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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
___ Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from ________________ to __________________
For the fiscal year ended December 31, 1998
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 Identification No.)
incorporation or organization)
25 Green Mountain Drive
South Burlington, VT 05403
_________________________________ __________
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (802) 864-5731
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each exchange on which registered
COMMON STOCK, PAR VALUE NEW YORK STOCK EXCHANGE
$3.33-1/3 PER SHARE
________________________________________________________________________
Securities registered pursuant to Section 12 (g) of the Act: None
________________________________________________________________________
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes __X__ No _____
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. _X_
The aggregate market value of the voting stock held by non-
affiliates of the registrant as of March 12, 1999, was $55,551,767.19
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 12, 1999,
was 5,322,325.
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 20, 1999, 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 approximately one quarter of the State's
population. We serve approximately 83,500 customers. The Company was
incorporated under the laws of the State of Vermont on April 7, 1893.
Our sources of revenue for the year ended December 31, 1998 were as
follows:
33.5% from residential customers,
33.5% from small commercial and industrial customers,
21.8% from large commercial and industrial customers,
9.0% from sales to other utilities, and
2.2% from other sources.
During 1998, our energy resources for retail and wholesale sales of
electricity were obtained as follows:
44.0% from hydroelectric sources (7.8% Company-owned, 0.1% New York
Power Authority (NYPA), 32.8% Hydro-Quebec and 3.3% small
power producers),
27.5% from a nuclear generating source (the Vermont Yankee nuclear
plant described below),
2.0% from coal sources,
3.5% from wood,
2.4% from natural gas,
1.5% from oil, and
0.6% from wind.
The remaining 18.5% was purchased on a short-term basis from other
utilities through the New England Power Pool (NEPOOL).
In 1998, we purchased 91.4% of the energy required to satisfy our
retail and wholesale sales of electricity (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 our entitlement to
a share of the power generated by the 531-MW Vermont Yankee nuclear
generating plant owned and operated by Vermont Yankee Nuclear Power
Corporation (Vermont Yankee). We have a 17.9% equity interest in
Vermont Yankee. For information concerning Vermont Yankee, see "Power
Resources - Vermont Yankee."
We participate in NEPOOL, a regional bulk power transmission
organization established to assure reliable and economical power supply
in the Northeast. Our representative to NEPOOL is Vermont Electric
Power Company, Inc. (VELCO), a transmission consortium owned by the
Company and other Vermont utilities, in which we have a 30% equity
interest. As a member of NEPOOL, we benefit from increased efficiencies
of centralized economic dispatch, availability of replacement power for
scheduled and unscheduled outages of our own power sources, sharing of
bulk transmission facilities and reduced generation reserve
requirements.
Our principal service territory is 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. We also distribute electricity
in four separate areas located in southern and southeastern Vermont that
are interconnected with our principal service area through the
transmission lines of VELCO and others. Included in these areas are the
communities of Vernon (where the Vermont Yankee plant is located),
Bellows Falls, White River Junction, Wilder, Wilmington and Dover. We
supply at wholesale a portion of the power requirements of several
municipalities and cooperatives in Vermont. We are obligated to meet
the changing electrical requirements of these wholesale customers, in
contrast to our obligation to other wholesale customers, which is
limited to specified amounts of capacity and energy established by
contract.
Major business activities in our 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.
Our largest customer is International Business Machines (IBM).
Electric energy sales to IBM for the years ended December 31, 1998, 1997
and 1996, accounted for 14.7%, 14.0% and 13.2%, respectively, of our
operating revenues in those years. No other retail customer accounted
for more than 1.0% of our revenue. Under the present regulatory system,
the loss of IBM as a customer would require the Company to seek rate
relief to recover the revenues previously paid by IBM from other
customers in an amount sufficient to offset the fixed costs that IBM had
been covering through its payments.
EMPLOYEES
As of December 31, 1998, the Company had 288 employees, exclusive
of temporary employees, and our subsidiary, Mountain Energy Inc., had
six employees.
SEASONAL NATURE OF BUSINESS
Winter recreational activities, longer hours of darkness and
heating loads from cold weather usually cause our peak electric sales to
occur in December, January or February. Our heaviest load in 1998 -
312.5 MW - occurred on January 14, 1998.
We charge our customers higher rates for billing cycles in
December through March and lower rates for the remaining months. These
are called "seasonally differentiated rates". In order to eliminate the
impact of the seasonally differentiated rates on earnings, we defer some
of the revenues from those four months and account for them in later
periods in which we have lower revenues or higher costs. By deferring
certain revenues we are able to match our revenues to our costs more
accurately.
Under this structure, retail electric rates produce average
revenues per kilowatthour during four peak season months (December
through March) that are approximately 30% higher than during the eight
off-season months (April through November). See "Energy Efficiency" and
"Rate Design."
OPERATING STATISTICS
For the Years Ended December 31
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
Net System Capability During Peak Month (MW)
Hydro (1)............................................ 174.8 180.0 193.8 152.1 179.0
Lease transmissions.................................. 0.6 0.6 0.6 0.3 2.1
Nuclear (1).......................................... 95.7 95.7 95.7 81.9 107.2
Conventional steam................................... 53.0 53.0 52.9 77.8 67.1
Internal combustion.................................. 49.0 64.0 60.7 62.0 60.2
Combined cycle....................................... 22.1 22.1 22.1 22.0 22.6
Wind................................................. 1.7 1.5 -- -- --
---------- ---------- ---------- ---------- ----------
Total capability (MW).............................. 396.9 416.9 425.8 396.1 438.2
Net system peak...................................... 312.5 311.5 313.0 297.1 308.3
---------- ---------- ---------- ---------- ----------
Reserve (MW)......................................... 84.4 105.4 112.8 99.0 129.9
========== ========== ========== ========== ==========
Reserve % of peak.................................... 27.0% 33.8% 36.0% 33.3% 42.1%
Net Production (MWH)
Hydro (1)............................................ 972,723 1,073,246 1,192,881 1,043,617 742,088
Lease transmissions.................................. -- -- -- -- --
Nuclear (1).......................................... 607,708 772,030 680,613 682,814 763,690
Conventional steam................................... 750,602 560,504 705,331 673,982 651,105
Internal combustion.................................. 40,148 4,827 2,674 6,646 3,532
Combined cycle....................................... 118,322 104,836 51,162 92,723 37,808
---------- ---------- ---------- ---------- ----------
Total production...................................2,489,503 2,515,443 2,632,661 2,499,782 2,198,223
Less non-requirements sales to other utilities....... 499,409 524,192 663,175 582,942 328,794
---------- ---------- ---------- ---------- ----------
Production for requirements sales....................1,990,094 1,991,251 1,969,486 1,916,840 1,869,429
Less requirements sales & lease transmissions (MWH)..1,883,959 1,870,913 1,814,371 1,760,830 1,730,497
---------- ---------- ---------- ---------- ----------
Losses and company use (MWH)......................... 106,135 120,338 155,115 156,010 138,932
========== ========== ========== ========== ==========
Losses as a percentage of total production............. 4.26% 4.78% 5.89% 6.24% 6.32%
System load factor (2)................................. 71.8% 71.6% 69.7% 71.2% 67.7%
Sales and Lease Transmissions (MWH)
Residential - GMP.................................... 533,904 549,259 557,726 549,296 564,635
Lease transmissons................................... -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 533,904 549,259 557,726 549,296 564,635
Commercial & industrial - small...................... 665,707 645,331 630,839 608,688 604,686
Commercial & industrial - large...................... 636,436 608,051 584,249 556,278 521,400
Other................................................ 3,476 3,939 2,898 8,855 1,146
---------- ---------- ---------- ---------- ----------
Total retail sales and lease transmissions.........1,839,522 1,806,580 1,775,712 1,723,117 1,691,867
Sales to municipals and cooperatives 44,437 64,333 38,659 37,713 38,630
---------- ---------- ---------- ---------- ----------
Total requirements sales...........................1,883,959 1,870,913 1,814,371 1,760,830 1,730,497
Other sales for resale............................... 499,409 524,192 663,175 582,942 328,794
---------- ---------- ---------- ---------- ----------
Total sales and lease transmissions................2,383,368 2,395,105 2,477,546 2,343,772 2,059,291
========== ========== ========== ========== ==========
Average Number of Electric Customers
Residential.......................................... 71,301 70,671 70,198 69,659 68,811
Commercial and industrial - small.................... 12,170 11,989 11,828 11,712 11,611
Commercial and industrial - large.................... 23 23 25 24 24
Other................................................ 70 75 75 76 76
---------- ---------- ---------- ---------- ----------
Total.............................................. 83,564 82,758 82,126 81,471 80,522
========== ========== ========== ========== ==========
Average Revenue per KWH (Cents)
Residential including lease revenues................. 11.56 11.18 10.87 10.09 9.03
Lease charges........................................ -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 11.56 11.18 10.87 10.09 9.03
Commercial and industrial - small.................... 9.29 9.10 8.96 8.42 8.00
Commercial and industrial - large.................... 6.32 6.22 6.28 5.86 6.02
Total retail including lease revenues................ 8.96 8.94 8.92 8.36 7.96
Average Use and Revenue Per Residential Customer
Kilowatt hours including lease transmissions......... 7,488 7,772 7,945 7,885 8,206
Revenues including lease revenues.................... $865 $869 $863 $796 $741
(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.
STATE AND FEDERAL REGULATION
General. The Company is subject to the regulatory authority of the
Vermont Public Service Board (VPSB), which extends to retail rates,
services and facilities, securities issues and various other matters.
The separate Vermont Department of Public Service (the Department),
created by statute in 1981, is responsible for development of energy
supply plans for the State of Vermont (the State), purchases of power as
an agent for the State and other general regulatory matters. The VPSB
principally conducts quasi-judicial proceedings, such as rate setting.
The Department, through a Director for Public Advocacy, is entitled to
participate as a litigant in such proceedings and regularly does so.
Our rate tariffs are uniform throughout our service area. We have
entered into a number of jobs incentive agreements, providing for
reduced capacity charges to large customers applicable only to new load.
We have an economic development agreement with IBM that provides for
contractually established charges, rather than tariff rates, for
incremental loads. See Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Results of Operations -
Operating Revenues and MWh Sales."
Our wholesale rate on sales to two wholesale customers is regulated
by the Federal Energy Regulatory Commission (FERC). Revenues from sales
to these customers were approximately 0.9% of operating revenues for
1998.
Late in 1989, we began serving a municipal utility, Northfield
Electric Department, under our wholesale tariff. This customer
increased our electricity sales in 1998 by approximately 24,064.6 MWh
and peak requirements by approximately 5.5 MW. Revenues in 1998 from
Northfield were $1,462,549.
We provide transmission service to twelve customers within the
State under rates regulated by the FERC; revenues for such services
amounted to less than 1.0% of the Company's operating revenues for 1998.
On April 24, 1996, the FERC issued Orders 888 and 889 that among
other things required the filing of open access transmission tariffs by
electric utilities. See Item 7. Management's Discussion and Analysis Of
Financial Condition And Results Of Operations - "Transmission Issues -
Federal Open Access Tariff Orders." NEPOOL's Open Access tariff for
certain transmission facilities, including certain facilities between
New York and New England, incorporates a load-based method of capacity
allocation for NEPOOL transmission facilities. The Open Access tariff
could reduce the amount of capacity available to the Company from such
facilities in the future. See Item 7. Management's Discussion and
Analysis Of Financial Condition and Results Of Operations -
"Transmission Issues - NEPOOL Transmission Tariff."
The Company has equity interests in Vermont Yankee, VELCO and
Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned
subsidiary of VELCO. We have filed an exemption statement under Section
3(a)(2) of the Public Utility Holding Company Act of 1935, thereby
securing exemption from the provisions of such Act, except for Section
9(a)(2), which prohibits the acquisition of securities of certain other
utility companies without approval of the Securities and Exchange
Commission (SEC). The SEC 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-electric projects owned by the Company:
Project Issue Date Period
- ------- ---------- ------
Bolton February 5, 1982 February 5, 1982 - February 4, 2022
Essex March 30, 1995 March 1, 1995 - March 1, 2025
Vergennes June 29, 1979 June 1, 1949 - May 31, 1999
Waterbury July 20, 1954 September 1, 1951 - August 31, 2001
Major project licenses provide that after an initial twenty-year
period, a portion of the earnings of such project in excess of a
specified rate of return is to be set aside in appropriated retained
earnings in compliance with FERC Order #5, issued in 1978. Although the
twenty-year periods expired in 1985, 1969 and 1971 in the cases of the
Essex, Vergennes and Waterbury projects, respectively, the amounts
appropriated are not material.
The relicensing application for Vergennes is on file with the FERC
and the relicensing application for Waterbury is being prepared for
filing. We expect both projects to be relicensed for a 30 year term in
the near future and does not have any competition for the licenses.
Department of Public Service Twenty-Year Electric Plan. In
December 1994, the Department adopted an update of its twenty-year
electrical power-supply plan (the Plan) for the State. The Plan
includes an overview of statewide growth and development as they relate
to future requirements for electrical energy; an assessment of available
energy resources; and estimates of future electrical energy demand.
In June 1996, we filed with the VPSB and the Department an
integrated resource plan pursuant to Vermont Statute 30 V.S.A. Section 218c.
That filing is still pending before the VPSB.
RECENT RATE DEVELOPMENTS
On May 8, 1998, we filed a request with the VPSB to increase retail
rates by 12.9 percent. The retail rate increase is needed to cover
higher power supply costs, the cost of the January 1998 ice storm,
higher taxes and investments in new plant and equipment.
On November 18, 1998, by Memorandum of Understanding (MOU), the
Company, the Department and IBM agreed to:
- implementation of a temporary rate increase of 5.7 percent,
effective December 15, 1998, with the potential for an additional
surcharge in order to produce additional revenues necessary to
provide the Company with the capacity to finance estimated 1999
Pine Street Barge Canal site expenditures of $5.8 million, and
- to stay, effective November 16, 1998, further rate proceedings in
this rate case until or after September 1, 1999, or such earlier
date to which the parties may later agree or the VPSB may order.
For further information regarding recent rate developments, see
Item 7. Management's Discussion and Analysis Of Financial
Condition and Results Of Operations - "Liquidity and Capital
Resources" and Note I of Notes to Consolidated Financial
Statements.
COMPETITION AND RESTRUCTURING
Electric utilities historically have had exclusive franchises for
the retail sale of electricity in specified service territories.
Legislative authority has existed since 1941 that would permit Vermont
cities, towns and villages to own and operate public utilities. Since
that time, no municipality served by the Company has established or, as
far as is known to the Company, is presently taking steps to establish a
municipal public utility.
In 1987, the Vermont General Assembly enacted legislation that
authorized the Department to sell electricity on a significantly
expanded basis. Before the new law was passed, the Department's
authority to make retail sales had been limited. It could sell at
retail only to residential and farm customers and could sell only power
that it had purchased from the Niagara and St. Lawrence projects
operated by the New York Power Authority.
Under the law, the Department can sell electricity purchased from
any source at retail to all customer classes throughout the State, but
only if it convinces the VPSB and other State officials that the public
good will be served by such sales. The Department has made limited
additional retail sales of electricity. The Department retains its
traditional responsibilities of public advocacy before the VPSB and
electricity planning on a statewide basis.
Regulatory and legislative authorities at the federal level and
among states across the country, including Vermont, are considering how
to restructure the electric utility industry to facilitate competition
for electricity sales at wholesale and retail levels. For further
information regarding Competition and Restructuring, See Item 7.
Management's Discussion and Analysis of Financial Condition and Results
of Operations - "Future Outlook."
POWER RESOURCES
The Company has agreed to enter into a contract with Morgan Stanley
Capital Group, Inc. as the result of our all power requirements
solicitation in 1998. See Note L of Notes to Consolidated Financial
Statements "Power Purchase and Supply Agreement".
The Company generated, purchased or transmitted 1,977,647.5 MWh of
energy for retail and requirements wholesale customers for the twelve
months ended December 31, 1998. The corresponding maximum one-hour
integrated demand during that period was 312.5 MW on January 14, 1998.
This compares to the all-time peak of 322.6 MW on December 27, 1989.
The following table shows the net generated and purchased energy, the
source of such energy for the twelve-month period and the capacity in
the month of the period system peak. See Note K of Notes to
Consolidated Financial Statements.
Net Generated and Net Generated and
Purchased in Year Purchased at Time
Ended 12/31/98 (a) of Annual Peak
___________________ ___________________
MWh % KW %
WHOLLY OWNED PLANTS
Hydro . . . . . . . . . . . . . 162,358.0 7.8 35,310 8.9
Diesel and Gas Turbine . . . . 4,647.8 0.2 46,030 11.6
Searsburg . . . . . . . . . . . 12,886.3 0.6 1,690 0.4
JOINTLY OWNED PLANTS
Wyman #4 . . . . . . . . . . . 14,144.5 0.7 7,030 1.8
Stony Brook I . . . . . . . . . 21,471.3 1.0 7,990 2.0
McNeil . . . . . . . . . . . . 14,192.3 0.7 6,450 1.6
OWNED IN ASSOCIATION W/OTHERS
Vermont Yankee Nuclear . . . . 571,407.1 27.5 95,680 24.1
NYPA LEASE TRANSMISSIONS
State of Vermont (NYPA) . . . . 1,650.3 0.1 620 0.2
LONG-TERM PURCHASES
Hydro-Quebec . . . . . . . . . 682,197.0 32.8 121,690 30.7
Merrimack #2 . . . . . . . . . 40,721.1 2.0 31,820 8.0
Stony Brook I . . . . . . . . 41,679.7 2.0 14,150 3.6
Small Power Producers . . . . . 126,507.7 6.1 24,650 6.2
SHORT-TERM PURCHASES . . . . . . 386,926.4 18.5 3,860 .9
___________ ____ _______ _____
Less System Sales Energy . . . (103,142.0)
NET OWN LOAD . . . . . . . . 1,977,647.5 100.0 396,970 100.0
=========== ====== ======= ======
(a) Excludes losses on off-system purchases, totaling 24,189 MWh per GA-
35 MWh production report.
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 531 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 our power contract, we
are 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, we sold
to other Vermont utilities a share of our entitlement to the output of
Vermont Yankee. Accordingly, those utilities have an aggregate
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. As a result of the bankruptcy of one of those
utilities, a portion of the entitlement has reverted back to us.
Accordingly, those utilities have an obligation to pay us 2.338% of
Vermont Yankee's operating expenses, fuel costs, decommissioning
expenses, interest expense and return on common equity, whether or not
the Vermont Yankee plant is operating.
Vermont Yankee has also entered into capital funds agreements with
its sponsor utilities that expire on December 31, 2002. Under our
Capital Funds Agreement, we are required, subject to obtaining necessary
regulatory approvals, to provide 20% of the capital requirements of
Vermont Yankee not obtained from outside sources.
On April 27, 1989, Vermont Yankee applied to the Nuclear Regulatory
Commission (NRC) for an amendment to its operating license to extend the
expiration date from December 2007 to March 2012, in order to take
advantage of current NRC policy to issue operating licenses for a 40-
year term measured from the grant of the operating license. Prior NRC
policy, under which the operating license was issued, called for a term
of 40 years from the date of the construction permit. On August 22,
1989, the State, 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 to 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's
assertions. On July 31, 1991, Vermont Yankee reached a settlement with
the State, and the State filed a withdrawal of its intervention. The
proceeding was dismissed on September 3, 1991.
The NRC's most recently issued Systematic Assessment of Licensee
Performance scores for Vermont Yankee are for the period January 19, 1997
to July 18, 1998. Operations, engineering, maintenance and plant
support were rated good. These scores were identical to Vermont Yankee's
scores for the prior 18 month-period except for plant support, which
declined from superior.
During periods when Vermont Yankee is unavailable, we incur
replacement power costs in excess of those costs that we would have
incurred for power purchased from Vermont Yankee. Replacement power is
available to us from NEPOOL and through 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 rate making purposes over the period until the next
scheduled outage. Vermont Yankee has adopted an 18-month refueling
schedule. On March 21, 1998, Vermont Yankee began a scheduled refueling
outage, which concluded June 3, 1998. The 1999 refueling outage is
scheduled to begin October 29, 1999. In the case of unscheduled outages
of significant duration resulting in substantial unanticipated costs for
replacement power, the VPSB generally has authorized deferral,
amortization and recovery of such costs.
Vermont Yankee's current estimate of decommissioning as approved by
FERC is approximately $407 million, of which $260 million has been
funded. Vermont Yankee is in the process of preparing an updated site
decommissioning cost study. Preliminary results indicate that the
revised estimate could exceed $500 million in 1998 dollars. Vermont
Yankee is required to file the results of the new study with the FERC by
March 31, 1999, and expects that any resulting change in rates will be
effective January 1, 2000. At December 31, 1998, our portion of the net
non-funded liability was $26 million, which we expect will be recovered
through rates over Vermont Yankee's remaining operating life.
During 1998, we incurred $27.2 million in Vermont Yankee annual
capacity charges, which included $2 million for interest charges. Our
share of Vermont Yankee's long-term debt at December 31, 1998 was $16.7
million.
During the year ended December 31, 1998, we utilized 571,407.1 MWh
of Vermont Yankee energy to meet 27.5% of our retail and requirements
wholesale (Rate W) sales. The average cost of Vermont Yankee
electricity in 1998 was 5.7 cents per KWh. Vermont Yankee's annual capacity
factor for 1998 was 73.6%, compared to 93.5% in 1997 and 83.0% in 1996.
The decrease in capacity was due to plant outages.
The Price-Anderson Act currently sets the statutory limit of
liability from a single incident at a nuclear power plant at $9.8
billion. Any damages beyond $9.8 billion are indemnified under the
Price-Anderson Act, 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 $9.6
billion per incident by assessing each of the 109 reactor units that are
currently subject to the Program in the United States a total of $88.1
million, limited to a maximum assessment of $10 million per incident per
nuclear unit in any one year. The maximum assessment is adjusted at
least every five years to reflect inflationary changes.
The above insurance now covers all workers employed at nuclear
facilities for bodily injury claims. Vermont Yankee had previously
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 no longer
participates in this retrospectively-based worker policy and has
replaced this policy with the guaranteed cost coverage mentioned above.
However, Vermont Yankee does retain a potential obligation for
retrospective adjustments due to past operations of several smaller
facilities that did not join the new program. These exposures will
cease to exist no later than December 31, 2007. Vermont Yankee's
maximum retrospective obligation remains at $3.1 million. The Secondary
Financial Protection layer, as referenced above, would be in excess of
the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance
Limited (NEIL) to cover the costs of property damage, decontamination or
premature decommissioning resulting from a nuclear incident. All
companies insured with NEIL are subject to retroactive assessments if
losses exceed the accumulated funds available. The maximum potential
assessment against Vermont Yankee with respect to NEIL losses arising
during the current policy year is $11.0 million. Vermont Yankee's
liability for the retrospective premium adjustment for any policy year
ceases six years after the end of that policy year unless prior demand
has been made.
See Note L-3 of Notes to Consolidated Financial Statements.
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 225-MW AC-to-DC-to-AC converter
terminal and seven miles of 345-kV transmission line. VELCO built and
operates the converter facilities, which we own jointly with a number of
other Vermont utilities.
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 9.0% 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
competitive prices;
- - 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. VETCO 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.
Each participant also pays a proportionate share of the total costs of
service associated with those portions of the transmission facilities
constructed in New Hampshire by a subsidiary of New England Electric
System.
Phase II. Agreements executed in 1985 among the Company, VELCO and
other NEPOOL members and Hydro-Quebec provided for the construction of
the second phase (Phase II) of the interconnection between the New
England Electric System and that of Hydro-Quebec. Phase II expands the
Phase I facilities from 690 MW to 2,000 MW, and provides for
transmission of Hydro-Quebec power from the Phase I terminal in northern
New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II
commenced in 1988 and was completed in late 1990. The Phase II
facilities commenced commercial operation November 1, 1990, initially at
a rating of 1,200 MW, and increased to a transfer capability of 2,000 MW
in July 1991. The Hydro-Quebec-NEPOOL Firm Energy Contract provides for
the import of economical Hydro-Quebec energy into New England. The
Company is entitled to 3.2% of the Phase II power-supply benefits.
Total construction costs for Phase II were approximately $487,000,000.
The New England participants, including the Company, have contracted to
pay monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs.
As a supporting participant, the Company must make support payments
under 30-year agreements. These support agreements meet the capital
lease accounting requirements under SFAS 13. At December 31, 1998, the
present value of the Company's obligation was $7,696,336. The Company's
projected future minimum payments under the Phase II support agreements
are $452,726 for each of the years 1999-2003 and an aggregate of
$5,432,706 for the years 2004-2020.
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, 1998, the capital structure
of such corporations was 41% common equity and 59% long-term debt. See
Note J of Notes to Consolidated Financial Statements.
At times, we request that portions of our power deliveries from
Hydro-Quebec and other sources be routed through New York. Our ability
to do so could be adversely affected by the proposed tariff that NEPOOL
has filed with the FERC, which would reduce our allocation of capacity
on transmission interfaces with New York. As a result, our ability to
import power to Vermont from outside New England could be adversely
affected, thereby impacting our power costs in the future. See Item 7.
Management's Discussion and Analysis Of Financial Condition and Results
Of Operations - "Transmission Issues" and Note J of Notes to
Consolidated Financial Statements.
Hydro-Quebec Power Supply Contracts. We have several purchase
power contracts with Hydro-Quebec. The bulk of our purchases are
comprised of two schedules, B and C3, pursuant to a Firm Contract dated
December 1987. Under these two schedules, we purchase 114.2 MW. Under
an arrangement negotiated in January 1996, the HQ 9601 and the HQ 9602
contracts, we received cash payments from Hydro-Quebec of $3,000,000 in
1996 and $1,100,000 in 1997. In accordance with such arrangement, we
agreed to shift certain transmission requirements, purchase certain
quantities of power and make certain minimum payments for periods in
which power is not purchased. In addition, in November 1996, we entered
into a Memorandum of Understanding with Hydro-Quebec under which Hydro-
Quebec paid $8,000,000 to the Company in exchange for certain power
purchase elections. See Item 7. Management's Discussion And Analysis Of
Financial Condition and Results Of Operations - "Power Supply Expenses"
and Notes J and K-2 of Notes to Consolidated Financial Statements.
In 1998, we utilized 351,012.6 MWh under Schedule B, 260,329.3 MWh
under Schedule C3, and 70,855.1 MWh under HQ 9601 and HQ 9602 to meet
32.8% of our retail and requirements wholesale sales. The average cost
of Hydro-Quebec electricity in 1998 was 6.8 cents per KWh.
New York Power Authority (NYPA). The Department allocates NYPA
power to us, which, in turn, we deliver to our residential and farm
customers. We purchased at wholesale 1,650.3 MWh to meet 0.1% of our
retail and requirements wholesale sales of NYPA power at an average cost
of 5.0 cents per KWh in 1998.
Merrimack Unit #2. Merrimack Unit #2 is a coal-fired steam plant
of 320.0 MW capacity located in Bow, New Hampshire, and owned by
Northeast Utilities. We were entitled to 31.05 MW of capacity and
related energy from the unit under a 30-year contract that expired May
1, 1998.
In 1998, we utilized 40,721.1 MWh from the unit to meet 2.0% of our
total retail and requirements wholesale sales. The average cost of
electricity from this unit was 5.7 cents per KWh in 1998. 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 Stony Brook, a 352.0-
MW combined-cycle intermediate generating station located in Ludlow,
Massachusetts, which commenced commercial operation in November 1981.
We entered into a Joint Ownership Agreement with MMWEC dated as of
October 1, 1977, whereby we acquired an 8.8% ownership share of the
plant, entitling us to 31.0 MW of capacity. In addition to this
entitlement, we have contracted for 14.2 MW of capacity for the life of
the Stony Brook I plant, for which we 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 all capable
of burning oil. 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 1998, we utilized 63,151.0 MWh from this plant to meet 3.0%
of our retail and requirements wholesale sales at an average cost of
4.2 cents. See Note I-4 and K-1 of Notes to Consolidated Financial
Statements.
Wyman Unit #4. The W. F. Wyman Unit #4, which is located in
Yarmouth, Maine, is an oil-fired steam plant with a capacity of 620 MW.
Central Maine Power Company sponsored the construction of this plant.
We have a joint-ownership share of 1.1% (7.1 MW) in the Wyman #4 unit,
which began commercial operation in December 1978.
During 1998, we utilized 14,144.5 MWh from this unit to meet 0.7%
of our retail and requirements wholesale sales at an average cost of
2.4 cents per kWh, based only on operation, maintenance, and fuel costs
incurred during 1998. See Note I-4 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 53.0 MW. We have an 11.0% or 5.8 MW interest in the J. C.
McNeil plant, which began operation in June 1984. In 1989, the plant
added the capability to burn natural gas on an as-
available/interruptible service basis.
During 1998, we utilized 14,192.3 MWh from this unit to meet 0.7%
of our retail and requirements wholesale sales at an average cost of
4.7 cents per kWh, based only on operation, maintenance, and fuel costs
incurred during 1998. See Note I-4 of Notes to Consolidated Financial
Statements.
Independent Power Producers. The VPSB has adopted rules that
implement for Vermont the purchase requirements established by federal
law in the Public Utility Regulatory Policies Act of 1978 (PURPA).
Under the rules, qualifying facilities have the option to sell their
output to a central state-purchasing agent under a variety of long- and
short-term, firm and non-firm pricing schedules. Each of these
schedules is based upon the projected Vermont composite system's power
costs that would be required but for the purchases from independent
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 rate-making purposes.
Currently, the State purchasing agent, Vermont Electric Power
Producers, Inc. (VEPPI), is authorized to seek 150 MW of power from
qualifying facilities under PURPA, of which our average pro rata share
in 1998 was approximately 32.9% or 49.3 MW.
The rated capacity of the qualifying facilities currently selling
power to VEPPI is approximately 74.5 MW. These facilities were all
online by the spring of 1993, and no other projects are under
development. We do not expect any new projects to come online in the
foreseeable future because the excess capacity in the region has
eliminated the need for and value of additional qualifying facilities.
In 1998, through both our direct contracts and VEPPI, we purchased
126,507.7 MWh of qualifying facilities production to meet 6.1% of our
retail and requirements wholesale sales at an average cost of 10.9 cents per
KWh.
Short Term Opportunity Purchases and Sales. We have arrangements
with numerous utilities and power marketers actively trading power in
New England and New York under which we may make purchases or sales of
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 for less than it would cost us to generate
the power with our own sources. Purchases also help us save on
replacement power costs during an outage of one of our base load
sources. Opportunity sales are arranged when we have 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. Prices are
set so as to recover all of the forecasted fuel or production costs and
to recover some, if not all, associated capacity costs.
During 1998, we purchased 386,926.4 MWh, meeting 18.5% of our
retail and requirements wholesale sales, at an average cost of 2.7 cents per
kWh.
NEPOOL. As a participant of NEPOOL, through VELCO, we take
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 us to maintain a generating
capacity reserve as set by NEPOOL, but which is lower than the reserve
which would be required if we were not a NEPOOL participant.
Company Hydroelectric Power. The Company wholly owns and operates
eight hydroelectric generating facilities located on river systems
within its service area, the largest of which has a generating output of
7.8 MW.
In 1998, these plants provided 162.358 MWh of low-cost energy,
meeting 7.8% of our retail and requirements wholesale sales at an
average cost of 3.3 cents per kWh, based on total embedded costs. See "State
and Federal Regulation" - "Licensing."
VELCO. The Company and six other Vermont electric distribution
utilities own 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. In 1986, we entered into an agreement for
the sale to United Illuminating of 23 MW of capacity produced by the
Stony Brook I combined-cycle plant and provided for our recovery of all
costs associated with the capacity and energy sold. The agreement
commenced October 1, 1986 and expired October 31, 1998.
Fuel. During 1998, our retail and requirements wholesale sales
were provided by the following fuel sources:
44.0% from hydro (7.8% Company-owned, 0.1% NYPA, 32.8% Hydro-Quebec and
3.3% from small power producers),
27.5% from nuclear,
2.0% from coal,
3.5% from wood,
2.4% from natural gas,
1.5% from oil,
0.6% from wind, and
18.5% purchased on a short-term basis from other utilities through
NEPOOL.
Vermont Yankee has several "requirement based" contracts for the
four components (uranium, conversion, enrichment and fabrication) used to
produce nuclear fuel. These contracts are executed only if the need or
requirement for fuel arises. Under these contracts, any disruption of
operating activity would allow Vermont Yankee to cancel or postpone
deliveries until actually required. The contracts extend through
various time periods and contain clauses to allow Vermont Yankee the
option to extend the agreements. Negotiation of new contracts and
renegotiations of existing contracts routinely occurs, the latter often
focuses on one of the four components. The price of the 1998 reload was
approximately $22 million. The 1999 reload will also cost approximately
$22 million. Future reload costs will depend on market and contract
prices
On January 20, 1997, Vermont Yankee entered into an agreement with
a former uranium supplier whereby the supplier could opt to terminate a
production purchase agreement dated August 4, 1978. Although there had
been no transactions under the production purchase agreement for several
years, Vermont Yankee maintained certain financial rights. In
consideration for the option to terminate the production purchase
agreement and the subsequent exercise of the option, Vermont Yankee
received $600,000 in 1997, which was recorded as an offset to nuclear
fuel expense. The potential future payments over a ten-year period
range from zero to $2.4 million. No payments were received in 1998
under this agreement. Due to the uncertainty of this transaction, any
benefits received will be recorded on a cash basis.
Vermont Yankee has a contract with the United States Department of
Energy (DOE) for the permanent disposal of spent nuclear fuel. Under
the terms of this contract, in exchange for the one-time fee discussed
below and a quarterly fee of 1 mil per kWh of electricity generated and
sold, the DOE agrees to provide disposal services when a facility for
spent nuclear fuel and other high-level radioactive waste is available,
which is required by contract to be prior to January 31, 1998. The
actual date for these disposal services is expected to be delayed many
years. DOE currently estimates that a permanent disposal facility will
not begin operation before 2010. A DOE temporary disposal site may be
provided in a few years, but no decision has been made to proceed on
providing a temporary disposal site at this time.
The DOE contract obligates Vermont Yankee to pay a one-time fee of
approximately $39.3 million for disposal costs for all spent fuel
discharged through April 7, 1983. Although such amount has been
collected in rates from the Vermont Yankee participants, Vermont Yankee
has elected to defer payment of the fee to the DOE as permitted by the
DOE contract. The fee must be paid no later than the first delivery of
spent nuclear fuel to the DOE. Interest accrues on the unpaid
obligation based on the thirteen-week Treasury Bill rate and is
compounded quarterly. Through 1998, Vermont Yankee accumulated
approximately $98 million in an irrevocable trust to be used exclusively
for defeasing this obligation at some future date, provided the DOE
complies with the terms of the aforementioned contract.
We do not maintain long-term contracts for the supply of oil for
our wholly-owned oil-fired peaking unit generating stations (80 MW). We
did not experience difficulty in obtaining oil for our own units during
1998, and, while no assurance can be given, we do not anticipate any
such difficulty during 1999. None of the utilities from which we expect
to purchase oil- or gas-fired capacity in 1999 has advised us of grounds
for doubt about maintenance of secure sources of oil and gas during the
year.
Merrimack #2 purchased coal under a long-term contract from Balley
Mine in western Pennsylvania and occasionally on the spot market from
northern West Virginia and southern Pennsylvania sources in 1998. Our
contract with Merrimack #2 expired May 1,1998.
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
233,312 tons of wood chips and mill residue and 181.9 million cubic feet
of natural gas in 1998. The McNeil plant is forecasting consumption of
wood chips for 1999 to be 200,000 tons and natural gas consumption of
136 million cubic feet.
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. We assume, 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.
Wind Project. Our 20 years of research and development work in
wind generation was recognized in 1993 when we were selected by the
DOE and the Electric Power Research Institute (EPRI) to build a commercial
scale wind-powered facility. The DOE and EPRI provided partial funding
for the wind project of approximately $3.9 million. The net cost to the
Company of the project, located in the southern Vermont town of Searsburg,
was $7.8 million. The eleven wind turbines have a rating of 6 MW and were
commissioned July 1, 1997.
In 1998, the plant provided 12,886.3 MWh, meeting 0.6% of our
retail and requirements wholesale sales at an average cost of 7.0 cents cents
per kWh.
ENERGY EFFICIENCY
In 1998, we continued to focus our energy efficiency services on
programs that encouraged customers to install energy efficient equipment
when they are planning to replace or buy new equipment rather than
attempting to convince them to replace equipment that is still in good
working order. This strategy, along with careful management, has helped
us to keep our cost-per-kilowatthour saved below 2 cents which is a 56%
reduction in costs since 1992. In 1998, our energy efficiency programs
saved 8,320 megawatthours, 4% above targeted savings for the year.
During the past eight years our efficiency programs have achieved a
cumulative annual savings of 79,049 megawatthours, saving approximately
$7 million per year for our customers.
We continued to work with other Vermont utilities and the Vermont
Department of Public Service to improve and expand a set of statewide
demand side management programs. This effort should reduce cost of
delivering these programs and provide a more standardized service to
customers throughout the State.
In 1998, we spent approximately $1.8 million on energy efficiency
programs, approximately 1.0% of our 1998 retail revenue.
RATE DESIGN
The Company seeks to design rates to encourage the shifting of
electrical use from peak hours to off-peak hours. Since 1976, we have
offered optional time-of-use rates for residential and commercial
customers. Currently, approximately 2,500 of our residential customers
continue to be billed on the original 1976 time-of-use rate basis. In
1987, we received regulatory approval for a rate design that permitted
us to charge prices for electric service that reflected as accurately as
possible the cost burden imposed by each customer class. Our rate
design objectives are to provide a stable pricing structure and to
accurately reflect the cost of providing electric services. 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 our largest customers
be charged time-of-use rates on a phased-in basis by 1994. At year end
December 31, 1998, approximately 1,350 of our largest customers,
comprising 48% of our retail revenues, continue to receive service on
mandatory time-of-use rates.
In May 1994, we filed our current rate design with the VPSB. The
parties, including the Department, IBM and a low-income advocacy group,
entered into a settlement that was approved by the VPSB on December 2,
1994. Under the settlement, the revenue allocation to each rate class
was adjusted to reflect class-by-class cost changes since 1987, the
differential between the winter and summer rates was reduced, the
customer charge was increased for most classes, and usage charges were
adjusted to be closer to the associated marginal costs.
No modifications to base rate design have taken place since the
VPSB Order issued on December 2, 1994.
DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS
In 1998, we had interruptible/dispatchable power contracts with
three major ski areas, interruptible-only contracts with five customers
and dispatchable-only contracts with an additional twenty-four
customers. The interruptible portion of the contracts allows the
Company to control power supply capacity charges by reducing our
capacity requirements. During 1998, we did not request any
interruptions due to the surplus capacity in the region. The
dispatchable portion of the contracts allows customers to purchase
electricity during times designated by the Company when low cost power
is available. The customer's demand during these periods is not
considered in calculating the monthly billing. This program enables the
Company and the customers to benefit from load control. We shift load
from our high cost peak periods and the customer uses inexpensive power
at a time when its use provides maximum value. These programs are
available by tariff for qualifying customers.
CONSTRUCTION AND CAPITAL REQUIREMENTS
Our capital expenditures for 1996 through 1998 and projection for
1999 are set forth in Item 7. Management's Discussion And Analysis Of
Financial Condition and Results Of Operations - "Liquidity and Capital
Resources" -"Construction." 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 1996-1998, internally generated funds, after payment
of dividends, provided approximately 60 percent of total capital
requirements for construction, sinking fund obligations and other
requirements. Internally generated funds provided 25 percent of such
requirements for 1998. We anticipate that for 1999, internally
generated funds will provide approximately 90 percent of total capital
requirements for regulated operations, the remainder to be derived from
bank loans.
ENVIRONMENTAL MATTERS
We have been notified by the Environmental Protection Agency (EPA)
that we are one of several potentially responsible parties for clean up
at the Pine Street Barge Canal site in Burlington, Vermont. For
information regarding the Pine Street Canal site and other environmental
matters see Item 7. Management's Discussion and Analysis Of Financial
Condition and Results of Operations - "Environmental Matters" and Note
I-2 of Notes to Consolidated Financial Statements.
UNREGULATED BUSINESSES
In 1998, we sold the assets of our wholly owned subsidiary, Green
Mountain Propane Gas Company. Through our subsidiary, Green Mountain
Resources, Inc., we agreed to sell our remaining interest in Green
Mountain Energy Resources to Green Funding I in early 1999. For
information regarding our unregulated businesses, see Item 7.
Management's Discussion and Analysis of Financial Condition and Results
of Operations- "Unregulated Businesses."
EXECUTIVE OFFICERS
Executive Officers of the Company as of March 15, 1999:
Name Age
Nancy Rowden Brock 43 Vice President, Chief Financial Officer and
Treasurer since December 1998. Chief
Corporate Strategic Planning Officer from
March 1998 to December 1998. Prior to
joining the Company, she was Chief Financial
Officer of SAL, Inc., 1997; and Senior Vice
President, Chief Financial Officer and
Treasurer for the Chittenden Corporation from
1988 to 1996.
Christopher L. Dutton 50 President, Chief Executive Officer of
the Company and Chairman of the Executive
Committee of the Corporation since August
1997. Vice President, Finance and
Administration, Chief Financial Officer and
Treasurer from 1995 to 1997. Vice President
and General Counsel from 1993 to January
1995. Vice President, General Counsel and
Corporate Secretary from 1989 to 1993.
Robert J. Griffin 42 Controller since October 1996. Manager
of General Accounting from 1990 to 1996.
Donna S. Laffan 49 Corporate Secretary since December
1993. Assistant Secretary from 1986 to 1993.
John J. Lampron 54 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.
Michael H. Lipson 54 General Counsel since August 1997.
Assistant General Counsel from 1994 to 1997.
Senior Attorney from 1993 to 1994. Corporate
Attorney from 1990 to 1993. Prior to joining
the Company, he was a partner with Miller,
Eggleston and Rosenberg Ltd.
Craig T. Myotte 44 Assistant Vice President-Engineering
and Operations since 1994. Assistant Vice
President-Operations and Maintenance from
1991 to 1994.
Walter S. Oakes 52 Assistant Vice President-Customer
Operations since June 1994. Assistant Vice
President, Human Resources from August 1993
to June 1994. Assistant Vice President-
Corporate Services from 1988 to 1993.
Mary G. Powell 38 Vice President, Administration since
February 1999. Vice President, Human
Resources and Organizational Development from
March 1998 to February 1999. Prior to
joining the Company, she was Senior Vice
President, Human Resources and Senior Vice
President Community Banking, Senior Vice
President Administration, and Vice President
of Human Resources for KEYCORP from October
1992 to March 1998.
Stephen C. Terry 56 Senior Vice President, Corporate
Development since August 1997. Vice
President and General Manager, Retail Energy
Services from 1995 to 1997. Vice President-
External Affairs from 1991 to January 1995.
Jonathan H. Winer 47 President of Mountain Energy, Inc.
since March 1997. Vice President and Chief
Operating Officer of Mountain Energy, Inc.
from 1989 to March 1997.
Officers are elected by the Board of Directors of the Company and
its wholly-owned subsidiaries, as appropriate, for one-year terms and
serve at the pleasure of such boards of directors.
ITEM 2. PROPERTY
GENERATING FACILITIES
Our Vermont properties are located in five areas and are
interconnected by transmission lines of VELCO and New England Power
Company. We wholly own and operate eight hydroelectric generating
stations with a total nameplate rating of 36.1 MW and an estimated
claimed capability of 35.7 MW. We also own two gas-turbine generating
stations with an aggregate nameplate rating of 59.9 MW and an estimated
aggregate claimed capability of 73.2 MW. We have two diesel generating
stations with an aggregate nameplate rating of 8.0 MW and an estimated
aggregate claimed capability of 8.6 MW. We also have a wind generating
facility with a nameplate rating of 6.1 MW.
We also own:
- - 17.9% of the outstanding common stock of Vermont Yankee, and are
entitled to 17.662% (93.8 MW of a total 531 MW) of the capacity
of the plant;
- - 1.1% (7.1 MW of a total 620 MW) joint-ownership share of the
Wyman #4 plant located in Maine;
- - 8.8% (31.0 MW of a total 352 MW) joint-ownership share of the
Stony Brook I intermediate units located in Massachusetts; and
- - 11.0% (5.8 MW of a total 53 MW) joint-ownership share of the J.C.
McNeil wood-fired steam plant located in Burlington, Vermont.
See Item 1. Business - "Power Resources" for plant details and the table
hereinafter set forth for generating facilities presently available.
TRANSMISSION AND DISTRIBUTION
The Company had, at December 31, 1998, approximately 1.5 miles of
115 kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4
miles of 44 kV and 284.6 miles of 34.5 kV transmission lines. Our
distribution system includes about 2,409 miles of overhead lines of
2.4 kV to 34.5 kV, and about 459 miles of underground cable of 2.4 kV to
34.5 kV. At such date, we owned approximately 158,820 kVa of substation
transformer capacity in transmission substations, 567,750 kVa of
substation transformer capacity in distribution substations and
1,079,987 kVa of transformers for step-down from distribution to
customer use.
The Company owns 34.8% of the Highgate transmission inter-tie, a
225-MW converter and transmission line utilized to transmit power from
Hydro-Quebec.
We also own 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 Company's wholly-owned plants are located on lands that we own
in fee. Water power and floodage rights are controlled through
ownership of the necessary land in fee or under easements.
Transmission and distribution facilities that 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 and a second mortgage and security interest in the
property securing the 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 Item 1. Business - "Power Resources."
Winter
Capability
Type Location Name Fuel MW(1)
---- -------- ---- ---- ---------
Wholly Owned Hydro Middlesex, VT Middlesex #2 Hydro 3.3
Marshfield, VT Marshfield #6 Hydro 4.9
Vergennes, VT Vergennes #9 Hydro 2.1
W. Danville, VT W. Danville #15 Hydro 1.1
Colchester, VT Gorge #18 Hydro 3.3
Essex Jct., VT Essex #19 Hydro 7.8
Waterbury, VT Waterbury #22 Hydro 5.0
Bolton, VT DeForge #1 Hydro 7.8
Diesel Vergennes, VT Vergennes #9 Oil 4.2
Essex Jct., VT Essex #19 Oil 4.4
Gas Berlin, VT Berlin #5 Oil 56.6
Turbine Colchester, VT Gorge #16 Oil 16.1
Wind Searsburg, VT Wind 1.2
Jointly Owned
Steam Vernon, VT Vermont Yankee Nuclear 93.8(2)
Yarmouth, ME Wyman #4 Oil 7.1
Burlington, VT McNeil Wood 6.6(3)
Combined Ludlow, MA Stony Brook #1 Oil/Gas 31.0(2)
Total Winter Capability 256.3
(1) Winter capability quantities are used since the Company's peak
usage occurs during the winter months. Some unit ratings are
reduced in the summer months due to higher ambient temperatures.
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 Item 1. Business -
"Power Resources - Long-Term Power Sales."
(3) The Company's entitlement in McNeil is 5.8 MW. However, we
receive up to 6.6 MW as a result of other owners' losses on this
system.
CORPORATE HEADQUARTERS
The Company has an operating lease for its Corporate Headquarters,
building, which it expects to vacate mid-year 1999. For a discussion
regarding this lease, see Note I-6 of Notes to Consolidated Financial
Statements.
ITEM 3. LEGAL PROCEEDINGS
See the discussion Item 7. Management's Discussion And Analysis Of
Financial Condition And Results Of Operations - "Environmental Matters"
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 under the symbol "GMP". The following
tabulation shows the high and low sales prices for the Common Stock on
the New York Stock Exchange during 1997 and 1998:
HIGH LOW
1997 First Quarter 25 1/4 22 5/8
Second Quarter 24 5/8 22 3/8
Third Quarter 26 1/4 18 7/8
Fourth Quarter 19 1/4 17 9/16
1998 First Quarter 20 1/16 18
Second Quarter 19 1/16 14 1/8
Third Quarter 14 9/16 11 1/8
Fourth Quarter 15 1/16 10 1/16
The number of common stockholders of record as of March 12, 1999
was 7,032.
Quarterly cash dividends were paid as follows during the past two
years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
1997 . . . . 53.0 cents 53.0 cents 27.5 cents 27.5 cents
1998 . . . . 27.5 cents 27.5 cents 27.5 cents 13.75 cents
Dividend Policy - On November 23, 1998, the Company's Board of
Directors announced a reduction in the quarterly dividend from $0.275
per share to $0.1375 per share on the Company's common stock. The
current indicated annual dividend is $0.55 per share of common stock.
Our current dividend policy reflects changes affecting the electric
utility industry, which is moving away from the traditional cost-of-
service regulatory model to a competition based market for power supply,
and the rate case developments discussed in Item 7. Management's
Discussion And Analysis Of Financial Condition And Results Of Operations
- - "1998 Retail Rate Case".
The current environment prompted us to reassess the appropriateness
of our dividend. The Company's Board of Directors will continue to
assess and adjust the dividend when appropriate, as the Vermont electric
industry evolves towards competition. In addition, if other events
beyond our control cause our financial situation to deteriorate further,
the Board of Directors will also consider whether the current dividend
level is appropriate or if the dividend should be reduced or eliminated.
See Item 7. Management's Discussion And Analysis Of Financial Condition
and Results Of Operations "Future Outlook - Competition and
Restructuring" and Note C of Notes to Consolidated Financial Statements
- - "Dividend Restrictions."
ITEM 6. SELECTED FINANCIAL DATA (In thousands except per share amounts)
Results of operations for the years ended December 31
- -----------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
Operating Revenues...........................$184,304 $179,323 $179,009 $161,544 $148,197
Operating Expenses........................... 178,832 163,808 162,882 146,249 133,680
--------- --------- --------- --------- ---------
Operating Income........................... 5,472 15,515 16,127 15,295 14,517
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity............................. 104 357 175 27 263
Other...................................... (577) 1,216 3,055 3,607 3,418
--------- --------- --------- --------- ---------
Total other income (deductions).......... (473) 1,573 3,230 3,634 3,681
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed funds..................... (131) (315) (468) (547) (539)
Other...................................... 8,007 7,965 7,866 7,973 7,735
--------- --------- --------- --------- ---------
Total interest charges................... 7,876 7,650 7,398 7,426 7,196
--------- --------- --------- --------- ---------
Net Income (Loss)............................ (2,877) 9,438 11,959 11,503 11,002
Dividends on Preferred Stock................. 1,296 1,433 1,010 771 794
--------- --------- --------- --------- ---------
Net Income (Loss)Applicable to Common Stock.. ($4,173) $8,005 $10,949 $10,732 $10,208
========= ========= ========= ========= =========
Common Stock Data
Earnings (loss)per share................... ($0.80) $1.57 $2.22 $2.26 $2.23
Cash dividends declared per share.......... $0.9625 $1.61 $2.12 $2.12 $2.12
Weighted average shares outstanding........ 5,243 5,112 4,933 4,747 4,588
Financial Condition as of December 31
- -------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
Assets
Utility Plant, Net..........................$195,556 $196,720 $189,853 $181,999 $175,987
Other Investments........................... 20,678 21,997 20,634 20,248 20,751
Current Assets.............................. 35,700 29,125 30,901 30,216 28,798
Deferred Charges............................ 30,576 27,390 43,224 42,951 35,659
Non-Utility Assets.......................... 27,314 42,060 39,927 37,868 33,416
--------- --------- --------- --------- ---------
Total Assets...............................$309,824 $317,292 $324,539 $313,282 $294,611
========= ========= ========= ========= =========
Capitalization and Liabilities
Common Stock Equity.........................$106,755 $114,377 $111,554 $106,408 $101,319
Redeemable Cumulative Preferred Stock....... 16,085 17,735 19,310 8,930 9,135
Long-Term Debt, Less Current Maturities..... 88,500 93,200 94,900 91,134 74,967
Capital Lease Obligation.................... 7,696 8,342 9,006 9,778 10,278
Curent Liabilities.......................... 28,825 25,286 21,037 32,629 40,441
Deferred Credits and Other.................. 54,889 45,282 54,968 52,041 49,434
Non-Utility Liabilities..................... 7,074 13,070 13,764 12,362 9,037
--------- --------- --------- --------- ---------
Total Capitalization and Liabilities.......$309,824 $317,292 $324,539 $313,282 $294,611
========= ========= ========= ========= =========
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
In this section, we explain the general financial condition and the
results of operations for Green Mountain Power Corporation (the Company)
and its subsidiaries, including:
- - Factors that affect our business;
- - Our earnings and costs in the periods presented and why they
changed between periods;
- - The source of our earnings;
- - Our expenditures for capital projects and what we expect they will
be in the future;
- - Where we expect to get cash for future capital expenditures; and
- - How all of the above affects our overall financial condition.
There are statements in this section that contain projections or
estimates and are considered to be "forward-looking" as defined by the
Securities and Exchange Commission. In these statements, you may find
words such as "believes," "expects," "plans," or similar words. These
statements are not guarantees of our future performance. There are
risks, uncertainties and other factors that could cause actual results
to be different from those projected. Some of the reasons the results
may be different are listed below and discussed under "Future Outlook",
"Environmental Matters", "Liquidity and Capital Resources" and "Year
2000 Computer Compliance" in this section:
- - Regulatory decisions or legislation;
- - Weather;
- - Energy supply and demand and pricing;
- - Availability, terms, and use of capital;
- - General economic and business environment;
- - Nuclear and environmental issues; and
- - Industry restructuring and cost recovery (including stranded
costs).
These forward-looking statements represent our estimates and
assumptions as of the date of this report.
EARNINGS SUMMARY
The Company lost $0.80 per average share of common stock in 1998 as
compared with earnings per share of common stock of $1.57 in 1997 and
$2.22 in 1996. The 1998 loss represents a negative return on average
common equity of 3.8 percent. The earned return on average common
equity was 7.1 percent in 1997 and 10.0 percent in 1996.
The decrease in earnings in 1998 resulted primarily from the
following:
- - A rate decision by the Vermont Public Service Board ("VPSB") in
February 1998 that disallowed recovery of $6 million for Hydro-
Quebec power supply expenses and other costs;
- - A $5.25 million loss accrued in 1998 resulting from the continued
disallowance of Hydro-Quebec power costs during 1999;
- - Higher 1998 power supply expenses resulting from a one time $8
million payment received from Hydro-Quebec in 1997 that reduced
1997 power supply expenses accordingly;
- - A $3.2 million charge associated with terminating the Company's
corporate headquarters lease and with workforce reductions in
1998; and
- - A $2.1 million (after-tax) loss experienced by Mountain Energy,
Inc. in 1998, as compared to earnings of $142,0000 in 1997,
resulting from a $1.2 million net write-off of a wind power
investment and continued start-up operating losses incurred by
Micronair LLC, a wholly-owned wastewater treatment investment.
This loss was substantially off-set by a $1.8 million reduction in
losses experienced by Green Mountain Resources, Inc. (GMRI) due to
the absence of start-up expenses in 1998, as compared to 1997.
The 1997 decrease in earnings was primarily due to diminished
results by two of the Company's wholly-owned subsidiaries.
- - Mountain Energy, Inc., the Company's subsidiary that invests in
energy generation, energy efficiency and wastewater treatment
projects, earned $1.2 million less in 1997 than in 1996. The
decrease in earnings was primarily due to operating losses incurred
by Micronair, LLC, a company in which Mountain Energy acquired a 71
percent interest in 1997, and a decline in rates paid for power
generated by one of the California wind facilities in which it has
invested.
- - GMRI's loss in 1997 was $1.4 million greater than the loss in 1996
due primarily to the development costs of its investment in Green
Mountain Energy Resources L.L.C. (GMER), the retail energy company
in which the Company sold a 67 percent interest during the third
quarter of 1997.
FUTURE OUTLOOK
Competition and Restructuring -- The electric utility business is
experiencing rapid and substantial changes. These changes are the
result of the following trends:
- - Surplus generating capacity;
- - Disparity in electric rates among and within various regions of the
country;
- - Improvements in generation efficiency;
- - Increasing demand for customer choice; and
- - New regulations and legislation intended to foster competition,
also known as "restructuring".
Electric utilities historically have had exclusive franchises for
the retail sale of electricity in specified service territories. As a
result, competition for retail customers has been limited to:
- - Competition with alternative fuel suppliers, primarily for heating
and cooling;
- - Competition with customer-owned generation; and
- - Direct competition among electric utilities to attract major new
facilities to their service territories.
These competitive pressures have led the Company and other utilities to
offer, from time to time, special discounts or service packages to
certain large customers.
In states across the country, including the New England states,
there has been legislation enacted to allow retail customers to choose
their electricity suppliers, with incumbent utilities required to
deliver that electricity over their transmission and distribution
systems (also known as "retail wheeling"). Increased competitive
pressure in the electric utility industry may restrict the Company's
ability to charge energy prices high enough to recover embedded costs,
such as the cost of purchased power obligations or of generation
facilities owned by the Company. The amount by which such costs might
exceed market prices is commonly referred to as "stranded costs."
Regulatory and legislative authorities at the federal level and in
states, including Vermont where legislation has not been enacted, are
considering how to facilitate competition for electricity sales at the
wholesale and retail levels.
The 1998 session of the Vermont General Assembly adjourned on April
16, 1998 without enacting legislation that would allow Vermont customers
to choose their electric supplier. There is currently no indication
that restructuring legislation will be enacted in the 1999 session.
In the future, the Vermont General Assembly through legislation, or
the VPSB through a subsequent report, action or proceeding, may allow
customers to choose their electric supplier. If this happens without
providing for recovery of a significant portion of the costs associated
with our power supply contracts, the Company's business, including our
operating results, cash flows and ability to pay dividends at the
current level, would be adversely affected. If actions by the Vermont
General Assembly or the VPSB threaten the Company's financial integrity,
we will evaluate all potential alternatives available to us at that
time, including, but not limited to, the filing of a petition for
reorganization under the United States Bankruptcy Code.
In August 1998, the VPSB hosted an open workshop to examine the
extent to which realistic opportunities exist to increase the value or
lower the costs of Vermont's existing power supply arrangements, and, if
such opportunities exist, to consider the best processes for attracting
the highest value proposals. Topics included:
- - Vermont's current power supply situation;
- - Case studies in reforming power supply; and
- - Opportunities in Vermont to reform the power supply.
In September 1998, the VPSB issued an Order (Docket No. 6140)
opening an investigation into the reform of Vermont's electric power
supply and ordered all Vermont electric utilities to participate. That
Order also requested participants to file with the VPSB position papers
to address the scope of the investigation and present substantive
proposals for reform. The Company, together with Central Vermont Public
Service Corporation (CVPS), Citizens Utilities Company and Associated
Industries of Vermont (AIV), an industrial trade association, filed a
position paper responding to the Order. We participated in the VPSB's
technical conference in October at which the scope of the investigation
was discussed. We filed our response to that conference indicating the
priorities and action steps we believe should be taken in order to
provide the greatest assistance in the effort to mitigate Vermont's
power supply costs.
On July 22, 1998, Governor Howard B. Dean announced the
appointment of the Working Group on Vermont's Electricity Future
(Working Group) to examine the structure of the utility industry in
Vermont. The Working Group was comprised of five citizens who were
charged with evaluating and devising sound public policy relating to the
future of the Vermont electric industry. The Working Group issued its
report on December 18, 1998. The fundamental conclusions of the report
are:
- - Bankruptcy is not a solution to Vermont restructuring efforts and
is not an appropriate means to resolve the above-market costs
associated with Vermont's power supply portfolio.
- - Financing mechanisms, including asset securitization, that have
been implemented in other states that have restructured their
electric industries should be made available in Vermont. Such
mechanisms would enable the utilities to provide an up-front lump-
sum payment to suppliers of power to Vermont utilities in exchange
for terminating or substantially reducing the pricing in their
contracts. The legislature or regulators could authorize such
financing mechanisms.
- - The utilities in Vermont should exit the power generation and
supply business as part of the restructuring of the electric
industry in Vermont. The Working Group believes that Vermont
should move rapidly into a restructured competitive environment in
which the incumbent utilities would serve as distribution
providers.
- - As a component of a restructuring plan, serious consideration
should be given to consolidation of the 22 utilities in Vermont,
beginning with the amalgamation of Citizens Utilities' Vermont
operations with Green Mountain Power Corporation and Central
Vermont Public Service Corporation.
On January 8, 1999, the Company, CVPS, AIV and Citizen Utilities
filed Consolidated Comments and Procedural Recommendations with the VPSB
regarding the Working Group's report. We have recommended to the VPSB
that it give priority to considering the Working Group's principal
recommendations, as discussed above, and approve the procedures
necessary for their implementation.
The idea of consolidation of Vermont's utilities needs further
exploration and the Company, CVPS and Citizens Utilities have signed
confidentiality agreements so that such exploration may proceed.
Consistent with the Company's charter, we will consider the benefits of
any merger or consolidation for our shareholders as well as the social,
legal and economic effects upon our customers, employees, suppliers and
others in similar relationships with us, and upon the communities in
which we do business.
Risk Factors -- The major risk factors for the Company arising from
electric industry restructuring, including risks pertaining to the
recovery of stranded costs, are:
- - Regulatory and legal decisions;
- - The market price of power; and
- - The amount of market share retained by the Company.
There can be no assurance that any final restructuring plan ordered
by the VPSB, the courts, or through legislation will include a mechanism
that would allow for full recovery of our stranded costs and include a
fair return on those costs as they are being recovered. If laws are
enacted or regulatory decisions are made that do not offer an adequate
opportunity to recover stranded costs, we believe we have compelling
legal arguments to challenge such laws or decisions.
The largest category of our potential stranded costs is future
costs under long-term power purchase contracts, which, based on current
forecasts, are above-market. We intend to pursue aggressively
mitigation efforts in order to maximize the recovery of these costs.
The magnitude of our stranded costs is largely dependent upon the future
market price of power. We have discussed various market price scenarios
with interested parties for the purpose of identifying stranded costs.
Preliminary market price assumptions, which are likely to change, have
resulted in estimates of the Company's stranded costs of between $245
million and $620 million.
If retail competition is implemented in Vermont, there will be an
impact on the Company's revenues from electricity sales. However, we
are unable to predict at this time the extent of this impact. The
Company, itself or through another marketing affiliate, may elect to
endeavor to retain and attract larger commercial customers in a
competitive retail environment, but neither its relative prospects nor
the margins it will realize on any such sales can be estimated at this
time.
Historically, electric utility rates have been based on a utility's
cost of service. As a result, electric utilities are subject to certain
accounting standards that are not applicable to other business
enterprises in general. Statement of Financial Accounting Standards No.
71 (SFAS 71) allows regulated entities, in appropriate circumstances, to
establish regulatory assets and liabilities, and thereby defer the
income statement impact of certain costs and revenues that are expected
to be realized in future rates. The Company has established regulatory
assets and liabilities under SFAS 71.
As described in the Notes to Consolidated Financial Statements, the
Company complies with the provisions of SFAS 71. In the event the
Company determines that it no longer meets the criteria for following
SFAS 71, the accounting impact would be an extraordinary, non-cash
charge to operations of an amount that could be material. Factors that
could give rise to the discontinuance of SFAS 71 include:
- - Deregulation;
- - A change in the regulators' approach to setting rates from cost-
based regulation to another form of regulation;
- - Increasing competition that limits our ability to sell utility
services or product at rates that will recover costs; and
- - Regulatory actions that result from resistance to rate increases
that limit our ability to sell utility services or products at
rates that will recover costs if we are unable to obtain relief
from prior regulatory actions through appeals to the VPSB or the
courts. See Note I of the Notes to Consolidated Financial
Statements and "Liquidity and Capital Resources".
Under SFAS 5, Accounting for Contingencies, the enactment of
restructuring legislation or issuance of a regulatory order containing
provisions that do not allow for stranded cost recovery, consisting
principally of above market power costs, would require the Company to
estimate and record losses immediately, on an undiscounted basis, for
any above market power purchase contracts and other costs which are
probable of not being recoverable from customers, to the extent that
those costs are estimable. We are unable to predict what form enacted
legislation or such an order will take, and we cannot predict if or to
what extent SFAS 71 will continue to be applicable in the future.
Members of the staff of the Securities and Exchange Commission have
raised questions concerning the continued applicability of SFAS 71 to
certain other electric utilities facing restructuring.
On July 24, 1997, the Emerging Issues Task Force of the Financial
Accounting Standards Board indicated that utilities should immediately
discontinue application of SFAS 71 for those business segments which
will become unregulated, if the utility has a final plan in place for
transition to competition. To the extent that the discontinued segment
has stranded costs that are recoverable through rates, those costs would
continue to be accounted for under SFAS 71.
SFAS 121, Accounting for the Impairment of Long Lived Assets,
requires that any assets, including regulatory assets, that are no
longer probable of recovery through future revenues be revalued based
upon future cash flows. SFAS 121 requires that a rate-regulated
enterprise recognize an impairment loss for regulatory assets that are
no longer probable of recovery. As of December 31, 1998, based upon the
regulatory environment within which we currently operate, no impairment
loss was recorded. Competitive influences or regulatory developments
may impact this status in the future.
We cannot predict whether restructuring legislation enacted by the
Vermont General Assembly or any subsequent report or actions of, or
proceedings before, the VPSB or the Vermont General Assembly would have
a material adverse effect on our operations, financial condition or
credit ratings. The failure to recover a significant portion of our
purchased power costs, or to retain and attract customers in a
competitive environment, would likely have a material adverse effect on
our business, including our operating results, cash flows and ability to
pay dividends at current levels.
For a discussion of a major risk factor arising from Vermont
regulatory treatment of the Company's recent rate filing, see "Liquidity
and Capital Resources", and Note I of the Notes to Consolidated
Financial Statements.
UNREGULATED BUSINESSES
The following is a discussion of the Company's unregulated enterprises.
Our unregulated businesses lost 39 cents per share of common stock in
1998 as compared to a loss of 31 cents per share of common stock in
1997.
Mountain Energy, Inc. (MEI), which invests in energy generation,
energy efficiency and waste water treatment projects, lost $2.1 million
in 1998, compared to earnings of $0.1 million in 1997. The 1998
decrease in earnings was due primarily to continued start-up operating
losses incurred by Micronair, LLC and a write-off related to a wind
facility in California.
Since its formation in 1989, MEI has invested more than $20 million
in operating energy projects, including two California wind projects,
hydroelectric projects in California and New Hampshire, a gas co-
generation facility in Illinois and energy efficiency installations in
Maine, New York, New Jersey, Massachusetts and Hawaii.
In 1997, MEI broadened its investment portfolio by acquiring an
initial 35 percent ownership interest in Micronair, LLC, which owns
certain patent rights to a wastewater treatment system that provides an
innovative and efficient solution to the bio-solids disposal issues
facing the United States. The Micronairr system enhances both the
processing and energy efficiency at wastewater facilities, virtually
eliminating bio-solids as a byproduct. In 1998, MEI acquired the
remaining interest in Micronair.
In 1998, MEI acquired a 33.9 percent equity interest in CASTion
Corporation, an industrial wastewater treatment company. CASTion's
Controlled Atmospheric Separation Technology (CAST ) separates clean
water from industrial process waste streams, in some cases recapturing
valuable minerals and chemicals for reuse. The potential market
continues to grow as public and regulatory tolerance for wastewater
discharges wanes. CASTion has fourteen systems in commercial operation.
Green Mountain Propane Gas, Limited (GMPG), which sold propane gas
at retail in Vermont and New Hampshire, experienced a $139,000 loss in
1998 as compared to a $136,000 loss in 1997.
On February 20, 1998, GMPG and the Company entered into a sales
agreement with VGS Propane, LLC for the sale of all GMPG assets. The
sale was completed on March 16, 1998.
The Company's unregulated rental water heater business earned
$416,000 in 1998, a slight increase from 1997's net income of $381,000.
The 1998 and 1997 results contributed 8 cents and 7 cents of earnings,
respectively, per share to the Company's consolidated results.
Green Mountain Resources, Inc. (GMRI) was formed in April 1996 to
explore opportunities in the emerging competitive retail energy market.
In 1998, GMRI lost $0.2 million compared to a loss of $2.0 million in
1997. GMRI's loss in 1997 was primarily due to development costs
associated with its investment in Green Mountain Energy Resources L.L.C.
(GMER).
On August 6, 1997, GMRI entered into an agreement with Green
Funding I, L.L.C. (GFI), whereby GMRI and GFI would jointly own GMER, a
Delaware limited liability company of which GMRI was previously the sole
owner. GMER is a company that has created retail brands of electricity
that are sold to consumers in competitive markets. GMRI received a
payment of $4 million from GMER at the closing in 1997 as reimbursement
for certain development expenses GMRI had incurred.
Under the terms of the original agreement through which GFI
acquired its interest in GMER, GMRI's ownership percentage of GMER would
be diluted if GFI and/or third parties proposed to contribute additional
capital to GMER, and GMRI did not make pro rata additional capital
contributions at such time. During 1998, GFI made additional,
substantial investments in GMER and it was anticipated that GFI or other
parties would make additional, substantial investments in 1999. GMRI
elected not to provide additional capital contributions, which reduced
its ownership percentage in GMER. In view of the likely need for future
investment in GMER's business, we considered it to be in the best
interest of our shareholders to sell GMRI's remaining interest in GMER.
In December 1998, GMRI and GFI replaced the 1997 agreement with a
new agreement, which among other things, provided for the sale of GMRI's
remaining interest in GMER in return for $1 million to be paid and
recorded as income in the first quarter of 1999. The funds were
received and will be used for the Company's general operating expenses.
The new agreement provides us substantial relief from a "non-
compete clause" in the 1997 agreement that would have restricted our
activities in the retail energy business for seven years.
RESULTS OF OPERATIONS
Operating Revenues and MWh Sales - Operating revenues and
megawatthour (MWh) sales for the years 1998, 1997 and 1996 consisted of:
1998 1997 1996
---- ---- ----
(Dollars in thousands)
Operating Revenues:
Retail . . . . . . . . . . . $164,855 $ 158,790 $ 154,916
Sales for Resale . . . . . . 16,529 17,847 20,667
Other . . . . . . . . . . . 2,920 2,686 3,426
-------- --------- ---------
Total Operating Revenues . . . $184,304 $ 179,323 $ 179,009
======== ========= =========
Megawatthour Sales:
Retail . . . . . . . . . . . 1,839,522 1,806,580 1,775,711
Sales for Resale . . . . . . 543,846 588,525 701,835
--------- --------- ---------
Total Megawatthour sales . . . 2,383,368 2,395,105 2,477,546
========= ========= =========
Average Number of Customers:
Residential . . . . . . . . 71,301 70,671 70,198
Commercial & Industrial . . 12,193 12,012 11,853
Other . . . . . . . . . . . 70 75 75
------ ------ ------
Total Customers . . . . . . . 83,564 82,758 82,126
====== ====== ======
Differences in operating revenues were due to changes in the following:
1997 1996
to to
1998 1997
---- ----
(In Thousands)
Operating Revenues:
Retail Rates . . . . . . . . . . . . . . . $ 3,113 $ 1,161
Retail Sales Volume . . . . . . . . . . . 2,952 2,713
Resales and Other Revenues . . . . . . . . (1,084) (3,560)
--------- --------
Increase in Operating Revenues . . . . . . . $ 4,981 $ 314
========= ========
In 1998, total electricity sales decreased 0.5 percent due
principally to a decrease in wholesale sales caused by a reduction in
low-margin, off-system sales.
Total operating revenues increased 2.8 percent in 1998. Total
retail revenues increased 3.8 percent in 1998 primarily due to:
- - A 3.9 percent increase in sales of electricity to our commercial
and industrial customers resulting from increased use of air
conditioning during the spring and summer months; and
- - A 3.79 percent retail rate increase for service rendered March 1,
1998.
The increase was partially offset by a 2.8 percent reduction in sales to
residential customers caused by warmer than normal winter months.
Wholesale revenues decreased 7.4 percent in 1998 primarily due to a
reduction in low-margin, off-system sales.
Total operating revenues were virtually unchanged in 1997. Total
retail revenues increased 2.5 percent in 1997 primarily due to an
increase in sales of electricity to our small commercial and industrial
customers resulting from modest customer growth and an increase in sales
to IBM. The increase in retail revenues was nearly offset by a 13.6
percent decrease in wholesale revenues caused by a reduction in low-
margin, off-system sales, which had a minimal impact on earnings and a
21.6 percent decrease in other operating revenues caused by a one-time
adjustment in 1996 to account for higher charges under a transmission
and interconnection agreement between CVPS and the Company.
IBM, the Company's single largest customer, operates manufacturing
facilities in Essex Junction, Vermont. IBM's electricity requirements
for its main plant and an adjacent plant accounted for 14.7, 14.0, and
13.2 percent of our operating revenues in 1998, 1997 and 1996,
respectively. No other retail customer accounted for more than one
percent of our revenue in any such year.
In February 1995, the Company and IBM entered into an Economic
Development Agreement (EDA I) that governed the prices to be paid by IBM
at its Essex Junction facility for incremental electric usage during
1995, 1996 and 1997. The contract, intended to promote growth in IBM's
operations and create jobs in our service area, applied only to that
portion of IBM's load that exceeded its 1994 consumption level. Most of
IBM's electric usage is billed under our tariff rate. The EDA I price,
although lower than our tariff rate, exceeded our marginal costs of
providing this incremental electric service to IBM. The VPSB approved
the EDA I in June 1995.
Prior to the expiration of the EDA I on December 31, 1997, the
Company and IBM negotiated a new, similar EDA (EDA II). The agreement
has most of the features of the EDA I, including use of the 1994 base to
determine incremental load and pricing above our marginal costs. A
separate pricing provision applies to load above 1997 levels. The
agreement is for one year, subject to extension for another year at
IBM's option. The VPSB approved the EDA II on May 21 1998. We believe
that the EDA I and EDA II benefit us because the agreements encourage
the incremental purchase of electricity by IBM at a price above our
marginal cost of providing such incremental service.
Power Supply Expenses -- Power supply expenses constituted 67.7
percent, 61.3 percent and 61.5 percent of total operating expenses for
the years 1998, 1997 and 1996, respectively. These expenses increased by
$20.7 million (20.6 percent) in 1998 and $120,000 (0.1 percent) in
1997.
Total power supply expenses increased 20.6 percent in 1998
primarily due to:
- - The absence in 1998 of the $8 million reduction of Hydro-Quebec
power costs resulting from the rate treatment of a payment
received from Hydro-Quebec in 1997;
- - A $5.25 million loss accrued in 1998 resulting from the continued
disallowance of Hydro-Quebec power costs during 1999; and
- - A $4.8 million increase in scheduled Hydro-Quebec contract
capacity costs in 1998.
Company-owned generation increased 20.4 percent in 1998 due to an
increase in the use of high-cost generating facilities that replaced
power that was unavailable from Hydro-Quebec during a severe ice storm
that affected much of Vermont, the Northeast United States and Quebec in
January 1998.
Total power supply expenses were slightly higher in 1997, although
the cost of several individual sources were significantly different from
their costs in 1996. Power supply expenses from Vermont Yankee
increased 7.3 percent in 1997 primarily due to the deferral in 1996 and
the amortization in 1997 of costs associated with a scheduled refueling
outage. Company-owned generation expenses increased 60.0 percent in
1997 primarily due to the increased usage of Company-owned plants
necessitated by the outage of certain nuclear power plants in the
region. These increases were nearly offset by a 6.2 percent decrease in
power supply expenses from other resources primarily due to the
recognition of $8 million received from Hydro-Quebec under a Memorandum
of Understanding entered into in 1996 (as described below) consistent
with a VPSB accounting order dated December 31, 1996.
During 1994, we negotiated an arrangement with Hydro-Quebec that
reduces the cost impacts associated with the purchase of Schedules B and
C3 under the 1987 Contract over the November 1995 through October 1999
period (the July 1994 Agreement). Under the July 1994 Agreement, we
will, in essence, take delivery of the amounts of energy as specified in
the 1987 Contract, but the associated fixed costs will be significantly
reduced from those specified in the 1987 Contract.
As part of the July 1994 Agreement, we are obligated to purchase $4
million (in 1994 dollars) worth of research and development work from
Hydro-Quebec over the four-year period, and made a $6.5 million (in 1994
dollars) cash payment to Hydro-Quebec in 1995. Hydro-Quebec retains the
right to curtail annual energy deliveries by 10 percent up to five
times, over the 2000 to 2015 period, if documented drought conditions
exist in Quebec.
Under an arrangement negotiated in January 1996, we received cash
payments from Hydro-Quebec of $3.0 million in 1996 and $1.1 million in
1997. Consistent with allowed ratemaking treatment, the $3.0 million
payment reduced purchase power expense by $1.75 million in 1996; the
balance of the payment reduced power costs in 1997. The $1.1 million
payment reduced purchase power expense ratably over the period beginning
June 1997 and ending May 1998. We received VPSB approval of this
accounting treatment in an Accounting Order dated December 31, 1996.
Under the 1996 arrangement we are required to shift up to 40
megawatts of our Schedule C3 deliveries to an alternate transmission
path, and use the associated portion of the NEPOOL/Hydro-Quebec
interconnection facilities to purchase power for the period from
September 1996 through June 2001 at prices that vary based upon
conditions in effect when the purchases are made. The 1996 arrangement
also provides for minimum payments by the Company to Hydro-Quebec for
periods in which power is not purchased under the arrangement. Although
our level of benefits will depend on various factors, we estimate that
the 1996 arrangement will provide a minimum benefit of $1.8 million on a
net present value basis. During 1998, we purchased or sold to others
44.2 percent of the minimum purchase obligation for that year. We
recorded a liability of $0.3 million for our remaining 1998 minimum
purchase obligation.
Under a separate agreement executed on December 5, 1997, Hydro-
Quebec provided a cash payment of $8.0 million to the Company in 1997.
In return for this payment, we provided Hydro-Quebec an option for the
purchase of power. Commencing April 1, 1998 and effective through the
term of the 1987 Contract, Hydro-Quebec can exercise an option to
purchase up to 52,500 MWh on an annual basis, at energy prices
established in accordance with the 1987 Contract, for an amount of
energy equivalent to the Company's firm capacity entitlements in the
1987 Contract. The cumulative amount of energy purchased over the
remaining term of the 1987 Contract shall not exceed 950,000 MWh.
Hydro-Quebec's option to curtail energy deliveries pursuant to the July
1994 Agre