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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, transmission and
distribution facilities. The Company must meet various land, water, air
and aesthetic requirements as administered by local, state and federal
regulatory agencies. The Company maintains an environmental compliance
and monitoring program that includes employee training, regular
inspection of Company facilities, research and development projects,
waste handling and spill prevention procedures and other activities.
Subject to the results of developments discussed in Note I.1 of Notes to
Consolidated Financial Statements concerning the Pine Street Marsh site
in Burlington, Vermont, the Company believes that it is in substantial
compliance with such requirements, and no material complaints concerning
compliance by the Company with present environmental protection
regulations are outstanding.
During 1991, the Company incurred approximately $400,000 in costs
associated with the Pine Street Marsh site for technical consultants and
legal assistance in connection with the United States Environmental
Protection Agency's (EPA) enforcement actions at the site and insurance
litigation. In its 1991 rate increase proceeding, the Company, for the
first time, sought to recover costs associated with the Pine Street
Marsh site in retail rates. The Department of Public Service and the
Company entered into an agreement providing that the Company was
entitled to recover all such costs incurred in 1991. The agreement
provided that such rate recovery is not intended to serve as a precedent
for retail ratemaking treatment of future costs incurred by the Company
in connection with the Pine Street Marsh site. The Company's rates
approved by the VPSB on April 2, 1992, reflected the 1991 Pine Street
related expenditures referred to above. From January 1, 1992 through
July 31, 1993, the Company incurred approximately $4.2 million in such
costs associated with the Pine Street Marsh site and insurance
litigation. In its 1993 rate proceeding, the Company sought to recover
these costs in retail rates. The Company and the other parties to the
rate proceeding entered into an agreement providing that the Company was
entitled to recover all such costs incurred in the January 1, 1992
through July 31, 1993 period. The agreement provided that such rate
recovery is not intended to serve as a precedent for retail ratemaking
of future costs incurred by the Company in connection with the Pine
Street Marsh site. This agreement, which is a part of an overall
2.9 percent rate increase settlement reached by the parties, is pending
before the VPSB.
As of December 31, 1993, the Company has reserved approximately $680,000
for costs attributable to the site, other than those costs that are the
subject of the two 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, of which $4.2 million is the subject of the agreement that
is a part of the settlement of the Company's 1993 rate proceeding
referred to above.
As is more fully set forth in Note I.1 of Notes to Consolidated
Financial Statements, the Company is unable to predict at this time the
magnitude of liability that may be imposed on it resulting from
potential claims for the cost of studies undertaken by the EPA or
performance of any remedial action in connection with the Pine Street
Marsh site. The Company is one of several parties that the EPA has
identified as potentially responsible for the cost of studying and
remedying the results of releases of allegedly hazardous substances at
the site. To the degree that it is held liable for such claims, the
Company will pursue claims against other responsible parties seeking to
ensure that they contribute appropriately to reimburse the Company for
any costs incurred.
In December 1991, the Company brought suit against several previous
insurers seeking recovery of all past costs and indemnity against future
liabilities associated with the environmental problems at the site. The
parties to the action are engaged in discovery and motions practice.
The Company has reached a confidential settlement with one of the
defendants, which 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 EPA first notified the Company that
it might be a potentially responsible party at the Pine Street site.
LIQUIDITY AND CAPITAL RESOURCES
Construction -- The Company's capital requirements result from the need
to construct facilities or to invest in programs to meet anticipated
customer demand for electric service. The policy of the Company is to
increase diversification of its power supply and other resources through
various means, including power purchase and sales arrangements and
relying on sources that represent relatively small additions to the
Company's mix to satisfy customer requirements. This permits the
Company to meet its financing needs in a flexible, orderly manner.
Planned expenditures over the next five years will be primarily for
distribution and conservation projects.
Capital expenditures over the past three years and forecasted for the
next five years are as follows:
Total Net
Actual Generation Transmission Distribution Conservation Other Expenditures
(Dollars in thousands and net of AFUDC and Customer Advances For Construction)
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
Other Cash Requirements -- In its January 1991 rate order, the VPSB
required that the Company set up a special trust account for monies
currently accrued for postretirement health care benefits. This fund
totaled $2.1 million at December 31, 1993, and $3.3 million at January
31, 1994. In 1994, the Company may devote $1 million to $4 million to
unregulated investments.
Insurance Settlement -- In January 1993, the Company settled a long-
disputed claim with a former medical benefits insurance carrier relating
to overcharged premiums dating back to 1984, resulting in an agreement
under which the carrier paid the Company $360,000. The Company received
this payment in the first quarter of 1993.
Rates -- On October 1, 1993, the Company filed a request with the VPSB
to increase retail rates by 8.6 percent. 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 EPA's RI/FS and
proposed remedy at the Pine Street Marsh site and with the Company's
litigation against its previous insurers seeking recovery of past costs
incurred and indemnity against future liabilities in connection with the
site. On January 28, 1994, the Company and the other parties in the
proceeding reached a settlement agreement providing for a 2.9 percent
retail rate increase effective June 15, 1994, and a target return on
equity for utility operations of 10.5 percent. The settlement agreement
also provided for the Company's recovery in rates of $4.2 million in
costs associated with the Pine Street Marsh site, as described herein
above. The agreement must be reviewed and approved by the VPSB before
it can take effect.
Financing and Capitalization -- For the period 1991 through 1993,
internally generated funds, after payment of dividends, provided
approximately 47 percent of total capital requirements for construction,
sinking funds and other requirements. The Company anticipates that for
the period 1994-1998, internally generated funds will provide
approximately 67 percent of total capital requirements.
In November of 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 rate of 6.7 percent and 5.71 percent, respectively. The
proceeds from the sale were used to refinance existing debt, to finance
construction and conservation expenditures, and for other corporate
purposes.
At December 31, 1993, the Company's capitalization consisted of
51.6 percent common equity, 43.4 percent long-term debt and 5.0 percent
preferred equity. The Company has a comprehensive capital plan to
maintain approximately this balance of common equity, long-term debt and
preferred equity.
The Company anticipates issuing additional shares of its common stock in
1994. The Company has not determined the date or the amount of the
stock issuance.
The Company's first mortgage securities are rated "A-" by Standard &
Poor's. This rating was affirmed in November of 1993 by Standard &
Poor's following its annual review of the Company. Standard & Poor's
changed its "outlook" of the Company from "stable" to "negative,"
reflecting Standard & Poor's assessment that the electric utility
industry is becoming increasingly more competitive. The Company's first
mortgage securities are rated "A" by Duff & Phelps.
See Note F of Notes to Consolidated Financial Statements for a
discussion of bank lines of credit available to the Company.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Page
Financial Statements
Statements of Consolidated Income
For the Years Ended December 31, 1993, 1992 and 1991 39
Consolidated Statements of Cash Flows for the
Years Ended December 31, 1993, 1992 and 1991 40
Consolidated Balance Sheets as of
December 31, 1993 and 1992 41-42
Consolidated Capitalization data as of
December 31, 1993 and 1992 43
Notes to Consolidated Financial Statements 44-63
Report of Independent Public Accountants 64
Schedules
For the Years Ended December 31, 1993, 1992 and 1991:
V Property, Plant and Equipment 65-67
VI Accumulated Depreciation and Amortization
of Property, Plant and Equipment 68
VIII Valuation and Qualifying Accounts and Reserves 69
IX Short-Term Borrowings 70
X Supplementary Income Statement Information 71
All other schedules are omitted as they are either not
required, not applicable or the information is
otherwise provided.
Consents and Reports of Independent
Public Accountants
KPMG Peat Marwick 109
Arthur Andersen & Co. 110-111
STATEMENTS OF CONSOLIDATED INCOME
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1993 1992 1991
----------------- --------------- ---------------
(In thousands except amounts per share)
Operating Revenues (Note A)..................................... $147,253 $145,240 $143,555
----------------- --------------- ---------------
Operating Expenses
Power Supply (Notes A, B and K)
Vermont Yankee Nuclear Power Corporation................... 29,785 29,230 27,464
Company-owned generation................................... 3,150 3,804 4,946
Purchases from others...................................... 46,066 41,878 45,951
Other operating............................................... 17,353 17,239 15,934
Transmission (Note J)......................................... 10,775 11,103 11,661
Maintenance................................................... 4,352 4,692 4,340
Depreciation and amortization (Note A)........................ 8,572 8,065 7,046
Taxes other than income....................................... 6,125 5,902 5,677
Income taxes (Note G)......................................... 6,249 6,915 6,022
----------------- --------------- ---------------
Total operating expenses................................... 132,427 128,828 129,041
----------------- --------------- ---------------
Operating Income......................................... 14,826 16,412 14,514
----------------- --------------- ---------------
Other Income
Equity in earnings of affiliates and
non-utility operations (Note B)............................ 2,341 2,178 2,755
Allowance for equity funds used during construction (Note A).. 273 186 225
Other income and deductions, net.............................. 19 (105) (66)
----------------- --------------- ---------------
Total other income.......................................... 2,633 2,259 2,914
----------------- --------------- ---------------
Income before interest charges............................ 17,459 18,671 17,428
----------------- --------------- ---------------
Interest Charges
Long-term debt................................................ 6,539 6,542 6,064
Other......................................................... 646 479 1,039
Allowance for borrowed funds used during
construction (Note A)...................................... (357) (202) (131)
----------------- --------------- ---------------
Total interest charges...................................... 6,828 6,819 6,972
----------------- --------------- ---------------
Net Income...................................................... 10,631 11,852 10,456
Dividends on preferred stock.................................... 811 831 852
----------------- --------------- ---------------
Net Income Applicable to Common Stock........................... $9,820 $11,021 $9,604
================= =============== ===============
Common Stock Data (Notes A and C)
Earnings per share............................................ $2.20 $2.54 $2.45
Cash dividends declared per share............................. $2.11 $2.08 $2.04
Weighted average shares outstanding........................... 4,457 4,345 3,919
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1993 1992 1991
--------- --------- ---------
(In thousands)
Operating Activities:
Net Income........................................................... $10,631 $11,852 $10,456
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization (Note A)........................... 8,572 8,065 7,046
Dividends from associated companies less equity income (Note B).. 254 659 190
Allowance for funds used during construction (Note A)............ (630) (388) (356)
Deferred purchased power costs (Note A).......................... (6,407) (5,347) 104
Amortization of purchased power costs (Note A)................... 3,717 3,825 1,840
Deferred income taxes (Note G)................................... 5,180 3,089 1,474
Amortization of gain on sale of property......................... (53) (53) (53)
Amortization of investment tax credits (Note G).................. (283) (284) (230)
Environmental proceedings costs.................................. (2,472) (2,612) (416)
Changes in:
Special deposits............................................... -- 90 --
Accounts receivable............................................ 2,384 (433) (2,885)
Accrued utility revenues....................................... (538) (368) (16)
Fuel, materials, and supplies.................................. 53 (113) 892
Prepayments and other current assets........................... 1,069 (1,401) (1,050)
Accounts payable............................................... 513 1,521 (573)
Taxes accrued.................................................. (418) (315) 420
Interest accrued............................................... 903 (733) (188)
Other current liabilities...................................... (2,745) 1,175 2,015
Other.......................................................... (2,620) 97 4,433
--------- --------- ---------
Net cash provided by operating activities.......................... 17,110 18,326 23,103
--------- --------- ---------
Investing Activities:
Construction expenditures.......................................... (15,949) (15,327) (19,475)
Conservation expenditures.......................................... (7,418) (3,006) (1,958)
Investment in nonutility property.................................. (5,950) (282) (2,305)
Special fund for post-retirement benefits (Note A)................. (601) (56) (1,463)
--------- --------- ---------
Net cash used in investing activities............................ (29,918) (18,671) (25,201)
--------- --------- ---------
Financing Activities:
Reduction in preferred stock (Note D).............................. (190) (250) (262)
Issuance of common stock (Note C).................................. 4,077 3,195 13,989
Short-term debt, net (Note F)...................................... 7,402 (2,093) 2,302
Sale of first mortgage bonds (Note E).............................. 20,000 17,000 --
Reduction in long-term debt (Note E)............................... (8,530) (7,246) (5,116)
Cash dividends..................................................... (10,204) (9,857) (8,837)
Reacquired common stock............................................ -- -- (96)
--------- --------- ---------
Net cash provided by financing activities........................ 12,555 749 1,980
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... (253) 404 (118)
Cash at beginning of year.......................................... 480 76 194
--------- --------- ---------
Cash at End of Year.................................................... $227 $480 $76
========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION December 31
1993 1992
--------- ---------
(In thousands)
ASSETS
Electric Utility
Utility Plant (Notes A, E and I)
Utility plant, at original cost....................$214,977 $201,643
Less accumulated depreciation...................... 64,226 58,516
--------- ---------
Net utility plant................................ 150,751 143,127
Property under capital lease (Note J).............. 11,029 11,950
Construction work in progress...................... 9,631 9,646
--------- ---------
Total utility plant, net......................... 171,411 164,723
--------- ---------
Other Investments
Associated companies at equity (Notes A,B and I)... 16,886 17,139
Other investments (Note A)......................... 5,642 4,561
--------- ---------
Total other investments.......................... 22,528 21,700
--------- ---------
Current Assets
Cash............................................... 50 200
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 14,814 17,198
Accrued utility revenues (Note A).................. 6,138 5,600
Fuel, materials and supplies, at average cost...... 2,841 2,894
Prepayments........................................ 1,984 1,866
Other.............................................. 1,117 309
--------- ---------
Total current assets............................. 26,944 28,067
--------- ---------
Deferred Charges
Future revenue due to income taxes................. 4,179 --
Unfunded future federal income taxes............... 4,590 --
Demand side management programs................... 12,809 6,429
Environmental proceedings costs.................... 5,356 2,969
Purchased power costs.............................. 4,134 1,445
Other.............................................. 11,277 8,169
--------- ---------
Total deferred charges........................... 42,345 19,012
--------- ---------
Non-Utility
Cash and cash equivalents.......................... 177 280
Other current assets............................... 3,479 4,736
Property and equipment............................. 11,331 10,589
Intangible assets.................................. 3,484 4,032
Other assets....................................... 10,155 4,079
--------- ---------
Total non-utility assets......................... 28,626 23,716
--------- ---------
Total Assets...........................................$291,854 $257,218
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION December 31
1993 1992
--------- ---------
(In thousands)
CAPITALIZATION AND LIABILITIES
Electric Utility
Capitalization (See Capitalization Data)
Common Stock Equity (Note C)
Common stock..................................... $15,120 $14,712
Additional paid-in capital....................... 57,178 53,510
Retained Earnings................................ 25,229 24,801
Treasury stock, at cost.......................... (378) (378)
--------- ---------
Total common stock equity...................... 97,149 92,645
Redeemable cumulative preferred stock (Note D)..... 9,385 9,575
Long-term debt, less current maturities (Note E)... 79,800 67,644
--------- ---------
Total capitalization........................... 186,334 169,864
--------- ---------
Capital lease obligation (Note J)...................... 11,029 11,950
Current Liabilities
Current maturuties of long-term debt............... 1,800 2,486
Short-term debt (Note F)........................... 19,015 11,614
Accounts payable, trade, and accrued liabilities... 8,373 7,701
Accounts payable to associated companies (Note B).. 4,302 4,461
Dividends declared................................. 199 203
Customer deposits.................................. 1,197 1,112
Taxes Accrued...................................... 397 815
Interest accrued................................... 2,070 1,167
Other.............................................. 1,526 540
--------- ---------
Total current liabilities...................... 38,879 30,099
--------- ---------
Deferred Credits
Accumulated deferred income taxes (Note G)......... 20,683 15,504
Unamortized investment tax credits (Note G)........ 5,672 5,955
Future revenue reduction due to income taxes....... 4,366 --
Unfunded future federal income taxes............... 4,179 --
Other (Note A)..................................... 13,541 11,805
--------- ---------
Total deferred credits......................... 48,441 33,264
--------- ---------
Non-Utility
Current liabilities................................ 666 3,524
Other liabilities.................................. 6,505 8,517
--------- ---------
Total non-utility liabilities.................. 7,171 12,041
--------- ---------
Total Capitalization and Liabilities...................$291,854 $257,218
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION December 31
Issued and Outstanding
CAPITAL STOCK Authorized 1993 1992 1993 1992
----------- ---------- ---------- --------- ---------
(In Thousands)
Common Stock,$3.33 1/3 par value (Note C)..................10,000,000 4,536,042 4,413,537 $15,120 $14,712
========= =========
-----------------------------------------------------------------------------------------------------------------
Authorized Outstanding
and Issued 1993 1992 1993 1992
----------- ---------- ---------- --------- ---------
(In thousands)
Redeemable Cumulative Preferred Stock
$100 par value (Note D)
4.75%,Class B, redeemable at
$101 per share........................................ 15,000 3,900 4,200 $390 $420
7%,Class C, redeemable at
$101 per share........................................ 15,000 5,550 5,550 555 555
9.375%,Class D,Series 1,
redeemable at $101 per share.......................... 40,000 14,400 16,000 1,440 1,600
8.625%,Class D,Series 3,
redeemable at $105.751 per share...................... 70,000 70,000 70,000 7,000 7,000
--------- ---------
Total Preferred Stock...................................... $9,385 $9,575
========= =========
LONG-TERM DEBT (Note E) 1993 1992
--------- ---------
(In thousands)
First Mortgage Bonds
5 1/8% Series due 1996.............................................................................. $3,000 $3,000
7% Series due 1998.................................................................................. 3,000 3,000
8 5/8% Series due 1999.............................................................................. -- 600
9 1/8% Series due 2003 - Cash sinking fund,$100,000
annually.......................................................................................... -- 3,400
10.7% Series due 2000 - Cash sinking fund,$1,800,000
annually.......................................................................................... 12,600 14,400
10.0% Series due 2004 - Cash sinking fund,commences 1995............................................ 17,000 17,000
9.64% Series due 2020............................................................................... 9,000 9,000
8.65% Series due 2022 - Cash sinking fund,commences 2012............................................ 13,000 13,000
6.84% Series due 1997 - Cash sinking fund,commences 1995............................................ 4,000 4,000
5.71% Series due 2000............................................................................... 5,000 --
6.7% series due 2018................................................................................ 15,000 --
Debentures
8 7/8% due 1994 - Cash sinking fund,$86,000 annually................................................ -- 980
12 5/8% due 1998 - Cash sinking fund,$500,000 annually.............................................. -- 1,750
--------- ---------
Total Long-term Debt Outstanding...................................................................... 81,600 70,130
Less Current Maturities (due within one year)....................................................... 1,800 2,486
--------- ---------
Total Long-term Debt, Net............................................................................. $79,800 $67,644
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
A. Significant Accounting Policies
1. System of Accounts
The Company's accounting records, rates, operations and certain other
practices of its electric utility business are subject to the regulatory
authority of the Federal Energy Regulatory Commission (FERC) and the
Vermont Public Service Board (VPSB).
2. Basis of Presentation
Included in equity in earnings of affiliates and non-utility operations
in the Other Income section of the Statements of Consolidated Income are
the results of operations of the Company's rental water heater program,
which is not regulated by the VPSB, and four of the Company's wholly
owned subsidiaries, Green Mountain Propane Gas Company, Mountain Energy,
Inc., GMP Real Estate Corporation, and Lease-Elec, Inc. (also unregulated).
Summarized financial information is as follows:
For the years ended December 31
1993 1992
---- ----
(In thousands)
Revenue . . . . . . . . . . . . . . . $11,487 $11,146
Expense. . . . . . . . . . . . . . . . 11,527 11,409
--------- ---------
Net Income (Loss) . . . . . . . . . . ($ 40) ($ 263)
========= =========
The Company carries its investments in various associated companies --
Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Vermont
Electric Power Company, Inc. (VELCO), New England Hydro-Transmission
Corporation, and New England Hydro-Transmission Electric Company -- at
equity.
3. Statements of Cash Flows
The following amounts of interest (net of amounts capitalized) and
income taxes were paid for the years ending December 31:
1993 1992 1991
---- ---- ----
(In thousands)
Interest . . . . . . . . . . . . . . . . $6,206 $7,683 $7,254
Income Taxes (Net of refunds) . . . . . $1,920 $3,511 $3,695
4. Utility Plant
The cost of plant additions includes all construction-related direct
labor and materials, as well as indirect construction costs including
the cost of money (Allowance for Funds Used During Construction or
AFUDC). The costs of renewals and betterments of property units are
capitalized; the costs of maintenance, repairs and replacements of minor
property items are charged to maintenance expense; the costs of units of
property removed from service, net of removal costs and salvage, are
charged to accumulated depreciation.
AFUDC represents the composite interest and equity costs of capital
funds used to finance construction. AFUDC, a non-cash item, is
recognized as a cost of "Utility Plant" with offsetting credits to
"Other Income" and "Interest Charges." This is in accordance with
established regulatory ratemaking practice under which a utility is
permitted a return on, and the recovery of, these capital costs through
their ultimate inclusion in rate base and in the provisions for
depreciation.
When Construction Work in Progress (CWIP) is included in rate base and
the utility is recovering the cost of financing this construction
through rates, no AFUDC is included in the cost of such construction.
The VPSB generally allows CWIP in rate base for short-term construction
projects and projects for which completion is imminent.
AFUDC, which is compounded semi-annually, was calculated using weighted
average rates of 7.2 percent, 8.9 percent and 7.6 percent for the years
1993, 1992 and 1991, respectively.
5. Depreciation
The Company provides for depreciation on the straight-line method based
on the cost and estimated remaining service life of the depreciable
property outstanding at the beginning of the year.
The annual depreciation provision was approximately 3.6 percent, 3.5
percent and 3.5 percent of total depreciable property at the beginning
of the year for 1993, 1992 and 1991, respectively.
6. Operating Revenues
Operating revenues consist principally of sales of electric energy. The
Company records accrued utility revenues, based on estimates of electric
service rendered and not billed at the end of an accounting period, in
order to match revenues with related costs.
7. Deferred Charges
In a manner consistent with authorized or expected ratemaking treatment,
the Company defers and amortizes certain replacement power, maintenance
and other costs associated with the Vermont Yankee nuclear plant. In
addition, the Company accrues other replacement power expenses to
reflect more accurately its cost of service to better match revenues and
expenses consistent with regulatory treatment.
At December 31, 1993 deferred charges totaled $42.3 million, consisting
of charges for conservation programs, response and litigation costs
attributable to the Pine Street Marsh site discussed in Note I.1, repair
costs for and relicensing of the Essex hydroelectric facility, repair
costs for the Vergennes hydroelectric facility, Hydro-Quebec power
contract negotiations and support charges, regulatory deferrals of storm
damages, PCB clean-up, regulatory deferrals of rights-of-way
maintenance, costs associated with the 1993 scheduled Vermont Yankee
outage, postretirement health care costs, and various other projects and
deferrals.
8. Earnings Per Share
Earnings per share are based upon the weighted average number of shares
of common stock outstanding during each year.
9. Major Customers
The Company had one major retail customer, IBM, metered at two
locations, that accounted for 13.6, 13.8 and 13.0 percent of operating
revenues in 1993, 1992 and 1991, respectively.
10. Pension and Retirement Plans
The Company has a defined benefit pension plan covering substantially
all of its employees. The retirement benefits are based on the
employees' level of compensation and length of service. The Company's
policy is to fund all pension costs accrued. The Company records annual
expense in accordance with methods approved in the rate-setting process.
Net pension costs reflect the following components and assumptions:
1993 1992 1991
---- ---- ----
(Dollars in thousands)
Service cost-benefits earned during the period . $ 748 $ 676 $ 621
Interest cost on projected benefit obligations . 1,593 1,466 1,275
Actual (return) loss on plan assets . . . . . . . (3,107) (1,743) (3,109)
Net amortization and deferral . . . . . . . . . . 1,141 (77) 1,440
Adjustment due to actions of regulator . . . . . 337 430 153
------ ------- ------
Net periodic pension cost funded and recognized . $ 712 $ 752 $ 380
====== ======= ======
Assumptions used to determine pension costs in 1993, 1992 and 1991 were:
Discount rate . . . . . . . . . . . . . . . . 8.0% 8.0% 8.0%
Rate of increase in future compensation levels 6.0% 6.0% 6.0%
Expected long-term rate of return on assets . 9.0% 9.0% 9.0%
The following table sets forth the Plan's funded status as of December 31:
1993 1992 1991
---- ---- ----
(In thousands)
Actuarial present value of benefit obligations:
Accumulated benefit obligations,
including vested benefits of $16,825,
$15,100 and $12,567, respectively . . . . . ($17,105) ($15,262) ($12,704)
========= ========= =========
Projected benefit obligations for
service rendered to date . . . . . . . . . ($21,002) ($19,235) ($16,563)
Plan assets at fair value . . . . . . . . . . . 23,981 21,167 19,675
------- ------- -------
Assets in excess of projected
benefit obligations . . . . . . . . . . . . . 2,979 1,932 3,112
Unrecognized net loss (gain) from past
experience different from that assumed . . . (272) 559 399
Prior service cost not yet recognized in net
periodic pension cost . . . . . . . . . . . . 1,885 2,028 842
Unrecognized net asset at transition
being recognized over 16.47 years . . . . . . (2,162) (2,391) (2,619)
Adjustment due to actions of regulator . . . . . (2,430) (2,128) (1,734)
------ ------ -----
Prepaid pension cost included in other assets . $ --- $ --- $ ---
====== ====== ======
The Company has evaluated the effect of a reduction in the discount rate
and compensation trend rate and has concluded that the net effect of
such changes is insignificant.
The plan assets consist primarily of cash equivalent funds, fixed income
securities and listed equity securities.
The Company also has a supplemental pension plan for certain employees.
Pension costs for the years ended December 31, 1993, 1992 and 1991 were
$384,000, $377,000 and $352,000, respectively, under this plan. This
plan is supported through insurance contracts.
11. Fair Value of Financial Instruments
If the first mortgage bonds, debentures, and preferred stock outstanding
at December 31, 1993 were refinanced using new issue debt rates of
interest, which are generally lower than the Company's outstanding
rates, the present value of those obligations would differ from the
amounts outstanding on the December 31, 1993 balance sheet by
nine percent. The Company does not anticipate a refinancing; however,
if such an event were to occur, there would be no gain or loss, inasmuch
as under established regulatory precedent, any such difference would be
reflected in rates and have no effect upon income.
12. Postretirement Health Care Benefits
The Company provides certain health care benefits for retired employees
and their dependents. Employees become eligible for these benefits if
they reach normal retirement age while working for the Company.
On January 1, 1993, the Company adopted the standard on accounting for
postretirement health care and other benefits, SFAS 106, which requires
the Company to use accrual accounting for postretirement benefits other
than pensions. Prior to 1993, the Company recognized the cost of
postretirement health care benefits by recording an amount equivalent to
that which had been allowed in rates. The difference between total cost
and claims paid was accrued on the balance sheet.
In its January 4, 1991 rate order, the VPSB required the Company to
establish a fund in which the Company will accumulate monies for
postretirement health care expenses. At December 31, 1993, the Company
had deposited $2.1 million in the investment fund, which is included in
other investments in the accompanying balance sheet. In January 1994,
the Company fully funded its accrued postretirement benefit cost of
$3.3 million. In order to maximize the tax deductible contributions
that are allowed under IRS regulations, the Company has amended its
pension plan and established separate VEBA trusts for its union and
nonunion employees.
The Company will seek and expects to receive rate recovery for all
amounts expended for postretirement health care benefits.
Net postretirement benefits costs for 1993 reflect the following
components and assumptions:
(In thousands)
Accumulated postretirement benefit obligation:
Current retirees . . . . . . . . . . . . . . . . . ($ 3,628)
Participants currently eligible . . . . . . . . . (2,288)
All others . . . . . . . . . . . . . . . . . . . . (4,789)
--------
Total accumulated postretirement benefit obligation . (10,705)
Plan assets at fair value . . . . . . . . . . . . . . 0
-------
Accumulated postretirement benefit obligation in excess
of plan assets . . . . . . . . . . . . . . . . . . (10,705)
Unrecognized transition obligation . . . . . . . . . 6,845
Unrecognized net loss (gain) . . . . . . . . . . . . 538
--------
Accrued postretirement benefit cost . . . . . . . . . $3,322
========
Net periodic postretirement benefit cost for 1993 includes the following
components:
(In thousands)
Service cost . . . . . . . . . . . . . . . . . . . . $ 438
Interest cost . . . . . . . . . . . . . . . . . . . 940
Amortization and deferral . . . . . . . . . . . . . 380
--------
Total net periodic postretirement benefit cost . . . $ 1,758
========
For measurement purposes, a 14.25 percent annual rate of increase in the
per capita cost of covered benefits was assumed for 1993; the rate was
assumed to decrease gradually to 5.5 percent by the year 2000 and remain
at that level thereafter. The health care cost trend rate assumption
has a significant effect on the amounts reported. For example,
increasing the assumed health care cost trend rate by one percentage
point would increase the accumulated postretirement benefit obligation
as of December 31, 1993 by $1.7 million and the aggregate of the service
and interest components of net periodic postretirement benefit cost for
the year ended December 31, 1993 by $241,000. The weighted average
discount rate used in determining the accumulated postretirement benefit
obligation was 8 percent at December 31, 1993.
The Company has evaluated the effect of a reduction in the discount rate
and medical care trend rate and has concluded that the net effect of
such changes is insignificant.
13. Deferred Credits
The Company has deferred credits and other long-term liabilities of
$22.1 million, consisting of operating lease equalization, general
liabilities and damages reserves and accruals for employee benefits.
B. Investments in Associated Companies
The Company accounts for investments in the following companies by the
equity method:
Investment in Equity
Percent Ownership December 31,
at December 31, 1993 1993 1992
-------------------- ---- ----
(In thousands)
VELCO - Common . . . . . . . . . 29.5% $ 1,816 $ 1,818
- Preferred . . . . . . . 30.0% 1,572 1,736
------- ------
Total VELCO . . . . . . . . . . 3,388 3,554
Vermont Yankee - Common . . . . 17.9% 9,745 9,731
New England Hydro-Transmission -
Common . . . . . . . . . . 3.18% 1,408 1,489
New England Hydro-Transmission
Electric - Common . . . . . 3.18% 2,345 2,396
-------- --------
$16,886 $17,170
======= ========
Undistributed earnings in associated companies totaled $1,140,000 at
December 31, 1993.
VELCO
VELCO is a corporation engaged in the transmission of electric power
within the state of Vermont. VELCO has entered into transmission
agreements with the State of Vermont and other electric utilities, and
under these agreements bills all costs, including interest on debt and a
fixed return on equity, to the State and others using the system. The
Company's purchases of transmission services from VELCO were
$8.0 million, $7.8 million and $7.8 million for the years 1993, 1992 and
1991, respectively. Pursuant to VELCO's Amended Articles of
Association, the Company is entitled to approximately 30 percent of the
dividends distributed by VELCO. The Company has recorded its equity in
earnings on this basis and also is obligated to provide its
proportionate share of the equity capital requirements of VELCO through
continuing purchases of its common stock, if necessary.
Summarized financial information for VELCO is as follows:
December 31,
---------------------------
1993 1992 1991
---- ---- ----
(In thousands)
Company's equity in net income . . . . . . . $ 406 $ 448 $ 466
======= ======= ======
Total assets . . . . . . . . . . . . . . . . $70,199 $70,821 $69,949
Less:
Liabilities and long-term debt . . . . . 58,806 58,889 57,395
------- ------- -------
Net assets . . . . . . . . . . . . . . . . . $11,393 $11,932 $12,554
======= ======= =======
Company's equity in net assets . . . . . . . $ 3,388 $ 3,554 $ 3,738
======= ======= =======
Vermont Yankee
The Company is responsible for 17.3 percent of Vermont Yankee's expenses of
operations, including costs of equity capital and estimated costs of
decommissioning, and is entitled to a similar share of the power output of
the nuclear plant, which has a net capacity of 520 megawatts. Vermont
Yankee's current estimate of decommissioning is approximately $253 million
in 1993 dollars, of which $99 million has been funded. At December 31,
1993, the Company's portion of the net unfunded liability was $27 million,
which it expects will be recovered through rates over Vermont Yankee's
remaining operating life. As a sponsor of Vermont Yankee, the Company also
is obligated to provide 20 percent of capital requirements not obtained by
outside sources. During 1993, the Company incurred $27.7 million in Vermont
Yankee annual capacity charges, which included $1.6 million for interest
charges. The Company's share of Vermont Yankee's long-term debt at December
31, 1993 was $13.8 million.
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $9.4 billion. Any liability beyond
$9.4 billion is indemnified under an agreement with the NRC. The first
$200 million of liability coverage is the maximum provided by private
insurance. The Secondary Financial Protection program is a retrospective
insurance plan providing additional coverage up to $9.2 billion per incident
by assessing retrospective premiums of $79.3 million 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 million per incident per
nuclear unit in any one year. The maximum assessment is to be adjusted at
least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities prior
to January 1, 1988, for bodily injury claims. Vermont Yankee has purchased
a master worker insurance policy with limits of $200 million with one
automatic reinstatement of policy limits to cover workers employed on or
after January 1, 1988. Vermont Yankee's estimated contingent liability for
a retrospective premium on the master worker policy as of December 1993 is
$3.1 million. The secondary financial protection program referenced above
provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL II) 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 $5.8 million at the time of the first loss and
$12.3 million 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.
Summarized financial information for Vermont Yankee is as follows:
December 31,
1993 1992 1991
---- ---- ----
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . . $180,145 $175,919 $151,722
Net income applicable to common stock . 7,793 7,921 8,490
Company's equity in net income . . . . . 1,425 1,415 1,516
Total assets . . . . . . . . . . . . . . . $469,770 $438,208 $417,618
Less:
Liabilities and long-term debt . . . . 415,606 383,933 363,354
-------- -------- --------
Net assets . . . . . . . . . . . . . . . . $ 54,164 $ 54,275 $ 54,264
======== ======== ========
Company's equity in net assets . . . . . . $ 9,745 $ 9,731 $ 9,729
======== ======== ========
C. Common Stock Equity
The Company maintains a Dividend Reinvestment and Stock Purchase Plan
(DRIP) under which 394,112 shares were reserved and unissued at December
31, 1993. The Company also funds an Employee Savings and Investment
Plan (ESIP). At December 31, 1993, there were 47,067 shares reserved
and unissued under the ESIP.
In October 1991, the Company issued 429,600 additional shares of common
stock at a price of $28.25 per share. The net proceeds were used to
reduce the Company's outstanding short-term debt, to finance planned
capital additions and to maintain an appropriate capital structure.
In May 1993, the Company amended its Articles of Association increasing
the number of authorized shares of common stock from 6,000,000 to
10,000,000.
Changes in common stock equity for the years ended December 31, 1991,
1992 and 1993 are as follows:
Common Stock Treasury Stock
------------------------ Paid-in Retained ------------------------ Stock
Shares Amount Capital Earnings Shares Amount Equity
------ ------ ------- -------- ------ ------ ------
(Dollars in thousands)
BALANCE, December 31, 1990............... 3,779,623 $12,599 $38,438 $21,187 11,586 ($282) $71,942
Common Stock Issuance:
Public:................................ 429,600 1,432 10,704 12,136
DRIP:.................................. 73,370 245 1,659 1,904
ESIP:.................................. 24,965 83 586 669
Purchase of Treasury Stock............... 4,270 (96) (96)
Net Income............................... 10,456 10,456
Cash Dividends on Capital Stock:
Common Stock -$2.04 per share..... (7,988) (7,988)
Preferred Stock -$4.75 per share..... (24) (24)
-$7.00 per share..... (45) (45)
-$9.375 per share.... (176) (176)
-$8.625 per share.... (604) (604)
Other-Common Stock Issuance Expense...... (719) (719)
------------------------------------------------------------------------------------
BALANCE, December 31, 1991............... 4,307,558 14,359 50,668 22,806 15,856 (378) 87,455
Common Stock Issuance:
DRIP:.................................. 84,637 282 2,251 2,533
ESIP:.................................. 21,342 71 591 662
Net Income............................... 11,852 11,852
Cash Dividends on Capital Stock:
Common Stock -$2.08 per share..... (9,029) (9,029)
Preferred Stock -$4.75 per share..... (22) (22)
-$7.00 per share..... (41) (41)
-$9.375 per share.... (161) (161)
-$8.625 per share.... (604) (604)
------------------------------------------------------------------------------------
BALANCE, December 31, 1992............... 4,413,537 14,712 53,510 24,801 15,856 (378) 92,645
Common Stock Issuance:
DRIP:.................................. 86,974 290 2,586 2,876
ESIP:.................................. 35,531 118 1,082 1,200
Net Income............................... 10,631 10,631
Cash Dividends on Capital Stock:
Common Stock -$2.08 per share..... (9,396) (9,396)
Preferred Stock -$4.75 per share..... (19) (19)
-$7.00 per share..... (38) (38)
-$9.375 per share.... (146) (146)
-$8.625 per share.... (604) (604)
------------------------------------------------------------------------------------
BALANCE, December 31, 1993............... 4,536,042 $15,120 $57,178 $25,229 15,856 ($378) $97,149
====================================================================================
Dividend Restrictions
Certain restrictions on the payment of cash dividends on common stock
are contained in the indentures relating to long-term debt and in the
Restated Articles of Association. Under the most restrictive of such
provisions, $17.9 million of retained earnings were free of restrictions
at December 31, 1993.
The properties of the Company include several hydroelectric projects
licensed under the Federal Power Act, with license expiration dates
ranging from 1993 to 2022. At December 31, 1993, $259,000 of retained
earnings had been appropriated as excess earnings on hydroelectric
projects as required by Section 10(d) of the Federal Power Act.
D. Preferred Stock
The holders of the preferred stock are entitled to specific voting
rights with respect to the placement of restrictions on certain types of
corporate actions. They are also entitled to elect the smallest number
of directors necessary to constitute a majority of the Board of
Directors in the event of preferred stock dividend arrearages equivalent
to or exceeding four quarterly dividends. Similarly, the holders of the
preferred stock are entitled to elect two directors in the event of a
default in any purchase or sinking fund requirements provided for any
class of preferred stock.
Certain classes of preferred stock are subject to annual purchase or
sinking fund requirements. The sinking fund requirements are mandatory.
The purchase fund requirements are mandatory, but holders may elect not
to accept the purchase offer. The redemption or purchase price to
satisfy these requirements may not exceed $100 per share plus accrued
dividends. All shares redeemed or purchased in connection with these
requirements must be canceled and may not be reissued. The annual
purchase and sinking fund requirements for certain classes of preferred
stock are:
Purchased and Sinking Fund
4.75%, Class B . . . . . . . . December 1 450 Shares
7%, Class C . . . . . . . . . December 1 450 Shares
9.375%, Class D, Series 1 . . December 1 1,600 Shares
The 8.625%, Class D, Series 3, preferred stock issued in September 1990,
requires no sinking fund.
Under the Restated Articles of Association relating to Redeemable
Cumulative Preferred Stock, the annual aggregate amounts of purchase and
sinking fund requirements for the next five years are $250,000 for each
of the years 1994 and 1995, and $1,650,000 for the years 1996 - 1998.
All of the classes of preferred stock are redeemable at the option of
the Company or, in the case of voluntary liquidation, at various prices
on various dates. The prices include the par value of the issue plus
any accrued dividends and a redemption premium. The redemption premium
for Class B, C and D, Series 1, is $1.00 per share. The redemption
premium for the Class D, Series 3, is $5.751 per share until September
1, 1994; $4.793 per share from September 1, 1994 to September 1, 1995;
$3.835 per share from September 1, 1995 to September 1, 1996; $2.877 per
share from September 1, 1996 to September 1, 1997; $1.919 per share from
September 1, 1997 to September 1, 1998; and $0.916 per share from
September 1, 1998 to September 1, 1999, after which there is no
redemption premium.
In May 1993, the Company amended its Articles of Association authorizing
a new class of preferred stock, Class E, which may be divided into and
issued in series. No shares of Class E preferred stock were issued as
of December 31, 1993.
E. Long-term Debt
Utility
Substantially all of the property and franchises of the Company are
subject to the lien of the indenture under which first mortgage bonds
have been issued. The annual sinking fund requirements (excluding
amounts that may be satisfied by property additions) and long-term debt
maturities for the next five years are:
Sinking
Funds Maturities Total
------- ---------- -----
(In thousands)
1994 . . . . . . . . . . . . . . $1,800 $ --- $1,800
1995 . . . . . . . . . . . . . . 4,833 --- 4,833
1996 . . . . . . . . . . . . . . 4,833 3,000 7,833
1997 . . . . . . . . . . . . . . 3,500 1,334 4,834
1998 . . . . . . . . . . . . . . 3,500 3,000 6,500
Non-Utility
At December 31, 1993, Green Mountain Propane Gas Company, the Company's
propane subsidiary, had long-term debt of $4,125,000, which was secured
by substantially all of the subsidiary's assets. The annual sinking
fund requirements and maturities for the next three years are:
Sinking
Funds Maturities Total
(In thousands)
1994 . . . . . . . . . . . . . $1,100 $ --- $1,100
1995 . . . . . . . . . . . . . 1,100 --- 1,100
1996 . . . . . . . . . . . . . 550 1,375 1,925
F. Short-term Debt
Utility
At December 31, 1993, the Company had lines of credit with five banks
totaling $30.5 million, with borrowings outstanding of $19.0 million.
Borrowings under these lines of credit are at interest rates ranging
from less than prime to the prime rate. The Company has fee
arrangements on its lines of credit ranging from 1/4 to 3/8 percent and
no compensating balance requirements. These lines of credit are subject
to periodic review and renewal during the year by the various banks.
Non-Utility
At December 31, 1993, Green Mountain Propane Gas Company, the Company's
propane subsidiary, had a line of credit with a bank for $2.0 million,
with borrowings outstanding of $400,000.
G. Income Taxes
Utility
On January 1, 1993, the Company adopted the standard on accounting for
income taxes, SFAS 109, which requires an asset and liability approach
for financial accounting and reporting for income taxes.
When implementing SFAS 109 the Company created additional deferred tax
assets of $4.8 million and deferred tax liabilities of $5.6 million to
give recognition to certain temporary differences previously not
recognized in the Company's financial statements. These additional
deferred taxes will be collected from or returned to ratepayers in
future periods and, accordingly, the Company recognized a regulatory
liability and regulatory asset related to income taxes of $4.8 million
and $5.6 million, respectively. The implementation of SFAS 109 on
January 1, 1993, and the application of SFAS 109 had no material impact
on the Company's results of operations or cash flows in the twelve
months ended December 31, 1993. Additionally, the Company does not
believe SFAS 109 will significantly impact future results of operations
or cash flows based on current ratemaking policy.
The implementation of SFAS 109 also requires the Company to consider now
the future utilization of deferred tax assets. If there is doubt that
the Company will be able to utilize these future tax benefits, it might
be necessary to establish a valuation allowance. The Company has
concluded that it is not necessary at this time to establish a valuation
allowance. The Company has been in a tax-paying position for
approximately ten years and does not foresee future events that will
alter the Company's capacity to utilize these deductions when intended.
The temporary differences which gave rise to the net deferred tax
liability at January 1, 1993 and December 31, 1993, were as follows:
At January 1, At December 31,
1993 1993
------------- ---------------
(In thousands)
Deferred Tax Assets
Contributions in aid of construction. . $ 4,584 $ 5,094
Deferred compensation and
postretirement benefits . . . . . . . 3,046 3,387
Alternative minimum tax credit . . . . 305 749
Excess deferred taxes . . . . . . . . . 2,287 2,188
Unamortized investment tax credits . . 2,528 2,402
Other . . . . . . . . . . . . . . . . . 2,077 1,018
------- -------
$14,827 $14,838
------- -------
Deferred Tax Liabilities
Property-related and other . . . . . . $22,659 $25,090
Demand side management costs . . . . . 2,856 5,841
Unamortized investment tax credit . . . 5,956 5,672
Reversal of previously flowed-through
tax depreciation . . . . . . . . . . 4,865 4,182
AFUDC equity basis adjustment . . . . . 771 726
-------- --------
37,107 41,511
-------- --------
Net accumulated deferred income tax
asset (liability) . . . . . . . . . . ($22,280) ($26,673)
========= =========
The following table reconciles the change in the net accumulated
deferred income tax liability to the deferred income tax expense
included in the income statement for the period:
Net change in deferred income tax liability per above table . . . $4,393
Change in income tax related regulatory assets and liabilities. . 503
Other adjustments . . . . . . . . . . . . . . . . . . . . . . . . 849
------
Deferred income tax expense for the period . . . . . . . . . . . $5,745
======
The components of the provision for income taxes are:
Year Ended December 31,
1993 1992 1991
---- ---- ----
(In thousands)
Current state income taxes . . . . . . . $ 134 $ 796 $ 991
Deferred state income taxes . . . . . . 1,225 716 332
Current federal income taxes . . . . . . 369 3,007 3,730
Deferred federal income taxes . . . . . 4,804 2,678 1,243
Investment tax credits -- net . . . . . (284) (284) (276)
------- ------- --------
Total income taxes . . . . . . . . . . . 6,248 6,913 6,020
Amounts included in "Other income" . . . 1 2 2
------- ------- -------
Income taxes charged to operations . . . $6,249 $6,915 $6,022
======= ======= =======
The following table details the components of the provisions for
deferred federal income taxes:
Year Ended December 31,
1993 1992 1991
---- ---- ----
(In thousands)
Deferred purchase power costs . . . . . $ 904 $ 475 $ (606)
Excess tax depreciation . . . . . . . . 1,300 1,512 1,497
Demand side management . . . . . . . . 1,918 733 584
State tax benefit . . . . . . . . . . . (416) (211) (52)
Contributions in aid of construction . (404) (746) (293)
Supplemental benefit plans . . . . . . (182) (42) (383)
Prepaid property taxes . . . . . . . . --- 8 36
Pine Street . . . . . . . . . . . . . . 817 237 152
Other . . . . . . . . . . . . . . . . . 867 712 308
------- ------- -------
$4,804 $2,678 $1,243
======= ======= =======
Total federal income taxes differ from the amounts computed by applying
the statutory tax rate to income before taxes. The reasons for the
differences are:
Year Ended December 31,
1993 1992 1991
---- ---- ----
(In thousands)
Income before income tax . . . . . . . $16,880 $18,765 $16,476
Federal statutory rate . . . . . . . . 34% 34% 34%
Computed "expected" federal
income taxes . . . . . . . . . . . . $ 5,739 $ 6,380 $ 5,602
Increase (decrease) in taxes
resulting from:
Tax versus book depreciation . . . . 327 357 357
Dividends received and paid credit . (580) (597) (634)
AFUDC - equity funds . . . . . . . . (93) (63) (77)
Amortization of ITC . . . . . . . . (284) (284) (276)
State tax benefit . . . . . . . . . (462) (514) (450)
Excess deferred taxes . . . . . . . (60) (60) (60)
Other . . . . . . . . . . . . . . . 302 182 235
------- ------- -------
Total federal income taxes . . . . . . $4,889 $5,401 $4,697
======= ======= =======
Effective federal income tax rate . . 28.9% 28.8% 28.5%
Non-Utility
The Company's non-utility subsidiaries had accumulated deferred income
taxes of $2.3 million on its balance sheet at December 31, 1993, largely
attributable to property-related transactions.
The components of the provision for income taxes for the non-utility
operations are:
Year Ended December 31,
1993 1992 1991
---- ---- ----
(In thousands)
State income taxes . . . . . . . . . . $ (58) $(104) $ (40)
Federal income taxes . . . . . . . . . (224) (314) (150)
Investment tax credits . . . . . . . . (45) (45) (61)
------ ------ ------
Income taxes charged to operations . . $(327) $(463) $(251)
====== ====== ======
Total federal income taxes differ from the amounts computed by applying
the statutory rate to income before taxes, primarily attributable to
state tax benefits.
The effective federal income tax rates for the non-utility operations
were 34.2 percent, 33.3 percent and 43.1 percent for the years ended
1993, 1992 and 1991, respectively.
H. Quarterly Financial Information (Unaudited)
The following quarterly financial information, in the opinion of
management, includes all adjustments necessary to a fair statement of
results of operations for such periods. Variations between quarters
reflect the seasonal nature of the Company's business and the timing of
rate changes.
1993 Quarter Ended
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Amounts in thousands, except per share)
Operating Revenues . . . . . . $40,751 $33,427 $35,647 $37,428 $147,253
Operating Income . . . . . . . 5,160 2,093 3,075 4,498 14,826
Net Income . . . . . . . . . . 4,302 966 2,051 3,312 10,631
Net Income Applicable to
Common Stock . . . . . . . . 4,099 763 1,848 3,110 9,820
Earnings per Average Share of
Common Stock . . . . . . . . $0.93 $0.17 $0.41 $0.69 $2.20
Weighted Average Number of
Common Shares Outstanding . 4,415 4,442 4,470 4,503 4,457
1992 Quarter Ended
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Amounts in thousands, except per share)
Operating Revenues . . . . . . $39,476 $33,288 $33,911 $38,565 $145,240
Operating Income . . . . . . . 5,636 2,420 3,888 4,468 16,412
Net Income . . . . . . . . . . 4,060 1,585 2,766 3,441 11,852
Net Income Applicable to
Common Stock . . . . . . . . 3,852 1,377 2,558 3,234 11,021
Earnings per Average Share of
Common Stock . . . . . . . . $0.89 $0.32 $0.59 $0.74 $2.54
Weighted Average Number of
Common Shares Outstanding . 4,305 4,329 4,359 4,386 4,345
I. Commitments and Contingencies
1. Environmental Matters
In 1982, the United States Environmental Protection Agency (EPA)
notified the Company that the EPA, pursuant to the Comprehensive
Environmental Response, Compensation and Liability Act of 1980 (CERCLA),
was considering spending public funds to investigate and take corrective
action involving claimed releases of allegedly hazardous substances at a
site identified as the Pine Street Marsh in Burlington, Vermont. On
part of this site was located a manufactured-gas facility owned and
operated by a number of separate enterprises, including the Company,
from the late 19th century to 1967. In its notice, the EPA stated that
the Company may be a "potentially responsible party" (PRP) under CERCLA
from which reimbursement of costs of investigation and of corrective
action may be sought. On February 23, 1988, the Company received a
Special Notice letter from the EPA stating that the letter constituted a
formal demand for reimbursement of costs, including interest thereon,
that were incurred and were expected to be incurred in response to the
environmental problems at the site.
On December 5, 1988, the EPA brought suit against the Company, New
England Electric System, and Vermont Gas Systems, Inc. in the United
States District Court for the District of Vermont seeking reimbursement
for costs it incurred in conducting activities in 1985 to remove
allegedly hazardous substances from the site, and requested a
declaratory judgment that the Company and the other defendants are
liable for all costs that have been incurred since the removal and that
continue to be incurred in responding to claims of releases or
threatened releases from the Maltex Pond Area -- the portion of the site
where the removal action occurred. The complaint specifically alleged
that the EPA expended at least $741,000 during the 1985 removal action
and sought interest on this amount from the date the funds were expended
and costs of litigation, including attorneys' fees. The Company entered
a cross-claim against New England Electric System and third-party claims
against UGI Corporation, Southern Union Corporation, the State of
Vermont, and an individual property owner at the site for recovery of
its response costs and for contribution. Fourth-party defendants
subsequently were joined.
In July 1990, the Company and other parties signed a proposed Consent
Decree settling the removal action litigation. All 14 settling
defendants contributed to the aggregate settlement amount of $945,000.
Individual contributions were treated as confidential under the proposed
Consent Decree.
On December 26, 1990, upon the unopposed motion of the United States,
the Consent Decree was entered by the Court.
During the summer and fall of 1989, the EPA conducted the initial phase
of the Remedial Investigation (RI) and commenced the Feasibility Study
(FS) relating to the site. In the fall of 1990 and in 1991, the EPA
conducted a second phase of RI work and studied the treatability of
soils and groundwater at the site. In the fall of 1991, the EPA
responded favorably to a request from the Company and other PRPs to
participate in informal discussions on the EPA's ongoing investigation
and evaluation of the site, and invited the Company and other interested
parties to share technical information and resources with the EPA that
might assist it in evaluating remedial options. 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
$49.5 million, including 30 years' operation and maintenance costs, with
a net present value of approximately $26.4 million. The EPA's preferred
remedy called for construction of a Containment/Disposal Facility "CDF"
over a portion of the site. The CDF would have consisted of subsurface
vertical barriers and a low permeability cap, with collection trenches
and hydraulic control system to capture groundwater and prevent its
migration outside of the CDF. Collected groundwater would have been
treated and discharged or stored and disposed of off-site. The proposed
remedy also would have required construction of new wetlands to replace
those that would be destroyed by construction of the CDF and a long-term
monitoring program.
On May 15, 1993, the PRP group in which the Company participated
submitted extensive comments to the EPA opposing the proposed remedy.
In response to an earlier request from the EPA, the PRP group also
submitted a detailed analysis of an alternative remedy anticipated to
cost approximately $20 million. In early June, in response to
overwhelming negative comment, the EPA withdrew its proposed remedy and
announced that it would work with all interested parties in developing a
new proposal. Since then, the EPA has established a coordinating
council, with representatives of PRPs, environmental groups, and
government agencies, and presided over by a neutral 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 Vermont Department of Public
Service (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 Vermont Public
Service Board (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 $4.2 million) 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 agreement 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 $4.2 million in costs that are the
subject of the rate case settlement agreement referred to above.
2. Operating Leases
The Company has an operating lease for its corporate headquarters
building and two of its service center buildings, including related real
estate. This lease has a base term of 25 years, ending June 30, 2009,
with renewal options aggregating another 25 years. The annual lease
charges will total $983,000 for each of the years 1994 through 2008 and
$574,000 for 2009. The Company has options to purchase the buildings at
fair market value at the end of the base term and at the end of each
renewal period.
3. Jointly-Owned Facilities
The Company had joint-ownership interests in electric generating and
transmission facilities at December 31, 1993, as follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
(In %) (In MW) (In thousands)
Highgate . . . . . . . . . . 33.8 67.6 $ 9,726 $2,310
McNeil . . . . . . . . . . . 11.0 5.9 $ 8,503 $2,464
Stony Brook (No. 1) . . . . . 8.8 30.2 $10,035 $4,660
Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,372 $1,100
Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 181
(1) Neutral conductor for NEPOOL/Hydro-Quebec Interconnection
The Company's share of expenses for these facilities is reflected in the
Statements of Consolidated Income. Each participant in these facilities
must provide for its own financing.
4. Rate Matters
On October 1, 1993, the Company filed a request with the VPSB to
increase retail rates by 8.6 percent. 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 last two years, and costs incurred in 1992 and through July 31,
1993, associated with the 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 parties to the
rate proceeding reached an agreement resulting in a 2.9 percent retail
rate increase and a return on equity of 10.5 percent, effective June 15,
1994. The agreement must be reviewed and approved by the VPSB.
5. Other Legal Matters
The Company is involved in legal and administrative proceedings in the
normal course of business and does not believe that the ultimate outcome
of these proceedings will have a material effect on the financial
position or the results of operations of the Company.
J. Obligations Under Transmission Interconnection Support Agreement
Agreements executed in 1985 among the Company, VELCO and other NEPOOL
members and Hydro-Quebec, provided for the construction of the second
phase (Phase II) of the interconnection between the New England electric
systems and that of Hydro-Quebec. Phase II expands the Phase I
facilities from 690 megawatts to 2,000 megawatts and provides for
transmission of Hydro-Quebec power from the Phase I terminal in northern
New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II
commenced in 1988 and was completed in late 1990. The Company is
entitled to 3.2 percent of the Phase II power-supply benefits. Total
construction costs for Phase II were approximately $487 million. The
New England participants, including the Company, have contracted to pay
monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs.
As a supporting participant, the Company must make support payments
under thirty-year agreements. These support agreements meet the capital
lease accounting requirements under SFAS 13. At December 31, 1993, the
present value of the Company's obligation is $11.0 million.
Projected future minimum payments under the Phase II support agreements
are as follows:
Year ending December 31,
1994 . . . . . . . . . . . $ 501,311
1995 . . . . . . . . . . . 501,311
1996 . . . . . . . . . . . 501,311
1997 . . . . . . . . . . . 501,311
1998 . . . . . . . . . . . 501,311
Total for 1999-2020 . . . 8,522,270
-----------
$11,028,825
===========
The Phase II portion of the project is owned by New England Hydro-
Transmission Electric Company and New England Hydro-Transmission
Corporation, subsidiaries of New England Electric System, in which
certain of the Phase II participating utilities, including the Company,
own equity interests. The Company holds approximately 3.2 percent of
the equity of the corporations owning the Phase II facilities.
K. Long-Term Power Purchases
1. Unit Purchases
Under long-term contracts with various electric utilities in the region,
the Company is purchasing certain percentages of the electrical output
of production plants constructed and financed by those utilities. Such
contracts obligate the Company to pay certain minimum annual amounts
representing the Company's proportionate share of fixed costs, including
debt service requirements (amounts necessary to retire the principal of
and to pay the interest on the portion of the related long-term debt
ascribed to the Company) whether or not the production plants are
operating. The cost of power obtained under such long-term contracts,
including payments required to be made when a production plant is not
operating, is reflected as "Power Supply Expenses" in the Statements of
Consolidated Income.
Information (including estimates for the Company's portion of certain
minimum costs and ascribed long-term debt) with regard to significant
purchased power contracts of this type in effect during 1993 follows:
Stony Vermont
Merrimack Brook Yankee
--------- ----- -------
(Dollars in thousands)
Plant capacity . . . . . . . . . . . 320.0 MW 343.0 MW 520.0 MW
Company's share of output . . . . . 8.9% 4.4% 17.3%
Contract period . . . . . . . . . . 1968-1998 (1) (2)
Company's annual share of:
Interest . . . . . . . . . . . . . $ 589 $ 307 $ 1,403
Other debt service . . . . . . . . 297 270 ---
Other capacity . . . . . . . . . . 1,560 353 26,327
------ ------ -------
Total annual capacity . . . . . . . $2,446 $ 930 $27,730
====== ====== =======
Company's share of long-term debt . $ 944 $5,983 $13,749
====== ====== =======
(1) Life of plant estimated to be 1981 - 2006.
(2) License for plant operations expires in 2012.
2. Hydro-Quebec System Power Purchases
Under various contracts approved by the VPSB, the details of which are
described in the table below, the Company purchases capacity and
associated energy produced by the Hydro-Quebec system. Such contracts
obligate the Company to pay certain fixed capacity costs whether or not
energy purchases above a minimum level set forth in the contracts are
made. Such minimum energy purchases must be made whether or not other,
less expensive energy sources might be available. These contracts are
intended to complement the other components in the Company's power
supply to achieve the most economic power-supply mix reasonably
available.
On October 12, 1990, the VPSB granted conditional approval of the
Company's purchases pursuant to the contract with Hydro-Quebec entered
into December 4, 1987: (1) Schedule A -- 17 megawatts of firm capacity
and associated energy to be delivered at the Highgate interconnection
for five years beginning 1990; (2) Schedule B -- 68 megawatts of firm
capacity and associated energy to be delivered at the Highgate
interconnection for twenty years beginning in September 1995; and (3)
Schedule C3 -- 46 megawatts of firm capacity and associated energy to be
delivered at interconnections to be determined at a later time for 20
years beginning in November 1995. The opponents to the December 1987
contract appealed the VPSB's October 1990 order to the Vermont Supreme
Court. On October 2, 1992, the Vermont Supreme Court affirmed the
VPSB's October 1990 order. On February 12, 1992, the VPSB issued an
order finding that the Company had complied with substantial conditions
imposed by the VPSB in its October 1990 order and approved the Company's
purchase under the December 1987 contract. In March 1992, the opponents
to the December 1987 contract appealed the VPSB's February 1992
compliance order to the Vermont Supreme Court. On May 7, 1993, the
Vermont Supreme Court affirmed the VPSB's compliance order approving the
Company's purchases under the December 1987 contract.
The Company anticipates that the Schedule C3 purchases will be delivered
over its entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase I
and Phase II). If such interconnection is utilized, the Company must
forego certain savings associated with other energy deliveries and
capacity arrangements that would benefit the Company if the
interconnection were not utilized for delivery of the Schedule C3
purchases. The Company believes that the benefits of the Schedule C3
purchases, if power is delivered over such interconnection, will offset
the value of the foregone savings.
In September 1993, the Company negotiated a renewal of a short-term
"tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec
delivers up to 61 megawatts of capacity and energy to the Company over
the NEPOOL/Hydro-Quebec interconnection. The electricity purchased
under this tertiary contract is priced at less than 2.5 cents per
kilowatthour. The benefits realized by the Company from this favorably
priced electricity will be greater than those associated with deliveries
foregone by the Company otherwise available over the NEPOOL/Hydro-Quebec
interconnection. This tertiary energy contract will expire in August
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. 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.
July 1984 December 1987 Contract
Contract Schedule A Schedule B Schedule C3
--------- ---------- ---------- -----------
(Dollars in thousands)
Capacity Acquired . . . . 50 MW 17 MW 68 MW 46 MW
Contract Period . . . . . 1985-1995 1990-1995 1995-2015 1995-2015
Minimum Energy Purchase
(annual load factor) . 50% 50% 75% 75%
(1992-1995)
Minimum Energy Charge . . $3,881 $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 $16,633 $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.
3. Rochester Gas & Electric Purchase
In 1988, the Company entered into a ten-year contract with Rochester Gas
and Electric Corporation (RG&E) for the purchase of up to 50 megawatts
of firm power and associated energy. This flexible contract allows the
Company the discretion of purchasing from 0 megawatts to 50 megawatts 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 percent 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 Niagra Mohawk
Power Corporation for the 50-megawatt maximum purchase. Both RG&E and
the Company have the option to terminate the contract effective 1995.
Pursuant to an agreement with Connecticut Light and Power Corporation
(CL&P) and Bozrah Light and Power (Bozrah) that was finalized in
December 1992, the Company exercised the option to terminate the RG&E
agreement and the transmission contract with Niagara Mohawk that
supports it effective October 31, 1995. The Company also agreed to
offer RG&E power to CL&P for purchase on a weekly basis through the
remaining term of the RG&E agreement, 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 percent of the
fixed costs of the transmission contract with Niagara Mohawk, and will
provide the Company with up to 50 megawatts of system power, to be
scheduled on a weekly basis, at a total price expected to be lower than
that provided under the existing RG&E contract. In addition, CL&P has
offered the Company an option, which may be exercised in yearly
increments starting in July 1994, to purchase up to 50 additional
megawatts of system power for the period July 1995 through December
2004.
The 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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and
capitalization data of Green Mountain Power Corporation (a Vermont
corporation) as of December 31, 1993 and 1992, and the related
consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1993. These financial statements
are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Green Mountain Power Corporation as of December 31, 1993 and 1992, and
the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 1993, in conformity
with generally accepted accounting principles.
As discussed in Notes A and G to the accompanying financial statements,
effective January 1, 1993, the Company changed its method of accounting
for post-retirement benefits other than pensions and income taxes.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts
February 1, 1994
Schedule V
GREEN MOUNTAIN POWER CORPORATION
PROPERTY, PLANT AND EQUIPMENT
December 31, 1993
Balance at Other Changes Balance at
Beginning of Additions Add End of
Classification Period at Cost (1) Retirements (Deduct) Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Electric Utility
Electric Plant
Intangible plant...................... $3,125,484 $1,555,539 $181,227 $71,406 $4,571,202
Steam production...................... 10,687,682 60,044 -- -- 10,747,726
Hydraulic production.................. 24,034,321 922,598 49,390 22,394 24,929,923
Other production...................... 17,533,239 886,850 18,474 -- 18,401,615
Transmission.......................... 25,623,292 3,171,249 69,184 (27,350) 28,698,007
Distribution.......................... 101,367,145 6,942,288 825,200 4,956 107,489,189
General............................... 19,271,489 1,685,095 745,253 (71,406) 20,139,925
------------- -------------- -------------- ------------- -------------
Total plant in service............... 201,642,652 15,223,663 1,888,728 0 214,977,587
Property under capital lease.......... 11,949,580 -- -- (920,755) 11,028,825
Construction work in progress......... 9,646,810 (16,152) -- -- 9,630,658
Held for future use................... -- -- -- -- --
------------- -------------- -------------- ------------- -------------
Total electric plant (2).............$223,239,042 $15,207,511 $1,888,728 ($920,755) $235,637,070
============= ============== ============== ============= =============
Other................................. $567,124 $113,438 $239,009 $ -- $441,553
============= ============== ============== ============= =============
Non-Utility
Land, buildings and general structure. $2,395,853 $ -- $ -- $ -- $2,395,853
Vehicles.............................. 1,102,438 177,948 47,585 -- 1,232,801
Office furniture and equipment........ 130,471 55,221 $ -- -- 185,692
Containers and equipment.............. 7,883,391 1,237,199 58,941 -- 9,061,649
------------- -------------- -------------- ------------- -------------
Total non-utility property........... $11,512,153 $1,470,368 $106,526 $ -- $12,875,995
============= ============== ============== ============= =============
Other
Rental water heaters................. $3,968,436 $148,428 $233,856 $ -- $3,883,008
============= ============== ============== ============= =============
(1) Includes a credit for contributions received in aid of construction of $1,367,697.
(2) For depreciation method and rates, see Note A-5 of Notes to Consolidated Financial Statements.
Schedule V
GREEN MOUNTAIN POWER CORPORATION
PROPERTY, PLANT AND EQUIPMENT
December 31, 1992
Balance at Other Changes Balance at
Beginning of Additions Add End of
Classification Period at Cost (1) Retirements (Deduct) Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Electric Utility
Electric Plant
Intangible plant...................... $4,582,132 $519,890 $1,976,538 -- $3,125,484
Steam production...................... 10,678,787 8,895 -- -- 10,687,682
Hydraulic production.................. 23,820,246 219,545 5,470 -- 24,034,321
Other production...................... 17,481,923 57,573 6,257 -- 17,533,239
Transmission.......................... 25,335,417 351,815 39,997 (23,943) 25,623,292
Distribution.......................... 94,142,001 8,290,182 1,088,981 23,943 101,367,145
General............................... 18,139,190 2,194,657 1,062,358 -- 19,271,489
------------- -------------- -------------- ------------- -------------
Total plant in service............... 194,179,696 11,642,557 4,179,601 -- 201,642,652
Property under capital lease.......... 12,627,179 -- -- (677,599) 11,949,580
Consrtuction work in progress......... 8,581,476 1,065,334 -- -- 9,646,810
Held for future use................... -- -- -- -- --
------------- -------------- -------------- ------------- -------------
Total electric plant (2).............$215,388,351 $12,707,891 $4,179,601 ($677,599) $223,239,042
============= ============== ============== ============= =============
Other................................. $328,115 $239,009 $ -- $ -- $567,124
============= ============== ============== ============= =============
Non-Utility
Land, buildings and general structure. $2,289,745 $106,108 $ -- $ -- $2,395,853
Vehicles.............................. 881,843 220,595 -- -- 1,102,438
Office furniture and equipment........ 125,967 4,504 -- -- 130,471
Containers and equipment.............. 5,129,626 2,753,765 -- -- 7,883,391
------------- -------------- -------------- ------------- -------------
Total non-utility property........... $8,427,181 $3,084,972 $ -- $ -- $11,512,153
============= ============== ============== ============= =============
Other
Rental water heaters................. $4,491,205 $137,496 $660,265 $ -- $3,968,436
============= ============== ============== ============= =============
(1) Includes a credit for contributions received in aid of construction of $3,574,832.
(2) For depreciation method and rates, see Note A-5 of Notes to Consolidated Financial Statements.
Schedule V
GREEN MOUNTAIN POWER CORPORATION
PROPERTY, PLANT AND EQUIPMENT
December 31, 1991
Balance at Other Changes Balance at
Beginning of Additions Add End of
Classification Period at Cost (1) Retirements (Deduct) Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Electric Utility
Electric Plant
Intangible plant...................... $3,336,411 $1,246,290 $2,818 $2,249 $4,582,132
Steam production...................... 10,645,867 32,920 -- -- 10,678,787
Hydraulic production.................. 20,892,720 2,962,727 59,700 24,499 23,820,246
Other production...................... 17,759,103 (283,626) 6,367 12,813 17,481,923
Transmission.......................... 23,934,794 1,521,265 20,324 (100,318) 25,335,417
Distribution.......................... 88,035,716 7,240,801 1,199,270 64,754 94,142,001
General............................... 17,688,502 2,081,321 1,626,606 (4,027) 18,139,190
------------- -------------- -------------- ------------- -------------
Total plant in service............... 182,293,113 14,801,698 2,915,085 (30) 194,179,696
Property under capital lease.......... 12,797,448 -- -- (170,269) 12,627,179
Consrtuction work in progress......... 8,633,566 (52,090) -- -- 8,581,476
Held for future use.................. -- -- -- -- --
------------- -------------- -------------- ------------- -------------
Total electric plant (2).............$203,724,127 $14,749,608 $2,915,085 ($170,299) $215,388,351
============= ============== ============== ============= =============
Other................................. $172,449 $155,666 $ -- $ -- $328,115
============= ============== ============== ============= =============
Non-Utility
Land, buildings and general structure. $1,428,719 $861,026 $ -- $ -- $2,289,745
Vehicles.............................. 335,788 559,605 13,550 -- 881,843
Office furniture and equipment........ 77,356 50,976 2,365 -- 125,967
Containers and equipment.............. 1,785,428 3,348,106 3,908 -- 5,129,626
------------- -------------- -------------- ------------- -------------
Total non-utility property........... $3,627,291 $4,819,713 $19,823 $ -- $8,427,181
============= ============== ============== ============= =============
Other
Rental water heaters................. $4,495,752 $125,321 $139,043 9,175 $4,491,205
============= ============== ============== ============= =============
(1) Includes a credit for contributions received in aid of construction of $2,166,566.
(2) For depreciation method and rates, see Note A-5 of Notes to Consolidated Financial Statements.
Schedule VI
GREEN MOUNTAIN POWER CORPORATION
ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
For the Years Ended December 31, 1993, 1992 and 1991
Additions
Balance at Charged to Other Changes Balance at
Beginning of Costs and Add End of
Description Period Expenses Retirements (Deduct) Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Year Ended December 31, 1993
Accumulated Depreciation
Electric Plant.................... $58,516,131 $7,290,093 $2,129,716 (1) $549,293 (2) $64,225,801
Non-Utility Property................ $923,034 $657,858 $28,598 $ -- $1,552,294
Rental Water Heaters................ $2,949,238 $268,734 $233,856 $ -- $2,984,116
Year Ended December 31, 1992
Accumulated Depreciation
Electric Plant...................... $55,658,400 $6,935,077 $4,603,309 (1) $525,963 (2) $58,516,131
Non-Utility Property................ $456,751 $466,283 $ -- $ -- $923,034
Rental Water Heaters................ $3,312,130 $297,373 $660,265 $ -- $2,949,238
Year Ended December 31, 1991
Accumulated Depreciation
Electric Plant...................... $51,353,779 $6,078,261 $2,245,263 (1) $471,623 (2) $55,658,400
Non-Utility Property................ $381,464 $95,110 $19,823 $ -- $456,751
Rental Water Heaters................ $3,132,416 $318,757 $139,043 $ -- $3,312,130
(1) Principally retirement and cost of removal charged to accumulated depreciation, net of salvage.
(2) Depreciation on transportation equipment charged to transportation clearing account.
Schedule VIII
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1993, 1992 and 1991
Additions
Balance at ------------------------------- Balance at
Beginning of Charged to Charged to End of
Description Period Cost & Expense Other Accounts Deductions Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Pine Street Marsh (1)
1993................................. $684,430 $ -- $ -- $ -- $684,430
1992................................. $687,136 $3,678 $ -- $6,384 $684,430
1991................................. $509,025 $240,606 $ -- $62,495 $687,136
Injuries and Damages
1993................................. ($2,357) $142,000 $ -- $33,983 $105,660
1992................................. ($12,413) $42,000 $ -- $31,944 ($2,357)
1991................................. $5,521 $42,413 $ -- $60,347 ($12,413)
Bad Debt Reserve (3)
1993................................. $469,922 $410,000 $89,014 (2) $329,083 $639,853
1992................................. $351,049 $449,475 $44,338 (2) $374,940 $469,922
1991................................. $300,370 $336,252 $104,883 (2) $390,456 $351,049
(1) See Note I-1 of the Notes to Consolidated Financial Statements.
(2) Represents collection of accounts previously written off.
(3) Includes non-utility bad debt reserve.
Schedule IX
GREEN MOUNTAIN POWER CORPORATION
Short-term Borrowings
For the Years Ended December 31, 1993, 1992 and 1991
Maximum Average Weighted
Amount Amount Average
Balance at Interest Rate Outstanding Outstanding Interest Rate
Category of Aggregate End of at End of During the During the During the
Short-term Borrowings Period Period Period Period (2) Period
----------------------------- ------------- -------------- -------------- ------------- -------------
Electric Utility
Notes Payable to Banks (1)
Period Ended - 1993................... $19,015,000 3.74% $26,100,000 $11,303,000 3.64% (3)
Period Ended - 1992................... $11,614,000 3.94% $13,784,000 $4,648,000 4.59% (3)
Period Ended - 1991................... $13,707,000 5.70% $16,400,000 $9,737,000 6.68% (3)
Non-Utility
Notes Payable to Banks
Period Ended - 1993................... $400,000 6.75% $750,000 $135,000 6.75% (3)
Period Ended - 1992................... $750,000 6.75% $750,000 $330,000 7.11% (3)
Period Ended - 1991................... $540,000 7.25% $555,000 $265,000 8.83% (3)
(1) The Company had lines of credit amounting to $30,500,000 at rates which ranged from 3.59%
to 5.00% at December 31, 1993. The Company had fee arrangements on its lines of credit.
(2) Average amount outstanding computed by using month-end debt balances.
(3) The weighted average interest rate is computed by using month-end debt
balances and month-end rates.
Schedule X
GREEN MOUNTAIN POWER CORPORATION
Supplementary Income Statement Information
For the Years Ended December 31, 1993, 1992 and 1991
Charged to Costs and Expenses
------------------------------------------------
Item 1993 1992 1991
- ------------------------ ------------- -------------- --------------
Electric Utility
Taxes Other than Income Taxes
Municipal property taxes............. $3,929,829 $3,801,888 $3,667,260
Payroll taxes........................ 885,897 843,042 831,433
Gross operating revenue tax.......... 1,310,052 1,256,933 1,178,722
------------- -------------- --------------
Total............................. $6,125,778 $5,901,863 $5,677,415
============= ============== ==============
Non-Utility
Depreciation.......................... $657,858 $466,284 $81,435
Amortization of intangible assets..... $549,504 $537,530 $305,184
Advertising........................... $76,625 $211,629 $89,665
All other items were not material or were disclosed in the
Consolidated Financial Statements or the related notes.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEMS 10, 11, 12 & 13
Certain information regarding executive officers called for by Item
10, "Directors and Executive Officers of the Registrant," is furnished
under the caption, "Executive Officers" in Item 1 of Part I of this Report.
The other information called for by Item 10, as well as that called for by
Items 11, 12, and 13, "Executive Compensation," "Security Ownership of
Certain Beneficial Owners and Management" and "Certain Relationships and
Related Transactions," will be set forth under the captions "Nominees for
Director," "Compliance with the Securities Exchange Act," "Executive
Compensation," "Pension Plan Information" and "Security Ownership of
Certain Beneficial Owners and Management" in the Company's definitive proxy
statement relating to its annual meeting of stockholders to be held on May
19, 1994. Such information is incorporated herein by reference. Such
proxy statement pertains to the election of directors and other matters.
Definitive proxy materials will be filed with the Securities and Exchange
Commission pursuant to Regulation 14A in April 1994.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
Filed
Herewith
On Page
Item 14(a)(1). The financial statements and financial 38
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.
Item 14(a)(2). The financial statements and financial 84
statement schedules of Vermont Yankee Nuclear Power Corporation,
together with report thereon of Arthur Andersen & Co. and KPMG
Peat Marwick are bound and filed herewith as Item 14(d).
ITEM 14(a)(3). EXHIBITS
Incorporated by Reference from
Exhibit SEC Docket OR
Number Exhibit Page Filed Herewith
______ _________________________________________ _______ ___________________
*3-a Restated Articles of Association, as certified 3-a
June 6, 1991.
*3-a-1 Amendment to 3-a above, dated as of May 20, 1993. 3-a-1
* 3-b By-laws of the Company, as amended 3-b
March 8, 1994.
4-b-1 Indenture of First Mortgage and Deed of Trust 4-b 2-27300
dated as of February 1, 1955.
4-b-2 First Supplemental Indenture dated as of 4-b-2 2-75293
April 1, 1961.
4-b-3 Second Supplemental Indenture dated as of 4-b-3 2-75293
January 1, 1966.
4-b-4 Third Supplemental Indenture dated as of 4-b-4 2-75293
July 1, 1968.
4-b-5 Fourth Supplemental Indenture dated as of 4-b-5 2-75293
October 1, 1969.
4-b-6 Fifth Supplemental Indenture dated as of 4-b-6 2-75293
December 1, 1973.
4-b-7 Seventh Supplemental Indenture dated as of 4-a-7 2-99643
August 1, 1976.
4-b-8 Eighth Supplemental Indenture dated as of 4-a-8 2-99643
December 1, 1979.
4-b-9 Ninth Supplemental Indenture dated as of 4-b-9 2-99643
July 15, 1985.
4-b-10 Tenth Supplemental Indenture dated as of 4-b-10 Form 10-K 1989
June 15, 1989. (1-8291)
4-b-11 Eleventh Supplemental Indenture dated as of 4-b-11 Form 10-Q Sept
September 1, 1990. 1990 (1-8291)
4-b-12 Twelfth Supplemental Indentrue dated as of 4-b-12 Form 10-K 1991
March 1, 1992. (1-8291)
4-b-13 Thirteenth Supplemental Indenture dated as of 4-b-13 Form 10-K 1991
March 1, 1992. (1-8291)
*4-b-14 Fourteenth Supplemental Indenture dated as of 4-b-14
November 1, 1993.
*4-b-15 Fifteenth Supplemental Indenture dated as of 4-b-15
November 1, 1993.
4-c Debenture Indenture dated as of August 1, 1967 4-c 2-75293
(6 5/8% Debentures due August 1, 1992).
4-c-1 First Supplemental Indenture dated as of 4-c-1 2-49697
August 1, 1969, amending Exhibit 4-c above.
4-d Debenture Indenture dated as of October 1, 1969 4-d 2-75293
(8 7/8% Debentures due October 1, 1994).
4-e Debenture Indenture dated as of December 1, 1976 4-d 2-99643
(9 3/8% Debentures due December 1, 1996).
4-f Debenture Indenture dated as of August 1, 1983 4-f Form 10K 1992
(12 5/8% Debentures due August 1, 1998). (1-8291)
10-a Form of Insurance Policy issued by Pacific 10-a 33-8146
Insurance Company, with respect to
indemnification of Directors and Officers.
10-b-1 Firm Power Contract dated September 16, 1958, 13-b 2-27300
between the Company and the State of Vermont
and supplements thereto dated September 19,
1958; November 15, 1958; October 1, 1960 and
February 1, 1964.
10-b-2 Power Contract, dated February 1, 1968, between 13-d 2-34346
the Company and Vermont Yankee Nuclear Power
Corporation.
10-b-3 Amendment, dated June 1, 1972, to Power Contract 13-f-1 2-49697
between the Company and Vermont Yankee Nuclear
Power Corporation.
10-b-3 Amendment, dated April 15, 1983, to Power 10-b-3(a) 33-8164
(a) Contract between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-3 Additional Power Contract, dated 10-b-3(b) 33-8164
(b) February 1, 1984,between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-4 Capital Funds Agreement, dated February 1, 13-e 2-34346
1968, between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-5 Amendment, dated March 12, 1968, to Capital 13-f 2-34346
Funds Agreement between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-6 Guarantee Agreement, dated November 5, 1981, 10-b-6 2-75293
of the Company for its proportionate share
of the obligations of Vermont Yankee Nuclear
Power Corporation under a $40 million loan
arrangement.
10-b-7 Three-Party Power Agreement among the Company, 13-i 2-49697
VELCO and Central Vermont Public Service
Corporation dated November 21, 1969.
10-b-8 Amendment to Exhibit 10-b-7, dated June 1, 1981. 10-b-8 2-75293
10-b-9 Three-Party Transmission Agreement among the 13-j 2-49697
Company, VELCO and Central Vermont Public
Service Corporation, dated November 21, 1969.
10-b-10 Amendment to Exhibit 10-b-9, dated June 1, 1981. 10-b-10 2-75293
10-b-12 Unit Purchase Contract dated February 10, 1968, 13-h 2-34346
between the Company and Vermont Electric
Power Company, Inc., for purchase of
"Merrimack" power from Public Service
Company of New Hampshire.
10-b-14 Agreement with Central Maine Power Company et 5.16 2-52900
al, to enter into joint ownership of Wyman
plant, dated November 1, 1974.
10-b-15 New England Power Pool Agreement as amended to 4.8 2-55385
November 1, 1975.
10-b-16 Bulk Power Transmission Contract between the 13-v 2-49697
Company and VELCO dated June 1, 1968.
10-b-17 Amendment to Exhibit 10-b-16, dated June 1, 1970. 13-v-i 2-49697
10-b-20 Power Sales Agreement, dated August 2, 1976, as 10-b-20 33-8164
amended October 1, 1977, and related
Transmission Agreement, with the Massachusetts
Municipal Wholesale Electric Company.
10-b-21 Agreement dated October 1, 1977, for Joint 10-b-21 33-8164
Ownership, Construction and Operation of the
MMWEC Phase I Intermediate Units, dated
October 1, 1977.
10-b-28 Contract dated February 1, 1980, providing for 10-b-28 33-8164
the sale of firm power and energy by the Power
Authority of the State of New York to the
Vermont Public Service Board.
10-b-30 Bulk Power Purchase Contract dated April 7, 10-b-32 2-75293
1976, between VELCO and the Company.
10-b-33 Agreement amending New England Power Pool 10-b-33 33-8164
Agreement dated as of December 1, 1981,
providing for use of transmission inter-
connection between New England and
Hydro-Quebec.
10-b-34 Phase I Transmission Line Support Agreement 10-b-34 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
VETCO and participating New England utilities
for construction, use and support of Vermont
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-35 Phase I Terminal Facility Support Agreement 10-b-35 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
New England Electric Transmission Corporation
and participating New England utilities for
construction, use and support of New Hampshire
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-36 Agreement with respect to use of Quebec 10-b-36 33-8164
Interconnection dated as of December 1, 1981,
among participating New England utilities
for use of transmission interconnection
between New England and Hydro-Quebec.
10-b-39 Vermont Participation Agreement for Quebec 10-b-39 33-8164
Inter-connection dated as of July 15, 1982,
between VELCO and participating Vermont
utilities for allocation of VELCO's rights
and obligations as a participating New
England utility in the transmission inter-
connection between New England and Hydro-Quebec.
10-b-40 Vermont Electric Transmission Company, Inc. 10-b-40 33-8164
Capital Funds Agreement dated as of July 15,
1982, between VETCO and VELCO for VELCO to
provide capital to VETCO for construction of
the Vermont facilities of the transmission
inter-connection between New England and
Hydro-Quebec.
10-b-41 VETCO Capital Funds Support Agreement dated as 10-b-41 33-8164
of July 15, 1982, between VELCO and partici-
pating Vermont utilities for allocation
of VELCO's obligation to VETCO under the
Capital Funds Agreement.
10-b-42 Energy Banking Agreement dated March 21, 1983, 10-b-42 33-8164
among Hydro-Quebec, VELCO, NEET and parti-
cipating New England utilities acting by and
through the NEPOOL Management Committee for
terms of energy banking between participating
New England utilities and Hydro-Quebec.
10-b-43 Interconnection Agreement dated March 21, 1983, 10-b-43 33-8164
between Hydro-Quebec and participating New
England utilities acting by and through the
NEPOOL Management Committee for terms and
conditions of energy transmission between
New England and Hydro-Quebec.
10-b-44 Energy Contract dated March 21, 1983, between 10-b-44 33-8164
Hydro-Quebec and participating New England
utilities acting by and through the NEPOOL
Management Committee for purchase of
surplus energy from Hydro-Quebec.
10-b-45 Firm-Power Agreement dated as of October 5, 1982, 10-b-45 33-8164
between Ontario Hydro and Vermont Department
of Public Service.
10-b-46 Sales Agreement, dated January 20, 1983, between 10-b-46 33-8164
Central Maine Power Company and the Company
for excess power.
10-b-48 Sales Agreement, dated February 1, 1983, 10-b-48 33-8164
betweenNiagara Mohawk and Vermont Electric
Power Company for purchase of energy.
10-b-50 Agreement for Joint Ownership, Construction and 10-b-50 33-8164
Operation of the Highgate Transmission
Interconnection, dated August 1, 1984,
between certain electric distribution
companies, including the Company.
10-b-51 Highgate Operating and Management Agreement, 10-b-51 33-8164
dated as of August 1, 1984, among VELCO and
Vermont electric-utility companies, including
the Company.
10-b-52 Allocation Contract for Hydro-Quebec Firm Power 10-b-52 33-8164
dated July 25, 1984, between the State of
Vermont and various Vermont electric utilities,
including the Company.
10-b-53 Highgate Transmission Agreement dated as of 10-b-53 33-8164
August 1, 1984, between the Owners of the
Project and various Vermont electric
distribution companies.
10-b-54 Lease and Sublease Agreement dated June 1, 1984, 10-b-54 33-8164
between Burlington Associates and the Company.
10-b-55 Ground Lease Agreement dated June 1, 1984, 10-b-55 33-8164
between GMP Real Estate Corporation and
Burlington Associates.
10-b-56 Assignment of Lease and Agreement, dated June 1, 10-b-56 33-8164
1984, from Burlington Associates to Teachers
Insurance and Annuity Association of America.
10-b-57 Mortgage dated June 1, 1984, from GMP Real Estate 10-b-57 33-8164
Corporation, Mortgagor, to Teachers Insurance
and Annuity Association of America, Mortgagee.
10-b-58 Lease and Operating Agreement dated June 28,1985, 10-b-58 33-8164
between the State of Vermont and the Company.
10-b-59 Service Contract dated June 28, 1985, between the 10-b-59 33-8164
State of Vermont and the Company.
10-b-61 Agreements entered in connection with Phase II 10-b-61 33-8164
of the NEPOOL/Hydro-Quebec + 450 KV HVDC
Transmission Interconnection.
10-b-62 Agreement between UNITIL Power Corp. and the 10-b-62 33-8164
Company to sell 23 MW capacity and energy from
Stony Brook Intermediate Combined Cycle Unit.
10-b-63 Sales Agreement dated as of June 20, 1986, 10-b-63 33-8164
between the Company and UNITIL Power Corp.
for sale of system power.
10-b-64 Sales Agreement dated as of June 20, 1986, 10-b-64 33-8164
between the Company and Fitchburg Gas and
Electric Light Company for sale of 10 MW
capacity and energy from the Vermont Yankee
plant.
10-b-65 Sales Agreement dated September 18, 1985, 10-b-65 Form 10-K 1991
between the Company and Fitchburg Gas and (1-8291)
Electric Light Company for the sale of
system power.
10-b-66 Sales Agreement dated January 1, 1987, between 10-b-66 Form 10-K 1991
the Company and Bozrah Light and Power (1-8291)
Company for sale of power.
10-b-67 Sales Agreement dated August 31, 1987, amending 10-b-67 Form 10-K 1992
the agreement dated June 20, 1986, between (1-8291)
the Company and UNITIL Power Corp. for sale
of system power.
10-b-68 Firm Power and Energy Contract dated December 4, 10-b-68 Form 10-K 1992
1987, between Hydro-Quebec and participating (1-8291)
Vermont utilities, including the Company, for
the purchase of firm power for up to thirty years.
10-b-69 Firm Power Agreement dated as of October 26, 1987, 10-b-69 Form 10-K 1992
between Ontario Hydro and Vermont Department of (1-8291)
Public Service.
10-b-70 Firm Power and Energy Contract dated as of 10-b-70 Form 10-K 1992
February 23, 1987, between the Vermont Joint (1-8291)
Owners of the Highgate facilities and Hydro-
Quebec for up to 50 MW of capacity.
10-b-70 Amendment to 10-b-70. 10-b-70(a) Form 10-K 1992
(a) (1-8291)
10-b-71 Interconnection Agreement dated as of 10-b-71 Form 10-K 1992
February 23, 1987, between the Vermont Joint (1-8291)
Owners of the Highgate facilities and Hydro-Quebec.
10-b-72 Participation Agreement dated as of April 1, 1988, 10-b-72 Form 10-Q
between Hydro-Quebec and participating Vermont June 1988
utilities, including the Company, implementing (1-8291)
the purchase of firm power for up to 30 years
under the Firm Power and Energy Contract dated
December 4, 1987 (previously filed with the
Company's Annual Report on Form 10-K for 1987,
Exhibit Number 10-b-68).
10-b-72 Restatement of the Participation Agreement filed 10-b-72(a) Form 10-K 1988
(a) as Exhibit 10-b-72 on Form 10-Q for June 1988. (1-8291)
10-b-73 Agreement dated as of May 1, 1988, between 10-b-73 Form 10-Q
Rochester Gas and Electric Corporation and the Sept. 1988
Company,implementing the Company's purchase of up (1-8291)
to 50 MW of electric capacity and associated energy.
10-b-74 Agreement dated as of November 1, 1988, between 10-b-74 Form 10-Q for
the Company and Fitchburg Gas and Electric Light Sept. 1988
Company,for sale of electric capacity and (1-8291)
associated energy.
10-b-74 Amendment to Exhibit 10-b-74. 10-b-74(a) Form 10-Q
(a) Sept 1989
(1-8291)
10-b-75 Allocation Agreement dated as of March 25, 1988, 10-b-75 Form 10-Q
between Ontario Hydro and the State of Vermont, Sept. 1988
for firm power and associated energy from (1-8291)
Ontario Hydro.
10-b-76 Agreement dated as of October 1, 1988, between 10-b-76 Form 10-K 1988
the Company and Central Hudson Gas & Electric (1-8291)
Corporation for the Company to purchase up to
50 MW of capacity and associated energy.
10-b-76 Transmission agreement dated February 28, 1989, 10-b-76(a) Form 10-K 1988
(a) between the Company and Consolidated Edison (1-8291)
Company of New York, Inc. (Con Edison), that
Con Edison will provide electric transmission
to the Company from Central Hudson Gas &
Electric Company.
10-b-77 Firm Power and Energy Contract dated December 29, 10-b-77 Form 10-K 1988
1988, between Hydro-Quebec and participating (1-8291)
Vermont utilities, including the Company, for the
purchase of up to 54 MW of firm power and energy.
10-b-78 Transmission Agreement dated December 23, 1988, 10-b-78 Form 10-K 1988
between the Company and Niagara Mohawk Power (1-8291)
Corporation (Niagara Mohawk), for Niagara
Mohawk to provide electric transmission to
the Company from RochesterGas and Electric
and Central Hudson Gas and Electric.
10-b-79 Lease Agreement dated November 1, 1988, between 10-b-79 Form 10-K 1988
the Company and International Business Machines (1-8291)
Corporation (IBM) for the lease to IBM of the
gas turbines and associated facilities located
on land adjacent to IBM's Essex Junction,
Vermont, plant.
10-b-80 Sales Agreement dated January 1, 1989, between 10-b-80 Form 10-K 1988
the Company and Public Service of New Hampshire (1-8291)
(PSNH)for PSNH to purchase electric capacity
from the Company.
10-b-81 Sales Agreement dated May 24, 1989, between 10-b-81 Form 10-Q
the Town of Hardwick, Hardwick Electric Department June 1989
and the Company for the Company to purchase (1-8291)
all of the output of Hardwick's generation and
transmission sources and to provide Hardwick
with all-requirements energy and capacity except
for that provided by the Vermont Department of
Public Service or Federal Preference Power.
10-b-82 Sales Agreement dated July 14, 1989, between 10-b-82 Form 10-Q
Northfield Electric Department and the Company June 1989
for the Company to purchase all of the output (1-8291)
of Northfield's generation and transmission
sources and to provide Northfield with all-
requirements energy and capacity except for
that provided by the Vermont Department of
Public Service or Federal Preference Power.
10-b-83 Power Purchase and Operating Agreement dated as 10-b-83 Form 10-Q
of April 20, 1990, between CoGen Lime Rock, June 1990
Inc., and the Company for the production of (1-8291)
energy to meet customer needs.
10-b-84 Capacity, Transmission and Energy Service 10-b-84 Form 10-K 1992
Agreement dated December 23, 1992, between (1-8291)
the Company and Connecticut Light and Power
Company (CL&P) for CL&P to supply power to
Bozrah Light and Power Company.
Management contracts or compensatory plans or arrangements
required to be filed as exhibits to this form 10-K
pursuant to Item 14(c).
10-c Contract dated as of October 15, 1983, between 10-c 33-8164
the Company and Thomas V. O'Connor, Jr.
10-c-1 Amendment dated as of March 31, 1988, to an 10-c-1 Form 10-Q
agreement between the Company and March 1988
Thomas V. O'Connor, Jr (1-8291)
10-d-1a Green Mountain Power Corporation Amended and 10-d-1a Form 10-Q
Restated Deferred Compensation Plans for March 1990
Directors and Officers. (1-8291)
*10-d-1b Green Mountain Power Corporation Second Amended 10-d-1b
and Restated Deferred Compensation Plan for
Directors.
*10-d-1c Green Mountain Power Corporation Second Amended 10-d-1c
and Restated Deferred Compensation Plan for
Officers.
*10-d-1d Amendment No. 93-1 to the Amended and Restated 10-d-1d
Deferred Compensation Plan for Officers.
10-d-2 Green Mountain Power Corporation Medical Expense 10-d-2 Form 10-K 1991
Reimbursement Plan. (1-8291)
10-d-3 Green Mountain Power Corporation Management 10-d-3 Form 10-K 1991
Incentive Plan. (1-8291)
10-d-4 Green Mountain Power Corporation Officer 10-d-4 Form 10-K 1991
Insurance Plan. (1-8291)
10-d-4a Green Mountain Power Corporation Officers' 10-d-4a Form 10-K 1990
Insurance Plan as amended. (1-8291)
10-d-5a Severance Agreements with J. V. Cleary, D. G. Hyde, 10-d-5a Form 10-K 1990
A. N. Terreri, E. M. Norse, T. V. O'Connor, Jr., (1-8291)
C. L. Dutton, G. J. Purcell, S. C. Terry and
T. C. Boucher.
10-d-6 Severance Agreements with W. S. Oakes, E. L. Shlatz 10-d-6 Form 10-K 1988
and J. H. Winer. (1-8291)
10-d-6a Restatement of 10-d-6 above. 10-d-6a Form 10-K 1990
(1-8291)
10-d-7 Severance Agreement with K. K. O'Neill. 10-d-7 Form 10-K 1990
(1-8291)
10-d-8 Green Mountain Power Corporation Officers' 10-d-8 Form 10-K 1990
Supplemental Retirement Plan. (1-8291)
10-d-9 Severance Agreement with C. T. Myotte. 10-d-9 Form 10-Q June
1991 (1-8291)
10-d-10 Severance Agreement with J. J. Lampron. 10-d-10 Form 10-K 1991
(1-8291)
10-d-11 Severance Agreement with D. R. Stroupe 10-d-11 Form 10-Q Sept
1992 (1-8291)
10-e-2 Agreement dated as of May 26, 1988, between the 10-e-2 Form 10-K for
Company and Thomas P. Salmon, Chairman of the Board. 1988 (1-8291)
16-a Letter from former accountant, Coopers & Lybrand. Form 8-K for
1987 (1-8291)
*23-a-1 Consent of Arthur Anderson & Co.
*23-a-2 Consent of KPMG Peat Marwick
____________________
* Filed herewith
ITEM 14(b)
There were no reports on Form 8-K filed for the quarter ending
December 31, 1993.
OTHER MATTERS
For the purposes of complying with the amendments to the rules
governing Form S-8 (effective July 13, 1990) under the Securities Act of
1933, the undersigned registrant hereby undertakes as follows, which
undertaking shall be incorporated by reference into registrant's
Registration Statement on Form S-8 No. 33-47985 (filed May 14, 1992):
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing provisions,
or otherwise, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public
policy as expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification against such
liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in
the successful defense of any action, suit or proceeding) is asserted by
such director, officer or controlling person in connection with the
securities being registered, the registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent, submit to
a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
By: /s/D. G. Hyde Date: March 31, 1994
----------------------------
(D. G. Hyde, President and
Chief Executive Officer)
Pursuant to the requriements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
/s/D. G. Hyde Chairman of the Executive Commit- March 31, 1994
(D. G. Hyde) tee, President, Chief Executive
Officer and Director
/s/E. M. Norse Vice President, Treasurer and March 31, 1994
(E. M. Norse) Chief Financial Officer (Principal
Financial Officer)
/s/G. J. Purcell Controller March 31, 1994
(G. J. Purcell) (Principal Accounting Officer)
/s/T. P. Salmon Chairman of the Board and March 31, 1994
(T. P. Salmon) Director
/s/R. E. Boardman Director March 31, 1994
(R. E. Boardman)
/s/N. L. Brue Director March 31, 1994
(N. L. Brue)
/s/W. H. Bruett Director March 31, 1994
(W. H. Bruett)
/s/M. O. Burns Director March 31, 1994
(M. O. Burns)
/s/J. V. Cleary Director March 31, 1994
(J. V. Cleary)
/s/R. I. Fricke Director March 31, 1994
(R. I. Fricke)
/s/E. A. Irving Director March 31, 1994
(E. A. Irving)
/s/M. L. Johnson Director March 31, 1994
(M. L. Johnson)
/s/R. W. Page Director March 31, 1994
(R. W. Page)
ITEM 14(d) FINANCIAL STATEMENTS
VERMONT YANKEE NUCLEAR POWER CORPORATION
FINANCIAL STATEMENTS
December 31, 1993, 1992 and 1991
(WITH INDEPENDENT AUDITOR'S REPORT THEREON)
VERMONT YANKEE NUCLEAR POWER CORPORATION
Index to Financial Statements and Financial Statement Schedules
Financial Statements: Page
Balance Sheets, December 31, 1993 and 1992 88-89
Statements of Income and Retained Earnings,
years ended December 31, 1993, 1992 and 1991 90
Statements of Cash Flows, years ended
December 31, 1993, 1992 and 1991 91
Notes to Financial Statements 92-105
Financial Statements:
Schedule I - Marketable Securities and Other
Investments at December 31, 1993 106
Schedule V - Property, Plant and Equipment,
years ended December 31, 1993, 1992 and 1991 107
Schedule VI - Accumulated Depreciation, Depletion
and Amortization of Property, Plant and
Equipment, years ended December 31, 1993, 108
1992 and 1991
All other schedules are omitted as the required information is
inapplicable or the required information is included in the financial
statements or related notes.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Stockholders and Board of Directors of
Vermont Yankee Nuclear Power Corporation:
We have audited the accompanying balance sheet of Vermont Yankee Nuclear
Power Corporation as of December 31, 1993, and the related statements of
income and retained earnings and cash flows for the year then ended.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audit. The financial statements of
Vermont Yankee Nuclear Power Corporation as of December 31, 1992 and
1991, were audited by other auditors whose report, dated February 5,
1993, expressed an unqualified opinion on those statements and included
an additional paragraph discussing the Company's 1992 change in
accounting for postretirement benefits other than pensions.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit also includes assessing the
accounting principles used and significant estimates made by management,
as well as evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Vermont
Yankee Nuclear Power Corporation as of December 31, 1993, and the
results of its operations and its cash flows for the year then ended, in
conformity with generally accepted accounting principles.
As discussed in Note 10 to the accompanying financial statements,
effective January 1, 1993, the Company adopted the provisions of
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as whole. Supplementary schedules I, V and
VI are presented for purposes of additional analysis and are not a
required part of the basic financial statements. This information has
been subjected to the auditing procedures applied in our audit of the
basic financial statements and, in our opinion, is fairly stated in, all
material respects, in relation to the basic financial statements taken
as a whole.
Boston, Massachusetts
January 27, 1994 ARTHUR ANDERSEN & CO.
INDEPENDENT AUDITORS' REPORT
The Stockholders and Board of Directors
Vermont Yankee Nuclear Power Corporation:
We have audited the balance sheet of Vermont Yankee Nuclear Power
Corporation as of December 31, 1992, and the related statements of
income and retained earnings and cash flows for each of the years in the
two-year period ended December 1992. In connection with our audits of
the financial statements, we also have audited the financial statement
schedules for each of the years in the two-year period ended December
31, 1992. These financial statements and financial statement schedules
are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial
statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Vermont
Yankee Nuclear Power Corporation at December 31, 1992 and the results of
its operations and cash flows for each of the years in the two-year
period ended December 31, 1992, in conformity with generally accepted
accounting principles. Also, in our opinion, the related financial
statement schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly, in all material respects,
the information set forth therein.
As discussed in note 13, the Company adopted the provisions of Statement
of Financial Accounting Standards Number 106, Employers' Accounting for
Postretirement Benefits Other than Pensions, in 1992.
KPMG Peat Marwick
Boston, Massachusetts
February 5, 1993
Balance Sheets
Assets
December 31,
------------
1993 1992
---- ----
(Dollars in thousands)
Utility plant:
Electric plant, at cost (note 6) $ 374,736 $ 362,278
Less accumulated depreciation 198,389 185,263
________ ________
176,347 177,015
Construction work in progress 597 6,408
________ ________
Net electric plant 176,944 183,423
________ ________
Nuclear fuel, at cost (note 6):
Assemblies in reactor 69,063 74,025
Fuel in process --- 5,236
Spent fuel 287,700 259,199
________ ________
356,763 338,460
Less accumulated amortization of burned
nuclear fuel 317,039 302,362
________ ________
39,724 36,098
Less accumulated amortization of final
core nuclear fuel 7,220 6,487
________ ________
Net nuclear fuel 32,504 29,611
________ ________
Net utility plant 209,448 213,034
________ ________
Current assets:
Cash and temporary investments 2,349 1,922
Accounts receivable from sponsors 12,235 15,407
Other accounts receivable 4,522 2,715
Materials and supplies 17,081 16,862
Prepaid expenses 3,949 4,381
________ ________
Total current assets 40,136 41,287
________ ________
Deferred charges:
Deferred decommissioning costs (note 2) 34,379 34,389
Accumulated deferred income taxes (note 10) 18,231 10,378
Deferred DOE enrichment site decontamination
and decommissioning fee (note 4) 18,627 18,143
Net unamortized loss on reacquired debt 2,942 ---
Other deferred charges (note 4) 3,643 4,994
________ ________
Total deferred charges 77,822 67,904
________ ________
Long-term funds at amortized cost:
Decommissioning fund (notes 2, 5, and 7) 98,880 82,091
Disposal fee defeasance fund (notes 5, 7, and 8) 43,484 33,892
________ ________
Total long-term funds 142,364 115,983
________ ________
$469,770 $438,208
======== ========
See accompanying notes to financial statements.
Balance Sheets
Capitalization and Liabilities
December 31,
------------
1993 1992
---- ----
(Dollars in thousands)
Capitalization:
Common stock equity:
Common stock, $100 par value; authorized
400,100 shares; issued 400,014 shares of which
7,533 are held in Treasury $ 40,001 $ 40,001
Additional paid-in capital 14,227 14,227
Treasury stock (7,533 shares at cost) (1,131) (1,131)
Retained earnings 1,067 1,178
________ ________
Total common stock equity 54,164 54,275
________ ________
Long-term obligations, net (notes 6 and 7) 79,636 74,193
________ ________
Total capitalization 133,800 128,468
________ ________
Commitments and contingencies (notes 2, 14 and 15)
Disposal fee and accrued interest for
spent nuclear fuel (notes 7 and 8) 80,688 78,239
________ ________
Current liabilities:
Accrued liabilities 28,063 22,743
Accounts payable 2,117 2,591
Accrued interest 635 974
Accrued taxes 1,206 1,472
________ ________
Total current liabilities 32,021 27,780
________ ________
Deferred credits:
Accrued decommissioning costs (note 2) 134,614 117,601
Accumulated deferred income taxes 56,478 58,963
Net regulatory tax liability (note 10) 8,351 ---
Accumulated deferred investment tax credits 7,013 7,590
Net unamortized gain on reacquired debt --- 1,732
Accrued DOE enrichment site decon-
tamination and decommissioning fee (note 4) 15,966 17,220
Other deferred credits 839 615
________ ________
Total deferred credits 223,261 203,721
________ ________
$469,770 $438,208
======== ========
See accompanying notes to financial statements.
Statements of Income and Retained Earnings
Years ended December 31,
------------------------
1993 1992 1991
---- ---- ----
(Dollars in thousands
except per share amounts)
Operating revenues $180,145 $175,919 $151,722
________ ________ ________
Operating expenses:
Nuclear fuel expense 19,526 21,240 24,864
Other operating expense 74,013 72,967 59,666
Maintenance 31,405 27,878 13,664
Depreciation 13,707 13,253 11,800
Decommissioning expense (note 2) 11,315 10,649 8,065
Taxes on income (note 10) 3,777 3,401 3,485
Property and other taxes 9,961 10,227 10,294
________ ________ ________
Total operating expenses 163,704 159,615 131,838
________ ________ ________
Operating income 16,441 16,304 19,884
________ ________ ________
Other income and (deductions):
Net earnings on decommissioning fund
(notes 2 and 5) 5,653 5,395 4,423
Decommissioning expense (note 2) (5,653) (5,395) (4,423)
Allowance for equity funds used
during construction 92 89 124
Interest 1,550 2,046 1,377
Taxes on other income (note 10) (623) (756) (447)
Other, net (232) (199) (917)
________ ________ ________
787 1,180 137
________ ________ ________
Income before interest expense 17,228 17,484 20,021
________ ________ ________
Interest expense:
Interest on long-term debt 7,281 7,101 7,684
Interest on disposal costs of spent
nuclear fuel (note 8) 2,450 2,801 4,312
Allowance for borrowed funds used
during construction (297) (339) (465)
________ ________ ________
Total interest expense 9,434 9,563 11,531
________ ________ ________
Net income 7,794 7,921 8,490
Retained earnings at beginning of year 1,178 1,166 1,982
________ ________ ________
8,972 9,087 10,472
Dividends declared 7,905 7,909 9,306
________ ________ ________
Retained earnings at end of year $ 1,067 $ 1,178 $ 1,166
======== ======== ========
Average number of shares outstanding
in thousands 392 392 394
======== ======== ========
Net income per average share of common
stock outstanding $ 19.86 $ 20.18 $ 21.56
======== ======== ========
Dividends per average share of common
stock outstanding $ 20.14 $ 20.15 $ 23.71
======== ======== ========
See accompanying notes to financial statements.
Statements of Cash Flows
Years ended December 31,
------------------------
1993 1992 1991
---- ---- ----
(Dollars in thousands)
Cash flows from operating activities:
Net income $ 7,794 $ 7,921 $ 8,490
________ ________ ________
Adjustments to reconcile net income
to net cash provided by operating
activities:
Amortization of nuclear fuel 15,410 18,143 21,002
Depreciation 13,707 13,253 11,800
Decommissioning expense 11,315 10,649 8,065
Deferred tax expense (979) (2,169) (801)
Amortization of deferred investment tax credit (577) (641) (740)
Nuclear fuel disposal fee interest accrual 2,450 2,802 4,312
Interest and dividends on disposal
fee defeasance fund (1,402) (1,385) (1,495)
(Increase) decrease in accounts receivable 1,365 688 (129)
(Increase) decrease in prepaid expenses 432 (1,159) 163
(Increase) in materials and supplies inventory (219) (454) (1,531)
Increase (decrease) in accounts payable
and accrued liabilities 4,846 (7,453) 5,495
Increase (decrease) in interest and
taxes payable (605) 306 (760)
Other (1,228) (1,410) (1,665)
________ ________ ________
Total adjustments 44,515 31,170 43,716
________ ________ ________
Net cash provided by operating activities 52,309 39,091 52,206
________ ________ ________
Cash flows from investing activities:
Electric plant additions (7,229) (10,750) (6,596)
Nuclear fuel additions (18,303) (4,707) (18,444)
Payments to decommissioning fund (11,250) (10,612) (8,323)
Payments to disposal fee defeasance fund (8,190) (5,190) (8,216)
________ ________ ________
Net cash used in investing activities (44,972) (31,259) (41,579)
________ ________ ________
Cash flows from financing activities:
Dividend payments (7,905) (7,909) (9,306)
Purchase of treasury stock --- --- (1,131)
Issuance of Series H first mortgage bonds, net --- --- 10,374
Issuance of Series I first mortgage
bonds, net 75,125 --- ---
Retirement of first mortgage bonds
including redemption costs (74,629) (6,521) (13,178)
Payments of long-term obligations (137,911) (107,763) (53,419)
Borrowings under long-term agreements 138,410 111,215 53,798
________ ________ ________
Net cash used in financing activities (6,910) (10,978) (12,862)
________ ________ ________
Net increase (decrease) in cash and
temporary investments 427 (3,146) (2,235)
Cash and temporary investments at
beginning of year 1,922 5,068 7,303
________ ________ ________
Cash and temporary investments
at end of year $ 2,349 $ 1,922 $ 5,068
======== ======== ========
See accompanying notes to financial statements.
Notes to Financial Statements
NOTE 1. Summary of Significant Accounting Policies
(a) Regulations and Operations
Vermont Yankee Nuclear Power Corporation ("the Company") is
subject to regulations prescribed by the Federal Energy
Regulatory Commission ("FERC"), and the Public Service Board of
the State of Vermont with respect to accounting and other
matters. The Company is also subject to regulation by the
Nuclear Regulatory Commission ("NRC") for nuclear plant licensing
and safety, and by federal and state agencies for environmental
matters such as air quality, water quality and land use.
Prior to November, 1993, the Company was subject to regulation by
the Securities and Exchange Commission. As a result of the debt
refinancing discussed in note 6, the Company is no longer subject
to such regulation.
The Company recognizes revenue pursuant to the terms of the Power
Contracts and Additional Power Contracts. The Sponsors, a group
of nine New England utilities, are severally obligated to pay the
Company each month their entitlement percentage of amounts equal
to the Company's total fuel costs and operating expenses of its
Plant, plus an allowed return on equity (since December 1, 1989,
12.25%). Such contracts also obligate the Sponsors to make
decommissioning payments through the end of the Plant's service
life and the completion of the decommissioning of the Plant. All
Sponsors are committed to such payments regardless of the Plant's
operating level or whether the Plant is out of service during the
period.
Under the terms of the Capital Funds Agreements, the Sponsors are
committed, subject to obtaining necessary regulatory
authorizations, to make funds available to obtain or maintain
licenses necessary to keep the Plant in operation.
(b) Depreciation and Maintenance
Electric plant is being depreciated on the straight-line method
at rates designed to fully depreciate all depreciable properties
over the lesser of estimated useful lives or the Plant's
remaining NRC license life, which extends to March, 2012.
Depreciation expense was equivalent to overall effective rates of
3.74%, 3.56% and 3.23% for the years 1993, 1992 and 1991,
respectively.
Renewals and betterments constituting retirement units are
charged to electric plant. Minor renewals and betterments are
charged to maintenance expense. When properties are retired, the
original cost, plus cost of removal, less salvage, is charged to
the accumulated provision for depreciation.
(c) Amortization of Nuclear Fuel
The cost of nuclear fuel is amortized to expense based on the
rate of burn-up of the individual assemblies comprising the total
core. The Company also provides for the costs of disposing of
spent nuclear fuel at rates specified by the United States
Department of Energy ("DOE") under a contract for disposal
between the Company and the DOE.
The Company amortizes to expense on a straight-line basis the
estimated costs of the final unspent nuclear fuel core, which is
expected to be in place at the expiration of the Plant's NRC
operating license in conformity with rates authorized by the
FERC.
(d) Amortization of Materials and Supplies
The Company amortizes to expense a formula amount designed to
fully amortize the cost of the material and supplies inventory
that is expected to be on hand at the expiration of the Plant's
NRC operating license.
(e) Long-term Funds
The Company accounts for its investments in long-term funds at
amortized cost since it has both the intent and ability to hold
these investments for the foreseeable future. Amortized cost
represents the cost to purchase the investment, net of any
unamortized premiums or discounts.
(f) Amortization of Gain and Loss on Reacquired Debt
The difference between the amount paid upon reacquisition of any
debt security and the face value thereof, plus any unamortized
premium, less any related unamortized debt expense and
reacquisition costs, or less any unamortized discount, related
unamortized debt expense and reacquisition costs applicable to
the debt redeemed, retired and canceled, is deferred by the
Company and amortized to expense on a straight-line basis over
the remaining life of the applicable security issues.
(g) Allowance for Funds Used During Construction
Allowance for funds used during construction ("AFUDC") is the
estimated cost of funds used to finance the Company's
construction work in progress and nuclear fuel in process which
is not recovered from the Sponsors through current revenues. The
allowance is not realized in cash currently, but under the Power
Contracts, the allowance will be recovered in cash over the
Plant's service life through higher revenues associated with
higher depreciation and amortization expense.
AFUDC was capitalized at overall effective rates of 5.92%, 6.82%
and 6.98% for 1993, 1992 and 1991, respectively, using the gross
rate method.
(h) Decommissioning
The Company is accruing the estimated costs of decommissioning
its Plant over the Plant's remaining NRC license life. Any
amendments to these estimated costs are accounted for
prospectively.
(i) Taxes on Income
Effective January 1, 1993, the Company began accounting for taxes
on income under the liability method required by Statement of
Financial Accounting Standard 109. See Note 10 for a further
discussion of this change in accounting.
Investment tax credits have been deferred and are being amortized
to income over the lives of the related assets.
(j) Cash Equivalents
For purposes of the Statements of Cash Flows, the Company
considers all highly liquid short-term investments with an
original maturity of three months or less to be cash equivalents.
(k) Reclassifications
Certain information in the 1992 and 1991 financial statements has
been reclassified to conform with the 1993 presentation.
(l) Earnings per Common Share
Earnings per common share have been computed by dividing earnings
available to common stock by the weighted average number of
shares outstanding during the year.
NOTE 2. Decommissioning
The Company accrues estimated decommissioning costs for its
nuclear plant over its remaining NRC licensed life based on
studies by an independent engineering firm that assumes that
decommissioning will be accomplished by the prompt removal and
dismantling method. This method requires that radioactive
materials be removed from the plant site and that all buildings
and facilities be dismantled immediately after shutdown. Studies
estimate that approximately six years would be required to
dismantle the Plant at shutdown, remove wastes and restore the
site. The Company has implemented rates based on a settlement
agreement with the FERC which allowed $190 million, in 1988
dollars, as the estimated decommissioning cost. This allowed
amount is used to compute the Company's liability and billings to
the Sponsors. Based on an assumed inflation rate of 6% per annum
and an expiration of the Plant's NRC operating license in 2012,
the estimated current cost of decommissioning is $253 million
and, at the end of 2012, is approximately $769 million. The
present value of the pro rata portion of decommissioning costs
recorded to date is $134.6 million. On December 31, 1993, the
balance in the Decommissioning Trust was $98.9 million.
Billings to Sponsors for estimated decommissioning costs
commenced during 1983, at which time the Company recorded a
deferred charge for the present value of decommissioning costs
applicable to operations of the Plant for prior periods. Current
period decommissioning costs not funded through billings to
Sponsors or earnings on decommissioning fund assets are also
deferred. These deferred costs will be amortized to expense as
they are funded over the remaining life of the NRC operating
license.
In 1994, the Company must file a revised estimate of
decommissioning costs and a revised schedule of future annual
decommissioning fund collections reflecting the historical
differences between assumed and actual rates of inflation and the
historical differences between assumed and actual rates of
earnings on decommissioning fund assets. Filings are required to
be made within four years of the most recent FERC approval of
decommissioning cost estimates and rates.
Cash received from Sponsors for plant decommissioning costs is
deposited into the Vermont Yankee Decommissioning Trust in either
the Qualified Fund (i.e., amounts currently deductible pursuant
to the IRS regulations) or the Nonqualified Fund (i.e., excess
collections pursuant to FERC authorization which are not
currently deductible). Funds held by the Trust are invested in
high-grade U.S. government securities and municipal obligations.
Interest earned by the Decommissioning Trust assets is recorded
in other income and deductions, with an equal and offsetting
amount representing the current period decommissioning cost
funded by such earnings reflected as decommissioning expense.
Decommissioning expense for 1991 included an adjustment of
approximately $2.1 million resulting from the Company's rate
reduction filing approved by the FERC on February 28, 1991 as
discussed in Note 3.
NOTE 3. FERC Rate Case Matters
On April 27, 1989, Vermont Yankee filed an application with the
NRC to extend the term of the operating license from 2007 to 2012
so that the Plant may operate for 40 years after it entered
commercial service in 1972. On December 17, 1990, the NRC issued
an amendment to the operating license extending its term to March
21, 2012. The Company submitted a rate reduction filing with the
FERC to reflect in rates the adjustments to decommissioning,
depreciation and amortization resulting from the license
extension. The Company proposed to make this reduction effective
as of March 1, 1991 and, since the extension was issued in 1990,
to reflect the necessary adjustment for the period January 1,
1990 through February 28, 1991.
On February 28, 1991, the FERC approved the Company's rate
reduction filing. The effects of this ruling were accounted for
prospectively in fiscal 1991, producing a net revenue reduction
ofapproximately $7.4 million in 1991, which reflected the
retroactive treatment to January 1, 1990. This ruling resulted
in reduced revenue requirements of approximately $3.5 million for
both 1992 and 1993, and similar reductions are expected in future
years.
On March 26, 1993, the FERC initiated a review of the return on
common equity component of the formula rates included in the
Company's Power Contracts. On October 22, 1993, the FERC
approved a settlement whereby the Company retained its 12.25%
authorized rate of return on common equity and agreed to credit
monthly power billings by approximately $139,000 beginning in
June, 1993.
In 1994, the Company will submit a rate filing to the FERC which
will include, among other things, a revised estimate of
decommissioning costs and a revised schedule of future annual
decommissioning fund collections.
NOTE 4. Other Deferred Charges and Credits
In October, 1992, Congress passed the Energy Policy Act of 1992
which requires, among other things, that certain utilities help
pay for the cleanup of the DOE's enrichment facilities over a 15-
year period. The Company's annual fee is estimated based on the
historical share of enrichment service provided by the DOE and is
indexed to inflation. These fees will not be adjusted for future
business as the DOE's future cost of sales will include a
decontamination and decommissioning component. The Act stipulates
that the annual fee shall be fully recoverable in rates in the
same manner as other fuel costs.
In 1993, the DOE billed and the Company paid the first of the 15
annual fees. As of December 31, 1993, the Company has recognized
a current accrued liability of $2.6 million for the two fee
payments expected to be made in 1994, a deferred credit of $16.0
million for the 12 annual fee payments that are due subsequent to
1994 and a corresponding regulatory asset of $18.6 million which
represents the total amount includable in future billings to the
purchasers under the Power Contracts. While these amounts are
reflected in these financial statements, the Company is reviewing
the DOE's calculation of the annual fee and believes that the
annual fee will ultimately be reduced.
Approximately $2.1 and $3.3 million of the $3.6 and $5.0 million
in other deferred charges at December 31, 1993 and 1992,
respectively, relate to payments made to the Vermont Low Level
Radioactive Waste Authority ("VLLRWA"), an agency of the State of
Vermont for the siting and construction of a low-level waste
disposal facility.
NOTE 5. Long-term Funds
The book value and estimated market value of long-term fund
investment securities at December 31, is as follows:
1993 1992
---- ----
Book Market Book Market
value value value value
----- ------ ----- ------
(Dollars in thousands)
Decommissioning fund:
U.S. Treasury obligations $17,262 $ 18,666 $22,000 $23,067
Municipal obligations 79,755 84,576 57,141 59,009
Accrued interest and money market funds 1,863 1,863 2,950 2,950
_______ _______ _______ _______
98,880 105,105 82,091 85,026
_______ _______ _______ _______
Disposal fee defeasance fund:
Short-term investments 39,870 39,870 26,457 26,457
Corporate bonds and notes 3,195 3,083 6,110 5,940
Accrued interest and money market funds 419 419 1,325 1,325
_______ _______ _______ _______
43,484 43,372 33,892 33,722
_______ _______ _______ _______
Total long-term fund investments $142,364 $148,477 $115,983 $118,748
======= ======= ======= =======
At December 31, 1993 and 1992, gross unrealized gains and losses
pertaining to the long-term investment securities were as
follows:
1993 1992
---- ----
(Dollars in thousands)
Unrealized gains on U.S. Treasury obligations $ 1,431 $ 1,071
------- -------
Unrealized losses on U.S. Treasury obligations $ (27) $ (4)
------- -------
Unrealized gains on Municipal obligations $ 4,843 $ 1,895
------- -------
Unrealized losses on Municipal obligations $ (22) $ (27)
------- -------
Unrealized losses on corporate bonds and notes $ (112) $ (170)
------- -------
Maturities of short-term obligations, bonds and notes (face
amount) at December 31, 1993 are as follows (dollars in
thousands):
Within one year $ 42,200
Two to five years 16,977
Five to seven years 19,670
Over seven years 57,860
_______
$136,707
=======
NOTE 6. Long-term Obligations
A summary of long-term obligations at December 31, 1993 and 1992
is as follows:
1993 1992
---- ----
(Dollars in thousands)
First mortgage bonds:
Series B - 8.50% due 1998 $ --- $ 1,307
Series C - 7.70% due 1998 --- 1,612
Series D - 10.125% due 2007 --- 23,147
Series E - 9.875% due 2007 --- 5,703
Series F - 9.375% due 2007 --- 5,704
Series G - 8.94% due 1995 --- 25,000
Series H - 8.25% due 1996 --- 8,388
Series I - 6.48% due 2009 75,845 ---
______ ______
Total first mortgage bonds 75,845 70,861
Eurodollar Agreement Commercial Paper 3,791 3,292
Unamortized premium on debt --- 40
______ ______
Total long-term obligations $79,636 $74,193
====== ======
The first mortgage bonds are issued under, have the terms and provisions
set forth in, and are secured by an Indenture of Mortgage dated as of
October 1, 1970 between the Company and the Trustee, as modified and
supplemented by 13 supplemental indentures. All bonds are secured by a
first lien on utility plant, exclusive of nuclear fuel, and a pledge of
the Power Contracts and the Additional Power Contracts (except for fuel
payments) and the Capital Funds Agreements with Sponsors.
On July 1, 1993, the Company retired the outstanding Series B and Series
C first mortgage bonds. In November, 1993, the Company issued $75.8
million of Series I, first mortgage bonds stated to mature on November
1, 2009. The Company applied the proceeds of the bond issuance
principally to retire the remaining Series D, Series E, Series F, Series
G and Series H first mortgage bonds including call premiums totalling
$3.7 million based on the early redemption of the bonds. Cash sinking
fund requirements for the Series I first mortgage bonds are $5.4 million
annually beginning in November, 1999.
The Company has a $75.0 million Eurodollar Credit Agreement that expires
on December 31, 1995 subject to three optional one-year extensions. The
Company issued commercial paper under this agreement with weighted
average interest rates of 3.22% for 1993 and 3.95% for 1992. Payment of
the commercial paper is supported by the Eurodollar Credit Agreement,
which is secured by a second mortgage on the Company's generating
facility.
NOTE 7. Disclosures About the Fair Value of Financial Instruments
The carrying amounts for cash and temporary investments, trade
receivables, accounts receivable from sponsors, accounts payable and
accrued liabilities approximate their fair values because of the short
maturity of these instruments. The fair values of long-term funds are
estimated based on quoted market prices for these or similar
investments. The fair values of each of the Company's long-term debt
instruments are estimated based on the quoted market prices for the same
or similar issues, or on the current rates offered to the Company for
debt of the same remaining maturities.
The estimated fair value of the Company's financial instruments as of
December 31 are summarized as follows (dollars in thousands):
1993 1992
---- ----
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
-------- ---------- -------- ----------
Decommissioning fund $98,880 $105,105 $82,091 $85,026
Disposal fee defeasance fund 43,484 43,372 33,892 33,722
Long-term debt 79,636 77,361 74,193 78,235
Disposal fee and accrued interest 80,688 80,688 78,239 78,239
Fair value estimates are made at a specific point in time, based on
relevant market information and information about the financial
instrument. These estimates are subjective in nature and involve
uncertainties and matters of significant judgment and therefore cannot
be determined with precision. Changes in assumptions could
significantly affect the estimates.
NOTE 8. Disposal Fee for Spent Nuclear Fuel
The Company has a contract with the United States Department of Energy
("DOE") for the permanent disposal of spent nuclear fuel. Under the
terms of this contract, in exchange for the one-time fee discussed below
and a quarterly fee of 1 mil per kwh of electricity generated and sold,
the DOE agrees to provide disposal services when a facility for spent
nuclear fuel and other high-level radioactive waste is available, which
is required by current statute to be prior to January 31, 1998.
The DOE contract obligates the Company to pay a one-time fee of
approximately $39.3 million for disposal costs for all spent fuel
discharged through April 7, 1983. Although such amount has been
collected in rates from the Sponsors, the Company has elected to defer
payment of the fee to the DOE as permitted by the DOE contract. The fee
must be paid no later than the first delivery of spent nuclear fuel to
the DOE. Interest accrues on the unpaid obligation based on the
thirteen-week Treasury Bill rate and is compounded quarterly. Through
1993, the Company deposited approximately $37.5 in an irrevocable trust
to be used exclusively for defeasing this obligation at some future
date, provided the DOE complies with the terms of the aforementioned
contract.
On December 31, 1991, the DOE issued an amended final rule modifying the
Standard Contract for Disposal of Spent Nuclear Fuel and/or High-level
Radioactive Waste. The amended final rule conforms with a March 17,
1989 ruling of the U.S. Court of Appeals for the District of Columbia
that the 1 mil per kilowatt hour fee in the Standard Contract should be
based on net electricity generated and sold. The impact of the
amendment on the Company was to reduce the basis for the fee by 6% on an
ongoing basis and to establish a receivable from the DOE for previous
overbillings and accrued interest. The Company has recognized in its
rates the full impact of the amended final rule to the Standard
Contract.
The DOE is refunding the overpayments, including interest, to utilities
over a four-year period ending in 1995 via credits against quarterly
payments. Interest is based on the 90-day Treasury Bill Auction Bond
Equivalent and will continue to accrue on amounts remaining to be
credited. At December 31, 1993 and 1992, respectively, approximately
$0.9 and $1.6 million in principal and interest is reflected in other
accounts receivable.
NOTE 9. Short-term Borrowings
The Company had lines of credit from various banks totalling $6.3
million at December 31, 1993 and 1992. The maximum amount of short-term
borrowings outstanding at any month-end during 1993, 1992 and 1991 was
approximately $0.2 million, $0.6 million and $0.4 million, respectively.
The average daily amount of short-term borrowings outstanding was
approximately $0.3 million for 1993, and $0.1 million for 1992 and 1991
with weighted average interest rates of 5.75% in 1993, 6.12 % in 1992
and 8.19% in 1991. There were no amounts outstanding under these lines
of credit as of December 31, 1993 and 1992.
NOTE 10. Taxes on Income
In February, 1992, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes", which required the Company to change from the deferred
method to the liability method of accounting for income taxes on January
1, 1993. The liability method accounts for deferred income taxes by
applying enacted statutory rates in effect at the balance sheet date to
differences between the book basis and the tax basis of assets and
liabilities ("temporary differences").
This new statement requires recognition of deferred tax liabilities for
(a) income tax benefits associated with timing differences previously
passed on to customers and (b) the equity component of allowance for
funds used during construction, and of a deferred tax asset for the tax
effect of the accumulated deferred investment tax credits. It also
requires the adjustment of deferred tax liabilities or assets for an
enacted change in tax laws or rates, among other things.
Although adoption of this new statement has not and is not expected to
have a material impact on the Company's cash flow, results of operations
or financial position because of the effect of rate regulation, the
Company was required to recognize an adjustment to accumulated deferred
income taxes and a corresponding regulatory asset or liability to
customers (in amounts equal to the required deferred income tax
adjustment) to reflect the future revenues or reduction in revenues that
will be required when the temporary differences turn around and are
recovered or settled in rates. In addition, this new statement required
a reclassification of certain deferred income tax liabilities to
liabilities to customers in order to reflect the Company's obligation to
flow back deferred income taxes provided at rates higher than the
current 35% federal tax rate. The Company has applied the provisions of
this new statement without restating prior year financial statements.
The components of income tax expense for the years ended December 31,
1993, 1992 and 1991 are as follows:
1993 1992 1991
---- ---- ----
(Dollars in thousands)
Taxes on operating income:
Current federal income tax $ 4,236 $ 4,926 $ 4,003
Deferred federal income tax (1,059) (1,840) (1,285)
Current state income tax 1,097 1,285 1,024
Deferred state income tax 80 (329) 483
Investment tax credit adjustment (577) (641) (740)
______ ______ ______
3,777 3,401 3,485
______ ______ ______
Taxes on other income:
Current federal income tax 496 598 353
Current state income tax 127 158 94
______ ______ ______
623 756 447
______ ______ ______
Total income taxes $ 4,400 $ 4,157 $ 3,932
====== ====== ======
A reconciliation of the Company's effective income tax rates with the
federal statutory rate is as follows:
1993 1992 1991
---- ---- ----
Federal statutory rate 35.0% 34.0% 34.0%
State income taxes, net of federal income tax benefit 6.9 6.1 6.1
Investment credit (4.7) (5.3) (6.0)
Book depreciation in excess of tax basis 2.0 1.9 1.7
AFUDC equity 0.6 0.9 0.9
Flowback of excess deferred taxes (3.6) (3.1) (6.7)
Other (0.1) (0.1) 1.7
____ ____ ____
36.1% 34.4% 31.7%
==== ==== ====
The items comprising deferred income tax expense are as follows:
1993 1992 1991
---- ---- ----
(Dollars in thousands)
Decommissioning expense not currently deductible $ (351) $ (104) $ 14
Tax depreciation over (under) financial statement
depreciation (978) (679) 955
Tax fuel amortization over (under) financial
statement amortization (255) (637) (1,389)
Tax loss on reacquisition of debt over (under)
financial statement expense 1,887 187 178
Pension expense not currently deductible (167) (192) (562)
Postemployment benefits deduction over (under)
financial statement expense 67 (141) ---
Amortization of materials and supplies not
currently deductible (335) (343) (239)
Low-level waste deduction over (under) financial
statement expense (596) 139 825
Flowback of excess deferred taxes (442) (376) (828)
Other 191 (23) 245
______ ______ ______
$ (979) $(2,169) $ (801)
====== ====== ======
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31, 1993 and January 1, 1993 are presented below:
December 31, January 1,
1993 1993
------------ ----------
(Dollars in thousands)
Deferred tax assets:
Accumulated amortization of final nuclear core $ 2,914 $ 2,559
Nuclear decommissioning liability 2,810 2,291
Regulatory liabilities 5,856 6,793
Accumulated deferred investment credit 2,830 2,984
Accumulated amortization of materials and supplies 2,281 1,851
Other 2,771 4,591
______ ______
Total gross deferred tax assets 19,462 21,069
Less valuation allowance 1,231 1,142
______ ______
Net deferred tax assets 18,231 19,927
______ ______
Deferred tax liabilities:
Plant and equipment (51,258) (51,399)
Other (5,220) (5,574)
______ ______
Total gross deferred tax liabilities (56,478) (56,973)
______ ______
Net deferred tax liability (38,247) (37,046)
====== ======
The valuation allowance is the result of a provision in Vermont tax law
which limits refunds resulting from carrybacks of net operating losses.
NOTE 11. Supplemental Cash Flow Information
The following information supplements the cash flow information provided in
the Statements of Cash Flows:
1993 1992 1991
---- ---- ----
(Dollars in thousands)
Cash paid during the year for:
Interest (net of amount capitalized) $7,632 $7,062 $7,990
===== ===== =====
Income taxes $7,070 $6,192 $4,793
===== ===== =====
NOTE 12. Pension Plans
The Company has two noncontributory pension plans covering substantially
all of its regular employees. The Company's funding policy is to fund the
net periodic pension expense accrued each year. Benefits are based on age,
years of service and the level of compensation during the final years of
employment.
The aggregate funded status of the Company's pension plans as of December
31, 1993 and 1992 is as follows:
December 31,
------------
1993 1992
---- ----
(Dollars in thousands)
Vested benefits $ 8,882 $ 6,548
Nonvested benefits 1,338 918
______ ______
Accumulated benefit obligation 10,220 7,466
Additional benefits related to future compensation levels 8,540 7,728
______ ______
Projected benefit obligation 18,760 15,194
Fair value of plan assets, invested primarily in
equities and bonds 16,343 13,791
______ ______
Projected benefit obligation in excess of plan assets $ 2,417 $ 1,403
====== ======
The increase in the projected benefit obligation from $15.2 million in
1992 to $18.8 million in 1993 is the result of additional service
accruals, interest costs and changed plan assumptions.
Certain changes in the items shown above are not recognized as they
occur, but are amortized systematically over subsequent periods.
Unrecognized amounts still to be amortized and the amount that is
included in the balance sheet appear below.
December 31,
------------
1993 1992
---- ----
(Dollars in thousands)
Unrecognized net transition obligation $ 996 $ 1,057
Unrecognized net gain (4,086) (4,939)
Pension liability included in balance sheet 4,866 4,610
Unrecognized prior service costs 641 675
______ ______
Projected benefit obligation in excess of
plan assets $ 2,417 $ 1,403
====== ======
The following are pension plan assumptions as of December 31, 1993 and
1992:
December 31,
------------
1993 1992
---- ----
Discount rate 7.0% 8.0%
Compensation scale 5.5% 6.5%
Expected return on assets 8.5% 8.5%
Net pension expense for the three years ending December 31, 1993 included
the following components:
1993 1992 1991
---- ---- ----
(Dollars in thousands)
Service cost - benefits earned $ 1,141 $ 1,275 $ 1,147
Interest cost on projected benefit obligation 1,288 1,305 1,104
Actual (return) loss on plan assets (1,792) (867) (2,124)
Net amortization and deferral 631 78 1,452
______ ______ ______
Net pension expense $ 1,268 $ 1,791 $ 1,579
====== ====== ======
NOTE 13. Postretirement Benefits Other Than Pensions
The Company adopted Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions"
(SFAS 106), on January 1, 1992. This statement requires companies to
use accrual accounting for postretirement benefits other than pensions.
Prior to 1992, the Company accrued and collected a portion of
postretirement benefits costs through decommissioning billings while the
remaining cost was expensed when benefits were paid. The incremental
cost, above the amount collected through decommissioning billings,
approximately $2.4 million, is now accrued and since January, 1992, has
been included in the Company's monthly power billings to Sponsors. The
Company is funding this liability by placing monies in separate trusts.
In order to maximize the deductible contributions permitted under IRS
regulations, the Company has amended its pension plans and established
separate VEBA trusts for management and union employees.
In December, 1992, the FERC issued its policy statement setting forth
how utilities can recover in rates the increased costs associated with
the implementation of SFAS 106. The policy statement specifies three
conditions that must be met before FERC will consider companies'
election of the accrual method: (a) the Company must agree to make cash
deposits to an irrevocable external trust fund, at least quarterly, in
amounts that are proportional and, on an annual basis, equal to the
annual test period allowance for postretirement benefits other than
pensions; (b) the Company must agree to maximize the use of income tax
deductions for contributions to funds of this nature; and (c) in order
to recover the transition obligation, the Company must file a general
rate change within three years of adoption of SFAS 106.
The following table presents the plan's funded status reconciled with
amounts recognized in the Company's balance sheets as of December 31,
1993 and December 31, 1992 (dollars in thousands):
Accumulated postretirement benefit obligation:
1993 1992
---- ----
Retirees $ 1,078 $ 1,277
Fully eligible active plan participants 921 1,332
Other active participants 8,071 9,935
______ ______
Total accumulated postretirement benefit obligation 10,070 12,544
Fair value of plan assets, invested primarily in
short-term investments 2,457 1,595
______ ______
Accumulated postretirement benefit
obligation in excess of plan assets $ 7,613 $10,949
====== ======
Unrecognized net transition obligation $ 7,933 $10,314
Unrecognized net gain (1,980) (126)
Accrued postretirement benefit cost collected through
decommissioning billings and included
in accrued liabilities 1,660 761
______ ______
Accumulated postretirement benefit obligation
in excess of plan assets $ 7,613 $10,949
====== ======
The net periodic postretirement benefit cost for 1993 and 1992 includes the
following components (dollars in thousands):
1993 1992
---- ----
Service cost $ 735 $ 958
Interest cost 652 941
Net amortization and deferral 350 543
_____ _____
Net periodic postretirement benefit cost $1,737 $2,442
===== =====
For measurement purposes, a 15% annual rate of increase in the per
capita cost of covered benefits (i.e., health care cost trend rate) was
assumed for 1993; the rate was assumed to decrease gradually to 6% by
the year 2001 and remain at that level thereafter. The health care cost
trend rate assumption has a significant effect on the amounts reported.
For example, increasing the assumed health care cost trend rates by one
percentage point in each year would increase the accumulated
postretirement benefit obligation as of December 31, 1993 by $2.2
million and the aggregate of the service and interest cost components of
net periodic postretirement benefit cost for the year ended December 31,
1993 by $0.3 million. The weighted-average discount rate used in
determining the accumulated postretirement benefit obligation was 7% at
December 31, 1993.
The change in the accumulated postretirement benefit obligation from
$12.5 million in 1992 to $10.0 million in 1993 is the result of
adjustments made to reflect a lower actual medical cost increase during
1993 than projected. The reduction in the unrecognized net transition
obligation from $10.3 million in 1992 to $7.9 million in 1993 is
primarily the result of elimination of Medicare Part B coverage.
NOTE 14. Lease Commitments
The Company leases equipment and systems under noncancelable operating
leases. Charges against income for rentals under these leases were
approximately $3.7 million, $2.6 million and $3.7 million in 1993, 1992
and 1991, respectively. Minimum future rentals as of December 31, 1993
are as follows:
Fiscal years ended Annual rentals
- ------------------ --------------
(Dollars in thousands)
1994 $3,283
1995 3,060
1996 2,878
1997 2,798
1998 and after 5,053
The Company has entered into an agreement with General Electric Capital
Corporation to lease certain equipment being constructed by General
Electric Corporation valued at approximately $29 million including
installation costs. Under the lease agreement, the Company will make 120
monthly payments of $342,358 per month commencing on the later of (1)
April 15, 1995 or (2) the commissioning date of the equipment. The
lease will also include the sale and leaseback of a $2 million turbine
rotor forging previously owned by the Company. The lease will be
classified as an operating lease for accounting purposes.
The construction contract requires progress payments to be paid by
Vermont Yankee prior to installation of the equipment. Just prior to
delivery of the equipment, the lessor will reimburse Vermont Yankee for
these payments and will continue to make the remaining payments until
the commencement date of the lease. During the time period subsequent
to equipment delivery before the equipment is commissioned, the Company
will pay interim rent to the lessor based on the amount of outstanding
progress payments. The final documentation of the lease is currently
being negotiated, and if a final agreement cannot be reached, the
Company would be responsible for substantial termination payments.
NOTE 15. Commitments and Contingencies
Low-level Waste
In February, 1993, the Vermont Public Service Board issued an order
which requires the Company to pay its share of expenses incurred by the
Vermont Low Level Radioactive Waste Authority for the period April, 1993
through June, 1994, currently capped at $4.5 million. In addition, in
accordance with Vermont Act 296, the order established a fund for the
long-term care of any eventual Vermont low-level waste disposal
facility. Based on this order, the Company must make annual payments of
approximately $0.8 million into the long-term care fund. Payments made
to the VLLRWA, not pertaining directly to the siting and construction of
a low-level waste disposal facility, are being expensed currently.
In parallel with siting a low-level radioactive waste facility in
Vermont, there has been a three-state effort between Vermont, Maine, and
Texas to form a compact to site such a facility in Texas. The Texas
Legislature has approved, and Governor Ann Richards of Texas has signed
into law, a bill that would form such a compact. On November 2, 1993,
Maine voters ratified the compact. Early during its 1994 session, the
Vermont Legislature is scheduled to vote to approve entry into the
compact. Following approval by the Vermont Legislature, the compact
will require approval of the U.S. Congress.
If the compact is successful and proceeds on schedule, Vermont Yankee
would begin sending its waste to a Texas facility during 1997. Under
the proposed compact, Vermont would pay the State of Texas $25 million
($12.5 million when the U.S. Congress ratifies the compact and $12.5
million when the facility opens). In addition, Vermont must pay $2.5
million ($1.25 million when Congress ratifies the compact and $1.25
million when the facility is licensed) for community assistance projects
in Hudspeth County, Texas, where the facility is to be located. Vermont
would also pay one-third of the Texas Low-Level Radioactive Waste
Disposal Compact Commission's expenses until the facility opens. The
Disposal fees for generators in Vermont and Maine would then be set at a
level that is the same for generators in Texas. The Company anticipates
recovering the costs of the compact from sponsors.
Nuclear Fuel
The Company 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 the Company to cancel
or postpone deliveries until actually needed.
Insurance
The Price-Anderson Act, as amended, currently limits public liability
from a single incident at a nuclear power plant to $9.4 billion. Any
damages beyond $9.4 billion are indemnified under an agreement with the
NRC, but subject to Congressional approval. The first $200 million of
liability coverage is the maximum provided by private insurance. The
Secondary Financial Protection program is a retrospective insurance plan
providing additional coverage up to $9.2 billion per incident by
assessing retrospective premiums of $79.3 million against each of the
116 reactor units that are currently subject to the Program in the
United States, limited to a maximum assessment of $10 million per
incident per nuclear unit in any one year. The maximum assessment is to
be adjusted at least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities
prior to January 1, 1988, for bodily injury claims. The Company has
purchased a Master Worker insurance policy with limits of $200 million
with one automatic reinstatement of policy limits to cover workers
employed on or after January 1, 1988. Vermont Yankee's estimated
contingent liability for a retrospective premium on the Master Workers
policy as of December, 1993 is $3.1 million. The Secondary Financial
Protection program referenced above provides coverage in excess of the
Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL II) 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 the Company with respect to losses arising
during the current policy year is $5.8 million at the time of a first
loss and $12.3 million at the time of a subsequent loss. The Company'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.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule I
Marketable Securities - Other Investments
(Dollars in Thousands)
_____________________________________________________________________________________
Name of Issuer and Number of Cost of Market Value Amount at Which
Title of Each Issue Shares or Each Issue of Each Issue Each Portfolio
Units - * at 12/31/93 of Equity
Principal Security Issues
Amounts of and Each Other
Bonds and Security Issue
Notes Is Carried
on the
Balance Sheet
_____________________________________________________________________________________
Decommissioning fund:
U.S. Treasury obligations $16,252 $17,262 $ 18,666 $17,262
Municipal obligations 78,055 79,755 84,576 79,755
Money market funds and
Accrued Interest 1,863 1,863 1,863 1,863
______ ______ _______ ______
$96,170 $98,880 $105,105 $98,880
====== ====== ======= ======
Disposal fee defeasance fund:
Short-term investments $40,200 $39,870 $39,870 $39,870
Corporate bonds and notes 3,200 3,195 3,083 3,195
Money market funds and
Accrued Interest 419 419 419 419
______ ______ _______ ______
$43,819 $43,484 $43,372 $43,484
====== ====== ======= ======
*Cost includes accrued interest and amortization of premiums and discounts.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule V - Property, Plant and Equipment
Years Ended December 31, 1993, 1992, and 1991
($000)
1993 1992 1991
---- ---- ----
Electric Plant:
Land and land rights $ 1,397 $ 1,127 $ 984
Structures and improvements 61,887 61,868 61,515
Reactor, turbogenerator and
accessory equipment 304,388 292,561 285,808
Transmission equipment 5,948 5,606 6,141
Other 1,116 1,116 1,116
Construction work in progress 597 6,408 4,188
_______ _______ _______
375,333 368,686 359,752
_______ _______ _______
Nuclear Fuel:
Assemblies in reactor 69,063 74,025 83,213
Fuel in process --- 5,236 637
Fuel in stock --- --- 22,863
Spent fuel 287,700 259,199 227,040
_______ _______ _______
356,763 338,460 333,753
_______ _______ _______
Total $732,096 $707,146 $693,505
======= ======= =======
Neither total additions of $25,361,000, $15,167,000 or $25,002,000 nor
total retirements of $411,000, $1,526,000, or $0 for the years ended
December 31, 1993, 1992 and 1991, respectively, exceeded 10% of the
utility plant balance at the end of the year.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule VI - Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
Years Ended December 31, 1993, 1992 and 1991
(Dollars in Thousands)
Additions Other
Balance Charged to Charges Balance
Beginning Costs and and At End
of Year Expenses Retirements (Deduct) of Year
--------- ---------- ----------- -------- -------
Accumulated depreciation
of electric plant: (A)
1993 185,263 13,707 (411) (170) (B) 198,389
1992 173,827 13,253 (1,526) (291) (B) 185,263
1991 162,065 11,800 --- ( 38) (B) 173,827
Accumulated amortization
of nuclear fuel:
1993 308,848 19,526 --- (4,115) (C) 324,259
1992 291,013 21,240 --- (3,405) (C) 308,848
1991 270,011 24,864 --- (3,862) (C) 291,013
Total accumulated
depreciation and
amortization
1993 494,111 33,234 (411) (4,286) 522,648
1992 464,840 34,493 (1,526) (3,696) 494,111
1991 432,076 36,664 --- (3,900) 464,840
(A) Electric plant is being depreciated on the straight-line method at rates designed to
fully depreciate all depreciable properties by 2012. (See Note 1 to the financial
statements).
(B) Represents net salvage and removal costs.
(C) Represents disposal costs of spent nuclear fuel.
EXHIBIT 23-a-2
CONSENT OF INDEPENDENT AUDITORS
The Board of Directors
Green Mountain Nuclear Power Corporation:
We consent to the incorporation by reference in the Registration
Statement on Form S-3, File No. 3-48882 and in the Registration
Statement on Form S-8, File No. 33-47985, of our report dated February
5, 1993, relating to the balance sheet of Vermont Yankee Nuclear Power
Corporation as of December 31, 1992 and the related statements of income
and retained earnings and cash flows for each of the years in the two-
year period ended December 31, 1992, which report is included in the
December 31, 1993 Annual Report on Form 10-K of Green Mountain Power
Corporation.
Boston, Massachusetts
March 28, 1994 KPMG Peat Marwick
EXHIBIT 23-a-1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated February 1, 1994 included in this
Form 10-K, into the Company's previously filed Registration Statement on
Form S-3, File No. 33-48882, and into the Company's previously filed
Registration Statement on Form S-8, File No. 33-47985.
Boston, Massachusetts
March 30, 1994 /s/ Arthur Andersen & Co.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements of Green Mountain Power
Corporation included in this Form 10-K and have issued our report
thereon dated February 1, 1994. Our audit was made for the purpose of
forming an opinion on the basic financial statements taken as a whole.
The schedules listed in the index on page 38 of this Form 10-K are the
responsibility of the Company's management and are presented for
purposes of complying with the Securities and Exchange Commission's
rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the
audit of the basic financial statements, and in our opinion, fairly
state, in all material respects, the financial data required to be set
forth therein in relation to the basic financial statements taken as a
whole.
Boston, Massachusetts
February 1, 1994 /s/ Arthur Andersen & Co.