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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
_X_ Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
___ Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from ________________ to __________________
For the fiscal year ended December 31, 1996
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 14, 1997, was $120,638,465.00
based on the closing price for the Common Stock on the New York Stock
Exchange as reported by The Wall Street Journal.
The number of shares of Common Stock outstanding on March 14, 1997,
was 5,052,920.
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 15, 1997, 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 82,500 customers. The Company was
incorporated under the laws of the State of Vermont on April 7, 1893.
For the year ended December 31, 1996, the Company's sources of
revenue were derived as follows: 33.3% from residential customers,
31.0% from small commercial and industrial customers, 20.1% from large
commercial and industrial customers, 11.3% from sales to other
utilities, and 4.3% from other sources. For the same period, the
Company's energy resources for retail and requirements wholesale sales
were obtained as follows: 50.4% from hydroelectric sources (7.4%
Company-owned, 0.1% New York Power Authority (NYPA), 39.6% Hydro-Quebec
and 3.3% small power producers), 27.9% from nuclear generating sources
(the Vermont Yankee plant described below), 7.4% from coal sources, 3.7%
from wood, 1.1% from natural gas, and 1.1% from oil. The remaining 8.4%
was purchased on a short-term basis from other utilities and through the
New England Power Pool (NEPOOL). In 1996, the Company purchased 96.7%
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, 1996, 1995 and 1994, electric
energy sales to International Business Machines Corporation (IBM), the
Company's largest customer, accounted for 13.2%, 12.9% and 13.7%,
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 344 employees, exclusive of temporary employees, as
of December 31, 1996. In addition, subsidiaries of the Company had 45
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 1996 - 313.0 MW - occurred on December 31, 1996. 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
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
Net System Capability During Peak Month (MW)
Hydro (1)............................................ 193.8 152.1 179.0 174.9 160.6
Lease transmissions.................................. 0.6 0.3 2.1 3.9 5.7
Nuclear (1).......................................... 95.7 81.9 107.2 109.5 109.6
Conventional steam................................... 52.9 77.8 67.1 92.6 95.0
Internal combustion.................................. 60.7 62.0 60.2 71.0 47.4
Combined cycle....................................... 22.1 22.0 22.6 22.8 21.6
---------- ---------- ---------- ---------- ----------
Total capability (MW).............................. 425.8 396.1 438.2 474.7 439.9
Net system peak...................................... 313.0 297.1 308.3 307.3 314.4
---------- ---------- ---------- ---------- ----------
Reserve (MW)......................................... 112.8 99.0 129.9 167.4 125.5
========== ========== ========== ========== ==========
Reserve % of peak.................................... 36.0% 33.3% 42.1% 54.5% 39.9%
Net Production (MWH)
Hydro (1)............................................1,192,881 1,043,617 742,088 751,078 641,525
Lease transmissions.................................. -- -- -- 15,425 58,374
Nuclear (1).......................................... 680,613 682,814 763,690 598,245 665,034
Conventional steam................................... 705,331 673,982 651,105 748,626 762,451
Internal combustion.................................. 2,674 6,646 3,532 2,849 1,504
Combined cycle....................................... 51,162 92,723 37,808 40,966 60,138
---------- ---------- ---------- ---------- ----------
Total production...................................2,632,661 2,499,782 2,198,223 2,157,189 2,189,026
Less non-requirements sales to other utilities....... 663,175 582,942 328,794 271,224 273,087
---------- ---------- ---------- ---------- ----------
Production for requirements sales....................1,969,486 1,916,840 1,869,429 1,885,965 1,915,939
Less requirements sales & lease transmissions (MWH)..1,814,371 1,760,830 1,730,497 1,749,454 1,794,986
---------- ---------- ---------- ---------- ----------
Losses and company use (MWH)......................... 155,115 156,010 138,932 136,511 120,953
========== ========== ========== ========== ==========
Losses as a percentage of total production............. 5.89% 6.24% 6.32% 6.33% 5.53%
System load factor (2)................................. 69.7% 71.2% 67.7% 68.7% 68.5%
Sales and Lease Transmissions (MWH)
Residential - GMP.................................... 557,726 549,296 564,635 541,579 505,234
Lease transmissons................................... -- -- -- 15,425 58,374
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 557,726 549,296 564,635 557,004 563,608
Commercial & industrial - small...................... 630,839 608,688 604,686 593,560 582,594
Commercial & industrial - large...................... 584,249 556,278 521,400 529,372 539,665
Other................................................ 2,898 8,855 1,146 8,868 6,312
---------- ---------- ---------- ---------- ----------
Total retail sales and lease transmissions.........1,775,712 1,723,117 1,691,867 1,688,804 1,692,179
Sales to municipals and cooperatives and
other requirements sales........................... 38,659 37,713 38,630 60,650 102,807
---------- ---------- ---------- ---------- ----------
Total requirements sales...........................1,814,371 1,760,830 1,730,497 1,749,454 1,794,986
Other sales for resale............................... 663,175 582,942 328,794 271,224 273,087
---------- ---------- ---------- ---------- ----------
Total sales and lease transmissions................2,477,546 2,343,772 2,059,291 2,020,678 2,068,073
========== ========== ========== ========== ==========
Average Number of Electric Customers
Residential.......................................... 70,198 69,659 68,811 67,994 67,201
Commercial and industrial - small.................... 11,828 11,712 11,611 11,447 11,245
Commercial and industrial - large.................... 25 24 24 25 24
Other................................................ 75 76 76 74 73
---------- ---------- ---------- ---------- ----------
Total.............................................. 82,126 81,471 80,522 79,540 78,543
========== ========== ========== ========== ==========
Average Revenue per KWH (Cents)
Residential including lease revenues................. 10.87 10.09 9.03 8.94 8.44
Lease charges........................................ -- -- -- 0.06 0.41
---------- ---------- ---------- ---------- ----------
Total Residential.................................. 10.87 10.09 9.03 9.00 8.85
Commercial and industrial - small.................... 8.96 8.42 8.00 7.97 7.82
Commercial and industrial - large.................... 6.28 5.86 6.02 5.96 5.89
Total retail including lease revenues................ 8.72 8.36 7.96 7.86 7.56
Average Use and Revenue Per Residential Customer
Kilowatt hours including lease transmissions......... 7,945 7,885 8,206 8,192 8,387
Revenues including lease revenues.................... $863 $796 $741 $733 $707
(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 0.9% of
operating revenues for 1996.
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
23,350 MWh and peak requirements by approximately 6EMW. Revenues in
1996 from Northfield were $1,389,972.
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 1996.
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, 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 of Vermont. The Plan
includes an overview of statewide growth and development as they relate
to future requirements for electrical energy; an assessment of available
energy resources; and estimates of 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
In early 1996, the Company entered into an agreement with Hydro-
Quebec which enabled the Company to settle its rate case filed in
September 1995. The settlement provided for an overall increase in
retail rates of 5.25%, effective June 1, 1996, and a target return on
equity for utility operations of 11.25%. 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."
In a recent order related to electric industry restructuring issued
by the VPSB on December 31, 1996 (Final Order), the VPSB requested
utilities to submit their initial utility restructuring plans to the
VPSB by June 30, 1997. These plans will set forth the utility's plan
for the structural changes required to implement functional separation
or operational unbundling of the regulated transmission and distribution
operations from the unregulated generation and retail competitive
services operations. These filings will include plans for providing
unbundled service rates and other elements to facilitate separation of
regulated and unregulated activities. The Company is currently in the
process of preparing its restructuring plan, including unbundled service
tariffs, for submission to the VPSB in accordance with its Final Order.
The Company's final restructuring plans will not be formulated until
definitive restructuring legislation has been adopted by the Vermont
General Assembly and such plans will be subject to approval by the VPSB.
POWER RESOURCES
The Company generated, purchased or transmitted 1,924,811.9 MWh of
energy for retail and requirements wholesale customers for the twelve
months ended December 31, 1996. The corresponding maximum one-hour
integrated demand during that period was 313.0 MW on December 31, 1996.
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 12/31/96 (a) of Annual Peak
___________________ ___________________
MWh %(b) KW %(b)
WHOLLY OWNED PLANTS
Hydro 150,586.2 7.4 35,300 8.3
Diesel and Gas Turbine 5,530.0 0.3 63,660 15.0
JOINTLY OWNED PLANTS
Wyman #4 5,941.5 0.3 7,030 1.7
Stony Brook I 10,291.7 0.5 7,990 1.9
McNeil 15,252.9 0.8 6,470 1.5
OWNED IN ASSOCIATION W/OTHERS
Vermont Yankee Nuclear 565,383.9 27.9 95,680 22.5
NYPA LEASE TRANSMISSIONS
State of Vermont (NYPA) 1,520.0 0.1 620 0.1
LONG-TERM PURCHASES
Hydro-Quebec 807,030.7 39.6 140,680 33.0
Merrimack #2 150,913.1 7.4 31,820 7.5
Stony Brook I 21,907.3 1.1 14,150 3.3
Small Power Producers 125,552.2 6.2 24,630 5.8
SHORT-TERM PURCHASES 167,343.5 8.4 0.0 0.0
___________ ____ _______ _____
Less System Sales Energy (102,441.1) (2,260) (0.6)
TOTAL 1,924,811.9 100.00 425,770 100.00
=========== ====== ======= ======
NOTE: (a) Excludes losses on off-system purchases, totaling 59,332
MWh.
(b) Percentages may be adjusted to total 100%.
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, a decision was made to retire one
of these units, effective immediately, with several years remaining on
its license. The NRC recently issued Vermont Yankee's Systematic
Assessment of Licensee Performance scores 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. In
1996, Vermont Yankee elected to accelerate certain safety and
management related projects intended to improve efficiency of the plant
and assure compliance with NRC regulations and the facility's operating
license.
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 September 7,
1996, Vermont Yankee began a scheduled refueling outage which ended
November 2, 1996. Vermont Yankee's next scheduled refueling is March,
1998. 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 is
approximately $366,000,000, of which $160,000,000 has been funded. At
December 31, 1996, the Company's portion of the net unfunded liability
was $36,000,000, which it expects will be recovered through rates over
Vermont Yankee's remaining operating life.
During 1996, the Company incurred $28,500,000 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,
1996 was $13,800,000.
During the year ended December 31, 1996, the Company utilized
565,383.9 MWh of Vermont Yankee energy to meet 27.9% of its retail and
requirements wholesale (Rate W) sales. The average cost of Vermont
Yankee electricity in 1996 was 4.8 cents per KWh. In 1996, Vermont Yankee
had an annual capacity factor of 83.0%, compared to 85.0% in 1995 and
96.1% in 1994.
The Price-Anderson Act currently limits public liability from a
single incident at a nuclear power plant to $8,900,000,000. Any
liability beyond $8,900,000,000 is indemnified under an agreement with
the NRC, but subject to Congressional approval. The first $200,000,000
of liability coverage is the maximum provided by private insurance. The
Secondary Financial Protection Program is a retrospective insurance plan
providing additional coverage up to $8,700,000,000 per incident by
assessing retrospective premiums of $79,300,000 against each of the 110
reactor units in the United States that are currently subject to the
Program, limited to a maximum assessment of $10,000,000 per incident per
nuclear unit in any one year. The maximum assessment is to be adjusted
at least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities
prior to January 1, 1988, for bodily claims. Vermont Yankee has purchased
a master worker insurance policy with limits of $200,000,000 with one
automatic reinstatement of policy limits to cover workers employed on or
after January 1, 1988. Vermont Yankee's estimated contingent liability
for a retrospective premium on the master worker policy as of December
1996 is $3,000,000. The secondary financial protection program referenced
above provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance
Limited (NEIL) 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 $13,300,000. Vermont Yankee's
liability for the retrospective premium adjustment for any policy year
ceases six years after the end of that policy year unless prior demand
has been made. See Note B of Notes to Consolidated Financial
Statements.
HYDRO-QUEBEC
Highgate Interconnection. On September 23, 1985, the Highgate
transmission facilities, which were constructed to import energy from
Hydro-Quebec in Canada, began commercial operation. The transmission
facilities at Highgate include a 225-MW AC-to-DC-to-AC converter
terminal and seven miles of 345-kV transmission line. VELCO built and
operates the converter facilities, which 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 PhaseEI. 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 690EMW to 2,000EMW, 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, 1996, the
present value of the Company's obligation was $9,000,000. The Company's
projected future minimum payments under the Phase II support agreements
are $474,013 for each of the years 1997-2001 and an aggregate of
$6,636,181 for the years 2002-2020.
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, 1996, 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, which incorporates
a load-based method of capacity allocation for transmission interfaces
between NEPOOL and the New York Power Pool. 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 will receive $1,100,000 in 1997.
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 will pay
$8,000,000 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 1996, the Company utilized 430,958.9 MWh under Schedule B,
300,359.7 MWh under Schedule C3, and 75,712.1 MWh under the tertiary
energy contract to meet 39.6% of its retail and requirements wholesale
sales. The average cost of Hydro-Quebec electricity in 1996 was 4.0 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
1,520.0 MWh to meet 0.1% of its retail and requirements wholesale sales
of NYPA power at an average cost of 0.8 cents per KWh in 1996. 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, 1996, the Company utilized
150,913.1 MWh from the unit to meet 7.4% of its total retail and
requirements wholesale sales. The average cost of electricity from this
unit was 3.8 cents per KWh in 1996. 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 1996, the Company utilized 32,199.0 MWh from this plant to
meet 1.6% of its retail and requirements wholesale sales at an average
cost of 7.6 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 1996, the Company utilized 5,941.5 MWh from this unit to
meet 0.3% of its retail and requirements wholesale sales at an average
cost of 6.1 per kWh, based only on operation, maintenance, and fuel
costs incurred during 1996. 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 1996,
the Company utilized 15,252.9 MWh from this unit to meet 0.8% of its
retail and requirements wholesale sales at an average cost of 5.4 cents per
kWh, based only on operation, maintenance, and fuel costs incurred
during 1996. 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 1996, the Company, through both its direct contracts and VEPPI,
purchased 125,552.2 MWh of qualifying facilities production to meet 6.2%
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. The price is set so as to recover the forecasted
fuel and capacity costs.
During 1996, the Company purchased 167,343.5 MWh, meeting 8.2% 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 1996, these plants provided 150,586.2 MWh of low-cost
energy, meeting 7.4% of the Company's retail and requirements wholesale
sales at an average cost of 2.9 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 1996, the Company's retail and requirements wholesale
sales were provided by the following fuel sources: 50.4% from hydro
(7.4% Company-owned, 0.1% NYPA, 39.6% Hydro-Quebec and 3.3% small power
producers), 27.9% from nuclear, 7.4% from coal, 3.7% from wood, 1.1%
from natural gas, and 1.1% from oil. The remaining 8.4% 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 (80EMW). The Company did not experience difficulty in obtaining oil
for its own units during 1996, and, while no assurance can be given,
does not anticipate any such difficulty during 1997. 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
221,529 tons of wood chips and mill residue and 23,340,000 cubic feet of
gas in 1996. The McNeil plant is forecasting consumption of wood chips
for 1997 to be 180,000 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 towns of Searsburg and Readsboro, is estimated to be
$11,000,000. The eleven wind turbines have a rating of 6 MW and are
expected to begin to generate electricity for the Company in 1997.
The Company is a utility leader in wind power research. The
CompanyOs 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 offers 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.
ENERGY EFFICIENCY
The Company develops and implements energy efficiency services,
known as demand-side management (DSM) programs, as part of its long-term
resource strategy. These programs are aimed at improving the match
between customer needs and the Company's ability to supply those needs
at a reasonable cost. Energy conservation, load management and
efficient electric use are central to these program efforts and provide
the means for controlling operating expenses and requirements for
additional capital investment. With more efficient electric
consumption, the use of existing resources can be optimized. DSM
program components also provide customers with options and choices with
respect to their use and cost of electric service.
In 1996, the Company focused its energy efficiency services on lost
opportunity programs that encourage customers to install energy
efficient equipment when they are planning to replace or buy new
equipment. This strategy has helped the Company to reduce its cost-per-
kilowatthour-saved by 51% since 1992. The current cost of saving a
kilowatthour is approximately 2.2 cents. In 1996, the Company's energy
efficiency programs saved 10,399 megawatthours of energy, 14% above
targeted savings for the year. During the past five years the Company's
efficiency programs have achieved a cumulative annual savings of 64,047
MWh.
One of the highlights of the Company's 1996 energy efficiency
initiatives was the successful completion of the Mad River Valley Energy
Project. The project reduced the peak demand in the Mad River Valley
(Vermont) and helped postpone the need for a costly transmission
upgrade. The Company is currently examining other areas of its
distribution system that may need upgrading in the near future and is
including energy efficiency as one of the options to help mitigate
costs.
In 1996, the Company spent approximately $2,400,000 on energy
efficiency programs, approximately 1.5% of its 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. By year end
December 31, 1996, approximately 1,350 of the Company's largest
customers, comprising 48% of retail revenues, were successfully
converted to 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.
Dispatchable and Interruptible Service Contracts. In 1996, 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 1996, 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 at the energy only cost of the rate. The customer's demand
during these periods is not considered in calculating the monthly
billing. This program provides customers with discretionary use of
portions of their load and the opportunity to maximize their energy
value, while, at the same time, the Company is able to retain customer
load requirements that might otherwise be met through alternative means.
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 1994-1996, internally generated funds, after payment
of dividends, provided approximately 60% of total capital requirements
for construction, sinking fund obligations and other requirements.
Internally generated funds provided 39% of such requirements for 1996,
inclusive of an optional redemption of $7,200,000 of first mortgage
bonds made by the Company. The Company anticipates that for 1997,
internally generated funds will provide approximately 87% of total
capital requirements for regulated operations, the remainder to be
derived from bank loans.
In January 1996, a portion of the proceeds from the sale of
$24,000,000 of the Company's first mortgage bonds in December 1995 was
used to refund $7,200,000 of the Company's 10.7% first mortgage bonds.
In October 1996, the Company issued $12,000,000 of its 7.32%, Class
E, Series 1, preferred stock. In November 1996, the Company sold
$10,000,000 of its first mortgage bonds at an interest rate of 7.18% and in
December 1996, the Company sold $4,000,000 of its first mortgage bonds
at an interest rate of 7.05%. The proceeds from these transactions were
used to repay short-term debt, to retire fixed income securities and for
other general corporate purposes.
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, including Green Mountain Resources, Inc., which is engaged
in the competitive marketing of energy products. For information
regarding unregulated businesses, see Item 7. MD&A- "Future Outlook -
Unregulated Businesses."
EXECUTIVE OFFICERS
Executive Officers of the Company as of March 28, 1997:
Name Age
Thomas C. Boucher 42 Vice President, Business Strategy and
Development since May 1996. Vice President,
Energy Resources and Planning from January
1995. Vice President-Corporate Planning from
1994 to 1995. Vice President, Financial
Planning from 1992 to 1994. Assistant Vice
President-Energy Planning from 1986 to 1992.
Christopher L. Dutton 48 Vice President, Finance and
Administration, Chief Financial Officer and
Treasurer since January 1995. Vice President
and General Counsel from 1993 to January
1995. Vice President, General Counsel and
Corporate Secretary from 1989 to 1993.
Robert J. Griffin 40 Controller since October 7, 1996.
Manager of General Accounting from 1990 to
1996.
Francis J. Heald 55 President of Green Mountain Propane Gas
Company since June 1996. Prior to joining
the Company, he was Executive Vice President
and General Manager of Pico Ski Resort, Inc.
Richard B. Hieber 58 Vice President, Electric Operations and
Engineering since September 1, 1996. 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.
Douglas G. Hyde 54 President, Chief Executive Officer and
Chairman of the Executive Committee of the
Corporation since 1993. Executive Vice
President, Chief Operating Officer and
Director from 1989 to 1993. President of
Green Mountain Resource, Inc.
Donna S. Laffan 47 Corporate Secretary since December
1993. Assistant Secretary from 1986 to 1993.
John J. Lampron 52 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.
Craig T. Myotte 42 Assistant Vice President-Engineering
and Operations since 1994. Assistant Vice
President-Operations and Maintenance from
1991 to 1994.
Edwin M. Norse 51 Vice President and General Manager,
Energy Resources and Sales since January
1995. 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 50 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.
Karen K. O'Neill 45 Assistant Vice President-Organizational
Development and Human Resources since June
1994. Assistant General Counsel from 1989 to
1994.
Stephen C. Terry 54 Vice President and General Manager,
Retail Energy Services since January 1995.
Vice President-External Affairs from 1991 to
January 1995.
Jonathan H. Winer 45 President of Mountain Energy, Inc.
since March 1997. Vice President and Chief
Operating Officer from 1989 to March 1997.
Robert C. Young 59 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.
Peter H. Zamore 44 General Counsel since January 1995.
Prior to joining the Company, he was a
partner at the law firm of Sheehey Brue Gray
& Furlong, P.C. from 1984 to 1995.
Officers are elected by the Board of Directors of the Company,
Mountain Energy, Inc., Green Mountain Resources, Inc. or Green Mountain
Propane Gas Company, 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 36.4 MW and an
estimated claimed capability of 35.7 MW. It also owns two gas-turbine
generating stations with an aggregate nameplate rating of 63.0 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 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.EMcNeil 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, 1996, 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 2,384 miles of overhead lines, 2.4 kV
to 34.5 kV, and about 432 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
1,260,901 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 57.1
Turbine Colchester, VT Gorge #16 Oil 16.1
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 255.6
(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 1996 and 1995:
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
1995 First Quarter 28 1/4 24 7/8
Second Quarter 27 24 3/4
Third Quarter 27 1/8 23 7/8
Fourth Quarter 28 5/8 27 3/4
The number of common stockholders of record as of March 14, 1997
was 8,716.
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
1995 53 cents 53 cents 53 cents 53 cents
Dividend Policy -- The Company's current dividend policy is based
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.
There is a strong movement in Vermont to restructure the electric
utility industry, to be implemented in 1998, in order to permit
competition in the generation and retail sale of electricity. Such
restructuring is expected, among other things, to lead to a loss of the
Company's current exclusive franchise for selling electricity at retail,
even though the Company currently expects that it would retain its
exclusive franchise to provide distribution service. Also, a business
operating in a competitive environment, including any unregulated
activities by the Company, would by its nature engender a different type
of earnings growth and volatility than is found in a regulated entity.
Should restructuring be approved in Vermont, it is likely that the
Company will reconsider its dividend policy and make appropriate changes
so that anticipated payout levels are more commensurate with the risk of
any new business activities to be undertaken and consistent with the
capital needs of its businesses. 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.
SELECTED FINANCIAL DATA (In thousands except per share amounts)
Results of operations for the years ended December 31
- -----------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
Operating Revenues........................$179,009 $161,544 $148,197 $147,253 $145,240
Operating Expenses........................ 162,882 146,249 133,680 132,427 128,828
--------- --------- --------- --------- ---------
Operating Income........................ 16,127 15,295 14,517 14,826 16,412
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity.......................... 175 27 263 273 186
Other................................... 3,055 3,607 3,418 2,360 2,073
--------- --------- --------- --------- ---------
Total other income.................... 3,230 3,634 3,681 2,633 2,259
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed funds.................. (468) (547) (539) (357) (202)
Other................................... 7,866 7,973 7,735 7,185 7,021
--------- --------- --------- --------- ---------
Total interest charges................ 7,398 7,426 7,196 6,828 6,819
--------- --------- --------- --------- ---------
Net Income................................ 11,959 11,503 11,002 10,631 11,852
Dividends on Preferred Stock.............. 1,010 771 794 811 831
--------- --------- --------- --------- ---------
Net Income Applicable to Common Stock..... $10,949 $10,732 $10,208 $9,820 $11,021
========= ========= ========= ========= =========
Common Stock Data
Earnings per share...................... $2.22 $2.26 $2.23 $2.20 $2.54
Cash dividends declared per share....... $2.12 $2.12 $2.12 $2.11 $2.08
Weighted average shares outstanding..... 4,933 4,747 4,588 4,457 4,345
Financial Condition as of December 31
- -------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
Assets
Utility Plant, Net.......................$189,853 $181,999 $175,987 $171,411 $164,723
Other Investments........................ 20,634 20,248 20,751 22,528 21,700
Current Assets........................... 30,901 30,216 28,798 26,215 28,067
Deferred Charges......................... 43,224 42,951 35,659 33,893 19,012
Non-Utility Assets....................... 39,927 37,868 33,416 28,626 23,716
--------- --------- --------- --------- ---------
Total Assets............................$324,539 $313,282 $294,611 $282,673 $257,218
========= ========= ========= ========= =========
Capitalization and Liabilities
Common Stock Equity......................$111,554 $106,408 $101,319 $97,149 $92,645
Redeemable Cumulative Preferred Stock.... 19,310 8,930 9,135 9,385 9,575
Long-Term Debt, Less Current Maturities.. 94,900 91,134 74,967 79,800 67,644
Capital Lease Obligation................. 9,006 9,778 10,278 11,029 11,950
Curent Liabilities....................... 21,037 32,629 40,441 37,925 30,099
Deferred Credits and Other............... 54,968 52,041 49,434 40,214 33,264
Non-Utility Liabilities.................. 13,764 12,362 9,037 7,171 12,041
--------- --------- --------- --------- ---------
Total Capitalization and Liabilities....$324,539 $313,282 $294,611 $282,673 $257,218
========= ========= ========= ========= =========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
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 1996 were $2.22 as
compared with $2.26 in 1995 and $2.23 in 1994. The 1996 earnings
represent an earned return on average common equity of 10.0 percent. In
both 1995 and 1994, the earned return on average common equity was 10.3
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 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.
The principal factors contributing to the increase in 1995 earnings
were higher retail revenues resulting from a 9.25 percent retail rate
increase that went into effect in June 1995, increased sales of
electricity to the Company's commercial and industrial customers, and a
$557,000 increase in the earnings of Mountain Energy, Inc., the
Company's wholly-owned subsidiary that invests in energy generation and
efficiency projects.
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 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 utilities (including the Company),
customers, environmental groups and other 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
Order on December 31, 1996.
The Final Order requires that Vermont investor-owned utilities
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 provides for competition for all customer classes to be completed by
the end of 1998. In view of this 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. 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 Order proposes 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 Order also states the VPSB's belief that "an
opportunity for full recovery must be explicitly tied to successful
mitigation." The Final Order further provides 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 Order calls for a multi-step process that would involve
(1) a rigorous estimate of stranded costs (which in turn would require
an estimate of future power costs) and a determination of the extent to
which stranded costs can be mitigated, (2) an adjustment of stranded
costs based on mitigation of such costs and changes in the market price
of power, and (3) a stranded cost reconciliation proceeding. The
process would consider each utility's estimate of stranded costs and the
success of its mitigation efforts on a case by case basis.
The Final Order proposes 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 Order also endorses the securitization
of stranded costs through the assignment of CTC receipts as a means of
achieving lower-cost financing and the Final Order supports legislative
action to achieve these savings.
The Company, Central Vermont Public Service Corporation (CVPS),
representatives of the Governor of Vermont and the Department are in the
process of negotiating a Memorandum of Understanding (MOU) that would
outline agreed-upon positions among the parties relative to the recovery
of stranded costs, distribution company rates, corporate unbundling and
societal benefit programs. The parties to the MOU mutually would
support those provisions in connection with any proposed legislation
before the Vermont General Assembly and in any regulatory proceeding
before the VPSB. If all of the terms of the MOU are not included in
final restructuring legislation and in an implementing VPSB Order, the
MOU will be of no force or effect.
Although not executed as of March 6, 1997, it is likely that the
MOU will include the following financial terms:
If the Company were able to reduce its power costs by $105 million
(on a net present value basis assuming a 10% discount rate), then
it would be conclusively deemed to have adequately mitigated
stranded costs for the purpose of recovering its remaining stranded
costs. The closer the Company is to the mitigation target, the
greater the likelihood that the Company will recover all of its
remaining stranded costs.
The CTC would be fixed initially at $30/MWh for the first two years
of retail competition. Any under-collections or over-collections of
the CTC, respectively, would be added to or subtracted from the
unrecovered stranded cost balance. The CTC would be adjusted
annually thereafter to achieve recovery of stranded costs by the
end of 2012.
Unbundled distribution subsidiary rates would be frozen for 1998
and 1999 and adjusted by 70% of the change in the consumer price
index for calendar years 2000 through 2004. Some portion of the
frozen and subsequent rates would be dependent on achieving
mutually agreed upon performance targets regarding quality of
service. The distribution subsidiary would also be able to
petition the VPSB for relief due to significant factors out of the
control of the distribution subsidiary, such as, but not limited
to, a change in income tax rates, the need for significant capital
expenditures to meet material customer expansions, natural
catastrophes or significant changes in load growth.
Proposals are currently being debated before the Vermont General
Assembly that would allow all classes of customers in Vermont to choose
their power supplier beginning in 1998. The terms of most of the
proposed legislation are generally consistent with the approach set
forth in the Final Order regarding eligibility for stranded cost
recovery, although some would permit less stranded cost recovery.
There is no assurance that any restructuring legislation will be
enacted by the Vermont General Assembly, or if legislation is enacted,
that it will be consistent with the terms of the Final Order or the MOU.
Risk Factors -- The major risk factors affecting the impact of
electric industry restructuring upon the Company, including 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 VPSB, the courts, or through legislation will include a CTC
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 opportunity
adequately to recover stranded costs, the Company believes it has 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 Order 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 $330 million and
$564 million, on a net present value basis, discounted at a rate of 10%.
If retail competition is implemented in Vermont and elsewhere, the
Company is unable to predict the impact of this competition on its
revenues, on the Company's ability to retain existing customers and
attract new customers, or on the margins that will be realized on retail
sales of electricity.
Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain
accounting standards that are not applicable to other business
enterprises in general. Statement of Financial Accounting Standards
(SFAS) 71, Accounting for Certain Types of Regulation, 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. Criteria
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.
The Company believes that the provisions of both the Final Order
and MOU, if implemented, would meet the criteria for continuing
application of SFAS 71 as to those costs for which recovery is
permitted. Because the Company is unable to predict what form enacted
legislation will take, however, it cannot predict if or to what extent
SFAS 71 will continue to be applicable in the future.
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, 1996, based upon the regulatory
environment within which the Company currently operates, SFAS 121 did
not have an impact on the Company's financial position or results of
operations. Competitive influences or regulatory developments may
impact this status in the future.
Thus, 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 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.
Unregulated Businesses -- For several years, the Company has had a
plan of diversification into unregulated businesses that complements the
Company's basic utility operations. The following is a discussion of
the Company's unregulated enterprises, including its newest subsidiary,
which is engaged in the competitive retail marketing of energy products.
Mountain Energy, Inc., which has invested in energy-related
businesses, earned $1.32 million in 1996, a slight decrease from 1995's
net income of $1.38 million. The 1996 results contributed 27 cents of
earnings per share to the Company's consolidated results as compared to
29 cents in 1995.
Since its formation in 1989, Mountain Energy has invested more than
$17 million in nine 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 March 1997, Mountain Energy broadened its investment portfolio
by acquiring a 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 sludge disposal
issues facing the United States. The Micronairr system enhances both
the processing and energy efficiency at wastewater facilities, virtually
eliminating sludge as a byproduct. This environmentally and
economically desirable result has already been demonstrated in several
commercial facilities.
Green Mountain Propane Gas Company, which sells propane gas at
retail in Vermont and New Hampshire, experienced a $335,000 loss in 1996
as compared to a $347,000 loss in 1995. 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. In 1995, the loss was due primarily to warmer than normal weather
in the first quarter of 1995 and reduced margins due to strong
competition. In both 1996 and 1995, the losses reduced the Company's
consolidated earnings by 7 cents per share.
The Company's unregulated rental water heater business earned
$379,000 in 1996, an increase from 1995's net income of $308,000. The
increase in income in 1996 was attributable to an increase in the rental
rate charged to customers. The 1996 results contributed 8 cents of
earnings per share to the Company's consolidated results as compared to
6 cents in 1995.
Green Mountain Resources, Inc. (GMRI) was formed in April 1996 to
explore opportunities in competitive retail energy markets. 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).
The State of New Hampshire has undertaken an experiment to provide
retail customer choice in the purchase of electricity. The New
Hampshire pilot program is one of the nation's first significant
attempts to test the viability of retail electric competition. GMEP has
been competing in New Hampshire since May 1996 with approximately two
dozen other suppliers to serve 17,000 eligible customers. The pilot
program will extend two years, with service that began in June 1996.
The Commonwealth of Massachusetts authorized Bay State Gas
Company's Pioneer Valley Customer Choice Residential Pilot Program (the
Bay State Gas Pilot), in which GMEP is participating. The Bay State Gas
Pilot permits the retail sale of natural gas to up to 10,000 eligible
residential customers and will extend for two years with service that
began in November 1996.
GMRI experienced a $579,000 loss in 1996, its first year of
operation. The loss experienced was consistent with the Company's
expectation and reflects a limited number of pilot customers coupled
with significant price competition on the part of energy providers
participating in the retail pilots. The 1996 results reduced the
Company's consolidated earnings by 12 cents per share. This loss was
mitigated to a large extent by offsetting payments the Company received
from GMEP for work performed on its behalf.
The Company believes that participation in these pilot programs
will enhance the capability of GMRI to compete in additional markets
that are opened for retail electric and natural gas customer choice.
GMRI may decide to participate in other retail energy programs that are
developed through GMEP or other entities that may be formed in the
future.
RESULTS OF OPERATIONS
Operating Revenues and MWh Sales--Operating revenues and megawatthour
(MWh) sales for the years 1996, 1995 and 1994 consisted of:
1996 1995 1994
---- ---- ----
(Dollars in Thousands)
Operating Revenues:
Retail . . . . . . . . . . . . . $ $154,916 $ 140,676 $ 131,444
Sales for Resale . . . . . . . . 20,667 17,541 13,521
Other . . . . . . . . . . . . . 3,426 3,327 3,232
---------- --------- ---------
Total Operating Revenues . . . . . $ 179,009 $ 161,544 $ 148,197
========== ========= =========
MWh Sales:
Retail . . . . . . . . . . . . . 1,775,711 1,723,117 1,691,867
Sales for Resale . . . . . . . . 701,835 620,655 367,424
--------- --------- ---------
Total MWh Sales . . . . . . . . . 2,477,546 2,343,772 2,059,291
========= ========= =========
Average Number of Customers:
Residential . . . . . . . . . . 70,198 69,659 68,811
Commercial & Industrial . . . . 11,853 11,736 11,635
Other . . . . . . . . . . . . . 75 76 76
------ ------ ------
Total Customers . . . . . . . . . . 82,126 81,471 80,522
====== ====== ======
Differences in operating revenues were due to changes in the following:
1995 1994
to to
1996 1995
---- ----
(In Thousands)
Operating Revenues:
Retail Rates . . . . . . . . . . . . . . . $ 9,654 $ 6,619
Retail Sales Volume . . . . . . . . . . . 4,586 2,613
Resales and Other Revenues . . . . . . . . 3,225 4,115
------- ------
Increase in Operating Revenues . . . . . . . $17,465 $13,347
======= =======
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.
In 1995, total electricity sales increased 13.8 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 9.0 percent in 1995 primarily due to a 9.25
percent retail rate increase that went into effect in June 1995 and the
increase in electricity sales previously mentioned. Total retail
revenues increased 7.0 percent in 1995 primarily due to the 9.25 percent
retail rate increase mentioned above. Wholesale revenues increased 29.7
percent in 1995 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 13.2, 12.9 and
13.7 percent of the Company's operating revenues in 1996, 1995 and 1994,
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) that established the price to be paid by IBM
at its Essex Junction facility for incremental electric usage during
1995, 1996 and 1997. The contract, which is intended to promote growth
in IBM's operations and create jobs in the Company's service area,
applies only to that portion of IBM's load that exceeds its 1994
consumption level. Most of IBM's electric usage is billed under the
Company's tariff rate. The EDA price, although lower than the Company's
tariff rate, exceeds the Company's marginal costs of providing this
incremental electric service to IBM. The VPSB approved the EDA in June
1995. The Company believes that the EDA benefits the Company because it
encourages 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 61.5
percent, 60.1 percent and 59.2 percent of total operating expenses for
the years 1996, 1995 and 1994, respectively. These expenses increased by
$12.3 million (14.0 percent) in 1996 and by $8.7 million (11.0 percent)
in 1995.
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.
Power supply expenses increased in 1995 as the Company produced and
purchased additional power to service increased electricity sales.
Under an arrangement negotiated in January 1996, the Company
received cash payments from Hydro-Quebec of $3.0 million in 1996 and
will receive $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 will reduce power
costs in 1997. The $1.1 million payment will reduce purchase power
expense ratably over the period beginning June 1997 and ending May 1998.
In response, the Company will 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 agreement. 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.
In November 1996, the Company entered into a Memorandum of
Understanding with Hydro-Quebec providing for the payment to the Company
of $8.0 million in 1997 in exchange for Hydro-Quebec's right to elect,
on or before September 1, 1997, one of two options to purchase power.
Under the first option, for the period commencing November 1, 1997 and
effective through the remaining term of the 1987 power supply agreement
between the Company and Hydro-Quebec (the 1987 Agreement), which expires
in 2015, Hydro-Quebec can exercise an option to purchase on an annual
basis, at energy prices established in accordance with the 1987
Agreement, an amount of energy equivalent to the Company's firm capacity
entitlements in the 1987 Agreement, delivered at up to an approximately
10.5 percent capacity factor, or 105,000 MWh. Under the second option,
for the period commencing November 1, 1997 and effective through the
remaining term of the 1987 Agreement, Hydro-Quebec can exercise an
option to purchase on an annual basis, at energy prices established in
accordance with the 1987 Agreement, an amount of energy equivalent to
the Company's firm capacity entitlements in the 1987 Agreement,
delivered at up to an approximately 5.25 percent capacity factor, or
52,500 MWh. Hydro-Quebec also would have the right under the second
option to elect to purchase up to 600,000 MWh of power from the Company
over the remaining term of the 1987 Agreement, commencing November 1,
1997, at the energy prices established in accordance with the 1987
Agreement, subject to certain annual and hourly volume limitations.
On December 31, 1996, the Company received an accounting order from
the VPSB that provides for recognition in 1997 revenues of the present
value payment of $8 million. The accounting order also continues the
limitation on the return on equity from utility operations of 11.25
percent which had been a part of the Company's last two rate settlements
through December 31, 1997. The Company estimates that the future costs
associated with the Memorandum of Understanding to be approximately $8.0
million on a net present value basis. Consistent with allowed
ratemaking treatment, the $8.0 million payment will be recognized in
income in the third and fourth quarters of 1997.
Other Operating Expenses -- 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.
Other operating expenses increased 4.8 percent in 1995 primarily
due to an increase in rent expense and expenses relating to customer-
focused research.
Transmission Expenses -- Transmission expenses increased 9.7
percent in 1996 primarily due to higher tariff rates under an
interconnection agreement between CVPS and the Company discussed below.
This increase was offset to a large extent by revenues generated by the
same interconnection agreement.
On August 28, 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 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. The Company disputes the
amount of the CVPS billing and estimates its liability in the range of
$1.0 million to $1.3 million, inclusive of amounts already expensed.
The Company has submitted a bill totaling approximately $500,000 to
CVPS for its services under the same interconnection agreement, and
credited this amount to transmission services in September 1996. CVPS
disputes approximately $100,000 of the amount billed by the Company.
On December 31, 1996, the Company received an accounting order from
the VPSB requiring that amounts deferred under the interconnection
agreement be expensed over the remaining eleven years of the agreement.
The interconnection agreement contains an arbitration clause for the
settlement of disputes. The Company has requested arbitration and is
unable to predict the ultimate outcome of that proceeding.
Transmission expenses decreased 4.8 percent in 1995 primarily due
to cost reduction measures implemented by Vermont Electric Power Company
(VELCO), a corporation engaged in the transmission of electric power
within the State of Vermont in which the Company has an equity interest.
Maintenance Expenses -- Maintenance expenses increased 6.0 percent
in 1996 due principally to a scheduled increase in plant maintenance.
Maintenance expenses decreased 5.7 percent in 1995 primarily due to
cost containment measures implemented by the Company.
Depreciation and Amortization -- 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 Marsh 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.
Depreciation and amortization expenses increased 32.1 percent in
1995 for the same reasons.
Income Taxes -- The effective federal income tax rates for the
years 1996, 1995 and 1994 were 27.2 percent, 25.3 percent and 25.1
percent, respectively.
Other Income -- 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 mitigated to a large extent by
offsetting payments received by the Company from GMEP for work performed
on its behalf.
Other income decreased 1.3 percent in 1995 primarily due to a
decrease in the allowance for equity funds used during construction
resulting from lower average construction work in progress balances and
an increase in short-term debt outstanding during the year and a
$389,000 decrease in earnings experienced by Green Mountain Propane Gas
Company. These decreases were partially offset by a $557,000 increase in
earnings of Mountain Energy, Inc.
Dividends on Preferred Stock -- Dividends on preferred stock
increased 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.
Dividends on preferred stock decreased 2.9 percent in 1995
primarily due to the repurchase by the Company in 1994 of the following
preferred stock: 450 shares of 4.75 percent, Class B; 450 shares of 7
percent, Class C, and 1,600 shares of 9.375 percent, Class D, Series 1.
Interest Charges -- 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.
Interest charges increased 3.2 percent in 1995 primarily due to
interest charges related to an increase in short-term debt outstanding
during 1995. These charges were partially offset by a reduction in
interest charges related to a decrease in the amount of long-term debt
outstanding during 1995.
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. The Company is currently in the process of responding
to the orders. On July 9, 1996, the Company filed with the FERC the
non-discriminatory open access tariffs required by Order 888. The
tariffs defined the Company's transmission system to include
subtransmission facilities owned by the Company 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. VELCO, in
turn, submitted to the FERC a request for waiver of its obligation to
file a separate open access transmission tariff. On September 11, 1996,
the FERC denied VELCO's waiver request. The Company is also in the
process of modifying its tariff to comply with various orders of the
FERC and in addition complying with the FERC's regulations relating to
OASIS, the electronic bulletin board to be used to post availability of
transmission capacity.
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 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, 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. NEPOOL has filed a
proposed tariff with the FERC that incorporates a load-based method of
capacity allocation for NEPOOL transmission facilities that would reduce
the amount of capacity allocated to VELCO for such transmission
facilities in the future. A reduction of VELCO's allocation of
capacity on transmission interfaces with New York and Canada would
adversely effect the Company's ability to import power to Vermont from
outside New England which would impact the Company's power costs in the
future. VELCO and the Company have filed comments with the FERC seeking
to change the effect of the proposed NEPOOL capacity allocation
procedures but the Company is unable to predict at this time the outcome
of these proceedings before the FERC.
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 Marsh
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 Marsh 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 Marsh 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 toward
the EPA's past response under a confidential Consent Decree. The
Company remains a PRP for 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 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. On December 1, 1994, the Company and two other PRPs, New
England Electric System (NEES) and Vermont Gas Systems (VGS), entered
into a confidential 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 1991, the Company brought suit against eight previous
insurers seeking recovery of unrecovered past costs and indemnity
against future liabilities associated with environmental problems at the
site. Discovery in the case, which was previously subject to a stay, is
proceeding and is largely complete. A trial in this litigation is
scheduled for late 1997. The Company has reached confidential final
settlements with two of the defendants in this litigation and has
obtained summary judgment declaring one non-settling insurer's duty to
defend.
The Company has deferred amounts received, under confidential
settlement, from third parties pending resolution of the Company's
ultimate liability with respect to the site and rate recognition of that
liability. 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 Marsh 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 Pine Street Marsh related costs, the Company and the
Department reached agreements in these cases that the full amount of
Pine Street Marsh 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 Marsh related expenditures
referred to above.
Management expects to seek and (assuming recovery consistent with
the previous regulatory treatment set forth above) receive ratemaking
treatment for unreimbursed costs incurred beyond the amounts for which
ratemaking treatment has been received.
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. After reviewing
the Company's current accounting policies and ratemaking treatment,
management does not believe that this SOP will have a material adverse
effect on the Company's financial position or results of operations upon
adoption.
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 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 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
1997 are as follows:
Total Net
Actual Generation Transmission Distribution Conservation Other Expenditures
(Dollars in thousands and net of AFUDC and Customer Advances For Construction)
1994 $2,540 $1,415 $7,902 $6,388 $1,815 $20,060
1995 2,696 1,067 8,935 4,152 2,824 19,674
1996 6,289* 528 8,422 3,090 3,394 21,723
Forecasted
1997 $2,680 $1,355 $8,591 $2,300 $7,504 $22,430
*Includes $4.978 million for wind project
Rates -- On September 26, 1994, the Company filed a request with
the VPSB to increase retail rates by 13.9 percent. The increase was
needed primarily to cover the rising cost of existing power sources, the
cost of new power sources that the Company secured to replace power
supply that will be lost in the near future, and the cost of energy
efficiency programs that the Company implemented for its customers. The
Company, the Department and the other parties in the proceeding reached
a settlement agreement providing for a 9.25 percent retail rate increase
effective June 15, 1995, and a target return on equity for utility
operations of 11.25 percent. In the event that the target return on
equity is exceeded, the Company would accelerate the amortization of
certain demand side management expenditures in the next year for which
rate recovery otherwise would have been sought. The agreement was
approved by the VPSB on June 9, 1995.
In September 1995, the Company filed a 12.7 percent retail rate
increase application to cover higher power supply costs, to support
additional investment in plant and equipment, to fund expenses
associated with the Pine Street Marsh site, and to cover higher costs of
capital. Early in 1996, the Company settled this rate case with the
Department and other parties.
The settlement became possible when the Company negotiated a new
arrangement with Hydro-Quebec that will reduce the Company's net power-
supply costs below the amounts anticipated in the rate increase request.
The settlement provided: projected additional annual revenues of $7.6
million; an overall increase in retail rates of 5.25 percent effective
June 1, 1996; target return on equity for utility operations of 11.25
percent (with a continuation of the amortization of any amount in excess
of the target rate of return in the following year, as described above);
and recovery of $1.3 million of costs associated with the Pine Street
Marsh site, amortized over five years. The VPSB approved the settlement
in an order dated May 23, 1996. In 1996, the rate of return on utility
operations was 11.8% and in 1995 was 11.3%. An accounting order
received from the VPSB on December 31, 1996 continues the limitation on
return on equity from utility operations through December 31, 1997.
Dividend Policy -- The Company's current dividend policy is based
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. As discussed under "Future Outlook-Competition
and Restructuring," there is a strong movement in Vermont to restructure
the electric utility industry, to be implemented in 1998, in order to
permit competition in the generation and retail sale of electricity.
Such restructuring would, among other things, lead to a loss of the
Company's current exclusive franchise for selling electricity at retail,
even though the Company would retain its exclusive franchise to provide
distribution service. Also, a business operating in a competitive
environment, including any unregulated activities by the Company, would
by its nature engender a different type of earnings growth and
volatility than is found in a regulated entity. Should restructuring be
approved in Vermont, it is likely that the Company will reconsider its
dividend policy and make appropriate changes so that anticipated payout
levels are more commensurate with the risk of any new business
activities to be undertaken and consistent with the capital needs of its
businesses.
Financing and Capitalization -- For the period 1994 through 1996,
internally generated funds, after payment of dividends, provided
approximately 60 percent of total capital requirements for construction,
sinking funds and other requirements. The Company anticipates that for
1997, internally generated funds will provide approximately 87 percent
of total capital requirements for regulated operations.
In January 1996, a portion of the proceeds from the sale of $24
million of the Company's first mortgage bonds in December 1995 was used
to refund $7.2 million of the Company's 10.7 percent first mortgage
bonds.
In October 1996, the Company issued $12 million of its 7.32
percent, Class E, Series 1, preferred stock. In November 1996, the
Company sold $10 million of its first mortgage bonds at an interest rate
of 7.18 percent and in December 1996, the Company sold $4 million of its
first mortgage bonds at an interest rate of 7.05 percent. The proceeds
from these transactions were used to repay short-term debt, to retire
fixed income securities and for other general corporate purposes.
At December 31, 1996, the Company's capitalization consisted of
48.8 percent common equity, 42.8 percent long-term debt and 8.4 percent
preferred equity. The Company has a comprehensive capital plan to
increase the equity component of its capital structure.
The rating of the Company's first mortgage bonds by Standard &
Poor's remains at "BBB+." In 1996, a rating of "BBB" was assigned to
the Company's preferred stock. Standard & Poor's "outlook" of the
Company remains "stable."
The rating of the Company's first mortgage bonds by Duff & Phelps
was lowered in September 1996 from "A-" to "BBB+." The rating of the
Company's preferred stock was also lowered from "BBB+" to "BBB." These
ratings reflect Duff & Phelps' assessment that the electric utility
industry in the region is becoming increasingly more competitive and
that the Company is highly dependent upon purchased power agreements
with escalating fixed payment obligations. Duff & Phelps, however,
concluded that the Company has low cost structures, access to a good
transmission system and a strong marketing-oriented focus.
The rating of the Company's first mortgage bonds by Moody's
Investment Services remains at "Baa2." In 1996, a rating of "baa3" was
assigned to the Company's preferred stock by Moody's. Moody's "outlook"
for the Company remains "stable."
See Note F of the Notes to Consolidated Financial Statements for a
discussion of bank lines of credit available to the Company.
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.
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, 1996, 1995 and 1994 38
Consolidated Statements of Cash Flows For the
Years Ended December 31, 1996, 1995 and 1994 39
Consolidated Balance Sheets as of
December 31, 1996 and 1995 40-41
Consolidated Capitalization Data as of
December 31, 1996 and 1995 42
Notes to Consolidated Financial Statements 43-61
Quarterly Financial Information 54
Report of Independent Public Accountants 62
Schedules
For the Years Ended December 31, 1996, 1995 and 1994:
II Valuation and Qualifying Accounts and Reserves 63
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 62 & 74
CONSOLIDATED STATEMENTS OF INCOME
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
1996 1995 1994
----------------- --------------- ---------------
(In thousands, except amounts per share)
Operating Revenues.............................................. $179,009 $161,544 $148,197
----------------- --------------- ---------------
Operating Expenses
Power Supply
Vermont Yankee Nuclear Power Corporation................... 30,596 30,222 30,300
Company-owned generation................................... 3,330 3,786 3,113
Purchases from others...................................... 66,320 53,915 45,777
Other operating............................................... 17,615 18,120 17,296
Transmission................................................. 10,833 9,874 10,374
Maintenance................................................... 4,463 4,210 4,465
Depreciation and amortization................................. 16,280 14,116 10,683
Taxes other than income....................................... 6,982 6,428 6,277
Income taxes.................................................. 6,463 5,578 5,395
----------------- --------------- ---------------
Total operating expenses................................... 162,882 146,249 133,680
----------------- --------------- ---------------
Operating Income......................................... 16,127 15,295 14,517
----------------- --------------- ---------------
Other Income
Equity in earnings of affiliates and
non-utility operations..................................... 2,880 3,513 3,112
Allowance for equity funds used during construction........... 175 27 263
Other income and deductions, net.............................. 175 94 306
----------------- --------------- ---------------
Total other income.......................................... 3,230 3,634 3,681
----------------- --------------- ---------------
Income before interest charges............................ 19,357 18,929 18,198
----------------- --------------- ---------------
Interest Charges
Long-term debt................................................ 6,872 6,546 6,868
Other......................................................... 994 1,427 867
Allowance for borrowed funds used during
construction............................................ (468) (547) (539)
----------------- --------------- ---------------
Total interest charges...................................... 7,398 7,426 7,196
----------------- --------------- ---------------
Net Income...................................................... 11,959 11,503 11,002
Dividends on preferred stock.................................... 1,010 771 794
----------------- --------------- ---------------
Net Income Applicable to Common Stock........................... $10,949 $10,732 $10,208
================= =============== ===============
Common Stock Data
Earnings per share............................................ $2.22 $2.26 $2.23
Cash dividends declared per share............................. $2.12 $2.12 $2.12
Weighted average shares outstanding........................... 4,933 4,747 4,588
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
1996 1995 1994
--------- --------- ---------
(In thousands)
Operating Activities:
Net Income........................................................... $11,959 $11,503 $11,002
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization.................................... 16,280 14,116 10,683
Dividends from associated companies less equity income........... 254 660 202
Allowance for funds used during construction..................... (643) (574) (803)
Deferred purchased power costs................................... (5,917) (12,935) (536)
Amortization of purchased power costs............................ 5,187 6,036 4,178
Deferred income taxes............................................ 1,937 3,715 1,585
Amortization of investment tax credits........................... (282) (283) (283)
Environmental proceedings costs, net............................. (1,720) (1,351) 7,103
Conservation expenditures........................................ (3,207) (3,960) (6,388)
Changes in:
Accounts receivable............................................ 347 (2,841) (426)
Accrued utility revenues....................................... (139) (510) 126
Fuel, materials and supplies................................... (309) 2 (473)
Prepayments and other current assets........................... (354) 1,562 (1,982)
Accounts payable............................................... 221 2,191 (2,327)
Taxes accrued.................................................. 415 (871) 1,044
Interest accrued............................................... (465) (106) (117)
Other current liabilities...................................... 1,065 (22) (65)
Other............................................................ 1,738 (95) 2,383
--------- --------- ---------
Net cash provided by operating activities.......................... 26,367 16,237 24,906
--------- --------- ---------
Investing Activities:
Construction expenditures.......................................... (17,541) (15,314) (13,536)
Investment in non-utility property................................. (2,203) (6,121) (1,220)
--------- --------- ---------
Net cash used in investing activities............................ (19,744) (21,435) (14,756)
--------- --------- ---------
Financing Activities:
Issuance of preferred stock........................................ 12,000 -- --
Reduction in preferred stock....................................... (1,620) (205) (250)
Issuance of common stock........................................... 4,642 4,404 3,671
Short-term debt, net............................................... (7,400) (11,799) 1,198
Issuance of long-term debt......................................... 14,000 25,917 --
Reduction in long-term debt........................................ (16,201) (4,833) (1,800)
Cash dividends..................................................... (11,455) (10,818) (10,504)
--------- --------- ---------
Net cash provided by (used in) financing activities.............. (6,034) 2,666 (7,685)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............... 589 (2,532) 2,465
Cash and cash equivalents at beginning of year..................... 160 2,692 227
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $749 $160 $2,692
========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION December 31
1996 1995
--------- ---------
(In thousands)
ASSETS
Utility Plant
Utility plant, at original cost....................$248,135 $239,291
Less accumulated depreciation...................... 81,286 75,797
--------- ---------
Net utility plant................................ 166,849 163,494
Property under capital lease....................... 9,006 9,778
Construction work in progress...................... 13,998 8,727
--------- ---------
Total utility plant, net......................... 189,853 181,999
--------- ---------
Other Investments
Associated companies, at equity ................... 15,769 16,024
Other investments ................................. 4,865 4,224
--------- ---------
Total other investments.......................... 20,634 20,248
--------- ---------
Current Assets
Cash............................................... 238 84
Accounts receivable, customers and others,
less allowance for doubtful accounts............. 17,733 18,081
Accrued utility revenues........................... 6,662 6,523
Fuel, materials and supplies, at average cost...... 3,621 3,312
Prepayments........................................ 2,206 1,890
Other.............................................. 441 326
--------- ---------
Total current assets............................. 30,901 30,216
--------- ---------
Deferred Charges
Demand side management programs.................... 16,409 18,367
Environmental proceedings costs.................... 7,991 7,893
Purchased power costs.............................. 9,163 8,433
Other.............................................. 9,661 8,258
--------- ---------
Total deferred charges........................... 43,224 42,951
--------- ---------
Non-Utility
Cash and cash equivalents.......................... 511 76
Other current assets............................... 3,979 4,055
Property and equipment............................. 11,226 11,478
Intangible assets.................................. 2,555 2,580
Equity investment in energy-related businesses..... 12,494 10,999
Other assets....................................... 9,162 8,680
--------- ---------
Total non-utility assets......................... 39,927 37,868
--------- ---------
Total Assets...........................................$324,539 $313,282
========= =========
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION December 31
1996 1995
--------- ---------
(In thousands)
CAPITALIZATION AND LIABILITIES
Capitalization (See Capitalization Data)
Common Stock Equity
Common stock..................................... $16,790 $16,168
Additional paid-in capital....................... 68,226 64,206
Retained Earnings................................ 26,916 26,412
Treasury stock, at cost.......................... (378) (378)
--------- ---------
Total common stock equity...................... 111,554 106,408
Redeemable cumulative preferred stock.............. 19,310 8,930
Long-term debt, less current maturities ........... 94,900 91,134
--------- ---------
Total capitalization........................... 225,764 206,472
--------- ---------
Capital Lease Obligation .............................. 9,006 9,778
--------- ---------
Current Liabilities
Current maturuties of long-term debt............... 3,034 7,833
Short-term debt.................................... 1,016 8,416
Accounts payable, trade, and accrued liabilities... 6,140 5,529
Accounts payable to associated companies........... 6,621 7,011
Dividends declared................................. 381 194
Customer deposits.................................. 689 816
Taxes Accrued...................................... 986 571
Interest accrued................................... 1,382 1,847
Other.............................................. 788 412
--------- ---------
Total current liabilities...................... 21,037 32,629
--------- ---------
Deferred Credits
Accumulated deferred income taxes.................. 26,726 25,292
Unamortized investment tax credits................. 4,825 5,107
Other.............................................. 23,417 21,642
--------- ---------
Total deferred credits......................... 54,968 52,041
--------- ---------
Non-Utility
Current liabilities................................ 1,752 1,124
Other liabilities.................................. 12,012 11,238
--------- ---------
Total non-utility liabilities.................. 13,764 12,362
--------- ---------
Total Capitalization and Liabilities...................$324,539 $313,282
========= =========
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 1996 1995 1996 1995
----------- ---------- ---------- --------- ---------
(In thousands)
Common Stock,$3.33 1/3 par value (Note C).......................... 10,000,000 5,037,143 4,850,496 $16,790 $16,168
========= =========
-----------------------------------------------------------------------------------------------------------------
Outstanding
Authorized Issued 1996 1995 1996 1995
---------- ----------- ---------- ---------- --------- ---------
(In thousands)
Redeemable Cumulative Preferred Stock,
$100 par value (Note D)
4.75%,Class B, redeemable at
$101 per share........................................ 15,000 15,000 2,850 3,000 $285 $300
7%,Class C, redeemable at
$101 per share........................................ 15,000 15,000 4,650 5,100 465 510
9.375%,Class D,Series 1,
redeemable at $101 per share.......................... 40,000 40,000 9,600 11,200 960 1,120
8.625%,Class D,Series 3,
redeemable at $103.835 per share...................... 70,000 70,000 56,000 70,000 5,600 7,000
7.32%,Class E,Series 1,................................. 200,000 120,000 120,000 -- 12,000 --
--------- ---------
Total Preferred Stock...................................... $19,310 $8,930
========= =========
LONG-TERM DEBT (Note E) 1996 1995
--------- ---------
(In thousands)
First Mortgage Bonds
5 1/8% Series due 1996........................................................................................$ -- $3,000
6.84% Series due 1997 - Cash sinking fund,$1,333,000
annually.................................................................................................. 1,334 2,667
7% Series due 1998............................................................................................ 3,000 3,000
10.7% Series due 2000......................................................................................... -- 9,000
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.................................................................................................. 13,600 15,300
7.05% Series due 2006......................................................................................... 4,000 --
7.18% Series due 2006......................................................................................... 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................................................................................ 97,934 98,967
Less Current Maturities (due within one year)................................................................. 3,034 7,833
--------- ---------
Total Long-term Debt, Net....................................................................................... $94,900 $91,134
========= =========
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 82,500 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, which supplies propane to 10,000 customers in
Vermont and New Hampshire, and Mountain Energy, Inc., which invests in energy
generation and efficiency projects across the United States. In 1996, the
Company's wholly-owned, unregulated subsidiary, Green Mountain Resources Inc.,
was created to participate, along with the wholly-owned subsidiaries of three
energy companies -- Hydro-Quebec, Consolidated Natural Gas Company, and
Noverco, Inc. - in pilot programs in New Hampshire and Massachusetts to test
the viability of retail electric competition through a limited liability
company (Green Mountain Energy Partners L.L.C.). 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,
--------------------------------
1996 1995
---- ----
(In thousands)
Revenues . . . . . . . . . . . . . . . $11,997 $11,905
Expenses. . . . . . . . . . . . . . . . 11,207 10,416
------- -------
Net Income . . . . . . . . . . . . . . $ 790 $ 1,489
======= =======
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. Criteria 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 writeoff 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, 1996,
based upon the regulatory environment within which the Company currently
operates, SFAS 121 did not have a material impact on the Company's financial
position or results of operations. 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.
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:
1996 1995 1994
---- ---- ----
(In thousands)
Interest . . . . . . . . . . . . . . . . $8,104 $7,940 $7,714
Income Taxes (Net of refunds) . . . . . $3,727 $2,949 $3,088
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 Company's retirements.
The annual depreciation provision was approximately 3.6 percent of total
depreciable property at the beginning of each year 1996, 1995 and 1994.
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 certain purchased power costs related to its obligations
under the Hydro-Quebec contracts.
At December 31, 1996, other deferred charges totaled $9.7 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.
9. Major Customers. The Company had one major retail customer, IBM,
metered at two locations, that accounted for 13.2, 12.9 and 13.7 percent of
operating revenues in 1996, 1995 and 1994, respectively.
10. Pension and Retirement Plans. The Company has a defined benefit
pension plan covering substantially all of its employees. The retirement
benefits are based on the employees' level of compensation and length of
service. The Company's policy is to fund all pension costs accrued. The
Company records annual expense based on amounts funded in accordance with
methods approved in the rate-setting process.
Net pension costs reflect the following components and assumptions:
1996 1995 1994
---- ---- ----
(Dollars in thousands)
Service cost-benefits earned during the period . $ 689 $ 687 $ 768
Interest cost on projected benefit obligations . 1,912 1,671 1,633
Actual return on plan assets . . . . . . . . . . (4,383) (6,447) (1,296)
Net amortization and deferral . . . . . . . . . . 1,756 4,232 (906)
Effect of voluntary retirement program . . . . . 416 765 ---
Adjustment due to actions of regulator . . . . . (366) (878) (174)
------- ------- -------
Net periodic pension cost funded and recognized . $ 24 $ 30 $ 25
======= ======= =======
Assumptions used to determine pension costs and the related benefit obligation
in 1996, 1995 and 1994 were:
Discount rate . . . . . . . . . . . . . . . . 8.0% 8.0% 7.5%*
Rate of increase in future compensation levels 5.0% 5.0% 5.0%
Expected long-term rate of return on assets . 9.0% 9.0% 9.0%
*The discount rate used to determine the accumulated benefit obligation
was 8.0%.
The following table sets forth the plan's funded status as of December 31:
1996 1995 1994
---- ---- ----
(In thousands)
Actuarial present value of benefit obligations:
Accumulated benefit obligations,
including vested benefits of $21,146,
$19,107 and $18,184, respectively . . . . ($21,376) ($19,431) ($18,479)
========= ======== ========
Projected benefit obligations for
service rendered to date . . . . . . . . ($25,615) ($21,974) ($21,363)
Plan assets at fair value . . . . . . . . . . 31,286 28,685 24,171
--------- --------- ---------
Assets in excess of projected
benefit obligations . . . . . . . . . . . . 5,671 6,711 2,808
Unrecognized net gain from past
experience different from that assumed . . (4,734) (5,188) (285)
Prior service cost not yet recognized in net
periodic pension cost . . . . . . . . . . . 1,474 1,506 1,642
Unrecognized net asset at transition
being recognized over 16.47 years . . . . . (1,477) (1,706) (1,934)
Adjustment due to actions of regulator . . . . (934) (1,323) (2,231)
-------- -------- -------
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, 1996, 1995 and 1994 were
$494,000, $397,000 and $381,000, respectively, under this plan. This plan is
funded in part through insurance contracts.
11. Postretirement Health Care Benefits. The Company provides certain
health care benefits for retired employees and their dependents. Employees
become eligible for these benefits if they reach normal retirement age while
working for the Company. The Company accrues the cost of these benefits
during the service life of covered employees.
Accrued postretirement health care expenses are recovered in rates if
those expenses are funded. In order to maximize the tax deductible
contributions that are allowed under IRS regulations, the Company amended its
pension plan to establish a 401-h subaccount and established separate VEBA
trusts for its union and non-union employees. The plan assets consist
primarily of cash equivalent funds, fixed income securities and equity
securities.
Net postretirement benefits costs for 1996 reflect the following
components and assumptions:
1996 1995 1994
---- ---- ----
(In thousands)
Accumulated postretirement benefit obligation:
Current retirees . . . . . . . . . . . . ($ 4,563) ($ 4,594) ($ 3,497)
Participants currently eligible . . . . (772) (681) (1,863)
All others . . . . . . . . . . . . . . . (3,837) (3,384) (3,785)
Total accumulated postretirement benefit
obligation . . . . . . . . . . . . . . . (9,172) (8,659) (9,145)
Plan assets at fair value . . . . . . . . . 6,327 5,465 3,433
Accumulated postretirement benefit
obligation in excess of plan assets . . (2,845) (3,194) (5,712)
Unrecognized prior service cost . . . . . . (867) (929) ---
Unrecognized transition obligation . . . . 5,630 5,982 6,485
Unrecognized net gain . . . . . . . . . . . (1,879) (1,687) (1,777)
-------- ------- --------
Prepaid (accrued) postretirement benefit
cost . . . . . . . . . . . . . . . . . . $ 39 $ 172 ($1,004)
======= ======= ========
Net periodic postretirement benefit cost for 1996 includes the following
components:
1996 1995 1994
---- ---- ----
(In thousands)
Service cost . . . . . . . . . . . . . . . . $ 247 $ 224 $ 407
Interest cost . . . . . . . . . . . . . . . 698 697 864
Actual return on plan assets . . . . . . . . (870) (586) (127)
Deferred asset loss/(gain) . . . . . . . . . 407 264 (107)
Recognition of transition obligation,
net of amortization . . . . . . . . . . . 245 234 361
------- ----- -------
Total net periodic postretirement
benefit cost . . . . . . . . . . . . . $ 727 $ 833 $ 1,398
======= ====== =======
Assumptions used to determine postretirement benefit costs and the
related benefit obligation were:
1996 1995 1994
---- ---- ----
Discount rate to determine postretirement
benefit costs . . . . . . . . . . . . . . 8.0% 8.5% 7.5%
Discount rate to determine postretirement
benefit obligation . . . . . . . . . . . . 8.0% 8.5% 8.5%
Expected long-term rate of return on assets 8.5% 7.5% 7.5%
For measurement purposes, a 6.0 percent annual rate of increase in the
per capita cost of covered benefits was assumed for 1996; 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, 1996 by $1.4 million and
the aggregate of the service and interest components of net periodic
postretirement benefit cost for the year ended December 31, 1996 by $211,000.
12. Fair Value of Financial Instruments. If the first mortgage bonds and
preferred stock outstanding at December 31, 1996 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, 1996 balance sheet by 3 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, 1996, the Company had other
deferred credits and long-term liabilities of $23.4 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.
15. Reclassification. Certain items on the prior years' financial
statements have been reclassified for consistent presentation with the current
year.
B. INVESTMENTS IN ASSOCIATED COMPANIES
The Company accounts for investments in the following companies by the
equity method:
Percent Ownership Investment in Equity
at December 31, 1996 December 31,
-------------------- --------------------
1996 1995
---- ----
(In thousands)
VELCO - Common . . . . . . . . . 29.5% $ 1,834 $ 1,811
- Preferred . . . . . . . 30.0% 1,118 1,278
----- -----
Total VELCO . . . . . . . . . . 2,952 3,089
Vermont Yankee - Common . . . . 17.9% 9,768 9,631
New England Hydro-Transmission -
Common . . . . . . . . . . 3.18% 1,205 1,296
New England Hydro-Transmission
Electric - Common . . . . . 3.18% 1,891 2,008
------- -------
$15,816 $16,024
======= =======
Undistributed earnings in associated companies totaled $714,000 at
December 31, 1996.
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 $7.7 million, $7.6 million
and $7.9 million for the years 1996, 1995 and 1994, 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,
-------------------------
1996 1995 1994
---- ---- ----
(In thousands)
Company's equity in net income . . . . . . . $ 383 $ 377 $ 386
======= ======= =======
Total assets . . . . . . . . . . . . . . . . $74,065 $71,668 $69,724
Less:
Liabilities and long-term debt . . . . . 64,159 61,238 58,850
------- ------- -------
Net assets . . . . . . . . . . . . . . . . . $9,906 $10,430 $10,874
======= ======= =======
Company's equity in net assets . . . . . . . $2,952 $ 3,089 $ 3,232
======= ======= =======
Vermont Yankee. The Company is responsible for 17.3 percent of Vermont
Yankee's expenses of operations, including costs of equity capital and
estimated costs of decommissioning, and is entitled to a similar share of the
power output of the nuclear plant, which has a net capacity of 531 megawatts.
Vermont Yankee's current estimate of decommissioning costs is approximately
$366 million, of which $160 million has been funded. At December 31, 1996,
the Company's portion of the net unfunded liability was $36 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 1996, the Company incurred $28.5 million in Vermont Yankee annual
capacity charges, which included $1.8 million for interest charges. The
Company's share of Vermont Yankee's long-term debt at December 31, 1996 was
$13.8 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
retrospective 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 covers all workers employed at nuclear facilities
prior to January 1, 1988, for bodily injury claims. Vermont Yankee has
purchased a master worker insurance policy with limits of $200 million with
one automatic reinstatement of policy limits to cover workers employed on or
after January 1, 1988. Vermont Yankee's estimated contingent liability for a
retrospective premium on the master worker policy as of December 1995 is
$3.0 million. The secondary financial protection program referenced above
provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited
(NEIL) 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
$13.3 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,
-------------------------
1996 1995 1994
---- ---- ----
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . . $181,715 $180,437 $162,757
Net income applicable to common stock . 6,985 6,790 6,588
Company's equity in net income . . . . . 1,232 1,171 1,143
Total assets . . . . . . . . . . . . . . . $565,000 $531,293 $512,142
Less:
Liabilities and long-term debt . . . . . 510,202 477,350 457,669
-------- -------- --------
Net assets . . . . . . . . . . . . . . . . $ 54,798 $ 53,943 $ 54,473
======== ======== ========
Company's equity in net assets . . . . . . $ 9,768 $ 9,631 $ 9,766
======== ======== ========
C. COMMON STOCK EQUITY
The Company maintains a Dividend Reinvestment and Stock Purchase Plan
(DRIP) under which 509,139 shares were reserved and unissued at December 31,
1996. The Company also funds an Employee Savings and Investment Plan (ESIP).
At December 31, 1996, there were 149,900 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. 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 1996, 7,035 shares of common stock were awarded under this
program. At December 31, 1996, there were 31,039 shares reserved and unissued
under the Compensation Program.
Changes in common stock equity for the years ended December 31, 1994,
1995 and 1996 are as follows:
Common Stock Treasury Stock
------------------------ Paid-in Retained ------------------------ Stock
Shares Amount Capital Earnings Shares Amount Equity
------ ------ ------- -------- ------ ------ ------
(Dollars in thousands)
BALANCE, December 31, 1993............... 4,536,042 $15,120 $57,178 $25,229 15,856 ($378) $97,149
Common Stock Issuance:
DRIP................................... 109,959 367 2,472 2,839
ESIP................................... 31,511 105 728 833
Net Income............................... 11,002 11,002
Cash Dividends on Capital Stock:
Common Stock -$2.12 per share..... (9,713) (9,713)
Preferred Stock -$4.75 per share..... (18) (18)
-$7.00 per share..... (38) (38)
-$9.375 per share.... (131) (131)
-$8.625 per share.... (604) (604)
------------------------------------------------------------------------------------
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
====================================================================================
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, $20.5 million of retained earnings were free
of restrictions at December 31, 1996.
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, 1996, $302,000 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 the years
1997-1999, $1,640,000 for 2000 and $235,000 for 2001.
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 $2.877 per share until September 1, 1997; $1.919 per share from
September 1, 1997 to September 1, 1998; and $0.916 per share from September 1,
1998 to September 1, 1999, after which there is no redemption premium.
In October 1996, the Company issued $12.0 million of its 7.32 percent,
Class E, Series 1, preferred stock.
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)
1997 . . . . . . . . . . . . . . $1,700 $1,334 $3,034
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
Non-Utility. At December 31, 1996, Green Mountain Propane Gas Company,
the Company's propane subsidiary, had long-term debt of $2,900,000, 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
efficiency projects, had unsecured long-term debt of $1,749,103. The annual
sinking fund requirements and maturities for the next four years are:
Sinking
Funds Maturities Total
------- ---------- -----
(In thousands)
1997 . . . . . . . . . . . . . $1,167 $ --- $1,167
1998 . . . . . . . . . . . . . 1,167 --- 1,167
1999 . . . . . . . . . . . . . 167 900 1,067
2000 . . . . . . . . . . . . . 83 1,166 1,249
F. SHORT-TERM DEBT
Utility. At December 31, 1996, the Company had lines of credit with six
banks totaling $40.0 million, with borrowings outstanding of $1.0 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 1/8 to 1/4 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 on December
31, 1996 and December 31, 1995 was 5.7 percent and 6.3 percent, respectively.
Non-Utility. At December 31, 1996, Green Mountain Propane Gas Company,
the Company's propane subsidiary, had a line of credit with a bank for
$1.5 million, with $275,000 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, 1996 and 1995, the net regulatory assets were $1,194,000 and
$690,000, respectively.
The temporary differences which gave rise to the net deferred tax
liability at December 31, 1996 and December 31, 1995, were as follows:
At December 31, At December 31,
1996 1995
--------------- ---------------
(In thousands)
Deferred Tax Assets
Contributions in aid of construction $ 7,094 $ 6,361
Deferred compensation and
post-retirement benefits . . . . . . 2,944 2,931
Alternative minimum tax credit . . . (552) (661)
Excess deferred taxes . . . . . . . . 1,891 1,990
Unamortized investment tax credits . 2,025 2,151
Other . . . . . . . . . . . . . . . . 2,719 2,982
------- -------
$16,121 $15,754
------- -------
Deferred Tax Liabilities
Property-related and other . . . . . $30,553 $28,009
Demand side management costs . . . . 5,856 6,685
Deferred purchased power costs . . . 3,716 2,901
Reversal of previously flowed-through
tax depreciation . . . . . . . . . 2,133 2,816
AFUDC equity basis adjustment . . . . 589 635
-------- ---------
42,847 41,046
-------- ---------
Net accumulated deferred income tax
liability . . . . . . . . . . . . . ($26,726) ($25,292)
========= =========
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,
--------------------------
1996 1995 1994
---- ---- ----
(In thousands)
Net change in deferred income tax
liability per above table . . . . . . . . . $1,434 $3,210 $1,080
Change in income tax related regulatory
assets and liabilities. . . . . . . . . . . 504 503 505
Change in alternative minimum tax credit . . 109 168 (1,578)
IRS audit adjustment, 1989 - 90 . . . . . . . -- 255 --
------ ------ ------
Deferred income tax expense for the period . $2,047 $4,136 $ 7
====== ====== ======
The components of the provision for income taxes are as follows:
Year Ended December 31,
------------------------
1996 1995 1994
---- ---- ----
(In thousands)
Current state income taxes . . . . . . . $ 990 $ 365 $1,205
Deferred state income taxes . . . . . . 459 897 70
Current federal income taxes . . . . . . 3,708 1,359 4,466
Deferred federal income taxes . . . . . 1,588 3,239 (63)
Investment tax credits -- net . . . . . (282) (282) (283)
------- ------- -------
Income taxes charged to operations . . . $6,463 $5,578 $5,395
======= ======= =======
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,
---------------------------
1996 1995 1994
---- ---- ----
(Dollars in thousands)
Income before income tax . . . . . . . $18,422 $17,081 $16,398
Federal statutory rate . . . . . . . . 34% 34% 34%
Computed "expected" federal
income taxes . . . . . . . . . . . . $ 6,263 $ 5,808 $ 5,575
Increase (decrease) in taxes
resulting from:
Tax versus book depreciation . . . . 327 327 327
Dividends received and paid credit . (524) (616) (499)
AFUDC - equity funds . . . . . . . . (59) (9) (89)
Amortization of ITC . . . . . . . . (282) (282) (283)
State tax benefit . . . . . . . . . (493) (429) (433)
Excess deferred taxes . . . . . . . (60) (60) (60)
Taxes attributable to subsidiaries . (140) (401) (268)
Other . . . . . . . . . . . . . . . (18) (22) (150)
------- ------- -------
Total federal income taxes . . . . . . $5,014 $4,316 $4,120
======= ======= =======
Effective federal income tax rate . . 27.2% 25.3% 25.1%
Non-Utility. The Company's non-utility subsidiaries had accumulated
deferred income taxes of $4.7 million on their balance sheets at December 31,
1996, largely attributable to property-related transactions.
The components of the provision for income taxes for the non-utility
operations are:
Year Ended December 31,
-----------------------
1996 1995 1994
---- ---- ----
(In thousands)
State income taxes . . . . . . . . . . $154 $165 $123
Federal income taxes . . . . . . . . . 207 613 444
Investment tax credits . . . . . . . . (45) (45) (45)
----- ----- -----
Income taxes charged to operations . . $316 $733 $522
===== ===== =====
Total federal income taxes differ from the amounts computed by applying
the statutory rate to income before taxes, primarily attributable to state tax
benefits.
The effective federal income tax rates for the non-utility operations
were 22.4 percent, 29.7 percent, and 29.0 percent for the years ended December
31, 1996, 1995 and 1994, respectively.
H. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following quarterly financial information, in the opinion of
management, includes all adjustments necessary to a fair statement of results
of operations for such periods. Variations between quarters reflect the
seasonal nature of the Company's business and the timing of rate changes.
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
1995 Quarter Ended
------------------
March June Sept. Dec. Total
----- ---- ----- ---- -----
(Amounts in thousands, except per share)
Operating Revenues . . . . . . $40,023 $37,127 $39,781 $44,613 $161,544
Operating Income . . . . . . . 4,482 2,770 3,826 4,217 15,295
Net Income . . . . . . . . . . 3,227 1,992 3,071 3,213 11,503
Net Income Applicable to
Common Stock . . . . . . . . 3,033 1,798 2,877 3,024 10,732
Earnings per Average Share of
Common Stock . . . . . . . . $0.65 $0.38 $0.60 $0.63 $2.26
Weighted Average Number of
Common Shares Outstanding . 4,680 4,721 4,771 4,815 4,747
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.
On December 31, 1996, the VPSB issued an Order which proposed the
commencement of competitive retail sales of electricity in early 1998. The
Vermont General Assembly is debating proposals that would allow retail
competition in Vermont in 1998.
The Company, Central Vermont Public Service Corporation, representatives
of the Governor of Vermont and the Department are in the process of
negotiating a Memorandum of Understanding that would outline agreed-upon
positions among the parties relative to the numerous issues involving the
industry restructuring.
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 Marsh 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 Marsh 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 Marsh 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 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 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. On December 1, 1994, the
Company, and two other PRPs, New England Electric System (NEES) and Vermont
Gas Systems (VGS), entered into a confidential 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 1991, the Company brought suit against eight previous
insurers seeking recovery of unrecovered past costs and indemnity against
future liabilities associated with environmental problems at the site.
Discovery in the case, which was previously subject to a stay, is proceeding
and is largely complete. A trial in this litigation is scheduled for late
1997. The Company has reached confidential final settlements with two of the
defendants in this litigation and has obtained summary judgment declaring one
insurer's duty to defend.
The Company has deferred amounts received, under confidential settlement,
from third parties pending resolution of the Company's ultimate liability with
respect to the site and rate recognition of that liability. 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 Marsh 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 Pine Street Marsh related
costs, the Company and the Department reached agreements in these cases that
the full amount of Pine Street Marsh 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 Marsh related expenditures
referred to above.
Management expects to seek and (assuming recovery consistent with the
previous regulatory treatment set forth above) receive ratemaking treatment
for unreimbursed costs incurred beyond the amounts for which ratemaking
treatment has been received.
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. After reviewing the Company's current accounting policies and
ratemaking treatment, management does not believe that this SOP will have a
material adverse effect on the Company's financial position or results of
operations upon adoption.
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 1997 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, 1996, as
follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- -------- ------- ------------
(In %) (In MW) (In thousands)
Highgate . . . . . . . . . . 33.8 67.6 $ 9,734 $3,056
McNeil . . . . . . . . . . . 11.0 5.9 $ 8,633 $3,323
Stony Brook (No. 1) . . . . . 8.8 31.0 $10,039 $5,919
Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,384 $1,309
Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 368
(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. 1994 Retail Rate Case - On September 26, 1994, the
Company filed a request with the VPSB to increase retail rates by 13.9
percent. The increase was needed primarily to cover the rising cost of
existing power sources, the cost of new power sources that the Company secured
to replace power supply that will be lost in the near future, and the cost of
energy efficiency programs that the Company implemented for its customers.
The Company, the Department and the other parties in the proceeding reached a
settlement agreement providing for a 9.25 percent retail rate increase
effective June 15, 1995, and a target return on equity for utility operations
of 11.25 percent. In the event that the target return on equity is exceeded,
the Company would accelerate the amortization of certain demand side
management expenditures in the next year for which rate recovery otherwise
would have been sought. The agreement was approved by the VPSB on June 9,
1995.
1995 Retail Rate Case - In September 1995, the Company filed a 12.7
percent retail rate increase to cover higher power supply costs, to support
additional investment in plant and equipment, to fund expenses associated with
the Pine Street Marsh site, and to cover higher costs of capital. Early in
1996, the Company settled this rate case with the Department and other
parties, enabling the Company to conduct its business and achieve satisfactory
financial results without the drain on human resources and the additional
costs that rate litigation imposes.
The settlement became possible when the Company negotiated a new
arrangement with Hydro-Quebec that will reduce the Company's net power-supply
costs below the amounts anticipated in the rate increase request. The
settlement provided: projected additional annual revenues of $7.6 million; an
overall increase in retail rates of 5.25 percent effective June 1, 1996;
target return on equity for utility operations of 11.25 percent (with a
continuation of the amortization of any amount in excess of the target rate of
return in the following year, as described above); and recovery of $1.3
million of costs associated with the Pine Street site, amortized over five
years. The VPSB approved the settlement in an order dated May 23, 1996. In
1996, the rate of return on utility operations was 11.8% and in 1995 was
11.3%. An accounting order received from the VPSB on December 31, 1996
continues the limitation on return on equity from utility operations through
December 31, 1997.
6. 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, 1996, the present
value of the Company's obligation is $9.0 million.
Projected future minimum payments under the Phase II support agreements are as
follows:
Year ending December 31,
1997 . . . . . . . . . . . $ 474,013
1998 . . . . . . . . . . . 474,013
1999 . . . . . . . . . . . 474,013
2000 . . . . . . . . . . . 474,013
2001 . . . . . . . . . . . 474,013
Total for 2002-2020 . . . 6,636,181
----------
$9,006,246
==========
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 1996 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 . . . . . 9.5% 4.0% 17.3%
Contract period . . . . . . . . . . 1968-1998 (1) (2)
Company's annual share of:
Interest . . . . . . . . . . . . . $ 650 $ 232 $ 1,829
Other debt service . . . . . . . . 365 307 ---
Other capacity . . . . . . . . . . 1,953 319 26,697
------ ------ -------
Total annual capacity . . . . . . . $2,968 $ 858 $28,526
====== ====== =======
Company's share of long-term debt . $ 907 $4,538 $13,845
====== ====== =======
(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
$3 million (in 1994 dollars) worth of research and development work from
Hydro-Quebec over the four-year period, and made a $7.5 million (in 1994
dollars) cash payment to Hydro-Quebec in 1995. The Company has exercised an
option to purchase $1 million worth of additional research and development
work and the $7.5 million cash payment was reduced accordingly. 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 four-year period covered
by the arrangement, combined unit costs will be lowered from 6.4 to 5.3 cents
per kilowatt-hour, reducing unit costs by 17 percent and saving $34.1 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 agreements (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 . . $10,584 $7,190
(1996) (1996)
$15,100 $10,416
(1997-2015)* (1997-2015)*
Annual Capacity Charge . $9,637 $1,712
(1996) (1996)
$17,124 $10,892
(1997-2015)* (1997-2015)*
Average Cost per KWH . . 4.7 cents 3.0 cents
(1996) ** (1996)**
7.0 cents 6.4 cents
(1997-2015)*** (1997-2015)***
* 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 agreement negotiated in January 1996 (the January 1996
Agreement), Hydro-Quebec provided a cash payment to the Company of $3.0
million in 1996 and will provide a 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 an alternate transmission path, 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 1996, the Company purchased or sold to others, 87.8% of
the minimum purchase obligation for that year. The remainder of the
requirement has been rolled over into the 1997 calendar year energy purchase
obligation.
Under a Memorandum of Understanding negotiated in November 1996, Hydro-
Quebec will provide cash payments 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, 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 the November 1996 Agreement 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.
Consistent with allowed ratemaking treatment, the $8.0 million payment
will be recognized in income in the third and fourth quarters of 1997.
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, 1996 and 1995, and the related
consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1996. These financial statements
are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of
Green Mountain Power Corporation as of December 31, 1996 and 1995, and
the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
Boston, Massachusetts
January 31, 1997
Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1996, 1995 and 1994
Additions
Balance at ------------------------------- Balance at
Beginning of Charged to Charged to End of
Description Period Cost & Expenses Other Accounts Deductions Period
- ----------------------------------- ------------- -------------- -------------- ------------- -------------
Pine Street Marsh (1)
1996................................. $0 $ -- $ -- $ -- $0
1995................................. $0 $ -- $ -- $ -- $0
1994................................. $684,430 $ -- $ -- $684,430 $0
Injuries and Damages
1996................................. $103,301 $572,000 $ -- $437,409 $237,892
1995................................. $513,720 $38,000 $ -- $448,419 $103,301
1994................................. $105,660 $35,000 $394,430 $21,370 $513,720
Bad Debt Reserve (3)
1996................................. $417,684 $677,272 $72,344 (2) $669,276 $498,024
1995................................. $402,923 $371,564 $48,696 (2) $405,499 $417,684
1994................................. $639,853 $243,974 $53,076 (2) $533,980 $402,923
(1) See Note I-1 of the Notes to Consolidated Financial Statements.
(2) Represents collection of accounts previously written off.
(3) Includes non-utility bad debt reserve.
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
Filed
Herewith
On Page
Item 14(a)(1). The financial statements and financial 37
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 Docker 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
February 10, 1997.
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-a-17 Form 10-Q Sept. 1995
to Registration Statement No. 33-59383. (1-8291)
10-a Form of Insurance Policy issued by Pacific 10-a 33-8146
Insurance Company, with respect to
indemnification of Directors and Officers.
10-b-1 Firm Power Contract dated September 16, 1958, 13-b 2-27300
between the Company and the State of Vermont
and supplements thereto dated September 19,
1958; November 15, 1958; October 1, 1960 and
February 1, 1964.
10-b-2 Power Contract, dated February 1, 1968, between 13-d 2-34346
the Company and Vermont Yankee Nuclear Power
Corporation.
10-b-3 Amendment, dated June 1, 1972, to Power Contract 13-f-1 2-49697
between the Company and Vermont Yankee Nuclear
Power Corporation.
10-b-3 Amendment, dated April 15, 1983, to Power 10-b-3(a) 33-8164
(a) Contract between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-3 Additional Power Contract, dated 10-b-3(b) 33-8164
(b) February 1, 1984,between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-4 Capital Funds Agreement, dated February 1, 13-e 2-34346
1968, between the Company and Vermont
Yankee Nuclear Power Corporation.
10-b-5 Amendment, dated March 12, 1968, to Capital 13-f 2-34346
Funds Agreement between the Company and
Vermont Yankee Nuclear Power Corporation.
10-b-6 Guarantee Agreement, dated November 5, 1981, 10-b-6 2-75293
of the Company for its proportionate share
of the obligations of Vermont Yankee Nuclear
Power Corporation under a $40 million loan
arrangement.
10-b-7 Three-Party Power Agreement among the Company, 13-i 2-49697
VELCO and Central Vermont Public Service
Corporation dated November 21, 1969.
10-b-8 Amendment to Exhibit 10-b-7, dated June 1, 1981. 10-b-8 2-75293
10-b-9 Three-Party Transmission Agreement among the 13-j 2-49697
Company, VELCO and Central Vermont Public
Service Corporation, dated November 21, 1969.
10-b-10 Amendment to Exhibit 10-b-9, dated June 1, 1981. 10-b-10 2-75293
10-b-12 Unit Purchase Contract dated February 10, 1968, 13-h 2-34346
between the Company and Vermont Electric
Power Company, Inc., for purchase of
"Merrimack" power from Public Service
Company of New Hampshire.
10-b-14 Agreement with Central Maine Power Company et 5.16 2-52900
al, to enter into joint ownership of Wyman
plant, dated November 1, 1974.
10-b-15 New England Power Pool Agreement as amended to 4.8 2-55385
November 1, 1975.
10-b-16 Bulk Power Transmission Contract between the 13-v 2-49697
Company and VELCO dated June 1, 1968.
10-b-17 Amendment to Exhibit 10-b-16, dated June 1, 1970. 13-v-i 2-49697
10-b-20 Power Sales Agreement, dated August 2, 1976, as 10-b-20 33-8164
amended October 1, 1977, and related
Transmission Agreement, with the Massachusetts
Municipal Wholesale Electric Company.
10-b-21 Agreement dated October 1, 1977, for Joint 10-b-21 33-8164
Ownership, Construction and Operation of the
MMWEC Phase I Intermediate Units, dated
October 1, 1977.
10-b-28 Contract dated February 1, 1980, providing for 10-b-28 33-8164
the sale of firm power and energy by the Power
Authority of the State of New York to the
Vermont Public Service Board.
10-b-30 Bulk Power Purchase Contract dated April 7, 10-b-32 2-75293
1976, between VELCO and the Company.
10-b-33 Agreement amending New England Power Pool 10-b-33 33-8164
Agreement dated as of December 1, 1981,
providing for use of transmission inter-
connection between New England and
Hydro-Quebec.
10-b-34 Phase I Transmission Line Support Agreement 10-b-34 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
VETCO and participating New England utilities
for construction, use and support of Vermont
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-35 Phase I Terminal Facility Support Agreement 10-b-35 33-8164
dated as of December 1, 1981, and Amendment
No. 1 dated as of June 1, 1982, between
New England Electric Transmission Corporation
and participating New England utilities for
construction, use and support of New Hampshire
facilities of transmission interconnection
between New England and Hydro-Quebec.
10-b-36 Agreement with respect to use of Quebec 10-b-36 33-8164
Interconnection dated as of December 1, 1981,
among participating New England utilities
for use of transmission interconnection
between New England and Hydro-Quebec.
10-b-39 Vermont Participation Agreement for Quebec 10-b-39 33-8164
Interconnection dated as of July 15, 1982,
between VELCO and participating Vermont
utilities for allocation of VELCO's rights
and obligations as a participating New
England utility in the transmission inter-
connection between New England and Hydro-Quebec.
10-b-40 Vermont Electric Transmission Company, Inc. 10-b-40 33-8164
Capital Funds Agreement dated as of July 15,
1982, between VETCO and VELCO for VELCO to
provide capital to VETCO for construction of
the Vermont facilities of the transmission
inter-connection between New England and
Hydro-Quebec.
10-b-41 VETCO Capital Funds Support Agreement dated as 10-b-41 33-8164
of July 15, 1982, between VELCO and 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-3 Green Mountain Power Corporation Management 10-d-3 Form 10-K 1991
Incentive Plan. (1-8291)
10-d-4 Green Mountain Power Corporation Officer 10-d-4 Form 10-K 1991
Insurance Plan. (1-8291)
10-d-4a Green Mountain Power Corporation Officers' 10-d-4a Form 10-K 1990
Insurance Plan as amended. (1-8291)
10-d-5a Severance Agreements with 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-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
*10-d-19 Severance Agreement with R. J. Griffin 10-d-19
*10-d-20 Severance Agreement with K. W. Hartley 10-d-20
*21 Subsidiaries of the Registrant
*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 December 11, 1996 setting forth the
computation of the Company's ratio of earnings to fixed charges and preferred
stock dividends.
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/ Douglas G. Hyde
Douglas G. Hyde, President
and Chief Executive Officer
Date: March 28, 1997
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/ Douglas G. Hyde President and Director March 28, 1997
Douglas G. Hyde (Principal Executive Officer)
/s/ Christopher L. Dutton Vice President, Treasurer and March 28, 1997
Christopher L. Dutton Chief Financial Officer (Principal
Financial Officer)
/s/ Robert J. Griffin Controller March 28, 1997
Robert J. Griffin (Principal Accounting Officer)
*Thomas P. Salmon Chairman of the Board
*Robert E. Boardman )
*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 28, 1997
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 January 31, 1997.
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 37 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
January 31, 1997 /s/ Arthur Andersen LLP