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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 Agreement can be exercised in addition to this purchase option.
Over the same period, Hydro-Quebec can exercise an option on an annual
basis to purchase up to 600,000 MWh at the 1987 Contract energy price.
Hydro-Quebec can purchase no more than 200,000 MWh in any given year. In
1998, Hydro-Quebec called on us to deliver 51,968 MWh to a third party
at a net cost to us of $232,958, which was due to higher energy
replacement costs. (See Note K of the Notes to Consolidated Financial
Statements).
The Company and the other Vermont Joint Owners (VJO) of the Hydro-
Quebec contract have sought arbitration to determine whether the
suspension of deliveries of power to Vermont during and after the
January 1998 ice storm constitutes a default by Hydro-Quebec under the
terms of the contract, or if there are other possible claims against
Hydro-Quebec arising from the suspension of deliveries. Hydro-Quebec
appears to maintain that the "force majeure" (superior or irreversible
force) provision in the contract applies, which could excuse its non-
delivery of power under certain circumstances. Arbitration of the
dispute may lead to one or more remedies having an impact on our
obligation under the contract.
On February 11, 1999, we entered into a contract with Morgan
Stanley Capital Group, Inc. (MS) as a result of our power requirements
solicitation in 1998. A master power purchase and sales agreement
(PPSA) dated February 11, 1999 defines the general contract terms under
which the parties may transact. The sales under the PPSA commenced on
February 12, 1999, and will terminate after all obligations under each
transaction entered into by MS and the Company have been fulfilled,
currently anticipated to be June 30, 2001. The PPSA has been noticed to
the VPSB and filed with the Federal Energy Regulatory Commission (FERC).
The parties have also agreed to enter into two transactions subject
to the PPSA.
- - Sale by the Company to MS. -- On a daily basis, and at MS's
discretion, we will sell power from all or part of our portfolio of
power resources to MS at predefined operating and pricing
parameters. We can decide to sell power to MS from any power
resource available to us, provided the sales of power are
consistent with the predefined operating and pricing parameters.
We retain all rights and obligations related to our power
resources, such as dispatch, plant modifications and transfer of
ownership. This transaction does not constitute a sale or lease of
any Company resource.
- - Sale by MS to the Company. -- MS will sell to us, at a predefined
price, power sufficient to serve pre-established load requirements.
MS has the right but not the obligation, upon a request from us, to
supply additional power at prices negotiated by both parties. The
power sold to us may be, but is not required to be, power that MS
has purchased from us under the transaction described above.
The parties have agreed to the protocols that will be used to
schedule power sales and purchases between the parties and to secure
necessary transmission with respect to the two transactions described
above.
The PPSA provides us with a means of managing price risks
associated with changing fossil fuel prices. We remain responsible for
balancing supply resources when actual loads vary from the pre-
established load requirements that MS is obligated to satisfy, and for
resource performance and availability.
Other Operating Expenses - Other operating expenses increased 26.9
percent in 1998 primarily due to:
- - Higher overhead costs resulting from less overhead charged to GMRI,
whose earnings are accounted for on the equity basis;
- - Losses associated with the expected termination of the lease for
our corporate headquarters building; and
- - Charges associated with a workforce reduction in 1998.
Other operating expenses decreased 4.7 percent in 1997 primarily
due to an increase in work performed on behalf of GMRI, effectively
reducing payroll and overhead expenses for the Company. Additionally,
the organizational changes attributable to the creation of GMER resulted
in fewer Company employees, causing a reduction in payroll expense.
Transmission Expenses - Transmission expenses decreased 15.6
percent in 1998 primarily due to a refund received from CVPS in 1998 as
a result of reduced levels of demand on the CVPS transmission system in
1997. We also received a refund in 1998 for charges that were
incorrectly assessed to us during 1997 by New England Power Company.
Transmission expenses increased 2.7 percent in 1997 primarily due
to higher tariffs under a new operating agreement with New England Power
Company.
Maintenance Expenses - Maintenance expenses increased 8.5 percent
in 1998 primarily due to scheduled plant maintenance activities at the
Stony Brook plant and the repair of damage caused by lightning at our
wind facility.
Maintenance expenses increased 7.2 percent in 1997 due to scheduled
increases in plant maintenance.
Depreciation and Amortization - In 1998, depreciation and
amortization expenses decreased 1.8 percent primarily due to a decrease
in the amortization of expenditures related to the Pine Street Barge
Canal site as a result of the VPSB Order of February 27, 1998, which
suspended the amortization charges.
This decrease was partially offset by an increase in depreciation
expenses associated with additional investment in our utility plant.
Depreciation and amortization expenses were virtually unchanged in
1997.
Income Taxes -- The effective federal income tax rates for the
years 1998, 1997 and 1996 were 26.1 percent, 32.8 percent and 27.2
percent, respectively.
Income taxes decreased in 1998 due to a decrease in taxable income.
The increase in 1997 income taxes is primarily due to an increase
in taxable income, an increase in the combined federal and state income
tax rate and an increase in the reserve for unaudited income tax years.
Other Income - Other income decreased $2 million in 1998, as
compared to 1997, primarily due to:
- - A $2.1 million (afer-tax)loss experienced by Mountain Energy, Inc.
resulting from a $1.2 million net write-off of a wind power
investment and start up operating losses incurred by Micronair LLC;
and
- - A $900,000 disallowance in costs associated with the wind facility
ordered by the VPSB in its February 27, 1998 Order.
In addition, the allowance for funds used during construction decreased
in 1998 resulting from lower construction work in progress balances
during the period. These decreases were partially offset by $1.8
million reduction in losses experienced by GMRI due to the absence of
start-up expenses in 1998 as compared to 1997.
Other income decreased 51.3 percent in 1997 primarily due to
diminished results by two of our wholly-owned subsidiaries.
- - Mountain Energy, Inc., the Company's subsidiary that invests in
energy generation and energy and waste water efficiency projects,
earned $1.2 million less in 1997 primarily due to start-up
operating losses incurred by Micronair LLC, a company in which
Mountain Energy bought 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 GMER,
the retail energy company in which the Company sold a controlling
interest during the third quarter of 1997.
Interest Charges - Interest charges increased 3.0 percent in 1998
primarily due to an increase in short-term interest expense related to a
higher amount of short-term debt outstanding during the year and a
decrease in the allowance for funds used during construction resulting
from lower construction work in progress balances in 1998. The
increases were partially offset by a decrease in long-term interest
charges related to a lower amount of long-term debt outstanding in 1998.
Interest charges increased 3.4 percent in 1997 primarily due to an
increase in long-term interest related to the sale of $10 million and $4
million of our first mortgage bonds in November and December 1996,
respectively. This increase was partially offset by a decrease in
interest charges related to a lower amount of short-term debt
outstanding during the year.
Dividends on Preferred Stock - Dividends on preferred stock
decreased by 9.6 percent in 1998 primarily due to the repurchase in 1997
of the following preferred stock: 150 shares of the 4.75 percent, Class
B; 1,600 shares of the 9.375 percent, Class D, Series 1; and 14,000
shares of the 8.625 percent, Class D, Series 3.
Dividends on preferred stock increased 41.8 percent in 1997 and
31.0 percent in 1996 primarily due to the issuance of 120,000 shares of
the Company's 7.32 percent, Class E, Series 1 preferred stock in October
1996.
TRANSMISSION ISSUES
Federal Open Access Tariff Orders -- On April 24, 1996, the FERC
issued Orders 888 and 889 which, among other things, required the filing
of open access transmission tariffs by electric utilities, and the
functional separation by utilities of their transmission operations from
power marketing operations. Order 888 also supports the full recovery
of legitimate and verifiable wholesale power costs previously incurred
under federal or state regulation.
On July 9, 1996, we filed with the FERC the non-discriminatory open
access tariffs required by Order 888 and subsequent modifications to the
tariff. The tariff defined our transmission system to include sub-
transmission facilities that we own including Phase I and Phase II
facilities and our entitlement to facilities owned by VELCO. Our
tariffs included charges related to the use of the VELCO transmission
system by customers. Other Vermont utilities required to make filings
with the FERC under Order 888 followed the same course of action. On
July 17, 1997, the FERC approved our Open Access Transmission Tariff,
and on August 30, 1997, we filed our compliance refund report.
In accordance with Order 889, we have also functionally separated
our transmission operations and filed with the FERC a code of conduct
for our transmission operations. We are currently revising the Code of
Conduct in response to a FERC Order issued on November 3, 1997. We do
not anticipate any material adverse effects or loss of wholesale
customers due to the FERC orders mentioned above.
NEPOOL Transmission Tariff -- Under an allocation agreement among
VELCO, Northeast Utilities and New England Power Corporation (the Three-
Party Agreement), VELCO currently has 14 percent of the capacity of
transmission facilities between New England, New York and Canada.
VELCO's capacity for such transmission facilities is allocated among
Vermont electric utilities, including the Company. Our ability to use
these delivery paths has been adversely impacted by a proposed NEPOOL
open access tariff (NEPOOL Fourth Supplement to Amendment 33) on file
with the FERC. Under the tariff, transmission capability or transfer
capacity between New York and New England will no longer be allocated in
a manner consistent with the Three-Party Agreement. Instead, rights to
the transfer capacity will be made more generally available to the
market subject to certain contingencies related to NEPOOL generation
availability and accounting for the delivery of various grand-fathered
contracts. Efforts by us and other VELCO members to negotiate with
NEPOOL participants for the preservation of rights to deliver long-term
firm contracts necessary to serve native load on these delivery routes
were unsuccessful. Consequently, on November 18, 1997 VELCO filed with
the FERC on behalf of the Vermont utilities (including the Company) a
motion to intervene and seeking summary judgment with respect to the
NEPOOL filing of the Fourth Supplement to Amendment 33. The Company and
other Vermont utilities have argued that the Fourth Supplement was a
proposal to terminate the Vermont utilities' existing and future rights
under the Three Party Agreement allocating the New York and New England
transmission ties and, specifically, the PV20 tie with the New York
Power Authority (NYPA).
The FERC, in an order dated April 20, 1998, took no action on
VELCO's motion other than to recommend that VELCO seek resolution of the
issue pursuant to the dispute resolution process under the proposed
NEPOOL Open Access tariff. The Vermont utilities continue to deliberate
on the appropriate approach to the NEPOOL Open Access tariff dispute
resolution process, which includes an assessment of economic
consequences of the tariff as currently implied.
ENVIRONMENTAL MATTERS
The electric industry typically uses or generates a range of
potentially hazardous products in its operations. We must meet various
land, water, air and aesthetic requirements as administered by local,
state and federal regulatory agencies. We believe that we are in
substantial compliance with these requirements, and that there are no
outstanding material complaints about our compliance with present
environmental protection regulations, except for developments related to
the Pine Street Barge Canal site.
We maintain a program to ensure that we are in compliance with
environmental regulations. This includes employee training, regular
inspection of our facilities, research and development projects, waste
handling and spill prevention procedures, program monitoring and other
activities.
Pine Street Barge Canal Site
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. We have
been notified by the Environmental Protection Agency (EPA) that we are
one of several potentially responsible parties (PRPs) for cleanup of the
Pine Street Barge Canal site in Burlington, Vermont, where coal tar and
other industrial materials were deposited. From the late 19th century
until 1967, gas was manufactured at the Pine Street Barge Canal site by
a number of enterprises, including the Company. In 1990, we were one of
the 14 parties that agreed to pay a total of $945,000 of the EPA's past
response costs under a Consent Decree. We remain a PRP for other past,
ongoing and future response costs. In November 1992, the EPA proposed a
cleanup plan estimated by the EPA to cost $47 million. In June 1993,
the EPA withdrew this cleanup plan in response to public concern about
the plan and its cost. In 1994, the EPA established a coordinating
council, with representatives of the PRPs, environmental and community
groups, the City of Burlington and the State of Vermont, presided over
by a neutral facilitator.
In June 1998, the Coordinating Council reached a consensus
agreement on a recommended plan for remediation of the Pine Street Barge
Canal site. As part of the Council's process of reaching a consensus
recommendation, the Company and certain other parties conditionally
agreed to fund environmentally beneficial projects in the greater
Burlington area, the cost of which may reach $3 million. In June 1998,
the EPA formally proposed the Council's recommended plan and received
public comments.
On September 29, 1998, the EPA issued its final Record of Decision,
announcing selection of the proposed remedy. The proposed remedy
includes:
- - Construction of an underwater cover over canal sediments that
present the highest risk to the environment;
- - Placement of a soil cap over certain contaminated wetland areas and
restoration of those areas;
- - Improvements that will better distribute storm water entering the
site; and
- - Monitoring of the site to ensure that the cap is effective over the
long term and that harmful contamination does not migrate offsite.
The EPA estimates that the present value cost of the remedy would be
$4.4 million, although actual costs may be higher.
As of December 31, 1998, our total expenditures related to the Pine
Street Barge Canal site since 1982 were approximately $16 million. This
includes those amounts not recovered in rates, amounts recovered in
rates, and amounts for which rate recovery has been sought but which are
presently awaiting further VPSB action. The bulk of these expenditures
consisted of transaction costs. Transaction costs include legal and
consulting costs associated with the Company's opposition to the EPA's
earlier proposals for the site, as well as litigation and related costs
necessary to obtain settlements with insurers and other PRPs to provide
amounts required to fund the clean up (remediation costs) and to address
liability claims at the site. A smaller amount of past expenditures was
for site-related response costs, including costs incurred pursuant to
the EPA and state orders that resulted in funding response activities at
the site, and to reimbursing the EPA and the State for oversight and
related response costs. The EPA and the State have asserted and
affirmed that all costs related to these orders are appropriate costs of
response under CERCLA for which the Company and other PRPs were legally
responsible.
The EPA has made claims against us for additional past costs
associated with the Pine Street Barge Canal site in an amount exceeding
$11 million. The EPA also has advised us that we may be responsible for
implementation of further response activities at the site. In early
1998, the United States and the State asked us to begin "fast-track"
negotiation of tentative terms of settlement of all cost reimbursement
and natural resource damages claims of the United States and the State.
Those negotiations began immediately, and included discussion of our
potential contribution claims against the United States. In May 1998, a
confidential tentative agreement was reached on issues under discussion.
We expect to complete negotiation soon of a final settlement with
the United States and the State over terms of a Consent Decree that will
cover claims addressed in the earlier negotiations and implementation of
the selected remedy. The Consent Decree must be submitted to a federal
court for approval and adoption as its order. We have entered into
various confidential settlement agreements with other PRPs that provide
for sharing of past response costs, future cleanup costs and related
future federal and state monetary claims.
We estimate that we have recovered or secured, or will recover,
through past settlements of litigation claims against insurers and other
parties, amounts that exceed estimated future remediation costs, future
federal and state government oversight costs and past EPA response
costs. We have concluded that our unrecovered transaction costs
mentioned above, which were necessary to recover settlements sufficient
to remediate the site, to oppose much more costly solutions proposed by
the EPA, to resolve monetary claims of the EPA and the State and to
remediate the site, are likely to be in the range of $5 to $9 million.
In 1998, we recorded a liability of $5 million to recognize the low end
of this range of costs. The estimated liability is not discounted, and
it is possible that our estimate of future costs could change by a
material amount. We also have recorded an offsetting regulatory asset
and we believe it is probable that we will receive future revenues to
recover these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, we sought
and received recovery for ongoing expenses associated with the Pine
Street Barge Canal site. Specifically, we proposed rate recognition of
our non-recovered expenditures incurred between January 1, 1991 and June
30, 1995 (in the total of approximately $8.7 million) for technical
consultants and legal assistance in connection with the EPA's
enforcement action at the site and insurance litigation. While
reserving the right to argue in the future about the appropriateness of
full rate recovery of the Pine Street Barge Canal costs, the Department,
and as applicable, other intervenors, reached agreements with the
Company in these cases that the full amount of the Pine Street Barge
Canal costs reflected in those rate cases should be recovered in rates.
Our rates, as approved by the VPSB in those proceedings, reflected the
Pine Street Barge Canal related expenditures referred to above.
We proposed in our rate filing made on June 16, 1997, recovery of
an additional $3.0 million in such expenditures. In an order in that
case released March 2, 1998, the VPSB suspended the amortization of
expenditures associated with the Pine Street Barge Canal site pending
further proceedings. Although it did not eliminate the rate base
deferral of these expenditures, or make any specific order in this
regard, the VPSB indicated that it was inclined to agree with other
parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance
carriers and other PRPs, should be "shared" between customers and
shareholders of the Company. In response to our Motion for
Reconsideration, the VPSB on June 8, 1998, stated "our intent, and we
believe the fair reading of our Order, was to reserve for a future
docket issues pertaining to the sharing of remediation-releated costs
between the Company and its customers." See "1997 Retail Rate Case"
below.
An authoritative accounting standard, Statement of Position (SOP)
96-1, has been issued by the accounting profession addressing
environmental remediation obligations. This SOP is effective for years
beginning in 1997, and addresses, among other things, regulatory
benchmarks that are likely triggers of the accrual of estimated losses,
the costs included in the measurement, including incremental costs of
remediation efforts such as post-remediation monitoring and long-term
operation and maintenance costs and costs of compensation and related
benefits of employees devoting time to the remediation. This SOP,
adopted by the Company in January 1997 as required, did not have a
material adverse effect on our financial position or results of
operations in 1998.
Clean Air Act -- Because we purchase most of our power supply from
other utilities, we do not anticipate that we will incur any material
direct cost increases as a result of the Federal Clean Air Act or
proposals to make more stringent regulations under that Act.
Furthermore, only one of our power supply purchase contracts, which
expired in early 1998, related to a generating plant that was affected
by Phase I of the acid rain provisions of this legislation, which went
into effect January 1, 1995.
LIQUIDITY AND CAPITAL RESOURCES
Construction -- Our capital requirements result from the need to
construct facilities or to invest in programs to meet anticipated
customer demand for electric service. If restructuring does occur, we
will reassess our capital expenditures for generation and other projects
and the terms of financing thereof.
Capital expenditures over the past three years and forecasted for 1999
are as follows:
(Dollars in thousands and net of AFUDC and Customer Advances for
Construction)
Total Net
Generation Transmission Distribution Conservation Other Expenditures
Actual:
1996 $6,287* $528 $8,422 $3,090 $3,511 $21,838
1997 3,462* 986 9,680 2,094 3,291 19,513
1998 543 751 6,063 1,244 4,568 13,169
Forecasted:
1999 $1,344 $500 $8,698 $2,200 $8,618** $21,360
*Includes $4.978 and $2.868 million for wind project in 1996 and 1997,
respectively.
**Includes $5.8 million related to Pine Street Barge Canal site.
1997 Retail Rate Case -- On June 16, 1997, the Company filed a request
with the VPSB to increase retail rates by 16.7 percent ($26 million in
additional annual revenues) and to increase the target return on common
equity from 11.25 percent to 13 percent. In our final submissions to
the VPSB we asked for an increase of 14.4 percent ($22 million in
additional annual revenues) due to changed estimates of costs to be
incurred in the rate year. On March 2, 1998, the VPSB released its
Order dated February 27, 1998, in the then pending rate case. The VPSB
authorized us to increase our rates by 3.61 percent, which gave us
increased annual revenues of $5.6 million.
The difference between the $22 million we asked for and the $5.6
million the VPSB authorized was due to the following:
- - Disallowance of the cost of power associated with the Hydro-Quebec
contract discussed below;
- - The VPSB's modification of our calculation of rate base;
- - The exclusion of future capital projects from rate base;
- - Suspension of recovery of Pine Street Barge Canal site
expenditures;
- - Various cost of service reductions in payroll and operations and
maintenance; and
- - A reduction in our requested allowed return on equity from 13
percent to 11.25 percent.
The VPSB Order denied us the right to charge customers $5.48
million of the annual costs for power purchased under our contract with
Hydro-Quebec. The VPSB denied recovery of these costs for the following
reasons:
- - The VPSB claimed that we had acted imprudently by committing to the
power contract with Hydro-Quebec in August 1991 (the imprudence
disallowance); and
- - To the extent that the costs of power to be purchased from Hydro-
Quebec are now higher than current estimates of market prices for
power during the contract term, after accounting for the imprudence
disallowance, the contract power is not "used and useful".
Generally accepted accounting principles (GAAP) required that we
record in the first quarter of 1998 the losses resulting from the
disallowed recovery of a portion of the 1998 Hydro-Quebec power contract
costs. The amount charged to first quarter income of $4.6 million (pre-
tax) was less than the full disallowance because we expected that new
rates would become effective in January 1999 as the result of our May 8,
1998 rate filing. The agreement to suspend our 1998 rate case, as
described below, delays the date of a final decision on the 1998 rate
case to December 15, 1999, and we recognized an additional loss of $5.25
million in the last quarter of 1998 representing the effect of the
presumed continued disallowance of Hydro-Quebec power costs through
December 15, 1999.
In its February 27, 1998 Order, the VPSB described its policies
that do not allow a utility to recover imprudent expenditures and the
costs of power supply contract purchases that the VPSB decides are not
used and useful. The VPSB also stated in its Order that the methods and
measures used in this rate case were provisional and applied to this
rate case only. If the VPSB were to apply the same, or similar, methods
and measures that they used in the 1997 rate case Order to future power
contract costs in our 1998 retail rate case, we would likely be required
to take a charge to income of approximately $170 million pre-tax. This
$170 million estimate represents primarily the 20 percent disallowance
for Hydro-Quebec power costs that the VPSB considered imprudent in its
Order. We will not be able to estimate the loss to be recorded for power
purchased after December 15, 1999, if any, until the pending 1998 rate
case is completed.
If the VPSB does not modify in future regulatory proceedings its
ruling that the costs of power purchased from Hydro-Quebec are above
estimated market rates and are not used and useful and, therefore, a
portion of such costs is not recoverable, we would likely conclude that
the VPSB has changed its approach to setting rates from cost-based rate
making to another form of regulation. We would then be required to
discontinue application of Statement of Financial Accounting Standards
No. 71(SFAS 71), Accounting for the Effects of Certain Types of
Regulation, described below, and eliminate all regulatory assets and
liabilities that arose from prior actions of the VPSB. The write-off of
these regulatory assets and liabilities, net of any tax effects, would
be charged to income as an extraordinary item for the financial
reporting period in which the discontinuation of SFAS 71 occurs.
SFAS 71 provides guidance in preparing financial statements for
public utilities that meet certain criteria of SFAS 71. The three
criteria that we must meet in order to follow the accounting guidance
under SFAS 71 are:
- - Our rates for regulated services and products provided to our
customers must be established by or be subject to approval by an
independent, third-party regulator;
- - The regulated rates are designed to recover our specific costs of
providing the regulated services or products; and
- - Depending on demand for regulated services and products, and the
level of competition, direct and indirect, it is reasonable to
assume that our rates are set at levels that will recover our costs
and that these rates can be charged to and collected from our
customers. This criterion must also take into account anticipated
changes in levels of demand or competition during the recovery
period for any capitalized costs.
We meet these criteria at present and, therefore the provisions of
SFAS 71 apply to us. Under SFAS 71 we are required to defer certain
costs that would typically be expensed under GAAP; these costs are
referred to as deferred charges or regulatory assets.
Our ability to defer a cost is subject to our ability to provide
evidence that the following additional criteria are met:
- - It is probable that the inclusion of the capitalized (deferred)
cost in allowed costs for ratemaking purposes will provide future
revenue in an amount at least equal to the capitalized (deferred)
cost; and
- - The future revenue will be provided to permit recovery of the
previously incurred cost rather than to provide for expected levels
of similar future costs.
Based on the December 31, 1998 balance sheet, if we were required
to discontinue the application of SFAS 71, we would be required to take
an after-tax charge to earnings of approximately $24.6 million
attributable to net regulatory assets.
On March 20, 1998, we filed with the VPSB a Motion for
Reconsideration of and to Alter or Amend the VPSB's Order released on
March 2, 1998. The principal areas in which we requested that the VPSB
change its ruling included the following:
- - A correction to the VPSB's calculation of the $5.48 million Hydro-
Quebec contract power cost disallowance;
- - Reversal of the accounting treatment specified by the VPSB for cash
payments made by Hydro-Quebec under arrangements that we had
previously negotiated in order to avoid rate increases in prior
years for customers;
- - Restoration of $418,000 of costs associated with the construction
of the Searsburg wind generation facility;
- - Restoration of various other compensation and payroll costs;
- - Reversal of the suspension of amortization of costs associated with
the Pine Street Barge Canal site; and
- - Reconsideration of our request to increase the allowed rate of
return from 11.25 percent to 12 percent.
Immediately following the issuance of the June 8, 1998 VPSB Order
on our Motion for Reconsideration, which largely reaffirmed the earlier
Order, Duff & Phelps and Standard & Poor's lowered our securities credit
ratings. Moody's also subsequently lowered our securities credit
ratings.
In June 1998, we appealed the VPSB's February 27, 1998 Order and
the June 8, 1998 Reconsideration Order to the Vermont Supreme Court.
The briefing of the case by all parties was completed in January 1999.
A hearing before the Vermont Supreme Court is scheduled for March 16,
1999. A number of other Vermont utilities have submitted briefs in
support of the Company.
We believe that the decisions in the VPSB's February 27, 1998 Order
and June 8, 1998 Reconsideration Order are factually inaccurate and
legally incorrect. Specifically, we are appealing the VPSB's
determination that we were imprudent in committing to the Hydro-Quebec
contract in August 1991, and VPSB ruling that because the contract power
is priced over-market under current forecasts of market prices, it is
therefore considered "not used and useful." The Company asserts, among
other arguments, that the VPSB's Order deprives the Company's
shareholders of their property in an unconstitutional manner. The
VPSB's decision, if not changed, could have a significant negative
impact on our reported financial condition, and could impact our credit
ratings, dividend policy and financial viability.
1998 Retail Rate Case -- On May 8, 1998, we filed a request with the VPSB to
increase our retail rates by 12.93 percent due to the following increases
in our cost of service:
- - The higher cost of power;
- - The cost of the January 1998 ice storm; and
- - Investments in new plant and equipment.
The VPSB suspended the tariff filings on June 15, 1998. We
submitted testimony in the case that included analysis of viable
alternatives to the Hydro-Quebec contract at various times in 1991 and
1992. The VPSB had taken the viewpoint in our 1997 rate case that we
would have been able to terminate the Hydro-Quebec contract without
penalty during that time period, and would have been able to access the
market for power at that time. Our analysis showed that, based on price
only, the Hydro-Quebec contract was less expensive than virtually all
other long term power resources available at that time. The analysis
also showed that when other non-price benefits, like environmental
benefits and the reliability of a system power resource, are taken into
account, the Hydro-Quebec contract was still less costly than
alternatives. We have testified that even today, when costs and
benefits for society are accounted for, as Vermont regulators and
statutes require, the Hydro-Quebec power is not more costly than market
power.
In testimony submitted on September 21, 1998, the Vermont
Department of Public Service (Department) argued for the following:
- - A $22 million disallowance of Hydro-Quebec contract costs;
- - A rate decrease of 3.6 percent;
- - The elimination of our common stock dividend; and
- - Various other restrictions.
Additionally, the Department's recommendation was that
approximately $12.5 million of the disallowance of Hydro-Quebec contract
costs be suspended for one year, which would provide us with a 4.5
percent rate increase only for that year, followed by automatic
reinstatement of the larger power cost disallowance with a resulting
decrease (in 2000) from our rate levels today, absent further VPSB
order. The Department recommended this one year delay in the Hydro-
Quebec contract cost disallowance in order to allow us time to negotiate
lower costs of power under the Hydro-Quebec contract.
IBM, our largest customer, argued for a rate decrease of 0.2
percent, a disallowance of Hydro-Quebec power costs in the amount of $13
million, and the elimination of the common stock dividend.
In our rebuttal case, we intended to present the VPSB with
testimony that:
- - The Department's and IBM's recommendations amount to improper rate
making that will have adverse economic and accounting impacts under
applicable accounting rules;
- - The only cogent evidence of alternative portfolios of power
resources available in 1991 presented to the VPSB is from our
witnesses and the only conclusion that can be drawn from that
evidence justifies a determination that there should be no Hydro-
Quebec power contract cost disallowance; and
- - We require substantial rate relief in order to ensure our financial
stability, access to capital markets and the continuation of
adequate, reliable and safe service to our customers.
We also intended to present to the VPSB considerable evidence that:
- - We have made, and continue to make, efforts to achieve a negotiated
reformulation of the arrangement with Hydro-Quebec;
- - Placing us at risk of bankruptcy will not improve our prospects of
achieving success in such a negotiation;
- - Bankruptcy reorganization is not an appropriate public policy
solution to high power cost obligations; and
- - Our default of obligations to Hydro-Quebec and other creditors
would cause substantial risks of default in the same contractual
relationships by many other Vermont utilities under "step-up" or
similar provisions contained in such arrangements.
On November 18, 1998, by Memorandum of Understanding (MOU), the
Company, the Department and IBM agreed to stay, effective November 16,
1998, rate proceedings in the 1998 rate case until or after September 1,
1999, or such earlier date as the parties may later agree to or the VPSB
may order. The MOU provides for a 5.7 percent temporary retail rate
increase, to produce $9.19 million in annualized additional revenue,
effective with service rendered December 15, 1998. An additional
surcharge in 1999 will be permitted, without further VPSB order, 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.
The stay and suspension of this pending rate case and the temporary
rate levels agreed to in the MOU are designed to allow us to continue to
provide adequate and efficient service to our customers while we seek
mitigation of power supply costs.
Following the stay, which expires on September 1, 1999 or such
earlier date as agreed to by the parties or ordered by the VPSB, the
remaining proceedings in the case would commence and, as noted above, a
final VPSB decision would be issued by December 15, 1999. In the event
that the VPSB issues a final order that allows a retail rate increase
that is less than the temporary rates, all sums collected in excess of
such final rates would be refunded by adjusting rates on a prospective
basis, by customer class, to reflect the appropriate refund amounts.
The MOU does not provide for any specific disallowance of power
costs under our purchase power contract with Hydro-Quebec. Issues
respecting recovery of such power costs are preserved for future
proceedings.
We agreed not to file with the VPSB a petition requesting any
further increase in retail electric rates prior to September 1, 1999,
except that this MOU does not preclude us from filing a request for
additional temporary rate increases pursuant to 30 V.S.A. Section 226(a).
The temporary rates include $1 million that is to be used for
enhanced right of way maintenance and pole testing and treatment.
Regulatory asset account balances of $5.1 million, which are
subject to recovery in this docket, are to be amortized over seven
years, beginning January 1999. These balances reflect only the amount
filed in the May 1998 rate case, and are related to regulatory
commission expense, tree trimming, storm damage and the costs associated
with the ice storm of 1998. This amortization period will be subject to
review by the VPSB after the expiration of the stay.
In the event that the Vermont Supreme Court issues an order
reversing the VPSB's orders in our 1997 rate case prior to issuance of a
final order in the 1998 rate case, any resulting adjustments in rates
will not become effective until the VPSB issues a final order in the
1998 rate case. The MOU provides that nothing in it will reduce or
limit our entitlement to full recovery of any amounts due us if we
should prevail on the appeal.
The MOU was approved by the VPSB on December 11, 1998. The
temporary rates, as adjusted by any surcharge related to the Pine Street
Barge Canal site described above, will remain in effect until the VPSB
issues a final order in the rate case docket, expected by December 15,
1999.
Notwithstanding the interim rate settlement, we are unable to
predict whether the MOU or other future events, singularly or in
combination, could cause our lending banks to refuse to allow further
borrowings under our revolving loan agreement, to seek to enter into a
new credit agreement with us and/or to immediately call in all
outstanding loans. If we are unable to borrow on a short-term basis, we
will evaluate all potential alternatives available at the time,
including, but not limited to, the filing of a petition for
reorganization under the United States Bankruptcy Code.
Dividend Policy -- On November 23, 1998, the Board of Directors of the
Company announced a reduction in the quarterly dividend on the Company's
common stock from $0.275 per share to $0.1375 per share. The new
indicated annual dividend rate is $0.55 per share.
Our 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,
as well as earnings projections associated with the rate case
developments referred to above. Our current environment has prompted
us to reassess the appropriateness of our dividend. The Board of
Directors will continue to assess and adjust the dividend when
appropriate, as the Vermont electricity 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.
Financing and Capitalization -- For the period 1996 through 1998,
internally generated funds, after payment of dividends, provided
approximately 60 percent of total capital requirements for construction,
sinking funds 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.
At December 31, 1998, our capitalization consisted of 50.1 percent
common equity, 42.3 percent long-term debt and 7.6 percent preferred
equity.
We have a revolving credit agreement in the amount of $45 million
with three banks, with borrowings outstanding of $7 million on December
31, 1998. We also have an uncommitted line of credit in the amount of
$500,000, under which no amounts were outstanding at December 31, 1998.
The revolving credit agreement requires us to certify on a
quarterly basis that we have not suffered a "material adverse change."
Similarly, as a condition to further borrowings, we must certify that
nothing has happened that has had or could reasonably be expected to
have a materially adverse effect on us since the date that we last
borrowed under this agreement. When the VPSB issued its Order dated
February 27, 1998, disallowing certain costs associated with our
contract to purchase power from Hydro-Quebec, the three banks required
modification of the terms of the revolving credit agreement that had
been made originally on August 12, 1997, which was unsecured and had a
three-year term. The modified agreement allows us to continue to borrow
until such time that:
- - A "material adverse effect" has occurred;
- - We are no longer in compliance with all other provisions of the
agreement, in which case further borrowing will not be permitted;
or
- - There has been a "material adverse change", in which case the banks
may declare us in default.
The modified terms also call in part for the following:
- - A reduction in the term of the agreement from three years to one
year, expiring June 30,1999;
- - A second priority mortgage, lien and security interest in the
collateral pledged under our first mortgage bond indenture granted
to the banks; and
- - An increase in the interest rates, facility fees and other fees
required to be paid by us under the agreement.
Required regulatory approval was obtained on June 3, 1998. The
restated credit agreement and related loan documents were effective on
August 17, 1998.
There are a number of future events that, singularly or in
combination, could lead the banks to refuse to allow further borrowings
under the existing credit agreement, to seek to enter into a new credit
agreement with us and/or to immediately call in all outstanding loans.
Some of those events are:
- - The VPSB issues an order in our pending 1998 rate case that
triggers a "material adverse change" for us; or
- - Hydro-Quebec is unwilling to make new arrangements regarding the
cost of power that we purchase under our contract with them.
Due to the negative outcome of the 1997 rate case, which was
decided by the VPSB's orders dated February 27 and June 8, 1998, (See
Note I of the Notes to Consolidated Financial Statements), the credit
ratings of our securities by the three rating agencies that rate us were
lowered as follows:
Duff & Phelps Moody's Standard & Poor's
From To From To From To
------------- ----------- ---------------
First Mortgage Bonds BBB+ BBB Baa2 Baa3 A- BBB
Unsecured medium term BBB BBB- - - BBB BB+
Preferred stock BBB BB+ baa3 ba1 BBB BB
Standard & Poor's also lowered our corporate credit rating from
"BBB+" to "BBB-". Duff & Phelps' and Standard & Poor's credit ratings
for us were placed and remain on Rating Watch-Down and Credit Watch
Negative, respectively, due to the high level of regulatory and public
policy uncertainty in Vermont and certain positions argued by the
Department in our rate cases. Moody's also lowered our ratings due to
"a difficult regulatory environment in Vermont and the resulting high
degree of financial uncertainty for GMP" and placed all of our ratings
on review for possible further downgrade. See Note F of the Notes to
Consolidated Financial Statements for a discussion of the bank credit
facilities available to the Company.
Standard & Poor's announced the generic implementation of a single
credit rating scale for both debt and preferred stock. As a result, on
February 23, 1999, they re-rated all preferred stock issues, including
the Company's, which resulted in the Company's preferred stock being
rated BB.
Corporate Headquarters Lease - As part of our efforts to reduce
operating costs, we evaluated options to our corporate headquarters
lease, which runs through June 2009. We are in the process of
negotiating the termination of our operating lease for our corporate
headquarters and two of our service centers. See Note I of the Notes to
Consolidated Financial Statements.
It is probable that we will purchase the lease and sell our
corporate headquarters in 1999. We have recorded a loss of
approximately $1.9 million (pre-tax) in 1998 to reflect the probable
loss of completing these transactions. We would retain ownership of our
two service centers.
Year 2000 Computer Compliance -- We use computer software, hardware, and
other equipment in our business that could be affected by the date
transition to the next century. Our primary Year 2000 concern is the
possibility of interruptions in delivery of electricity to our
customers. We are not able to predict the impact of any interruption on
our operations or earnings, but the impact could be material.
In the past several years, we purchased and have nearly completed
installing new customer service and financial management systems. These
systems have greatly reduced our exposure to date-related problems. We
will implement and test further upgrades to these systems during 1999 to
ensure that they are Year 2000 compliant. We have also replaced
equipment that would have been affected by the date change.
Management has established a project team to address Year 2000
issues. The team is focused on three elements that are integral to the
project: business continuity, project management and risk management.
Business continuity involves the continuation of reliable electric
supply and service in a safe and cost-effective manner. Project
management involves defining and meeting the project scope schedule and
budget. Risk management involves customer management, contingency
planning and legal issues. In addition to these internal efforts, we
are working with various industry groups to coordinate electric utility
industry Year 2000 efforts.
The approach to identifying and addressing non-compliant software
applications and embedded systems consists of the following stages:
inventory and awareness, assessment, renovation, testing and
implementation. The first stage is to inventory all applications and
systems. The assessment stage involves determining whether software
applications and embedded systems are Year 2000 compliant and
prioritizing remediation needs based on risk management. The renovation
stage involves remediating or upgrading applications and systems to make
them Year 2000 ready. The testing stage determines whether the
renovated applications and systems are Year 2000 ready. The
implementation stage occurs when the tested applications and systems are
deployed.
We have also developed contingency plans for major outages and are
adapting these to the special problems posed by the date change to the
next century. If an unexpected outage does occur we can operate
equipment manually and will have personnel at important locations on New
Years Eve 1999 and into 2000.
Our Year 2000 project focuses on those facets of our business that
are required to deliver reliable electric service. The project
encompasses the computer systems that support our core business
functions such as customer information and billing, finance,
procurement, supply and personnel as well as the components of metering,
transmission, distribution and generation support. The project also
focuses on embedded systems, instrumentation and control systems in
facilities.
The following table summarizes the status of our progress toward
achieving Year 2000 readiness. The figures set forth in the table
represent the estimated extent to which each phase of the Year 2000
project for software applications and embedded systems have been
completed.
Software Embedded
Applications Systems
Inventory . . . . . . . .100% 100%
Assessment . . . . . . . 75% 100%
Renovation . . . . . . . 30% 90%
Testing . . . . . . . . . 30% 90%
Implementation . . . . . 30% 90%
Our current schedule is subject to change, depending on
developments that may arise through unforeseen business circumstances,
and through remediation and testing phases of our compliance effort. Our
ability to deliver electricity to our customers could also be impacted
if one of our major power suppliers or vendors of telecommunication
service experienced a date-related system failure. An interruption in
power supplied by other delivery systems, such as the independent system
operator (ISO) for New England, could also cause power delivery problems
for us. We are participating in the efforts of the ISO's New England
Joint Oversight Committee to ensure that the systems and delivery of
electricity in New England are in compliance. We have asked these
companies to send written reports on their status in eliminating Year
2000 issues that could negatively affect their ability to serve us. All
other major vendors or businesses that we depend on for services or
supplies have also been asked to report on their status.
The total cost of remediating or upgrading software that would not
otherwise be replaced in accordance with our business plans is
approximately $376,000. Approximately $50,000 has been expended as of
December 31, 1998 for external labor, hardware and software costs, and
for the costs of employees who are dedicated to the Year 2000 project.
The foregoing amounts do not include the cost of new software
applications installed as a result of strategic replacement projects
described earlier. Such replacement projects have not been accelerated
because of Year 2000 issues.
The cost of the project and the dates on which we plan to complete
our Year 2000 modifications are based on management's best estimates,
which were derived utilizing numerous assumptions of future events,
including the continued availability of certain resources, third
parties' Year 2000 readiness and other factors. Further, we expect to
incur additional costs after 1999 to remediate and replace less critical
software applications and embedded systems.
We have also begun the process of developing contingency plans to
address the most reasonably likely worst case scenarios that could occur
in the event that various Year 2000 issues are not resolved in a timely
manner. Contingency planning is an ongoing process and will continue
through the fourth quarter of 1999.
The phases of our contingency planning process include business
impact analysis, contingency planning and testing. Business impact
analysis requires business unit personnel to evaluate the impact of
mission-critical systems failure on our core business operations,
focusing on specific failure scenarios and how they can be mitigated.
The necessary conditions for enacting the plans will be documented along
with the appropriate personnel responsible in each of the business units
should a Year 2000 failure occur. Additionally we have participated in
system readiness drills to simulate major outages and restart capability
and will continue to participate in scheduled drills in 1999.
Based on our current schedule for completion of Year 2000 tasks, we
believe that our planning is adequate to secure Year 2000 readiness of
our critical systems. Nevertheless, achieving Year 2000 readiness is
subject to various risks and uncertainties, many of which are described
above. We are not able to predict all the factors that could cause
actual results to differ materially from our current expectations as to
our Year 2000 readiness. However, if we, or third parties with whom we
have significant business relationships, fail to achieve Year 2000
readiness with respect to critical systems, there could be a material
adverse effect on our results of operations, financial position and cash
flows.
Effects of Inflation -- Financial statements are prepared in accordance
with generally accepted accounting principles and report operating
results in terms of historic costs. This accounting provides reasonable
financial statements but does not always take inflation into
consideration. As rate recovery is based on these historical costs and
known and measurable changes, the Company is able to receive some rate
relief for inflation. It does not receive immediate rate recovery
relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation
on plant costs are generally offset by the fact that these assets are
financed through long-term debt.
MANAGEMENT AND ORGANIZATIONAL CHANGES
In 1998, in response to changes in the electric utility industry,
we initiated work to reduce our non-power supply costs and position the
Company as a distribution company with potential to grow. Through an
early retirement incentive option and voluntary severance packages
offered in 1998, we reduced the core workforce by 10 percent. The cost
associated with this workforce change was approximately $3 million
pretax in 1998, but is expected to result in significant future cost
savings. We expensed $1.3 million of these costs, and received an
accounting order from the VPSB allowing us to defer the remaining $1.7
million expended in 1998, which we plan to seek and expect to receive
recovery of in our current or future rate proceedings.
Concurrently, three of the senior management team left the Company
on December 31, 1998, thereby reducing the executive ranks by 20
percent. The officers were:
- - Richard B. Hieber, Senior Vice President and Chief Operating
Officer,
- - Edwin M. Norse, Vice President, Chief Financial Officer and
Treasurer, and
- - Robert C. Young, Assistant Vice President, Customer Operations.
On November 23, 1998, Nancy R. Brock was elected Vice President,
Chief Financial Officer and Treasurer by the Company's Board of
Directors. On February 8, 1999, the Company's Board of Directors
elected Mary G. Powell, Vice President, Administration.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Page
Financial Statements
Consolidated Statements of Income
For the Years Ended December 31, 1998, 1997, and 1996 . . . . . . . . 48
Consolidated Statements of Cash Flows For the
Years Ended December 31, 1998, 1997 and 1996 . . . . . . . . . . . . 49
Consolidated Balance Sheets as of
December 31, 1998 and 1997 . . . . . . . . . . . . . . . . . . . . . 50
Consolidated Capitalization Data as of
December 31, 1998 and 1997 . . . . . . . . . . . . . . . . . . . . . 52
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . 53
Quarterly Financial Information . . . . . . . . . . . . . . . . . . . . . 67
Report of Independent Public Accountants . . . . . . . . . . . . . . . . 81
Schedules
For the Years Ended December 31, 1998, 1997 and 1996:
II Valuation and Qualifying Accounts and Reserves . . . . . . . . . 82
All other schedules are omitted as they are either
not required, not applicable or the information is
otherwise provided.
Consents and Reports of Independent Public Accountants . . . . . . . . .81,95
Arthur Andersen LLP
CONSOLIDATED STATEMENTS OF INCOME
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1998 1997 1996
----------------- --------------- ---------------
(In thousands, except amounts per share)
Operating Revenues.............................................. $184,304 $179,323 $179,009
----------------- --------------- ---------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation................... 32,910 32,817 30,596
Company-owned generation................................... 6,412 5,327 3,330
Purchases from others...................................... 81,706 62,222 66,320
Other operating............................................... 21,291 16,780 17,615
Transmission................................................. 9,389 11,122 10,833
Maintenance................................................... 5,190 4,785 4,463
Depreciation and amortization................................. 16,059 16,359 16,280
Taxes other than income....................................... 7,242 7,205 6,982
Income taxes.................................................. (1,367) 7,191 6,463
----------------- --------------- ---------------
Total operating expenses................................... 178,832 163,808 162,882
----------------- --------------- ---------------
Operating Income......................................... 5,472 15,515 16,127
----------------- --------------- ---------------
Other Income
Equity in earnings of affiliates and
non-utility operations..................................... (28) 427 2,880
Allowance for equity funds used during construction........... 104 357 175
Other income (deductions), net................................ (549) 789 175
----------------- --------------- ---------------
Total other income (deductions)............................. (473) 1,573 3,230
----------------- --------------- ---------------
Income before interest charges............................ 4,999 17,088 19,357
----------------- --------------- ---------------
Interest Charges
Long-term debt................................................ 6,991 7,274 6,872
Other......................................................... 1,016 691 994
Allowance for borrowed funds used during
construction............................................... (131) (315) (468)
----------------- --------------- ---------------
Total interest charges...................................... 7,876 7,650 7,398
----------------- --------------- ---------------
Net Income (Loss)............................................... (2,877) 9,438 11,959
Dividends on preferred stock.................................... 1,296 1,433 1,010
----------------- --------------- ---------------
Net Income (Loss) Applicable to Common Stock.................... ($4,173) $8,005 $10,949
================= =============== ===============
Common Stock Data
Earnings (loss) per share..................................... ($0.80) $1.57 $2.22
Cash dividends declared per share............................. $0.9625 $1.61 $2.12
Weighted average shares outstanding........................... 5,243 5,112 4,933
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1998 1997 1996
--------- --------- ---------
(In thousands)
Operating Activities:
Net Income (Loss).................................................... ($2,877) $9,438 $11,959
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 16,059 16,359 16,280
Dividends from associated companies less equity income........... 812 (90) 254
Allowance for funds used during construction..................... (235) (672) (643)
Deferred purchased power costs................................... (7,830) (331) (5,917)
Amortization of purchased power costs............................ 6,405 5,212 5,187
Deferred income taxes............................................ (112) (2,715) 1,937
Amortization of investment tax credits........................... (282) (282) (282)
Environmental proceedings costs, net............................. 3,010 (2,123) (1,720)
Conservation expenditures........................................ (1,833) (2,411) (3,207)
Changes in:
Accounts receivable............................................ (1,611) 368 347
Accrued utility revenues....................................... (105) 156 (139)
Fuel, materials and supplies................................... 122 359 (309)
Prepayments and other current assets........................... (983) (6,749) (354)
Accounts payable............................................... (1,893) 1,728 221
Taxes accrued.................................................. (2,473) 1,856 415
Interest accrued............................................... (108) (71) (465)
Other current liabilities...................................... 3,229 (164) 1,065
Other............................................................ 644 6,635 1,738
--------- --------- ---------
Net cash provided by operating activities.......................... 9,939 26,503 26,367
--------- --------- ---------
Investing Activities:
Construction expenditures.......................................... (10,900) (16,409) (17,541)
Investment in non-utility property................................. (1,442) 218 (2,203)
Proceeds from sale of propane subsidiary........................... 11,500 -- --
--------- --------- ---------
Net cash used in investing activities............................ (842) (16,191) (19,744)
--------- --------- ---------
Financing Activities:
Issuance of preferred stock........................................ -- -- 12,000
Reduction in preferred stock....................................... (1,650) (1,575) (1,620)
Issuance of common stock........................................... 1,587 3,023 4,642
Short-term debt, net............................................... 4,384 1,600 (7,400)
Issuance of long-term debt......................................... -- -- 14,000
Reduction in long-term debt........................................ (6,767) (4,201) (16,201)
Cash dividends..................................................... (6,332) (9,637) (11,455)
--------- --------- ---------
Net cash used in financing activities............................ (8,778) (10,790) (6,034)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... 319 (478) 589
Cash and cash equivalents at beginning of year..................... 271 749 160
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $590 $271 $749
========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION December 31
1998 1997
--------- ---------
(In thousands)
ASSETS
Electric Utility
Utility Plant
Utility plant, at original cost...........................$276,853 $265,441
Less accumulated depreciation............................. 94,604 87,689
--------- ---------
Net utility plant....................................... 182,249 177,752
Property under capital lease.............................. 7,696 8,342
Construction work in progress............................. 5,611 10,626
--------- ---------
Total utility plant, net................................ 195,556 196,720
--------- ---------
Other Investments
Associated companies, at equity .......................... 15,048 15,860
Other investments ........................................ 5,630 6,137
--------- ---------
Total other investments................................. 20,678 21,997
--------- ---------
Current Assets
Cash and cash equivalents................................. 439 118
Accounts receivable, customers and others, less allowance
for doubtful accounts of $449 and $385.................. 18,977 17,365
Accrued utility revenues.................................. 6,611 6,505
Fuel, materials and supplies, at average cost............. 3,139 3,261
Prepayments............................................... 6,091 1,563
Other..................................................... 443 313
--------- ---------
Total current assets.................................... 35,700 29,125
--------- ---------
Deferred Charges
Demand side management programs........................... 10,590 13,692
Purchased power costs..................................... 5,708 4,283
Other..................................................... 14,278 9,415
--------- ---------
Total deferred charges.................................. 30,576 27,390
--------- ---------
Non-Utility
Cash and cash equivalents................................. 151 153
Other current assets...................................... 7,823 11,501
Property and equipment.................................... 1,213 10,784
Intangible assets......................................... 1,658 2,116
Equity investment in energy-related businesses............ 12,357 12,824
Other assets.............................................. 4,112 4,682
--------- ---------
Total non-utility assets................................ 27,314 42,060
--------- ---------
Total Assets..................................................$309,824 $317,292
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION December 31
1998 1997
--------- ---------
(In thousands)
CAPITALIZATION AND LIABILITIES
Electric Utility
Capitalization (See Capitalization Data)
Common Stock Equity
Common stock............................................ $17,711 $17,318
Additional paid-in capital.............................. 71,914 70,720
Retained Earnings....................................... 17,508 26,717
Treasury stock, at cost................................. (378) (378)
--------- ---------
Total common stock equity............................. 106,755 114,377
Redeemable cumulative preferred stock..................... 16,085 17,735
Long-term debt, less current maturities .................. 88,500 93,200
--------- ---------
Total capitalization.................................. 211,340 225,312
--------- ---------
Capital Lease Obligation ..................................... 7,696 8,342
--------- ---------
Current Liabilities
Current maturuties of long-term debt...................... 1,700 1,700
Short-term debt........................................... 7,000 2,616
Accounts payable, trade, and accrued liabilities.......... 5,453 6,828
Accounts payable to associated companies.................. 7,143 7,661
Dividends declared........................................ 362 350
Customer deposits......................................... 336 721
Taxes Accrued............................................. 370 2,843
Interest accrued.......................................... 1,203 1,311
Other..................................................... 5,258 1,256
--------- ---------
Total current liabilities............................. 28,825 25,286
--------- ---------
Deferred Credits
Accumulated deferred income taxes......................... 23,389 23,501
Unamortized investment tax credits........................ 4,260 4,542
Pine street Marsh clean-up................................ 5,000 --
Other..................................................... 22,240 17,239
--------- ---------
Total deferred credits................................ 54,889 45,282
--------- ---------
Non-Utility
Current liabilities....................................... 720 1,119
Other liabilities......................................... 6,354 11,951
--------- ---------
Total non-utility liabilities......................... 7,074 13,070
--------- ---------
Total Capitalization and Liabilities..........................$309,824 $317,292
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION December 31
Issued and Outstanding
CAPITAL STOCK Authorized 1998 1997 1998 1997
----------- ---------- ---------- --------- ---------
(In thousands)
Common Stock,$3.33 1/3 par value (Note C)........................ 10,000,000 5,313,296 5,195,432 $17,711 $17,318
========= =========
-----------------------------------------------------------------------------------------------------------------
Outstanding
Authorized Issued 1998 1997 1998 1997
---------- ----------- ---------- ---------- --------- ---------
(In thousands)
Redeemable Cumulative Preferred Stock,
$100 par value (Note D)
4.75%,Class B, redeemable at
$101 per share...................................... 15,000 15,000 2,250 2,850 $225 $270
7%,Class C, redeemable at
$101 per share...................................... 15,000 15,000 4,200 4,650 420 465
9.375%,Class D,Series 1,
redeemable at $101 per share........................ 40,000 40,000 6,400 9,600 640 800
8.625%,Class D,Series 3,
redeemable at $101.919 per share.................... 70,000 70,000 28,000 56,000 2,800 4,200
7.32%,Class E,Series 1,............................... 200,000 120,000 120,000 120,000 12,000 12,000
--------- ---------
Total Preferred Stock.................................... $16,085 $17,735
========= =========
LONG-TERM DEBT (Note E) 1998 1997
--------- ---------
(In thousands)
First Mortgage Bonds
7% Series due 1998..........................................................................................$ -- $3,000
5.71% Series due 2000....................................................................................... 5,000 5,000
6.21% Series due 2001....................................................................................... 8,000 8,000
6.29% Series due 2002....................................................................................... 8,000 8,000
6.41% Series due 2003....................................................................................... 8,000 8,000
10.0% Series due 2004 - Cash sinking fund,$1,700,000
annually................................................................................................ 10,200 11,900
7.05% Series due 2006....................................................................................... 4,000 4,000
7.18% Series due 2006....................................................................................... 10,000 10,000
6.7% Series due 2018........................................................................................ 15,000 15,000
9.64% Series due 2020....................................................................................... 9,000 9,000
8.65% Series due 2022 - Cash sinking fund,commences 2012.................................................... 13,000 13,000
--------- ---------
Total Long-term Debt Outstanding.............................................................................. 90,200 94,900
Less Current Maturities (due within one year)............................................................... 1,700 1,700
--------- ---------
Total Long-term Debt, Net..................................................................................... $88,500 $93,200
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
A. SIGNIFICANT ACCOUNTING POLICIES
1. The Company. Green Mountain Power Corporation (the Company) is
an investor-owned electric services company located in Vermont that
serves approximately one-quarter of the State's population. The most
significant portion of the Company's net income is derived from its
regulated electric utility operation, which purchases and generates
electric power and distributes it to 83,500 retail and wholesale
customers. At December 31, 1998, the Company's primary subsidiary
investment was in Mountain Energy Inc., which invests in energy
generation, energy efficiency and wastewater treatment projects across
the United States. In 1998 the Company sold the assets of its wholly
owned propane gas subsidiary, Green Mountain Propane Gas Company (GMPG).
The impact of this transaction did not have a material impact on the
Company's results of operations. In 1998, through its subsidiary, Green
Mountain Resources, Inc. (GMRI), the Company agreed to sell its
remaining interest in Green Mountain Energy Resources L.L.C. (GMER) to
Green Funding I in early 1999. The results of these subsidiaries, the
Company's unregulated rental water heater program and its other
unregulated wholly-owned subsidiaries (GMP Real Estate Corporation and
Lease-Elec, Inc.) are included in earnings of affiliates and non-utility
operations in the Other Income section of the Consolidated Statements of
Income. Summarized financial information is as follows:
For the years ended December 31
1998 1997 1996
---- ---- ----
(In thousands)
Revenues . . . . . . . . . . . . . $ 4,967 $11,842 $11,997
Expenses . . . . . . . . . . . . . 7,035 13,439 11,207
-------- -------- ------
Net Income (Loss) . . . . . . . . $(2,068) ($1,597) $790
======== ======== ======
The Company carries its investments in various associated companies
- -- Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Vermont
Electric Power Company, Inc. (VELCO), New England Hydro-Transmission
Corporation, and New England Hydro-Transmission Electric Company -- at
equity.
2. Basis of Presentation The Company's utility operations,
including accounting records, rates, operations and certain other
practices of its electric utility business, are subject to the
regulatory authority of the Federal Energy Regulatory Commission (FERC)
and the Vermont Public Service Board (VPSB).
The accompanying consolidated financial statements conform to
generally accepted accounting principles applicable to rate-regulated
enterprises in accordance with Statement of Financial Accounting
Standards (SFAS) 71, Accounting for Certain Types of Regulation. Under
SFAS 71, the Company accounts for certain transactions in accordance
with permitted regulatory treatment. As such, regulators may permit
incurred costs, typically treated as expenses, to be deferred and
recovered in future revenues. Conditions that give rise to the
discontinuance of SFAS 71 include (1) increasing competition that
restricts the Company's ability to establish prices to recover its costs
of providing regulated service, and (2) a change in the manner in which
rates are set by regulators from cost-based regulation to another form
of regulation. In the event that the Company no longer meets the
criteria under SFAS 71, the Company would be required to write off its
net regulatory assets and liabilities which totaled $24.6 million as of
December 31, 1998.
SFAS 121, Accounting for the Impairment of Long Lived Assets,
requires that any assets, including regulatory assets, which are no
longer probable of recovery through future revenues, be revalued based
upon future cash flows. SFAS 121 requires that a rate-regulated
enterprise recognize an impairment loss for regulatory assets which are
no longer probable of recovery. As of December 31, 1998, based upon the
regulatory environment within which the Company currently operates, no
impairment loss was recorded under SFAS 121. Competitive influences or
regulatory developments may impact this status in the future.
3. Statements of Cash Flows. The following amounts of interest
(net of amounts capitalized) and income taxes were paid for the years
ending December 31:
1998 1997 1996
---- ---- ----
(In thousands)
Interest . . . . . . . . . . . . . . $7,857 $7,800 $8,104
Income Taxes (Net of refunds) . . . . 2,285 5,853 3,727
4. Utility Plant. The cost of plant additions includes all
construction-related direct labor and materials, as well as indirect
construction costs, including the cost of money (Allowance for Funds
Used During Construction or AFUDC). The costs of renewals and
betterments of property units are capitalized. The costs of
maintenance, repairs and replacements of minor property items are
charged to maintenance expense. The costs of units of property removed
from service, net of removal costs and salvage, are charged to
accumulated depreciation.
5. Depreciation. The Company provides for depreciation on the
straight-line method based on the cost and estimated remaining service
life of the depreciable property outstanding at the beginning of the
year and adjusted for salvage value and cost of removal of the property.
The annual depreciation provision was approximately 3.7 percent of
total depreciable property at the beginning of 1998 and 3.6 percent at
the beginning of 1997 and 1996.
6. Operating Revenues. Operating revenues consist principally of
sales of electric energy. The Company records accrued utility revenues,
based on estimates of electric service rendered and not billed at the
end of an accounting period, in order to match revenues with related
costs.
7. Deferred Charges. In a manner consistent with authorized or
expected ratemaking treatment, the Company defers and amortizes certain
replacement power, maintenance and other costs associated with the
Vermont Yankee nuclear plant. In addition, the Company accrues and
amortizes other replacement power expenses to reflect more accurately
its cost of service to better match revenues and expenses consistent
with regulatory treatment.
The Company defers and amortizes costs associated with its
investment in the demand side management program.
At December 31, 1998, other deferred charges totaled $14.3 million,
consisting of regulatory proceedings expenses, regulatory deferrals of
storm damages, deferred termination costs associated with the Company's
workforce reduction, preliminary survey and investigation charges,
rights-of-way maintenance, unamortized debt expense, repair costs for
the Essex and Vergennes hydroelectric facilities and transmission
interconnection charges and various other projects and deferrals.
8. Earnings (Loss) Per Share. Earnings (loss) per share are based
on the weighted average number of shares of common stock outstanding
during each year.
Statement of Financial Accounting Standards No. 128, Earnings per
Share (SFAS 128) effective for financial statements issued for annual
periods ending after December 15, 1997, replaces the definition of
primary earnings per share, calculated in accordance with the provisions
of APB 15, with a new calculation, basic earnings per share. Fully
diluted earnings per share, now called diluted earnings per share, is
still required. Since the Company has not issued any potentially
dilutive securities, both calculations are the same.
9. Major Customers. The Company had one major retail customer,
IBM, metered at two locations, that accounted for 14.7, 14.0 and
13.2 percent of operating revenues in 1998, 1997 and 1996, respectively.
10. Pension and Retirement Plans. The Company has a defined
pension plan covering substantially all of its employees. The
retirement benefits are based on the employees' level of compensation
and length of service. The Company's policy is to fund all accrued
pension costs. As a result of a rate order issued by the VPSB, the
Company now accounts for its deferred pension plan under the provisions
of SFAS 87, Employers' Accounting for Pensions. Prior to this, the
Company recorded annual expense based on amounts funded in accordance
with methods approved in the rate-setting process.
The Company provides certain health care benefits for retired
employees and their dependents. Employees become eligible for these
benefits if they reach normal retirement age while working for the
Company. The Company accrues the cost of these benefits during the
service life of covered employees.
Accrued postretirement health care expenses are recovered in rates
if those expenses are funded. In order to maximize the tax deductible
contributions that are allowed under IRS regulations, the Company
amended its pension plan to establish a 401-h subaccount and separate
VEBA trusts for its union and non-union employees. The plan assets
consist primarily of cash equivalent funds, fixed income securities and
equity securities.
In 1998, the Company adopted SFAS 132, Employers' Disclosures about
Pensions and Other Postretirement Benefits. The provisions of SFAS 132
revise employers' disclosures about pension and other postretirement
benefit plans. It does not change the measurement or recognition of
these plans but standardizes the disclosure requirements for pensions
and other postretirement benefits to the extent possible.
The following provides a reconciliation of benefit obligations, plan
assets and funded status of the plans as of December 31, 1998 and 1997.
Other
Pension Benefits Postretirement Benefits
--------------------- -------------------------
1998 1997 1998 1997
--------------------- -------------------------
(In thousands) (In thousands)
Change in Projected Benefit Obligation:
Projected benefit obligation as of prior year end.. $28,630 $25,615 $11,046 $9,202
Service cost....................................... 787 720 282 228
Interest cost...................................... 2,043 2,069 799 763
Loss on immediate retirement....................... -- -- 42 --
Special termination benefit........................ 2,026 -- 44 --
Change in discount rate............................ -- -- 897 964
Other.............................................. -- -- -- 435
Actuarial loss..................................... 438 2,290 -- --
Benefits paid...................................... (3,064) (1,852) (558) (546)
Curtailment........................................ -- (212) -- --
--------------------- -------------------------
Projected benefit obligation as of year end......... $30,860 $28,630 $12,552 $11,046
===================== =========================
Change in Plan Assets:
Fair value of plan assets as of prior year end..... $35,773 $31,286 $7,893 $6,327
Contributions...................................... -- -- 76 --
Actual return on plan assets....................... 5,321 6,339 1,766 1,566
Benefits paid...................................... (3,064) (1,852) -- --
--------------------- -------------------------
Fair value of plan assets as of year end............ $38,030 $35,773 $9,735 $7,893
===================== =========================
Funded status as of year end........................ $7,170 $7,143 ($2,817) ($3,153)
Unrecognized transition obligation (asset).......... (1,021) (1,249) 4,926 5,278
Unrecognized prior service cost..................... 1,113 1,247 (743) (805)
Unrecognized net actuarial gain..................... (7,569) (5,962) (1,471) (1,400)
Adjustments due to actions of regulator............. -- (1,179) -- --
---------------------- --------------------------
Prepaid (accrued) benefit cost as of year end....... ($307) $-- ($105) ($80)
====================== ==========================
The plan assets consist primarily of cash equivalent funds, fixed income securities and equity securities.
The Company also has a supplemental pension plan for certain employees. Pension costs for the years ended
December 31, 1998, 1997 and 1996 were $397,000, $456,000 and $494,000, respectively, under this plan.
This plan is funded in part through insurance contracts.
Other
Pension Benefits Postretirement Benefits
--------------------- -------------------------
1998 1997 1998 1997
--------------------- -------------------------
Weighted average assumptions as of year end:
Discount rate....................................... 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets...................... 9.00% 9.00% 8.50% 8.50%
Rate of compensation increase....................... 4.00% 4.50% -- --
Net periodic pension and other postretirement
benefit costs include the following components:
Other
Pension Benefits Postretirement Benefits
------------------------------ ------------------------------------
1998 1997 1996 1998 1997 1996
------------------------------ ------------------------------------
(In Thousands)
Service cost........................................ $787 $720 $689 $282 $228 $247
Interest cost....................................... 2,043 2,069 1,912 799 763 698
Expected return on plan assets...................... (3,081) (2,739) (2,513) (671) (539) (464)
Amortization of transition asset.................... (228) (228) (228) -- -- --
Amortization of net gain from earlier periods....... -- -- -- (17) (28) (45)
Amortization of prior service cost.................. 134 143 141 (61) (61) (61)
Amortization of the transition obligation........... -- -- -- 351 351 352
Recognized net actuarial gain....................... (195) (83) (27) -- -- --
Special termination benefit......................... 2,026 -- -- 44 -- --
Effect of voluntary retirement programs............. -- -- 416 -- -- --
Adjustment due to actions of regulator.............. -- 126 (366) -- -- --
------------------------------ ------------------------------------
Net periodic benefit cost........................... $1,486 $8 $24 $727 $714 $727
============================== ====================================
For postretirement benefit cost measurement purposes, a 5.6 percent annual rate of increase in the per capita
cost of covered benefits was assumed for 1998; the rate was assumed to decrease gradually to 5.0 percent by
the year 2002 and remain at that level thereafter. The health care cost trend rate assumption has a significant
effect on the amounts reported. For example, increasing the assumed health care cost trend rate
by one percentage point would increase the accumulated postretirement benefit obligation as of December 31, 1998
by $1.9 million and the aggregate of the service and interest components of net periodic postretirement benefit cost
fot the year ended December 31, 1998 by $170,000.
The special termination benefit recorded in 1998 resulted from the early retirement incentive option offered to
employees in 1998.
The curtailment recorded in 1997 resulted from the effect of the voluntary retirement option offered
to employees in 1996.
Prior to 1998 the Company recorded annual expense and prepaid (accrued) benefit cost on the cash basis in accordance
with methods approved in the rate-setting process. The adjustment to accomplish this accounting was through
the line item "Adjustments due to actions of regulator."
11. Fair Value of Financial Instruments. If the first mortgage
bonds and preferred stock outstanding at December 31, 1998 were
refinanced using new issue debt rates of interest, which, on average,
are lower than the Company's outstanding rates, the present value of
those obligations would increase from the amounts outstanding on the
December 31, 1998 balance sheet by approximately 4 percent. In the
event of such a refinancing, there would be no gain or loss, inasmuch as
under established regulatory precedent, any such difference would be
reflected in rates and have no effect upon income.
12. Deferred Credits. At December 31, 1998, the Company had other
deferred credits and long-term liabilities of $22.2 million, consisting
of operating lease equalization, reserves for damage claims and
environmental liabilities and accruals for employee benefits and
deferred compensation.
13. Segments and Related Information. In 1998, the Company
adopted SFAS No. 131, Disclosures About Segments of an Enterprise and
Related Information.
The Company has two reportable segments, the electric utility and
Mountain Energy, Inc. The electric utility is engaged in supplying
electrical energy in the State of Vermont and also reports the results
of its wholly-owned unregulated subsidiaries (GMPG, GMRI, GMP Real
Estate, Lease-Elec, Inc., and the rental water heater program) as a
separate line item in the Other Income Section in the Consolidated
Statement of Income.
Mountain Energy, Inc. is an unregulated business that invests in
energy generation, energy efficiency and waste water treatment projects.
Segment information for the year ended December 31, 1998 includes
the following:
Electric Mountain Energy
-------- ---------------
(In thousands)
Revenues-external . . . . . . . . . . . . $184,304 $2,092
Interest income . . . . . . . . . . . . --- 1,344
Depreciation and amortization . . . . . . 16,059 382
Interest expense . . . . . . . . . . . . 7,876 183
Income taxes . . . . . . . . . . . . . . (1,367) (1,463)
Earnings (loss) of equity investments . . (28) 1,840
Segment loss . . . . . . . . . . . . . . (2,087) (2,086)
Segment assets . . . . . . . . . . . . . 283,014 26,810
Capital expenditures . . . . . . . . . . 10,879 21
Equity investments . . . . . . . . . . . 15,048 12,413
Segment information for the year ended December 31, 1997 includes the
following:
Electric Mountain Energy
-------- ---------------
(In thousands)
Revenues-external . . . . . . . . . . . . $179,323 $4,500
Interest income . . . . . . . . . . . . . --- 2,654
Depreciation and amortization . . . . . . 16,359 125
Interest expense . . . . . . . . . . . . 7,650 207
Income taxes . . . . . . . . . . . . . . 7,191 104
Earnings of equity investments . . . . . 427 305
Segment profit . . . . . . . . . . . . . 7,863 142
Segment assets . . . . . . . . . . . . . 292,246 25,046
Capital expenditures . . . . . . . . . . 16,394 15
Equity investments . . . . . . . . . . . 15,860 11,449
Segment information for the year ended December 31, 1996 includes the
following:
Electric Mountain Energy
-------- ---------------
(In thousands)
Revenues-external . . . . . . . . . . . $179,009 $2,848
Interest income . . . . . . . . . . . . --- 1,276
Depreciation and amortization . . . . . 16,280 13
Interest expense . . . . . . . . . . . . 7,398 213
Income taxes . . . . . . . . . . . . . . 6,463 803
Earnings of equity investments . . . . . 2,880 1,631
Segment profit . . . . . . . . . . . . . 9,633 1,316
Segment assets . . . . . . . . . . . . . 285,877 21,498
Capital expenditures . . . . . . . . . . 17,538 3
Equity investments . . . . . . . . . . . 15,769 12,944
Net income (loss) of Mountain Energy, Inc. is included in the
Equity (Loss) in Earnings of Affiliates and Non-Utility Operations line
of the Consolidated Statement of Income.
The following table is a reconciliation of Mountain Energy's income
(loss) to the equity (loss) in earnings of affiliates and non-utility
operations:
For the year ended December 31,
1998 1997 1996
---- ---- ----
(In thousands)
Mountain Energy income (loss) . . . . . . . ($2,086) $ 142 $ 1,316
Electric equity (loss) in earnings of
affiliates and non-utility operations . . 2,058 285 1,564
-------- ------ -------
Total equity (loss) in earnings of
affiliates and non-utility operations . . ($28) $ 427 $ 2,880
======== ======= =======
14. Use of Estimates. The preparation of financial statements in
conformity with generally accepted accounting principles requires the
use of estimates and assumptions that affect assets and liabilities, the
disclosure of contingent assets and liabilities, and revenues and
expenses. Actual results could differ from those estimates.
15. New Accounting Pronouncements.
Statement of Position (SOP 98-1). In 1998, the Company
adopted SOP 98-1, Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use. The provisions of SOP 98-1
require that administrative and general costs, training costs, and
overheads incurred during software development be expensed. The Company
has historically capitalized these costs. Adoption of SOP 98-1 did not
have a material impact on the Company's reported financial position or
its results of operations for 1998.
SFAS 133. In June 1998, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 133 (SFAS
133), Accounting for Derivative Instruments and Hedging Activities.
SFAS 133 establishes accounting and reporting standards requiring that
every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either
an asset or liability measured at its fair value. SFAS 133 requires
that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting.
SFAS 133 is effective for fiscal years beginning after June 15, 1999.
SFAS 133 must be applied to (a) derivative instruments and (b) certain
derivative instruments embedded in hybrid contracts that were issued,
acquired, or substantively modified after December 31, 1997 (and, at the
Company's election, before January 1, 1998).
The Company has not yet quantified the impacts of adopting SFAS 133
on its financial statements and has not determined the timing of or
method of its adoption of SFAS 133. However, SFAS 133 could increase
volatility in earnings and other comprehensive income.
16. Reclassification. Certain items on the prior years' financial
statements have been reclassified for consistent presentation with the
current year.
B. INVESTMENTS IN ASSOCIATED COMPANIES
The Company accounts for investments in the following companies by
the equity method:
Percent Ownership Investment in Equity
at December 31, 1998 December 31,
-------------------- --------------------
1998 1997
---- ----
(In thousands)
VELCO - Common . . . . . . . . . . 29.5% $1,828 $1,833
- Preferred . . . . . . . . 30.0% 829 961
----- -----
Total VELCO . . . . . . . . . . . 2,657 2,794
Vermont Yankee - Common . . . . . 17.9% 9,759 9,701
New England Hydro-Transmission -
Common . . . . . . . . . . . 3.18% 1,015 1,063
New England Hydro-Transmission
Electric - Common . . . . . 3.18% 1,615 1,811
------- -------
$15,046 $15,369
======= =======
Undistributed earnings in associated companies totaled $699,000 at
December 31, 1998.
VELCO. VELCO is a corporation engaged in the transmission of
electric power within the State of Vermont. VELCO has entered into
transmission agreements with the State of Vermont and other electric
utilities, and under these agreements bills all costs, including
interest on debt and a fixed return on equity, to the State and others
using its transmission system. The Company's purchases of transmission
services from VELCO were $7.1 million, $7.6 million and $7.7 million for
the years 1998, 1997 and 1996, respectively. Pursuant to VELCO's
Amended Articles of Association, the Company is entitled to
approximately 30 percent of the dividends distributed by VELCO. The
Company has recorded its equity in earnings on this basis and also is
obligated to provide its proportionate share of the equity capital
requirements of VELCO through continuing purchases of its common stock,
if necessary.
Summarized financial information for VELCO is as follows:
December 31,
1998 1997 1996
---- ---- ----
(In thousands)
Company's equity in net income . . . . . . . . $ 338 $ 354 $ 383
====== ====== ======
Total assets . . . . . . . . . . . . . . . . . $67,658 $70,566 $74,065
Less:
Liabilities and long-term debt . . . . . . 58,690 61,162 61,159
------ ------ -------
Net assets . . . . . . . . . . . . . . . . . . $8,968 $9,404 $ 9,906
====== ====== =======
Company's equity in net assets . . . . . . . . $2,657 $2,794 $ 2,952
====== ====== =======
Vermont Yankee. The Company is responsible for 17.9 percent of
Vermont Yankee's expenses of operations, including costs of equity
capital and estimated costs of decommissioning, and is entitled to a
similar share of the power output of the nuclear plant, which has a net
capacity of 531 megawatts. Vermont Yankee's current estimate of
decommissioning costs is approximately $407 million, of which $260
million has been funded. At December 31, 1998, the Company's portion of
Vermont Yankee's net unfunded liability was $26 million, which it
expects will be recovered through rates over Vermont Yankee's remaining
operating life. 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. As a sponsor of Vermont Yankee, the
Company also is obligated to provide 20 percent of capital requirements
not obtained by outside sources. During 1998, the Company incurred
$27.2 million in Vermont Yankee annual capacity charges, which included
$2.0 million for interest charges. The Company's share of Vermont
Yankee's long-term debt at December 31, 1998 was $16.7 million.
The Price-Anderson Act currently sets the statutory 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 for 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.
For recent events related to Vermont Yankee, see NOTE L-3 --
Subsequent Events.
Summarized financial information for Vermont Yankee is as follows:
December 31,
1998 1997 1996
---- ---- ----
(In thousands)
Earnings:
Operating revenues . . . . . . . . . $195,249 $173,106 $181,715
Net income applicable to common
Stock . . . . . . . . . . . . . . 7,125 6,834 6,985
Company's equity in net income . . . 1,267 1,244 1,232
Total assets . . . . . . . . . . . . . $635,874 $610,024 $565,000
Less:
Liabilities and long-term debt . . . 581,231 555,735 510,202
-------- -------- --------
Net assets . . . . . . . . . . . . . . $ 54,643 $ 54,289 54,798
======== ======== ========
Company's equity in net assets . . . . $ 9,759 $ 9,701 $ 9,768
======== ======== ========
C. COMMON STOCK EQUITY
The Company maintains a Dividend Reinvestment and Stock Purchase
Plan (DRIP) under which 300,504 shares were reserved and unissued at
December 31, 1998. The Company also funds an Employee Savings and
Investment Plan (ESIP). At December 31, 1998, there were 86,807 shares
reserved and unissued under the ESIP.
During 1995, the Company's Board of Directors, with subsequent
approval of the Company's common shareholders, adopted the Compensation
Program for Officers and Certain Key Management Personnel. The program
links a portion of the officers and key management personnels'
compensation to corporate performance results. Participants are
entitled to receive cash and restricted and unrestricted stock grants in
predetermined proportions. Participants who receive restricted stock
are entitled to receive dividends and have voting rights but assumption
of full beneficial ownership is contingent upon two restrictions of a
five year duration, including no transferability and forfeiture of the
stock upon termination of employment with the Company. Participants who
receive unrestricted stock assume full beneficial ownership upon grant
and may retain or sell such shares. During 1998, 6,531 shares were
returned to the Company resulting from the termination of employment of
several participants. At December 31, 1998, there were 26,614 shares
reserved and unissued under the Compensation Program.
On June 17, 1998, the Company adopted a Shareholder Rights Plan that
authorized assignment of one share purchase right for each outstanding
share of Common Stock, par value $3.33 1/3 per share, of the Company.
The Rights were assigned on June 26, 1998 to the shareholders of record
on that date. Each Right entitles the registered holder to purchase from
the Company one Share at a price of $45.00 per Share, when the Rights
become exercisable.
The Plan is designed to improve the Company's ability to represent
the interests of shareholders in dealing with unilateral actions by
hostile acquirors that are calculated to deprive the Company's Board and
its shareholders of their ability to determine the destiny of the
Company and to optimize shareholder value.
Changes in common stock equity for the years ended December 31, 1996,
1997 and 1998 are as follows:
Common Stock Treasury Stock
------------------------ Paid-in Retained ------------------------ Stock
Shares Amount Capital Earnings Shares Amount Equity
------ ------ ------- -------- ------ ------ ------
(Dollars in thousands)
BALANCE, December 31, 1995............... 4,850,496 $16,168 $64,206 $26,412 15,856 ($378) $106,408
Common Stock Issuance:
DRIP................................... 149,968 500 3,188 3,688
ESIP................................... 29,644 99 668 767
Compensation Program:
Restricted Shares.................... 2,392 8 59 67
Stock Grant.......................... 4,643 15 105 120
Net Income............................... 11,959 11,959
Cash Dividends on Capital Stock:
Common Stock -$2.12 per share..... (10,445) (10,445)
Preferred Stock -$4.75 per share..... (14) (14)
-$7.00 per share..... (35) (35)
-$9.375 per share.... (101) (101)
-$8.625 per share.... (543) (543)
-$7.32 per share..... (317) (317)
------------------------------------------------------------------------------------
BALANCE, December 31, 1996............... 5,037,143 16,790 68,226 26,916 15,856 (378) 111,554
Common Stock Issuance:
DRIP................................... 120,631 402 2,182 2,584
ESIP................................... 26,702 89 507 596
Compensation Program:
Restricted Shares.................... 6,190 21 119 140
Stock Grant.......................... 4,766 16 92 108
Net Income............................... 9,438 9,438
Cash Dividends on Capital Stock:
Common Stock -$1.61 per share..... (8,204) (8,204)
Preferred Stock -$4.75 per share..... (13) (13)
-$7.00 per share..... (33) (33)
-$9.375 per share.... (86) (86)
-$8.625 per share.... (423) (423)
-$7.32 per share..... (878) (878)
Other-Preferred Stock Issuance Expense... (406) (406)
------------------------------------------------------------------------------------
BALANCE, December 31, 1997............... 5,195,432 17,318 70,720 26,717 15,856 (378) 114,377
Common Stock Issuance:
DRIP................................... 88,004 293 928 1,221
ESIP................................... 36,391 121 427 548
Compensation Program:
Restricted Shares.................... (6,531) (21) (161) (182)
Net Loss................................. (2,877) (2,877)
Cash Dividends on Capital Stock:
Common Stock -$0.9625 per share... (5,035) (5,035)
Preferred Stock -$4.75 per share..... (12) (12)
-$7.00 per share..... (32) (32)
-$9.375 per share.... (72) (72)
-$8.625 per share.... (302) (302)
-$7.32 per share..... (879) (879)
------------------------------------------------------------------------------------
BALANCE, December 31, 1998............... 5,313,296 $17,711 $71,914 $17,508 15,856 ($378) $106,755
====================================================================================
Dividend Restrictions. Certain restrictions on the payment of cash
dividends on common stock are contained in the Company's indenture
relating to long-term debt and in the Restated Articles of Association.
Under the most restrictive of such provisions, $8.5 million of retained
earnings were free of restrictions at December 31, 1998.
The properties of the Company include several hydroelectric
projects licensed under the Federal Power Act, with license expiration
dates ranging from 1999 to 2025. At December 31, 1998, $59,000 of
retained earnings had been appropriated as excess earnings on
hydroelectric projects as required by Section 10(d) of the Federal Power
Act.
D. PREFERRED STOCK
The holders of the preferred stock are entitled to specific voting
rights with respect to certain types of corporate actions. They are
also entitled to elect the smallest number of directors necessary to
constitute a majority of the Board of Directors in the event of
preferred stock dividend arrearages equivalent to or exceeding four
quarterly dividends. Similarly, the holders of the preferred stock are
entitled to elect two directors in the event of a default in any
purchase or sinking fund requirements provided for any class of
preferred stock.
Certain classes of preferred stock are subject to annual purchase
or sinking fund requirements. The sinking fund requirements are
mandatory. The purchase fund requirements are mandatory, but holders
may elect not to accept the purchase offer. The redemption or purchase
price to satisfy these requirements may not exceed $100 per share plus
accrued dividends. All shares redeemed or purchased in connection with
these requirements must be canceled and may not be reissued. The annual
purchase and sinking fund requirements for certain classes of preferred
stock are as follows:
Purchase and Sinking Fund
8.625%, Class D, Series 3 . . . . . . . . September 1 14,000 Shares
4.75%, Class B . . . . . . . . . . . . . . December 1 450 Shares
7%, Class C . . . . . . . . . . . . . . . December 1 450 Shares
9.375%, Class D, Series 1 . . . . . . . . December 1 1,600 Shares
Under the Restated Articles of Association relating to Redeemable
Cumulative Preferred Stock, the annual aggregate amount of purchase and
sinking fund requirements for the next five years are $1,650,000 for
1999, $1,640,000 for 2000, $235,000 for 2001-2002 and $75,000 for 2003.
Certain classes of preferred stock are redeemable at the option of
the Company or, in the case of voluntary liquidation, at various prices
on various dates. The prices include the par value of the issue plus
any accrued dividends and a redemption premium. The redemption premium
for Class B, C and D, Series 1, is $1.00 per share. The redemption
premium for the Class D, Series 3 is $0.916 per share until September 1,
1999, after which there is no redemption premium.
E. LONG-TERM DEBT
Utility. Substantially all of the property and franchises of the
Company are subject to the lien of the indenture under which first
mortgage bonds have been issued. The annual sinking fund requirements
(excluding amounts that may
be satisfied by property additions) and long-term debt maturities for
the next five years are:
Sinking
Funds Maturities Total
------- ---------- -----
(In thousands)
1999 . . . . . . . . . . . $1,700 $ --- $1,700
2000 . . . . . . . . . . . 1,700 5,000 6,700
2001 . . . . . . . . . . . 1,700 8,000 9,700
2002 . . . . . . . . . . . 1,700 8,000 9,700
2003 . . . . . . . . . . . 1,700 8,000 9,700
Non-Utility. At December 31, 1998, Mountain Energy, Inc., the
Company's subsidiary that invests in energy generation, energy
efficiency and wastewater treatment projects, had unsecured long-term
debt of $1,416,667. The annual sinking fund requirements and maturities
for the next two years are:
Sinking
Funds Maturities Total
------- ---------- -----
(In thousands)
1999 . . . . . . . . . . . . . $167 $ --- $ 167
2000 . . . . . . . . . . . . . 83 1,167 1,250
F. SHORT-TERM DEBT
The Company has a revolving credit agreement in the amount of $45
million with three banks, with borrowings outstanding of $7.0 million on
December 31, 1998 and an uncommitted line of credit in the amount of
$500,000, under which no amounts were outstanding at December 31, 1998.
The revolving credit agreement requires the Company to certify on a
quarterly basis that the Company has not suffered a "material adverse
change." Similarly, as a condition to further borrowings, the Company
must certify that nothing has happened that has had or could reasonably
be expected to have a materially adverse effect on the Company since the
date that it last borrowed under this agreement. When the VPSB issued
its Order dated February 27, 1998, disallowing certain costs associated
with the Company's contract to purchase power from Hydro-Quebec, the
three banks required modification of the terms of the revolving credit
agreement, which had been made originally on August 12, 1997, which was
unsecured and had a three-year term. The modified agreement allows the
Company to continue to borrow until such time that:
- - A "material adverse effect" has occurred;
- - The Company is no longer in compliance with all other provisions of
the agreement, in which case further borrowing will not be
permitted; or
- - There has been a "material adverse change", in which case the banks
may declare the Company in default.
The modified terms also call in part for the following:
- - A reduction in the term of the Agreement from three years to one,
expiring June 30, 1999;
- - A second priority mortgage, lien and security interest in the
collateral pledged under our first mortgage bond indenture granted
to the banks; and
- - An increase in the interest rates, facility fees and other fees
required to be paid by the Company under the agreement.
Required regulatory approval was obtained on June 3, 1998. The
restated credit agreement and related loan documents were effective on
August 17, 1998.
There are a number of future events that, singularly or in
combination, could lead the banks to refuse to allow further borrowings
under the existing credit agreement, to seek to enter into a new credit
agreement with the Company and/or to immediately call in all outstanding
loans. Some of those events are:
- - The VPSB issues an order in the Company's pending 1998 rate case
that triggers a "material adverse change" for the Company; or
- - Hydro-Quebec is unwilling to make new arrangements regarding the
cost of power that the Company purchases under its contract with
Hydro-Quebec.
The weighted average interest rate on borrowings outstanding at
December 31, 1998 and December 31, 1997 was 6.2 percent and 7.0 percent,
respectively.
There was no non-utility short term debt outstanding at December
31, 1998.
G. INCOME TAXES
Utility. The Company accounts for income taxes using an asset and
liability approach. This approach accounts for deferred income taxes by
applying statutory rates in effect at year end to the differences
between the book and tax bases of assets and liabilities.
The regulatory assets and liabilities represent taxes that will be
collected from or returned to customers through rates in future periods.
As of December 31, 1998 and 1997, the net regulatory assets were
$2,214,000 and $1,704,000, respectively.
The temporary differences which gave rise to the net deferred tax
liability at December 31, 1998 and December 31, 1997, were as follows:
At December 31, At December 31,
1998 1997
--------------- ---------------
(In thousands)
Deferred Tax Assets
Contributions in aid of construction . . . $8,551 $ 7,946
Deferred compensation and
post retirement benefits . . . . . . . 4,455 3,199
Alternative minimum tax credit . . . . . (56) 15
Self-insurance and other reserves . . . . 2,009 67
Pine street reserve . . . . . . . . . . . 2,469 1,142
Other . . . . . . . . . . . . . . . . . . 995 2,003
------ ------
18,423 14,372
------ ------
Deferred Tax Liabilities
Property-related and other . . . . . . . 34,806 31,864
Demand side management costs . . . . . . 3,557 4,775
Deferred purchased power costs . . . . . 3,449 1,234
------ ------
41,812 37,873
------ ------
Net accumulated deferred income tax
liability . . . . . . . . . . . . . . .($23,389) ($23,501)
========= =========
The following table reconciles the change in the net accumulated
deferred income tax liability to the deferred income tax expense
included in the income statement for the period:
Year Ended December 31,
1998 1997 1996
---- ---- ----
(In thousands)
Net change in deferred income tax
liability per above table . . . . . . . ($112) ($3,225) $1,434
Change in income tax related regulatory
assets and liabilities . . . . . . . . 510 509 504
Change in alternative minimum tax credit . (70) 567 109
----- -------- -------
Deferred income tax expense for the
Period . . . . . . . . . . . . . . . . . . $328 ($2,149) $2,047
===== ======== ======
The components of the provision (benefit) for income taxes are as
follows:
Year Ended December 31,
1998 1997 1996
---- ---- ----
(In thousands)
Current federal income taxes . . . . . ($1,047) $7,355 $3,708
Current state income taxes . . . . . . (366) 2,267 990
-------- ------ -----
Total current income taxes . . . . . . ($1,413) 9,622 4,698
-------- ------ -----
Deferred federal income taxes . . . . . 219 (1,623) 1,588
Deferred state income taxes . . . . . . 109 (526) 459
-------- ------- ------
Total deferred income taxes . . . . . . 328 (2,149) 2,047
-------- ------- ------
Investment tax credits - net . . . . . (282) (282) (282)
-------- ------- -------
Income taxes charged (credited)
to operations . . . . . . . . . . . ($1,367) $7,191 $6,463
======== ====== ======
Total federal income taxes differ from the amounts computed by
applying the statutory tax rate to income before taxes. The reasons for
the differences are as follows:
Year Ended December 31,
1998 1997 1996
---- ---- ----
(Dollars in thousands)
Income (loss) before income tax . . . ($4,244) $16,630 $ 18,422
Federal statutory rate. . . . . . . . 34% 34.5% 34%
Computed "expected" federal
income taxes . . . . . . . . . . . ($1,443) $ 5,737 $ 6,263
Increase (decrease) in taxes
resulting from:
Tax versus book depreciation . . . 153 349 327
Dividends received and paid
Credit . . . . . . . . . . . . . . (480) (575) (524)
AFUDC - equity funds . . . . . . . (36) (123) (59)
Amortization of ITC . . . . . . . . (282) (282) (282)
State tax benefit (provision) . . . 87 (601) (493)
Excess deferred taxes . . . . . . . (60) (60) (60)
Taxes attributable to subsidiaries 845 682 (140)
Tax reserve . . . . . . . . . . . . 45 270 (101)
Other . . . . . . . . . . . . . . . 61 53 83
-------- ------- -------
Total federal income taxes . . . . . ($1,110) $5,450 $5,014
======== ======= =======
Effective federal income tax rate . . 26.1% 32.8% 27.2%
The decrease in 1998 is primarily due to taxes attributable to the
subsidiaries. The increase in 1997 is due to taxes attributable to the
subsidiaries in 1996 as well as an increase in the tax reserve for 1996.
Non-Utility. The Company's non-utility subsidiaries had
accumulated deferred income taxes of $4.6 million on their balance
sheets at December 31, 1998, largely attributable to property-related
transactions.
The components of the provision (benefit) for income taxes for the
non-utility operations are:
Year Ended December 31,
1998 1997 1996
---- ---- ----
(In thousands)
State income taxes . . . . . . . . . ($503) $78 $154
Federal income taxes . . . . . . . . (1,332) (1,071) 207
Investment tax credits . . . . . . . (111) (45) (45)
-------- -------- -----
Income tax (benefit)/provision
charged (credited) to operations $(1,946) ($1,038) $316
======== ======== =====
The effective federal income tax rates for the non-utility
operations were 32.6 percent, 37.0 percent, and 22.4 percent for the
years ended December 31, 1998, 1997 and 1996, respectively.
The decrease in 1998 is primarily due to a relatively large state
tax benefit in 1998. The increase in 1997 is primarily due to a
relatively large federal tax benefit in 1997.
H. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following quarterly financial information, in the opinion of
management, includes all adjustments necessary to a fair statement of
results of operations for such periods. Variations between quarters
reflect the seasonal nature of the Company's business and the timing of
rate changes.
1998 Quarter Ended
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Dollars in thousands, except per share)
Operating Revenues . . . . . . .$46,932 $43,733 $47,984 $45,655 $184,304
Operating Income . . . . . . . . 316 2,811 3,147 (802) 5,472
Net Income . . . . . . . . . . . (3,065) 1,271 1,943 (3,026) (2,877)
Net Income Applicable to
Common Stock . . . . . . . . . (3,405) 931 1,633 (3,332) (4,173)
Earnings per Average Share of
Common Stock . . . . . . . . . ($0.66) $0.18 $0.31 ($0.63) ($0.80)
Weighted Average Number of
Common Shares Outstanding . . 5,196 5,222 5,261 5,291 5,243
1997 Quarter Ended
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Dollars in thousands, except per share)
Operating Revenues . . . . . . $47,204 $42,682 $43,574 $45,863 $179,323
Operating Income . . . . . . . 4,251 2,991 4,542 3,731 15,515
Net Income . . . . . . . . . . 3,315 1,230 3,371 1,522 9,438
Net Income Applicable to
Common Stock . . . . . . . . 2,941 856 3,022 1,186 8,005
Earnings per Average Share
Common Stock . . . . . . . . $0.58 $0.17 $0.59 $0.23 $1.57
Weighted Average Number of
Common Shares Outstanding . 5,044 5,096 5,138 5,168 5,112
I. COMMITMENTS AND CONTINGENCIES
1. Industry 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".
For further discussion, see Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Future Outlook".
2. Environmental Matters. The electric industry typically uses or
generates a range of potentially hazardous products in its operations.
The Company must meet various land, water, air and aesthetic
requirements as administered by local, state and federal regulatory
agencies. The Company believes that it is in substantial compliance
with these requirements, and that there are no outstanding material
complaints about its compliance with present environmental protection
regulations, except for developments related to the Pine Street Barge
Canal site.
Pine Street Barge Canal Site
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. The
Company has been notified by the Environmental Protection Agency (EPA)
that it is one of several potentially responsible parties (PRPs) for
cleanup of the Pine Street Barge Canal site in Burlington, Vermont,
where coal tar and other industrial materials were deposited. From the
late 19th century until 1967, gas was manufactured at the Pine Street
Barge Canal site by a number of enterprises, including the Company. In
1990, the Company was one of the 14 parties that agreed to pay a total
of $945,000 of the EPA's past response costs under a Consent Decree.
The Company remains a PRP for other past, ongoing and future response
costs. In November 1992, the EPA proposed a cleanup plan estimated by
the EPA to cost $47 million. In June 1993, the EPA withdrew this
cleanup plan in response to public concern about the plan and its cost.
In 1994, the EPA established a coordinating council, with
representatives of the PRPs, environmental and community groups, the
City of Burlington and the State of Vermont, presided over by a neutral
facilitator.
In June 1998, the Coordinating Council reached a consensus
agreement on a recommended plan for remediation of the Pine Street Barge
Canal site. As part of the Council's process of reaching a consensus
recommendation, the Company and certain other parties conditionally
agreed to fund environmentally beneficial projects in the greater
Burlington area, the cost of which may reach $3 million. In June 1998,
the EPA formally proposed the Council's recommended plan and received
public comments.
On September 29, 1998, the EPA issued its final Record of Decision,
announcing selection of the proposed remedy. The proposed remedy
includes:
- - Construction of an underwater cover over canal sediments that
present the highest risk to the environment;
- - Placement of a soil cap over certain contaminated wetland areas and
restoration of those areas;
- - Improvements that will better distribute storm water entering the
site; and
- - Monitoring of the site to ensure that the cap is effective over the
long term and that harmful contamination does not migrate offsite.
The EPA estimates that the present value cost of the remedy will be $4.4
million, although actual costs may be higher.
As of December 31, 1998, the Company's total expenditures related
to the Pine Street Barge Canal site since 1982 were approximately $16
million. This includes those amounts not recovered in rates, amounts
recovered in rates, and amounts for which rate recovery has been sought
but which are presently awaiting further VPSB action. The bulk of these
expenditures consisted of transaction costs. Transaction costs include
legal and consulting costs associated with the Company's opposition to
the EPA's earlier proposals for the site, as well as litigation and
related costs necessary to obtain settlements with insurers and other
PRPs to provide amounts required to fund the clean up (remediation
costs) and to address liability claims at the site. A smaller amount of
past expenditures was for site-related response costs, including costs
incurred pursuant to the EPA and state orders that resulted in funding
response activities at the site, and to reimbursing the EPA and the
State for oversight and related response costs. The EPA and the State
have asserted and affirmed that all costs related to these orders are
appropriate costs of response under CERCLA for which the Company and
other PRPs were legally responsible.
The EPA has made claims against the Company for additional past
costs associated with the Pine Street Barge Canal site in an amount
exceeding $11 million. The EPA also has advised the Company that the
Company may be responsible for implementation of further response
activities at the site. In early 1998, the United States and the State
asked the Company to begin "fast-track" negotiation of tentative terms
of settlement of all cost reimbursement and natural resource damages
claims of the United States and the State. Those negotiations began
immediately, and included discussion of the Company's potential
contribution claims against the United States. In May 1998, a
confidential tentative agreement was reached on issues under discussion.
The Company expects to complete negotiation soon of a final
settlement with the United States and the State over terms of a Consent
Decree that will cover claims addressed in the earlier negotiations and
implementation of the selected remedy. The Consent Decree must be
submitted to a federal court for approval and adoption as its order.
The Company has entered into various confidential settlement agreements
with other PRPs that provide for sharing of past response costs, future
cleanup costs and related future federal and state monetary claims.
The Company estimates that it has recovered or secured, or will
recover, through past settlements of litigation claims against insurers
and other parties, amounts that exceed estimated future remediation
costs, future federal and state government oversight costs and past EPA
response costs. The Company has concluded that its unrecovered
transaction costs mentioned above, which were necessary to recover
settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, to resolve monetary claims of the EPA and
the State and to remediate the site, are likely to be in the range of $5
to $9 million. In 1998, the Company recorded a liability of $5 million
to recognize the low end of this range of costs. The estimated
liability is not discounted, and it is possible that the Company's
estimate of future costs could change by a material amount. The Company
also has recorded an offsetting regulatory asset and the Company
believes it is probable that it will receive future revenues to recover
these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, the Company
sought and received recovery for ongoing expenses associated with the
Pine Street Barge Canal site. Specifically, the Company proposed rate
recognition of its non-recovered expenditures incurred between January
1, 1991 and June 30, 1995 (in the total of approximately $8.7 million)
for technical consultants and legal assistance in connection with the
EPA's enforcement action at the site and insurance litigation. While
reserving the right to argue in the future about the appropriateness of
full rate recovery of the Pine Street Barge Canal costs, the
Department, and as applicable, other intervenors, reached agreements
with the Company in these cases that the full amount of the Pine Street
Barge Canal costs reflected in those rate cases should be recovered in
rates. The Company's rates, as approved by the VPSB in those
proceedings, reflected the Pine Street Barge Canal related expenditures
referred to above.
The Company proposed in its rate filing made on June 16, 1997,
recovery of an additional $3.0 million in such expenditures. In an order
in that case released March 2, 1998, the VPSB suspended the amortization
of expenditures associated with the Pine Street Barge Canal site pending
further proceedings. Although it did not eliminate the rate base
deferral of these expenditures, or make any specific order in this
regard, the VPSB indicated that it was inclined to agree with other
parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance
carriers and other PRPs, should be "shared" between customers and
shareholders of the Company. In response to the Company's Motion for
Reconsideration, the VPSB on June 8, 1998 stated "our intent, and we
believe the fair reading of our Order, was to reserve for a future
docket issues pertaining to the sharing of remediation-related costs
between the Company and its customers."
An authoritative accounting standard, Statement of Position (SOP)
96-1, has been issued by the accounting profession addressing
environmental remediation obligations. This SOP is effective for years
beginning in 1997, and addresses, among other things, regulatory
benchmarks that are likely triggers of the accrual of estimated losses,
the costs included in the measurement, including incremental costs of
remediation efforts such as post-remediation monitoring and long-term
operation and maintenance costs and costs of compensation and related
benefits of employees devoting time to the remediation. This SOP,
adopted by the Company in January 1997 as required, did not have a
material adverse effect on its financial position or results of
operations in 1998.
Clean Air Act -- Because the Company purchases most of its power
supply from other utilities, it does not anticipate that it will incur
any material direct cost increases as a result of the Federal Clean Air
Act or proposals to make more stringent regulations under that Act.
Furthermore, only one of the Company's power supply purchase contracts,
which expired in early 1998, related to a generating plant that was
affected by Phase I of the acid rain provisions of this legislation,
which went into effect January 1, 1995.
3. Operating Leases. The Company has an operating lease for its
corporate headquarters building and two of its service center buildings.
See Item 6 below.
4. Jointly-Owned Facilities. The Company had joint-ownership
interests in electric generating and transmission facilities at December
31, 1998, as follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- -------- ------- ------------
(In %) (In MW) (In thousands)
Highgate . . . . . . 33.8 67.6 $10,532 $3,573
McNeil . . . . . . . 11.0 5.9 $ 8,729 $3,898
Stony Brook (No. 1) . 8.8 31.0 $10,331 $6,752
Wyman(No.4) . . . . . 1.1 6.8 $ 2,370 $1,448
Metallic Neutral
Return (1). . .. . 59.4 --- $ 1,563 $ 494
(1) Neutral conductor for NEPOOL/Hydro-Quebec Interconnection
The Company's share of expenses for these facilities is reflected
in the Consolidated Statements of Income. Each participant in these
facilities must provide for its own financing.
5. 1997 Retail Rate Case -- On June 16, 1997, the Company filed a
request with the VPSB to increase retail rates by 16.7 percent ($26
million in additional annual revenues) and to increase the target return
on common equity from 11.25 percent to 13 percent. In its final
submissions to the VPSB, the Company asked for an increase of 14.4
percent ($22 million in additional annual revenues) due to changed
estimates of costs to be incurred in the rate year. On March 2, 1998,
the VPSB released its Order dated February 27, 1998, in the then pending
rate case. The VPSB authorized the Company to increase its rates by
3.61 percent, which gave it increased annual revenues of $5.6 million.
The difference between the $22 million we asked for and the $5.6
million the VPSB authorized was due to the following:
- - Disallowance of the cost of power associated with the Hydro-Quebec
contract discussed below;
- - The VPSB's modification of our calculation of rate base;
- - The exclusion of future capital projects from rate base;
- - Suspension of recovery of Pine Street Barge Canal site
expenditures;
- - Various cost of service reductions in payroll and operations and
maintenance; and
- - A reduction in our requested allowed return on equity from 13
percent to 11.25 percent.
The VPSB Order denied us the right to charge customers $5.48
million of the annual costs for power purchased under our contract with
Hydro-Quebec. The VPSB denied recovery of these costs for the following
reasons:
- - The VPSB claimed that we had acted imprudently by committing to the
power contract with Hydro-Quebec in August 1991 (the imprudence
disallowance); and
- - To the extent that the costs of power to be purchased from Hydro-
Quebec are now higher than current estimates of market prices for
power during the contract term, after accounting for the imprudence
disallowance, the contract power is not "used and useful".
Generally accepted accounting principles (GAAP) required that we
record in the first quarter of 1998 the losses resulting from the
disallowed recovery of a portion of the 1998 Hydro-Quebec power contract
costs. The amount charged to first quarter income of $4.6 million (pre-
tax) was less than the full disallowance because we expected that new
rates would become effective in January 1999 as the result of our May 8,
1998 rate filing. The agreement to suspend our 1998 rate case, as
described below, delays the date of a final decision on the 1998 rate
case to December 15, 1999, and we recognized an additional loss of $5.25
million in the last quarter of 1998 representing the effect of the
presumed continued disallowance of Hydro-Quebec power costs through
December 15, 1999.
In its February 27, 1998 Order, the VPSB described its policies
that do not allow a utility to recover imprudent expenditures and the
costs of power supply contract purchases that the VPSB decides are not
used and useful. The VPSB also stated in its Order that the methods and
measures used in this rate case were provisional and applied to this
rate case only. If the VPSB were to apply the same, or similar, methods
and measures that they used in the 1997 rate case Order to future power
contract costs in our 1998 retail rate case, we would likely be required
to take a charge to income of approximately $170 million pre-tax. This
$170 million estimate represents primarily the 20 percent disallowance
for Hydro-Quebec power costs that the VPSB considered imprudent in its
Order. We will not be able to estimate the loss to be recorded for power
purchased after December 15, 1999, if any, until the pending 1998 rate
case is completed.
If the VPSB does not modify in future regulatory proceedings its
ruling that the costs of power purchased from Hydro-Quebec are above
estimated market rates and are not used and useful and, therefore, a
portion of such costs is not recoverable, we would likely conclude that
the VPSB has changed its approach to setting rates from cost-based rate
making to another form of regulation. We would then be required to
discontinue application of Statement of Financial Accounting Standards
No. 71(SFAS 71), Accounting for the Effects of Certain Types of
Regulation, described below, and eliminate all regulatory assets and
liabilities that arose from prior actions of the VPSB. The write-off of
these regulatory assets and liabilities, net of any tax effects, would
be charged to income as an extraordinary item for the financial
reporting period in which the discontinuation of SFAS 71 occurs.
SFAS 71 provides guidance in preparing financial statements for
public utilities that meet certain criteria of SFAS 71. The three
criteria that we must meet in order to follow the accounting guidance
under SFAS 71 are:
- - Our rates for regulated services and products provided to our
customers must be established by or be subject to approval by an
independent, third-party regulator;
- - The regulated rates are designed to recover our specific costs of
providing the regulated services or products; and
- - Depending on demand for regulated services and products, and the
level of competition, direct and indirect, it is reasonable to
assume that our rates are set at levels that will recover our costs
and that these rates can be charged to and collected from our
customers. This criterion must also take into account anticipated
changes in levels of demand or competition during the recovery
period for any capitalized costs.
We meet these criteria at present and, therefore the provisions of
SFAS 71 apply to us. Under SFAS 71 we are required to defer certain
costs that would typically be expensed under GAAP; these costs are
referred to as deferred charges or regulatory assets.
Our ability to defer a cost is subject to our ability to provide
evidence that the following additional criteria are met:
- - It is probable that the inclusion of the capitalized (deferred)
cost in allowed costs for ratemaking purposes will provide future
revenue in an amount at least equal to the capitalized (deferred)
cost; and
- - The future revenue will be provided to permit recovery of the
previously incurred cost rather than to provide for expected levels
of similar future costs.
Based on the December 31, 1998 balance sheet, if we were required
to discontinue the application of SFAS 71, we would be required to take
an after-tax charge to earnings of approximately $24.6 million
attributable to net regulatory assets.
On March 20, 1998, we filed with the VPSB a Motion for
Reconsideration of and to Alter or Amend the VPSB's Order released on
March 2, 1998. The principal areas in which we requested that the VPSB
change its ruling included the following:
- - A correction to the VPSB's calculation of the $5.48 million Hydro-
Quebec contract power cost disallowance;
- - Reversal of the accounting treatment specified by the VPSB for cash
payments made by Hydro-Quebec under arrangements that we had
previously negotiated in order to avoid rate increases in prior
years for customers;
- - Restoration of $418,000 of costs associated with the construction
of the Searsburg wind generation facility;
- - Restoration of various other compensation and payroll costs;
- - Reversal of the suspension of amortization of costs associated with
the Pine Street Barge Canal site; and
- - Reconsideration of our request to increase the allowed rate of
return from 11.25 percent to 12 percent.
Immediately following the issuance of the June 8, 1998 VPSB Order
on our Motion for Reconsideration, which largely reaffirmed the earlier
Order, Duff & Phelps and Standard & Poor's lowered our securities credit
ratings. Moody's also subsequently lowered our securities credit
ratings.
In June 1998, we appealed the VPSB's February 27, 1998 Order and
the June 8, 1998 Reconsideration Order to the Vermont Supreme Court.
The briefing of the case by all parties was completed in January 1999.
A hearing before the Vermont Supreme Court is scheduled for March 16,
1999. A number of other Vermont utilities have submitted briefs in
support of the Company.
The Company believes that the decisions in the VPSB's February 27,
1998 Order and June 8, 1998 Reconsideration Order are factually
inaccurate and legally incorrect. Specifically, the Company is
appealing the VPSB's determination that it was imprudent in committing
to the Hydro-Quebec contract in August, 1991, and the VPSB's ruling that
because the contract power is priced over-market under current forecasts
of market prices, it is therefore considered "not used and useful". The
Company asserts, among other arguments, that the VPSB's Order deprives
the Company's shareholders of their property in an unconstitutional
manner. The VPSB's decision, if not changed, could have a significant
negative impact on the Company's reported financial condition, and could
impact its credit ratings, dividend policy and financial viability.
1998 Retail Rate Case -- On May 8, 1998, the Company filed a request
with the VPSB to increase its retail rates by 12.93 percent due to the
following increases in its cost of service:
- - The higher cost of power;
- - The cost of the January 1998 ice storm; and
- - Investments in new plant and equipment.
The VPSB suspended the tariff filings on June 15, 1998. The
Company submitted testimony in the case that included analysis of viable
alternatives to the Hydro-Quebec contract at various times in 1991 and
1992. The VPSB had taken the viewpoint in the Company's 1997 rate case
that the Company would have been able to terminate the Hydro-Quebec
contract without penalty during that time period, and would have been
able to access the market for power at that time. The Company's
analysis showed that, based on price only, the Hydro-Quebec contract was
less expensive than virtually all other long term power resources
available at that time. The analysis also showed that when other non-
price benefits, like environmental benefits and the reliability of a
system power resource, are taken into account, the Hydro-Quebec contract
was still less costly than alternatives. The Company has testified that
even today, when costs and benefits for society are accounted for, as
Vermont regulators and statutes require, the Hydro-Quebec power is not
more costly than market power.
In testimony submitted on September 21, 1998, the Department argued
for the following:
- - A $22 million disallowance of Hydro-Quebec contract costs;
- - A rate decrease of 3.6 percent;
- - The elimination of the Company's common stock dividend; and
- - Various other restrictions.
Additionally, the Department's recommendation was that
approximately $12.5 million of the disallowance of Hydro-Quebec contract
costs be suspended for one year, which would provide the Company with a
4.5 percent rate increase only for that year, followed by automatic
reinstatement of the larger power cost disallowance with a resulting
decrease (in 2000) from its rate levels today, absent further VPSB
order. The Department recommended this one year delay in the Hydro-
Quebec contract cost disallowance in order to allow the Company time to
negotiate lower costs of power under the Hydro-Quebec contract.
IBM, the Company's largest customer, argued for a rate decrease of
0.2 percent, a disallowance of Hydro-Quebec power costs in the amount of
$13 million, and the elimination of the common stock dividend.
In its rebuttal case, the Company intended to present the VPSB with
testimony that:
- - The Department's and IBM's recommendations amount to improper rate
making that will have adverse economic and accounting impacts under
applicable accounting rules;
- - The only cogent evidence of alternative portfolios of power
resources available in 1991 presented to the VPSB is from the
Company's witnesses and the only conclusion that can be drawn from
that evidence justifies a determination that there should be no
Hydro-Quebec power contract cost disallowance; and
- - The Company requires substantial rate relief in order to ensure its
financial stability, access to capital markets and the continuation
of adequate, reliable and safe service to its customers.
The Company also intended to present to the VPSB considerable
evidence that:
- - It has made, and continues to make, efforts to achieve a
negotiated reformulation of the arrangement with Hydro-Quebec;
- - Placing it at risk of bankruptcy will not improve the Company's
prospects of achieving success in such a negotiation;
- - Bankruptcy reorganization is not an appropriate public policy
solution to high power cost obligations; and
- - Its default of obligations to Hydro-Quebec and other creditors
would cause substantial risks of default in the same contractual
relationships by many other Vermont utilities under "step-up" or
similar provisions contained in such arrangements.
On November 18, 1998, by Memorandum of Understanding (MOU), the
Company, the Department and IBM agreed to stay, effective November 16,
1998, rate proceedings in the 1998 rate case until or after September 1,
1999, or such earlier date as the parties may later agree to or the VPSB
may order. The MOU provides for a 5.7 percent temporary retail rate
increase, to produce $9.19 million in annualized additional revenue,
effective with service rendered December 15, 1998. An additional
surcharge in 1999 will be permitted, without further VPSB 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.
The stay and suspension of this pending rate case and the temporary
rate levels agreed to in the MOU are designed to allow the Company to
continue to provide adequate and efficient service to its customers
while it seeks mitigation of power supply costs.
Following the stay, which expires on September 1, 1999 or such
earlier date as agreed to by the parties or ordered by the VPSB, the
remaining proceedings in the case would commence and, as noted above, a
final VPSB decision would be issued by December 15, 1999. In the event
that the VPSB issues a final order that allows a retail rate increase
that is less than the temporary rates, all sums collected in excess of
such final rates would be refunded by adjusting rates on a prospective
basis, by customer class, to reflect the appropriate refund amounts.
The MOU does not provide for any specific disallowance of power
costs under the Company's purchase power contract with Hydro-Quebec.
Issues respecting recovery of such power costs are preserved for future
proceedings.
The Company agreed not to file with the VPSB a petition requesting
any further increase in retail electric rates prior to September 1,
1999, except that this MOU does not preclude it from filing a request
for additional temporary rate increases pursuant to 30 V.S.A. Section
226(a).
The temporary rates include $1 million that is to be used for
enhanced right-of-way maintenance and pole testing and treatment.
Regulatory asset account balances of $5.3 million, which are
subject to recovery in this docket, are to be amortized over seven
years, beginning January 1999. These balances reflect only the amount
filed in the May 1998 rate case, and are related to regulatory
commission expense, tree trimming, storm damage and the costs associated
with the ice storm of 1998. This amortization period will be subject to
review by the VPSB after the expiration of the stay.
In the event that the Vermont Supreme Court issues an order
reversing the VPSB's orders in the Company's 1997 rate case prior to
issuance of a final order in the 1998 rate case, any resulting
adjustments in rates will not become effective until the VPSB issues a
final order in the 1998 rate case. The MOU provides that nothing in it
will reduce or limit the Company's entitlement to full recovery of any
amounts due it if it should prevail on the appeal.
The MOU was approved by the VPSB on December 11, 1998. The
temporary rates, as adjusted by any surcharge related to the Pine Street
Barge Canal site described above, will remain in effect until the VPSB
issues a final order in the rate case docket, expected by December 15,
1999.
Notwithstanding the interim rate settlement, the Company is unable
to predict whether the MOU or other future events, singularly or in
combination, could cause its lending banks to refuse to allow further
borrowings under its revolving loan agreement, to seek to enter into a
new credit agreement with the Company and/or to immediately call in all
outstanding loans. If the Company is unable to borrow on a short-term
basis, it will evaluate all potential alternatives available at the
time, including, but not limited to, the filing of a petition for
reorganization under the United States Bankruptcy Code.
6. Corporate Headquarters Lease - As part of the Company's efforts
to reduce operating costs, it evaluated options to its corporate
headquarters lease, which runs through June 2009. The Company is in the
process of negotiating the termination of its operating lease for its
corporate headquarters and two of its service centers.
It is probable that the Company will purchase the lease and sell
the corporate headquarters in 1999. The Company has recorded a loss of
approximately $1.9 million (pre-tax) in 1998 to reflect the probable
loss of completing these transactions. The Company would retain
ownership of its two service centers.
7. Deferred Charges Not Included in Rate Base. The Company has
incurred and deferred approximately $7.3 million in costs for tree
trimming, storm damage and regulatory commission work of which $5.3
million will be amortized over seven years beginning in January 1999.
Currently, the Company also amortizes costs based on historical averages
and does not receive a return on amounts deferred in excess of
historical averages. Management expects to seek and receive ratemaking
treatment for deferred costs in future filings.
8. Other Legal Matters. The Company is involved in legal and
administrative proceedings in the normal course of business and does not
believe that the ultimate outcome of these proceedings will have a
material effect on the financial position or the results of operations
of the Company.
J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT
Agreements executed in 1985 among the Company, VELCO, other NEPOOL
members and Hydro-Quebec provided for the construction of the second
phase (Phase II) of the interconnection between the New England electric
systems and that of Hydro-Quebec. Phase II expands the Phase I
facilities from 690 megawatts to 2,000 megawatts and provides for
transmission of Hydro-Quebec power from the Phase I terminal in northern
New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II
commenced in 1988 and was completed in late 1990. The Company is
entitled to 3.2 percent of the Phase II power-supply benefits. Total
construction costs for Phase II were approximately $487 million. The
New England participants, including the Company, have contracted to pay
monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs.
As a supporting participant, the Company must make support payments
under thirty-year agreements. These support agreements meet the capital
lease accounting requirements under SFAS 13. At December 31, 1998, the
present value of the Company's obligation was $7.7 million.
Projected future minimum payments under the Phase II support agreements
are as follows:
Year ending December 31,
1999 . . . . . . . . . . . . $ 452,726
2000 . . . . . . . . . . . . 452,726
2001 . . . . . . . . . . . 452,726
2002 . . . . . . . . . . . 452,726
2003 . . . . . . . . . . . 452,726
Total for 2004-2020 . . . . 5,432,706
----------
$7,696,336
==========
The Phase II portion of the project is owned by New England Hydro-
Transmission Electric Company and New England Hydro-Transmission
Corporation, subsidiaries of New England Electric System, in which
certain of the Phase II participating utilities, including the Company,
own equity interests. The Company holds approximately 3.2 percent of
the equity of the corporations owning the Phase II facilities.
K. LONG-TERM POWER PURCHASES
1. Unit Purchases. Under long-term contracts with various electric
utilities in the region, the Company is purchasing certain percentages
of the electrical output of production plants constructed and financed
by those utilities. Such contracts obligate the Company to pay certain
minimum annual amounts representing the Company's proportionate share of
fixed costs, including debt service requirements (amounts necessary to
retire the principal of and to pay the interest on the portion of the
related long-term debt ascribed to the Company) whether or not the
production plants are operating. The cost of power obtained under such
long-term contracts, including payments required to be made when a
production plant is not operating, is reflected as "Power Supply
Expenses" in the accompanying Consolidated Statements of Income.
Information (including estimates for the Company's portion of
certain minimum costs and ascribed long-term debt) with regard to
significant purchased power contracts of this type in effect at December
31, 1998 follows:
Stony Vermont
Brook Yankee
----- -------
(Dollars in thousands)
Plant capacity . . . . . . . . . . . . .352.0 MW 531.0 MW
Company's share of output . . . . . . . 4.4% 17.7%
Contract period . . . . . . . . . . . . (1) (2)
Company's annual share of:
Interest . . . . . . . . . . . . . . $ 207 $ 2,040
Other debt service . . . . . . . . . 333 ---
Other capacity . . . . . . . . . . . 221 29,637
------ -------
Total annual capacity . . . . . . . . $ 761 $31,677
====== =======
Company's share of long-term
Debt . . . . . . . . . . . . . . . . . $3,931 $16,696
====== =======
(1) Life of plant estimated to be 1981 - 2006.
(2) License for plant operations expires in 2012.
2. Hydro-Quebec System Power Purchases. Under various contracts,
the details of which are described in the table below, the Company
purchases capacity and associated energy produced by the Hydro-Quebec
system. Such contracts obligate the Company to pay certain fixed
capacity costs whether or not energy purchases above a minimum level set
forth in the contracts are made. Such minimum energy purchases must be
made whether or not other, less expensive energy sources might be
available. These contracts are intended to complement the other
components in the Company's power supply to achieve the most economic
power-supply mix reasonably available.
The Company's current purchases pursuant to the contract with
Hydro-Quebec entered into December 4, 1987 (the 1987 Contract) are as
follows: (1) Schedule B -- 68 megawatts of firm capacity and associated
energy to be delivered at the Highgate interconnection for 20 years that
began in September 1995; and (2) Schedule C3 -- 46 megawatts of firm
capacity and associated energy to be delivered at interconnections to be
determined at any time for 20 years, which began in November 1995.
During 1994, the Company negotiated an arrangement with Hydro-
Quebec that reduces the cost impacts associated with the purchase of
Schedules B and C3 under the 1987 Contract, over the November 1995
through October 1999 period (the July 1994 Agreement). Under the July
1994 Agreement, the Company, in essence, will take delivery of the
amounts of energy as specified in the 1987 Contract, but the associated
fixed costs will be significantly reduced from those specified in the
1987 Contract.
As part of the July 1994 Agreement, the Company is obligated to
purchase $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.
During the first year of the July 1994 Agreement (the period from
November 1995 through October 1996), the average cost per kilowatt-hour
of Schedules B and C3 combined was cut from 6.4 to 4.2 cents per
kilowatt-hour, a 34 percent (or $16 million) cost reduction. Over the
period from November 1996 through December 2000 and accounting for the
cash payments to Hydro-Quebec, the combined unit costs will be lowered
from 6.5 to 5.8 cents per kilowatthour, reducing unit costs by 10
percent and saving $20.7 million in nominal terms.
All of the Company's contracts with Hydro-Quebec call for the
delivery of system power and are not related to any particular
facilities in the Hydro-Quebec system. Consequently, there are no
identifiable debt-service charges associated with any particular Hydro-
Quebec facility that can be distinguished from the overall charges paid
under the contracts.
A summary of the Hydro-Quebec contracts, including the July 1994
Agreement, but excluding the January and November 1996 arrangements
(described below) including historic and projected charges for the years
indicated, follows:
The 1987 Contract
Schedule B Schedule C3
---------- -----------
(Dollars in thousands)
Capacity Acquired . . . . . . . . . . . . 68 MW 46 MW
Contract Period . . . . . . . . . . . .1995-2015 1995-2015
Minimum Energy Purchase
(annual load factor) . . . . . . . . . . 75% 75%
Annual Energy Charge . . . . . . . . . . $9,271 $6,825
(1998) (1998)
$15,151 10,451
(1999-2015)* (1999-2015)*
Annual Capacity Charge . . . . . . . . . $17,303 $3,394
(1998) (1998)
$17,074 $11,593
(1999-2015)* (1999-2015)*
Average Cost per KWH . . . . . . . . . . 7.6 cents** 4.0 cents
(1998)*** (1998)***
7.0 cents 6.9 cents
(1999-2015)****(1999-2015)****
*Estimated average.
**Higher per kwh rate for Schedule B in 1998, as compared to future
years, is due to the 1998 ice storm. Schedule B was delivered at a
capacity factor of 63%; future years are estimated to be at 75%
capacity factor.
***Excludes amortization of payments to Hydro-Quebec for the July 1994
Agreement.
****Estimated average in nominal dollars, levelized over the period
indicated.
Includes amortization of payments to Hydro-Quebec for the July 1994
Agreement.
Under an arrangement negotiated in January 1996, the Company
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. The Company received VPSB
approval of this accounting treatment in an Accounting Order dated
December 31, 1996.
Under the 1996 arrangement, the Company is required to shift up to
40 megawatts of its 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
the level of benefits to the Company will depend on various factors, the
Company estimates that the 1996 arrangement will provide a minimum
benefit of $1.8 million on a net present value basis. During 1998, the
Company purchased or sold to others 44.2 percent of the minimum purchase
obligation for that year. The Company recorded a liability of $0.3
million for its 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, the Company 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 Agreement can be exercised in addition to this purchase option.
Over the same period, Hydro-Quebec can exercise an option on an annual
basis to purchase up to 600,000 MWh at the 1987 Contract energy price.
Hydro-Quebec can purchase no more than 200,000 MWh in any given year. In
1998, Hydro-Quebec called on the Company to deliver 51,968 MWh to a
third party at a net cost to the Company of $232,958 which was due to
higher energy replacement costs.
L. SUBSEQUENT EVENTS
1. Power Purchase and Supply Agreement -- On February 11, 1999,
the Company entered into a contract with Morgan Stanley Capital Group,
Inc. (MS) as a result of the Company's power requirements solicitation
in 1998. A master power purchase and sales agreement (PPSA) dated
February 11, 1999 defines the general contract terms under which the
parties may transact. The sales under the PPSA commenced on February
12, 1999, and will terminate after all obligations under each
transaction entered into by MS and the Company have been fulfilled,
currently anticipated to be June 30, 2001. The PPSA has been noticed
to the VPSB and filed with the FERC.
The parties have also agreed to enter into two transactions subject
to the PPSA.
- - Sale by the Company to MS. -- On a daily basis, and at MS's
discretion, the Company will sell power from all or part of its
portfolio of power resources to MS at predefined operating and
pricing parameters. The Company can decide to sell power to MS
from any power resource available to it, provided the sales of
power are consistent with the predefined operating and pricing
parameters. The Company retains all rights and obligations
related to its power resources, such as dispatch, plant
modifications and transfer of ownership. This transaction does not
constitute a sale or lease of any Company resource.
- - Sale by MS to the Company. - MS will sell to the Company, at a
predefined price, power sufficient to serve pre-established load
requirements. MS has the right but not the obligation, upon a
request from the Company, to supply additional power at prices
negotiated by both parties. The power sold to the Company may be,
but is not required to be, power that MS has purchased from the
Company under the transaction described above.
The parties have agreed to the protocols that will be used to
schedule power sales and purchases between the parties and to secure
necessary transmission with respect to the two transactions described
above.
The PPSA provides the Company with a means of managing price risks
associated with changing fossil fuel prices. The Company remains
responsibile for balancing supply resources when actual loads vary from
the pre-established load requirements that MS is obligated to satisfy
and for resource performance and availability.
2. 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 substantial,
additional investments in GMER and it was anticipated that GFI or other
parties would make substantial, additional 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, the Company considered it to be in the
best interest of its 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 the Company substantial relief from a
"non-compete clause" in the 1997 agreement that would have restricted
its activities in the retail energy business for seven years.
3. Vermont Yankee. On February 25, 1999, the Board of Directors
of Vermont Yankee Nuclear Power Corporation granted an exclusive right
to AmerGen Energy Company to conduct due diligence and negotiate a
possible agreement to purchase the assets of Vermont Yankee. Due
diligence will occur over a 120-day period.
AmerGen was formed in 1997 as a joint venture by PECO Energy of
Philadelphia, Pennsylvania and British Energy of Edinburgh, United
Kingdom to purchase and operate nuclear plants in the United States.
Regulatory approval by the Nuclear Regulatory Commission, the
Securities and Exchange Commission and the VPSB and others will be
needed prior to completion of any final sale transaction.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and
capitalization data of Green Mountain Power Corporation (a Vermont
corporation) as of December 31, 19987 and 1997, and the related
consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1998. These financial statements
are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
As discussed in Note I.5, the Company has appealed the Vermont Public
Service Board's February 27, 1998 rate order to the Vermont Supreme
Court. In addition, the Company is involved in a rate proceeding
initiated in 1998 that is anticipated to reach final decision by
December 15, 1999. The outcomes of the appeal process and the rate
proceeding could have a significant adverse impact on the Company's
reported financial condition and 1999 results of operations and could
impact the Company's financial viability.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Green Mountain Power Corporation as of December 31, 1998 and 1997, and
the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 5, 1999
(except with respect to the matters discussed
in Note L as to which the date is February 26, 1999)
Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1998, 1997 and 1996
Additions
Balance at ------------------------------- Balance at
Beginning of Charged to Charged to End of
Description Period Cost & Expenses Other Accounts Deductions Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Injuries and Damages
1998................................. $663,785 $2,735,000 $5,000,000 $500,000 $7,898,785
1997................................. $237,892 $427,546 $ -- $1,653 $663,785
1996................................. $103,301 $572,000 $ -- $437,409 $237,892
Bad Debt Reserve (2)
1998................................. $493,405 $393,949 $83,299 (1) $575,653 $395,000
1997................................. $498,024 $637,010 $173,899 (1) $815,528 $493,405
1996................................. $417,684 $677,272 $72,344 (1) $669,276 $498,024
(1) Represents collection of accounts previously written off.
(2) Includes non-utility bad debt reserve.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEMS 10, 11, 12 & 13
Certain information regarding executive officers called for by Item
10, "Directors and Executive Officers of the Registrant," is furnished
under the caption, "Executive Officers" in Item 1 of Part I of this
Report. The other information called for by Item 10, as well as that
called for by Items 11, 12, and 13, "Executive Compensation," "Security
Ownership of Certain Beneficial Owners and Management" and "Certain
Relationships and Related Transactions," will be set forth under the
captions "Election of Directors," "Board Compensation, Meetings,
Committees and Other Relationships" "Section 16(a) Beneficial Ownership
Reporting Compliance," "Executive Compensation and Other Information,"
"Compensation Committee Report on Executive Compensation," "Performance
Graph," "Pension Plan Information and Other Benefits" and "Securities
Ownership of Certain Beneficial Owners and Management" in the Company's
definitive proxy statement relating to its annual meeting of
stockholders to be held on May 20, 1999. Such information is
incorporated herein by reference. Such proxy statement pertains to the
election of directors and other matters. Definitive proxy materials
will be filed with the Securities and Exchange Commission pursuant to
Regulation 14A in April 1999.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
Filed
Herewith
On Page
Item 14(a)(1). The financial statements and financial 47
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.
ITEM 14 (a) (3). EXHIBITS
Incorporated by Reference from
Exhibit SEC Docket or
Number Exhibit Page Filed Herewith
- ------- ------- -------------------
3-a Restated Articles of Association, as certified 3-a Form 10-K 1993
June 6, 1991. (1-8291)
3-a-1 Amendment to 3-a above, dated as of May 20, 1993. 3-a-1 Form 10-K 1993
(1-8291)
3-a-2 Amendment to 3-a above, dated as of October 11, 1996. 3-a-2 Form 10-Q Sept. 1996
(1-8291)
3-b By-laws of the Company, as amended 3-b Form 10-K 1996
February 10, 1997. (1-8291)
4-b-1 Indenture of First Mortgage and Deed of Trust 4-b 2-27300
dated as of February 1, 1955.
4-b-2 First Supplemental Indenture dated as of 4-b-2 2-75293
April 1, 1961.
4-b-3 Second Supplemental Indenture dated as of 4-b-3 2-75293
January 1, 1966.
4-b-4 Third Supplemental Indenture dated as of 4-b-4 2-75293
July 1, 1968.
4-b-5 Fourth Supplemental Indenture dated as of 4-b-5 2-75293
October 1, 1969.
4-b-6 Fifth Supplemental Indenture dated as of 4-b-6 2-75293
December 1, 1973.
4-b-7 Seventh Supplemental Indenture dated as 4-a-7 2-99643
August 1, 1976.
4-b-8 Eighth Supplemental Indenture dated as of 4-a-8 2-99643
December 1, 1979.
4-b-9 Ninth Supplemental Indenture dated as of 4-b-9 2-99643
July 15, 1985.
4-b-10 Tenth Supplemental Indenture dated as of 4-b-10 Form 10-K 1989
June 15, 1989. (1-8291)
4-b-11 Eleventh Supplemental Indenture dated as of 4-b-11 Form 10-Q Sept
September 1, 1990. 1990 (1-8291)
4-b-12 Twelfth Supplemental Indentrue dated as of 4-b-12 Form 10-K 1991
March 1, 1992. (1-8291)
4-b-13 Thirteenth Supplemental Indenture dated as of 4-b-13 Form 10-K 1991
March 1, 1992. (1-8291)
4-b-14 Fourteenth Supplemental Indenture dated as of 4-b-14 Form 10-K 1993
November 1, 1993. (1-8291)
4-b-15 Fifteenth Supplemental Indenture dated as of 4-b-15 Form 10-K 1993
November 1, 1993. (1-8291)
4-b-16 Sixteenth Supplemental Indenture dated as of 4-b-16 Form 10-K 1995
December 1, 1995. (1-8291)
4-b-17 Revised form of Indenture as filed as an Exhibit 4-b-17 Form 10-Q Sept. 1995
to Registration Statement No. 33-59383. (1-8291)
4-b-18 Credit Agreement by and among Green Mountain Power 4-b-18 Form 10-K 1997
The Bank of Nova Scotia, State Street Bank and (1-8291)
Trust Company, Fleet National Bank, and Fleet
National Bank, as Agent
4-b-18 Amendment to Exhibit 4-b-18 4-b-18a Form 10-Q Sept. 1998
(a) (1-8291)
10-a Form of Insurance Policy issued by Pacific 10-a 33-8146
Insurance Company, with respect to
indemnification of Directors and Officers.
10-b-1 Firm Power Contract dated September 16, 1958, 13-b 2-27300
between the Company and the State of Vermont
and supplements thereto dated September 19,
1958; November 15, 1958; October 1, 1960 and
February 1, 1964.
10-b-2 Power Contract, dated February 1, 1968, between 13-d 2-34346
the Company and Vermont Yankee Nuclear Power
Corporation.
10-b-3 Amendment, dated June 1, 1972, to Power Contract 13-f-1 2-49697
between the Company and Vermont Yankee Nuclear
Power Corporation.
10-b-3 Amendment, dated April 15, 1983, to Power 10-b-3(a) 33-8164
(a) Contract between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-3 Additional Power Contract, dated 10-b-3(b) 33-8164
(b) February 1, 1984,between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-4 Capital Funds Agreement, dated February 1, 13-e 2-34346
1968, between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-5 Amendment, dated March 12, 1968, to Capital 13-f 2-34346
Funds Agreement between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-6 Guarantee Agreement, dated November 5, 1981, 10-b-6 2-75293
of the Company for its proportionate share
of the obligations of Vermont Yankee Nuclear
Power Corporation under a $40 million loan
arrangement.
10-b-7 Three-Party Power Agreement among the Company, 13-i 2-49697
VELCO and Central Vermont Public Service
Corporation dated November 21, 1969.
10-b-8 Amendment to Exhibit 10-b-7, dated June 1, 1981. 10-b-8 2-75293
10-b-9 Three-Party Transmission Agreement among the 13-j 2-49697
Company, VELCO and Central Vermont Public
Service Corporation, dated November 21, 1969.
10-b-10 Amendment to Exhibit 10-b-9, dated June 1, 1981. 10-b-10 2-75293
10-b-12 Unit Purchase Contract dated February 10, 1968, 13-h 2-34346
between the Company and Vermont Electric
Power Company, Inc., for purchase of
"Merrimack" power from Public Service
Company of New Hampshire.
10-b-14 Agreement with Central Maine Power Company et 5.16 2-52900
al, to enter into joint ownership of Wyman
plant, dated November 1, 1974.
10-b-15 New England Power Pool Agreement as amended to 4.8 2-55385
November 1, 1975.
10-b-16 Bulk Power Transmission Contract between the 13-v 2-49697
Company and VELCO dated June 1, 1968.
10-b-17 Amendment to Exhibit 10-b-16, dated June 1, 1970. 13-v-i 2-49697
10-b-20 Power Sales Agreement, dated August 2, 1976, as 10-b-20 33-8164
amended October 1, 1977, and related
Transmission Agreement, with the Massachusetts
Municipal Wholesale Electric Company.
10-b-21 Agreement dated October 1, 1977, for Joint 10-b-21 33-8164
Ownership, Construction and Operation of the
MMWEC Phase I Intermediate Units, dated
October 1, 1977.
10-b-28 Contract dated February 1, 1980, providing for 10-b-28 33-8164
the sale of firm power and energy by the Power
Authority of the State of New York to the
Vermont Public Service Board.
10-b-30 Bulk Power Purchase Contract dated April 7, 10-b-32 2-75293
1976, between VELCO and the Company.
10-b-33 Agreement amending New England Power Pool 10-b-33 33-8164
Agreement dated as of December 1, 1981,
providing for use of transmission inter-
connection between New England and
Hydro-Quebec.
10-b-34 Phase I Transmission Line Support Agreement 10-b-34 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
VETCO and participating New England utilities
for construction, use and support of Vermont
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-35 Phase I Terminal Facility Support Agreement 10-b-35 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
New England Electric Transmission Corporation
and participating New England utilities for
construction, use and support of New Hampshire
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-36 Agreement with respect to use of Quebec 10-b-36 33-8164
Interconnection dated as of December 1, 1981,
among participating New England utilities
for use of transmission interconnection
between New England and Hydro-Quebec.
10-b-39 Vermont Participation Agreement for Quebec 10-b-39 33-8164
Interconnection dated as of July 15, 1982,
between VELCO and participating Vermont
utilities for allocation of VELCO's rights
and obligations as a participating New
England utility in the transmission inter-
connection between New England and Hydro-Quebec.
10-b-40 Vermont Electric Transmission Company, Inc. 10-b-40 33-8164
Capital Funds Agreement dated as of July 15,
1982, between VETCO and VELCO for VELCO to
provide capital to VETCO for construction of
the Vermont facilities of the transmission
inter-connection between New England and
Hydro-Quebec.
10-b-41 VETCO Capital Funds Support Agreement dated as 10-b-41 33-8164
of July 15, 1982, between VELCO and participating
Vermont utilities for allocation of VELCO's
obligation to VETCO under the Capital Funds
Agreement.
10-b-42 Energy Banking Agreement dated March 21, 1983, 10-b-42 33-8164
among Hydro-Quebec, VELCO, NEET and parti-
cipating New England utilities acting by and
through the NEPOOL Management Committee for
terms of energy banking between participating
New England utilities and Hydro-Quebec.
10-b-43 Interconnection Agreement dated March 21, 1983, 10-b-43 33-8164
between Hydro-Quebec and participating New
England utilities acting by and through the
NEPOOL Management Committee for terms and
conditions of energy transmission between
New England and Hydro-Quebec.
10-b-44 Energy Contract dated March 21, 1983, between 10-b-44 33-8164
Hydro-Quebec and participating New England
utilities acting by and through the NEPOOL
Management Committee for purchase of
surplus energy from Hydro-Quebec.
10-b-45 Firm-Power Agreement dated as of October 5, 1982, 10-b-45 33-8164
between Ontario Hydro and Vermont Department
of Public Service.
10-b-46 Sales Agreement, dated January 20, 1983, between 10-b-46 33-8164
Central Maine Power Company and the Company
for excess power.
10-b-48 Sales Agreement, dated February 1, 1983, 10-b-48 33-8164
between Niagara Mohawk and Vermont Electric
Power Company for purchase of energy.
10-b-50 Agreement for Joint Ownership, Construction and 10-b-50 33-8164
Operation of the Highgate Transmission
Interconnection, dated August 1, 1984,
between certain electric distribution
companies, including the Company.
10-b-51 Highgate Operating and Management Agreement, 10-b-51 33-8164
dated as of August 1, 1984, among VELCO and
Vermont electric-utility companies, including
the Company.
10-b-52 Allocation Contract for Hydro-Quebec Firm Power 10-b-52 33-8164
dated July 25, 1984, between the State of
Vermont and various Vermont electric utilities,
including the Company.
10-b-53 Highgate Transmission Agreement dated as of 10-b-53 33-8164
August 1, 1984, between the Owners of the
Project and various Vermont electric
distribution companies.
10-b-54 Lease and Sublease Agreement dated June 1, 1984, 10-b-54 33-8164
between Burlington Associates and the Company.
10-b-55 Ground Lease Agreement dated June 1, 1984, 10-b-55 33-8164
between GMP Real Estate Corporation and
Burlington Associates.
10-b-56 Assignment of Lease and Agreement, dated June 1, 10-b-56 33-8164
1984, from Burlington Associates to Teachers
Insurance and Annuity Association of America.
10-b-57 Mortgage dated June 1, 1984, from GMP Real Estate 10-b-57 33-8164
Corporation, Mortgagor, to Teachers Insurance
and Annuity Association of America, Mortgagee.
10-b-58 Lease and Operating Agreement dated June 28,1985, 10-b-58 33-8164
between the State of Vermont and the Company.
10-b-59 Service Contract dated June 28, 1985, between the 10-b-59 33-8164
State of Vermont and the Company.
10-b-61 Agreements entered in connection with Phase II 10-b-61 33-8164
of the NEPOOL/Hydro-Quebec + 450 KV HVDC
Transmission Interconnection.
10-b-62 Agreement between UNITIL Power Corp. and the 10-b-62 33-8164
Company to sell 23 MW capacity and energy from
Stony Brook Intermediate Combined Cycle Unit.
10-b-63 Sales Agreement dated as of June 20, 1986, 10-b-63 33-8164
between the Company and UNITIL Power Corp.
for sale of system power.
10-b-64 Sales Agreement dated as of June 20, 1986, 10-b-64 33-8164
between the Company and Fitchburg Gas and
Electric Light Company for sale of 10 MW
capacity and energy from the Vermont Yankee
plant.
10-b-65 Sales Agreement dated September 18, 1985, 10-b-65 Form 10-K 1991
between the Company and Fitchburg Gas and (1-8291)
Electric Light Company for the sale of
system power.
10-b-66 Sales Agreement dated January 1, 1987, between 10-b-66 Form 10-K 1991
the Company and Bozrah Light and Power (1-8291)
Company for sale of power.
10-b-67 Sales Agreement dated August 31, 1987, amending 10-b-67 Form 10-K 1992
the agreement dated June 20, 1986, between (1-8291)
the Company and UNITIL Power Corp. for sale
of system power.
10-b-68 Firm Power and Energy Contract dated December 4, 10-b-68 Form 10-K 1992
1987, between Hydro-Quebec and participating (1-8291)
Vermont utilities, including the Company, for
the purchase of firm power for up to thirty years.
10-b-69 Firm Power Agreement dated as of October 26, 1987, 10-b-69 Form 10-K 1992
between Ontario Hydro and Vermont Department of (1-8291)
Public Service.
10-b-70 Firm Power and Energy Contract dated as of 10-b-70 Form 10-K 1992
February 23, 1987, between the Vermont Joint (1-8291)
Owners of the Highgate facilities and Hydro-
Quebec for up to 50 MW of capacity.
10-b-70 Amendment to 10-b-70. 10-b-70(a) Form 10-K 1992
(a) (1-8291)
10-b-71 Interconnection Agreement dated as of 10-b-71 Form 10-K 1992
February 23, 1987, between the Vermont Joint (1-8291)
Owners of the Highgate facilities and Hydro-Quebec.
10-b-72 Participation Agreement dated as of April 1, 1988, 10-b-72 Form 10-Q
between Hydro-Quebec and participating Vermont June 1988
utilities, including the Company, implementing (1-8291)
the purchase of firm power for up to 30 years
under the Firm Power and Energy Contract dated
December 4, 1987 (previously filed with the
Company's Annual Report on Form 10-K for 1987,
Exhibit Number 10-b-68).
10-b-72 Restatement of the Participation Agreement filed 10-b-72(a) Form 10-K 1988
(a) as Exhibit 10-b-72 on Form 10-Q for June 1988. (1-8291)
10-b-73 Agreement dated as of May 1, 1988, between 10-b-73 Form 10-Q
Rochester Gas and Electric Corporation and the Sept. 1988
Company, implementing the Company's purchase of up (1-8291)
to 50 MW of electric capacity and associated energy.
10-b-74 Agreement dated as of November 1, 1988, between 10-b-74 Form 10-Q for
the Company and Fitchburg Gas and Electric Light Sept. 1988
Company, for sale of electric capacity and (1-8291)
associated energy.
10-b-74 Amendment to Exhibit 10-b-74. 10-b-74(a) Form 10-Q
(a) Sept 1989
(1-8291)
10-b-75 Allocation Agreement dated as of March 25, 1988, 10-b-75 Form 10-Q
between Ontario Hydro and the State of Vermont, Sept. 1988
for firm power and associated energy from (1-8291)
Ontario Hydro.
10-b-77 Firm Power and Energy Contract dated December 29, 10-b-77 Form 10-K 1988
1988, between Hydro-Quebec and participating (1-8291)
Vermont utilities, including the Company, for the
purchase of up to 54 MW of firm power and energy.
10-b-78 Transmission Agreement dated December 23, 1988, 10-b-78 Form 10-K 1988
between the Company and Niagara Mohawk Power (1-8291)
Corporation (Niagara Mohawk), for Niagara
Mohawk to provide electric transmission to
the Company from Rochester Gas and Electric
and Central Hudson Gas and Electric.
10-b-79 Lease Agreement dated November 1, 1988, between 10-b-79 Form 10-K 1988
the Company and International Business Machines (1-8291)
Corporation (IBM) for the lease to IBM of the
gas turbines and associated facilities located
on land adjacent to IBM's Essex Junction,
Vermont, plant.
10-b-80 Sales Agreement dated January 1, 1989, between 10-b-80 Form 10-K 1988
the Company and Public Service of New Hampshire (1-8291)
(PSNH)for PSNH to purchase electric capacity
from the Company.
10-b-81 Sales Agreement dated May 24, 1989, between 10-b-81 Form 10-Q
the Town of Hardwick, Hardwick Electric Department June 1989
and the Company for the Company to purchase (1-8291)
all of the output of Hardwick's generation and
transmission sources and to provide Hardwick
with all-requirements energy and capacity except
for that provided by the Vermont Department of
Public Service or Federal Preference Power.
10-b-82 Sales Agreement dated July 14, 1989, between 10-b-82 Form 10-Q
Northfield Electric Department and the Company June 1989
for the Company to purchase all of the output (1-8291)
of Northfield's generation and transmission
sources and to provide Northfield with all-
requirements energy and capacity except for
that provided by the Vermont Department of
Public Service or Federal Preference Power.
10-b-83 Power Purchase and Operating Agreement dated as 10-b-83 Form 10-Q
of April 20, 1990, between CoGen Lime Rock, June 1990
Inc., and the Company for the production of (1-8291)
energy to meet customer needs.
10-b-84 Capacity, Transmission and Energy Service 10-b-84 Form 10-K 1992
Agreement dated December 23, 1992, between (1-8291)
the Company and Connecticut Light and Power
Company (CL&P) for CL&P to supply power to
Bozrah Light and Power Company.
*10-b-85 Power Purchase and Sale Agreement between 10-b-85
Morgan Stanley Capital Group Inc. and the
Company
Management contracts or compensatory plans or arrangements
required to be filed as exhibits to this form 10-K
pursuant to Item 14(c).
10-d-1b Green Mountain Power Corporation Second Amended 10-d-1b Form 10-K 1993
and Restated Deferred Compensation Plan for (1-8291)
Directors.
10-d-1c Green Mountain Power Corporation Second Amended 10-d-1c Form 10-K 1993
and Restated Deferred Compensation Plan for (1-8291)
Officers.
10-d-1d Amendment No. 93-1 to the Amended and Restated 10-d-1d Form 10-K 1993
Deferred Compensation Plan for Officers. (1-8291)
10-d-1e Amendment No. 94-1 to the Amended and Restated 10-d-1e Form 10-Q
Deferred Compensation Plan for Officers. June 1994
(1-8291)
10-d-2 Green Mountain Power Corporation Medical Expense 10-d-2 Form 10-K 1991
Reimbursement Plan. (1-8291)
10-d-4 Green Mountain Power Corporation Officer 10-d-4 Form 10-K 1991
Insurance Plan. (1-8291)
10-d-4a Green Mountain Power Corporation Officers' 10-d-4a Form 10-K 1990
Insurance Plan as amended. (1-8291)
10-d-8 Green Mountain Power Corporation Officers' 10-d-8 Form 10-K 1990
Supplemental Retirement Plan. (1-8291)
10-d-15b Green Mountain Power Corporation Compensation Program 10-d-15b
for Officers and Key Management Personnel as amended
August 4, 1997
*10-d-21 Severance Agreement with N. R. Brock 10-d-21
*10-d-22 Severance Agreement with C. L. Dutton 10-d-22
*10-d-23 Severance Agreement with R. J. Griffin 10-d-23
*10-d-24 Severance Agreement with J. J. Lampron 10-d-24
*10-d-25 Severance Agreement with M. H. Lipson 10-d-25
*10-d-26 Severance Agreement with C. T. Myotte 10-d-26
*10-d-27 Severance Agreement with W. S. Oakes 10-d-27
*10-d-28 Severance Agreement with M. G. Powell 10-d-28
*10-d-29 Severance Agreement with S. C. Terry 10-d-29
*10-d-30 Severance Agreement with J. H. Winer 10-d-30
21 Subsidiaries of the Registrant 21 Form 10-K 1996
(1-8291)
*23-a-1 Consent of Arthur Andersen LLP
*24 Power of Attorney
*27 Financial Data Schedule
____________________
* Filed herewith
Item 14(b). A report on Form 8-K was filed on January 8, 1999,
setting forth the conclusions of a report issued December 18, 1998 by
the Working Group on Vermont's Electricity Future, and the financial
implications of the sale by the Company's wholly owned subsidiary, Green
Mountain Resources Inc., of its remaining interest in Green Mountain
Energy.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
GREEN MOUNTAIN POWER CORPORATION
By: /s/ Christopher L. Dutton
_________________________
Christopher L. Dutton, President
and Chief Executive Officer
Date: March 25, 1999
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
SIGNATURE TITLE DATE
/s/ Christopher L. Dutton President and Director March 25, 1999
Christopher L. Dutton (Principal Executive Officer)
/s/ Nancy R. Brock Vice President, Treasurer and March 25, 1999
Nancy R. Brock Chief Financial Officer (Principal
Financial Officer)
/s/ Robert J. Griffin Controller March 25, 1999
Robert J. Griffin (Principal Accounting Officer)
*Thomas P. Salmon Chairman of the Board
*Nordahl L. Brue )
*William H. Bruett )
*Lorraine E. Chickering )
*John V. Cleary )
Directors
*Euclid A. Irving )
*Martin L. Johnson )
*Ruth W. Page )
*By: /s/ Christopher L. Dutton_ March 25, 1999
Christopher L. Dutton
(Attorney - in - Fact)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements of Green Mountain Power
Corporation included in this Form 10-K and have issued our report
thereon dated February 5, 1999. Our audit was made for the purpose of
forming an opinion on the basic financial statements taken as a whole.
The schedule listed in the index on page 47 of this Form 10-K is the
responsibility of the Company's management and is presented for purposes
of complying with the Securities and Exchange Commission's rules and is
not part of the basic consolidated financial statements. This schedule
has been subjected to the auditing procedures applied in the audit of
the basic consolidated financial statements, and in our opinion, fairly
states, in all material respects, the financial data required to be set
forth therein in relation to the basic consolidated financial statements
taken as a whole.
Boston, Massachusetts
March 25, 1999 /s/ Arthur Andersen LLP