.................................. 3.9 5.7 5.7 9.4 9.4
Nuclear (1).......................................... 109.5 109.6 85.0 67.6 67.6
Conventional steam................................... 92.6 95.0 88.5 114.4 157.4
Internal combustion.................................. 71.0 47.4 52.0 47.7 13.9
Combined cycle....................................... 22.8 21.6 22.6 22.8 22.8
---------- ---------- ---------- ---------- ----------
Total capability (MW).............................. 474.7 439.9 415.1 381.5 392.5
Net system peak...................................... 307.3 314.4 308.5 301.9 322.6
---------- ---------- ---------- ---------- ----------
Reserve (MW)......................................... 167.4 125.5 106.6 79.6 69.9
========== ========== ========== ========== ==========
Reserve % of peak.................................... 54.5% 39.9% 34.6% 26.4% 21.7%
Net Production (MWH)
Hydro (1)............................................ 751,078 641,525 611,658 784,358 749,029
Lease transmissions.................................. 15,425 58,374 67,600 66,235 151,391
Nuclear (1).......................................... 598,245 665,034 731,582 671,563 618,102
Conventional steam................................... 748,626 762,451 799,781 859,059 928,184
Internal combustion.................................. 2,849 1,504 3,809 1,176 9,299
Combined cycle....................................... 40,966 60,138 104,344 90,825 138,732
---------- ---------- ---------- ---------- ----------
Total production...................................2,157,189 2,189,026 2,318,774 2,473,216 2,594,737
Less nonrequirements sales to other utilities........ 271,224 273,087 448,110 587,475 710,055
---------- ---------- ---------- ---------- ----------
Production for requirements sales....................1,885,965 1,915,939 1,870,664 1,885,741 1,884,682
Less requirements sales & lease transmissions (MWH)..1,749,454 1,794,986 1,742,308 1,759,393 1,726,177
---------- ---------- ---------- ---------- ----------
Losses and company use (MWH)......................... 136,511 120,953 128,356 126,348 158,505
========== ========== ========== ========== ==========
Losses as a percentage of total production............. 6.33% 5.53% 5.54% 5.11% 6.11%
System load factor (2)................................. 68.7% 68.5% 67.9% 69.5% 64.4%
Sales and Lease Transmissions (MWH)
Residential - GMP.................................... 541,579 505,234 483,998 500,163 446,972
Lease transmissons................................... 15,425 58,374 67,600 67,370 135,147
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 557,004 563,608 551,598 567,533 582,119
Commercial & industrial - small...................... 593,560 582,594 571,818 580,562 571,282
Commercial & industrial - large...................... 529,372 539,665 519,201 519,688 499,562
Other................................................ 8,868 6,312 2,770 (4,726) 11,197
---------- ---------- ---------- ---------- ----------
Total retail sales and lease transmissions.........1,688,804 1,692,179 1,645,387 1,663,057 1,664,160
Sales to municipals and cooperatives and
other requirements sales........................... 60,650 102,807 96,921 96,335 62,017
---------- ---------- ---------- ---------- ----------
Total requirements sales...........................1,749,454 1,794,986 1,742,308 1,759,392 1,726,177
Other sales for resale............................... 271,224 273,087 448,110 587,474 725,382
---------- ---------- ---------- ---------- ----------
Total sales and lease transmissions................2,020,678 2,068,073 2,190,418 2,346,866 2,451,559
========== ========== ========== ========== ==========
Average Number of Electric Customers
Residential.......................................... 67,994 67,201 66,406 65,553 64,330
Commercial and industrial - small.................... 11,447 11,245 11,215 11,300 10,956
Commercial and industrial - large.................... 25 24 24 23 22
Other................................................ 74 73 71 71 69
---------- ---------- ---------- ---------- ----------
Total.............................................. 79,540 78,543 77,716 76,947 75,377
========== ========== ========== ========== ==========
Average Revenue per KWH (Cents)
Residential including lease revenues................. 8.94 8.44 8.06 7.54 6.76
Lease charges........................................ 0.06 0.41 0.26 0.25 0.42
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 9.00 8.85 8.32 7.79 7.18
Commercial and industrial - small.................... 7.97 7.82 7.53 6.99 6.78
Commercial and industrial - large.................... 5.96 5.89 5.72 5.30 5.16
Total retail including lease revenues................ 7.86 7.56 7.29 6.79 6.39
Average Use and Revenue Per Residential Customer
Kilowatt hours including lease transmissions......... 8,192 8,387 8,306 8,658 9,049
Revenues including lease revenues.................... $733 $707 $670 $653 $611
(1) See Note K of Notes to Consolidated Financial Statements.
(2) Load factor is based on net system peak and firm MWH
production less off-system losses.
DEMAND-SIDE MANAGEMENT
The Company has committed itself to the development and implementation
of demand-side management 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. Demand-side management 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.
Due to the economics of New England's current excess power supply
market, the Company is expected to reevaluate demand-side management
program design in 1994 to take into account lower marginal avoided costs.
This program redesign may entail program modifications, curtailment or
deferment, the addition of strategies for strategic efficient load growth,
and modification of existing energy conservation measures.
Integrated Resource Plan. In 1990, the Company entered into a
collaborative design agreement with the Vermont Department of Public
Service, the Conservation Law Foundation and other interested parties to
assist with the development of its demand-side management plans. This
collaborative design process culminated with an agreement on the design of
eleven specific demand-side management programs and on issues related to
regulatory approval and cost recovery for program implementation. These
demand-side management programs were filed with the VPSB in May 1991. The
VPSB approved these programs in September 1991.
In October 1991, the Company completed development of its second
formal Integrated Resource Plan. The Plan identified the most cost-
effective composite of supply- and demand-side resource alternatives to
meet the anticipated future energy needs of the Company's customers;
integrated the planning functions of the energy supply, demand-side
management, finance and engineering areas of the Company; and incorporated
the implementation of those specific demand-side management programs
approved by the VPSB in 1991. The Plan forecasted an increasing role for
demand-side management in future Company operations. Planned demand-side
management programs are projected to meet approximately one-third of the
Company's expected load growth into the next century.
Current engineering and economic assumptions vary from those used in
the Company's October 1991 Integrated Resource Plan. Avoided power supply
costs have declined considerably. As a consequence, it is likely that the
pace of demand-side management expenditures could change.
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 3,000 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 new rate
design that permits it to charge prices for electric service that reflect
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 4,000 largest customers be charged time-of-use rates on a phased-
in basis by 1994. As of April 1, 1991, approximately 1,300 of the
Company's largest customers, comprising 48% of retail revenues, were
successfully converted to time-of-use rates. During 1991 additional
implementation of time-of-use rates was discontinued until further research
on the cost effectiveness of time-of-use rates for small customers is
performed. This work is continuing and will be reflected in the Company's
next rate design proceeding, expected to be filed during the second quarter
of 1994.
Dispatchable and Interruptible Service Contracts. In 1993, the
Company had dispatchable and interruptible power contracts with four major
ski areas, interruptible only contracts with three other customers and
dispatchable-only contracts with four customers. The dispatchable portions
of the contracts allow customers to purchase additional energy when the
Company has low-cost electricity available ("dispatchable hours"), while
the interruptible portions of the contracts allow the Company to avoid
power supply capacity charges by reducing the Company's capacity
requirements. Due to the surplus capacity in the region, the Company
suspended the interruptible portions of the contracts but continued to
offer the dispatchable portions to its customers.
In 1993, the Company revised its tariffs to permit other commercial
customers to participate in the dispatchable and interruptable service
contract program if their load requirements made it practical for them to
do so. As of the end of 1993, three additional customers had signed
contracts to participate in the program. By participating in the program
these customers can now buy electricity from the Company during
dispatchable hours without incurring a demand charge. The Company, in
turn, is able to retain customer load requirements that otherwise might
have been met through self-generation.
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 7,100 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 1993, the
Company offered five commercial and industrial energy efficiency programs
to qualifying customers. These programs offer comprehensive technical
assistance to identify cost-effective electric energy efficiency
opportunities which may qualify for financial incentives. In addition,
fuel-switching opportunities are identified for customers, although no
direct financial incentives are provided. Approximately 1,000 customers
participated in these programs in 1993, resulting in an approximate savings
of 16,000 MWh. In 1993, the Company achieved approximately 160% of its
energy savings targets developed in the collaborative design agreement
discussed above, with the overall program performance (residential,
commercial and industrial) of approximately 145% of the energy savings
targets.
Residential Energy Management Services. In 1993, the Company offered
six demand-side management 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 6,000 residential customers participated in these
programs in 1993 resulting in an annual savings of approximately 3,419 MWh.
POWER RESOURCES
The Company generated, purchased and (in the case of NYPA power)
transmitted 1,848,608 MWh of energy for retail and requirements wholesale
customers for the twelve months ended December 31, 1993. The corresponding
maximum one-hour integrated demand during that period was 307.3 MW on
February 1, 1993. This compares to the previous all-time peak of 322.6 MW
on December 27, 1989. The following tabulation shows the annual average
capacity, 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."
>
1993 Average Net Generated and Net Generated and
Monthly Net Purchased Year Purchased in Month
Capability Ended 12/31/93 (a) of Annual Peak
____________ ___________________ ___________________
KW MWh % KW %
WHOLLY OWNED PLANTS
Hydro 34,363 123,946 6.65 35,660 7.51
Diesel and Gas Turbine 63,487 2,320 0.12 74,370 15.67
JOINTLY OWNED PLANTS
Wyman #4 7,058 6,474 0.35 7,083 1.49
Stony Brook I 5,478 7,001 0.38 7,194 1.52
McNeil 6,412 11,561 0.62 6,567 1.38
OWNED IN ASSOCIATION W/OTHERS
Vermont Yankee Nuclear (b) 79,823 531,997 28.56 80,663 16.99
NYPA LEASE TRANSMISSIONS
State of Vermont (NYPA) 2,997 29,047 1.56 3,906 0.82
LONG-TERM PURCHASES
Hydro-Quebec 99,946 532,452 28.59 89,064 18.77
Merrimack #2 30,457 230,812 12.39 30,457 6.42
Stony Brook I 12,947 13,590 0.73 13,788 2.91
Small Power Producers 22,064 106,647 5.73 21,743 4.58
Rochester Gas & Electric 0 0 0 0 0
SHORT-TERM PURCHASES
Ontario Hydro #3 20,271 44,165 2.37 29,476 6.21
Other Utilities 40,597 218,100 11.71 73,739 15.54
NEPCO (STAMFORD) 664 4,465 0.24 901 0.19
______ _______ _____ ______ _____
Less System Sales Energy (13,969)
TOTAL 426,564 1,848,608 100.00 474,611 100.00
======= ========= ====== ======= ======
NOTE: (a) Excludes losses on off-system purchases, totaling 37,357
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.
See Notes 1 and 2 of Notes to Financial Statements of Vermont Yankee.
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. In late August 1993, Vermont Yankee began a scheduled refueling
outage which was completed on October 26, 1993. Vermont Yankee's next
scheduled refueling is March 1995. 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
$7,229,000 in 1993, $10,750,000 in 1992 and $6,596,000 in 1991. Vermont
Yankee estimates capital expenditures amounting to approximately
$15,650,000 for 1994.
During the year ended December 31, 1993, the Company utilized 531,997
MWh of Vermont Yankee energy to meet 28.6% of its retail and requirements
wholesale sales. The average cost of electricity produced by the plant in
1993 was 5.3 cents per KWh. In 1993, Vermont Yankee had an annual capacity
factor of 76.9%, compared to 83.3% in 1992 and 91.2% in 1991.
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $9,400,000,000. Any liability beyond
$9,400,000,000 is indemnified under an agreement with the NRC. 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 $9,200,000,000 per
incident by assessing retrospective premiums of $79,300,000 against each of
the 116 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 $3,100,000. The secondary financial protection program referenced above
provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL II) to cover the costs of property damage, decontamination or
premature decommissioning resulting from a nuclear incident. All companies
insured with NEIL II are subject to retroactive assessments if losses
exceed the accumulated funds available to NEIL II. The maximum potential
assessment against Vermont Yankee with respect to losses arising during the
current policy year is $5,800,000 at the time of the first loss and
$12,300,000 at the time of a subsequent loss. 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.
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, 1993,
the present value of the Company's obligation was $11,000,000. The
Company's projected future minimum payments under the Phase II support
agreements are $501,311 for each of the years 1994-1998 and an aggregate of
$8,522,270 for the years 1999-2020.
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, 1993, the capital structure of such corporations
was 40% common equity and 60% long-term debt.
Hydro-Quebec Power Supply Contracts. Under various contracts approved
by the VPSB, the details of which are described in the table below, the
Company purchases capacity and associated energy produced by the Hydro-
Quebec system. Such contracts obligate the Company to pay certain fixed
capacity costs whether or not energy purchases above a minimum level set
forth in the contracts are made. Such minimum energy purchases must be
made whether or not other, less expensive energy sources might be
available. These contracts are intended to complement the other components
in the Company's power supply to achieve the most economic power-supply mix
reasonably available.
July 1984 December 1987 Contract
Contract Schedule A Schedule B Schedule C3
__________ __________ __________ ___________
(Dollars in thousands)
Capacity Acquired 50 MW 17 MW 68 MW 46 MW
Contact Period 1985-1995 1990-1995 1995-2015 1995-2015
Minimum Energy Purchase 50% 50% 75% 75%
(annual load factor) (1992-1995)
Minimum Energy Charge $3,881 $2,134 $16,157 $11,060
(1993) (1993) (1995-2015)* (1995-2015)*
$3,785 $2,281
(1994-1995)* (1994-1995)
Annual Capacity Charge $3,379 $1,681 $16,663 $11,821
(1993) (1993) (1995-2015)* (1995-2015)*
$3,355 $1,691
(1994-1995)* (1994-1995)*
Average Cost per KWH 2.8 cents 5.5 cents 7.0 cents 7.3 cents
(1993) (1993) (1995-2015)** (1995-2015)**
2.7 cents 4.6 cents
(1994-1995)* (1994-1995)*
* Estimated average
** Estimated average in nominal dollars, levelized over the period indicated.
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 1993, 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 1994. The Company anticipates that purchases of
tertiary energy will extend beyond August 1994, 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.
The December 1987 contract also contains a provision that prohibits
Hydro-Quebec, for a period ending in 1995, from selling power under similar
terms and conditions to any other United States utility at a price lower
than the Company would pay unless the lower price is made available to the
Company. The price of the energy acquired under the December 1987 contract
will reflect adjustments in the United States Gross National Product
Implicit Price Deflator over the term of the contract. The price of the
capacity acquired will reflect adjustments in a pertinent construction cost
index (the Handy Whitman Index of Public Utility Construction Costs) until
the time deliveries begin. From the commencement of deliveries to the
expiration of the contract, the capacity price is essentially frozen.
(Some adjustments are made to reflect changes in financing costs over
time.) Based on current integrated resource analyses, the Company believes
that these contracts for Hydro-Quebec system power compare favorably with
alternative long-term resources available to the Company.
In 1993, the Company utilized 353,729 MWh of Hydro-Quebec energy under
the July 1984 contract, 67,833 MWh under the December 1987 contract
Schedule A and 110,890 MWh under the tertiary energy contract to meet 28.6%
of its retail and requirements wholesale sales. The average cost of Hydro-
Quebec electricity in 1993 was 3.4 cents per KWh. See Notes J and K-2 of
Notes to Consolidated Financial Statements.
New York Power Authority ("NYPA"). NYPA power provided 15,425 MWh to
the Vermont Department of Public Service (the "Department") customers,
delivered over the Company's facilities at an average retail rate of 0.9 cents
per KWh. As of August 1993, the Department chose not to continue retailing
NYPA power to the Company's customers. The Department now wholesales the
allocation of NYPA power to the Company who, in turn, delivers the power to
residential and farm customers. In addition, the Company purchased at
wholesale 13,622 MWh of NYPA power at an average cost of 1.3 cents per KWh in
1993. 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 1993 - June 1994 2.0
July 1994 - June 1995 0.3
July 1995 - June 1996 0.3
July 1996 - June 1997 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, 1993, the Company utilized 230,812 MWh
from the unit to meet 12.4% of its total retail and requirements wholesale
sales. Merrimack Unit #2 operated at a 73.1% annual capacity factor in
1993 and 66.8% in 1992. The average cost of electricity from this unit was
3.0 cents per KWh in 1993. 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 1993, the Company utilized 20,591 MWh from this plant to meet
1.1% of its retail and requirements wholesale sales at an average cost of
9.8 cents per KWh. See Note I-3 and K-1 of Notes to Consolidated Financial
Statements.
Ontario Hydro. The State of Vermont executed a five-year contract
with Ontario Hydro, commencing November 1, 1987, and expiring October 31,
1992, which provides for the purchase by the State of 73 MW of high-
availability power. The contract has options for increasing the power
purchased starting November 1 of 1988, 1989, 1990 and 1991, to a maximum of
88 MW, 98 MW, 108 MW and 112 MW, respectively. This contract can be
extended for three additional five-year periods. The maximum option
increases have been exercised. The Company receives a share of the Ontario
Hydro power imported by the State. The Company's obligation under this
contract terminated as of December 1993. The Company's average share of
such power for 1993 was 20.3 MW, and 44,165 MWh of Ontario Hydro energy
were utilized to meet 2.4% of its retail and requirements wholesale sales.
The average cost of this power was 5.3 cents per KWh in 1993.
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 the 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 1993, the Company utilized 6,474 MWh from this unit to meet
0.3% of its retail and requirements wholesale sales at an average cost of
5.3 cents per KWh. 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 1993, the
Company utilized 11,561 MWh from this unit to meet 0.5% of its retail and
requirements wholesale sales at an average cost of 7.0 cents per KWh. 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. This flexible contract allows the Company the discretion of
purchasing from 0 MW to 50 MW on a weekly basis. The Company has no
obligation to purchase power in any week. When the Company elects to
schedule a purchase, however, it must take and pay for energy at a 75% load
factor, or pay a penalty, in the week of the purchase. 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 contract 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
contract 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
contract, and to 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 will replace the
Company as the supplier of electricity to Bozrah, will assume
responsibility for approximately 75% of the fixed costs of the transmission
contract with Niagara Mohawk, and will provide 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 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
MW of system power for the period July 1995 through December 2004.
The Company expects that the reductions in its 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. The arrangement was approved by
FERC effective May 1, 1993.
Estimated Charges
1993
Annual Transmission Reservations $300,000
Average Cost per kWh (1993)(1)
4.1 cents (1994-1995)
(1) No power purchases were made under the RG&E or CL&P contracts described
above during 1993.
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 ("PURPA") of 1978. 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 32.6% or
48.8 MW.
In 1993, the Company, through both its direct contracts and the
Vermont Power Exchange, purchased 106,647 MWh of small power production to
meet 5.7% of its retail and requirements wholesale sales at an average cost
of 10.0 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 1993, the Company purchased 222,565 MWh, 11.9% of the Company's
retail and requirements wholesale sales, at an average cost of 2.4 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 1993, these plants provided 123,946 MWh of low-cost energy,
meeting 6.6% of the Company's retail and requirements wholesale sales at an
average cost of 0.9 cents per KWh. 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 1993, the Company's retail and requirements wholesale
sales were provided by the following fuel sources: 42.5% from hydro (6.6%
Company-owned, 1.6% NYPA, 28.6% Hydro-Quebec and 5.7% small power
producers), 28.5% from nuclear, 14.8% from coal, 1.1% from natural gas,
0.7% from oil and 0.4% from wood. The remaining 12.0% was purchased on a
short-term basis from other utilities and through NEPOOL.
Vermont Yankee has approximately $165 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
this contract, DOE will provide disposal services when a facility for spent
nuclear fuel and other high level radioactive waste is available, which is
required under current statutes to be prior to January 31, 1998. A
facility is not yet available. Vermont Yankee also bills its sponsors,
including the Company, a disposal fee, which is subject to annual DOE
adjustment of $.001 per KWh of net generation. See Management's Financial
Analysis in Item 7 herein, Note B of Notes to Consolidated Financial
Statements and Note 8 to Vermont Yankee Notes to Financial Statements.
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 1993, and, while no assurance can be given, does not
anticipate any such difficulty during 1994. None of the utilities from
which the Company expects to purchase oil- or gas-fired capacity in 1994
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 28, 1994,
there was a 90-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 103,814
tons of wood chips and mill residue and 257,393,000 cubic feet of gas in
1993. The McNeil plant is forecasting consumption of wood chips for 1994
to be 120,000 tons and gas consumption of 600,000,000 cubic feet.
Burlington Electric Department advises that, as of February 26, 1994, there
were 9,200 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's wholesale rate on sales to eight wholesale customers is
regulated by the FERC. Revenues from sales to these customers were
approximately 2.4% of operating revenues for 1993.
Included within these customers is the Bozrah Light and Power Company,
a private electric utility in Connecticut, with whom the Company had a
contract to provide wholesale electric service on a full-requirements
basis. Service to Bozrah began in March 1987 and terminated May 1, 1993.
See "Power Resources - New York Purchases: Rochester Gas and Electric
Corporation" for a discussion of the three-party agreement negotiated by
the Company relating to the termination of full-requirements service to
Bozrah.
Late in 1989, the Company began serving two new municipal utilities,
Northfield and Hardwick, under its wholesale tariff. These customers
increased electricity sales by approximately 46,000 MWh and peak
requirements by approximately 9 MW. Revenues in 1993 from Northfield and
Hardwick were $1,727,058. Service to Hardwick under the Company's
wholesale tariff terminated on April 30, 1993.
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 1993.
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 by mid-1994. 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. On October 15,
1988, 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 electrical energy demand. The Plan calls for
exploring the potential reduction of electrical demand through
conservation and load management.
The Company continues to implement its Integrated Resource Plan in a
manner consistent with the Department's Plan. The 1991 Integrated Resource
Plan calls for the continued design and delivery of conservation and load
management programs, customer programs and education programs as well as
measures concerning the efficient distribution of power to the end user.
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. Thereafter, the Company and other PRPs held
several meetings with the EPA to discuss technical issues and received
copies of the EPA's Supplemental Remedial Investigation Final Report, and
its Baseline Risk Assessment Final Report.
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 a 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 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 mediator. The council is charged with
determining what additional studies may be appropriate for the site and may
also eventually address additional response activities. The Company is
represented on the council.
In early 1994, the Company and other PRPs met with the EPA to commence
negotiations on an Administration Order of Consent pursuant to which the
PRPs would conduct additional studies agreed to by the coordinating
council. Although negotiations are not yet complete, it is likely that the
EPA will consent to allowing the PRPs to conduct additional studies at the
site and that the EPA will not require 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.
In September 1991, the Company, New England Electric System and
Vermont Gas Systems, Inc. entered into confidential negotiations with most
other PRPs concerning allocation of unresolved liabilities concerning the
site. Those negotiations are continuing.
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. The
parties to this action are engaged in discovery and motions practice.
The Company has reached a confidential settlement with one of the
defendants that provided the Company with second layer excess liability
coverage for a seven month period in 1976. The Company has also reached a
confidential agreement in principle with another insurance company
defendant that 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 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.
In its 1991 rate case, the Company, for the first time, sought
recovery for expenses associated with the Pine Street Marsh site.
Specifically, the Company proposed rate recognition of its estimated,
unrecovered 1991 expenditures (approximately $400,000) 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 Department reached
agreement that the full amount of Pine Street Marsh costs reflected in the
Company's 1991 rate case should be recovered in rates. The Company's rates
approved by the VPSB on April 2, 1992, reflected the 1991 Pine Street Marsh
related expenditures referred to above.
In its rate increase request filed on October 1, 1993, the Company
proposed rate recognition for its expenditures between January 1, 1992 and
July 31, 1993 (approximately $4,200,000) for technical consultants and
legal assistance in connection with the EPA's enforcement actions at the
site and insurance litigation. The Department and the Company have reached
the same agreement regarding recovery of these costs in rates that they
reached with respect to the Company's 1991 Pine Street Marsh related
expenditures. A comprehensive settlement of the Company's 1993 rate case,
including the agreement regarding Pine Street Marsh costs, is currently
pending before the VPSB.
As of December 31, 1993, the Company had reserved approximately
$680,000 for costs attributable to the site, other than those costs that
are the subject of the agreements between the Department and the Company
mentioned above. Management expects to seek and receive ratemaking
treatment for other costs incurred beyond the amounts that have been
reserved. As of December 31, 1993, such other costs are approximately
$4,918,000, which includes the $4,200,000 in costs that are the subject of
the most recent rate case settlement agreement referred to above.
COMPETITION
The Company serves a fixed area of Vermont under VPSB franchise.
Except as noted below, the Company's electric business is substantially
free from competition 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.
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
1993 1992
---- ----
(In thousands)
Revenue . . . . . . . . . . . . . . . $11,487 $11,146
Expense . . . . . . . . . . . . . . . 11,527 11,409
--------- ---------
Net Income (Loss) . . . . . . . . . . ($ 40) ($ 263)
========= =========
EMPLOYEES
The Company had 387 employees, exclusive of temporary employees, as of
December 31, 1993. In addition, subsidiaries of the Company had 58
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 1993 peak of 307.3 MW occurred
on February 1, 1993. 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 60% higher than during the eight off-
season months (April through November).
EXECUTIVE OFFICERS
Executive Officers of the Company as of March 31, 1994:
Name Age
Douglas G. Hyde 51 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 60 Senior Vice President and Chief Operating
Officer since 1993. Senior Vice President
from 1984 to 1993. President - Mountain
Energy, Inc. since December 1989.
Edwin M. Norse 48 Vice President, Chief Financial Officer and
Treasurer since 1986. President-Green
Mountain Propane Gas Company since October
1993.
Christopher L. Dutton 45 Vice President and General Counsel since
1993. Vice President, General Counsel and
Corporate Secretary from 1989 to 1993.
General Counsel and Corporate Secretary
from 1984 to 1989.
Glenn J. Purcell 60 Controller since September 1986.
Thomas C. Boucher 39 Vice President-Corporate Planning since
December 1992. Assistant Vice President-
Energy Planning from 1986 to 1992.
Stephen C. Terry 51 Vice President-External Affairs since
December 1991. Assistant Vice President-
Corporate Relations from 1986 to 1991.
Walter S. Oakes 47 Assistant Vice President-Corporate Services
since December 1988. Director-Customer
Services from 1987 to 1988.
Robert C. Young 56 Assistant Vice President-Operations and
Engineering since December 1992. 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 42 Assistant General Counsel since December
1989. Senior Attorney from 1988 to
December 1989. Corporate Attorney from
1985 to 1988.
Craig T. Myotte 39 Assistant Vice President-Operations and
Maintenance since May 1991. Director-
System Operations from 1986 to 1991.
John J. Lampron 49 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 44 Corporate Secretary since December 1993.
Assistant Secretary from 1986 to 1993.
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 an aggregate effective capability of 35.7 MW. It
also owns two gas-turbine generating stations with effective capabilities
of 15.2 MW and 56.3 MW, respectively. The Company has two diesel
generating stations with an aggregate effective capability of 8.4 MW,
bringing wholly owned effective capability to 116.3 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, 1993, approximately 1.5 miles of 115-
kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 miles of
44-kV and 265.1 miles of 34.5 kV transmission lines. Its distribution
system included about 2,336 miles of overhead lines, 2.4 kV to 34.5 kV, and
about 392 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 1,207,299 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 3.4
Marshfield, VT Marshfield #6 Hydro 5.0
Vergennes, VT Vergennes #9 Hydro 2.3
W. Danville, VT W. Danville #15 Hydro 1.2
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 8.4
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 30.2(2)
_____
Total Winter Capability 250.3
(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
1992 and 1993:
HIGH LOW
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
1992 First Quarter 31 1/4 29 1/4
Second Quarter 30 3/4 29
Third Quarter 33 5/8 30
Fourth Quarter 33 1/4 30 1/8
The number of common stockholders of record as of March 18, 1994, was
6,693.
Quarterly cash dividends were paid as follows for the past two years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
1993 52 1/2 cents 52 1/2 cents 53 cents 53 cents
1992 51 1/2 cents 51 1/2 cents 52 1/2 cents 52 1/2 cents
SELECTED FINANCIAL DATA
Results of operations for the years ended December 31
- -----------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
Operating Revenues........................$147,253 $145,240 $143,555 $147,633 $144,028
Operating Expenses........................ 132,427 128,828 129,041 133,925 131,853
--------- --------- --------- --------- ---------
Operating Income........................ 14,826 16,412 14,514 13,708 12,175
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity.......................... 273 186 225 86 136
Other................................... 2,360 2,073 2,689 2,037 2,196
--------- --------- --------- --------- ---------
Total other income.................... 2,633 2,259 2,914 2,123 2,332
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed funds.................. (357) (202) (131) (394) (360)
Other................................... 7,185 7,021 7,103 7,259 5,839
--------- --------- --------- --------- ---------
Total interest charges................ 6,828 6,819 6,972 6,865 5,479
--------- --------- --------- --------- ---------
Net Income................................ 10,631 11,852 10,456 8,966 9,028
Dividends on Preferred Stock.............. 811 831 852 421 292
--------- --------- --------- --------- ---------
Net Income Applicable to Common Stock..... $9,820 $11,021 $9,604 $8,545 $8,736
========= ========= ========= ========= =========
Common Stock Data
Earnings per share...................... $2.20 $2.54 $2.45 $2.29 $2.36
Cash dividends declared per share....... $2.11 $2.08 $2.04 $2.00 $1.95
Weighted average shares outstanding..... 4,457 4,345 3,919 3,729 3,697
Financial Condition as of December 31
- -------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
Assets
Utility Plant, Net.......................$171,411 $164,723 $159,730 $152,370 $131,754
Other Investments........................ 22,528 21,700 21,624 19,785 19,312
Current Assets........................... 26,944 28,067 26,778 25,891 26,818
Deferred Charges......................... 42,345 19,012 11,271 10,536 7,224
Non-Utility Assets....................... 28,626 23,716 19,832 11,078 9,209
--------- --------- --------- --------- ---------
Total Assets............................$291,854 $257,218 $239,235 $219,660 $194,317
========= ========= ========= ========= =========
Capitalization and Liabilities
Common Stock Equity...................... $97,149 $92,645 $87,455 $71,942 $69,459
Redeemable Cumulative Preferred Stock.... 9,385 9,575 9,825 10,087 3,374
Long-Term Debt, Less Current Maturities.. 79,800 67,644 56,270 60,626 56,992
Capital Lease Obligation................. 11,029 11,950 12,627 12,797 --
Curent Liabilities....................... 38,879 30,099 32,893 32,399 34,263
Deferred Credits and Other............... 48,441 33,264 29,694 27,358 25,676
Non-Utility Liabilities.................. 7,171 12,041 10,471 4,451 4,553
--------- --------- --------- --------- ---------
Total Capitalization and Liabilities....$291,854 $257,218 $239,235 $219,660 $194,317
========= ========= ========= ========= =========
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 1993
were $2.20 as compared with $2.54 in 1992 and $2.45 in 1991. The 1993
earnings represent an earned return on average common equity of
10.3 percent. In 1992 and 1991, the earned return on equity was 12.2
and 12.5 percent, respectively.
The 1993 decrease in earnings resulted principally from a nearly two-
fold increase in purchases of electricity from independent power
producers mandated by federal and state law. These purchases are priced
at rates set by the Vermont Public Service Board (VPSB) based on the
VPSB calculations of the statewide long-term cost of electricity
acquisitions avoided by such purchases. In 1993, these rates were
substantially higher than the Company's overall cost of electricity.
The principal factors contributing to the earnings results in 1992 were
higher retail revenues, due primarily to a rate increase of 5.6 percent
that took effect in April 1992, and stable energy prices.
Operating Revenues and MWH Sales -- Operating revenues and MWH sales
for the years 1993, 1992 and 1991 consisted of
1993 1992 1991
---- ---- ----
(Dollars in Thousands)
Operating Revenues:
Retail . . . . . . . . . . . . . $ 130,061 $ 126,057 $ 118,021
Sales for Resale . . . . . . . . 14,441 17,258 23,663
Other . . . . . . . . . . . . . 2,751 1,925 1,871
---------- ---------- ----------
Total Operating Revenues . . . . . $ 147,253 $ 145,240 $ 143,555
========== ========== ==========
Megawatthour Sales:
Retail . . . . . . . . . . . . . 1,688,803 1,692,179 1,645,387
Sales for Resale . . . . . . . . 331,875 375,894 545,031
--------- --------- ---------
Total Megawatthour Sales . . . . . 2,020,678 2,068,073 2,190,418
========= ========= =========
Average Number of Customers:
Residential . . . . . . . . . . 67,994 67,201 66,406
Commercial & Industrial . . . . 11,472 11,269 11,239
Other . . . . . . . . . . . . . 74 73 71
------ ------ ------
Total Customers . . . . . . . . . . 79,540 78,543 77,716
====== ====== ======
Differences in operating revenues were due to changes in the following:
1992 1991
to to
1993 1992
---- ----
(In Thousands)
Operating Revenues:
Retail Rates . . . . . . . . . . . . . . . $4,269 $4,499
Retail Sales Volume . . . . . . . . . . . (265) 3,537
Resales and Other Revenues . . . . . . . . (1,991) (6,351)
------- -------
Increase in Operating Revenues . . . . . . . $2,013 $1,685
======= =======
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 due primarily 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.
In 1992, total electricity sales decreased 5.6 percent due principally
to a reduction in wholesale sales. Total operating revenues increased
1.1 percent in 1992, due primarily to a 5.6 percent rate increase that
was effective in April 1992, and to increased sales of electricity to
retail customers reflecting colder (but normal) temperatures in 1992 and
higher usage by commercial and industrial customers. These factors were
principally responsible for the 6.8 percent rise in retail revenues that
occurred in 1992. Wholesale revenues declined 27.1 percent in 1992 due
principally to the end of a multi-year contract under which the Company
sold electricity to another New England utility, the sluggish economy,
and the availability of inexpensive, excess power 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 13.6, 13.8 and
13.0 percent of the Company's operating revenues in 1993, 1992 and 1991,
respectively. No other retail customer accounted for more than
one percent of the Company's revenue.
Power Supply Expenses -- Power supply expenses constituted 59.7 percent,
58.1 percent and 60.7 percent of total operating expenses for the years
ended 1993, 1992 and 1991, respectively. These expenses increased by
$4.1 million in 1993 (5.5 percent), and decreased by $3.4 million
(4.4 percent) in 1992.
Power supply expenses increased in 1993 due primarily to a nearly
twofold increase in purchases of electricity from independent power
producers mandated by federal and state law. The average cost per
kilowatthour of such electricity is substantially greater than the
Company's embedded cost of electricity.
The decrease in power supply expenses in 1992 was principally the result
of lower fuel prices, abundant and inexpensive opportunity purchases,
reduced levels of wholesale electricity sales and favorable changes in
the Company's power purchase contracts with Hydro-Quebec.
Other Operating Expenses -- Other operating expenses were virtually
unchanged in 1993 from 1992.
Higher pension and postretirement health care benefit costs and
increased regulatory commission expenses resulted in an 8.2 percent
increase in other operating expenses in 1992.
Transmission Expenses -- The Company's restructuring of a series of
transmission contracts produced a 3.0 percent decrease in transmission
expenses in 1993.
Transmission expenses decreased 4.8 percent in 1992 for the same reason.
Maintenance Expenses -- Maintenance expenses decreased 7.3 percent in
1993 due principally to a scheduled increase in activity in various
capital projects that had the effect of reducing activity by Company
employees on maintenance projects.
Maintenance expenses increased 8.1 percent in 1992 due principally to
scheduled increases in tree trimming expenses and hydroelectric
generating facilities maintenance.
Depreciation and Amortization -- Depreciation and amortization expenses
increased 6.3 percent in 1993, reflecting continuing additions to the
Company's distribution facilities.
Depreciation and amortization expenses increased 14.5 percent in 1992,
reflecting continuing additions to the Company's distribution facilities
and the amortization of costs of conservation programs.
Income Taxes -- The effective federal tax rates for the years 1993, 1992
and 1991 were 28.9 percent, 28.8 percent and 28.5 percent, respectively.
The various effects and components of the income tax provisions are
detailed in Note G of the Notes to Financial Statements.
Other Income -- Other income increased 16.6 percent in 1993 due
primarily to an increase in earnings of the Company's wholly owned
subsidiary, Mountain Energy, Inc., and to the VPSB's disallowance in the
1992 retail rate case of approximately $400,000 in construction costs.
Diminished equity in earnings of affiliates and non-utility operations,
primarily attributable to operating losses sustained by the propane
subsidiary, was responsible for a 20.9 percent decrease in other income
in 1992, compared to the previous year.
Interest Charges -- Interest charges were virtually unchanged in 1993
from 1992.
A 67.2 percent decrease in short-term debt interest expense, due to both
lower interest rates and a reduction in short-term borrowings, was
partially offset by an increase in long-term debt expense resulting in
an overall decrease of 2.9 percent in interest charges in 1992.
Dividends on Preferred Stock -- 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.
Dividends on preferred stock decreased 2.5 percent in 1992 due primarily
to the repurchase of preferred stock by the Company in 1991 of the same
class and quantity.
Future Outlook -- The Company continues to implement aggressive
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
1.0 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 recently enacted 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, transm