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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, 1997
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 13, 1998, was $94,094,396.88
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 13, 1998,
was 5,191,415.
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 21, 1998, 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. It serves approximately 83,000 customers. The Company was
incorporated under the laws of the State of Vermont on April 7, 1893.
For the year ended December 31, 1997, the Company's sources of
revenue were derived as follows: 34.3% from residential customers,
32.7% from small commercial and industrial customers, 21.1% from large
commercial and industrial customers, 10.0% from sales to other
utilities, and 1.9% from other sources. For the same period, the
Company's energy resources for retail and requirements wholesale sales
were obtained as follows: 46.9% from hydroelectric sources (6.9%
Company-owned, 0.1% New York Power Authority (NYPA), 36.8% Hydro-Quebec
and 3.1% small power producers), 36.5% from nuclear generating sources
(the Vermont Yankee plant described below), 9.2% from coal sources, 3.3%
from wood, 0.9% from natural gas, 0.5% from oil, and 0.3% from wind.
The remaining 2.4% was purchased on a short-term basis from other
utilities and through the New England Power Pool (NEPOOL). In 1997, the
Company purchased 92.7% of the energy required to satisfy its retail and
requirements wholesale sales (including energy purchased from Vermont
Yankee and under other long-term purchase arrangements). See Note K of
Notes to Consolidated Financial Statements.
A major source of the Company's power supply is its entitlement to
a share of the power generated by the 531-MW Vermont Yankee nuclear
generating plant owned and operated by Vermont Yankee Nuclear Power
Corporation (Vermont Yankee), in which the Company has a 17.9% equity
interest. For information concerning Vermont Yankee, see "Power
Resources - Vermont Yankee."
The Company participates in NEPOOL, a regional bulk power
transmission organization established to assure the reliability and
economic efficiency of power supply in the Northeast. The Company's
representative to NEPOOL is the Vermont Electric Power Company, Inc.
(VELCO), a transmission consortium owned by the Company and other
Vermont utilities, in which the Company has a 30% equity interest. As a
member of NEPOOL, the Company benefits from increased efficiencies of
centralized economic dispatch, availability of replacement power for
scheduled and unscheduled outages of its own power sources, sharing of
bulk transmission facilities and reduced generation reserve
requirements.
The principal territory served by the Company comprises an area
roughly 25 miles in width extending 90 miles across north central
Vermont between Lake Champlain on the west and the Connecticut River on
the east. Included in this territory are the cities of Montpelier,
Barre, South Burlington, Vergennes and Winooski, as well as the Village
of Essex Junction and a number of smaller towns and communities. The
Company also distributes electricity in four noncontiguous areas located
in southern and southeastern Vermont that are interconnected with the
Company's principal service area through the transmission lines of VELCO
and others. Included in these areas are the communities of Vernon
(where the Vermont Yankee plant is located), Bellows Falls, White River
Junction, Wilder, Wilmington and Dover. The Company also supplies at
wholesale a portion of the power requirements of several municipalities
and cooperatives in Vermont and one utility in another state. The
Company is obligated to meet the changing electrical requirements of
these wholesale customers, in contrast to the Company's obligation to
other wholesale customers, which is limited to specified amounts of
capacity and energy established by contract.
Major business activities in the Company's service areas include
computer assembly and components manufacturing (and other electronics
manufacturing), granite fabrication, service enterprises such as
government, insurance and tourism (particularly winter recreation), and
dairy and general farming.
During the years ended December 31, 1997, 1996, and 1995, electric
energy sales to International Business Machines Corporation (IBM), the
Company's largest customer, accounted for 14.0%, 13.2% and 12.9%,
respectively, of the Company's operating revenues in those years. No
other retail customer accounted for more than 1.0% of the Company's
revenue. Under the present regulatory system, the loss of IBM as a
customer of the Company 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
The Company had 321 employees, exclusive of temporary employees, as
of December 31, 1997. In addition, subsidiaries of the Company had 48
employees at year end.
SEASONAL NATURE OF BUSINESS
The Company experiences its heaviest loads in the colder months of
the year. Winter recreational activities, longer hours of darkness and
heating loads from cold weather usually cause the Company's peak
electric sales to occur in December, January or February. The Company's
heaviest load in 1997 - 311.5 MW - occurred on December 22, 1997. The
Company's retail electric rates are seasonally differentiated. Under
this structure, retail electric rates produce average revenues per
kilowatt hour during four peak season months (December through March)
that are approximately 30% higher than during the eight off-season
months (April through November). See "Energy Efficiency - Rate Design."
OPERATING STATISTICS
For the Years Ended December 31
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
Net System Capability During Peak Month (MW)
Hydro (1)............................................ 180.0 193.8 152.1 179.0 174.9
Lease transmissions.................................. 0.6 0.6 0.3 2.1 3.9
Nuclear (1).......................................... 95.7 95.7 81.9 107.2 109.5
Conventional steam................................... 53.0 52.9 77.8 67.1 92.6
Internal combustion.................................. 64.0 60.7 62.0 60.2 71.0
Combined cycle....................................... 22.1 22.1 22.0 22.6 22.8
Wind................................................. 1.5 -- -- -- --
---------- ---------- ---------- ---------- ----------
Total capability (MW).............................. 416.9 425.8 396.1 438.2 474.7
Net system peak...................................... 311.5 313.0 297.1 308.3 307.3
---------- ---------- ---------- ---------- ----------
Reserve (MW)......................................... 105.4 112.8 99.0 129.9 167.4
========== ========== ========== ========== ==========
Reserve % of peak.................................... 33.8% 36.0% 33.3% 42.1% 54.5%
Net Production (MWH)
Hydro (1)............................................1,073,246 1,192,881 1,043,617 742,088 751,078
Lease transmissions.................................. -- -- -- -- 15,425
Nuclear (1).......................................... 772,030 680,613 682,814 763,690 598,245
Conventional steam................................... 560,504 705,331 673,982 651,105 748,626
Internal combustion.................................. 4,827 2,674 6,646 3,532 2,849
Combined cycle....................................... 104,836 51,162 92,723 37,808 40,966
---------- ---------- ---------- ---------- ----------
Total production...................................2,515,443 2,632,661 2,499,782 2,198,223 2,157,189
Less non-requirements sales to other utilities....... 524,192 663,175 582,942 328,794 271,224
---------- ---------- ---------- ---------- ----------
Production for requirements sales....................1,991,251 1,969,486 1,916,840 1,869,429 1,885,965
Less requirements sales & lease transmissions (MWH)..1,870,913 1,814,371 1,760,830 1,730,497 1,749,454
---------- ---------- ---------- ---------- ----------
Losses and company use (MWH)......................... 120,338 155,115 156,010 138,932 136,511
========== ========== ========== ========== ==========
Losses as a percentage of total production............. 4.78% 5.89% 6.24% 6.32% 6.33%
System load factor (2)................................. 71.6% 69.7% 71.2% 67.7% 68.7%
Sales and Lease Transmissions (MWH)
Residential - GMP.................................... 549,259 557,726 549,296 564,635 541,579
Lease transmissons................................... -- -- -- -- 15,425
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 549,259 557,726 549,296 564,635 557,004
Commercial & industrial - small...................... 645,331 630,839 608,688 604,686 593,560
Commercial & industrial - large...................... 608,051 584,249 556,278 521,400 529,372
Other................................................ 3,939 2,898 8,855 1,146 8,868
---------- ---------- ---------- ---------- ----------
Total retail sales and lease transmissions.........1,806,580 1,775,712 1,723,117 1,691,867 1,688,804
Sales to municipals and cooperatives and
other requirements sales........................... 64,333 38,659 37,713 38,630 60,650
---------- ---------- ---------- ---------- ----------
Total requirements sales...........................1,870,913 1,814,371 1,760,830 1,730,497 1,749,454
Other sales for resale............................... 524,192 663,175 582,942 328,794 271,224
---------- ---------- ---------- ---------- ----------
Total sales and lease transmissions................2,395,105 2,477,546 2,343,772 2,059,291 2,020,678
========== ========== ========== ========== ==========
Average Number of Electric Customers
Residential.......................................... 70,671 70,198 69,659 68,811 67,994
Commercial and industrial - small.................... 11,989 11,828 11,712 11,611 11,447
Commercial and industrial - large.................... 23 25 24 24 25
Other................................................ 75 75 76 76 74
---------- ---------- ---------- ---------- ----------
Total.............................................. 82,758 82,126 81,471 80,522 79,540
========== ========== ========== ========== ==========
Average Revenue per KWH (Cents)
Residential including lease revenues................. 11.18 10.87 10.09 9.03 8.94
Lease charges........................................ -- -- -- -- 0.06
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 11.18 10.87 10.09 9.03 9.00
Commercial and industrial - small.................... 9.10 8.96 8.42 8.00 7.97
Commercial and industrial - large.................... 6.22 6.28 5.86 6.02 5.96
Total retail including lease revenues................ 8.94 8.92 8.36 7.96 7.86
Average Use and Revenue Per Residential Customer
Kilowatt hours including lease transmissions......... 7,772 7,945 7,885 8,206 8,192
Revenues including lease revenues.................... $869 $863 $796 $741 $733
(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, 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 is
principally responsible for quasi-judicial proceedings, such as rate
proceedings. The Department, through a Director for Public Advocacy, is
entitled to participate as a litigant in such proceedings and regularly
does so.
The Company's rate tariffs are uniform throughout its service area.
The Company has entered into two economic development agreements,
providing for reduced charges to large customers to be applied only to
new load. A third economic development agreement with IBM was part of
the rate settlement approved by the VPSB on May 23, 1996. See Item 7.
Management's Discussion and Analysis of Financial Condition and Results
of Operations (MD&A) - "Results of Operations - Operating Revenues and
MWh Sales."
The Company's wholesale rate on sales to three wholesale customers
is regulated by the Federal Energy Regulatory Commission (FERC).
Revenues from sales to these customers were approximately 0.8% of
operating revenues for 1997.
Late in 1989, the Company began serving a municipal utility,
Northfield Electric Department, under its wholesale tariff. This
customer increased the Company's electricity sales by approximately
23,406.4 MWh and peak requirements by approximately 5.5 MW. Revenues in
1997 from Northfield were $1,348,962.
The Company provides 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 1997.
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. See Item 7. MD&A - "Transmission Issues - Federal
Open Access Tariff Orders." NEPOOL has proposed a transmission tariff
for certain transmission facilities, including certain facilities
between New York and New England, that incorporates a load-based method
of capacity allocation for NEPOOL transmission facilities. The proposal
could reduce the amount of capacity available to the Company from such
facilities in the future. See Item 7. MD&A - "Transmission Issues -
Proposed NEPOOL Transmission Tariff."
By reason of its relationship with Vermont Yankee, VELCO and
Vermont Electric Transmission Company, Inc. (VETCO), a wholly owned
subsidiary of VELCO, the Company has 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) thereof (which prohibits the acquisition of securities
of certain other utility companies without approval of the Securities
and Exchange Commission). The Securities and Exchange Commission has
the power to institute proceedings to terminate such exemption for
cause.
Licensing. Pursuant to the Federal Power Act, the FERC has granted
licenses for the following hydro projects:
Project Issue Date Period
- ------- ---------- ------
Bolton February 5, 1982 February 5, 1982 - February 4, 2022
Essex 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, the Vergennes and the Waterbury projects, the amounts
appropriated are not material.
Department of Public Service Twenty-Year Power Plan. In December
1994, the Department adopted an update of its twenty-year electrical
power-supply plan (the Plan) for the State. The Plan includes an
overview of statewide growth and development as they relate to future
requirements for electrical energy; an assessment of available energy
resources; and estimates of future electrical energy demand.
The Company's Integrated Resource Plan (IRP) was published in June
1996. It was developed in a manner consistent with the Department's
Plan. The Company's 1996 IRP calls for a greater emphasis on
distributed utility approaches that can best use the Company's assets,
maximize the benefit of energy efficiency programs, and provide
customers with the highest quality service.
RECENT RATE DEVELOPMENTS
On June 16, 1997, the Company filed a request with the VPSB to
increase retail rates by 16.7 percent and the target return on common
equity from 11.25 percent to 13 percent. The retail rate increase is
needed to cover higher power supply costs and the Company's rising cost
of capital. For further information regarding recent rate developments,
see Item 7. MD&A - "Liquidity and Capital Resources - Rates" and Note
I.5 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 industry to facilitate competition for
electricity sales at wholesale and retail levels. For further
information regarding Competition and Restructuring, See Item 7. MD&A -
"Future Outlook."
POWER RESOURCES
The Company generated, purchased or transmitted 1,954,535.9 MWh of
energy for retail and requirements wholesale customers for the twelve
months ended December 31, 1997. The corresponding maximum one-hour
integrated demand during that period was 311.5 MW on December 22, 1997.
This compares to the previous all-time peak of 322.6 MW on December 27,
1989. The following tabulation shows the source of such energy for the
twelve-month period and the capacity in the month of the period system
peak. See also "Power Resources - Long-Term Power Sales."
Net Generated and Net Generated and
Purchased in Year Purchased in Month
Ended 12/31/97 (a) of Annual Peak
___________________ ___________________
MWh % KW %
WHOLLY OWNED PLANTS
Hydro 140,754.0 6.9 35,300 8.5
Diesel and Gas Turbine 2,671.7 0.1 61,030 14.6
Searsburg 5,386.7 0.3 1,500 0.4
JOINTLY OWNED PLANTS
Wyman #4 3,386.1 0.2 7,030 1.7
Stony Brook I 7,339.2 0.4 7,990 1.9
McNeil 11,075.7 0.5 6,450 1.5
OWNED IN ASSOCIATION W/OTHERS
Vermont Yankee Nuclear 748,068.8 36.5 95,680 22.9
NYPA LEASE TRANSMISSIONS
State of Vermont (NYPA) 1,541.9 0.1 620 0.1
LONG-TERM PURCHASES
Hydro-Quebec 754,280.5 36.8 126,680 30.4
Merrimack #2 189,033.1 9.2 31,820 7.6
Stony Brook I 14,647.2 0.7 14,150 3.4
Small Power Producers 121,938.4 5.9 24,860 6.0
SHORT-TERM PURCHASES 52,185.9 2.4 3,860 1.0
___________ ____ _______ _____
2,052,309.2 100.0
Less System Sales Energy (97,773.8)
NET OWN LOAD 1,954,535.4 416,970 100.0
=========== ====== ======= ======
(a) Excludes losses on off-system purchases, totaling 36,716 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 its Power Contract, the
Company is required to pay 20% of Vermont Yankee's operating expenses
(including depreciation and taxes), fuel costs (including charges in
respect of estimated costs of disposal of spent nuclear fuel),
decommissioning expenses, interest expense and return on common equity,
whether or not the Vermont Yankee plant is operating. In 1969, the
Company sold to other Vermont utilities a share of its entitlement to
the output of Vermont Yankee. Accordingly, those utilities had an
obligation to the Company to pay 2.735% of Vermont Yankee's operating
expenses, fuel costs, decommissioning expenses, interest expense and
return on common equity. As a result of the bankruptcy of one of those
utilities, a portion of the entitlement has reverted back to the
Company. Accordingly, those utilities have an obligation to the Company
to pay 2.338% of Vermont Yankee's operating expenses, fuel costs,
decommissioning expenses, interest expense and return on common equity.
Vermont Yankee has also entered into capital funds agreements with
its sponsor utilities that expire on December 31, 2002. Under its
Capital Funds Agreement, the Company is required, subject to obtaining
necessary regulatory approvals, to provide 20% of the capital
requirements of Vermont Yankee not obtained from outside sources.
On April 27, 1989, Vermont Yankee applied to the Nuclear Regulatory
Commission (NRC) for an amendment to its operating license to extend the
expiration date from December 2007 to March 2012, in order to take
advantage of current NRC policy to issue operating licenses for a 40-
year term measured from the grant of the operating license. Prior NRC
policy, under which the operating license was issued, called for a term
of 40 years from the date of the construction permit. On August 22,
1989, the State, 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.
In New England, five nuclear units are currently under orders from
the NRC not to operate until shown to be in compliance with applicable
safety provisions. In December 1996 and August 1997, decisions were
made to retire two New England nuclear units, Connecticut Yankee and
Maine Yankee, effective immediately, with several years remaining on
each license. The NRC's most recently issued Vermont Yankee's
Systematic Assessment of Licensee Performance scores are for the period
July 16, 1995 to January 18, 1997. Operations, engineering and
maintenance were rated good, while plant support was rated superior.
These scores are identical to Vermont Yankee's scores for the prior 18
month-period.
During periods when Vermont Yankee is unavailable, the Company
incurs replacement power costs in excess of those costs that the Company
would have incurred for power purchased from Vermont Yankee.
Replacement power is available to the Company from NEPOOL and through
special contractual arrangements with other utilities. Replacement
power costs adversely affect cash flow and, absent deferral,
amortization and recovery through rates, would adversely affect reported
earnings. Routinely, in the case of scheduled outages for refueling,
the VPSB has permitted the Company to defer, amortize and recover these
excess replacement power costs for financial reporting and ratemaking
purposes over the period until the next scheduled outage. Vermont
Yankee has adopted an 18-month refueling schedule. On March 21, 1998,
Vermont Yankee began a scheduled refueling outage. 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 $386,000,000, of which $193,000,000 has been
funded. At December 31, 1997, the Company's portion of the net unfunded
liability was $34,000,000, which it expects will be recovered through
rates over Vermont Yankee's remaining operating life.
During 1997, the Company incurred $27,200,000 in Vermont Yankee
annual capacity charges, which included $1,800,000 for interest charges.
The Company's share of Vermont Yankee's long-term debt at December 31,
1997 was $16,000,000.
During the year ended December 31, 1997, the Company utilized
748,068.8 MWh of Vermont Yankee energy to meet 36.5% of its retail and
requirements wholesale (Rate W) sales. The average cost of Vermont
Yankee electricity in 1997 was 4.4 cents per KWh. In 1997, Vermont Yankee
had an annual capacity factor of 93.5%, compared to 83.0% in 1996 and
85.0% in 1995.
INSURANCE
The Price-Anderson Act currently limits public liability from a
single incident at a nuclear power plant to $8.9 billion. Any
liability beyond $8.9 billion are indemnified under an agreement with
the NRC, but subject to congressional approval. The first $200 million
of liability coverage is the maximum provided by private insurance. The
Secondary Financial Protection Program is a retrospective insurance plan
providing additional coverage up to $8.7 billion per incident by
assessing premiums of $79.3 million against each of the 110 reactor
units in the United States that are currently subject to the Progam,
limited to a maximum assessment of $10 million per incident per nuclear
unit in any one year. The maximum assessment is expected to be 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.
Vermont Yankee does, however, 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 restrospective 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, decontanmination
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.
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 are jointly owned by a number
of Vermont utilities, including the Company.
NEPOOL/Hydro-Quebec Interconnection. VELCO and certain other
NEPOOL members have entered into agreements with Hydro-Quebec providing
for the construction in two phases of a direct interconnection between
the electric systems in New England and the electric system of Hydro-
Quebec in Canada. The Vermont participants in this project, which has a
capacity of 2,000 MW, will derive about 9.0% 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 a cost below that of the
replacement cost of power and energy otherwise available to the New
England participants; energy banking, under which participating New
England utilities will transmit relatively inexpensive energy to Hydro-
Quebec during off-peak periods and will receive equal amounts of energy,
after adjustment for transmission losses, from Hydro-Quebec during peak
periods when replacement costs are higher; and provision for emergency
transfers and mutual backup to improve reliability for both the Hydro-
Quebec system and the New England systems.
Phase I. The first phase (Phase I) of the NEPOOL/Hydro-Quebec
Interconnection consists of transmission facilities having a capacity of
690 MW that traverse a portion of eastern Vermont and extend to a
converter terminal located in Comerford, New Hampshire. These
facilities entered commercial operation on October 1, 1986. 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, as
well as 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, 1997, the
present value of the Company's obligation was $8,300,000. The Company's
projected future minimum payments under the Phase II support agreements
are $463,450 for each of the years 1998-2002 and an aggregate of
$6,024,845 for the years 2003-2020.
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, 1997, the capital structure
of such corporations was 39.0% common equity and 61.0% long-term debt.
See Note J of Notes to Consolidated Financial Statements.
At times, the Company requests that portions of its power
deliveries from Hydro-Quebec and other sources be routed through New
York. The Company's ability to do so could be adversely affected by the
proposed tariff that NEPOOL has filed with the FERC. A reduction of the
Company's allocation of capacity on transmission interfaces with New
York could adversely affect the Company's ability to import power to
Vermont from outside New England which would impact the Company's power
costs in the future. See Item 7. MD&A - "Transmission Issues" and Note
J of Notes to Consolidated Financial Statements.
Hydro-Quebec Power Supply Contracts. Under an arrangement
negotiated in January 1996, the Company received cash payments from
Hydro-Quebec of $3,000,000 in 1996 and $1,100,000 in 1997. In
accordance with such arrangement, the Company will shift certain
transmission requirements and make certain minimum payments for periods
in which power is not purchased. In addition, in November 1996, the
Company 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. MD&A - "Power Supply
Expenses" and Notes J and K-2 of Notes to Consolidated Financial
Statements.
In 1997, the Company utilized 405,383.2 MWh under Schedule B,
276,031.2 MWh under Schedule C3, and 72,866.1 MWh under the tertiary
energy contract to meet 36.8% of its retail and requirements wholesale
sales. The average cost of Hydro-Quebec electricity in 1997 was 3.7 cents
per KWh.
New York Power Authority (NYPA). The Department allocates NYPA
power to the Company which, in turn, delivers the power to its
residential and farm customers. The Company purchased at wholesale
1,541.9 MWh to meet 0.1% of its retail and requirements wholesale sales
of NYPA power at an average cost of 0.7 cents per KWh in 1997. Under the
allocation currently made by NYPA of NYPA power to states neighboring
New York, residential and farm customers in the Company's service
territory will be entitled to 0.3 MW annually.
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. The Company is entitled to 28.48 MW of capacity
and related energy from the unit under a 30-year contract expiring May
1, 1998. During the year ended December 31, 1997, the Company utilized
189,033.1 MWh from the unit to meet 9.2% of its total retail and
requirements wholesale sales. The average cost of electricity from this
unit was 3.4 cents per KWh in 1997. 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.
The Company entered into a Joint Ownership Agreement with MMWEC dated as
of October 1, 1977, whereby the Company acquired an 8.8% ownership share
of the plant, entitling the Company to 31.0 MW of capacity. In addition
to this entitlement, the Company has contracted for 14.2 MW of capacity
for the life of the Stony Brook I plant, for which it will pay a
proportionate share of MMWEC's share of the plant's fixed costs and
variable operating expenses. The three units that comprise Stony Brook
I are primarily oil-fired. Two of the units are also capable of burning
natural gas. The natural gas system at the plant was modified in 1985
to allow two units to operate simultaneously on natural gas.
During 1997, the Company utilized 21,986.4 MWh from this plant to
meet 1.1% of its retail and requirements wholesale sales at an average
cost of 9.5 cents (purchased power). 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.
The construction of this plant was sponsored by Central Maine Power
Company. The Company has a joint-ownership share of 1.1% (6.8 MW) in
the Wyman #4 unit, which began commercial operation in December 1978.
During 1997, the Company utilized 3,386.1 MWh from this unit to
meet 0.2% of its retail and requirements wholesale sales at an average
cost of 4.7 per kWh, based only on operation, maintenance, and fuel
costs incurred during 1997. 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. The Company has an 11% or 5.9 MW interest in the
J. C. McNeil plant, which began operation in June 1984. During 1997,
the Company utilized 11,075.7 MWh from this unit to meet 0.5% of its
retail and requirements wholesale sales at an average cost of 5.2 cents per
kWh, based only on operation, maintenance, and fuel costs incurred
during 1997. In 1989, the plant added the capability to burn natural
gas on an as-available/interruptible service basis. See Note I-4 of
Notes to Consolidated Financial Statements.
Small Power Production. The VPSB has adopted rules that implement
for Vermont the purchase requirements established by federal law in the
Public Utility Regulatory Policies Act of 1978 (PURPA). Under the
rules, 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 which is based upon the
projected Vermont composite system's power costs which would be required
but for the purchases from small producers. The state purchasing agent
assigns the energy so purchased, and the costs of purchase, to each
Vermont retail electric utility based upon its pro rata share of total
Vermont retail energy sales. Utilities may also contract directly with
producers. The rules provide that all reasonable costs incurred by a
utility under the rules will be included in the utilities' revenue
requirements for ratemaking purposes.
Currently, the state purchasing agent, Vermont Electric Power
Producers, Inc. (VEPPI), is authorized to seek 150 MW of power from
qualifying facilities under PURPA, of which the Company's current pro
rata share would be approximately 32.7% or 49.1 MW.
The rated capacity of the qualifying facilities currently selling
power to VEPPI is approximately 74 MW. These facilities were all online
by the spring of 1993, and no other projects are under development. The
Company does 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 1997, the Company, through both its direct contracts and VEPPI,
purchased 121,938.4 MWh of qualifying facilities production to meet 5.9%
of its retail and requirements wholesale sales at an average cost of
10.7 cents per KWh.
Short-Term Opportunity Purchases and Sales. The Company has made
arrangements with several utilities in New England and New York under
which the Company may make purchases or sales of utility system power on
short notice and generally for brief periods of time when it appears
economic to do so. Opportunity purchases are arranged when it is
possible to purchase power from another utility for less than it would
cost the Company to generate the power with its own sources. Purchases
also help the Company save on replacement power costs during an outage
of one of its base load sources. Opportunity sales are arranged when
the Company has surplus energy available at a price that is economic to
other regional utilities at any given time. The sales are arranged
based on forecasted costs of supplying the incremental power necessary
to serve the sale. 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 1997, the Company purchased 52,185.9 MWh, meeting 2.4% of
the Company's retail and requirements wholesale sales, at an average
cost of 2.7 cents per kWh.
NEPOOL. As a participant of NEPOOL, through VELCO, the Company
takes advantage of pool operations with central economic dispatch of
participants' generating plants, pooling of transmission facilities and
economy and emergency exchange of energy and capacity. The NEPOOL
agreement also imposes obligations on the Company to maintain a
generating capacity reserve as set by NEPOOL, but which is lower than
the reserve which would be required if the Company 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
8.8 MW. In 1997, these plants provided 140,754 MWh of low-cost energy,
meeting 6.9% of the Company's retail and requirements wholesale sales at
an average cost of 4.2 cents per kWh, based on total embedded costs. See
"State and Federal Regulation - Licensing."
VELCO. The Company, together with six other Vermont electric
distribution utilities, owns VELCO. Since commencing operation in 1958,
VELCO has transmitted power for its owners in Vermont, including power
from NYPA and other power contracted for by Vermont utilities. VELCO
also purchases bulk power for resale at cost to its owners, and as a
member of NEPOOL, represents all Vermont electric utilities in pool
arrangements and transactions. See Note B of Notes to Consolidated
Financial Statements.
Long-Term Power Sales. In 1986, the Company entered into an
agreement for the sale to United Illuminating of 23 MW of capacity
produced by the Stony Brook I combined-cycle plant for a 12-year period
commencing October 1, 1986. The agreement provides for the recovery by
the Company of all costs associated with the capacity and energy sold.
Fuel. During 1997, the Company's retail and requirements wholesale
sales were provided by the following fuel sources: 46.9% from hydro
(6.9% Company-owned, 0.1% NYPA, 36.8% Hydro-Quebec and 3.1% small power
producers), 36.5% from nuclear, 9.2% from coal, 3.3% from wood, 0.9%
from natural gas, 0.5% from oil, and 0.3% from wind. The remaining 2.4%
was purchased on a short-term basis from other utilities and through
NEPOOL.
Vermont Yankee has approximately $133,000,000 of "requirements
based" purchase contracts for nuclear fuel needs to meet substantially
all of its power production requirements through 2002. Under these
contracts, any disruption of operating activity would allow Vermont
Yankee to cancel or postpone deliveries until actually needed.
Vermont Yankee has a contract with the United States Department of
Energy (DOE) for the permanent disposal of spent nuclear fuel. Under
the terms of this contract, in exchange for the one-time fee discussed
below and a quarterly fee of 1 mil per KWh of electricity generated and
sold, the DOE agrees to provide disposal services when a facility for
spent nuclear fuel and other high-level radioactive waste is available,
which is required by contract to be prior to January 31, 1998. The
actual date for these disposal services is expected to be delayed many
years.
The DOE contract obligates Vermont Yankee to pay a one-time fee of
approximately $39,300,000 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 1996, Vermont Yankee accumulated
approximately $78,000,000 in an irrevocable trust to be used exclusively
for defeasing this obligation at some future date, provided the DOE
complies with the terms of the aforementioned contract.
The Company does not maintain long-term contracts for the supply of
oil for the oil-fired peaking unit generating stations wholly owned by
it (80 MW). The Company did not experience difficulty in obtaining oil
for its own units during 1997, and, while no assurance can be given,
does not anticipate any such difficulty during 1998. None of the
utilities from which the Company expects to purchase oil- or gas-fired
capacity in 1997 has advised the Company of grounds for doubt about
maintenance of secure sources of oil and gas during the year.
Coal for Merrimack #2 is presently being purchased 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.
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
249,662 tons of wood chips and mill residue and 34,629,000 cubic feet of
gas in 1997. The McNeil plant is forecasting consumption of wood chips
for 1998 to be 200,000 tons and gas consumption of 136,000,000 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. The Company assumes for planning and budgeting
purposes that the plant will be supplied with gas during the months of
April through November, and that it will run solely on oil during the
months of December through March. The plant maintains an oil supply
sufficient to meet approximately one-half of its annual needs.
Wind Project. The Company's 20 years of research and development
work in wind generation was recognized in 1993 when the Company was
selected by the DOE and the Electric Power Research Institute (EPRI) to
build a commercial scale wind-powered facility. The Company was awarded
$3,500,000 by the DOE and EPRI to provide partial funding for the wind
project. The overall cost of the project, located in the southern
Vermont town of Searsburg , is estimated to be $11,000,000. The eleven
wind turbines have a rating of 6 MW and were commissioned July 1, 1997.
The Company is a utility leader in wind power research. The
Company's extensive wind resource database shows that wind power is
technically feasible and is becoming economically viable at other sites
within Vermont. Several years of wind turbine operation at Mt. Equinox,
Vermont, has provided the Company with valuable knowledge about the
effects of icing and extreme cold on the performance of wind turbines,
and the necessary adaptations for these conditions.
The Searsburg wind project affords an opportunity to employ
turbines that are of an advanced design and larger scale than the Mt.
Equinox turbines. The economies of scale and advanced technology
inherent in these turbines offer a more competitive and reliable source
of power than earlier designs. First-hand knowledge about these
turbines in Vermont's climatic conditions will enable the Company to
make intelligent and timely decisions about this power resource, which
can be installed in increments that closely match the need for power.
Furthermore, the project's size and northerly location will boost the
commercialization of wind power by deploying a new model of turbines in
sufficient quantities to obtain statistically valid operations and
maintenance data, which will be shared with other utilities. Finally,
information related to the siting, permitting, and possible impacts on
the natural environment will also be documented and shared with the
industry and the public.
The Company estimates that the wind project will cause rates to
rise less than one-half of 1% in the first several years of the project.
Early in the next century, however, the Company projects that
electricity from wind energy will cost less than comparable power from
other sources. Over the life of the project, the average cost of
electricity from the wind farm, which provides electricity at times of
peak demand for the Company, is expected to be competitive with the cost
of alternatives in the market.
In 1997, the plant provided 5,387 MWh, meeting 0.3% of the
Company's retail and requirements wholesale sales.
ENERGY EFFICIENCY
In 1997, the Company continued to focus its energy efficiency
services on lost opportunity programs which encouraged customers to
install energy efficient equipment when they are planning to replace or
buy new equipment. This strategy, along with careful management, has
helped the Company to further reduce its cost-per-kilowatthour saved by
10% below its costs in 1996. The current cost of saving per
kilowatthour is approximately 2 cents which is a 56% reduction in costs
since 1992. In 1997, the Company's energy efficiency programs saved
8,633 MWH, 64% above targeted savings for the year. During the past
five years, the Company's efficiency programs have achieved a cumulative
savings of 71,217 megawatthours.
In 1997, the Company worked with other Vermont utilities and the
Department to develop a set of statewide energy efficiency programs.
This effort should reduce the cost of delivering these programs and
provide a more standardized service to customers throughout the State.
In 1997, the Company spent approximately $1,900,000 on energy
efficiency programs, approximately 1.2% of 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, the Company has offered optional time-of-use rates for residential
and commercial customers. Currently, approximately 2,500 of the
Company's residential customers continue to be billed on the original
1976 time-of-use rate basis. In 1987, the Company received regulatory
approval for a rate design that permitted it to charge prices for
electric service that reflected as accurately as possible the cost
burden imposed by each customer class. The Company's 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 the Company's largest customers
be charged time-of-use rates on a phased-in basis by 1994. At year end
December 31, 1997, approximately 1,350 of the Company's largest
customers, comprising 48% of retail revenues, continue to receive
service on mandatory time-of-use rates.
In May 1994, the Company filed its 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 rate redesign has taken place since the VPSB Order issued on
December 2, 1994.
Dispatchable and Interruptible Service Contracts. In 1997, the
Company 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 allow the Company to control
power supply capacity charges by reducing the Company's capacity
requirements. During 1997, the Company did not request any
interruptions due to the surplus capacity in the region. The
dispatchable portion of the contracts allows customers to purchase
electricity during times designated by the Company when low cost power
is available. 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. The Company
shifts load from its high cost peak periods while 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
The Company's capital expenditures for 1994 through 1996 and
projection for 1997 are set forth in Item 7. MD&A - "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 1995-1997, internally generated funds, after payment
of dividends, provided approximately 62% of total capital requirements
for construction, sinking fund obligations and other requirements.
Internally generated funds provided 129% of such requirements for 1997.
The Company anticipates that for 1998, internally generated funds will
provide approximately 48% of total capital requirements for regulated
operations, the remainder to be derived from bank loans.
In connection with the foregoing, see Item 7. MD&A - "Liquidity and
Capital Resources."
ENVIRONMENTAL MATTERS
The Company has been notified by the Environmental Protection
Agency (EPA) that it is one of several potentially responsible parties
for clean up at the Pine Street marsh site in Burlington, Vermont. For
information regarding the Pine Street Marsh and other environmental
matters see Item 7. MD&A - "Environmental Matters" and Note I-2 of Notes
to Consolidated Financial Statements.
UNREGULATED BUSINESSES
The Company has had a plan of diversification into unregulated
businesses that complements the Company's basic utility operations. The
diversification plan has involved the establishment of several
subsidiaries. For information regarding unregulated businesses, see
Item 7. MD&A- "Future Outlook - Unregulated Businesses."
EXECUTIVE OFFICERS
Executive Officers of the Company as of March 27, 1998:
Name Age
Nancy R. Brock 42 Chief Corporate Strategic Planning
Officer since March, 1998. Prior to joining
the Company, she was Chief Financial Officer
of SAL, Inc., 1997; and Senior Vice President
and Chief Financial Officer for the
Chittenden Corporation from 1988 to 1996.
Christopher L. Dutton 49 President, Chief Executive Officer 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 41 Controller since October 7, 1996.
Manager of General Accounting from 1990 to
1996.
Richard B. Hieber 59 Senior Vice President and Chief
Operating Officer since August 1997. Vice
President, Electric Operations and
Engineering from 1996 to 1997. Prior to
joining the Company, he was President and
Chief Executive Officer of Stone & Webster
Management Consultants, Inc. from 1992 to
1996 and Senior Vice President from 1991 to
1992.
Donna S. Laffan 48 Corporate Secretary since December
1993. Assistant Secretary from 1986 to 1993.
John J. Lampron 53 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 53 General Counsel since August 1997.
Assistant General Counsel from 1990 to 1997.
Prior to joining the Company, he was a
partner with Miller, Eggleston and Rosenberg
Ltd.
Craig T. Myotte 43 Assistant Vice President-Engineering
and Operations since 1994. Assistant Vice
President-Operations and Maintenance from
1991 to 1994.
Edwin M. Norse 52 Vice President, Chief Financial Officer
and Treasurer since August 1997. Vice
President and General Manager, Energy
Resources and Sales from 1995 to 1997. Vice
President, Chief Financial Officer and
Treasurer from 1986 to January 1995.
President-Green Mountain Propane Gas Company
from October 1993 to June 1996.
Walter S. Oakes 51 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 37 Vice President, Human Resources and
Organizational Development since March, 1998.
Prior to joining the Company, she was Senior
Vice President, Human Resources and Senior
Vice President Community Banking, Senior Vice
President Human Resources Administration, and
Vice president of Human Resources for KEYCORP
from October 1992 to March 1998.
Stephen C. Terry 55 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 46 President of Mountain Energy, Inc.
since March 1997. Vice President and Chief
Operating Officer of Mountain Energy, Inc.
from 1989 to March 1997.
Robert C. Young 60 Assistant Vice President-Customer
Operations since 1994. Assistant Vice
President-Operations and Engineering from
1992 to 1994. Director of Engineering from
August 1991 to December 1992. Director of
Special Projects from August 1991 to March
1992. Prior to joining the Company, he was
employed by the Burlington Electric
Department for thirty-two years, including
sixteen years as General Manager.
Officers are elected by the Board of Directors of the Company,
Mountain Energy, Inc., or Green Mountain Resources, Inc., as
appropriate, for one-year terms and serve at the pleasure of such boards
of directors.
ITEM 2. PROPERTY
GENERATING FACILITIES
The Company's Vermont properties are located in five areas and are
interconnected by transmission lines of VELCO and New England Power
Company. The Company wholly owns and operates eight hydroelectric
generating stations with a total nameplate rating of 36.1 MW and an
estimated claimed capability of 35.7 MW. It also owns two gas-turbine
generating stations with an aggregate nameplate rating of 59.9 MW and an
estimated aggregate claimed capability of 73.2 MW. The Company has two
diesel generating stations with an aggregate nameplate rating of 8.0 MW
and an estimated aggregate claimed capability of 8.6 MW. The Company
has a wind generating facility with a name plate rating of 6.1 MW.
The Company also owns 17.9% of the outstanding common stock, and is
entitled to 17.6624% (93.8 MW of a total 531 MW) of the capacity, of
Vermont Yankee, a 1.1% (6.8 MW of a total 620 MW) joint-ownership share
of the Wyman #4 plant located in Maine, an 8.8% (31.0 MW of a total 352
MW) joint-ownership share of the Stony Brook I intermediate units
located in Massachusetts and an 11% (5.9 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, 1997, approximately 1.5 miles of
115 kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4
miles of 44 kV and 265.4 miles of 34.5 kV transmission lines. Its
distribution system includes about 2,399 miles of overhead lines of
2.4 kV to 34.5 kV, and about 445 miles of underground cable of 2.4 kV to
34.5 kV. At such date, the Company owned approximately 153,275 kVa of
substation transformer capacity in transmission substations, 446,050 kVa
of substation transformer capacity in distribution substations and
1,070,604 kVa of transformers for step-down from distribution to
customer use.
The Company owns 33.8% of the Highgate transmission intertie, a
225-MW converter and transmission line utilized to transmit power from
Hydro-Quebec.
The Company also owns 29.5% of the common stock and 30% of the
preferred stock of VELCO, which operates a high-voltage transmission
system interconnecting electric utilities in the State of Vermont.
PROPERTY OWNERSHIP
The principal wholly-owned plants of the Company are located on
lands owned in fee by the Company. Water power and floodage rights are
controlled through ownership of the necessary land in fee or under
easements.
Transmission and distribution facilities which are not located in
or over public highways are, with minor exceptions, located either on
land owned in fee or pursuant to easements which, in nearly all cases,
are perpetual. Transmission and distribution lines located in or over
public highways are so located pursuant to authority conferred on public
utilities by statute, subject to regulation by state or municipal
authorities.
INDENTURE OF FIRST MORTGAGE
The Company's interests in substantially all of its properties and
franchises are subject to the lien of the mortgage securing its First
Mortgage Bonds.
GENERATING FACILITIES OWNED
The following table gives information with respect to generating
facilities presently available in which the Company has an ownership
interest. See also 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, the
Company receives up to 6.6 MW as a result of other owners' losses
on this system.
CORPORATE HEADQUARTERS
For a discussion of the Company's operating lease for its Corporate
Headquarters building, see Note I-3 of Notes to Consolidated Financial
Statements.
ITEM 3. LEGAL PROCEEDINGS
See the discussion Item 7. MD&A - "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 1996:
HIGH LOW
1996 First Quarter $29 1/8 $26 7/8
Second Quarter 27 7/8 22 7/8
Third Quarter 26 3/8 23 1/2
Fourth Quarter 25 1/8 22 3/4
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
The number of common stockholders of record as of March 11, 1998
was 7,883.
Quarterly cash dividends were paid as follows during the past two
years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
------- ------- ------- -------
1996 53 cents 53 cents 53 cents 53 cents
1997 53 cents 53 cents 27.5 cents 27.5 cents
Dividend Policy - On September 17, 1997, the Company's Board of
Directors announced a reduction in the quarterly dividend from $.053 per
share to $0.275 per share on the Company's common stock.
Historically, the Company has based its dividend policy on the
continued validity of three assumptions: The ability to achieve
earnings growth, the receipt of an allowed rate of return that
accurately reflects the Company's cost of capital, and the retention of
its exclusive franchise. The Company's common stock dividend payout has
ranged from 94 to 103 percent of earnings over the past five years. The
Company's revised dividend policy, which incorporates a target payout
ratio of 60 to 70 percent, reflects the greater risks facing the Company
as a result of the changing environment of the electric utility
industry. This policy contemplates a target payout that is in line with
industry trends and is comparable to that of other companies in the
utility industry. The policy assumes fair and appropriate ratemaking.
However, the VPSB's recent rate Order, if unchanged, will require the
Company to reassess the current dividend level. See Item 7. MD&A
"Future Outlook - Competition and Restructuring" and Note C of Notes to
Consolidated Financial Statements for discussion of limitations on
dividends.
ITEM 6. SELECTED FINANCIAL DATA (In thousands except per share amounts)
Results of operations for the years ended December 31
- -----------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
Operating Revenues........................$179,323 $179,009 $161,544 $148,197 $147,253
Operating Expenses........................ 163,808 162,882 146,249 133,680 132,427
--------- --------- --------- --------- ---------
Operating Income........................ 15,515 16,127 15,295 14,517 14,826
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity.......................... 357 175 27 263 273
Other................................... 1,216 3,055 3,607 3,418 2,360
--------- --------- --------- --------- ---------
Total other income.................... 1,573 3,230 3,634 3,681 2,633
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed funds.................. (315) (468) (547) (539) (357)
Other................................... 7,965 7,866 7,973 7,735 7,185
--------- --------- --------- --------- ---------
Total interest charges................ 7,650 7,398 7,426 7,196 6,828
--------- --------- --------- --------- ---------
Net Income................................ 9,438 11,959 11,503 11,002 10,631
Dividends on Preferred Stock.............. 1,433 1,010 771 794 811
--------- --------- --------- --------- ---------
Net Income Applicable to Common Stock..... $8,005 $10,949 $10,732 $10,208 $9,820
========= ========= ========= ========= =========
Common Stock Data
Earnings per share...................... $1.57 $2.22 $2.26 $2.23 $2.20
Cash dividends declared per share....... $1.61 $2.12 $2.12 $2.12 $2.11
Weighted average shares outstanding..... 5,112 4,933 4,747 4,588 4,457
Financial Condition as of December 31
- -------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
Assets
Utility Plant, Net.......................$196,720 $189,853 $181,999 $175,987 $171,411
Other Investments........................ 21,997 20,634 20,248 20,751 22,528
Current Assets........................... 29,125 30,901 30,216 28,798 26,215
Deferred Charges......................... 35,831 43,224 42,951 35,659 33,893
Non-Utility Assets....................... 42,060 39,927 37,868 33,416 28,626
--------- --------- --------- --------- ---------
Total Assets............................$325,733 $324,539 $313,282 $294,611 $282,673
========= ========= ========= ========= =========
Capitalization and Liabilities
Common Stock Equity......................$114,377 $111,554 $106,408 $101,319 $97,149
Redeemable Cumulative Preferred Stock.... 17,735 19,310 8,930 9,135 9,385
Long-Term Debt, Less Current Maturities.. 93,200 94,900 91,134 74,967 79,800
Capital Lease Obligation................. 8,342 9,006 9,778 10,278 11,029
Curent Liabilities....................... 25,286 21,037 32,629 40,441 37,925
Deferred Credits and Other............... 53,723 54,968 52,041 49,434 40,214
Non-Utility Liabilities.................. 13,070 13,764 12,362 9,037 7,171
--------- --------- --------- --------- ---------
Total Capitalization and Liabilities....$325,733 $324,539 $313,282 $294,611 $282,673
========= ========= ========= ========= =========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OFOPERATIONS
This section presents management's assessment of Green Mountain
Power Corporation's (the Company) financial condition and the principal
factors having an impact on the results of its operations. This
discussion should be read in conjunction with the consolidated financial
statements and notes thereto contained in this annual report. This
section contains forward-looking statements as defined under the
securities laws. Actual results could differ materially from those
projected. This section, particularly under "Future Outlook -
Competition and Restructuring" and "Risk Factors," lists some of the
reasons why results could differ materially from those projected.
EARNINGS SUMMARY
Earnings per average share of common stock in 1997 were $1.57 as
compared with $2.22 in 1996 and $2.26 in 1995. The 1997 earnings
represent an earned return on average common equity of 7.1 percent. The
earned return on average common equity in 1996 was 10.0 percent and 10.3
percent in 1995.
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 has invested in energy
generation and energy and wastewater efficiency projects, earned $1.2
million less in 1997 than in 1996, 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. Green Mountain Resources Inc.'s (GMRI) 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 to an affiliate of the Sam Wyly family during the third quarter
of 1997. Subsequently, the Wyly family affiliate invested an additional
$10 million in GMER, increasing its ownership percentage to 74.3
percent.
The 1996 decrease in earnings was primarily due to increased
mandatory purchases of power from independent power producers resulting
from greater production from in-state hydroelectric plants and unusually
warm weather in December 1996 that adversely affected the Company's
electric operating revenues and sales of propane by the Company's
wholly-owned subsidiary, Green Mountain Propane Gas Company.
FUTURE OUTLOOK
Competition and Restructuring -- The electric utility business is
being subjected to rapidly increasing competitive pressures stemming
from a combination of trends, including the presence of surplus
generating capacity, a 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. To date, this competition
has been most prominent in the bulk power market, in which non-utility
generators have significantly increased their market share.
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: (i)
competition with alternative fuel suppliers, primarily for heating and
cooling; (ii) competition with customer-owned generation; and (iii)
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 an increasing number of proposals 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
among states across the country, including Vermont, are considering how
to facilitate competition for electricity sales at the wholesale and
retail levels. On October 24, 1994, the Vermont Public Service Board
(VPSB) and the Vermont Department of Public Service (the Department)
convened a "Roundtable on Competition and the Electric Industry,"
consisting of representatives of affected parties. On July 17, 1995, a
subgroup of the Roundtable agreed on a set of 14 principles intended to
guide the debate in Vermont concerning competition. These principles,
among other things, call for exploration of the potential for retail
competition, honoring of past utility commitments incurred under
regulation, protection for low income customers, and continued
exploration of renewable resources, energy efficiency and environmental
protections.
On September 14, 1995, Governor Dean of Vermont announced his
desire to provide for competition and a restructuring of the electric
utility industry. The Governor's announcement included proposed
legislative adoption of restructuring principles, a VPSB proceeding to
address the issue, the submission by Vermont electric utilities of
detailed plans by May 1, 1996, and implementation of restructuring by
the beginning of 1998. In response to a Department petition, the VPSB
opened a proceeding on utility industry restructuring by order dated
October 17, 1995. On December 29, 1995, the Company released its
proposed restructuring plan, calling for corporate separation into a
regulated company for transmission and distribution functions and an
unregulated company for generation and sales functions.
On October 16, 1996, the VPSB issued a Draft Report and Order which
proposed the commencement of competitive retail sales of electricity in
early 1998, while distribution and transmission functions would remain
subject to regulation. The Company and other parties responded to the
Draft Report and Order in November 1996, and the VPSB issued its Final
Report and Order on December 31, 1996 (Final Report).
The Final Report indicated that Vermont investor-owned utilities
may be required to divide their competitive retail and regulated
distribution and transmission functions into separate corporate
subsidiaries in order to achieve a functional separation of regulated
and unregulated businesses, and envisioned competition for all customer
classes to be completed by the end of 1998. In view of this potential
change in structure as well as the unknown relative level of competition
each corporation may face, the Company cannot predict the future cost or
availability of capital for the new subsidiary corporations, except to
the extent that it has already created a functionally-separate retail
marketing affiliate, GMER. See Management's Discussion and Analysis of
Financial Condition and Results of Operations - "Unregulated Businesses
- - Green Mountain Resources, Inc." Furthermore, most of the assets of
the Company are encumbered by a lien of the Company's First Mortgage
Indenture. The Company cannot predict with certainty at this time the
cost and feasibility of obtaining approval from the existing
bondholders, to the extent that it is determined that such approvals are
necessary, in order to achieve functional separation.
The Final Report proposed an approach that takes into account
multiple factors that the VPSB believes will "create the opportunity for
full recovery of stranded costs provided they are legitimate,
verifiable, otherwise recoverable, prudently incurred and non-
mitigable," but the Final Report also stated the VPSB's belief that "an
opportunity for full recovery must be explicitly tied to successful
mitigation." The Final Report further provided that, where a utility
has successfully mitigated its stranded costs, the opportunity should
exist for substantial or full recovery of stranded costs when the
magnitude of the post-mitigation stranded costs, among other things,
allows for rates that are comparable to regional rates.
The Final Report proposed that allowed stranded cost recovery be
accomplished through the use of a non-bypassable access charge, or
Competitive Transition Charge (CTC), collected by the regulated
distribution company. The Final Report also endorsed the securitization
of stranded costs through the assignment of CTC receipts as a means of
achieving lower-cost financing and supported legislative action to
achieve these savings.
In early 1997, the Company, Central Vermont Public Service
Corporation (CVPS), representatives of the Governor of Vermont and the
Department negotiated a Memorandum of Understanding (MOU) that outlined
agreed-upon positions among the parties relative to the recovery of
stranded costs, distribution company rates, corporate unbundling and
societal benefit programs.
In early April 1997, the Vermont Senate passed Senate Bill No. 62
(S. 62), an electric utility restructuring bill, which requires passage
by the Vermont House of Representatives and signature by the Governor
before becoming law. This bill was opposed by the Company and other
utilities in Vermont in the legislative session that ended in June 1997.
S. 62 establishes several goals, including the conflicting objectives
that stranded costs be shared equally between utilities and customers
and that the continuing financial integrity of the utility be preserved.
Under S. 62, full retail competition in Vermont would have started
in October 1998 and the VPSB was given considerable discretion to weigh
various potentially conflicting objectives, including the two objectives
set forth above, in deciding the extent to which and manner under which
a utility can recover stranded costs. S. 62 also provides: (1) that
utilities must either divest unregulated enterprises or "functionally
separate" them from regulated business activities; (2) an incentive for
the early closing and decommissioning of the Vermont Yankee nuclear
power plant; (3) that any retail electricity provider in Vermont shall
have "ownership" of sufficient tradable renewable energy credits as
defined in S. 62; (4) that the VPSB may order performance-based
regulation for distribution functions if it finds that departure from
cost-of-service regulation is in the public interest; (5) for the
provision of out placement service and severance pay for utility
employees adversely affected by restructuring, with such costs shared
equally by the utility and its customers; and (6) that if a utility has
received some above-market cost recovery and then the utility is
acquired, the VPSB is to determine how much, if at all, the value of the
acquired company was enhanced by the recovery of above-market costs and
thereafter determine how the enhanced value should be shared equitably
between the acquired utility's shareholders and customers.
The Company has strenuously opposed the enactment of S. 62 into law
principally because its stranded cost sharing provisions would
jeopardize the Company's financial viability. The ability of the Company
to apply accounting standards that recognize the economic effect of rate
regulation and record regulatory assets and liabilities would be
significantly challenged by the proposed enactment of S. 62. In the
event that the criteria for applying Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (SFAS 71) are no longer met, the Company would be required to
write-off a material amount of its regulatory assets. More
significantly, the Company would be required to record its best estimate
of the loss resulting from the equal sharing between the Company and its
customers of the portion of stranded costs represented by above-market
purchase power obligations. These obligations result from contracts for
power entered into by the Company to meet its obligation to serve its
retail customers. Such losses could impact the Company's credit rating,
dividend policy and financial viability.
In mid-April 1997, the Vermont House of Representatives indicated
through its Speaker that there was insufficient time in the legislative
session (which ended in June 1997) to act upon a utility restructuring
bill. S. 62 was not considered by the Vermont House of Representatives
in the 1997 legislative session. However, along with other proposed
bills, it is being considered by the House of Representatives during the
1998 session.
On July 28, 1997, the Speaker of the House named an eleven member
non-standing committee to consider reform of the Vermont Electric
Utility Regulatory System. In mid-October 1997, the Chair of the
Committee reported that the Committee did not recommend that the Vermont
Legislature consider legislation during the 1998 session to allow
customer choice at this time. Nevertheless, proposed electric utility-
related legislation, which the House has taken no action on, consists of
the following: (1) H. 663, which would create performance-based
regulation, but not provide for competitive retail sales of electricity;
(2) H. 701, which would mirror most of the terms of the MOU but would
not provide reasonable stranded cost recovery for the Company; and (3)
H. 675, which also would mirror most of the terms of the MOU but would
confer jurisdiction on the VPSB to provide for stranded cost recovery as
a ratemaking function.
There is no assurance that any restructuring legislation will be
enacted by the Vermont General Assembly in its 1998 session that is
scheduled to adjourn mid-April 1998 or, if legislation is enacted, that
it will be consistent with the terms of the Final Report. The Company
has stated its position that if legislation is enacted that threatens
the Company's financial integrity, it will pursue all remedies available
to it under law.
Risk Factors -- The major risk factors for the Company arising from
electric industry restructuring, including risks pertaining to the
recovery of stranded costs, are: (i) regulatory and legal decisions;
(ii) the market price of power; and (iii) the amount of market share
retained by the Company. There can be no assurance that a final
restructuring plan ordered by the VPSB, the courts, or through
legislation will include a CTC or other mechanism that would allow for
full recovery of 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, the Company believes it has compelling legal arguments
to challenge such laws or decisions.
The largest category of the Company's stranded costs are future
costs under long-term power purchase contracts. The Company intends to
pursue compliance with the steps outlined in the Final Report and
aggressively to pursue mitigation efforts in order to maximize its
recovery of these costs. The magnitude of stranded costs for the
Company is largely dependent upon the future market price of power. The
Company has 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 $265 million and
$1.1 billion.
If retail competition is implemented in Vermont, there will be an
impact on the Company's revenues from electricity sales. However, the
Company is unable to predict at this time the extent of this impact.
GMER, the Company's affiliate, is expected to participate in the
residential and small commercial and industrial customer market in
Vermont at such time when restructuring occurs. The Company has agreed
not to compete against GMER in the retail energy business for a period
of seven years. 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 or 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. SFAS 71 requires 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.
As described in Note A.2 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 (1)
increasing competition that restricts the Company's ability to charge
prices to recover specific costs and (2) a significant change in the
manner in which rates are set by regulators from cost-based regulation
to another form of regulation. (See Note I of the Notes to Consolidated
Financial Statements.)
The Company believes that the provisions of the Final Report, if
implemented, would meet the criteria for continuing application of SFAS
71 as to those costs for which recovery is permitted. S. 62, however,
would not meet the criteria for the continuing application of SFAS 71.
Under SFAS 5, Accounting for Contingencies, the enactment of S. 62 or
other restructuring legislation or order containing comparable
provisions on stranded cost recovery would also require the Company to
immediately estimate and record losses, on an undiscounted basis, for
any discretionary above market power purchase contracts and other costs
which are not probable of recovery from customers, to the extent that
those costs are estimable. The Company is unable to predict what form
enacted legislation will take, and it 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 assets secured in arrangements such as a CTC, those assets would
continue to be accounted for under SFAS 71.
SFAS 121, Accounting for the Impairment of Long Lived Assets, which
was implemented by the Company on January 1, 1996, 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 which are no longer probable of
recovery. As of December 31, 1997, based upon the regulatory
environment within which the Company currently operates, no impairment
loss was incurred. Competitive influences or regulatory developments
may impact this status in the future.
The Company 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 the Company's
operations, financial condition or credit ratings. The Company's
failure to recover a significant portion of its purchased power costs,
or to retain and attract customers in a competitive environment, would
likely have a material adverse effect on the Company's business,
including its 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 Note I of
the Notes to Consolidated Financial Statements.
Unregulated Businesses -- The following is a discussion of the
Company's unregulated enterprises.
Mountain Energy, Inc., which has invested in energy generation and
energy and waste water efficiency projects, earned $142,000 in 1997,
compared to net income of $1.32 million in 1996. The 1997 decrease in
earnings was due primarily to start-up operating losses incurred by
Micronair, LLC. and a decline in rates paid for power generated by one
of its wind facilities in California. The 1997 results contributed 3
cents of earnings per share to the Company's consolidated results as
compared to 27 cents in 1996.
Since its formation in 1989, Mountain Energy has invested more than
$20 million in ten operating energy projects, including two California
wind projects, hydroelectric projects in California and New Hampshire, a
gas cogeneration facility in Illinois and energy efficiency
installations in Maine, New York, New Jersey, Massachusetts and Hawaii.
In 1997, Mountain Energy 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 biosolids disposal
issues facing the United States. The Micronairr system enhances both
the processing and energy efficiency at wastewater facilities, virtually
eliminating biosolids as a byproduct. Mountain Energy increased its
ownership interest in Micronair to 71 percent at the end of 1997.
Green Mountain Propane Gas Company (GMPG), which sells propane gas
at retail in Vermont and New Hampshire, experienced a $136,000 loss in
1997 as compared to a $335,000 loss in 1996. The loss in 1997 was due
primarily to a decrease in propane sales caused by warmer than normal
weather in early 1997. In 1997 and 1996, the losses incurred by GMPG
reduced the Company's consolidated earnings by 3 cents and 7 cents,
respectively, per share of common stock. 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. See
Note I of the Notes to Consolidated Financial Statements.
The loss in 1996 was due primarily to strong competition, low
margins due to significant wholesale price fluctuations, increased
producer pipeline restrictions beginning in November 1996 and warmer
than normal weather in December 1996.
The Company's unregulated rental water heater business earned
$381,000 in 1997, a slight increase from 1996's net income of $379,000.
The 1997 and 1996 results contributed 7 and 8 cents of earnings,
respectively, per share to the Company's consolidated results.
Green Mountain Resources, Inc., which was formed in April 1996 to
explore opportunities in competitive retail energy markets, experienced
a loss of $2.0 million in 1997 that was $1.4 million greater than its
loss of $579,000 in 1996, due primarily to the development costs of its
investment in GMER.
On August 6, 1997, the Company and the Sam Wyly family announced
that their affiliates will jointly own GMER, a Delaware limited
liability company of which GMRI was the sole owner. GMER is competing
in the emerging consumer retail energy market starting in California
where customers are able to choose their electricity supplier as of
March 31, 1998. GMER has created retail brands of electricity and
natural gas that will be sold to consumers who care about the
environment in competitive markets across the nation. An affiliate of
the Sam Wyly family, Green Funding I, L.L.C. (the Investor), entered
into an Operating Agreement with GMRI governing the ownership of GMER.
Pursuant to the terms of the Operating Agreement, the Investor initially
agreed to invest up to $30 million in GMER in exchange for an equity
interest of 67 percent while GMRI contributed certain assets and
business development concepts in exchange for an equity interest of 33
percent in GMER. Subsequently, the Investor agreed to invest an
additional $10 million in GMER, increasing its ownership percentage to
74.3 percent. These ownership interests may be reduced further if GMER
warrants and options issued to GMER management and consultants are
exercised. GMRI's ownership percentage of GMER will be further diluted
if the Investor and/or third parties contribute additional capital to
GMER and GMRI does not make pro rata additional capital contributions at
such time. GMRI received a payment of $4 million from GMER at the
closing as reimbursement for certain development expenses incurred.
Pursuant to the terms of the Operating Agreement, funds provided by the
Investor will be used to pay future GMER development expenses and
operating costs. GMRI is not obligated to fund future development
costs, and the Operating Agreement provides that GMRI will not be
allocated operating losses from GMER, thus limiting the Company's
shareholders' future financial risk while preserving their opportunity
to participate in the success of GMER. In addition, the Company and the
Investor have agreed that neither the Company nor the Investor will
compete against GMER in the retail energy business for a period of seven
years.
Douglas G. Hyde, a director, President and Chief Executive Officer
of the Company, resigned those positions with the Company effective
August 6, 1997 in order to become the President and Chief Executive
Officer of GMER. Thomas C. Boucher, Vice President, Energy Resources
and Planning; Kevin W. Hartley, Vice President, Marketing; Karen K.
O'Neill, Vice President, Organizational Development; and Peter H.
Zamore, General Counsel of the Company, resigned those offices in order
to join Mr. Hyde as members of the GMER management team.
In 1996, GMRI, together with subsidiaries of Hydro-Quebec,
Consolidated Natural Gas Corporation and Noverco, Inc., participated in
the retail sales of energy in pilot programs in New Hampshire and
Massachusetts through Green Mountain Energy Partners L.L.C. (GMEP). In
1997, Consolidated Natural Gas and Noverco withdrew from the pilot
program. GMRI has concluded its participation in the Massachusetts
pilot, but will continue participating through May 31, 1998 in the New
Hampshire pilot program which was designed to test the viability of
retail electric competition by providing customer choice in the purchase
of electricity. In January 1998, Hydro-Quebec withdrew from the pilot
program.
RESULTS OF OPERATIONS
Operating Revenues and MWh Sales--Operating revenues and megawatthour
(MWh) sales for the years 1997, 1996 and 1995 consisted of:
1997 1996 1995
---- ---- ----
(Dollars in Thousands)
Operating Revenues:
Retail . . . . . . . . . . . . . $ 158,790 $ 154,916 $ 140,676
Sales for Resale . . . . . . . . 17,847 20,667 17,541
Other . . . . . . . . . . . . . 2,686 3,426 3,327
--------- --------- ---------
Total Operating Revenues . . . . . $ 179,323 $ 179,009 $ 161,544
========= --------- ---------
Megawatthour Sales:
Retail . . . . . . . . . . . . . 1,806,580 1,775,711 1,723,117
Sales for Resale . . . . . . . . 588,525 701,835 620,655
--------- --------- ---------
Total Megawatthour sales . . . 2,395,105 2,477,546 2,343,772
========= ========= =========
Average Number of Customers:
Residential . . . . . . . . . . 70,671 70,198 69,659
Commercial & Industrial . . . . 12,012 11,853 11,736
Other . . . . . . . . . . . . . 75 75 76
------ ------ ------
Total Customers . . . . . . . . . . 82,758 82,126 81,471
====== ====== ======
Differences in operating revenues were due to changes in the following:
1996 1995
to to
1997 1996
---- ----
(In Thousands)
Operating Revenues:
Retail Rates . . . . . . . . . . . . . . . $ 1,161 $ 9,654
Retail Sales Volume . . . . . . . . . . . 2,713 4,586
Resales and Other Revenues . . . . . . . . (3,560) 3,225
------- -------
Increase in Operating Revenues . . . . . . . $ 314 $17,465
======= =======
In 1997, total electricity sales decreased 3.3 percent due
principally to a decrease in wholesale sales caused by a reduction in
low-margin, off-system sales. Sales of electricity to residential
customers was negatively impacted by winter temperatures in the first
quarter of 1997 that were substantially warmer than normal.
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 the Company's 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.
In 1996, total electricity sales increased 5.7 percent due
principally to an increase in electricity consumption by the Company's
commercial and industrial customers and regional market conditions that
allowed the Company to buy electricity and to resell it to other
utilities at prices slightly higher than the purchase price. Total
operating revenues increased 10.8 percent in 1996 primarily due to
retail rate increases of 9.25 percent and 5.25 percent that went into
effect in June 1995 and June 1996, respectively, and the increase in
electricity sales mentioned above. Total retail revenues increased 10.1
percent in 1996 primarily due to the retail rate increases mentioned
above. Wholesale revenues increased 17.8 percent in 1996 primarily due
to the regional market conditions mentioned above.
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 14.0, 13.2 and
12.9 percent of the Company's operating revenues in 1997, 1996 and 1995,
respectively. No other retail customer accounted for more than one
percent of the Company's revenue.
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 the Company's 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 the Company's tariff rate.
The EDA I price, although lower than the Company's tariff rate, exceeded
the Company's 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 the Company's marginal
costs. A separate pricing provision applies to load above 1997 levels.
The Company expects the VPSB to approve EDA II as presented in early
1998. The Company believ