Back to GetFilings.com
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 believes that the EDA I and EDA II benefit the
Company because the agreements encourage the incremental purchase of
electricity by IBM at a price above the Company's marginal cost of
providing such incremental service.
Power Supply Expenses -- Power supply expenses constituted 61.3
percent, 61.5 percent and 60.1 percent of total operating expenses for
the years 1997, 1996 and 1995, respectively. These expenses increased by
$120,000 (0.1 percent) in 1997 and by $12.3 million (14.0 percent) in
1996.
Total power supply expenses were slightly higher in 1997, although
the cost of several individual sources were significantly different from
their costs in 1996. Power supply expenses from Vermont Yankee
increased 7.3 percent in 1997 primarily due to the deferral in 1996 and
the amortization in 1997 of costs associated with a scheduled refueling
outage. Company-owned generation expenses increased 60.0 percent in
1997 primarily due to the increased usage of Company-owned plants
necessitated by the outage of certain nuclear power plants in the
region. These increases were nearly offset by a 6.2 percent decrease in
power supply expenses from other resources primarily due to the
recognition of $8 million received from Hydro-Quebec under a Memorandum
of Understanding entered into in 1996 (as described below) consistent
with a VPSB accounting order dated December 31, 1996. (This accounting
treatment was subsequently changed. See below.)
During 1994, the Company negotiated an arrangement with Hydro-
Quebec that reduces the cost impacts associated with the purchase of
Schedules B and C3 under the 1987 Contract over the November 1995
through October 1999 period (the July 1994 Agreement). Under the July
1994 Agreement, the Company, in essence, will take delivery of the
amounts of energy as specified in the 1987 Contract, but the associated
fixed costs will be significantly reduced from those specified in the
1987 Contract.
As part of the July 1994 Agreement, the Company is obligated to
purchase $4 million (in 1994 dollars) worth of research and development
work from Hydro-Quebec over the four-year period, and made a $6.5
million (in 1994 dollars) cash payment to Hydro-Quebec in 1995. Hydro-
Quebec retains the right to curtail annual energy deliveries by 10
percent up to five times, over the 2000 to 2015 period, if documented
drought conditions exist in Quebec.
Under an arrangement negotiated in January 1996, the Company
received cash payments from Hydro-Quebec of $3.0 million in 1996 and
$1.1 million in 1997. Consistent with allowed ratemaking treatment, the
$3.0 million payment reduced purchase power expense by $1.75 million in
1996; the balance of the payment reduced power costs in 1997. The $1.1
million payment reduces purchase power expense ratably over the period
beginning June 1997 and ending May 1998. An Order issued by the VPSB in
March 1998 requires the Company instead to amortize the $1.1 million
over a four-year period. (See Note I of the Notes to Consolidated
Financial Statements.)
The 1996 arrangement requires the Company to shift up to 40
megawatts of its Schedule C3 deliveries to an alternate transmission
path, and use the associated portion of the NEPOOL/Hydro-Quebec
interconnection facilities to purchase power for the period from
September 1996 through June 2001 at prices that vary based upon
conditions in effect when the purchases are made. The 1996 arrangement
also provides for minimum payments by the Company to Hydro-Quebec for
periods in which power is not purchased under the arrangement. Although
the level of benefits to the Company will depend on various factors, the
Company estimates that the 1996 arrangement will provide a minimum
benefit of $1.8 million on a net present value basis.
Under a separate agreement executed on December 5, 1997, Hydro-
Quebec provided a cash payment of $8.0 million to the Company in 1997.
In return for this payment, the Company is providing Hydro-Quebec with
the choice of selecting one of two alternatives by April 1, 1998,
described below:
Alternative A: For the period commencing November 1, 1997 and effective
through the remaining term of the 1987 Contract, which expires in 2015,
Hydro-Quebec can exercise an option to purchase up to 105,000 MWh on an
annual basis, at energy prices established in accordance with the 1987
Contract, for an amount of energy equivalent to the Company's firm
capacity entitlements in the 1987 Contract. The cumulative amount of
energy purchased over the remaining term of the 1987 Contract shall not
exceed 1,900,000 MWh. Hydro-Quebec may not exercise its annual rights
to purchase power in the amounts specified under an arrangement made in
November 1996 during those years in which Hydro-Quebec exercises its
rights to curtail energy deliveries in accordance with the July 1994
Agreement.
Alternative B: For the period commencing November 1, 1997 and effective
through the remaining term of the 1987 Contract, Hydro-Quebec can
exercise an option to purchase up to 52,500 MWh on an annual basis, at
energy prices established in accordance with the 1987 Contract, for an
amount of energy equivalent to the Company's firm capacity entitlements
in the 1987 Contract. The cumulative amount of energy purchased over
the remaining term of the 1987 Contract shall not exceed 950,000 MWh.
Unlike Alternative A, Hydro-Quebec's option to curtail energy deliveries
pursuant to the July 1994 Agreement can be exercised in addition to the
purchase option under Alternative B. Finally, for the period commencing
January 1, 1998 and effective though the remaining term of the 1987
Contract under Alternative B, Hydro-Quebec can exercise an option on an
annual basis to purchase up to 600,000 MWh at the 1987 Contract energy
price. Hydro-Quebec can purchase no more than 200,000 MWh in any given
year. Under modifications agreed to by Hydro-Quebec and the Company,
Hydro-Quebec has until April 1, 1998 to elect either Alternative A or B.
(See Note K of the Notes to Consolidated Financial Statements).
Notwithstanding the December 31, 1996 accounting order, the VPSB
ordered a change in accounting treatment in an Order released on March
2, 1998. The Company intends to appeal or request reconsideration of
this decision. (See Note I of the Notes to Consolidated Financial
Statements.)
Power supply expenses increased in 1996 primarily due to higher
costs for power purchased from Hydro-Quebec, increases in mandatory
purchases from independent power producers and purchases of additional
power to service increased electricity sales.
Vermont Yankee's operating expenses for 1996 exceeded the level of
such expenses incurred during 1995 by approximately $1.3 million, of
which approximately $230,000 was allocated to the Company. In 1996,
Vermont Yankee elected to accelerate certain safety and management
related projects intended to improve efficiency of the plant and assure
compliance with Nuclear Regulatory Commission regulations and the
facility's operating license.
Other Operating Expenses -- Other operating expenses decreased 4.7
percent in 1997 primarily due to an increase in work performed on behalf
of GMRI, effectively reducing payroll and overhead expenses for the
Company. Additionally, the organizational changes attributable to the
creation of GMER resulted in fewer Company employees, causing a
reduction in payroll expense.
Other operating expenses decreased 2.8 percent in 1996 primarily
due to a decrease in salaries resulting from a reduction in the
workforce and to a decrease in medical insurance claims experienced by
the Company.
Transmission Expenses - Transmission expenses increased 2.7 percent
in 1997 primarily due to higher tariffs under a new operating agreement
with New England Power Company.
Transmission expenses increased 9.7 percent in 1996 primarily due
to higher tariff rates under a transmission and interconnection
agreement between CVPS and the Company discussed below. This increase
was offset to a large extent by revenues generated by the same
transmission and interconnection agreement.
In August 1996, the Company received a bill totaling approximately
$1.9 million from CVPS for service at certain transmission
interconnections that are the subject of a 1993 transmission and
interconnection agreement between the Company and CVPS. The bill
covered the period October 1993 through June 1996. In September 1996,
the Company charged approximately $700,000 of the CVPS invoice to
transmission rent expense and deferred the remaining charges. The
Company paid the CVPS billing but sought relief under the agreement's
arbitration clause on the ground, among others, that substantial
portions of the bill, inclusive of interest, were not properly
chargeable under the agreement.
The Company submitted a bill totaling approximately $500,000 to
CVPS for its services under the same transmission and interconnection
agreement, and credited this amount to transmission services in
September 1996. CVPS disputed a portion of the amount billed by the
Company, but paid the bill.
On December 31, 1996, the Company received an accounting order from
the VPSB permitting amounts deferred under the transmission and
interconnection agreement to be expensed over the remaining eleven years
of the agreement subject to review in future rate cases.
In February 1998, following arbitration, the Company received
$428,000 from CVPS, in resolution of each of the parties' claims under
this agreement. Management sought to recover in rates (by inclusion in
ratebase) the 13-month average balance of the charges from CVPS net of
amounts recovered in prior rate orders of the costs of transmission
under this agreement, revenues that the Company received under the
agreement for providing service to CVPS, and the approximate amount of
the arbitration award. The amount sought in the rate case was
approximately $747,000. Management received ratemaking treatment for
these costs in an Order released by the VPSB on March 2, 1998.
Maintenance Expenses - Maintenance expenses increased 7.2 percent
in 1997 and 6.0 percent in 1996 primarily due to scheduled increases in
plant maintenance.
Depreciation and Amortization - Depreciation and amortization
expenses were virtually unchanged in 1997.
Depreciation and amortization expenses increased 15.3 percent in
1996 primarily due to the amortization of expenditures related to energy
conservation programs and the Pine Street Barge Canal site environmental
matter (See Note I of the Notes to Consolidated Financial Statements)
and to the depreciation of expenditures related to additional investment
in the Company's distribution facilities.
Income Taxes -- The effective federal income tax rates for the
years 1997, 1996 and 1995 were 32.8 percent, 27.2 percent and 25.3
percent, respectively.
The increase in 1997 income taxes is primarily due to an increase
in taxable income, an increase in the combined federal and state income
tax rate and an increase in the reserve for unaudited income tax years.
Other Income - Other income decreased 51.3 percent in 1997
primarily due to diminished results by two of the Company's wholly-owned
subsidiaries. Mountain Energy, Inc., the Company's subsidiary that
invests in energy generation and energy and waste water efficiency
projects, earned $1.2 million less in 1997 primarily due to start-up
operating losses incurred by Micronair LLC, a company in which Mountain
Energy bought a 71 percent interest in 1997, and a decline in rates paid
for power generated by one of the California wind facilities in which it
has invested. GMRI's loss in 1997 was $1.4 million greater than the
loss in 1996 due primarily to the development costs of its investment in
GMER, the retail energy company in which the Company sold a controlling
interest to an affiliate of the Sam Wyly family during the third quarter
of 1997.
Other income decreased 11.1 percent in 1996 primarily due to a
$579,000 loss experienced by GMRI. The impact of the GMRI loss on
consolidated earnings was diminished to a large extent by offsetting
payments received by the Company from GMEP for work performed on its
behalf.
Dividends on Preferred Stock - Dividends on preferred stock
increased 41.8 percent in 1997 and 31.0 percent in 1996 primarily due to
the issuance of 120,000 shares of the Company's 7.32 percent, Class E,
Series 1 preferred stock in October 1996.
Interest Charges - Interest charges increased 3.4 percent in 1997
primarily due to an increase in long-term interest related to the sale
of $10 million and $4 million of the Company's first mortgage bonds in
November and December 1996, respectively. This increase was partially
offset by a decrease in interest charges related to a lower amount of
short-term debt outstanding during the year.
Interest charges were virtually unchanged in 1996. An increase in
interest charges related to a higher amount of long-term debt
outstanding during the year and a decrease in the allowance for funds
used during construction were slightly more than offset by a reduction
in interest charges related to a lower amount of short-term debt
outstanding during the year.
TRANSMISSION ISSUES
Federal Open Access Tariff Orders -- On April 24, 1996, the Federal
Energy Regulatory Commission (FERC) issued Orders 888 and 889 which,
among other things, required the filing of open access transmission
tariffs by electric utilities, and the functional separation by
utilities of their transmission operations from power marketing
operations. Order 888 also supports the full recovery of legitimate and
verifiable wholesale power costs previously incurred under federal or
state regulation.
On July 9, 1996, the Company filed with the FERC the non-
discriminatory open access tariffs required by Order 888 and subsequent
modifications to the tariff. The tariff defined the Company's
transmission system to include subtransmission facilities owned by the
Company including Phase I and Phase II facilities and the Company's
entitlement to facilities owned by VELCO. The Company's tariffs
included charges related to the use of the VELCO transmission system by
customers. Other Vermont utilities required to make filings with the
FERC under Order 888 followed the same course of action. On July 17,
1997, the FERC approved the Company's Open Access Transmission Tariff,
and on August 30, 1997 the Company filed its compliance refund report.
In accordance with Order 889, the Company has also functionally
separated its transmission operations and filed with the FERC a code of
conduct for its transmission operations. The Company is currently
revising the Code of Conduct in response to a FERC Order respecting it
issued on November 3, 1997. The Company does not anticipate any
material adverse effects or loss of wholesale customers due to the FERC
orders mentioned above.
Proposed NEPOOL Transmission Tariff -- Under an allocation
agreement among VELCO, Northeast Utilities and New England Power
Corporation (the Three-Party Agreement), VELCO currently has 14 percent
of the capacity of transmission facilities between New England, New York
and Canada. VELCO's capacity for such transmission facilities is
allocated among Vermont electric utilities, including the Company. The
Company's ability to use these delivery paths has been adversely
impacted by a proposed NEPOOL open access tariff (NEPOOL Fourth
Supplement to Amendment 33) on file with the FERC. Under the tariff as
filed, transmission capability or transfer capacity between New York and
New England will no longer be allocated in a manner consistent with the
Three-Party Agreement. Instead, rights to the transfer capacity will be
made more generally available to the market subject to certain
contingencies related to NEPOOL generation availability and accounting
for the delivery of various grandfathered contracts. Efforts by the
Company and other VELCO members to negotiate with NEPOOL participants
for the preservation of rights to deliver long-term firm contracts
necessary to serve native load on these delivery routes were
unsuccessful. Consequently, on November 18, 1997 VELCO filed with the
FERC on behalf of the Vermont utilities (including the Company) a motion
to intervene and seeking summary judgment with respect to the NEPOOL
filing of the Fourth Supplement filing or the VELCO filing. The Company
and other Vermont utilities have argued inter alia that the Fourth
Supplement was a proposal to terminate the Vermont utilities existing
and future rights under the Three Party Agreement allocating the New
York and New England transmission ties and, specifically, the PV20 tie
with the New York Power Authority (NYPA).
ENVIRONMENTAL MATTERS
Public concern for the environment has resulted in increased
government regulation of the licensing and operation of electric
generation, transmission and distribution facilities. The electric
industry typically uses or generates a range of potentially hazardous
products in its operations. The Company must meet various land, water,
air and aesthetic requirements as administered by local, state and
federal regulatory agencies. The Company maintains an environmental
compliance and monitoring program that includes employee training,
regular inspection of Company facilities, research and development
projects, waste handling and spill prevention procedures and other
activities. Subject to developments concerning the Pine Street Barge
Canal site described below, the Company believes that it is in
substantial compliance with such requirements, and no material
complaints concerning compliance by the Company with present
environmental protection regulations are outstanding.
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. The
Company has been notified by the Environmental Protection Agency (EPA)
that it is one of several potentially responsible parties (PRPs) for
cleanup of the Pine Street Barge Canal site in Burlington, Vermont,
where coal tar and other industrial materials were deposited. From the
late 19th century until 1967, gas was manufactured at the Pine Street
Barge Canal site by a number of enterprises, including the Company. In
1990, the Company was one of the 14 parties that agreed to pay a total
of $945,000 of the EPA's past response costs under a Consent Decree.
The Company remains a PRP for other past, ongoing and future response
costs. In November 1992, the EPA proposed a cleanup plan estimated by
the EPA to cost $47 million. In June 1993, the EPA withdrew this
cleanup plan in response to public concern about the plan and its cost.
The cost of any future cleanup plan, the magnitude of unresolved EPA
cost recovery claims, and the Company's share of such costs are
uncertain at this time.
Since 1994, the EPA has established a coordinating council, with
representatives of the PRPs, environmental and community groups, the
City of Burlington and the State of Vermont presided over by a neutral
facilitator. The council has determined, by consensus, what additional
studies were appropriate for the site, and is addressing the question of
additional response activities. The EPA, the State of Vermont and other
parties have entered into two consent orders for completion of
appropriate studies. Work is continuing under the second of those
orders. Most recently, on September 23, 1997, the council reached
tentative agreement on a key component of the proposed remedy for the
Pine Street site, namely, placement of an underwater sand/silt cap on
areas of the canal and wetland sediments, combined with long-term
monitoring to ensure effectiveness of the cap and to ensure that
groundwater does not reach Lake Champlain, adjacent to the site. The
EPA has estimated the costs of this remedy at between $6 to $10 million,
subject to change. In addition, the council is exploring supplemental
projects in and around the site and Burlington as part of a larger plan
to improve environmental conditions in the vicinity.
On December 1, 1994, the Company and two other PRPs, New England
Electric System (NEES) and Vermont Gas Systems (VGS), entered into a
confidential settlement agreement with the State of Vermont, the City of
Burlington and nearly all other landowner PRPs under which, subject to
certain qualifications, the liability of those landowner PRPs for future
Superfund response costs would be limited and specified. On December 1,
1994, the Company entered into a confidential agreement with VGS
compromising contribution and cost recovery claims of each party and
contractual indemnity claims of the Company arising from the 1964 sale
of the manufactured gas plant to VGS. In March 1996, the Company and
NEES entered into a confidential agreement compromising past and future
contribution and cost recovery claims of both parties relating to
response costs. In December 1997, the Company and Southern Union Co.
entered into a confidential settlement agreement compromising past and
future contribution and cost recovery claims of both parties relating to
response costs. The Company has received payment of the full amount
provided for in the settlement. In January 1998, the Company and UGI
Utilities, Inc. entered into a confidential settlement agreement
compromising past and future contribution and cost recovery claims of
both parties relating to response costs. The Company has received
payment of the initial amount provided for in the settlement. The EPA
has advised the Company that it has incurred substantial unrecovered
response sums at the site which, together with interest the EPA alleges
may be payable, amount to approximately $11.0 million. The Company has
not yet received a formal demand for these sums. The Company will
vigorously dispute the EPA's recovery of such costs, which include
substantial sums for studies and other activities that were not
reasonably necessary and were not undertaken consistent with legal and
regulatory requirements. Further, the Company's agreements with certain
PRP's will reduce the extent to which it may bear these past response
costs. Consequently, the Company is not able at this time to predict
with certainty whether, or the extent to which, it will be required to
pay such past response costs.
In December 1991, the Company brought suit against eight previous
insurers seeking recovery of unrecovered past costs, cost of defense and
indemnity against future liabilities associated with environmental
problems at the site. Discovery in the case, which was previously
subject to a stay, is complete. The Company has reached confidential
settlements with the defendants in this litigation; several such
settlements are in the final stages of documentation.
The Company has deferred amounts received from third parties, under
confidential settlements, pending resolution of the Company's ultimate
liability with respect to the site and rate recognition of that
liability.
Although the cost of the coordinating council's tentative
remediation plan, described above, is not expected to approach the EPA's
earlier estimate of remediation costs for its original clean-up plan,
the current EPA estimate is subject to change. Since the Company
believes it may prevail with respect to some of the EPA's unrecovered
response costs, the Company is unable to predict at this time the
magnitude of any liability resulting from potential claims for the costs
to investigate and remediate the site, or the likely disposition or
magnitude of claims the Company may have against others, including its
insurers, except to the extent described above.
Through rate cases filed in 1991, 1993, 1994, and 1995, the Company
has sought and received recovery for ongoing expenses associated with
the Pine Street Barge Canal site. Specifically, the Company proposed
rate recognition of its unrecovered expenditures incurred between
January 1, 1991 and June 30, 1995 (in the total of approximately $8.7
million) for technical consultants and legal assistance in connection
with the EPA's enforcement action at the site and insurance litigation.
While reserving the right to argue in the future about the
appropriateness of rate recovery for the Pine Street Barge Canal site
related costs, the Company and the Department reached agreements in
these cases that the full amount of the Pine Street Barge Canal site
costs reflected in those rate cases should be recovered in rates. The
Company's rates approved by the VPSB in those proceedings reflected the
Pine Street Barge Canal site related expenditures referred to above.
The Company proposed in the rate filing made on June 16, 1997 recovery
of an additional $3.0 million in such expenditures.
In an Order released March 2, 1998, the VPSB suspended the
amortization of expenditures associated with the Pine Street Barge Canal
site pending further proceedings. Although it did not eliminate the
rate base deferral of these expenditures, or make any specific order in
this regard, the VPSB indicated that it was inclined to agree with other
parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance
carriers and other PRP's, should be "shared" between customers and
shareholders of the Company.
As of December 31, 1997, total expenditures for the Pine Street
Barge Canal site were $13.4 million, inclusive of the $11.7 million
referred to above.
An authoritative accounting standard, Statement of Position (SOP)
96-1, has been issued by the accounting profession addressing
environmental remediation obligations. This SOP is effective for years
beginning in 1997, and addresses, among other things, regulatory
benchmarks that are likely triggers of the accrual of estimated losses,
the costs included in the measurement, including incremental costs of
remediation efforts such as post-remediation monitoring and long-term
operation and maintenance costs and costs of compensation and related
benefits of employees devoting time to the remediation. This SOP,
adopted by the Company in January 1997, as required, did not have a
material adverse effect on the Company's financial position or results
of operations.
Clean Air Act -- Because the Company purchases most of its power
supply from other utilities, it does not anticipate that it will incur
any material direct cost increases as a result of the Federal Clean Air
Act or proposals to make more stringent regulations under that Act.
Furthermore, only one of its power supply purchase contracts, which
expires in early 1998, relates to a generating plant that is likely to
be affected by the acid rain provisions of this legislation. Overall,
approximately 10 percent of the Company's committed electricity supply
(a contract to purchase coal-fired generation that expires in early
1998) is expected to be affected by federal and state environmental
compliance requirements.
LIQUIDITY AND CAPITAL RESOURCES
Construction -- The Company's capital requirements result from the
need to construct facilities or to invest in programs to meet
anticipated customer demand for electric service. If restructuring does
occur, the Company will reassess its capital expenditures for generation
and other projects and the terms of financing thereof.
Capital expenditures over the past three years and projected for
1998 are as follows:
Total Net
Actual Generation Transmission Distribution Conservation Other Expenditures
- ------ ---------- ------------ ------------ ------------ ----- ------------
(Dollars in thousands and net of AFUDC and Customer Advances For Construction)
1995 $2,696 $1,067 $8,935 $4,152 $2,969 $19,819
1996 6,287* 528 8,422 3,090 3,511 21,838
1997 3,462* 986 9,680 2,094 3,291 19,513
Forecasted
1998 $1,283 $501 $8,681 $2,500 $9,221 $22,186
*Includes $4.978 and $2.868 million for wind project in 1996 and 1997,
respectively.
Rates -- On June 16, 1997, the Company filed a request with the
VPSB to increase retail rates by 16.7 percent ($26 million in additional
annual revenues) and the target return on common equity from 11.25
percent to 13 percent. Initial hearings before the VPSB began November
3, 1997. The VPSB allowed the intervention of various other parties.
In August 1997, several groups, including the Vermont Public
Interest Research Group (VPIRG), demanded that the VPSB appoint an
independent counsel to advocate against recovery of Hydro-Quebec power
costs by the Company. The VPSB issued an order appointing an
"independent investigator," described as a person or persons who will
perform a rigorous and impartial analysis of the Company's actions with
respect to its power supply options, including the Hydro-Quebec
contract. On November 7, 1997, the VPSB selected a firm, MSB Energy
Associates, Inc. (MSB) to undertake the tasks.
In testimony filed with the VPSB on October 17, 1997, the
Department asked the VPSB to find the Company's negotiation, execution
and decision to "lock in" the contract with Hydro-Quebec to be imprudent
and uneconomic. The Department had supported the contract in the period
1989-1991 after completing its own analysis, based on substantially the
same information that was available to the Company. The VPSB in 1990,
1991, 1992 and 1994 issued orders that determined the contract to be
needed to supply electricity to Vermont customers, economically
beneficial to the State and an appropriate part of the Company's
legally-required least-cost integrated resource plan.
On October 31, 1997, the Company filed with the VPSB Objections and
a Motion to Strike relating to the Hydro Quebec contract testimony and
requested that the VPSB schedule oral argument on the motion prior to
November 17, 1997. The grounds for the motion were that the VPSB had
previously decided the issues sought to be relitigated. The VPSB heard
argument on the motion on November 14, 1997 and ruled against the
Company, but granted the Company leave to renew the motion. The Company
did so in its post-hearing briefs.
In its testimony, submitted in late 1997, MSB was critical of the
Company's power supply decision-making in 1991, and recommended a steep
disallowance of the Hydro-Quebec power costs, in excess of $10 million
per year. During the rebuttal phase of the rate case, the Company
showed that MSB was not independent and did not present "rigorous
analysis" as the VPSB had ordered. MSB's presentation adopted the
testimony of the Department's principal witnesses as well as theories
espoused by a professional expert retained by IBM and MSB failed to
present its own analysis showing that, based on any information
possessed or available to the Company during the critical summer and
fall of 1991, the long-term Hydro-Quebec contract was uneconomic.
The Company filed a motion to strike the MSB testimony and to
impose sanctions upon MSB for submitting testimony without any good
faith factual or legal basis. The VPSB struck several portions of MSB's
testimony forming the core of their arguments on imprudence, based on
legal or contract interpretation, on the ground that MSB had no
qualifications to present this testimony.
Briefs in the case on non-Hydro-Quebec issues were filed January
30, 1998; the Hydro-Quebec briefs were filed on February 2; all reply
briefs were filed on February 6. In its final submissions, the Company
reduced the requested increase to 14.4 percent ($22 million in
additional annual revenues) due to changed estimates of costs to be
incurred in the rate year.
On March 2, 1998, the VPSB released a decision in the rate case.
The Order granted a $5.6 million increase in annual revenue in response
to the Company's request for a $22 million increase in annual revenue.
The Company is exploring all legal and regulatory remedies open to it to
challenge the VPSB's decision. The VPSB's ruling, if not changed, would
have a significant adverse impact on the Company's reported financial
condition and 1998 results of operations and, depending on future
proceedings to be conducted by the VPSB, could impact the Company's
credit rating, dividend policy and financial viability. See Note I of
the Notes to Consolidated Financial Statements for a complete
discussion.
Dividend Policy -- On September 17, 1997, the Company's Board of
Directors announced a reduction in the quarterly dividend from $0.53 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.
Financing and Capitalization -- For the period 1995 through 1997,
internally generated funds, after payment of dividends, provided
approximately 62 percent of total capital requirements for construction,
sinking funds and other requirements. The Company anticipates that for
1998, internally generated funds will provide approximately 48 percent
of total capital requirements for regulated operations.
At December 31, 1997, the Company's capitalization consisted of
50.4 percent common equity, 41.8 percent long-term debt and 7.8 percent
preferred equity. The Company has a comprehensive capital plan to
increase the equity component of its capital structure.
In May 1997, the rating of the Company's first mortgage bonds by
Standard & Poor's was upgraded from "BBB+" to "A-," reflecting Standard
& Poor's revised assessment of the ultimate recovery risk of the senior
secured debt of utilities. The Company's corporate credit rating
remains at "BBB+." The preferred stock rating remains at "BBB." In
March 1998, Standard & Poor's placed the Company's credit ratings on
Creditwatch with negative implications in reaction to what they
characterize as an adverse ruling by the VPSB regarding the Company's
rate increase request.
The rating of the Company's first mortgage bonds by Duff & Phelps
remains at "BBB+." The ratings of the Company's preferred stock remains
at "BBB." In March 1998, Duff & Phelps placed the Company's credit
ratings on Rating Watch - Down in reaction to what they characterize as
a negative outcome in the Company's rate increase request decided by the
VPSB.
The rating of the Company's first mortgage bonds by Moody's
Investment Services remains at "Baa2." The rating of the Company's
preferred stock remains at "baa3." In March 1998, Moody's changed its
rating outlook for the Company to negative and indicated the Company's
credit ratings were pressured in reaction to what they characterize as a
negative order from the VPSB regarding the Company's rate increase
request.
See Note F of the Notes to Consolidated Financial Statements for a
discussion of the bank credit facilities available to the Company. See
Note I of the Notes to Consolidated Financial Statements for a
discussion of the VPSB rate order.
Year 2000 Computer Compliance - The Company utilizes software and
related technologies throughout its businesses that will be affected by
the date change in the year 2000. The Company is in the process of
implementing new customer service and financial systems which are year
2000 compliant. An internal study is currently underway to determine
the full scope and related costs to insure that the Company's systems
continue to meet its internal needs and those of its customers.
Maintenance or modification costs will be expensed as incurred, while
the costs of new software will be capitalized and amortized over the
software's useful life. These expenditures may be significant and
continue through the year 2000.
The Company expects to have achieved compliance with year 2000
requirements for its financial and operating systems by June 30, 1999.
Failure to comply by January 1, 2000 would have a material adverse
effect on the Company's operations.
Effects of Inflation -- Financial statements are prepared in
accordance with generally accepted accounting principles and report
operating results in terms of historic costs. This accounting provides
reasonable financial statements but does not always take inflation into
consideration. As rate recovery is based on these historical costs and
known and measurable changes, the Company is able to receive some rate
relief for inflation. It does not receive immediate rate recovery
relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation
on plant costs are generally offset by the fact that these assets are
financed through long-term debt.
MANAGEMENT CHANGES
The Company's Board of Directors elected Christopher L. Dutton as
President and Chief Executive Officer and a director of the Company
effective August 6, 1997. Mr. Dutton has served as Chief Financial
Officer of the Company since 1995. He joined the Company in 1984 and
served as Vice President and General Counsel before being named Chief
Financial Officer of the Company.
On October 6,1997, the Company's Board of Directors elected the
following officers: Richard B. Hieber, Senior Vice President and Chief
Operating Officer; Michael H. Lipson, General Counsel; Edwin M. Norse,
Vice President and Chief Financial Officer and Treasurer; and Stephen C.
Terry, Senior Vice President, Corporate Development. Jonathan H. Winer
will continue to serve as President of the Company's subsidiary,
Mountain Energy, Inc., and will assume new responsibilities as part of
the Company's senior management.
On February 9, 1998, the Company's Board of Directors elected the
following officers: Mary G. Powell, Vice President Human Resources and
Organizational Development, and Nancy R. Brock, Chief Corporate
Strategic Planning Officer.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Page
Financial Statements
Consolidated Statements of Income
For the Years Ended December 31, 1997, 1996 and 1995 43
Consolidated Statements of Cash Flows For the
Years Ended December 31, 1997, 1996 and 1995 44
Consolidated Balance Sheets as of
December 31, 1997 and 1996 45-46
Consolidated Capitalization Data as of
December 31, 1997 and 1996 47
Notes to Consolidated Financial Statements 48-69
Quarterly Financial Information 59-60
Report of Independent Public Accountants 70
Schedules
For the Years Ended December 31, 1997, 1996 and 1995:
II Valuation and Qualifying Accounts and Reserves 71
All other schedules are omitted as they are either
not required, not applicable or the information is
otherwise provided.
Consents and Reports of Independent Public Accountants
Arthur Andersen LLP 70 & 82
CONSOLIDATED STATEMENTS OF INCOME
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1997 1996 1995
----------------- --------------- ---------------
(In thousands, except amounts per share)
Operating Revenues.............................................. $179,323 $179,009 $161,544
----------------- --------------- ---------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation................... 32,817 30,596 30,222
Company-owned generation................................... 5,327 3,330 3,786
Purchases from others...................................... 62,222 66,320 53,915
Other operating............................................... 16,780 17,615 18,120
Transmission................................................. 11,122 10,833 9,874
Maintenance................................................... 4,785 4,463 4,210
Depreciation and amortization................................. 16,359 16,280 14,116
Taxes other than income....................................... 7,205 6,982 6,428
Income taxes.................................................. 7,191 6,463 5,578
----------------- --------------- ---------------
Total operating expenses................................... 163,808 162,882 146,249
----------------- --------------- ---------------
Operating Income......................................... 15,515 16,127 15,295
----------------- --------------- ---------------
Other Income
Equity in earnings of affiliates and
non-utility operations..................................... 427 2,880 3,513
Allowance for equity funds used during construction........... 357 175 27
Other income and deductions, net.............................. 789 175 94
----------------- --------------- ---------------
Total other income.......................................... 1,573 3,230 3,634
----------------- --------------- ---------------
Income before interest charges............................ 17,088 19,357 18,929
----------------- --------------- ---------------
Interest Charges
Long-term debt................................................ 7,274 6,872 6,546
Other......................................................... 691 994 1,427
Allowance for borrowed funds used during
construction............................................ (315) (468) (547)
----------------- --------------- ---------------
Total interest charges...................................... 7,650 7,398 7,426
----------------- --------------- ---------------
Net Income...................................................... 9,438 11,959 11,503
Dividends on preferred stock.................................... 1,433 1,010 771
----------------- --------------- ---------------
Net Income Applicable to Common Stock........................... $8,005 $10,949 $10,732
================= =============== ===============
Common Stock Data
Earnings per share............................................ $1.57 $2.22 $2.26
Cash dividends declared per share............................. $1.61 $2.12 $2.12
Weighted average shares outstanding........................... 5,112 4,933 4,747
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION December 31
1997 1996
--------- ---------
(In thousands)
ASSETS
Utility Plant
Utility plant, at original cost....................$265,441 $248,135
Less accumulated depreciation...................... 87,689 81,286
--------- ---------
Net utility plant................................ 177,752 166,849
Property under capital lease....................... 8,342 9,006
Construction work in progress...................... 10,626 13,998
--------- ---------
Total utility plant, net......................... 196,720 189,853
--------- ---------
Other Investments
Associated companies, at equity ................... 15,860 15,769
Other investments ................................. 6,137 4,865
--------- ---------
Total other investments.......................... 21,997 20,634
--------- ---------
Current Assets
Cash............................................... 118 238
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 17,365 17,733
Accrued utility revenues........................... 6,505 6,662
Fuel, materials and supplies, at average cost...... 3,261 3,621
Prepayments........................................ 1,563 2,206
Other.............................................. 313 441
--------- ---------
Total current assets............................. 29,125 30,901
--------- ---------
Deferred Charges
Demand side management programs.................... 13,692 16,409
Environmental proceedings costs.................... 8,441 7,991
Purchased power costs.............................. 4,283 9,163
Other.............................................. 9,415 9,661
--------- ---------
Total deferred charges........................... 35,831 43,224
--------- ---------
Non-Utility
Cash and cash equivalents.......................... 153 511
Other current assets............................... 11,501 3,979
Property and equipment............................. 10,784 11,226
Intangible assets.................................. 2,116 2,555
Equity investment in energy-related businesses..... 12,824 12,494
Other assets....................................... 4,682 9,162
--------- ---------
Total non-utility assets......................... 42,060 39,927
--------- ---------
Total Assets...........................................$325,733 $324,539
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION December 31
1997 1996
--------- ---------
(In thousands)
CAPITALIZATION AND LIABILITIES
Capitalization (See Capitalization Data)
Common Stock Equity
Common stock..................................... $17,318 $16,790
Additional paid-in capital....................... 70,720 68,226
Retained earnings................................ 26,717 26,916
Treasury stock, at cost.......................... (378) (378)
--------- ---------
Total common stock equity...................... 114,377 111,554
Redeemable cumulative preferred stock.............. 17,735 19,310
Long-term debt, less current maturities ........... 93,200 94,900
--------- ---------
Total capitalization........................... 225,312 225,764
--------- ---------
Capital Lease Obligation .............................. 8,342 9,006
--------- ---------
Current Liabilities
Current maturuties of long-term debt............... 1,700 3,034
Short-term debt.................................... 2,616 1,016
Accounts payable, trade, and accrued liabilities... 6,828 6,140
Accounts payable to associated companies........... 7,661 6,621
Dividends declared................................. 350 381
Customer deposits.................................. 721 689
Taxes accrued...................................... 2,843 986
Interest accrued................................... 1,311 1,382
Other.............................................. 1,256 788
--------- ---------
Total current liabilities...................... 25,286 21,037
--------- ---------
Deferred Credits
Accumulated deferred income taxes.................. 23,501 26,726
Unamortized investment tax credits................. 4,542 4,825
Other.............................................. 25,680 23,417
--------- ---------
Total deferred credits......................... 53,723 54,968
--------- ---------
Non-Utility
Current liabilities................................ 1,119 1,752
Other liabilities.................................. 11,951 12,012
--------- ---------
Total non-utility liabilities.................. 13,070 13,764
--------- ---------
Total Capitalization and Liabilities...................$325,733 $324,539
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1997 1996 1995
--------- --------- ---------
(In thousands)
Operating Activities:
Net Income........................................................... $9,438 $11,959 $11,503
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 16,359 16,280 14,116
Dividends from associated companies less equity income........... (90) 254 660
Allowance for funds used during construction..................... (672) (643) (574)
Deferred purchased power costs................................... (331) (5,917) (12,935)
Amortization of purchased power costs............................ 5,212 5,187 6,036
Deferred income taxes............................................ (2,715) 1,937 3,715
Amortization of investment tax credits........................... (282) (282) (283)
Environmental proceedings costs, net............................. (2,123) (1,720) (1,351)
Conservation expenditures........................................ (2,411) (3,207) (3,960)
Changes in:
Accounts receivable............................................ 368 347 (2,841)
Accrued utility revenues....................................... 156 (139) (510)
Fuel, materials and supplies................................... 359 (309) 2
Prepayments and other current assets........................... (6,749) (354) 1,562
Accounts payable............................................... 1,728 221 2,191
Taxes accrued.................................................. 1,856 415 (871)
Interest accrued............................................... (71) (465) (106)
Other current liabilities...................................... (164) 1,065 (22)
Other............................................................ 6,635 1,738 (95)
--------- --------- ---------
Net cash provided by operating activities.......................... 26,503 26,367 16,237
--------- --------- ---------
Investing Activities:
Construction expenditures.......................................... (16,409) (17,541) (15,314)
Investment in non-utility property................................. 218 (2,203) (6,121)
--------- --------- ---------
Net cash used in investing activities............................ (16,191) (19,744) (21,435)
--------- --------- ---------
Financing Activities:
Issuance of preferred stock........................................ -- 12,000 --
Reduction in preferred stock....................................... (1,575) (1,620) (205)
Issuance of common stock........................................... 3,023 4,642 4,404
Short-term debt, net............................................... 1,600 (7,400) (11,799)
Issuance of long-term debt......................................... -- 14,000 25,917
Reduction in long-term debt........................................ (4,201) (16,201) (4,833)
Cash dividends..................................................... (9,637) (11,455) (10,818)
--------- --------- ---------
Net cash provided by (used in) financing activities.............. (10,790) (6,034) 2,666
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... (478) 589 (2,532)
Cash and cash equivalents at beginning of year..................... 749 160 2,692
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $271 $749 $160
========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION December 31
Issued and Outstanding
CAPITAL STOCK Authorized 1997 1996 1997 1996
----------- ---------- ---------- --------- ---------
(In thousands)
Common Stock,$3.33 1/3 par value (Note C)....................... 10,000,000 5,195,432 5,037,143 $17,318 $16,790
========= =========
-----------------------------------------------------------------------------------------------------------------
Outstanding
Authorized Issued 1997 1996 1997 1996
---------- ----------- ---------- ---------- --------- ---------
(In thousands)
Redeemable Cumulative Preferred Stock,
$100 par value (Note D)
4.75%,Class B, redeemable at
$101 per share..................................... 15,000 15,000 2,700 2,850 $270 $285
7%,Class C, redeemable at
$101 per share..................................... 15,000 15,000 4,650 4,650 465 465
9.375%,Class D,Series 1,
redeemable at $101 per share....................... 40,000 40,000 8,000 9,600 800 960
8.625%,Class D,Series 3,
redeemable at $101.919 per share................... 70,000 70,000 42,000 56,000 4,200 5,600
7.32%,Class E,Series 1,.............................. 200,000 120,000 120,000 120,000 12,000 12,000
--------- ---------
Total Preferred Stock................................... $17,735 $19,310
========= =========
LONG-TERM DEBT (Note E) 1997 1996
--------- ---------
(In thousands)
First Mortgage Bonds
6.84% Series due 1997......................................................................................$ -- $1,334
7% Series due 1998......................................................................................... 3,000 3,000
5.71% Series due 2000...................................................................................... 5,000 5,000
6.21% Series due 2001...................................................................................... 8,000 8,000
6.29% Series due 2002...................................................................................... 8,000 8,000
6.41% Series due 2003...................................................................................... 8,000 8,000
10.0% Series due 2004 - Cash sinking fund,$1,700,000
annually............................................................................................... 11,900 13,600
7.05% Series due 2006...................................................................................... 4,000 4,000
7.18% Series due 2006...................................................................................... 10,000 10,000
6.7% Series due 2018....................................................................................... 15,000 15,000
9.64% Series due 2020...................................................................................... 9,000 9,000
8.65% Series due 2022 - Cash sinking fund,commences 2012................................................... 13,000 13,000
--------- ---------
Total Long-term Debt Outstanding............................................................................. 94,900 97,934
Less Current Maturities (due within one year).............................................................. 1,700 3,034
--------- ---------
Total Long-term Debt, Net.................................................................................... $93,200 $94,900
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
A. SIGNIFICANT ACCOUNTING POLICIES
1. The Company. Green Mountain Power Corporation (the Company) is
an investor-owned energy services company located in Vermont that serves
one-quarter of its population. The most significant portion of the
Company's net income is derived from its regulated electric utility
operation, which purchases and generates electric power and distributes
it to 83,200 retail and wholesale customers. Two of the Company's
wholly-owned subsidiaries (which are not regulated by the Vermont Public
Service Board (VPSB)) are Green Mountain Propane Gas Company (GMPG),
which supplies propane to 10,000 customers in Vermont and New Hampshire,
and Mountain Energy, Inc., which has invested in energy generation and
energy and waste water efficiency projects across the United States. In
1996, the Company's wholly-owned, unregulated subsidiary, Green Mountain
Resources, Inc. (GMRI), was created to participate in the emerging
retail energy market. The results of these subsidiaries, the Company's
unregulated rental water heater program and its other unregulated
wholly-owned subsidiaries (GMP Real Estate Corporation and Lease-Elec,
Inc.) are included in earnings of affiliates and non-utility operations
in the Other Income section of the Consolidated Statements of Income.
Summarized financial information is as follows:
For the years ended December 31,
1997 1996
---- ----
(In thousands)
Revenues . . . . . . . . . . . . . . . $11,842 $11,997
Expenses. . . . . . . . . . . . . . . . 13,439 11,207
-------- -------
Net Income . . . . . . . . . . . . . . $(1,597) $ 790
======== =======
In 1997, the Company and an affiliate of the Sam Wyly family
announced that they will jointly own Green Mountain Energy Resources
L.L.C. (GMER), a Delaware limited liability company in which GMRI was
the sole owner. GMER is competing in the emerging retail energy market
starting in California where customers are able to choose their
electricity supplier as of March 31, 1998. See Management's Discussion
and Analysis of Financial Condition and Results of Operations - Future
Outlook - Unregulated Businesses for a complete discussion.
The Company carries its investments in various associated companies
- -- Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Vermont
Electric Power Company, Inc. (VELCO), New England Hydro-Transmission
Corporation, and New England Hydro-Transmission Electric Company -- at
equity.
2. Basis of Presentation The Company's utility operations,
including accounting records, rates, operations and certain other
practices of its electric utility business, are subject to the
regulatory authority of the Federal Energy Regulatory Commission (FERC)
and the VPSB.
The accompanying consolidated financial statements conform to
generally accepted accounting principles applicable to rate-regulated
enterprises in accordance with Statement of Financial Accounting
Standards (SFAS) 71, Accounting for Certain Types of Regulation. Under
SFAS 71, the Company is permitted to account for certain transactions in
accordance with permitted regulatory treatment. As such, regulators may
permit incurred costs, typically treated as expenses, to be deferred and
recovered in future revenues. Conditions that give rise to the
discontinuance of SFAS 71 include (1) increasing competition that
restricts the Company's ability to establish prices to recover specific
costs, and (2) a change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. In
the event that the Company no longer meets the criteria under SFAS 71,
the Company would be required to write off related regulatory assets and
liabilities.
SFAS 121, Accounting for the Impairment of Long Lived Assets, which
became effective for the Company January 1, 1996, requires that any
assets, including regulatory assets, which are no longer probable of
recovery through future revenues, be revalued based upon future cash
flows. SFAS 121 requires that a rate-regulated enterprise recognize an
impairment loss for regulatory assets which are no longer probable of
recovery. As of December 31, 1997, based upon the regulatory
environment within which the Company currently operates, no impairment
loss need be recorded under SFAS 121. Competitive influences or
regulatory developments may impact this status in the future. See
Management's Discussion and Analysis of Financial Condition and Results
of Operations for a discussion of electric utility restructuring which
may impact the Company's application of SFAS 71 and 121, and Note I of
the Notes to Consolidated Financial Statements.
3. Statements of Cash Flows. The following amounts of interest
(net of amounts capitalized) and income taxes were paid for the years
ending December 31:
1997 1996 1995
---- ---- ----
(In thousands)
Interest . . . . . . . . . . . . . . . . $7,800 $8,104 $7,940
Income Taxes (Net of refunds) . . . . . 5,853 3,727 2,949
4. Utility Plant. The cost of plant additions includes all
construction-related direct labor and materials, as well as indirect
construction costs, including the cost of money (Allowance for Funds
Used During Construction or AFUDC). The costs of renewals and
betterments of property units are capitalized. The costs of
maintenance, repairs and replacements of minor property items are
charged to maintenance expense. The costs of units of property removed
from service, net of removal costs and salvage, are charged to
accumulated depreciation.
5. Depreciation. The Company provides for depreciation on the
straight-line method based on the cost and estimated remaining service
life of the depreciable property outstanding at the beginning of the
year and adjusted for salvage value and cost of removal of the property.
The annual depreciation provision was approximately 3.6 percent of
total depreciable property at the beginning of each year 1997, 1996 and
1995.
6. Operating Revenues. Operating revenues consist principally of
sales of electric energy. The Company records accrued utility revenues,
based on estimates of electric service rendered and not billed at the
end of an accounting period, in order to match revenues with related
costs.
7. Deferred Charges. In a manner consistent with authorized or
expected ratemaking treatment, the Company defers and amortizes certain
replacement power, maintenance and other costs associated with the
Vermont Yankee nuclear plant. In addition, the Company accrues and
amortizes other replacement power expenses to reflect more accurately
its cost of service to better match revenues and expenses consistent
with regulatory treatment.
The Company defers and amortizes costs associated with its
investment in the demand side management program.
At December 31, 1997, other deferred charges totaled $9.4 million,
consisting of repair costs for the Essex and Vergennes hydroelectric
facilities, regulatory deferrals of storm damages, rights-of-way
maintenance, regulatory proceedings expenses, unamortized debt expense,
preliminary survey and investigation charges, transmission
interconnection charges and various other projects and deferrals.
8. Earnings Per Share. Earnings per share are based on the
weighted average number of shares of common stock outstanding during
each year.
In March 1997, the Financial Accounting Standards Board issued a
new accounting standard, Statement of Financial Accounting Standards
No. 128, Earnings per Share (SFAS 128). SFAS 128, effective for
financial statements issued for annual periods ending after December 15,
1997, replaces the definition of primary earnings per share, calculated
in accordance with the provisions of APB 15, with a new calculation,
basic earnings per share. Fully diluted earnings per share, now called
diluted earnings per share, is still required. Since the Company has
not issued any potentially dilutive securities, both calculations are
the same.
9. Major Customers. The Company had one major retail customer,
IBM, metered at two locations, that accounted for 14.0, 13.2 and
12.9 percent of operating revenues in 1997, 1996 and 1995, respectively.
10. Pension and Retirement Plans. The Company has a defined
benefit pension plan covering substantially all of its employees. The
retirement benefits are based on the employees' level of compensation
and length of service. The Company's policy is to fund all accrued
pension costs. The Company records annual expense based on amounts
funded in accordance with methods approved in the rate-setting process.
Net pension costs reflect the following components and assumptions:
1997 1996 1995
---- ---- ----
(Dollars in thousands)
Service cost-benefits earned during the period . $ 720 $ 689 $ 687
Interest cost on projected benefit obligations . 2,069 1,912 1,671
Actual return on plan assets . . . . . . . . . . (6,339) (4,383) (6,447)
Net amortization and deferral . . . . . . . . . . 3,432 1,756 4,232
Effect of voluntary retirement program . . . . . --- 416 765
Adjustment due to actions of regulator . . . . . 126 (366) (878)
------ ------ -------
Net periodic pension cost funded and recognized . $ 8 $ 24 $ 30
====== ====== =======
Assumptions used to determine pension costs and the related benefit
obligation in 1997, 1996 and 1995 were:
Discount rate . . . . . . . . . . . . . . . . 7.25% 8.0% 8.0%
Rate of increase in future compensation levels 4.5% 5.0% 5.0%
Expected long-term rate of return on assets . 9.0% 9.0% 9.0%
The following table sets forth the plan's funded status as of December
31:
1997 1996 1995
---- ---- ----
(In thousands)
Actuarial present value of benefit obligations:
Accumulated benefit obligations,
including vested benefits of $24,231,
$21,146 and $19,107, respectively . . . . ($25,717) ($21,376) ($19,431)
========= ========= =========
Projected benefit obligations for
service rendered to date . . . . . . . . ($28,630) ($25,615) ($21,974)
Plan assets at fair value . . . . . . . . . . 35,773 31,286 28,685
--------- --------- ---------
Assets in excess of projected
benefit obligations . . . . . . . . . . . . 7,143 5,671 6,711
Unrecognized net gain from past
experience different from that assumed . . (5,962) (4,734) (5,188)
Prior service cost not yet recognized in net
periodic pension cost . . . . . . . . . . . 1,247 1,474 1,506
Unrecognized net asset at transition
being recognized over 16.47 years . . . . . (1,249) (1,477) (1,706)
Adjustment due to actions of regulator . . . . (1,179) (934) (1,323)
-------- -------- -------
Prepaid pension cost included in other assets $ --- $ --- $ ---
======== ======== =======
The plan assets consist primarily of cash equivalent funds, fixed
income securities and equity securities.
The Company also has a supplemental pension plan for certain
employees. Pension costs for the years ended December 31, 1997, 1996
and 1995 were $456,000, $494,000 and $397,000, respectively, under this
plan. This plan is funded in part through insurance contracts.
11. Postretirement Health Care Benefits. The Company provides
certain health care benefits for retired employees and their dependents.
Employees become eligible for these benefits if they reach normal
retirement age while working for the Company. The Company accrues the
cost of these benefits during the service life of covered employees.
Accrued postretirement health care expenses are recovered in rates
if those expenses are funded. In order to maximize the tax deductible
contributions that are allowed under IRS regulations, the Company
amended its pension plan to establish a 401-h sub-account and separate
VEBA trusts for its union and non-union employees. The plan assets
consist primarily of cash equivalent funds, fixed income securities and
equity securities.
Net postretirement benefits costs reflect the following components
and assumptions:
1997 1996 1995
---- ---- ----
(In thousands)
Accumulated postretirement benefit obligation:
Current retirees . . . . . . . . . . . . ($ 6,412) ($ 4,563) ($ 4,594)
Participants currently eligible . . . . (483) (772) (681)
All others . . . . . . . . . . . . . . . (4,151) (3,837) (3,384)
--------- --------- ---------
Total accumulated postretirement benefit
obligation . . . . . . . . . . . . . . . (11,046) (9,172) (8,659)
Plan assets at fair value . . . . . . . . . 7,893 6,327 5,465
--------- --------- --------
Accumulated postretirement benefit
obligation in excess of plan assets . . (3,153) (2,845) (3,194)
Unrecognized prior service cost . . . . . . (805) (867) (929)
Unrecognized transition obligation . . . . 5,278 5,630 5,982
Unrecognized net gain . . . . . . . . . . . (1,400) (1,879) (1,687)
-------- -------- --------
Prepaid (accrued) postretirement benefit
cost . . . . . . . . . . . . . . . . . . $ (80) $ 39 $ 172
======== ======== ========
Net periodic postretirement benefit cost includes the following
components:
1997 1996 1995
---- ---- ----
(In thousands)
Service cost . . . . . . . . . . . . . . . . $ 228 $ 247 $ 224
Interest cost . . . . . . . . . . . . . . . 763 698 697
Actual return on plan assets . . . . . . . . (1,566) (870) (586)
Deferred asset gain. . . . . . . . . . . . . 1,028 407 264
Recognition of transition obligation,
net of amortization . . . . . . . . . . . 261 245 234
------- ------- -------
Total net periodic postretirement
benefit cost . . . . . . . . . . . . . $ 714 $ 727 $ 833
======= ======= =======
Assumptions used to determine postretirement benefit costs and the
related benefit obligation were:
1997 1996 1995
---- ---- ----
Discount rate to determine postretirement
benefit costs . . . . . . . . . . . . . . 8.0% 8.0% 8.5%
Discount rate to determine postretirement
benefit obligation . . . . . . . . . . . . 7.25% 8.0% 8.5%
Expected long-term rate of return on assets. 8.5% 8.5% 7.5%
For measurement purposes, a 5.8 percent annual rate of increase in
the per capita cost of covered benefits was assumed for 1997; the rate
was assumed to decrease gradually to 5.0 percent by the year 2001 and
remain at that level thereafter. The health care cost trend rate
assumption has a significant effect on the amounts reported. For
example, increasing the assumed health care cost trend rate by one
percentage point would increase the accumulated postretirement benefit
obligation as of December 31, 1997 by $1.7 million and the aggregate of
the service and interest components of net periodic postretirement
benefit cost for the year ended December 31, 1997 by $156,000.
12. Fair Value of Financial Instruments. If the first mortgage
bonds and preferred stock outstanding at December 31, 1997 were
refinanced using new issue debt rates of interest, which, on average,
are lower than the Company's outstanding rates, the present value of
those obligations would differ from the amounts outstanding on the
December 31, 1997 balance sheet by 4 percent. In the event of such a
refinancing, there would be no gain or loss, inasmuch as under
established regulatory precedent, any such difference would be reflected
in rates and have no effect upon income.
13. Deferred Credits. At December 31, 1997, the Company had other
deferred credits and long-term liabilities of $25.7 million, consisting
of operating lease equalization, reserves for damage claims and
environmental liabilities and accruals for employee benefits.
14. Use of Estimates. The preparation of financial statements in
conformity with generally accepted accounting principles requires the
use of estimates and assumptions that affect assets and liabilities, the
disclosure of contingent assets and liabilities, and revenues and
expenses. Actual results could differ from those estimates.
B. INVESTMENTS IN ASSOCIATED COMPANIES
The Company accounts for investments in the following companies by
the equity method:
Percent Ownership Investment in Equity
at December 31, 1997 December 31,
-------------------- --------------------
1997 1996
---- ----
(In thousands)
VELCO - Common . . . . . . . . . 29.5% $ 1,833 $ 1,834
- Preferred . . . . . . . 30.0% 961 1,118
-------- -------
Total VELCO . . . . . . . . . . 2,794 2,952
Vermont Yankee - Common . . . . 17.9% 9,701 9,768
New England Hydro-Transmission -
Common . . . . . . . . . . 3.18% 1,063 1,205
New England Hydro-Transmission
Electric - Common . . . . . 3.18% 1,811 1,891
------- -------
$15,369 $15,816
======= =======
Undistributed earnings in associated companies totaled $632,000 at
December 31, 1997.
VELCO. VELCO is a corporation engaged in the transmission of
electric power within the State of Vermont. VELCO has entered into
transmission agreements with the State of Vermont and other electric
utilities, and under these agreements bills all costs, including
interest on debt and a fixed return on equity, to the State and others
using the system. The Company's purchases of transmission services from
VELCO were $7.6 million, $7.7 million and $7.6 million for the years
1997, 1996 and 1995, respectively. Pursuant to VELCO's Amended Articles
of Association, the Company is entitled to approximately 30 percent of
the dividends distributed by VELCO. The Company has recorded its equity
in earnings on this basis and also is obligated to provide its
proportionate share of the equity capital requirements of VELCO through
continuing purchases of its common stock, if necessary.
Summarized financial information for VELCO is as follows:
December 31,
------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Company's equity in net income . . . . . . . $ 354 $ 383 $ 377
======= ======= =======
Total assets . . . . . . . . . . . . . . . . $70,566 $74,065 $71,668
Less:
Liabilities and long-term debt . . . . . 61,162 64,159 61,238
------ ------- -------
Net assets . . . . . . . . . . . . . . . . . $9,404 $ 9,906 $10,430
====== ======= =======
Company's equity in net assets . . . . . . . $2,794 $ 2,952 $ 3,089
====== ======= =======
Vermont Yankee. The Company is responsible for 17.7 percent of
Vermont Yankee's expenses of operations, including costs of equity
capital and estimated costs of decommissioning, and is entitled to a
similar share of the power output of the nuclear plant, which has a net
capacity of 531 megawatts. Vermont Yankee's current estimate of
decommissioning costs is approximately $386 million, of which $193
million has been funded. At December 31, 1997, the Company's portion of
the net unfunded liability was $34 million, which it expects will be
recovered through rates over Vermont Yankee's remaining operating life.
As a sponsor of Vermont Yankee, the Company also is obligated to provide
20 percent of capital requirements not obtained by outside sources.
During 1997, the Company incurred $28.5 million in Vermont Yankee annual
capacity charges, which included $1.9 million for interest charges. The
Company's share of Vermont Yankee's long-term debt at December 31, 1997
was $16.2 million.
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 is indemnified under an agreement with the Nuclear
Regulatory Commission, 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 Program, 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 retrospective obligation remains at $3.1 million. The Secondary
Financial Protection layer, as referenced above, would be in excess of
the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance
Limited (NEIL) to cover the costs of property damage, decontamination or
premature decommissioning resulting from a nuclear incident. All
companies insured with NEIL are subject to retroactive assessments if
losses exceed the accumulated funds available. The maximum potential
assessment against Vermont Yankee with respect to NEIL losses arising
during the current policy year is $11.0 million. Vermont Yankee's
liability for the retrospective premium adjustment for any policy year
ceases six years after the end of that policy year unless prior demand
has been made.
Summarized financial information for Vermont Yankee is as follows:
December 31,
--------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . . $173,106 $181,715 $180,437
Net income applicable to common stock . 6,834 6,985 6,790
Company's equity in net income . . . . . 1,244 1,232 1,171
Total assets . . . . . . . . . . . . . . . $610,024 $565,000 $531,293
Less:
Liabilities and long-term debt . . . . . 555,735 510,202 477,350
-------- -------- --------
Net assets . . . . . . . . . . . . . . . . $ 54,289 $ 54,798 $ 53,943
======== ======== ========
Company's equity in net assets . . . . . . $ 9,701 $ 9,768 $ 9,631
======== ======== ========
C. COMMON STOCK EQUITY
The Company maintains a Dividend Reinvestment and Stock Purchase
Plan (DRIP) under which 388,508 shares were reserved and unissued at
December 31, 1997. The Company also funds an Employee Savings and
Investment Plan (ESIP). At December 31, 1997, there were 123,198 shares
reserved and unissued under the ESIP.
During 1995, the Company's Board of Directors, with subsequent
approval of the Company's common shareholders, adopted the Compensation
Program for Officers and Certain Key Management Personnel. The program
links a portion of the officers and key management personnels'
compensation to corporate performance results. Participants are
entitled to receive cash and restricted and unrestricted stock grants in
predetermined proportions. Participants who receive restricted stock
are entitled to receive dividends and have voting rights but assumption
of full beneficial ownership is contingent upon two restrictions of a
five year duration, including no transferability and forfeiture of the
stock upon termination of employment with the Company. Participants who
receive unrestricted stock assume full beneficial ownership upon grant
and may retain or sell such shares. During 1997, 10,956 shares of
common stock were awarded under this program. At December 31, 1997,
there were 20,083 shares reserved and unissued under the Compensation
Program.
Changes in common stock equity for the years ended December 31,
1995, 1996 and 1997 are as follows:
Common Stock Treasury Stock
------------------------ Paid-in Retained ------------------------ Stock
Shares Amount Capital Earnings Shares Amount Equity
------ ------ ------- -------- ------ ------ ------
(Dollars in thousands)
BALANCE, December 31, 1994............... 4,677,512 $15,592 $60,378 $25,727 15,856 ($378) $101,319
Common Stock Issuance:
DRIP................................... 125,046 417 2,731 3,148
ESIP................................... 36,012 120 829 949
Compensation Program:
Restricted Shares.................... 8,100 27 182 209
Stock Grant.......................... 3,826 12 86 98
Net Income............................... 11,503 11,503
Cash Dividends on Capital Stock:
Common Stock -$2.12 per share..... (10,047) (10,047)
Preferred Stock -$4.75 per share..... (15) (15)
-$7.00 per share..... (36) (36)
-$9.375 per share.... (116) (116)
-$8.625 per share.... (604) (604)
------------------------------------------------------------------------------------
BALANCE, December 31, 1995............... 4,850,496 16,168 64,206 26,412 15,856 (378) 106,408
Common Stock Issuance:
DRIP................................... 149,968 500 3,188 3,688
ESIP................................... 29,644 99 668 767
Compensation Program:
Restricted Shares.................... 2,392 8 59 67
Stock Grant.......................... 4,643 15 105 120
Net Income............................... 11,959 11,959
Cash Dividends on Capital Stock:
Common Stock -$2.12 per share..... (10,445) (10,445)
Preferred Stock -$4.75 per share..... (14) (14)
-$7.00 per share..... (35) (35)
-$9.375 per share.... (101) (101)
-$8.625 per share.... (543) (543)
-$7.32 per share..... (317) (317)
------------------------------------------------------------------------------------
BALANCE, December 31, 1996............... 5,037,143 16,790 68,226 26,916 15,856 (378) 111,554
Common Stock Issuance:
DRIP................................... 120,631 402 2,182 2,584
ESIP................................... 26,702 89 507 596
Compensation Program:
Restricted Shares.................... 6,190 21 119 140
Stock Grant.......................... 4,766 16 92 108
Net Income............................... 9,438 9,438
Cash Dividends on Capital Stock:
Common Stock -$2.12 per share..... (8,204) (8,204)
Preferred Stock -$4.75 per share..... (13) (13)
-$7.00 per share..... (33) (33)
-$9.375 per share.... (86) (86)
-$8.625 per share.... (423) (423)
-$7.32 per share..... (878) (878)
Other-Preferred Stock Issuance Expense... (406) (406)
------------------------------------------------------------------------------------
BALANCE, December 31, 1997............... 5,195,432 $17,318 $70,720 $26,717 15,856 ($378) $114,377
====================================================================================
Dividend Restrictions. Certain restrictions on the payment of cash
dividends on common stock are contained in the Company's indenture
relating to long-term debt and in the Restated Articles of Association.
Under the most restrictive of such provisions, $17.5 million of retained
earnings were free of restrictions at December 31, 1997.
The properties of the Company include several hydroelectric
projects licensed under the Federal Power Act, with license expiration
dates ranging from 1999 to 2025. At December 31, 1997, $350,000 of
retained earnings had been appropriated as excess earnings on
hydroelectric projects as required by Section 10(d) of the Federal Power
Act.
D. PREFERRED STOCK
The holders of the preferred stock are entitled to specific voting
rights with respect to certain types of corporate actions. They are
also entitled to elect the smallest number of directors necessary to
constitute a majority of the Board of Directors in the event of
preferred stock dividend arrearages equivalent to or exceeding four
quarterly dividends. Similarly, the holders of the preferred stock are
entitled to elect two directors in the event of a default in any
purchase or sinking fund requirements provided for any class of
preferred stock.
Certain classes of preferred stock are subject to annual purchase
or sinking fund requirements. The sinking fund requirements are
mandatory. The purchase fund requirements are mandatory, but holders
may elect not to accept the purchase offer. The redemption or purchase
price to satisfy these requirements may not exceed $100 per share plus
accrued dividends. All shares redeemed or purchased in connection with
these requirements must be canceled and may not be reissued. The annual
purchase and sinking fund requirements for certain classes of preferred
stock are as follows:
Purchase and Sinking Fund
8.625%, Class D, Series 3 . . September 1 14,000 Shares
4.75%, Class B . . . . . . . . December 1 450 Shares
7%, Class C . . . . . . . . . December 1 450 Shares
9.375%, Class D, Series 1 . . December 1 1,600 Shares
Under the Restated Articles of Association relating to Redeemable
Cumulative Preferred Stock, the annual aggregate amount of purchase and
sinking fund requirements for the next five years are $1,650,000 for
each of the years 1998-1999, $1,640,000 for 2000 and $235,000 for 2001-
2002.
Certain classes of preferred stock are redeemable at the option of
the Company or, in the case of voluntary liquidation, at various prices
on various dates. The prices include the par value of the issue plus
any accrued dividends and a redemption premium. The redemption premium
for Class B, C and D, Series 1, is $1.00 per share. The redemption
premium for the Class D, Series 3, is $1.919 per share until September
1, 1998; and $0.916 per share from September 1, 1998 to September 1,
1999, after which there is no redemption premium.
E. LONG-TERM DEBT
Utility. Substantially all of the property and franchises of the
Company are subject to the lien of the indenture under which first
mortgage bonds have been issued. The annual sinking fund requirements
(excluding amounts that may be satisfied by property additions) and
long-term debt maturities for the next five years are:
Sinking
Funds Maturities Total
------- ---------- -----
(In thousands)
1998 . . . . . . . . . . . . . .$1,700 $3,000 $4,700
1999 . . . . . . . . . . . . . . 1,700 --- 1,700
2000 . . . . . . . . . . . . . . 1,700 5,000 6,700
2001 . . . . . . . . . . . . . . 1,700 8,000 9,700
2002 . . . . . . . . . . . . . . 1,700 8,000 9,700
Non-Utility. At December 31, 1997, Green Mountain Propane Gas
Company, the Company's propane subsidiary, had long-term debt of
$1,900,000, which was secured by substantially all of the subsidiary's
assets, and Mountain Energy, Inc., the Company's subsidiary that invests
in energy generation and energy and wastewater efficiency projects, had
unsecured long-term debt of $1,583,330. The annual sinking fund
requirements and maturities for the next three years are:
Sinking
Funds Maturities Total
------- ---------- -----
(In thousands)
1998 . . . . . . . . . . . . . $1,167 $ --- $1,167
1999 . . . . . . . . . . . . . 167 900 1,067
2000 . . . . . . . . . . . . . 83 1,166 1,249
F. SHORT-TERM DEBT
Utility. On August 12, 1997, the Company entered into a revolving
credit agreement in the amount of $45 million with three banks, which
replaces a portion of its lines of credit. At December 31, 1997, there
were no borrowings outstanding under this revolving credit agreement.
At December 31, 1997, the Company had lines of credit with two
banks totaling $8.0 million, with borrowings outstanding of $2.6
million. Borrowings under these lines of credit are at interest rates
based on various market rates and are generally less than the prime
rate. The Company has fee arrangements on its lines of credit ranging
from 0 to 1/8 percent and no compensating balance requirements. These
lines of credit are subject to periodic review and renewal during the
year by the various banks.
The weighted average interest rate on borrowings outstanding at
December 31, 1997 and December 31, 1996 was 7.0 percent and 5.7 percent,
respectively.
Non-Utility. At December 31, 1997, Green Mountain Propane Gas
Company, the Company's propane subsidiary, had a line of credit with a
bank for $750,000, with $400,000 outstanding.
G. INCOME TAXES
Utility. The Company accounts for income taxes using an asset and
liability approach. This approach accounts for deferred income taxes by
applying statutory rates in effect at year end to the differences
between the book and tax bases of assets and liabilities.
The regulatory assets and liabilities represent taxes that will be
collected from or returned to customers through rates in future periods.
As of December 31, 1997 and 1996, the net regulatory assets were
$1,704,000 and $1,194,000, respectively.
The temporary differences which gave rise to the net deferred tax
liability at December 31, 1997 and December 31, 1996, were as follows:
At December 31, At December 31,
1997 1996
--------------- ---------------
(In thousands)
Deferred Tax Assets
Contributions in aid of construction $ 7,946 $ 7,094
Deferred compensation and
post-retirement benefits . . . . . . 3,199 2,944
Alternative minimum tax credit . . . 15 (552)
Other . . . . . . . . . . . . . . . . 3,212 2,719
------- -------
14,372 12,205
------- -------
Deferred Tax Liabilities
Property-related and other . . . . . 31,864 29,359
Demand side management costs . . . . 4,775 5,856
Deferred purchased power costs . . . 1,234 3,716
-------- --------
37,873 38,931
-------- --------
Net accumulated deferred income tax
liability . . . . . . . . . . . . . ($23,501) ($26,726)
========= =========
The following table reconciles the change in the net accumulated
deferred income tax liability to the deferred income tax expense
included in the income statement for the period:
Year Ended December 31,
--------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Net change in deferred income tax
liability per above table . . . . . . . . . ($3,225) $1,434 $3,210
Change in income tax related regulatory
assets and liabilities. . . . . . . . . . . 509 504 503
Change in alternative minimum tax credit . . 567 109 168
IRS audit adjustment, 1989 - 1990 . . . . . . -- -- 255
-------- ------ ------
Deferred income tax expense for the period . ($2,149) $2,047 $4,136
======== ====== ======
The components of the provision for income taxes are as follows:
Year Ended December 31,
----------------------------
1997 1996 1995
---- ---- ----
(In thousands)
Current federal income taxes . . . . . . $7,355 $3,708 $ 1,359
Current state income taxes . . . . . . . 2,267 990 365
------ ------ -------
Total current income taxes. . . . . . 9,622 4,698 1,724
------ ------ -------
Deferred federal income taxes . . . . . (1,623) 1,588 3,239
Deferred state income taxes . . . . . . (526) 459 897
------- ----- -----
Total deferred income taxes. . . . . . (2,149) 2,047 4,136
------- ----- -----
Investment tax credits -- net . . . . . (282) (282) (282)
------ ------- -------
Income taxes charged to operations . . . $7,191 $6,463 $5,578
====== ======= =======
Total federal income taxes differ from the amounts computed by
applying the statutory tax rate to income before taxes. The reasons for
the differences are as follows:
Year Ended December 31,
-------------------------
1997 1996 1995
---- ---- ----
(Dollars in thousands)
Income before income tax . . . . . . . $16,630 $18,422 $17,081
Federal statutory rate . . . . . . . . 34.5% 34% 34%
Computed "expected" federal
income taxes . . . . . . . . . . . . $ 5,737 $ 6,263 $ 5,808
Increase (decrease) in taxes
resulting from:
Tax versus book depreciation . . . . 349 327 327
Dividends received and paid credit . (575) (524) (616)
AFUDC - equity funds . . . . . . . . (123) (59) (9)
Amortization of ITC . . . . . . . . (282) (282) (282)
State tax benefit . . . . . . . . . (601) (493) (429)
Excess deferred taxes . . . . . . . (60) (60) (60)
Taxes attributable to subsidiaries . 682 (140) (401)
Tax reserve . . . . . . . . . . . . 270 (101) (3)
Other . . . . . . . . . . . . . . . 53 83 (19)
------ ------ -------
Total federal income taxes . . . . . . $5,450 $5,014 $4,316
====== ====== =======
Effective federal income tax rate . . 32.8% 27.2% 25.3%
Non-Utility. The Company's non-utility subsidiaries had
accumulated deferred income taxes of $7.1 million on their balance
sheets at December 31, 1997, largely attributable to property-related
transactions.
The components of the provision for the income tax/(benefit) for
the non-utility operations are:
Year Ended December 31,
-----------------------------
1997 1996 1995
---- ---- ----
(In thousands)
State income taxes . . . . . . . . . . $ 78 $154 $165
Federal income taxes . . . . . . . . . (1,071) 207 613
Investment tax credits . . . . . . . . (45) (45) (45)
-------- ------ ------
Income tax (benefit)/provision charged
to operations. . . . . . . . . . . . . $(1,038) $ 316 $ 733
======== ====== ======
The effective federal income tax rates for the non-utility
operations were 37.0 percent, 22.4 percent, and 29.7 percent for the
years ended December 31, 1997, 1996 and 1995, respectively.
The increase in 1997 income taxes is primarily due to an increase
in taxable income, an increase in the combined federal and state income
tax rate and an increase in the reserve for unaudited income tax years.
H. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following quarterly financial information, in the opinion of
management, includes all adjustments necessary to a fair statement of
results of operations for such periods. Variations between quarters
reflect the seasonal nature of the Company's business and the timing of
rate changes.
1997 Quarter Ended
------------------
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Amounts in thousands, except per share)
Operating Revenues . . . . . . $ 47,204 $42,682 $43,574 $45,863 $179,323
Operating Income . . . . . . . 4,251 2,991 4,542 3,731 15,515
Net Income . . . . . . . . . . 3,315 1,230 3,371 1,522 9,438
Net Income Applicable to
Common Stock . . . . . . . . 2,941 856 3,022 1,186 8,005
Earnings per Average Share of
Common Stock . . . . . . . . $0.58 $0.17 $0.59 $0.23 $1.57
Weighted Average Number of
Common Shares Outstanding . 5,044 5,096 5,138 5,168 5,112
1996 Quarter Ended
------------------
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Amounts in thousands, except per share)
Operating Revenues . . . . . . $ 48,415 $40,467 $44,423 $45,704 $179,009
Operating Income . . . . . . . 5,073 1,859 4,419 4,776 16,127
Net Income . . . . . . . . . . 4,065 1,024 3,474 3,396 11,959
Net Income Applicable to
Common Stock . . . . . . . . 3,875 834 3,315 2,925 10,949
Earnings per Average Share of
Common Stock . . . . . . . . $0.80 $0.17 $0.67 $0.58 $2.22
Weighted Average Number of
Common Shares Outstanding . 4,860 4,911 4,959 5,003 4,933
I. COMMITMENTS AND CONTINGENCIES
1. Industry 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.
For a complete discussion, see Management's Discussion and Analysis
of Financial Condition and Results of Operations - "Future Outlook".
2. Environmental Matters. Public concern for the environment has
resulted in increased government regulation of the licensing and
operation of electric generation, transmission and distribution
facilities. The electric industry typically uses or generates a range
of potentially hazardous products in its operations. The Company must
meet various land, water, air and aesthetic requirements as administered
by local, state and federal regulatory agencies. The Company
maintains an environmental compliance and monitoring program that
includes employee training, regular inspection of Company facilities,
research and development projects, waste handling and spill prevention
procedures and other activities. Subject to developments concerning the
Pine Street Barge Canal site described below, the Company believes that
it is in substantial compliance with such requirements, and no material
complaints concerning compliance by the Company with present
environmental protection regulations are outstanding.
The Federal Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), commonly known as the "Superfund" law, generally
imposes strict, joint and several liability, regardless of fault, for
remediation of property contaminated with hazardous substances. The
Company has been notified by the Environmental Protection Agency (EPA)
that it is one of several potentially responsible parties (PRPs) for
cleanup of the Pine Street Barge Canal site in Burlington, Vermont,
where coal tar and other industrial materials were deposited. From the
late 19th century until 1967, gas was manufactured at the Pine Street
Barge Canal site by a number of enterprises, including the Company. In
1990, the Company was one of the 14 parties that agreed to pay a total
of $945,000 of the EPA's past response costs under a Consent Decree.
The Company remains a PRP for other past, ongoing and future response
costs. In November 1992, the EPA proposed a cleanup plan estimated by
the EPA to cost $47 million. In June 1993, the EPA withdrew this
cleanup plan in response to public concern about the plan and its cost.
The cost of any future cleanup plan, the magnitude of unresolved EPA
cost recovery claims, and the Company's share of such costs are
uncertain at this time.
Since 1994, the EPA has established a coordinating council, with
representatives of the PRPs, environmental and community groups, the
City of Burlington and the State of Vermont presided over by a neutral
facilitator. The council has determined, by consensus, what additional
studies were appropriate for the site, and is addressing the question of
additional response activities. The EPA, the State of Vermont and other
parties have entered into two consent orders for completion of
appropriate studies. Work is continuing under the second of those
orders. Most recently, on September 23, 1997, the council reached
tentative agreement on a key component of the proposed remedy for the
Pine Street site, namely, placement of an underwater sand/silt cap on
areas of the canal and wetland sediments, combined with long-term
monitoring to ensure effectiveness of the cap and to ensure that
groundwater does not reach Lake Champlain, adjacent to the site. The
EPA has estimated the costs of this remedy at between $6 to $10 million,
subject to change. In addition, the council is exploring supplemental
projects in and around the site and Burlington as part of a larger plan
to improve environmental conditions in the vicinity.
On December 1, 1994, the Company, and two other PRPs, New England
Electric System (NEES) and Vermont Gas Systems (VGS), entered into a
confidential settlement agreement with the State of Vermont, the City of
Burlington and nearly all other landowner PRPs under which, subject to
certain qualifications, the liability of those landowner PRPs for future
Superfund response costs would be limited and specified. On December 1,
1994, the Company entered into a confidential agreement with VGS
compromising contribution and cost recovery claims of each party and
contractual indemnity claims of the Company arising from the 1964 sale
of the manufactured gas plant to VGS. In March 1996, the Company and
NEES entered into a confidential agreement compromising past and future
contribution and cost recovery claims of both parties relating to
response costs. In December 1997, the Company and Southern Union Co.
entered into a confidential settlement agreement compromising past and
future contribution and cost recovery claims of both parties relating to
response costs. The Company has received payment of the full amount
provided for in the settlement. In January 1998, the Company and UGI
Utilities, Inc. entered into a confidential settlement agreement
compromising past and future contribution and cost recovery claims of
both parties relating to response costs. The Company has received
payment of the initial amount provided for in the settlement. The EPA
has advised the Company that it has incurred substantial unrecovered
response sums at the site which, together with interest the EPA alleges
may be payable, amounts to approximately $11.0 million. The Company has
not yet received a formal demand for these sums. The Company will
vigorously dispute the EPA's recovery of such costs, which include
substantial sums for studies and other activities that were not
reasonably necessary and were not undertaken consistent with legal and
regulatory requirements. Further, the Company's settlement agreements
with certain PRP's will reduce the extent to which it may bear these
past response costs. Consequently, the Company is not able at this time
to predict with certainty whether, or the extent to which it will be
required to pay such past response costs.
In December 1991, the Company brought suit against eight previous
insurers seeking recovery of unrecovered past costs, cost of defense and
indemnity against future liabilities associated with environmental
problems at the site. Discovery in the case, which was previously
subject to a stay, is complete. The Company has reached confidential
settlements with the defendants in this litigation; several such
settlements are in the final stages of documentation.
The Company has deferred amounts received from third parties, under
confidential settlements, pending resolution of the Company's ultimate
liability with respect to the site and rate recognition of that
liability.
Although the cost of the coordinating council's tentative
remediation plan, described above, is not expected to approach EPA's
earlier estimate of remediation costs for its original clean-up plan,
because the current EPA estimate is subject to change, and because the
Company believes it may prevail with respect to some of the EPA's
unrecovered response costs, the Company is unable to predict at this
time the magnitude of any liability resulting from potential claims for
the costs to investigate and remediate the site, or the likely
disposition or magnitude of claims the Company may have against others,
including its insurers, except to the extent described above.
Through rate cases filed in 1991, 1993, 1994 and 1995, the Company
has sought and received recovery for ongoing expenses associated with
the Pine Street Barge Canal site. Specifically, the Company proposed
rate recognition of its unrecovered expenditures incurred between
January 1, 1991 and June 30, 1995 (in the total of approximately $8.7
million) for technical consultants and legal assistance in connection
with the EPA's enforcement action at the site and insurance litigation.
While reserving the right to argue in the future about the
appropriateness of rate recovery for the Pine Street Barge Canal site
related costs, the Company and the Vermont Department of Public Service
(the Department) reached agreements in these cases that the full amount
of the Pine Street Barge Canal site costs reflected in those rate cases
should be recovered in rates. The Company's rates approved by the VPSB
in those proceedings reflected the Pine Street Barge Canal site related
expenditures referred to above. The Company proposed, in a rate filing
made on June 16, 1997 recovery of an additional $3.0 million in such
expenditures.
In an Order released March 2, 1998, the VPSB suspended the
amortization of expenditures associated with the Pine Street Barge Canal
site pending further proceedings. Although it did not eliminate the
rate base deferral of these expenditures, or make any specific order in
this regard, the VPSB indicated that it was inclined to agree with other
parties in the case that the ultimate costs of the Pine Street Barge
Canal, taking into account recoveries from insurance carriers and other
PRP's, should be shared between customers and shareholders of the
Company.
As of December 31, 1997, total expenditures for the Pine Street
Barge Canal site were $13.4 million, inclusive of the $11.7 million
referred to above.
An authoritative accounting standard, Statement of Position (SOP)
96-1, has been issued by the accounting profession addressing
environmental remediation obligations. This SOP is effective for years
beginning in 1997, and addresses, among other things, regulatory
benchmarks that are likely triggers of the accrual of estimated losses,
the costs included in the measurement, including incremental costs of
remediation efforts such as post-remediation monitoring and long-term
operation and maintenance costs and costs of compensation and related
benefits of employees devoting time to the remediation. This SOP,
adopted by the Company in January 1997, as required, did not have a
material adverse effect on the Company's financial position or results
of operations, due to current ratemaking treatment. Should a change in
the Company's historical ratemaking occur this conclusion could change.
3. Operating Leases. The Company has an operating lease for its
corporate headquarters building and two of its service center buildings,
including related real estate. This lease has a base term of 25 years,
ending June 30, 2009, with renewal options aggregating another 25 years.
The annual lease charges will total $983,000 for each of the years 1998
through 2008 and $574,000 for 2009. The Company has options to purchase
the buildings at fair market value at the end of the base term and at
the end of each renewal period.
4. Jointly-Owned Facilities. The Company had joint-ownership
interests in electric generating and transmission facilities at December
31, 1997, as follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- -------- ------- ------------
(In %) (In MW) (In thousands)
Highgate . . . . . . . . . . 33.8 67.6 $10,592 $3,309
McNeil . . . . . . . . . . . 11.0 5.9 $ 8,633 $3,613
Stony Brook (No. 1) . . . . . 8.8 31.0 $10,039 $6,348
Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,384 $1,384
Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 431
(1) Neutral conductor for NEPOOL/Hydro-Quebec Interconnection
The Company's share of expenses for these facilities is reflected
in the Consolidated Statements of Income. Each participant in these
facilities must provide for its own financing.
5. Rate Matters. On June 16, 1997, the Company filed a request
with the VPSB to increase retail rates by 16.7 percent ($26 million in
additional annual revenues) and the target return on common equity from
11.25 percent to 13 percent. Initial hearings before the VPSB began
November 3, 1997. The VPSB allowed the intervention of various other
parties.
In August 1997, several groups, including the Vermont Public
Interest Research Group (VPIRG), demanded that the VPSB appoint an
independent counsel to advocate against recovery of Hydro-Quebec power
costs by the Company. The VPSB issued an order appointing an
"independent investigator," described as a person or persons who will
perform a rigorous and impartial analysis of the Company's actions with
respect to its power supply options, including the Hydro-Quebec
contract. On November 7, 1997, the VPSB selected a firm, MSB Energy
Associates, Inc. (MSB) to undertake the tasks.
In testimony filed with the VPSB on October 17, 1997, the
Department asked the VPSB to find the Company's negotiation, execution
and decision to "lock in" the contract with Hydro-Quebec to be imprudent
and uneconomic. The Department had supported the contract in the period
1989-1991 after completing its own analysis, based on substantially the
same information that was available to the Company. The VPSB in 1990,
1991, 1992 and 1994 issued orders that determined the contract to be
needed to supply electricity to Vermont customers, economically
beneficial to the State and an appropriate part of the Company's
legally-required least-cost integrated resource plan.
On October 31, 1997, the Company filed with the VPSB Objections and
a Motion to Strike relating to the Hydro Quebec contract testimony and
requested that the VPSB schedule oral argument on the motion prior to
November 17, 1997. The grounds for the motion were that the VPSB had
previously decided the issues sought to be relitigated. The VPSB heard
argument on the motion on November 14, 1997 and ruled against the
Company, but granted the Company leave to renew the motion. The Company
did so in its post-trial briefs.
In its testimony, submitted in late 1997, MSB was critical of the
Company's power supply decision-making in 1991, and recommended a steep
disallowance of the Hydro-Quebec power costs, in excess of $10 million
per year. During the rebuttal phase of the rate case, the Company
showed that, MSB was not independent and did not present "rigorous
analysis" as the VPSB had ordered. MSB's presentation adopted the
testimony of the Department's principal witnesses as well as theories
espoused by a professional expert retained by IBM and MSB failed to
present its own analysis showing that, based on any information
possessed or available to the Company during the critical summer and
fall of 1991, the long-term Hydro-Quebec contract was uneconomic.
The Company filed a motion to strike the MSB testimony and to
impose sanctions upon MSB for submitting testimony without any good
faith factual or legal basis. The VPSB struck several portions of MSB's
testimony forming the core of their arguments on imprudence, based on
legal or contract interpretation, on the ground that MSB had no
qualifications to present this testimony.
Briefs in the case on non-Hydro-Quebec issues were filed January
30, 1998; the Hydro-Quebec briefs were filed on February 2; all reply
briefs were filed on February 6. In its final submissions, the Company
reduced the requested increase to 14.4 percent due to changed estimates
of costs to be incurred in the rate year.
6. Subsequent Events. On March 2, 1998, the VPSB released its
Order in the Company's pending rate case. The VPSB ordered the
Company's rates increased by 3.61 percent, increasing annual revenues by
$5.6 million. The Company had sought in its final submissions to the
VPSB an increase of $22 million in revenue to cover increased cost of
service.
Approximately $11 million of the reduction of the Company's revenue
request resulted primarily from the VPSB's modification of the Company's
calculation of rate base, the exclusion of future capital projects from
rate base, various cost of service reductions in areas of payroll and
operations and maintenance, and a reduction in the requested allowed
return on equity from 13 percent to 11.25 percent. More significantly,
the VPSB denied the recovery by the Company of $5.48 million in costs
related to its long-term Hydro-Quebec power contract. The decision
stated that the Company had been imprudent in locking-into the power
contract in August 1991 and that the contract power would not be used
and useful to utility customers to the extent that power costs, after
accounting for the imprudence disallowance, were in excess of current
estimates of market prices for power. Unless the Order is modified, the
Company must accrue its estimate of the loss related to these imprudence
and used and useful disallowances.
The Order discussed the VPSB's policies of disallowing the recovery
of imprudent expenditures and power contract purchases that it
determines not to be used and useful. However, the Order also stated
that the methodologies and measures used in this rate case were
provisional and applicable in the current proceeding only. The VPSB
went on to state that it will schedule subsequent proceedings to examine
the appropriate methodologies for measuring the effects of imprudence
and calculating the portion of the contract that is not used and useful.
If the VPSB were to apply the methodologies and measures used in the
Order (or similar methodologies and measures) to future power contract
costs, notwithstanding its statement that it will reexamine such
matters, the Company would be required under Statement of Financial
Accounting Standards No. 5 to record an expense of approximately $180
million based on the estimated future market price of power used by the
VPSB in its Order. However, the Company will not be able to estimate
the loss to be recorded, if any, until the reconsideration and appeal
processes and such subsequent proceedings are completed.
Furthermore, if the VPSB's ruling, that above-market Hydro-Quebec
power contract costs are not used and useful and should be shared
equally between ratepayers and shareholders, is not modified, then the
Company's rates may be set, effectively, on a basis other than its costs
to provide service. This would require the Company to discontinue the
application of Statement of Financial Accounting Standards No. 71,
resulting in the write-off of regulatory assets and liabilities with a
charge to earnings, as an extraordinary item. As of December 31, 1997,
the Company had approximately $15 million of net regulatory assets on
its balance sheet.
In addition to the Hydro-Quebec power contract disallowances
described above, the Order also requires the Company to create a
deferred credit for $9.1 million of payments received by the Company in
1997 pursuant to two arrangements with Hydro-Quebec that were designed
to decrease the costs of the contract power. The Order, contrary to the
VPSB's prior Accounting Order dated December 31, 1996, now requires the
Company to amortize this deferred credit over the remaining lives of the
related power contracts. Unless the current Order is modified, the
Company would be required to expense approximately $8.6 million
previously recognized in earnings related to the $9.1 million.
In response to the Order, the rating agencies that rate the
Company's fixed income securities have placed the Company's credit
ratings on their rating watch or rating outlook with negative or down
implications.
The Company is exploring all legal and regulatory remedies open to
it to challenge the VPSB decision, including requesting reconsideration
from the VPSB and a direct appeal to the Vermont Supreme Court. The
Company believes that the decisions set forth in the Order are inaccurate
factually and incorrect legally. The VPSB's ruling, if not changed,
would have a significant impact on the Company's reported financial
condition and 1998 results of operations and, depending on the outcome of
future proceedings to be conducted by the VPSB, could impact the
Company's credit ratings, dividend policy and financial viability.
On February 20, 1998, the Company and GMPG entered into a sales
agreement with VGS Propane, LLC, for the sale of all GMPG assets which
had a net book value of $8.1 million at December 31, 1997. This sale is
not expected to have a material impact on the Company's results of
operations.
7. Deferred Charges Not Included in Rate Base. The Company has
incurred and deferred approximately $3.1 million in costs for tree
trimming, storm damage and regulatory commission work. Currently, the
Company amortizes such costs based on historical averages and does not
receive a return on amounts deferred. Management expects to seek and
receive ratemaking treatment for these costs in future filings.
In early January 1998, Vermont and much of the Northeast
experienced a severe ice storm which resulted in approximately $2.5
million of storm damage costs which will also be deferred. Management
will seek and expects to receive a return on these costs as discussed
above.
8. Other Legal Matters. The Company is involved in legal and
administrative proceedings in the normal course of business and does not
believe that the ultimate outcome of these proceedings will have a
material effect on the financial position or the results of operations
of the Company.
J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT
Agreements executed in 1985 among the Company, VELCO and other
NEPOOL members and Hydro-Quebec provided for the construction of the
second phase (Phase II) of the interconnection between the New England
electric systems and that of Hydro-Quebec. Phase II expands the Phase I
facilities from 690 megawatts to 2,000 megawatts and provides for
transmission of Hydro-Quebec power from the Phase I terminal in northern
New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II
commenced in 1988 and was completed in late 1990. The Company is
entitled to 3.2 percent of the Phase II power-supply benefits. Total
construction costs for Phase II were approximately $487 million. The
New England participants, including the Company, have contracted to pay
monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs.
As a supporting participant, the Company must make support payments
under thirty-year agreements. These support agreements meet the capital
lease accounting requirements under SFAS 13. At December 31, 1997, the
present value of the Company's obligation is $8.3 million.
Projected future minimum payments under the Phase II support agreements
are as follows:
Year ending December 31,
1998 . . . . . . . . . . . $ 463,450
1999 . . . . . . . . . . . 463,450
2000 . . . . . . . . . . . 463,450
2001 . . . . . . . . . . . 463,450
2002 . . . . . . . . . . . 463,450
Total for 2003-2020 . . . 6,024,845
----------
$8,342,095
==========
The Phase II portion of the project is owned by New England Hydro-
Transmission Electric Company and New England Hydro-Transmission
Corporation, subsidiaries of New England Electric System, in which
certain of the Phase II participating utilities, including the Company,
own equity interests. The Company holds approximately 3.2 percent of
the equity of the corporations owning the Phase II facilities.
K. LONG-TERM POWER PURCHASES
1. Unit Purchases. Under long-term contracts with various electric
utilities in the region, the Company is purchasing certain percentages
of the electrical output of production plants constructed and financed
by those utilities. Such contracts obligate the Company to pay certain
minimum annual amounts representing the Company's proportionate share of
fixed costs, including debt service requirements (amounts necessary to
retire the principal of and to pay the interest on the portion of the
related long-term debt ascribed to the Company) whether or not the
production plants are operating. The cost of power obtained under such
long-term contracts, including payments required to be made when a
production plant is not operating, is reflected as "Power Supply
Expenses" in the accompanying Consolidated Statements of Income.
Information (including estimates for the Company's portion of
certain minimum costs and ascribed long-term debt) with regard to
significant purchased power contracts of this type in effect during 1997
follows:
Stony Vermont
Merrimack Brook Yankee
--------- ----- -------
(Dollars in thousands)
Plant capacity . . . . . . . . . . . 320.0 MW 352.0 MW 531.0 MW
Company's share of output . . . . . 8.9% 4.4% 17.7%
Contract period . . . . . . . . . . 1968-1998 (1) (2)
Company's annual share of:
Interest . . . . . . . . . . . . . $ 645 $ 221 $ 1,850
Other debt service . . . . . . . . 371 319 ---
Other capacity . . . . . . . . . . 1,939 387 25,328
------ ------ -------
Total annual capacity . . . . . . . $2,955 $ 927 $27,178
====== ====== =======
Company's share of long-term debt . $ 894 $4,241 $16,220
====== ====== =======
(1) Life of plant estimated to be 1981 - 2006.
(2) License for plant operations expires in 2012.
2. Hydro-Quebec System Power Purchases. Under various contracts,
the details of which are described in the table below, the Company
purchases capacity and associated energy produced by the Hydro-Quebec
system. Such contracts obligate the Company to pay certain fixed
capacity costs whether or not energy purchases above a minimum level
set forth in the contracts are made. Such minimum energy purchases must
be made whether or not other, less expensive energy sources might be
available. These contracts are intended to complement the other
components in the Company's power supply to achieve the most economic
power-supply mix reasonably available.
The Company's current purchases pursuant to the contract with
Hydro-Quebec entered into December 4, 1987 (the 1987 Contract) are as
follows: (1) Schedule B -- 68 megawatts of firm capacity and associated
energy to be delivered at the Highgate interconnection for twenty years
beginning in September 1995; and (2) Schedule C3 -- 46 megawatts of firm
capacity and associated energy to be delivered at interconnections to be
determined at any time for 20 years, which began in November 1995.
During 1994, the Company negotiated an arrangement with Hydro-
Quebec that reduces the cost impacts associated with the purchase of
Schedules B and C3 under the 1987 Contract, over the November 1995
through October 1999 period (the July 1994 Agreement). Under the July
1994 Agreement, the Company, in essence, will take delivery of the
amounts of energy as specified in the 1987 Contract, but the associated
fixed costs will be significantly reduced from those specified in the
1987 Contract.
As part of the July 1994 Agreement, the Company is obligated to
purchase $4 million (in 1994 dollars) worth of research and development
work from Hydro-Quebec over the four-year period, and made a $6.5
million (in 1994 dollars) cash payment to Hydro-Quebec in 1995. Hydro-
Quebec retains the right to curtail annual energy deliveries by 10
percent up to five times, over the 2000 to 2015 period, if documented
drought conditions exist in Quebec.
During the first year of the July 1994 Agreement (the period from
November 1995 through October 1996), the average cost per kilowatt-hour
of Schedules B and C3 combined was cut from 6.4 to 4.2 cents per
kilowatt-hour, a 34 percent (or $16 million) cost reduction. Over the
period from November 1996 through December 2000 and accounting for the
cash payments to Hydro-Quebec, the combined unit costs will be lowered
from 6.6 to 5.9 cents per kilowatthour, reducing unit costs by 10
percent and saving $20.7 million in nominal terms.
All of the Company's contracts with Hydro-Quebec call for the
delivery of system power and are not related to any particular
facilities in the Hydro-Quebec system. Consequently, there are no
identifiable debt-service charges associated with any particular Hydro-
Quebec facility that can be distinguished from the overall charges paid
under the contracts.
A summary of the Hydro-Quebec contracts, including the July 1994
Agreement, but excluding the January and November 1996 arrangements
(described below) including historic and projected charges for the years
indicated, follows:
The 1987 Contract
Schedule B Schedule C3
---------- -----------
(Dollars in thousands)
Capacity Acquired . . . . 68 MW 46 MW
Contract Period . . . . . 1995-2015 1995-2015
Minimum Energy Purchase
(annual load factor) . . 75% 75%
Annual Energy Charge . . $10,555 $7,188
(1997) (1997)
$14,999 $10,347
(1998-2015)* (1998-2015)*
Annual Capacity Charge . . $14,018 $1,913
(1997) (1997)
$17,135 $11,320
(1998-2015)* (1998-2015)*
Average Cost per KWH . . 6.1 cents 3.3 cents
(1997) ** (1997)**
7.0 cents 6.7 cents
(1998-2015)*** (1998-2015)***
* Estimated average.
** Excludes amortization of payments to Hydro-Quebec for the July 1994
Agreement.
***Estimated average in nominal dollars, levelized over the period
indicated. Includes amortization of payments to Hydro-Quebec for the
July 1994 Agreement.
Under an arrangement negotiated in January 1996 (the January 1996
Agreement), Hydro-Quebec provided a cash payment to the Company of $3.0
million in 1996 and provided an additional cash payment of $1.1 million
in 1997. In return, the Company has agreed, under certain
circumstances, to shift up to 40 megawatts of the Schedule C3 deliveries
from the NEPOOL/Hydro-Quebec interconnection facilities to alternate
transmission paths, using the freed-up transmission path for an
incremental purchase. The Company will purchase an annual minimum
quantity of energy for the Company's use or resale for the period of
September 1996 through June 2001. The purchase price will vary based
upon conditions in effect when the purchases are made, or on the resale
conditions at the time. Should the Company not satisfy its obligation
to purchase the quantity of energy in any calendar year, it must pay a
cancellation fee or rollover its residual purchase obligation into the
succeeding calendar year period. Although the level of benefits to the
Company will depend on various factors, the Company estimates that the
January 1996 Agreement will provide a minimum benefit of $1.8 million on
a net present value basis. During 1997, the Company purchased or sold
to others, 51.4 percent of the minimum purchase obligation for that
year. The Company will not rollover the balance of purchase obligations
into 1998, but instead will pay a cancellation fee.
Under an agreement executed on December 5, 1997, Hydro-Quebec
provided a cash payment of $8.0 million to the Company in 1997. In
return for this payment, the Company is providing Hydro-Quebec with the
choice of selecting one of two alternatives by April 1, 1998, described
below:
Alternative A: For the period commencing November 1, 1997 and effective
through the remaining term of the 1987 Contract, which expires in 2015,
Hydro-Quebec can exercise an option to purchase up to 105,000 MWh on an
annual basis, at energy prices established in accordance with the 1987
Contract, for an amount of energy equivalent to the Company's firm
capacity entitlements in the 1987 Contract. The cumulative amount of
energy purchased over the remaining term of the 1987 Contract may not
exceed 1,900,000 MWh. Hydro-Quebec may not exercise its annual rights
to purchase power in the amounts specified under an arrangement made in
November 1996 during those years in which Hydro-Quebec exercises its
rights to curtail energy deliveries in accordance with the July 1994
Agreement.
Alternative B: For the period commencing November 1, 1997 and effective
through the remaining term of the 1987 Contract, Hydro-Quebec can
exercise an option to purchase up to 52,500 MWh on an annual basis, at
energy prices established in accordance with the 1987 Contract, for an
amount of energy equivalent to the Company's firm capacity entitlements
in the 1987 Contract. The cumulative amount of energy purchased over
the remaining term of the 1987 Contract shall not exceed 950,000 MWh.
Unlike Alternative A, Hydro-Quebec's option to curtail energy deliveries
pursuant to the July 1994 Agreement can be exercised in addition to the
purchase option under Alternative B. Finally, for the period commencing
January 1, 1998 and effective though the remaining term of the 1987
Contract under Alternative B, Hydro-Quebec can exercise an option on an
annual basis to purchase up to 600,000 MWh at the 1987 Contract energy
price. Hydro-Quebec can purchase no more than 200,000 MWh in any given
year. Under modifications agreed to by Hydro-Quebec and the Company,
Hydro-Quebec has until April 1, 1998 to elect either Alternative A or B.
Consistent with an accounting order from the VPSB issued on
December 31, 1996, the $8.0 million payment was recognized in income in
1997. However, it was necessary to change the accounting treatment
subsequently based on an order issued by the VPSB in March 1998,
resulting in the amortization of the $8 million over the life of the
contract. The Company intends to appeal or request reconsideration of
this decision. (See Note I of the Notes to Consolidated Financial
Statements.)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and
capitalization data of Green Mountain Power Corporation (a Vermont
corporation) as of December 31, 1997 and 1996, and the related
consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1997. These financial statements
are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
As discussed in Note I.6, on March 2, 1998, the Company received a rate
order from the Vermont Public Service Board (the VPSB) allowing for a
$5.6 million increase in annual revenue in response to the Company's
request for a $22 million increase in annual revenue. The Company is
exploring all legal and regulatory remedies open to it to challenge the
correctness of the VPSB's decision. The VPSB's ruling, if not changed,
would have a significant adverse impact on the company's reported
financial condition and 1998 results of operations and, depending on
future proceedings to be conducted by the VPSB, could impact the
Company's financial viability.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Green Mountain Power Corporation as of December 31, 1997 and 1996, and
the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 1997, in conformity
with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 2, 1998 (except with respect to the matter discussed in Note
I.6, as to which the date is March 2, 1998)
Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1997, 1996 and 1995
Additions
Balance at ------------------------------- Balance at
Beginning of Charged to Charged to End of
Description Period Cost & Expenses Other Accounts Deductions Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Injuries and Damages
1997................................. $237,892 $427,546 $ -- $1,653 $663,785
1996................................. $103,301 $572,000 $ -- $437,409 $237,892
1995................................. $513,720 $38,000 $ -- $448,419 $103,301
Bad Debt Reserve (2)
1997................................. $498,024 $637,010 $173,899 (1) $815,528 $493,405
1996................................. $417,684 $677,272 $72,344 (1) $669,276 $498,024
1995................................. $402,923 $371,564 $48,696 (1) $405,499 $417,684
(1) Represents collection of accounts previously written off.
(2) Includes non-utility bad debt reserve.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEMS 10, 11, 12 & 13
Certain information regarding executive officers called for by Item
10, "Directors and Executive Officers of the Registrant," is furnished
under the caption, "Executive Officers" in Item 1 of Part I of this
Report. The other information called for by Item 10, as well as that
called for by Items 11, 12, and 13, "Executive Compensation," "Security
Ownership of Certain Beneficial Owners and Management" and "Certain
Relationships and Related Transactions," will be set forth under the
captions "Election of Directors," "Board Compensation, Other
Relationship, Meetings and Committees," "Section 16(a) Beneficial
Ownership Reporting Compliance," "Executive Compensation," "Compensation
Committee Report on Executive Compensation," "Performance Graphs,"
"Pension Plan Information" and "Securities Ownership of Certain
Beneficial Owners and Management" in the Company's definitive proxy
statement relating to its annual meeting of stockholders to be held on
May 15, 1997. Such information is incorporated herein by reference.
Such proxy statement pertains to the election of directors and other
matters. Definitive proxy materials will be filed with the Securities
and Exchange Commission pursuant to Regulation 14A in April 1997.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
A report on Form 8-K was filed on March 12, 1998 setting forth the
financial and accounting implications for the Company resulting from the
Vermont Public Service Board's Order in the Company's rate case.
Filed
Herewith
On Page
Item 14(a)(1). The financial statements and financial 42
statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.
ITEM 14 (a) (3). EXHIBITS
Incorporated by Reference from
Exhibit SEC Docket or
Number Exhibit Page Filed Herewith
- ------- ----------------------------------------------- ------- -------------------
3-a Restated Articles of Association, as certified 3-a Form 10-K 1993
June 6, 1991. (1-8291)
3-a-1 Amendment to 3-a above, dated as of May 20, 1993. 3-a-1 Form 10-K 1993
(1-8291)
3-a-2 Amendment to 3-a above, dated as of October 11, 1996. 3-a-2 Form 10-Q Sept. 1996
(1-8291)
3-b By-laws of the Company, as amended 3-b Form 10-K 1996
February 10, 1997. (1-8291)
4-b-1 Indenture of First Mortgage and Deed of Trust 4-b 2-27300
dated as of February 1, 1955.
4-b-2 First Supplemental Indenture dated as of 4-b-2 2-75293
April 1, 1961.
4-b-3 Second Supplemental Indenture dated as of 4-b-3 2-75293
January 1, 1966.
4-b-4 Third Supplemental Indenture dated as of 4-b-4 2-75293
July 1, 1968.
4-b-5 Fourth Supplemental Indenture dated as of 4-b-5 2-75293
October 1, 1969.
4-b-6 Fifth Supplemental Indenture dated as of 4-b-6 2-75293
December 1, 1973.
4-b-7 Seventh Supplemental Indenture dated as 4-a-7 2-99643
August 1, 1976.
4-b-8 Eighth Supplemental Indenture dated as of 4-a-8 2-99643
December 1, 1979.
4-b-9 Ninth Supplemental Indenture dated as of 4-b-9 2-99643
July 15, 1985.
4-b-10 Tenth Supplemental Indenture dated as of 4-b-10 Form 10-K 1989
June 15, 1989. (1-8291)
4-b-11 Eleventh Supplemental Indenture dated as of 4-b-11 Form 10-Q Sept
September 1, 1990. 1990 (1-8291)
4-b-12 Twelfth Supplemental Indentrue dated as of 4-b-12 Form 10-K 1991
March 1, 1992. (1-8291)
4-b-13 Thirteenth Supplemental Indenture dated as of 4-b-13 Form 10-K 1991
March 1, 1992. (1-8291)
4-b-14 Fourteenth Supplemental Indenture dated as of 4-b-14 Form 10-K 1993
November 1, 1993. (1-8291)
4-b-15 Fifteenth Supplemental Indenture dated as of 4-b-15 Form 10-K 1993
November 1, 1993. (1-8291)
4-b-16 Sixteenth Supplemental Indenture dated as of 4-b-16 Form 10-K 1995
December 1, 1995. (1-8291)
4-b-17 Revised form of Indenture as filed as an Exhibit 4-b-17 Form 10-Q Sept. 1995
to Registration Statement No. 33-59383. (1-8291)
*4-b-18 Credit Agreement by and among Green Mountain Power 4-b-18
The Bank of Nova Scotia, State Street Bank and
Trust Company, Fleet National Bank, and Fleet
National Bank, as Agent
10-a Form of Insurance Policy issued by Pacific 10-a 33-8146
Insurance Company, with respect to
indemnification of Directors and Officers.
10-b-1 Firm Power Contract dated September 16, 1958, 13-b 2-27300
between the Company and the State of Vermont
and supplements thereto dated September 19,
1958; November 15, 1958; October 1, 1960 and
February 1, 1964.
10-b-2 Power Contract, dated February 1, 1968, between 13-d 2-34346
the Company and Vermont Yankee Nuclear Power
Corporation.
10-b-3 Amendment, dated June 1, 1972, to Power Contract 13-f-1 2-49697
between the Company and Vermont Yankee Nuclear
Power Corporation.
10-b-3 Amendment, dated April 15, 1983, to Power 10-b-3(a) 33-8164
(a) Contract between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-3 Additional Power Contract, dated 10-b-3(b) 33-8164
(b) February 1, 1984,between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-4 Capital Funds Agreement, dated February 1, 13-e 2-34346
1968, between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-5 Amendment, dated March 12, 1968, to Capital 13-f 2-34346
Funds Agreement between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-6 Guarantee Agreement, dated November 5, 1981, 10-b-6 2-75293
of the Company for its proportionate share
of the obligations of Vermont Yankee Nuclear
Power Corporation under a $40 million loan
arrangement.
10-b-7 Three-Party Power Agreement among the Company, 13-i 2-49697
VELCO and Central Vermont Public Service
Corporation dated November 21, 1969.
10-b-8 Amendment to Exhibit 10-b-7, dated June 1, 1981. 10-b-8 2-75293
10-b-9 Three-Party Transmission Agreement among the 13-j 2-49697
Company, VELCO and Central Vermont Public
Service Corporation, dated November 21, 1969.
10-b-10 Amendment to Exhibit 10-b-9, dated June 1, 1981. 10-b-10 2-75293
10-b-12 Unit Purchase Contract dated February 10, 1968, 13-h 2-34346
between the Company and Vermont Electric
Power Company, Inc., for purchase of
"Merrimack" power from Public Service
Company of New Hampshire.
10-b-14 Agreement with Central Maine Power Company et 5.16 2-52900
al, to enter into joint ownership of Wyman
plant, dated November 1, 1974.
10-b-15 New England Power Pool Agreement as amended to 4.8 2-55385
November 1, 1975.
10-b-16 Bulk Power Transmission Contract between the 13-v 2-49697
Company and VELCO dated June 1, 1968.
10-b-17 Amendment to Exhibit 10-b-16, dated June 1, 1970. 13-v-i 2-49697
10-b-20 Power Sales Agreement, dated August 2, 1976, as 10-b-20 33-8164
amended October 1, 1977, and related
Transmission Agreement, with the Massachusetts
Municipal Wholesale Electric Company.
10-b-21 Agreement dated October 1, 1977, for Joint 10-b-21 33-8164
Ownership, Construction and Operation of the
MMWEC Phase I Intermediate Units, dated
October 1, 1977.
10-b-28 Contract dated February 1, 1980, providing for 10-b-28 33-8164
the sale of firm power and energy by the Power
Authority of the State of New York to the
Vermont Public Service Board.
10-b-30 Bulk Power Purchase Contract dated April 7, 10-b-32 2-75293
1976, between VELCO and the Company.
10-b-33 Agreement amending New England Power Pool 10-b-33 33-8164
Agreement dated as of December 1, 1981,
providing for use of transmission inter-
connection between New England and
Hydro-Quebec.
10-b-34 Phase I Transmission Line Support Agreement 10-b-34 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
VETCO and participating New England utilities
for construction, use and support of Vermont
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-35 Phase I Terminal Facility Support Agreement 10-b-35 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
New England Electric Transmission Corporation
and participating New England utilities for
construction, use and support of New Hampshire
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-36 Agreement with respect to use of Quebec 10-b-36 33-8164
Interconnection dated as of December 1, 1981,
among participating New England utilities
for use of transmission interconnection
between New England and Hydro-Quebec.
10-b-39 Vermont Participation Agreement for Quebec 10-b-39 33-8164
Interconnection dated as of July 15, 1982,
between VELCO and participating Vermont
utilities for allocation of VELCO's rights
and obligations as a participating New
England utility in the transmission inter-
connection between New England and Hydro-Quebec.
10-b-40 Vermont Electric Transmission Company, Inc. 10-b-40 33-8164
Capital Funds Agreement dated as of July 15,
1982, between VETCO and VELCO for VELCO to
provide capital to VETCO for construction of
the Vermont facilities of the transmission
inter-connection between New England and
Hydro-Quebec.
10-b-41 VETCO Capital Funds Support Agreement dated as 10-b-41 33-8164
of July 15, 1982, between VELCO and partici-
pating Vermont utilities for allocation
of VELCO's obligation to VETCO under the
Capital Funds Agreement.
10-b-42 Energy Banking Agreement dated March 21, 1983, 10-b-42 33-8164
among Hydro-Quebec, VELCO, NEET and parti-
cipating New England utilities acting by and
through the NEPOOL Management Committee for
terms of energy banking between participating
New England utilities and Hydro-Quebec.
10-b-43 Interconnection Agreement dated March 21, 1983, 10-b-43 33-8164
between Hydro-Quebec and participating New
England utilities acting by and through the
NEPOOL Management Committee for terms and
conditions of energy transmission between
New England and Hydro-Quebec.
10-b-44 Energy Contract dated March 21, 1983, between 10-b-44 33-8164
Hydro-Quebec and participating New England
utilities acting by and through the NEPOOL
Management Committee for purchase of
surplus energy from Hydro-Quebec.
10-b-45 Firm-Power Agreement dated as of October 5, 1982, 10-b-45 33-8164
between Ontario Hydro and Vermont Department
of Public Service.
10-b-46 Sales Agreement, dated January 20, 1983, between 10-b-46 33-8164
Central Maine Power Company and the Company
for excess power.
10-b-48 Sales Agreement, dated February 1, 1983, 10-b-48 33-8164
between Niagara Mohawk and Vermont Electric
Power Company for purchase of energy.
10-b-50 Agreement for Joint Ownership, Construction and 10-b-50 33-8164
Operation of the Highgate Transmission
Interconnection, dated August 1, 1984,
between certain electric distribution
companies, including the Company.
10-b-51 Highgate Operating and Management Agreement, 10-b-51 33-8164
dated as of August 1, 1984, among VELCO and
Vermont electric-utility companies, including
the Company.
10-b-52 Allocation Contract for Hydro-Quebec Firm Power 10-b-52 33-8164
dated July 25, 1984, between the State of
Vermont and various Vermont electric utilities,
including the Company.
10-b-53 Highgate Transmission Agreement dated as of 10-b-53 33-8164
August 1, 1984, between the Owners of the
Project and various Vermont electric
distribution companies.
10-b-54 Lease and Sublease Agreement dated June 1, 1984, 10-b-54 33-8164
between Burlington Associates and the Company.
10-b-55 Ground Lease Agreement dated June 1, 1984, 10-b-55 33-8164
between GMP Real Estate Corporation and
Burlington Associates.
10-b-56 Assignment of Lease and Agreement, dated June 1, 10-b-56 33-8164
1984, from Burlington Associates to Teachers
Insurance and Annuity Association of America.
10-b-57 Mortgage dated June 1, 1984, from GMP Real Estate 10-b-57 33-8164
Corporation, Mortgagor, to Teachers Insurance
and Annuity Association of America, Mortgagee.
10-b-58 Lease and Operating Agreement dated June 28,1985, 10-b-58 33-8164
between the State of Vermont and the Company.
10-b-59 Service Contract dated June 28, 1985, between the 10-b-59 33-8164
State of Vermont and the Company.
10-b-61 Agreements entered in connection with Phase II 10-b-61 33-8164
of the NEPOOL/Hydro-Quebec + 450 KV HVDC
Transmission Interconnection.
10-b-62 Agreement between UNITIL Power Corp. and the 10-b-62 33-8164
Company to sell 23 MW capacity and energy from
Stony Brook Intermediate Combined Cycle Unit.
10-b-63 Sales Agreement dated as of June 20, 1986, 10-b-63 33-8164
between the Company and UNITIL Power Corp.
for sale of system power.
10-b-64 Sales Agreement dated as of June 20, 1986, 10-b-64 33-8164
between the Company and Fitchburg Gas and
Electric Light Company for sale of 10 MW
capacity and energy from the Vermont Yankee
plant.
10-b-65 Sales Agreement dated September 18, 1985, 10-b-65 Form 10-K 1991
between the Company and Fitchburg Gas and (1-8291)
Electric Light Company for the sale of
system power.
10-b-66 Sales Agreement dated January 1, 1987, between 10-b-66 Form 10-K 1991
the Company and Bozrah Light and Power (1-8291)
Company for sale of power.
10-b-67 Sales Agreement dated August 31, 1987, amending 10-b-67 Form 10-K 1992
the agreement dated June 20, 1986, between (1-8291)
the Company and UNITIL Power Corp. for sale
of system power.
10-b-68 Firm Power and Energy Contract dated December 4, 10-b-68 Form 10-K 1992
1987, between Hydro-Quebec and participating (1-8291)
Vermont utilities, including the Company, for
the purchase of firm power for up to thirty years.
10-b-69 Firm Power Agreement dated as of October 26, 1987, 10-b-69 Form 10-K 1992
between Ontario Hydro and Vermont Department of (1-8291)
Public Service.
10-b-70 Firm Power and Energy Contract dated as of 10-b-70 Form 10-K 1992
February 23, 1987, between the Vermont Joint (1-8291)
Owners of the Highgate facilities and Hydro-
Quebec for up to 50 MW of capacity.
10-b-70 Amendment to 10-b-70. 10-b-70(a) Form 10-K 1992
(a) (1-8291)
10-b-71 Interconnection Agreement dated as of 10-b-71 Form 10-K 1992
February 23, 1987, between the Vermont Joint (1-8291)
Owners of the Highgate facilities and Hydro-Quebec.
10-b-72 Participation Agreement dated as of April 1, 1988, 10-b-72 Form 10-Q
between Hydro-Quebec and participating Vermont June 1988
utilities, including the Company, implementing (1-8291)
the purchase of firm power for up to 30 years
under the Firm Power and Energy Contract dated
December 4, 1987 (previously filed with the
Company's Annual Report on Form 10-K for 1987,
Exhibit Number 10-b-68).
10-b-72 Restatement of the Participation Agreement filed 10-b-72(a) Form 10-K 1988
(a) as Exhibit 10-b-72 on Form 10-Q for June 1988. (1-8291)
10-b-73 Agreement dated as of May 1, 1988, between 10-b-73 Form 10-Q
Rochester Gas and Electric Corporation and the Sept. 1988
Company,implementing the Company's purchase of up (1-8291)
to 50 MW of electric capacity and associated energy.
10-b-74 Agreement dated as of November 1, 1988, between 10-b-74 Form 10-Q for
the Company and Fitchburg Gas and Electric Light Sept. 1988
Company,for sale of electric capacity and (1-8291)
associated energy.
10-b-74 Amendment to Exhibit 10-b-74. 10-b-74(a) Form 10-Q
(a) Sept 1989
(1-8291)
10-b-75 Allocation Agreement dated as of March 25, 1988, 10-b-75 Form 10-Q
between Ontario Hydro and the State of Vermont, Sept. 1988
for firm power and associated energy from (1-8291)
Ontario Hydro.
10-b-77 Firm Power and Energy Contract dated December 29, 10-b-77 Form 10-K 1988
1988, between Hydro-Quebec and participating (1-8291)
Vermont utilities, including the Company, for the
purchase of up to 54 MW of firm power and energy.
10-b-78 Transmission Agreement dated December 23, 1988, 10-b-78 Form 10-K 1988
between the Company and Niagara Mohawk Power (1-8291)
Corporation (Niagara Mohawk), for Niagara
Mohawk to provide electric transmission to
the Company from RochesterGas and Electric
and Central Hudson Gas and Electric.
10-b-79 Lease Agreement dated November 1, 1988, between 10-b-79 Form 10-K 1988
the Company and International Business Machines (1-8291)
Corporation (IBM) for the lease to IBM of the
gas turbines and associated facilities located
on land adjacent to IBM's Essex Junction,
Vermont, plant.
10-b-80 Sales Agreement dated January 1, 1989, between 10-b-80 Form 10-K 1988
the Company and Public Service of New Hampshire (1-8291)
(PSNH)for PSNH to purchase electric capacity
from the Company.
10-b-81 Sales Agreement dated May 24, 1989, between 10-b-81 Form 10-Q
the Town of Hardwick, Hardwick Electric Department June 1989
and the Company for the Company to purchase (1-8291)
all of the output of Hardwick's generation and
transmission sources and to provide Hardwick
with all-requirements energy and capacity except
for that provided by the Vermont Department of
Public Service or Federal Preference Power.
10-b-82 Sales Agreement dated July 14, 1989, between 10-b-82 Form 10-Q
Northfield Electric Department and the Company June 1989
for the Company to purchase all of the output (1-8291)
of Northfield's generation and transmission
sources and to provide Northfield with all-
requirements energy and capacity except for
that provided by the Vermont Department of
Public Service or Federal Preference Power.
10-b-83 Power Purchase and Operating Agreement dated as 10-b-83 Form 10-Q
of April 20, 1990, between CoGen Lime Rock, June 1990
Inc., and the Company for the production of (1-8291)
energy to meet customer needs.
10-b-84 Capacity, Transmission and Energy Service 10-b-84 Form 10-K 1992
Agreement dated December 23, 1992, between (1-8291)
the Company and Connecticut Light and Power
Company (CL&P) for CL&P to supply power to
Bozrah Light and Power Company.
Management contracts or compensatory plans or arrangements
required to be filed as exhibits to this form 10-K
pursuant to Item 14(c).
10-c Contract dated as of October 15, 1983, between 10-c 33-8164
the Company and Thomas V. O'Connor, Jr.
10-c-1 Amendment dated as of March 31, 1988, to an 10-c-1 Form 10-Q
agreement between the Company and March 1988
Thomas V. O'Connor, Jr (1-8291)
10-d-1b Green Mountain Power Corporation Second Amended 10-d-1b Form 10-K 1993
and Restated Deferred Compensation Plan for (1-8291)
Directors.
10-d-1c Green Mountain Power Corporation Second Amended 10-d-1c Form 10-K 1993
and Restated Deferred Compensation Plan for (1-8291)
Officers.
10-d-1d Amendment No. 93-1 to the Amended and Restated 10-d-1d Form 10-K 1993
Deferred Compensation Plan for Officers. (1-8291)
10-d-1e Amendment No. 94-1 to the Amended and Restated 10-d-1e Form 10-Q
Deferred Compensation Plan for Officers. June 1994
(1-8291)
10-d-2 Green Mountain Power Corporation Medical Expense 10-d-2 Form 10-K 1991
Reimbursement Plan. (1-8291)
10-d-4 Green Mountain Power Corporation Officer 10-d-4 Form 10-K 1991
Insurance Plan. (1-8291)
10-d-4a Green Mountain Power Corporation Officers' 10-d-4a Form 10-K 1990
Insurance Plan as amended. (1-8291)
10-d-5a Severance Agreements with D. G. Hyde, E. M. Norse, 10-d-5a Form 10-K 1990
C. L. Dutton, S. C. Terry and T.C. Boucher. (1-8291)
10-d-6 Severance Agreements with W. S. Oakes, 10-d-6 Form 10-K 1988
and J. H. Winer. (1-8291)
10-d-6a Restatement of 10-d-6 above. 10-d-6a Form 10-K 1990
(1-8291)
10-d-7 Severance Agreement with K. K. O'Neill. 10-d-7 Form 10-K 1990
(1-8291)
10-d-8 Green Mountain Power Corporation Officers' 10-d-8 Form 10-K 1990
Supplemental Retirement Plan. (1-8291)
10-d-9 Severance Agreement with C. T. Myotte. 10-d-9 Form 10-Q June
1991 (1-8291)
10-d-10 Severance Agreement with J. J. Lampron. 10-d-10 Form 10-K 1991
(1-8291)
10-d-13 Severance Agreement with M. H. Lipson. 10-d-13 Form 10-K 1994
(1-8291)
10-d-14 Severance Agreement with D. G. Whitmore. 10-d-14 Form 10-K 1994
(1-8291)
10-d-15a Green Mountain Power Corporation Compensation Program 10-d-15a Form 10-Q
for Officers and Key Management Personnel as amended Sept. 1995
August 8, 1995 (1-8291)
*10-d-15b Green Mountain Power Corporation Compensation Program 10-d-15b
for Officers and Key Management Personnel as amended
August 4, 1997
10-d-16 Severance Agreement with R. C. Young 10-d-16 Form 10-Q March
1995 (1-8291)
10-d-17 Severance Agreement with P. H. Zamore 10-d-17 Form 10-Q March
1995 (1-8291)
10-d-18 Severance Agreement with R. B. Hieber 10-d-18 Form 10-K 1996
(1-8291)
10-d-19 Severance Agreement with R. J. Griffin 10-d-19 Form 10-K 1996
(1-8291)
10-d-20 Severance Agreement with K. W. Hartley 10-d-20 Form 10-K 1996
(1-8291)
21 Subsidiaries of the Registrant 21 Form 10-K 1996
(1-8291)
*23-a-1 Consent of Arthur Andersen LLP
*24 Power of Attorney
*27 Financial Data Schedule
____________________
* Filed herewith
ITEM 14(b)
A report on Form 8-K was filed on March 12, 1998 setting forth the
financial and accounting implications for the Company resulting from the
Vermont Public Service Board's Order in the Company's rate case.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
GREEN MOUNTAIN POWER CORPORATION
By: /s/ Christopher L. Dutton
_________________________
Christopher L. Dutton, President
and Chief Executive Officer
Date: March 26, 1998
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates
indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Christopher L. Dutton President and Director March 26, 1998
Christopher L. Dutton (Principal Executive Officer)
/s/ Edwin M. Norse Vice President, Treasurer and March 26, 1998
Edwin M. Norse Chief Financial Officer (Principal
Financial Officer)
/s/ Robert J. Griffin Controller March 26, 1998
Robert J. Griffin (Principal Accounting Officer)
*Thomas P. Salmon Chairman of the Board
*Nordahl L. Brue )
*William H. Bruett )
*Merrill O. Burns )
*Lorraine E. Chickering )
*John V. Cleary )
Directors
*Richard I. Fricke )
*Euclid A. Irving )
*Martin L. Johnson )
*Ruth W. Page )
*By: /s/ Christopher L. Dutton_ March 26, 1998
Christopher L. Dutton
(Attorney - in - Fact)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements of Green Mountain Power
Corporation included in this Form 10-K and have issued our report
thereon dated February 2, 1998. Our audit was made for the purpose of
forming an opinion on the basic financial statements taken as a whole.
The schedule listed in the index on page 42 of this Form 10-K is the
responsibility of the Company's management and is presented for purposes
of complying with the Securities and Exchange Commission's rules and is
not part of the basic consolidated financial statements. This schedule
has been subjected to the auditing procedures applied in the audit of
the basic consolidated financial statements, and in our opinion, fairly
states, in all material respects, the financial data required to be set
forth therein in relation to the basic consolidated financial statements
taken as a whole.
Boston, Massachusetts
February 2, 1998 /s/ Arthur Andersen LLP