Back to GetFilings.com
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
_X_ Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
___ Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
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)
163 Acorn Lane
Colchester, VT 05446
- -------------------------------------------------------------------
(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 21, 2001, WAS APPROXIMATELY $77,278,643 BASED ON THE
CLOSING PRICE OF $13.84 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 21, 2001, WAS
5,583,717
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders to be held on May 17, 2001, 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.
2
Green Mountain Power Corporation
Form 10-K for the fiscal year ended December 31, 2000
Table of contents Page
Part I, Item 1, Company business 3
Item 2, Property 17
Item 3, Legal Proceedings 19
Item 4, Submission of matters to vote 19
Part II, Item 5, Market related matters 20
Item 6, Five-Year Financial Highlights 22
Item 7, Management's Discussion and Analysis 23
Item 8, Index to Consolidated Financial Statements
and Notes 39
Item 9, Changes and Disagreements with Accountants 72
Items 10 through 13, Certain Officer information 72
Item 14, Exhibits, Financial Statement Schedules, 72
And Reports on Form 8-K
PART I
ITEM 1. BUSINESS
THE COMPANY
Green Mountain Power Corporation (the "Company") is a public utility
operating company engaged in supplying electrical energy in the State of Vermont
in a territory with approximately one quarter of the State's population. We
serve approximately 86,000 customers. The Company was incorporated under the
laws of the State of Vermont on April 7, 1893.
Our sources of revenue for the year ended December 31, 2000 were as
follows:
* 25.2% from residential customers;
* 25.4% from small commercial and industrial customers;
* 16.0% from large commercial and industrial customers;
* 31.9% from sales to other utilities; and
* 1.5% from other sources.
During 2000, our energy resources for retail and wholesale sales of
electricity were obtained as follows:
* 35.8% from hydroelectric sources (3.9% Company-owned, 0.1% New York Power
Authority ("NYPA"), 29.5% Hydro-Quebec and 2.3% small power producers);
* 28.8% from a nuclear generating source (the Vermont Yankee nuclear plant
described below);
* 2.8% from wood;
* 2.7% from oil;
* 2.2% from natural gas; and
* 0.4% from wind.
The remaining 27.3% was purchased on a short-term basis from other
utilities through the Independent System Operator of New England ("ISO"),
formerly the New England Power Pool ("NEPOOL").
In 2000, we purchased 92.8% of the energy required to satisfy our retail
and wholesale sales of electricity (including energy purchased from Vermont
Yankee Nuclear Power Corporation ("Vermont Yankee") and under other long-term
purchase arrangements). See Note K of Notes to Consolidated Financial
Statements("Notes"), Annual Report to Stockholders, 2000 ("Annual Report").
A major source of the Company's power supply is our entitlement to a share
of the power generated by the 531 megawatt (MW) Vermont Yankee nuclear
generating plant owned and operated by Vermont Yankee Nuclear Power Corporation.
We have a 17.9% equity interest in Vermont Yankee. For information concerning
Vermont Yankee, see Power Resources - Vermont Yankee.
The Company participates in NEPOOL, a regional bulk power transmission
organization established to assure reliable and economical power supply in the
Northeast. The ISO was created to manage the operations of NEPOOL in 1999. The
ISO works as a clearinghouse for purchasers and sellers of electricity in the
new deregulated markets. Sellers place bids for the sale of their generation or
purchased power resources and if demand is high enough the output from those
resources is sold. We must purchase additional electricity to meet customer
demand during periods of high usage and to replace energy repurchased by
Hydro-Quebec under an arrangement negotiated in 1997. Our costs to serve demand
during periods of warmer than normal temperatures in summer months and to
replace such energy repurchases by Hydro-Quebec rose substantially after the
market opened to competitive bidding on May 1, 1999. The cost of securing
future power supplies has also risen in tandem with higher summer supply costs.
The Company's principal service territory is an area roughly 25 miles in
width extending 90 miles across north central Vermont between Lake Champlain on
the west and the Connecticut River on the east. Included in this territory are
the cities of Montpelier, Barre, South Burlington, Vergennes and Winooski, as
well as the Village of Essex Junction and a number of smaller towns and
communities. We also distribute electricity in four separate areas located in
southern and southeastern Vermont that are interconnected with our principal
service area through the transmission lines of Vermont Electric Power Company,
Inc. ("VELCO") and others. Included in these areas are the communities of
Vernon (where the Vermont Yankee plant is located), Bellows Falls, White River
Junction, Wilder, Wilmington and Dover. We supply at wholesale a portion of the
power requirements of several municipalities and cooperatives in Vermont. We
are obligated to meet the changing electrical requirements of these wholesale
customers, in contrast to our obligation to other wholesale customers, which is
limited to specified amounts of capacity and energy established by contract.
Major business activities in our service areas include computer assembly
and components manufacturing (and other electronics manufacturing), software
development, granite fabrication, service enterprises such as government,
insurance, regional retail shopping and tourism (particularly winter
recreation), and dairy and general farming.
SEGMENT INFORMATION
The Company has partially sold or disposed of the operations and assets of
Mountain Energy, Inc. ("MEI"), classified as discontinued operations in 1999.
MEI was renamed Northern Water Resources, Inc. in January 2001. Industry
segment information required to be disclosed is presented in Note L of the Notes
to Annual Report.
SEASONAL NATURE OF BUSINESS
Winter recreational activities, longer hours of darkness and heating loads
from cold weather usually cause our peak electric sales to occur in December,
January or February. Our heaviest load in 2000, 323.5 MW, occurred on January
17, 2000.
We charge our customers higher rates for billing cycles in December
through March and lower rates for the remaining months. These are called
seasonally differentiated rates. In order to eliminate the impact of the
seasonally differentiated rates on earnings, we defer some of the revenues from
those four months and account for them in later periods in which we have lower
revenues or higher costs. In prior periods, by deferring certain revenues we
are able to match our revenues to our costs more accurately.
Under this structure, retail electric rates produce average revenues per
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 and Rate Design.
Under NEPOOL market rules implemented in May 1999, the cost basis that had
supported the Company's rate design was eliminated, making the seasonal rate
structure no longer appropriate. A request to eliminate the seasonal rate
structure in all classes of service effective April 2001 was approved by the
Vermont Public Service Board (the "VPSB") in January 2001.
SINGLE CUSTOMER DEPENDENCE
The Company had one major retail customer, IBM, metered at two locations,
that accounted for 11.2 percent, 11.8 percent, and 14.7 percent of total
operating revenues, and 16.5 percent, 16.4 percent and 17.1 percent of the
Company's retail operating revenues in 2000, 1999 and 1998, respectively. IBM's
percent of total revenues in 2000 decreased due to an increase in total
operating revenues as a result of sales for resale pursuant to the Company's
power supply agreement with Morgan Stanley Capital Group, Inc. ("MS"), which is
discussed in greater detail in Management's Discussion and Analysis of Financial
Condition and Results of Operations ("MD and A")-Power Contract Commitments. No
other retail customer accounted for more than 1.0% of our revenue during the
past three years. Under the present regulatory system, the loss of IBM as a
customer would require the Company to seek rate relief to recover the revenues
previously paid by IBM from other customers in an amount sufficient to offset
the fixed costs that IBM had been covering through its payments. See Notes A
and K of the Notes to Annual Report.
Operating statistics for the past five years are presented in the following
table.
GREEN MOUNTAIN POWER CORPORATION
Operating Statistics For the years ended December 31,
2000 1999 1998 1997 1996
----------- ----------- ----------- ----------- -----------
Total capability (MW) . . . . . . . . . . . . . . 411.1 393.2 396.9 416.9 425.8
Net system peak . . . . . . . . . . . . . . . . . 323.5 317.9 312.5 311.5 313.0
----------- ----------- ----------- ----------- -----------
Reserve (MW). . . . . . . . . . . . . . . . . . . 87.6 75.3 84.4 105.4 112.8
=========== =========== =========== =========== ===========
Reserve % of peak . . . . . . . . . . . . . . . . 27.1% 23.7% 27.0% 33.8% 36.0%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . . 1,053,223 1,095,738 972,723 1,073,246 1,192,881
Wind. . . . . . . . . . . . . . . . . . . . . . . 12,246 7,956 - - -
Nuclear . . . . . . . . . . . . . . . . . . . . . 803,303 731,431 607,708 772,030 680,613
Conventional steam. . . . . . . . . . . . . . . . 2,704,427 2,328,267 750,602 560,504 705,331
Internal combustion . . . . . . . . . . . . . . . 35,699 12,312 40,148 4,827 2,674
Combined cycle. . . . . . . . . . . . . . . . . . 73,433 99,962 118,322 104,836 51,162
----------- ----------- ----------- ----------- -----------
Total production. . . . . . . 4,682,331 4,275,666 2,489,503 2,515,443 2,632,662
Less non-firm sales to other utilities. . . . . . 2,573,576 2,152,781 499,409 524,192 663,175
----------- ----------- ----------- ----------- -----------
Production for firm sales . . . . . . . . . . . . 2,108,755 2,122,885 1,990,094 1,991,251 1,969,487
Less firm sales and lease transmissions. . . . . 1,954,898 1,920,257 1,883,959 1,870,914 1,814,371
----------- ----------- ----------- ----------- -----------
Losses and company use (MWH). . . . . . . . . . . 153,857 202,628 106,134 120,337 155,115
=========== =========== =========== =========== ===========
Losses as a % of total production . . . . . . . . 3.29% 4.74% 4.26% 4.78% 5.89%
System load factor (***). . . . . . . . . . . . . 68.8% 80.3% 71.8% 71.6% 69.7%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . . 22.5% 25.6% 39.1% 42.7% 45.3%
Wind. . . . . . . . . . . . . . . . . . . . . . . 0.3% 0.2% 0.0% 0.0% 0.0%
Nuclear . . . . . . . . . . . . . . . . . . . . . 17.1% 17.1% 24.4% 30.6% 25.9%
Conventional steam. . . . . . . . . . . . . . . . 57.8% 54.5% 30.2% 22.3% 26.8%
Internal combustion . . . . . . . . . . . . . . . 0.8% 0.3% 1.6% 0.2% 0.1%
Combined cycle. . . . . . . . . . . . . . . . . . 1.6% 2.3% 4.8% 4.2% 1.9%
----------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0%
=========== =========== =========== =========== ===========
Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . . 558,682 544,447 533,904 549,259 557,726
Commercial & industrial - small . . . . . . . . . 704,126 688,493 665,707 645,331 630,838
Commercial & industrial - large . . . . . . . . . 683,296 664,110 636,436 608,051 584,249
Other . . . . . . . . . . . . . . . . . . . . . . 6,713 3,138 3,476 3,939 2,898
----------- ----------- ----------- ----------- -----------
Total retail sales and lease transmissions. . . . 1,952,817 1,900,188 1,839,522 1,806,581 1,775,712
Sales to Municipals & Cooperatives (Rate W) . . . 2,081 20,069 44,437 64,333 38,660
----------- ----------- ----------- ----------- -----------
Total Requirements Sales. . . . . . . . . . . . . 1,954,898 1,920,257 1,883,959 1,870,914 1,814,371
Other Sales for Resale. . . . . . . . . . . . . . 2,573,576 2,152,781 499,409 524,192 663,175
----------- ----------- ----------- ----------- -----------
Total sales and lease transmissions(MWH) . . . . 4,528,474 4,073,038 2,383,368 2,395,106 2,477,546
=========== =========== =========== =========== ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . . 72,424 71,515 71,301 70,671 70,198
Commercial and industrial small . . . . . . . . . 12,746 12,438 12,170 11,989 11,828
Commercial and industrial large . . . . . . . . . 23 23 23 23 25
Other . . . . . . . . . . . . . . . . . . . . . . 65 66 70 75 75
----------- ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . . . . . 85,258 84,042 83,564 82,758 82,126
=========== =========== =========== =========== ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . . 12.50 12.32 11.56 11.18 10.87
Commercial & industrial - small . . . . . . . . . 10.00 9.88 9.29 9.10 8.96
Commercial & industrial - large . . . . . . . . . 6.51 6.55 6.32 6.22 6.28
----------- ----------- ----------- ----------- -----------
Total retail including lease. . . . . . . . . . . 9.52 9.47 8.96 8.79 8.72
=========== =========== =========== =========== ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . . 7,717 7,617 7,488 7,772 7,945
Revenues including lease revenues . . . . . . . . $ 965 $ 938 $ 865 $ 869 $ 863
(*) MW - Megawatt is one thousand kilowatts.
(**) MWH - Megawatt hour is one thousand kilowatt hours.
(***) Load factor is based on net system peak and firm MWH production less
off-system losses.
EMPLOYEES
As of December 31, 2000, the Company had 197 employees, exclusive of
temporary employees, and our subsidiary, MEI, had five employees. The 101
union employees on strike from January 4, 2001 through January 26, 2001 acted
professionally throughout the three week strike. The Company considers its
relations with employees to be excellent.
STATE AND FEDERAL REGULATION
General. The Company is subject to the regulatory authority of the VPSB,
which extends to retail rates, services and facilities, securities issues and
various other matters. The separate Vermont Department of Public Service (the
"Department"), created by statute in 1981, is responsible for development of
energy supply plans for the State of Vermont (the "State"), purchases of power
as an agent for the State and other general regulatory matters. The VPSB
principally conducts quasi-judicial proceedings, such as rate setting. The
Department, through a Director for Public Advocacy, is entitled to participate
as a litigant in such proceedings and regularly does so.
Our rate tariffs are uniform throughout our service area. We have entered
into a number of jobs incentive agreements, providing for reduced capacity
charges to large customers applicable only to new load. We have an economic
development agreement with IBM that provides for contractually established
charges, rather than tariff rates, for incremental loads. See Item 7. MD and A
- - Results of Operations - Operating Revenues and MWh Sales.
Our wholesale rate on sales to two wholesale customers is regulated by the
Federal Energy Regulatory Commission ("FERC"). Revenues from sales to these
customers were less than 1% of operating revenues for 2000.
We provide transmission service to twelve customers within the State under
rates regulated by the FERC; revenues for such services amounted to less than
1.0% of the Company's operating revenues for 2000.
On April 24, 1996, the FERC issued Orders 888 and 889 which, among other
things, required the filing of open access transmission tariffs by electric
utilities, and the functional separation by utilities of their transmission
operations from power marketing operations. Order 888 also supports the full
recovery of legitimate and verifiable wholesale power costs previously incurred
under federal or state regulation.
On July 17, 1997, the FERC approved our Open Access Transmission Tariff,
and on August 30, 1997 we filed our compliance refund report. In accordance
with Order 889, we have also functionally separated our transmission operations
and filed with the FERC a code of conduct for our transmission operations. We
do not anticipate any material adverse effects or loss of wholesale customers
due to the FERC orders mentioned above. The Open Access tariff could reduce the
amount of capacity available to the Company from such facilities in the future.
See Item 7. MD and A - Transmission Expenses.
The Company has equity interests in Vermont Yankee, VELCO and Vermont
Electric Transmission Company, Inc. ("VETCO"), a wholly owned subsidiary of
VELCO. We have filed an exemption statement under Section 3(a)(2) of the Public
Utility Holding Company Act of 1935, thereby securing exemption from the
provisions of such Act, except for Section 9(a)(2), which prohibits the
acquisition of securities of certain other utility companies without approval of
the Securities and Exchange Commission ("SEC"). The SEC has the power to
institute proceedings to terminate such exemption for cause.
Licensing. Pursuant to the Federal Power Act, the FERC has granted
licenses for the following hydro-electric projects owned by the Company:
Issue Date Licensed Period
------------- ---------------
Project Site:
Bolton. . . . February 5,1982 February 5,1982 - February 4, 2022
Essex . . . . March 30, 1995 March 1, 1995 - March 1, 2025
Vergennes . . June 29, 1999 June 1, 1999 - May 31, 2029
Waterbury . . July 20, 1954 September 1, 1951 - August 31, 2001
Major project licenses provide that after an initial twenty-year period, a
portion of the earnings of such project in excess of a specified rate of return
is to be set aside in appropriated retained earnings in compliance with FERC
Order #5, issued in 1978. Although the twenty-year periods expired in 1985,
1969 and 1971 in the cases of the Essex, Vergennes and Waterbury projects,
respectively, the amounts appropriated are not material.
The relicensing application for Waterbury was filed in August 1999. The
Company expects the project to be relicensed for a 30 year term in the near
future and does not have any competition for the licenses.
Department of Public Service Twenty-Year Electric Plan. In December 1994,
the Department adopted an update of its twenty-year electrical power-supply plan
(the "Plan") for the State. The Plan includes an overview of statewide growth
and development as they relate to future requirements for electrical energy; an
assessment of available energy resources; and estimates of future electrical
energy demand.
In June 1996, we filed with the VPSB and the Department an integrated
resource plan pursuant to Vermont Statute 30 V.S.A. 218c. That filing is
still pending before the VPSB.
RECENT RATE DEVELOPMENTS
On March 2, 1998, the VPSB released its Order dated February 27, 1998 in
the then pending rate case. The VPSB authorized us to increase our rates by
3.61 percent, which gave us increased annual revenues of $5.6 million. The VPSB
Order denied us the right to charge customers $5.48 million of the annual costs
for power purchased under our contract with Hydro-Quebec. The VPSB denied
recovery of these costs for the following reasons:
* the VPSB claimed that we had acted imprudently by committing to the power
contract with Hydro-Quebec in August 1991 (the imprudence disallowance); and
* to the extent that the costs of power to be purchased from Hydro-Quebec
were then higher than current estimates of market prices for power during the
Contract term, after accounting for the imprudence disallowance, the contract
power was not "used and useful".
On May 8, 1998, we filed a request with the VPSB to increase our retail
rates by 12.93 percent due to higher power costs, the cost of the January 1998
ice storm, and investments in new plant and equipment.
On November 18, 1998, by Memorandum of Understanding ("MOU"), the Company,
the Department and IBM agreed to stay rate proceedings in the 1998 rate case
until or after September 1, 1999, or such earlier date as the parties may later
agree to or the VPSB may order. The agreement to suspend our 1998 rate case
delayed the date of a final decision on the 1998 rate case to December 15, 1999,
and we recognized an additional loss of $5.25 million in the last quarter of
1998 representing the effect of the continued disallowance of Hydro-Quebec costs
through December 15, 1999. The MOU provided for a 5.5% temporary retail rate
increase, to produce $8.9 million in annualized additional revenue, effective
with service rendered December 15, 1998. An additional surcharge was permitted,
without further VPSB order, in order to produce additional revenues necessary to
provide the Company with the capacity to finance 1999 Pine Street Barge Canal
site expenditures. The MOU was approved by the VPSB on December 11, 1998. The
MOU did not provide for any specific disallowance of power costs under our
purchase power contract with Hydro-Quebec. Issues respecting recovery of such
power costs were preserved for future proceedings. The stay and suspension of
this pending rate case and the temporary rate levels agreed to in the MOU were
designed to allow us to continue to provide adequate and efficient service to
our customers while we seek mitigation of power supply costs.
On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments to the MOU that the Company had entered into with the Department and
IBM. The two amendments continued the stay of proceedings until September 1,
2000, with a final decision expected by December 31, 2000. The amendments
maintained the other features of the original MOU, and the second amendment
provided for a temporary rate increase of 3 percent, in addition to the current
temporary rate level, to become effective as of January 1, 2000.
The Company reached a final settlement agreement with the Department in the
pending rate case during November 2000. The final settlement agreement contains
the following provisions:
* A rate increase of 3.42 percent above existing rates, beginning with bills
rendered January 23, 2001, and prior temporary rate increases become permanent;
* Rates are set at levels that recover the Company's Hydro-Quebec VJO
contract costs, effectively ending the regulatory disallowances experienced by
the Company over the past three years;
* The Company agrees not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a
request for rate relief if power supply costs increase in excess of $3.75
million over forecasted levels;
* The Company agreed to write off approximately $3.2 million in unrecovered
rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
* Seasonal rates will be eliminated April 2001, which is expected to
generate approximately $6 million in cash flow that can be utilized to offset
increased costs during 2001, 2002 and 2003; and
* The Company agrees to consult extensively with the Department regarding
capital spending commitments for upgrading our electric distribution system and
to adopt customer care and reliability performance standards, in a first step
toward possible development of performance-based rate-making.
On January 23, 2001, the VPSB approved the Company's settlement with the
Department, with two additional conditions:
* The VPSB Order requires the Company and customers to share equally, with
an $8.0 million limit to the customers' share, any premium above book value
realized by the Company in any future merger, acquisition or asset sale; and
* The second condition restricts Company investments in non-utility
operations.
For further information regarding recent rate developments, see Item
7. MD and A - Liquidity and Capital Resources, Rates, and Note I of Notes to
Annual Report.
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.
In certain states across the country, including the New England states,
legislation has been enacted to allow retail customers to choose their
electricity suppliers, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems. Increased
competitive pressure in the electric utility industry may restrict the Company's
ability to charge energy prices sufficient to recover embedded costs, such as
the cost of purchased power obligations or of generation facilities owned by the
Company. The amount by which such costs might exceed market prices is commonly
referred to as stranded costs.
Regulatory and legislative authorities at the federal level and in some
states, including Vermont where legislation has not been enacted, are
considering how to facilitate competition for electricity sales. For further
information regarding Competition and Restructuring, See Item 7. MD and A -
Future Outlook.
POWER RESOURCES
The Company has renewed a contract with Morgan Stanley Capital Group, Inc.
as the result of our all power requirements solicitation in 1999. See Notes I
and K of Notes to Consolidated Financial Statements.
The Company generated, purchased or transmitted 2,790,018 MWh of energy for
retail and requirements wholesale customers for the twelve months ended December
31, 2000. The corresponding maximum one-hour integrated demand during that
period was 323.5 MW on January 17, 2000. This compares to the previous all-time
peak of 322.6 MW on December 27, 1989. The following table shows the net
generated and purchased energy, the source of such energy for the twelve-month
period and the capacity in the month of the period system peak. See Note K of
Notes to Annual Report.
Net Electricity Generated and Purchased and Capacity at Peak
During year At time of
Ended 12/31/2000 of annual peak
MWH percent KW percent
----------------- --------------- ------- --------
Wholly-owned plants:
Hydro . . . . . . . . . . . . . . 108,230 3.9% 35,300 8.6%
Diesel and Gas Turbine. . . . . . 35,699 1.3% 46,200 11.3%
Wind. . . . . . . . . . . . . . . 12,246 0.4% 850 0.2%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . . 15,443 0.6% 7,100 1.7%
Stony Brook I . . . . . . . . . . 50,537 1.8% 31,000 7.6%
McNeil. . . . . . . . . . . . . . 33,569 1.2% 6,600 1.6%
Owned in association with Others:
Vermont Yankee Nuclear. . . . . . 803,303 28.8% 95,680 23.3%
Long Term Purchases:
Hydro-Quebec. . . . . . . . . . . 824,993 29.5% 114,200 27.8%
Stony Brook I . . . . . . . . . . 22,896 0.8% 14,150 3.5%
Other:
NYPA. . . . . . . . . . . . . . . 1,453 0.1% 250 0.1%
Small Power Producers . . . . . . 120,000 4.3% 24,650 6.0%
Short-term purchases. . . . . . . 761,649 27.3% 34,100 8.3%
----------------- --------------- ------- --------
Total . . . . . . . . . . . . . . 2,790,018 410,080
Less system sales energy. . . . . (2,256) -
----------------- ---------------
Net Own Load. . . . . . . . . . . 2,787,762 100.00% 410,080 100.00%
================= =============== ======= ========
Vermont Yankee.
On October 15, 1999, the owners of Vermont Yankee Nuclear Power Corporation
accepted a bid from AmerGen Energy Company for the Vermont Yankee generating
plant, intending to complete the sale before December 2000. AmerGen and the
Department then negotiated a revised offer in November 2000, which was
subsequently dismissed as insufficient by the VPSB in February 2001. Entergy
Nuclear Inc. has also made an offer, and two other companies have indicated they
would participate in an auction, if held. The plant is likely to be sold at
auction, the terms and conditions of which are unknown at this time.
The Company and Central Vermont Public Service Corporation acted as lead
sponsors in the construction of the Vermont Yankee Nuclear Plant, a
boiling-water reactor designed by General Electric Company. The plant, which
became operational in 1972, has a generating capacity of 531 MW. Vermont Yankee
has entered into power contracts with its sponsor utilities, including the
Company, that expire at the end of the life of the unit. Pursuant to our power
contract, we are required to pay 20% of Vermont Yankee's operating expenses
(including depreciation and taxes), fuel costs (including charges in respect of
estimated costs of disposal of spent nuclear fuel), decommissioning expenses,
interest expense and return on common equity, whether or not the Vermont Yankee
plant is operating. In 1969, we sold to other Vermont utilities a share of our
entitlement to the output of Vermont Yankee. Accordingly, those utilities have
an obligation to pay us 2.338% of Vermont Yankee's operating expenses, fuel
costs, decommissioning expenses, interest expense and return on common equity,
whether or not the Vermont Yankee plant is operating.
Vermont Yankee has also entered into capital funds agreements with its
sponsor utilities that expire on December 31, 2002. Under our Capital Funds
Agreement, we are required, subject to obtaining necessary regulatory approvals,
to provide 20% of the capital requirements of Vermont Yankee not obtained from
outside sources.
In December 1996, August 1997 and July 1998, decisions were made to retire
three New England nuclear units, Connecticut Yankee, Maine Yankee and Millstone
1 effective immediately, with several years remaining on each license. The
NRC's most recently issued Systematic Assessment of Licensee Performance scores
for Vermont Yankee are for the period January 19, 1997 to July 18, 1998.
Operations, engineering, maintenance and plant support were rated good. These
scores were identical to Vermont Yankee's scores for the prior 18 month-period
except for plant support, which declined from superior.
During periods when Vermont Yankee power is unavailable, we incur
replacement power costs in excess of those costs that we would have incurred for
power purchased from Vermont Yankee. Replacement power is available to us from
the ISO and through contractual arrangements with other utilities. Replacement
power costs adversely affect cash flow and, absent deferral, amortization and
recovery through rates, would adversely affect reported earnings. Routinely, in
the case of scheduled outages for refueling, the VPSB has permitted the Company
to defer, amortize and recover these excess replacement power costs for
financial reporting and rate making purposes over the period until the next
scheduled outage. Vermont Yankee has adopted an 18-month refueling schedule.
The 2001 refueling outage is tentatively scheduled to begin June 2001, though it
may occur earlier. 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 costs to decommission the plant, using
the 1993 FERC approved 5.4 percent escalation rate, is approximately $430
million, of which $247 million has been funded. At December 31, 2000, our
portion of the net non-funded liability was $33 million, which we expect will be
recovered through rates over Vermont Yankee's remaining operating life. Vermont
Yankee's current operating license expires March 2012.
During the year ended December 31, 2000, we used 803,303 MWh of Vermont
Yankee energy to meet 28.8% of our retail and requirements wholesale ("Rate W")
sales. The average cost of Vermont Yankee electricity in 2000 was $0.039 per
KWh. Vermont Yankee's annual capacity factor for 2000 was 99.2%, compared with
90.9% in 1999, 73.6% in 1998 and 93.5% in 1997. The 1999 capacity factor was
the best ever for Vermont Yankee in a year that included a refueling outage.
See Note B of Notes to Annual Report.
Hydro-Quebec
Highgate Interconnection. On September 23, 1985, the Highgate transmission
facilities, which were constructed to import energy from Hydro-Quebec in Canada,
began commercial operation. The transmission facilities at Highgate include a
225-MW AC-to-DC-to-AC converter terminal and seven miles of 345-kV transmission
line. VELCO built and operates the converter facilities, which we own jointly
with a number of other Vermont utilities.
NEPOOL/Hydro-Quebec Interconnection. VELCO and certain other NEPOOL
members have entered into agreements with Hydro-Quebec which provided for the
construction in two phases of a direct interconnection between the electric
systems in New England and the electric system of Hydro-Quebec in Canada. The
Vermont participants in this project, which has a capacity of 2,000 MW, will
derive about 9.0% of the total power-supply benefits associated with the
NEPOOL/Hydro-Quebec interconnection. The Company, in turn, receives about
one-third of the Vermont share of those benefits.
The benefits of the interconnection include:
* access to surplus hydroelectric energy from Hydro-Quebec at competitive
prices;
* energy banking, under which participating New England utilities will
transmit relatively inexpensive energy to Hydro-Quebec during off-peak periods
and will receive equal amounts of energy, after adjustment for transmission
losses, from Hydro-Quebec during peak periods when replacement costs are higher;
and
* a provision for emergency transfers and mutual backup to improve
reliability for both the Hydro-Quebec system and the New England systems.
Phase I. The first phase ("Phase I") of the NEPOOL/Hydro-Quebec
Interconnection consists of transmission facilities having a capacity of 690 MW
that traverse a portion of eastern Vermont and extend to a converter terminal
located in Comerford, New Hampshire. These facilities entered commercial
operation on October 1, 1986. VETCO was organized to construct, own and operate
those portions of the transmission facilities located in Vermont. Total
construction costs incurred by VETCO for Phase I were $47,850,000. Of that
amount, VELCO provided $10,000,000 of equity capital to VETCO through sales of
VELCO preferred stock to the Vermont participants in the project. The Company
purchased $3,100,000 of VELCO preferred stock to finance the equity portion of
Phase I. The remaining $37,850,000 of construction cost was financed by VETCO's
issuance of $37,000,000 of long-term debt in the fourth quarter of 1986 and the
balance of $850,000 was financed by short-term debt.
Under the Phase I contracts, each New England participant, including the
Company, is required to pay monthly its proportionate share of VETCO's total
cost of service, including its capital costs. Each participant also pays a
proportionate share of the total costs of service associated with those portions
of the transmission facilities constructed in New Hampshire by a subsidiary of
New England Electric System.
Phase II. Agreements executed in 1985 among the Company, VELCO and other
NEPOOL members and Hydro-Quebec provided for the construction of the second
phase ("Phase II") of the interconnection between the New England Electric
System and that of Hydro-Quebec. Phase II expanded the Phase I facilities from
690 MW to 2,000 MW, and provides for transmission of Hydro-Quebec power from the
Phase I terminal in northern New Hampshire to Sandy Pond, Massachusetts.
Construction of Phase II commenced in 1988 and was completed in late 1990. The
Phase II facilities commenced commercial operation November 1, 1990, initially
at a rating of 1,200 MW, and increased to a transfer capability of 2,000 MW in
July 1991. The Hydro-Quebec-NEPOOL Firm Energy Contract provides for the import
of economical Hydro-Quebec energy into New England. The Company is entitled to
3.2% of the Phase II power-supply benefits. Total construction costs for Phase
II were approximately $487,000,000. The New England participants, including the
Company, have contracted to pay monthly their proportionate share of the total
cost of constructing, owning and operating the Phase II facilities, including
capital costs. As a supporting participant, the Company must make support
payments under 30-year agreements. These support agreements meet the capital
lease accounting requirements under SFAS 13. At December 31, 2000, the present
value of the Company's obligation was approximately $6,449,000. The Company's
projected future minimum payments under the Phase II support agreements are
approximately $430,000 for each of the years 2001-2005 and an aggregate of
$4,299,000 for the years 2006-2020.
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, 2000, the capital structure of such corporations was
approximately 39% common equity and 61% long-term debt. See Notes B and J of
Notes to Annual Report.
At times, we request that portions of our power deliveries from
Hydro-Quebec and other sources be routed through New York. Our ability to do so
could be adversely affected by the proposed tariff that NEPOOL has filed with
the FERC, which would reduce our allocation of capacity on transmission
interfaces with New York. As a result, our ability to import power to Vermont
from outside New England could be adversely affected, thereby impacting our
power costs in the future. See Item 7. MD and A - Transmission Issues and Note
J of Notes to Annual Report.
Hydro-Quebec Power Supply Contracts. We have several purchase power
contracts with Hydro-Quebec. The bulk of our purchases are comprised of two
schedules, B and C3, pursuant to a Firm Contract dated December 1987. Under
these two schedules, we purchase 114.2 MW. Under an arrangement negotiated in
January 1996, we received payments from Hydro-Quebec of $3,000,000 in 1996 and
$1,100,000 in 1997. In accordance with such arrangement, we agreed to shift
certain transmission requirements, purchase certain quantities of power and make
certain minimum payments for periods in which power is not purchased. In
addition, in November 1996, we entered into a Memorandum of Understanding with
Hydro-Quebec under which Hydro-Quebec paid $8,000,000 to the Company in exchange
for certain power purchase options. The exercise of these options in 2000
resulted in an increase of approximately $7.7 million to power supply expense to
meet contractual obligations under the Company's December 1997 sell-back
agreement with Hydro-Quebec. See Item 7. MD and A - Power Supply Expenses, and
Notes I, J and K of Notes to Annual Report.
In 2000, we used 406,408 MWh under Schedule B, 273,088 MWh under Schedule
C3, and 149,551 MWh under the HQ 9601 and 9602 arrangements to meet 29.7% of our
retail and requirements wholesale sales. The average cost of Hydro-Quebec
electricity in 1999 was $0.06 per KWh.
Stony Brook I. The Massachusetts Municipal Wholesale Electric Company
("MMWEC") is principal owner and operator of Stony Brook, a 352.0-MW
combined-cycle intermediate generating station located in Ludlow, Massachusetts,
which commenced commercial operation in November 1981. We entered into a Joint
Ownership Agreement with MMWEC dated as of October 1, 1977, whereby we acquired
an 8.8% ownership share of the plant, entitling us to 31.0 MW of capacity. In
addition to this entitlement, we have contracted for 14.2 MW of capacity for the
life of the Stony Brook I plant, for which we will pay a proportionate share of
MMWEC's share of the plant's fixed costs and variable operating expenses. The
three units that comprise Stony Brook I are all capable of burning oil. Two of
the units are also capable of burning natural gas. The natural gas system at
the plant was modified in 1985 to allow two units to operate simultaneously on
natural gas.
During 2000, we used 73,433 MWh from this plant to meet 2.6% of our retail
and requirements wholesale sales at an average cost of $0.064 per KWh. See Note
I and K of Notes to Annual Report.
Wyman Unit #4. The W. F. Wyman Unit #4, which is located in Yarmouth,
Maine, is an oil-fired steam plant with a capacity of 620 MW. Central Maine
Power Company sponsored the construction of this plant. We have a
joint-ownership share of 1.1% (7.1 MW) in the Wyman #4 unit, which began
commercial operation in December 1978.
During 2000, we used 15,443 MWh from this unit to meet 0.6% of our retail
and requirements wholesale sales at an average cost of $0.044 per kWh, based
only on operation, maintenance, and fuel costs incurred during 2000. See Note I
of Notes to Annual Report.
McNeil Station. The J.C. McNeil station, which is located in Burlington,
Vermont, is a wood chip and gas-fired steam plant with a capacity of 53.0 MW.
We have an 11.0% or 5.8 MW interest in the J. C. McNeil plant, which began
operation in June 1984. In 1989, the plant added the capability to burn natural
gas on an as-available/interruptible service basis.
During 2000, we used 33,569 MWh from this unit to meet 1.2% of our retail
and requirements wholesale sales at an average cost of $0.053 per kWh, based
only on operation, maintenance, and fuel costs incurred during 2000. See Note I
of Notes to Annual Report.
Independent Power Producers. The VPSB has adopted rules that implement for
Vermont the purchase requirements established by federal law in the Public
Utility Regulatory Policies Act of 1978 ("PURPA"). Under the rules, qualifying
facilities have the option to sell their output to a central state-purchasing
agent under a variety of long- and short-term, firm and non-firm pricing
schedules. Each of these schedules is based upon the projected Vermont
composite system's power costs that would be required but for the purchases from
independent producers. The State purchasing agent assigns the energy so
purchased, and the costs of purchase, to each Vermont retail electric utility
based upon its pro rata share of total Vermont retail energy sales. Utilities
may also contract directly with producers. The rules provide that all
reasonable costs incurred by a utility under the rules will be included in the
utilities' revenue requirements for rate-making purposes.
Currently, the State purchasing agent, Vermont Electric Power Producers,
Inc. ("VEPPI"), is authorized to seek 150 MW of power from qualifying facilities
under PURPA, of which our average pro rata share in 2000 was approximately 32.9%
or 49.3 MW.
The rated capacity of the qualifying facilities currently selling power to
VEPPI is approximately 74.5 MW. These facilities were all online by the spring
of 1993, and no other projects are under development. We do not expect any new
projects to come online in the foreseeable future because the excess capacity in
the region has eliminated the need for and value of additional qualifying
facilities.
In 2000, through our direct contracts and VEPPI, we purchased 120,000 MWh
of qualifying facilities production to meet 4.3% of our retail and requirements
wholesale sales at an average cost of $0.113 per KWh.
Short Term Opportunity Purchases and Sales. We have arrangements with
numerous utilities and power marketers actively trading power in New England and
New York under which we may make purchases or sales of power on short notice and
generally for brief periods of time when it appears economic to do so.
Opportunity purchases are arranged when it is possible to purchase power for
less than it would cost us to generate the power with our own sources.
Purchases also help us save on replacement power costs during an outage of one
of our base load sources. Opportunity sales are arranged when we have surplus
energy available at a price that is economic to other regional utilities at any
given time. The sales are arranged based on forecasted costs of supplying the
incremental power necessary to serve the sale. Prices are set so as to recover
all of the forecasted fuel or production costs and to recover some, if not all,
associated capacity costs.
During 2000, we purchased 757,595 MWh, meeting 27.1% of our retail and
requirements wholesale sales, at an average cost of $0.044 per kWh.
Company Hydroelectric Power. The Company wholly owns and operates eight
hydroelectric generating facilities located on river systems within its service
area, the largest of which has a generating output of 7.8 MW.
In 2000, the Company owned hydroelectric plants provided 108,230 MWh of
low-cost energy, meeting 3.9% of our retail and requirements wholesale sales at
an average cost of $0.051 per kWh based on total embedded costs and maintenance.
See State and Federal Regulation - Licensing.
VELCO. The Company and six other Vermont electric distribution utilities
own VELCO. Since commencing operation in 1958, VELCO has transmitted power for
its owners in Vermont, including power from NYPA and other power contracted for
by Vermont utilities. VELCO also purchases bulk power for resale at cost to its
owners, and as a member of NEPOOL, represents all Vermont electric utilities in
pool arrangements and transactions. See Note B of Notes to Annual Report.
Fuel. During 2000, our retail and requirements wholesale sales were
provided by the following fuel sources:
* 35.8% from hydroelectric sources (3.9% Company-owned, 0.1% NYPA, 29.5%
Hydro-Quebec and 2.3% small power producers);
* 28.8% from a nuclear generating source (the Vermont Yankee nuclear plant
described below);
* 2.8% from wood;
* 2.7% from oil;
* 2.2% from natural gas;
* 0.4% from wind power producers; and
* 27.3% was purchased on a short-term basis from other utilities through the
Independent System Operator of New England ("ISO"), formerly the New England
Power Pool ("NEPOOL").
Vermont Yankee has several requirement-based contracts for the four
components (uranium, conversion, enrichment and fabrication) used to produce
nuclear fuel. These contracts are executed only if the need or requirement for
fuel arises. Under these contracts, any disruption of operating activity would
allow Vermont Yankee to cancel or postpone deliveries until actually required.
The contracts extend through various time periods and contain clauses to allow
Vermont Yankee the option to extend the agreements. Negotiation of new
contracts and renegotiations of existing contracts routinely occurs, often
focusing on one of the four components at a time. The 1999 reload cost
approximately $20.8 million. Future reload costs will depend on market and
contract prices
On January 20, 1997, Vermont Yankee entered into an agreement with a former
uranium supplier whereby the supplier could opt to terminate a production
purchase agreement dated August 4, 1978. Although there had been no
transactions under the production purchase agreement for several years, Vermont
Yankee maintained certain financial rights. In consideration for the option to
terminate the production purchase agreement and the subsequent exercise of the
option, Vermont Yankee received $600,000 in 1997, which was recorded as an
offset to nuclear fuel expense. The potential future payments over a ten-year
period range from zero to $2.4 million. No payments were received in 2000 under
this agreement. Due to the uncertainty of this transaction, any benefits
received will be recorded on a cash basis.
Vermont Yankee has a contract with the United States Department of Energy
("DOE") for the permanent disposal of spent nuclear fuel. Under the terms of
this contract, in exchange for the one-time fee discussed below and a quarterly
fee of 1 mil per kWh of electricity generated and sold, the DOE agrees to
provide disposal services when a facility for spent nuclear fuel and other
high-level radioactive waste is available, which is required by contract to be
prior to January 31, 1998. The actual date for these disposal services is
expected to be delayed many years. DOE currently estimates that a permanent
disposal facility will not begin operation before 2010. A DOE temporary
disposal site may be provided in a few years, but no decision has been made to
proceed on providing a temporary disposal site at this time.
The DOE contract obligates Vermont Yankee to pay a one-time fee of
approximately $39.3 million for disposal costs for all spent fuel discharged
through April 7, 1983. Although such amount has been collected in rates from
the Vermont Yankee participants, Vermont Yankee has elected to defer payment of
the fee to the DOE as permitted by the DOE contract. The fee must be paid no
later than the first delivery of spent nuclear fuel to the DOE. Interest
accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate
and is compounded quarterly. Through 2000 Vermont Yankee accumulated
approximately $108.0 million in an irrevocable trust to be used exclusively for
settling this obligation at some future date, provided the DOE complies with the
terms of the aforementioned contract.
We do not maintain long-term contracts for the supply of oil for our
wholly-owned oil-fired peak generating stations (80 MW). We did not experience
difficulty in obtaining oil for our own units during 2000, and, while no
assurance can be given, we do not anticipate any such difficulty during 2001.
None of the utilities from which we expect to purchase oil- or gas-fired
capacity in 2001 has advised us of grounds for doubt about maintenance of secure
sources of oil and gas during the year.
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 299,246 tons of
wood chips and mill residue, 1,146,045 gallons of fuel oil, and 1.044 billion
cubic feet of natural gas in 2000. The McNeil plant, assuming any needed
regulatory approvals are obtained, is forecasting year 2001 consumption of wood
chips to be 300,000 tons, fuel oil of 200,000 gallons and natural gas
consumption of 26 million cubic feet.
The Stony Brook combined-cycle generating station is capable of burning
either natural gas or oil in two of its turbines. Natural gas is supplied to
the plant subject to its availability. During periods of extremely cold
weather, the supplier reserves the right to discontinue deliveries to the plant
in order to satisfy the demand of its residential customers. We assume, for
planning and budgeting purposes, that the plant will be supplied with gas during
the months of April through November, and that it will run solely on oil during
the months of December through March. The plant maintains an oil supply
sufficient to meet approximately one-half of its annual needs.
Wind Project. The Company was selected by the DOE and the Electric Power
Research Institute ("EPRI") to build a commercial scale wind-powered facility.
The DOE and EPRI provided partial funding for the wind project of approximately
$3.9 million. The net cost to the Company of the project, located in the
southern Vermont town of Searsburg, was $7.8 million. The eleven wind turbines
have a rating of 6 MW and were commissioned July 1, 1997.
In 2000, the plant provided 12,246 MWh, meeting 0.4% of the Company's
retail and requirements wholesale sales at an average cost of $0.07 per kWh.
ENERGY EFFICIENCY
In 2000, GMP focused its energy efficiency services on transferring its
programs that encouraged customers to install energy efficient equipment to the
Energy Efficiency Utility created by the VPSB in 1999 to manage energy
efficiency programs for all utilities in Vermont. The Company's customers are
now billed a separate EEU charge that we remit directly to the EEU. During the
past eight years the Company's efficiency programs have achieved a cumulative
annual savings of 89,000 megawatthours, saving approximately $7.9 million per
year for our customers. In 2000, we spent approximately $305,000 on energy
efficiency programs.
RATE DESIGN
The Company seeks to design rates to encourage the shifting of electrical
use from peak hours to off-peak hours. Since 1976, we have offered optional
time-of-use rates for residential and commercial customers. Currently,
approximately 2,160 of the Company's residential customers continue to be billed
on the original 1976 time-of-use rate basis. In 1987, the Company received
regulatory approval for a rate design that permitted it to charge prices for
electric service that reflected as accurately as possible the cost burden
imposed by each customer class. The Company's rate design objectives are to
provide a stable pricing structure and to accurately reflect the cost of
providing electric services. This rate structure helps to achieve these goals.
Since inefficient use of electricity increases its cost, customers who are
charged prices that reflect the cost of providing electrical service have real
incentives to follow the most efficient usage patterns. Included in the VPSB's
order approving this rate design was a requirement that the Company's largest
customers be charged time-of-use rates on a phased-in basis by 1994. At
December 31, 2000, approximately 1,360 of the Company's largest customers,
comprising 52% of retail revenues, continue to receive service on mandatory
time-of-use rates.
In May 1994, the Company filed its current rate design with the VPSB. The
parties, including the Department, IBM and a low-income advocacy group, entered
into a settlement that was approved by the VPSB on December 2, 1994. Under the
settlement, the revenue allocation to each rate class was adjusted to reflect
class-by-class cost changes since 1987, the differential between the winter and
summer rates was reduced, the customer charge was increased for most classes,
and usage charges were adjusted to be closer to the associated marginal costs.
No modifications to base rate redesign have taken place since the VPSB
Order issued on December 2, 1994, however, as previously noted, the VPSB
Settlement Order of January 2001 eliminates seasonal rate differentials
effective April 2001.
DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS
In 2000, we had 28 dispatchable power contracts: 20 contracts were
year-round, while the 8 seasonal contracts include two major ski areas. The
dispatchable portion of the contracts allows customers to purchase electricity
during times designated by the Company when low cost power is available. The
customer's demand during these periods is not considered in calculating the
monthly billing. This program enables the Company and the customers to benefit
from load control. We shift load from our high cost peak periods and the
customer uses inexpensive power at a time when its use provides maximum value.
These programs are available by tariff for qualifying customers.
CONSTRUCTION AND CAPITAL REQUIREMENTS
Our capital expenditures for 1998 through 2000 and projection for 2001 are
set forth in Item 7. Management's Discussion And Analysis Of Financial Condition
and Results Of Operations - Liquidity and Capital Resources-Construction.
Construction projections are subject to continuing review and may be revised
from time-to-time in accordance with changes in the Company's financial
condition, load forecasts, the availability and cost of labor and materials,
licensing and other regulatory requirements, changing environmental standards
and other relevant factors.
For the period 1998-2000, internally generated funds, after payment of
dividends, provided approximately 59 percent of total capital requirements for
construction, sinking fund obligations and other requirements. Internally
generated funds provided 40 percent of such requirements for 2000. We
anticipate that for 2001, internally generated funds will provide approximately
90 percent of total capital requirements for regulated operations, the remainder
to be derived from bank loans.
In connection with the foregoing, see Item 7. MD and A - Liquidity and
Capital Resources.
ENVIRONMENTAL MATTERS
We had been notified by the Environmental Protection Agency ("EPA") that we
were one of several potentially responsible parties for clean up at the Pine
Street Barge Canal site in Burlington, Vermont. In September 1999, we
negotiated a final settlement with the United States, the State of Vermont, and
other parties over terms of a Consent Decree that covers claims addressed in
earlier negotiations and implementation of the selected remedy. In October
1999, the federal district court approved the Consent Decree that addresses
claims by the EPA for past Pine Street Barge Canal site costs, natural resource
damage claims and claims for past and future oversight costs. The Consent
Decree also provides for the design and implementation of response actions at
the site. For information regarding the Pine Street Canal site and other
environmental matters see Item 7. MD and - Environmental Matters, and Note I of
Notes to Annual Report.
UNREGULATED BUSINESSES
In 1998, we sold the assets of our wholly owned subsidiary, Green Mountain
Propane Gas Company. In 1999, Green Mountain Resources, Inc. sold its remaining
interest in Green Mountain Energy Resources to Green Funding I. During 1999,
the Company discontinued operations of Mountain Energy, Inc. ("MEI"), a
subsidiary of the Company that invests in wastewater, energy efficiency and
generation businesses. The loss in 2000 reflects the sale of most of MEI's
remaining energy assets and the current estimated costs of winding down MEI's
wastewater businesses. For information regarding our remaining unregulated
businesses, see Item 7. MD and A - Future Outlook - Unregulated Businesses.
EXECUTIVE OFFICERS
The Executive Officers names, ages, and positions of the Company as of March 15,
2001 are:
Nancy Rowden Brock 45
Vice President, Chief Financial Officer and Treasurer since December 1998, and
Secretary since August 1999. Chief Corporate Strategic Planning Officer from
March 1998 to December 1998. Prior to joining the Company, she was Chief
Financial Officer of SAL, Inc., 1997; and Senior Vice President, Chief Financial
Officer and Treasurer for the Chittenden Corporation from 1988 to 1996.
Christopher L. Dutton 52
President, Chief Executive Officer of the Company and Chairman of the
Executive Committee of the Company since August 1997. Vice President, Finance
and Administration, Chief Financial Officer and Treasurer from 1995 to August
1997. Vice President and General Counsel from 1993 to January 1995. Vice
President, General Counsel and Corporate Secretary from 1989 to 1993.
Robert J. Griffin 44
Controller since October 1996. Manager of General Accounting from 1990 to
1996.
Walter S. Oakes 54
Vice President-Field Operations since August 1999. Assistant Vice
President-Customer Operations from June 1994 to August 1999. Assistant Vice
President, Human Resources from August 1993 to June 1994. Assistant Vice
President-Corporate Services from 1988 to 1993.
Mary G. Powell 40
Senior Vice President-Customer and Organizational Development since
December 1999. Vice President-Administration from February 1999 through December
1999. Vice President, Human Resources and Organizational Development from March
1998 to February 1999. Prior to joining the Company, she was President of
HRworks, a human resources management firm, from January 1997 to March 1998.
From 1992 to January 1997, she worked for KeyCorp in Vermont, most recently as
Senior Vice President Community Banking. At KeyCorp, she also served as Vice
President Administration and Vice President of Human Resources.
Stephen C. Terry 58
Senior Vice President-Government and Legal Relations since August 1999.
Senior Vice President, Corporate Development from August 1997 to August 1999.
Vice President and General Manager, Retail Energy Services from 1995 to August
1997. Vice President-External Affairs from 1991 to January 1995.
Jonathan H. Winer 49
President of Mountain Energy, Inc. since March 1997. Vice President and
Chief Operating Officer of Mountain Energy, Inc. from 1989 to March 1997.
Resigned effective January 17, 2001.
Officers are elected by the Board of Directors of the Company and its
wholly-owned subsidiaries, as appropriate, for one-year terms and serve at the
pleasure of such boards of directors.
ITEM 2. PROPERTY
GENERATING FACILITIES
Our Vermont properties are located in five areas and are interconnected by
transmission lines of VELCO and New England Power Company. We wholly own and
operate eight hydroelectric generating stations with a total nameplate rating of
36.1 MW and an estimated claimed capability of 35.7 MW. We also own two
gas-turbine generating stations with an aggregate nameplate rating of 59.9 MW
and an estimated aggregate claimed capability of 73.2 MW. We have two diesel
generating stations with an aggregate nameplate rating of 8.0 MW and an
estimated aggregate claimed capability of 8.6 MW. We also have a wind
generating facility with a nameplate rating of 6.1 MW.
We also own:
* 17.9% of the outstanding common stock, and are entitled to 17.662% (93.8
MW of a total 531 MW) of the capacity, of Vermont Yankee,
* 1.1% (7.1 MW of a total 620 MW) joint-ownership share of the Wyman #4
plant located in Maine,
* 8.8% (31.0 MW of a total 352 MW) joint-ownership share of the Stony Brook
I intermediate units located in Massachusetts, and
* 11.0% (5.8 MW of a total 53 MW) joint-ownership share of the J.C. McNeil
wood-fired steam plant located in Burlington, Vermont.
See Item 1. Business - Power Resources for plant details and the table
hereinafter set forth for generating facilities presently available.
TRANSMISSION AND DISTRIBUTION
The Company had, at December 31, 2000, approximately 1.5 miles of 115 kV
transmission lines, 10.5 miles of 69 kV transmission lines, 5.4 miles of 44 kV
and 284.6 miles of 34.5 kV transmission lines. Our distribution system includes
approximately 2,705 miles of overhead lines of 2.4 kV to 34.5 kV, and about 461
miles of underground cable of 2.4 kV to 34.5 kV. At such date, we owned
approximately 158,820 kVa of substation transformer capacity in transmission
substations, 569,750 kVa of substation transformer capacity in distribution
substations and 1,085,000 kVa of transformers for step-down from distribution to
customer use.
The Company owns 34.8% of the Highgate transmission inter-tie, a 225-MW
converter and transmission line used to transmit power from Hydro-Quebec.
We also own 29.5% of the common stock and 30% of the preferred stock of
VELCO, which operates a high-voltage transmission system interconnecting
electric utilities in the State of Vermont.
PROPERTY OWNERSHIP
The Company's wholly-owned plants are located on lands that we own in fee.
Water power and floodage rights are controlled through ownership of the
necessary land in fee or under easements.
Transmission and distribution facilities that are not located in or over
public highways are, with minor exceptions, located either on land owned in fee
or pursuant to easements which, in nearly all cases, are perpetual.
Transmission and distribution lines located in or over public highways are so
located pursuant to authority conferred on public utilities by statute, subject
to regulation by state or municipal authorities.
INDENTURE OF FIRST MORTGAGE
The Company's interests in substantially all of its properties and
franchises are subject to the lien of the mortgage securing its First Mortgage
Bonds.
The Company has also provided a second mortgage, lien and security interest
in the collateral pledged under the first mortgage bond indenture to two banks
participating in the Company's revolving credit agreement with Fleet National
Bank and Citizens Bank of Massachusetts.
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
Location Name Fuel MW(1)
--------------- --------------- -------- -----
Wholly Owned
Hydro . . . . . . . . . Middlesex, VT Middlesex #2 Hydro 3.3
Hydro . . . . . . . . . Marshfield, VT Marshfield #6 Hydro 4.9
Hydro . . . . . . . . . Vergennes, VT Vergennes #9 Hydro 2.1
Hydro . . . . . . . . . W. Danville, VT W. Danville #15 Hydro 1.1
Hydro . . . . . . . . . Colchester, VT Gorge #18 Hydro 3.3
Hydro . . . . . . . . . Essex Jct., VT Essex #19 Hydro 7.8
Hydro . . . . . . . . . Waterbury, VT Waterbury #22 Hydro 5.0 (4)
Hydro . . . . . . . . . Bolton, VT DeForge #1 Hydro 7.8
Diesel. . . . . . . . . Vergennes, VT Vergennes #9 Oil 4.2
Diesel. . . . . . . . . Essex Jct., VT Essex #19 Oil 4.4
Gas . . . . . . . . . . Berlin, VT Berlin #5 Oil 56.6
Turbine . . . . . . . . Colchester, VT Gorge #16 Oil 16.1
Wind. . . . . . . . . . Searsburg, VT Searsburg Wind 1.2
Jointly Owned
Steam . . . . . . . . . Vernon, VT Vermont Yankee Nuclear 93.8 (2)
Steam . . . . . . . . . Yarmouth, ME Wyman #4 Oil 7.1
Steam . . . . . . . . . Burlington, VT McNeil Wood/Gas 6.6 (3)
Combined. . . . . . . . Ludlow, MA Stony Brook #1 Oil/Gas 31.0 (2)
Total Winter Capability 256.3
========
(1) Winter capability quantities are used since the Company's peak usage
occurs during the winter months. Some unit ratings are reduced in the summer
months due to higher ambient temperatures. Capability shown includes capacity
and associated energy sold to other utilities.
(2) For a discussion of the impact of various power supply sales on the
availability of generating facilities, see Item 1. Business - Power Resources.
(3) The Company's entitlement in McNeil is 5.8 MW. However, we receive up to
6.6 MW as a result of other owners' losses on this system.
(4) Reservoir has been drained, dam awaiting repairs by Army Corps of
Engineers.
CORPORATE HEADQUARTERS
The Company terminated an operating lease for its corporate headquarters
building and two of its service center buildings in the first quarter of 1999.
During 1998, the Company recorded a loss of approximately $1.9 million before
applicable income taxes to reflect the probable loss resulting from this
transaction. The Company sold its corporate headquarters building in 1999, but
retained ownership of the two service centers.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in several legal proceedings, the outcome of which
will significantly affect the viability and or potential profitability of the
Company. The most significant legal proceeding is arbitration about
Hydro-Quebec's non-delivery of power as a result of the January 1998 ice storm
in eastern North America. See the discussion under Item 7. MD and A -
Environmental Matters, Rate Matters, and Note I of the Notes to Annual Report.
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 1999 and 2000:
HIGH LOW
-------------- ---------
1999 $. . . . . . $
First Quarter. 11 3/16 9 3/4
Second Quarter 11 5/16 8 11/16
Third Quarter. 14 10 1/4
Fourth Quarter 10 1/4 7 1/8
2000
First Quarter. 9 6 9/16
Second Quarter 8 1/2 6 5/8
Third Quarter. 8 3/4 7 3/8
Fourth Quarter 14 3/4 7 9/16
The number of common stockholders of record as of March 21, 2001 was 6,050.
Quarterly cash dividends were paid as follows during the past two years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- --------
1999 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1375
2000 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1375
Dividend Policy On November 23, 1998, the Company's Board of Directors
announced a reduction in the quarterly dividend from $0.275 per share to $0.1375
per share on the Company's common stock. The current indicated annual dividend
is $0.55 per share of common stock.
Our current dividend policy reflects changes affecting the electric utility
industry, which is moving away from the traditional cost-of-service regulatory
model to a competition based market for power supply.
The current environment prompted us to reassess the appropriateness of our
traditional dividend policy. Historically, we based our dividend policy on the
continued validity of three assumptions: The ability to achieve earnings growth,
the receipt of an allowed rate of return that accurately reflects our cost of
capital, and the retention of our exclusive franchise. The Company's Board of
Directors will continue to assess and adjust the dividend, when appropriate, as
the Vermont electric industry evolves towards competition. In addition, if
other events beyond our control cause the Company's financial situation to
deteriorate further, the Board of Directors will also consider whether the
current dividend level is appropriate or if the dividend should be reduced or
eliminated. See Item 7. MD and A - Future Outlook, Competition and
Restructuring, and Note C of Notes to Annual Report. for a discussion of
dividend restrictions.
ITEM 6. SELECTED FINANCIAL DATA
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,
- --------------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
In thousands, except per share data
Operating Revenues . . . . . . . . . . . . . $277,326 $251,048 $184,304 $179,323 $179,009
Operating Expenses . . . . . . . . . . . . . 272,066 243,102 178,832 163,808 162,882
--------- --------- --------- --------- ---------
Operating Income . . . . . . . . . . . . 5,260 7,946 5,472 15,515 16,127
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity . . . . . . . . . . . . . . 284 134 104 357 175
Other. . . . . . . . . . . . . . . . . . . 2,422 3,319 1,509 1,074 1,739
--------- --------- --------- --------- ---------
Total other income . . . . . . . . . . . 2,706 3,453 1,613 1,431 1,914
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed . . . . . . . . . . . . . (228) (91) (131) (315) (468)
Other. . . . . . . . . . . . . . . . . . . 7,485 7,274 8,007 7,965 7,866
--------- --------- --------- --------- ---------
Total interest charges . . . . . . . . . 7,257 7,183 7,876 7,650 7,398
--------- --------- --------- --------- ---------
Net Income (Loss) from continuing. . . . . . 709 4,216 (791) 9,296 10,643
operations before preferred dividends
Net Income (Loss) from discontinued
operations, including provisions
for loss on disposal . . . . . . . . . . . (6,549) (7,279) (2,086) 142 1,316
Dividends on Preferred Stock . . . . . . . . 1,014 1,155 1,296 1,433 1,010
--------- --------- --------- --------- ---------
Net Income (Loss)Applicable
to Common Stock. . . . . . . . . . . . . . $ (6,854) $ (4,218) $ (4,173) $ 8,005 $ 10,949
========= ========= ========= ========= =========
Common Stock Data
Earnings per share-continuing operations . $ (0.06) $ 0.57 $ (0.40) $ 1.54 $ 1.95
Earnings per share-discontinued operations $ (1.19) $ (1.36) $ (0.40) $ 0.03 $ 0.27
Earnings per share-basic and diluted . . . $ (1.25) $ (0.79) $ (0.80) $ 1.57 $ 2.22
Cash dividends declared per share. . . . . $ 0.55 $ 0.55 $ 0.96 $ 1.61 $ 2.12
Weighted average shares outstanding. . . . 5,491 5,361 5,243 5,112 4,933
FINANCIAL CONDITION AS OF DECEMBER 31
- ------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
In thousands
ASSETS
Utility Plant, Net. . . . . . . . . . . $194,672 $192,896 $195,556 $196,720 $189,853
Other Investments . . . . . . . . . . . 20,730 20,665 20,678 21,997 20,634
Current Assets. . . . . . . . . . . . . 53,652 33,238 35,700 29,125 30,901
Deferred Charges. . . . . . . . . . . . 46,036 41,853 35,576 35,831 43,224
Non-Utility Assets. . . . . . . . . . . 1,518 11,099 27,314 42,060 39,927
-------- -------- -------- -------- --------
Total Assets. . . . . . . . . . . . . $316,608 $299,751 $314,824 $325,733 $324,539
======== ======== ======== ======== ========
CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . . $ 92,044 $100,645 $106,755 $114,377 $111,554
Redeemable Cumulative Preferred Stock . 12,795 14,435 16,085 17,735 19,310
Long-Term Debt, Less Current Maturities 72,100 81,800 88,500 93,200 94,900
Capital Lease Obligation. . . . . . . . 6,449 7,038 7,696 8,342 9,006
Current Liabilities . . . . . . . . . . 68,109 36,708 28,825 25,286 21,037
Deferred Credits and Other. . . . . . . 61,794 59,125 59,889 53,723 54,968
Non-Utility Liabilities . . . . . . . . 3,317 - 7,074 13,070 13,764
-------- -------- -------- -------- --------
Total Capitalization and Liabilities. $316,608 $299,751 $314,824 $325,733 $324,539
======== ======== ======== ======== ========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
In this section, we explain the general financial condition and the results
of operations for Green Mountain Power Corporation (the "Company") and its
subsidiaries. This explanation includes:
* factors that affect our business;
* our earnings and costs in the periods presented and why they changed
between periods;
* the source of our earnings;
* our expenditures for capital projects and what we expect they will be in
the future;
* where we expect to get cash for future capital expenditures; and
* how all of the above affects our overall financial condition.
There are statements in this section that contain projections or estimates
and that are considered to be forward-looking as defined by the Securities and
Exchange Commission (the "SEC"). In these statements, you may find words such
as believes, expects, plans, or similar words. These statements are not
guarantees of our future performance. There are risks, uncertainties and other
factors that could cause actual results to be different from those projected.
Some of the reasons the results may be different are discussed under "Future
Outlook", "Transmission Issues", "Environmental Matters", "Rates" and "Liquidity
and Capital Resources" in this section, and include:
* regulatory and judicial decisions or legislation;
* weather;
* energy supply and demand and pricing;
* contractual commitments;
* availability, terms, and use of capital;
* general economic and business environment;
* nuclear and environmental issues; and
* industry restructuring and cost recovery (including stranded costs).
These forward-looking statements represent our estimates and assumptions
only as of the date of this report.
EARNINGS SUMMARY
On January 23, 2001, the Vermont Public Service Board ("VPSB") issued
an order (the "Settlement Order") approving a settlement between the Company and
the Vermont Department of Public Service (the "Department") that grants the
Company an immediate 3.42 percent rate increase, and allows full recovery of
power supply costs under the Hydro-Quebec Vermont Joint Owners ("VJO") contract.
The Settlement Order paves the way for restoration of the Company's investment
grade status (See "Retail Rate Cases" and "Liquidity and Capital Resources" in
this section)and gives the Company an opportunity to earn its allowed rate of
return during 2001, or approximately $1.96 per share. During 2000, the
Company lost $1.25 per share of common stock, compared with a loss per share of
$0.79 in 1999 and a loss per share of $0.80 in 1998. The 2000 loss represents a
negative return on average common equity of 7.1 percent. The return on average
common equity was negative 4.0 percent in 1999 and negative 3.8 percent in 1998.
The loss from continuing operations was $0.06 per share in 2000, compared with
earnings of $0.57 per share in 1999 and a loss of $0.40 in 1998. Certain
subsidiary operations, classified as discontinued in 1999, lost $1.19 per share
in 2000, compared with a loss of $1.36 per share in 1999 and a loss of $0.40 per
share in 1998.
The consolidated loss in 2000 was greater than the prior year consolidated
loss as a result of the VPSB Settlement Order that disallowed recovery of $3.2
million or $0.35 per share in regulatory litigation costs and from higher power
supply costs that were not recovered in rates. Power supply expense increased
$30.2 million in 2000, outpacing revenue growth of $26.3 million and reductions
in depreciation and amortization expense of $0.9 million.
The 1999 improvement in results from continuing operations was primarily
due to three factors:
* retail operating revenues increased by $15.1 million, reflecting a 5.5
percent temporary rate increase that went into effect on December 15, 1998, and
a 3.9 percent increase in sales to commercial and industrial customers in 1999;
* operating costs were $3.7 million lower in 1999 due to the Company's
termination of its corporate headquarters lease, reduced costs associated with
the Company's headquarters facilities and lower payroll expense reflecting
mid-year reductions in the number of employees; and
* results for 1998 reflected pretax charges of $9.8 million in disallowed
Hydro-Quebec power costs for both 1998 and 1999, compared with disallowed power
costs of $7.5 million for 2000 recorded in 1999.
The 1999 earnings improvement was partially offset by:
* a $4.3 million increase in the capacity costs in 1999 associated with our
long-term Hydro-Quebec power supply contract;
* an increase in the costs of short-term power following the deregulation of
energy markets in New England, as well as an increase in our costs to serve
increased local loads and an increase of approximately $5.4 million to supply
power to meet contractual obligations under the Company's December 1997
sell-back agreement with Hydro-Quebec; and
* a $1.9 million increase in capacity costs associated with a contract with
Vermont Yankee Nuclear Power Corporation ("Vermont Yankee").
The Company's discontinued operations lost $1.19 in 2000 compared with a
loss of $1.36 in 1999. During 1999, the Company discontinued operations of
Mountain Energy, Inc. ("MEI"), a subsidiary of the Company that invests in
wastewater, energy efficiency and generation businesses. The loss in 2000
reflects the sale of most of MEI's remaining energy assets and the current
estimated costs of winding down MEI's wastewater businesses. During January
2001, MEI changed its name to Northern Water Resources, Inc. ("NWR").
FUTURE OUTLOOK
COMPETITION AND RESTRUCTURING-The electric utility business is experiencing
rapid and substantial changes. These changes are the result of the following
trends:
* disparity in electric rates, transmission, and generating capacity among
and within various regions of the country;
* improvements in generation efficiency;
* increasing demand for customer choice; and
* new regulations and legislation intended to foster competition, also known
as restructuring.
Electric utilities historically have had exclusive franchises for the
retail sale of electricity in specified service territories. As a result,
competition for retail customers has been limited to:
* competition with alternative fuel suppliers, primarily for heating and
cooling;
* competition with customer-owned generation; and
* direct competition among electric utilities to attract major new
facilities to their service territories.
These competitive pressures have led the Company and other utilities to
offer, from time to time, special discounts or service packages to certain large
customers.
In certain states across the country, including all the New England states
except Vermont, legislation has been enacted to allow retail customers to choose
their electricity suppliers, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems (also known as
retail wheeling). Increased pressure in the electric utility industry may
restrict the Company's ability to charge energy prices sufficient to recover
embedded costs, such as the cost of purchased power obligations or of generation
facilities owned by the Company. The amount by which such costs might exceed
market prices is commonly referred to as stranded costs.
Regulatory and legislative authorities at the federal level and in some
states, including Vermont where legislation has not been enacted, are
considering whether, when and how to facilitate competition for electricity
sales at the wholesale and retail levels. Recent difficulties in some
regulatory jurisdictions, such as California, have dampened any immediate push
towards deregulation in Vermont. However, in the future, the Vermont General
Assembly through legislation, or the VPSB through a subsequent report, action or
proceeding, may allow customers to choose their electric supplier. If this
happens without providing for recovery of a significant portion of the costs
associated with our power supply obligations and other costs of providing
vertically integrated service, the Company's franchise, including our operating
results, cash flows and ability to pay dividends at the current level, would be
adversely affected.
ITEM 7A. RISK FACTORS-The major risk factors for the Company arising from
electric industry restructuring, including risks pertaining to the recovery of
stranded costs, are:
* regulatory and legal decisions;
* cost and amount of default service responsibility;
* the market price of power; and
* the amount of market share retained by the Company.
There can be no assurance that any potential future restructuring plan
ordered by the VPSB, the courts, or through legislation will include a mechanism
that would allow for full recovery of our stranded costs and include a fair
return on those costs as they are being recovered. If laws are enacted or
regulatory decisions are made that do not offer an adequate opportunity to
recover stranded costs, we believe we have compelling legal arguments to
challenge such laws or decisions.
The largest category of our potential stranded costs is future costs under
long-term power purchase contracts, which, based on current forecasts, are
above-market. The magnitude of our stranded costs is largely dependent upon the
future market price of power. We have discussed various market price scenarios
with interested parties for the purpose of identifying stranded costs.
Preliminary market price assumptions, which are likely to change, have resulted
in estimates of the Company's stranded costs of between $74 million and $162
million. We intend to aggressively pursue mitigation efforts in order to
minimize the amount and maximize the recovery of these costs.
If retail competition is implemented in Vermont, we cannot predict what
the impact would be on the Company's revenues from electricity sales.
Historically, electric utility rates have been based on a utility's cost of
service. As a result, electric utilities are subject to certain accounting
standards that apply only to regulated businesses. Statement of Financial
Accounting Standards Number 71, ("SFAS 71"), Accounting for the Effects of
Certain Types of Regulation, allows regulated entities, in appropriate
circumstances, to establish regulatory assets and liabilities, and thereby defer
the income statement impact of certain costs and revenues that are expected to
be realized in future rates. The Company has established approximately $47.5
million of net regulatory assets and liabilities under SFAS 71.
The Company currently 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 would be material. Factors that could give rise to
the discontinuance of SFAS 71 include:
* deregulation;
* a change in the regulator's approach to setting rates from cost-based
regulation to another form of regulation;
* increasing competition that limits our ability to sell utility services or
products at rates that will recover costs; and
* regulatory actions that limit rate relief to a level insufficient to
recover costs.
Under Statement of Financial Accounting Standards Number 5 ("SFAS 5"),
Accounting for Contingencies, the enactment of restructuring legislation or
issuance of a regulatory order containing provisions that do not allow for the
recovery of above-market power costs would require the Company to estimate and
record losses immediately, on an undiscounted basis, for any above-market power
purchase contracts and other costs which are probable of not being recoverable
from customers, to the extent that those costs are estimable.
We are unable to predict what form future legislation, if passed, or an
order if issued, will take, and we cannot predict if or to what extent SFAS 71
will continue to be applicable in the future. In addition, members of the staff
of the Securities and Exchange Commission have raised questions concerning the
continued applicability of SFAS 71 to certain other electric utilities facing
restructuring.
We cannot predict whether restructuring legislation enacted by the
Vermont General Assembly or any subsequent report or actions of, or proceedings
before, the VPSB or the Vermont General Assembly would have a material adverse
effect on our operations, financial condition or credit ratings. The failure to
recover a significant portion of our purchased power costs, or to retain and
attract customers in a competitive environment, would likely have a material
adverse effect on our business, including our operating results, cash flows and
ability to pay dividends at current levels.
Inherent in our market risk sensitive instruments and positions is the
potential loss arising from adverse changes in our commodity prices.
Restructuring of the wholesale market for electricity has brought increased
price volatility to our power supply markets.
The price of electricity is subject to fluctuations resulting from changes
in supply and demand. To reduce price risk caused by these market fluctuations,
we have established a policy to hedge (through the utilization of derivatives)
our supply and related purchase and sales commitments, as well as our
anticipated purchase and sales. Because the commodities covered by these
derivatives are substantially the same commodities that the Company buys and
sells in the physical market, no special correlation studies other than
monitoring the degree of convergence between the derivative and cash markets,
are deemed necessary. Changes in market value of derivatives have a high
correlation to the price changes of the hedged commodities.
A sensitivity analysis has been prepared to estimate the exposure to the
market price risk of our electricity commodity positions. Our daily net
commodity position consists of purchased electric capacity. The table below
presents market risk estimated as the potential loss in fair value resulting
from a hypothetical ten percent adverse change in prices. Actual results may
differ materially from the table.
Commodity Price Risk At December 31, 2000
Fair Value Market Risk
--------------- ------------
(in thousands)
Highest long position. $ 173,741 $ 17,374
Highest short position $ 201,608 $ 20,161
Average short position $ 27,867 $ 2,787
Risk factors associated with the discontinuation of MEI operations include
the outcome of warranty litigation, and future cash requirements necessary to
minimize costs of winding down wastewater operations. Several municipalities
using wastewater treatment equipment provided by Micronair, LLC, a wholly owned
subsidiary of MEI, have commenced or threatened litigation against Micronair.
The ultimate loss remains subject to the disposition of remaining MEI assets and
liabilities, and could exceed the amounts recorded.
UNREGULATED BUSINESSES
In 2000, we significantly reduced our investment in unregulated
businesses, continuing the process we began in June 1999, when we decided to
sell or otherwise dispose of the assets of MEI, and report its results as loss
from operations of a discontinued segment. MEI, which invested in energy
generation, energy efficiency and waste water treatment projects, lost $6.5
million in 2000, compared with a loss of $7.3 million in 1999. The 2000 loss
results primarily from provisions to recognize present and estimated future
losses from the sale of MEI's remaining businesses, including anticipated
operating losses.
Green Mountain Resources, Inc. ("GMRI") was formed in April 1996 to
explore opportunities in the emerging competitive retail energy market. In
2000, GMRI earned $19,000 compared with earnings of $583,000 in 1999. GMRI's
earnings in 1999 were primarily due to the sale of its remaining interest in
Green Mountain Energy Resources ending operations for this subsidiary.
The Company's unregulated rental water heater business earned $498,000 in
2000, essentially unchanged from 1999's net income of $500,000. Both 2000 and
1999 results contributed earnings of $0.09 per share to the Company's
consolidated results.
RESULTS OF OPERATIONS
OPERATING REVENUES AND MWH SALES-Operating revenues and megawatthour ("MWh")
sales for the years ended 2000, 1999 and 1998 consisted of:
Years ended December 31,
2000 1999 1998
------------------------- ---------- ----------
(dollars in thousands)
Operating Revenues
Retail. . . . . . . . $ 188,849 $ 179,997 $ 164,855
Sales for Resale. . . 85,428 68,305 16,529
Other . . . . . . . . 3,049 2,746 2,920
------------------------- ---------- ----------
Total Operating Revenues. $ 277,326 $ 251,048 $ 184,304
========================= ========== ==========
MWH Sales-Retail. . . . . 1,947,857 1,900,188 1,839,522
MWH Sales for Resale. . . 2,575,657 2,172,849 543,846
------------------------- ---------- ----------
Total MWH Sales . . . . . 4,523,514 4,073,037 2,383,368
========================= ========== ==========
Average Number of Customers
Years ended December 31,
2000 1999 1998
------------------------ ------ ------
Residential . . . . . . . 72,424 71,515 71,301
Commercial and Industrial 12,769 12,461 12,193
Other . . . . . . . . . . 65 66 70
------------------------ ------ ------
Total Number of Customers. . 85,258 84,042 83,564
======================== ====== ======
Differences in operating revenues were due to changes in the following:
Change in Operating Revenues 1999 to 1998 to
2000 1999
------- -------
(In thousands)
Retail Rates. . . . . . . . . . $ 4,230 $ 9,395
Retail Sales Volume . . . . . . 4,622 5,747
Resales and Other Revenues. . . 17,426 51,602
------- -------
Increase in Operating Revenues. $26,278 $66,744
======= =======
In 2000, total electricity sales increased 11.1 percent due principally to sales
for resale executed pursuant to the Morgan Stanley Capital Group, Inc. ("MS")
agreement, described in more detail below under the headings "Power Supply
Expense" and "Power Contract Commitments". Total operating revenues increased
$26.3 million or 10.5 percent primarily for the same reason. Total retail
revenues increased $8.9 million or 4.9 percent in 2000 primarily due to:
* a 3.0 percent retail rate increase that went into effect January 2000; and
* a 2.6 percent increase in sales of electricity to both our commercial and
industrial and our residential customers resulting primarily from customer
growth and load growth for our largest customer.
In 1999, total electricity sales increased 70.9 percent due principally to
sales for resale executed pursuant to the MS agreement. Total operating
revenues increased $66.7 million or 36.2 percent in 1999 for the same reason.
Total retail revenues increased $15.1 million or 9.2 percent in 1999 primarily
due to:
* a 5.5 percent retail rate increase for service rendered on or after
December 15, 1998;
* a 3.9 percent increase in sales of electricity to our commercial and
industrial customers resulting from customer growth and increased use of air
conditioning during the spring and summer months; and
* a 3.3 percent increase in sales of electricity to residential customers, a
result of customer growth and a warmer than normal summer.
International Business Machines ("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
11.2, 11.8, and 14.7 percent of the Company's total operating revenues in 2000,
1999, and 1998, respectively, and 16.5, 16.4 and 17.1 percent of the Company's
retail operating revenues in 2000, 1999, and 1998, respectively. No other
retail customer accounted for more than one percent of the Company's revenue in
any year.
Since 1995, the Company has had agreements with IBM with respect to
electricity sales above agreed-upon base-load levels. On December 8, 2000, the
VPSB approved a new three-year agreement between the Company and IBM, ending
December 31, 2003. The price of power for the renewal period of the agreement is
above our marginal costs of providing incremental service to IBM.
POWER SUPPLY EXPENSES-Our inability to recover our power supply costs has been
the primary reason for the poor performance of the Company's common stock over
the past three years. The Settlement Order removes this obstacle by allowing
the Company rate recovery of its estimated power supply costs for 2001.
Furthermore, the Settlement Order allows the Company to use approximately $6.0
million in rate levelization cash flow to achieve its allowed rate of return in
2001 and 2002, and, together with the extension of our power supply agreement
with MS, provides us an opportunity to recover our power supply costs in 2002
without further rate relief (See "Power Supply Commitments", "Retail Rate Cases"
and "Risk Factors" in this section).
Power supply expenses constituted 79.4, 75.4, and 67.7 percent of total
operating expenses for the years 2000, 1999, and 1998, respectively. Power
supply expenses increased by $30.2 million or 16.5 percent in 2000 and $62.2
million or 51.4 percent in 1999. The increase in power supply expenses from 1999
to 2000 resulted from the following:
* a $20.0 million increase from power purchased for resale, primarily under
a power supply agreement discussed below, whereby we buy power from MS that is
sufficient to serve pre-established load requirements at a pre-defined price;
* a $7.7 million increase in energy costs arising from a power supply
arrangement with Hydro-Quebec, discussed below, whereby Hydro-Quebec has an
option to purchase energy at prices that were below market replacement costs;
* the costs to serve increased retail sales of electricity of 2.8 percent in
2000 and higher unit power supply costs; and
* a $3.6 million increase in capacity costs associated with our long-term
Hydro-Quebec power supply contract.
These amounts were partially offset by a reduction in 2000 of $9.7 million
in losses accrued for the Hydro-Quebec power cost disallowance under past
regulatory rulings. Results for 1999 reflected pretax charges of $2.2 million
in disallowed Hydro-Quebec power costs, compared with the amortization during
2000 of accrued power expense of $7.5 million for 2000 that had been recorded in
1999. The power supply costs of Company-owned generation increased 74.8
percent or $4.2 million in 2000 due to purchases by MS under a power supply
agreement discussed below and because units were dispatched for system
reliability requirements due to the unavailability of certain transmission
facilities. Power supply expenses increased by $62.2 million or 51.4 percent
from 1998 to 1999. The increase in power supply expenses from 1998 to 1999
resulted from the following:
* a $57.0 million increase reflecting the power purchase and supply
agreement discussed below, whereby we buy power from MS that is sufficient to
serve pre-established load requirements at a pre-defined price;
* a $4.3 million increase in the capacity costs in 1999 associated with our
long-term Hydro-Quebec power supply contract;
* an increase in the costs of short-term power following the deregulation of
wholesale energy markets in New England, as well as an increase in our costs to
serve increased local loads and to supply power to meet contractual obligations
under the Company's December 1997 sell-back arrangement with Hydro-Quebec (net
cost approximately $5.4 million); and
* a $1.9 million increase in Vermont Yankee capacity costs.
These amounts were partially offset by a reduction of $2.3 million in
losses accrued for the Hydro-Quebec power cost disallowance. Results for 1998
reflected pretax charges of $9.8 million in disallowed Hydro-Quebec power costs
for both 1998 and 1999, compared with disallowed power costs of $7.5 million for
2000 recorded in 1999.
The power supply costs of Company-owned generation decreased 13.0 percent
in 1999 due to the severe 1998 ice storm in New England that caused increased
usage in that year of peak generation resources to replace power that was
unavailable from Hydro-Quebec.
An Independent System Operator in New England ("ISO") replaced the New
England Power Pool ("NEPOOL") effective May 1, 1999. The ISO works as a
clearinghouse for purchasers and sellers of electricity in the new deregulated
wholesale markets. Sellers place bids for the sale of their generation or
purchased power resources and if demand is high enough the output from those
resources is sold.
We must purchase electricity to meet customer demand during periods of high
usage and to replace energy repurchased by Hydro-Quebec under an arrangement
negotiated in 1997. Our costs to serve demand during periods of warmer than
normal temperatures in summer months and to replace such energy repurchases by
Hydro-Quebec rose substantially after the wholesale power markets became
deregulated, which caused much greater volatility in spot prices for
electricity. The cost of securing future power supplies has also risen
substantially in tandem with higher summer power supply costs. The Company
cannot predict the duration or the extent to which future prices will continue
to trade above historical levels of cost. If the new markets continue to
experience the volatility evident during 1999 and 2000, our earnings and cash
flow could be adversely impacted by a material amount.
POWER CONTRACT COMMITMENTS- On February 11, 1999, we entered into a contract
with MS as a result of our power requirements solicitation in 1998. A master
power purchase and sales agreement ("PPSA") defines the general contract terms
under which the parties may transact. The sales under the PPSA commenced on
February 12, 1999 and will terminate after all obligations under each
transaction entered into by MS and the Company has been fulfilled. The PPSA has
been noticed to the VPSB and filed with the Federal Energy Regulatory Commission
("FERC"). In January 2001, the PPSA was modified and extended to December 31,
2003.
The PPSA provides us with a means of managing price risks associated with
changing fossil fuel prices. On a daily basis, and at MS's discretion, we sell
power to MS from either (i) all or part of our portfolio of power resources at
predefined operating and pricing parameters or (ii) any power resources
available to us, provided that sales of power from sources other than
Company-owned generation comply with the predefined operating and pricing
parameters. MS then sells to us, at a predefined price, power sufficient to
serve pre-established load requirements. MS is also responsible for scheduling
supply resources. We remain responsible for resource performance and
availability. MS provides no coverage against major unscheduled outages. The
Company and MS have agreed to the protocols that are used to schedule power
sales and purchases and to secure necessary transmission. We estimate that the
Company saved approximately $4.8 million during 2000 over what our energy costs
would have been absent the PPSA due to our avoiding significant increases in
2000 fossil fuel prices.
During 1994, we negotiated an arrangement with Hydro-Quebec that reduced
the cost under our 1987 contract with Hydro-Quebec over the November 1995
through October 1999 period (the "July 1994 Agreement").
As part of the July 1994 Agreement, we were obligated to purchase $4.0
million (in 1994 dollars) worth of research and development work from
Hydro-Quebec over a four-year period (which has since been extended to 2001),
and made a $6.5 million (in 1994 dollars) payment to Hydro-Quebec in 1995.
Hydro-Quebec retains the right to curtail annual energy deliveries by 10 percent
up to five times, over the 2000 to 2015 period, if documented drought conditions
exist in Qu bec.
During the first year of the July 1994 Agreement (the period from November
1995 through October 1996), the average cost per kilowatt-hour of Schedules B
and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a 34 percent
(or $16 million) cost reduction. Over the period from November 1996 through
December 2000 and accounting for the payments to Hydro-Quebec, the combined unit
costs will be lowered from 6.5 to 5.9 cents per kilowatt-hour, reducing unit
costs by 10 percent and saving $20.7 million in nominal terms.
Under a power supply arrangement executed in January 1996 ("9601"), we
received payments from Hydro-Quebec of $3.0 million in 1996 and $1.1 million in
1997. Under 9601 we are required to shift up to 40 megawatts of 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. 9601 also provides for minimum payments
by the Company to Hydro-Quebec for periods in which power is not purchased under
the arrangement. 9601 allows Hydro-Quebec to curtail deliveries of energy
should it need to use certain resources to supplement available supply.
Hydro-Quebec did curtail deliveries in the fourth quarter of 2000. Although our
level of future benefits will depend on various factors, including market prices
and availability of energy from HQ, we estimate that 9601 has provided a benefit
of approximately $3.0 million on a net present value basis through December 31,
2000.
Under a separate arrangement executed on December 5, 1997 ("9701"),
Hydro-Quebec paid $8.0 million to the Company in 1997. In return for this
payment, we provided Hydro-Quebec options for the purchase of power. Commencing
April 1, 1998 and effective through the term of the 1987 Contract, which ends in
2015, Hydro-Quebec may purchase up to 52,500 MWh ("option A") on an annual
basis, at the 1987 Contract energy prices, which are substantially below current
market prices. The cumulative amount of energy that may be purchased under
option A shall not exceed 950,000 MWh
Over the same period, Hydro-Quebec may exercise an option to purchase a
total of 600,000 MWh ("option B") at the 1987 Contract energy price. Under
option B, Hydro-Quebec may purchase no more than 200,000 MWh in any year. As of
December 31, 2000, Hydro-Quebec had purchased or called to purchase 349,000 MWh
under option B, including calls for January and February of 2001.
In 2000, Hydro-Quebec exercised option A and option B, calling for
deliveries to third parties at a net cost to the Company of approximately $14.0
million (including the cost of January and February, 2001 calls, and the cost of
related financial positions), which was due to higher energy replacement costs
incurred by the Company. Approximately $6.6 million of the $14.0 million net
9701 costs were recovered in rates on an annual basis.
In 1999, Hydro-Quebec called for deliveries to third parties at a net cost
of approximately $6.3 million. Hydro-Quebec's option to curtail energy
deliveries pursuant to the July 1994 Agreement can be exercised in addition to
these purchase options.
The VPSB, in the Settlement Order said, "The record does not demonstrate
that any other New England utility foresaw the extent and degree of volatility
that has developed in the New England wholesale power markets. Absent that
volatility, the 97-01 Agreement would not have had adverse effects." In
conjunction with the Settlement Order, Hydro-Quebec committed to the
Department, that it would not call any energy under option B of 9701 during
2002.
In 1999, the Company and the other Vermont Joint Owners who are parties to
the Hydro-Quebec contract initiated an arbitration against Hydro-Quebec,
pursuant to the 1987 Contract terms, to determine whether Hydro-Quebec's
suspension of deliveries of power to Vermont during and after the January 1998
ice storm evidenced a default by Hydro-Quebec under the terms of that contract.
Hydro-Quebec maintains that the "force majeure" (superior or irreversible force)
provision in the 1987 Contract applies, which could excuse its non-delivery of
power under these circumstances. Arbitration of the dispute may lead to
remedies having a material impact on our contractual obligation, including the
possibility that the 1987 Contract be declared terminated or void. If
arbitration results in a cash payment, it will first be applied to a regulatory
asset of $4.7 million for arbitration litigation costs. The Settlement Order
provides that the Company will not earn a return on these litigation costs,
unless the case results in lower power supply costs for ratepayers. Hearings
have concluded and a decision is expected in April 2001. If the contract is
declared terminated or void, the Company would have to replace a substantial
amount of its power needs at terms which could materially exceed the 1987
Contract price for 2001. The Company believes that it could contract
replacement power at costs below the long term costs of the 1987 Contract.
OTHER OPERATING EXPENSES- Other operating expenses increased $0.1 million in
2000. The increase is primarily due to a $3.2 million charge for disallowed
regulatory litigation costs, ordered by the VPSB as part of the Settlement
Order. The increase was offset by a $3.3 million decrease in administrative and
general expense caused by the Company's reorganization efforts that reduced the
size of the workforce and lowered building occupancy costs.
Other operating expenses decreased $3.7 million or 17.4 percent in 1999.
The decrease resulted from:
* a $1.9 million estimated loss in 1998 to recognize the cost of terminating
the Company's corporate headquarters operating lease. The facilities were sold
in April 1999;
* a $1.4 million reduction in administrative and general salaries related to
a workforce reduction plan;
* the elimination in 1999 of a regulatory liability of $1.2 million relating
to the Company's former corporate headquarters; and
* reductions in lease expense and facility carrying costs resulting from the
disposal of the former headquarters.
These savings were partially offset by increased costs of approximately
$1.8 million associated with the Company's reorganization.
TRANSMISSION EXPENSES-Transmission expenses increased $1.5 million or 14.0
percent in 2000 primarily due to congestion charges that reflect the lack of
adequate transmission or generation capacity in certain locations within New
England. These charges are allocated to all ISO New England members. The Company
is unable to predict the magnitude or duration of future congestion charge
allocation, but amounts could be material. Transmission expenses increased $1.4
million or 15.0 percent in 1999 due to costs associated with the creation of the
ISO as the clearing house for power trades in New England and due to refunds in
1998 from Central Vermont Public Service Corp. and New England Power Company.
A FERC ruling in December 2000 required ISO New England to revise its
installed capability ("ICAP") deficiency charge of $0.17 per kw month to $8.75
per kw month retroactive to August 1, 2000. On January 10, 2001, FERC stayed its
order "to ensure that bills for past periods will not be assessed until the
Commission has considered the pending requests for rehearing, which, if
successful, would then require extensive refunds and surcharges." On March 6,
2001, FERC issued an Order on Rehearing in which it partly reversed itself on
the ICAP charge. Although the Commission first concluded that a $8.75 charge is
reasonable and that the charge would remain in place until the ISO supports an
acceptable superseding proposal, the Commission then concluded that reinstating
the $8.75 would have a large cost impact. As a result, the $0.17 per kW month
charge was reinstated from August 1, 2000 until April 1, 2001. The Commission
allowed the $8.75 charge to become effective on April 1, 2001 until the
effective date of any superseding charge the Commission might accept. On March
16, 2001, an ISO New England participant filed a request for re-hearing the
FERC's March 6, 2001 Order on Rehearing. The request asks for a reversal of the
lowered ICAP charge for the period from August 1, 2000 until April 1, 2001. If
the lowered ICAP charge is increased to $8.75 per kw month, then the Company
would be required to pay ISO New England approximately $1.4 million. Management
cannot determine the ultimate impact of the request at this time.
In 2000, FERC issued a separate order ("Order 2000") requiring all
utilities to file plans for the formation and administration of regional
transmission organizations ("RTO"). In January 2001, the Company and other
Vermont transmission owning companies filed in compliance with Order 2000. The
Vermont companies support the Petition for Declaratory Order by various New
England transmission owning companies, with reservations. The Vermont companies'
principal concerns relate to:
* whether a New England RTO ("NERTO") will include all non-Pool Transmission
Facilities in the NERTO Tariff on a rolled in basis;
* whether Highgate and Phase I/Phase II transmission facilities will be
included in the Tariff without a separate transmission levy;
* whether NERTO will continue the transition to a single regional
transmission rate; and
* the percentage of equity that transmission owners may acquire in the new
organization.
The Company is unable to estimate how these issues will be resolved, but
the impact could be material.
MAINTENANCE EXPENSES-Maintenance expenses decreased $0.1 million or 1.4 percent
in 2000 due to changes in scheduled maintenance. Maintenance expenses increased
$1.5 million or 29.6 percent in 1999, reflecting increased expenditures on
right-of-way maintenance programs.
DEPRECIATION AND AMORTIZATION- Depreciation and amortization expenses
decreased $0.9 million or 5.5 percent in 2000 due to reductions in amortization
of demand side management costs that were only partially offset by increased
depreciation of utility plant in service. In 1999, depreciation and amortization
were at similar levels compared with that of 1998.
INCOME TAXES-Income tax amounts decreased for 2000 due to an increase in the
Company's taxable loss. Income taxes decreased for 1999 due to a decrease in
taxable income.
OTHER INCOME- Other income decreased $0.7 million in 2000 due to a $0.6
million gain on the 1999 sale of GMER. Other income increased $1.9 million in
1999, due to the 1999 gain on the sale of the Company's remaining interest in
GMER discussed previously under "Unregulated Businesses", and a $0.9 million
write-off in 1998 for disallowed costs at our Searsburg wind project.
INTEREST CHARGES-Interest expense increased $0.1 million or 1.0 percent in 2000
due to increases in short-term debt and rising interest rates that were
partially offset by reductions in long-term debt. Interest expense decreased
$0.7 million or 8.7 percent in 1999, consistent with reductions in average
long-term and short-term debt outstanding during the year.
DIVIDENDS ON PREFERRED STOCK- Dividends on preferred stock decreased
$141,000, or 12.2 percent in 2000 due to repurchases of preferred stock. In
1999, the dividends on preferred stock also decreased $141,000 or 10.9 percent
for the same reason.
ENVIRONMENTAL MATTERS
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air and
aesthetic requirements as administered by local, state and federal regulatory
agencies. We believe that we are in substantial compliance with these
requirements, and that there are no outstanding material complaints about our
compliance with present environmental protection regulations, except for
developments related to the Pine Street Barge Canal site.
PINE STREET BARGE CANAL SITE-The Federal Comprehensive Environmental Response,
Compensation, and Liability Act ("CERCLA"), commonly known as the "Superfund"
law, generally imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous substances. We have
previously been notified by the Environmental Protection Agency ("EPA") that we
are one of several potentially responsible parties ("PRPs") for cleanup of the
Pine Street Barge Canal site in Burlington, Vermont, where coal tar and other
industrial materials were deposited.
In September 1999, we negotiated a final settlement with the United States,
the State of Vermont (the "State"), and other parties to a Consent Decree that
covers claims with respect to the site and implementation of the selected site
cleanup remedy. In November 1999, the Consent Decree was filed in the federal
district court. The Consent Decree addresses claims by the EPA for past Pine
Street Barge Canal site costs, natural resource damage claims and claims for
past and future oversight costs. The Consent Decree also provides for the
design and implementation of response actions at the site.
As of December 31, 2000, our total expenditures related to the Pine Street
Barge Canal site since 1982 were approximately $23.5 million. This includes
amounts not recovered in rates, amounts recovered in rates, and amounts for
which rate recovery has been sought but which are presently awaiting further
VPSB action. The bulk of these expenditures consisted of transaction costs.
Transaction costs include legal and consulting costs associated with the
Company's opposition to the EPA's earlier proposals for a more expensive remedy
at the site, litigation and related costs necessary to obtain settlements with
insurers and other PRPs to provide amounts required to fund the clean up
("remediation costs"), and to address liability claims at the site. A smaller
amount of past expenditures was for site-related response costs, including costs
incurred pursuant to EPA and State orders that resulted in funding response
activities at the site, and to reimbursing the EPA and the State for oversight
and related response costs. The EPA and the State have asserted and affirmed
that all costs related to these orders are appropriate costs of response under
CERCLA for which the Company and other PRPs were legally responsible.
We estimate that we have recovered or secured, or will recover, through
settlements of litigation claims against insurers and other parties, amounts
that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We currently estimate
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $12.4 million over the next 33
years. The estimated liability is not discounted, and it is possible that our
estimate of future costs could change by a material amount. We also have
recorded an offsetting regulatory asset and we believe that it is probable that
we will receive future revenues to recover these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and
received recovery for ongoing expenses associated with the Pine Street Barge
Canal site. While reserving the right to argue in the future about the
appropriateness of full rate recovery of the site-related costs, the Company and
the Department, and as applicable, other parties, reached agreements in these
cases that the full amount of the site-related costs reflected in those rate
cases should be recovered in rates.
We proposed in our rate filing made on June 16, 1997 recovery of an
additional $3.0 million in such expenditures. In an Order in that case released
March 2, 1998, the VPSB suspended the amortization of expenditures associated
with the Pine Street Barge Canal site pending further proceedings. Although it
did not eliminate the rate base deferral of these expenditures, or make any
specific order in this regard, the VPSB indicated that it was inclined to agree
with other parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance carriers
and other PRPs, should be shared between customers and shareholders of the
Company. In response to our Motion for Reconsideration, the VPSB on June 8,
1998 stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
The Settlement Order released January 23, 2001 did not change the status of Pine
Street cost recovery.
CLEAN AIR ACT-Because we purchase most of our power supply from other utilities,
we do not anticipate that we will incur any material direct cost increases as a
result of the Federal Clean Air Act or proposals to make more stringent
regulations under that Act. Furthermore, only one of our power supply purchase
contracts, which expired in early 1998, related to a generating plant that was
affected by Phase I of the acid rain provisions of this legislation, which went
into effect January 1, 1995.
RATES
RETAIL RATE CASES- On March 2, 1998, the VPSB released its Order dated February
27, 1998 in the then pending rate case (the "1997 rate case"). The VPSB
authorized us to increase our rates by 3.61 percent, which gave us increased
annual revenues of $5.6 million. The VPSB Order denied us the right to charge
customers $5.48 million of the annual costs for power purchased under our
contract with Hydro-Quebec. The VPSB denied recovery of these costs for the
following reasons:
* The VPSB claimed that we had acted imprudently by committing to the power
contract with Hydro-Quebec in August 1991 (the imprudence disallowance); and
* To the extent that the costs of power to be purchased from Hydro-Quebec
were higher than current estimates of market prices for power during the
contract term, after accounting for the imprudence disallowance, the contract
power was decreed not "used and useful".
We appealed the VPSB's ruling in the 1997 rate case to the Vermont Supreme
Court.
On May 8, 1998, we filed a request with the VPSB to increase our retail
rates by 12.93 percent due to higher power costs, the cost of the January 1998
ice storm, and investments in new plant and equipment (the "1998 rate case").
On November 18, 1998, by Memorandum of Understanding ("MOU"), the
Company, the Department and IBM agreed to stay rate proceedings in the 1998 rate
case until or after September 1, 1999, or such earlier date as the parties may
later agree to or the VPSB may order. The agreement to suspend our 1998 rate
case delayed the date of a final decision on the 1998 rate case to December 15,
1999, and we recognized an additional loss of $5.25 million in the last quarter
of 1998 representing the effect of the continued disallowance of Hydro-Quebec
costs through December 15, 1999. The MOU provided for a 5.5 percent temporary
rate increase, to produce $8.9 million in annualized additional revenue,
effective with service rendered December 15, 1998. An additional surcharge was
permitted, without further VPSB order, in order to produce additional revenues
necessary to provide the Company with the capacity to finance 1999 Pine Street
Barge Canal site expenditures. The MOU was approved by the VPSB on December 11,
1998. The MOU did not provide for any specific disallowance of power costs under
our purchase power contract with Hydro-Quebec. Issues respecting recovery of
such power costs were preserved for future proceedings.
The stay and suspension of the 1998 rate case and the temporary rate levels
agreed to in the MOU were designed to allow us to continue to provide adequate
and efficient service to our customers while we sought mitigation of power
supply costs.
On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments to the MOU that the Company had entered into with the Department and
IBM. The two amendments continued the stay of proceedings until September 1,
2000, with a final decision expected by December 31, 2000. The amendments
maintained the other features of the original MOU, and the second amendment
provided for a temporary rate increase of 3 percent, in addition to the previous
temporary rate level, to become effective as of January 1, 2000. The Company
reached a final settlement agreement with the Department in the 1998 rate case
during November 2000. The final settlement agreement contains the following
provisions:
* A rate increase of 3.42 percent above existing rates, beginning with bills
rendered January 23, 2001, and prior temporary rate increases became permanent;
* Rates set at levels that recover the Company's Hydro-Quebec VJO contract
costs, effectively ending the regulatory disallowances experienced by the
Company over the past three years;
* The Company agrees not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a
request for additional rate relief if power supply costs increase in excess of
$3.75 million over forecasted levels;
* The Company agreed to write off approximately $3.2 million in unrecovered
rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
* Seasonal rates will be eliminated in April 2001, which is expected to
generate approximately $6.0 million in additional cash flow in 2001 that can be
utilized to offset increased costs during 2001, 2002 and 2003;
* The Company agrees to consult extensively with the Department regarding
capital spending commitments for upgrading our electric distribution system and
to adopt customer care and reliability performance standards, in a first step
toward possible development of performance-based rate-making; and
* The Company agrees to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in the 1997 rate case.
On January 23, 2001, the VPSB approved the Company's settlement with the
Department, with two additional conditions:
* The VPSB Order requires the Company and customers to share equally any
premium above book value realized by the Company in any future merger,
acquisition or asset sale, subject to an $8.0 million limit on the customers'
share; and
* The second condition restricts Company investments in non-utility
operations.
LIQUIDITY AND CAPITAL RESOURCES
CONSTRUCTION-Our capital requirements result from the need to construct
facilities or to invest in programs to meet anticipated customer demand for
electric service. Capital expenditures over the past three years and forecasted
for 2001 are as follows:
Generation Transmission Distribution Conservation Other* Total
--------------- ------------- ------------- ------------- ------- -------
(In thousands)
Actual:
- ---------
1998. . . $ 543 $ 751 $ 6,063 $ 1,244 $ 4,568 $13,169
1999. . . 210 144 5,930 1,943 9,039 17,266
2000. . . 2,195 931 7,169 ** 3,955 14,250
Forecast:
- ---------
2001. . . $ 2,830 $ 2,060 $ 8,540 ** $ 2,320 $15,750
* Other includes $6.1 million in 1999, $1.3 million in 2000, and $1.9 million
in 2001 for the Pine Street Barge Canal Site.
**A state-wide Energy Efficiency Utility set up by the VPSB in 1999 manages all
energy efficiency programs, receiving funds the Company bills to its customers
as a separate charge.
DIVIDEND POLICY- The annual dividend rate was $0.55 per share at December 31,
2000.
The Settlement Order limits the dividend rate at its current level until
short term credit facilities are replaced with long term debt or equity
financing. Retained earnings at December 31, 2001 were approximately $0.5
million. The Company anticipates substantial improvement in retained earnings
during 2001, beginning with the first quarter, and believes it will be able to
maintain the current dividend rate. If retained earnings were eliminated, the
Company would not be able to declare a dividend under its Restated Articles of
Association.
FINANCING AND CAPITALIZATION-Internally-generated funds provided approximately
59 percent of requirements for 2000, 1999 and 1998 combined.
Internally-generated funds, after payment of dividends, provide capital
requirements for construction, sinking funds and other requirements. We
anticipate that for 2001, internally generated funds will provide approximately
90 percent of total capital requirements for regulated operations.
At December 31, 2000, our capitalization consisted of 49.3 percent common
equity, 43.8 percent long-term debt and 6.9 percent preferred equity.
On June 21, 2000, we renewed a $15.0 million revolving credit agreement
with Fleet National Bank and Citizens Bank of Massachusetts (the "Fleet
Agreement"). The Fleet Agreement is for a period of 364 days and will expire on
June 20, 2001. At December 31, 2000, there was $0.5 million outstanding on the
Fleet Agreement. The Fleet Agreement is secured by granting the banks a second
priority mortgage, lien and security interest in the collateral pledged under
the Company's first mortgage bond indenture.
On September 20, 2000, we established a $15.0 million revolving credit
agreement with KeyBank National Association ("KeyBank"). The agreement will
expire on September 19, 2001. Pursuant to a one year power supply option
agreement between the Company and Energy East Corporation ("EE"), EE made a
payment of $15.0 million to the Company. In exchange, the Company gave EE an
option to purchase energy from certain wholly owned production facilities, for a
period not to exceed 15 years, if the funds are not returned to EE upon request
after September 2001. The Company was required to invest the funds provided by
EE in a certificate of deposit at KeyBank pledged by the Company to secure the
repayment of the Keybank revolving credit facility. At December 31, 2000, there
was $15.0 million outstanding on the KeyBank line of credit.
The Company anticipates that it will secure financing that replaces some or
all of its expiring facilities during 2001. The Settlement Order will likely
permit restoration of the Company's investment grade debt rating, allowing
arrangement of such financing as the Company needs during 2001.
The credit ratings of the Company's securities are:
Fitch Moody's Standard & Poor's
-------- ------- -----------------
First mortgage bonds . . . BB+ Baa2 BBB
Unsecured medium term debt BB- -- --
Preferred stock. . . . . . B+ baa3 BB
On March 5, 2001, Moody's Investors Service upgraded the Company's first
mortgage bond rating to Baa2 from Ba1, and upgraded the Company's preferred
stock rating to baa3 from ba3. The rating action reflected Moody's earnings and
cash flow expectations for the Company following the Settlement Order.
On August 25, 2000, Fitch (formerly Duff & Phelps) downgraded the credit
ratings of the Company to below investment grade and maintained the ratings on
Rating Watch-Negative. Since the Settlement Order, Fitch and Standard & Poor's
have favorably changed their outlook relative to the ratings direction for the
Company, moving us from Rating Watch-Negative and Credit Watch- Negative to
Rating Watch-Positive and Credit Watch-Developing, respectively.
NUCLEAR DECOMMISSIONING-The staff of the SEC has questioned certain current
accounting practices of the electric utility industry regarding the recognition,
measurement and classification of decommissioning costs for nuclear generating
units in financial statements. In response to these questions, the Financial
Accounting Standards Board had agreed to review the accounting for closure and
removal costs, including decommissioning. We do not believe that changes in
such accounting, if required, would have an adverse effect on the results of
operations due to our current and future ability to recover decommissioning
costs through rates.
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.
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Financial Statements Page
Consolidated Statements of Income 40
For the Years Ended December 31, 2000, 1999, and 1998
Consolidated Statements of Cash Flows For the 41
Years Ended December 31, 2000, 1999, and 1998
Consolidated Balance Sheets as of 42
December 31, 2000 and 1999
Consolidated Capitalization Data as of 44
December 31, 2000 and 1999
Notes to Consolidated Financial Statements 45
Quarterly Financial Information 68
Report of Independent Public Accountants 69
Schedules
For the Years Ended December 31, 2000, 1999, and 1998:
II Valuation and Qualifying Accounts and Reserves 70
All other schedules are omitted as they are either
not required, not applicable or the information is
otherwise provided.
Consent and Report of Independent Public Accountants
Arthur Andersen LLP 71
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31,
2000 1999 1998
--------- --------- ---------
(In thousands, except per share data)
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $277,326 $251,048 $184,304
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation . . . . . . . . . . . . . . . . . 34,813 34,987 32,910
Company-owned generation . . . . . . . . . . . . . . . . . . . . . . . . . 9,756 5,582 6,412
Purchases from others. . . . . . . . . . . . . . . . . . . . . . . . . . . 168,947 142,699 81,706
Other operating. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,644 17,582 21,291
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,258 10,800 9,389
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,633 6,728 5,190
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . 15,304 16,187 16,059
Taxes other than income. . . . . . . . . . . . . . . . . . . . . . . . . . . 7,402 7,295 7,242
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (691) 1,242 (1,367)
--------- --------- ---------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . 272,066 243,102 178,832
--------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,260 7,946 5,472
--------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. . . . . . . . . 2,495 2,919 2,058
Allowance for equity funds used during construction. . . . . . . . . . . . . 284 134 104
Other income (deductions), net . . . . . . . . . . . . . . . . . . . . . . . (73) 400 (549)
--------- --------- ---------
Total other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,706 3,453 1,613
--------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 7,966 11,399 7,085
--------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,499 6,716 6,991
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 986 558 1,016
Allowance for borrowed funds used during construction. . . . . . . . . . . . (228) (91) (131)
--------- --------- ---------
Total interest charges . . . . . . . . . . . . . . . . . . . . . . . . . . 7,257 7,183 7,876
--------- --------- ---------
INCOME (LOSS) BEFORE PREFERRED DIVIDENDS AND
DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . 709 4,216 (791)
Dividends on preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . 1,014 1,155 1,296
--------- --------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS . . . . . . . . . . . . . . . . . . . (305) 3,061 (2,087)
Net loss from discontinued segment operations, net of applicable income taxes. - (603) (2,086)
Loss on disposal, including provisions for
operating losses during phaseout period, net of applicable income taxes. . . (6,549) (6,676) -
--------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . . . . . . . . . . $ (6,854) $ (4,218) $ (4,173)
========= ========= =========
COMMON STOCK DATA
Basic and diluted earnings (loss) per share from discontinued operations . . . $ (1.19) $ (1.36) $ (0.40)
Basic and diluted earnings (loss) per share from continuing operations . . . . (0.06) 0.57 (0.40)
--------- --------- ---------
Basic and diluted earnings (loss) per share. . . . . . . . . . . . . . . . . . $ (1.25) $ (0.79) $ (0.80)
========= ========= =========
Cash dividends declared per share. . . . . . . . . . . . . . . . . . . . . . . $ 0.55 $ 0.55 $ 0.96
Weighted average shares outstanding. . . . . . . . . . . . . . . . . . . . . . 5,491 5,361 5,243
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Balance - beginning of period. . . . . . . . . . . . . . . . . . . . . . . . . $ 10,344 $ 17,508 $ 26,717
Net Income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,840) (3,063) (2,877)
--------- --------- ---------
4,504 14,445 23,840
--------- --------- ---------
Cash dividends-redeemable cumulative preferred stock . . . . . . . . . . . . . 1,014 1,155 1,296
Cash dividends-common stock. . . . . . . . . . . . . . . . . . . . . . . . . . 2,997 2,946 5,036
--------- --------- ---------
4,011 4,101 6,332
--------- --------- ---------
Balance - end of period. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 493 $ 10,344 $ 17,508
========= ========= =========
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED
DECEMBER 31,
2000 1999 1998
--------------- -------- ---------
OPERATING ACTIVITIES: (In thousands)
Net Loss . . . . . . . . . . . . . . . . . . . . . . . . . $ (5,840) $(3,063) ($2,877)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . . 15,304 16,187 16,059
Dividends from associated companies less equity income. . (26) 169 812
Allowance for funds used during construction. . . . . . . (512) (224) (235)
Amortization of purchased power costs . . . . . . . . . . 5,575 5,725 6,405
Deferred income taxes . . . . . . . . . . . . . . . . . . 443 1,812 (112)
Loss on discontinued segment operations . . . . . . . . . 6,549 6,676 -
Deferred purchased power costs. . . . . . . . . . . . . . (6,692) (6,590) (7,830)
Accrued purchase power contract option call . . . . . . . 8,276 - -
Deferred arbitration costs. . . . . . . . . . . . . . . . (3,184) (1,684) -
Amortization of investment tax credits. . . . . . . . . . (282) (282) (282)
Provision for chargeoff of deferred regulatory asset. . . 3,229 - 0
Environmental and conservation expenditures . . . . . . . (2,073) (8,048) 1,177
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . . (3,862) 474 (1,611)
Accrued utility revenues. . . . . . . . . . . . . . . . (125) (358) (105)
Fuel, materials and supplies. . . . . . . . . . . . . . (766) (150) 122
Prepayments and other current assets. . . . . . . . . . (165) 4,009 (983)
Accounts payable. . . . . . . . . . . . . . . . . . . . 3,004 665 (1,893)
Accrued income taxes payable and receivable . . . . . . (372) (1,611) (2,473)
Other current liabilities . . . . . . . . . . . . . . . (7,341) 1,722 3,229
Other . . . . . . . . . . . . . . . . . . . . . . . . . . (180) (324) 536
--------------- -------- ---------
Net cash provided by continuing operations. . . . . . . . 10,959 15,105 9,939
Net change in discontinued segment. . . . . . . . . . . . 245 (138) -
--------------- -------- ---------
Net cash provided by operating activities . . . . . . . . 11,204 14,967 9,939
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . . . (13,853) (9,174) (10,900)
Proceeds from sale of subsdiaries . . . . . . . . . . . . . 6,000 - 11,500
Investment in nonutility property . . . . . . . . . . . . . (187) (190) (1,442)
--------------- -------- ---------
Net cash used in investing activities . . . . . . . . . . (8,040) (9,364) (842)
--------------- -------- ---------
FINANCING ACTIVITIES:
Issuance of common stock. . . . . . . . . . . . . . . . . . 1,250 1,054 1,587
Investment in certificate of deposit, pledged for revolver. (15,437) - -
Power supply option obligation. . . . . . . . . . . . . . . 15,419 - -
Short-term debt, net. . . . . . . . . . . . . . . . . . . . 7,600 900 4,384
Cash dividends. . . . . . . . . . . . . . . . . . . . . . . (4,011) (4,101) (6,332)
Reduction in preferred stock. . . . . . . . . . . . . . . . (1,640) (1,650) (1,650)
Reduction in long-term debt . . . . . . . . . . . . . . . . (6,700) (1,700) (6,767)
--------------- -------- ---------
Net cash used in financing activities . . . . . . . . . . (3,519) (5,497) (8,778)
--------------- -------- ---------
Net increase(decrease) in cash and cash equivalents . . . . (355) 106 319
Cash and cash equivalents at beginning of period. . . . . . 696 590 271
--------------- -------- ---------
Cash and cash equivalents at end of period. . . . . . . . . $ 341 $ 696 $ 590
=============== ======== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . . $ 7,185 $ 7,034 $ 7,857
Income taxes, net . . . . . . . . . . . . . . . . . . . . 1,191 997 2,285
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31,
2000 1999
-------- --------
(In thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost. . . . . . . . $291,107 $283,917
Less accumulated depreciation. . . . . . . . . 110,273 102,854
-------- --------
Net utility plant. . . . . . . . . . . . . . . 180,834 181,063
Property under capital lease . . . . . . . . . 6,449 7,038
Construction work in progress. . . . . . . . . 7,389 4,795
-------- --------
Total utility plant, net . . . . . . . . . . 194,672 192,896
-------- --------
OTHER INVESTMENTS
Associated companies, at equity. . . . . . . . 14,373 14,545
Other investments. . . . . . . . . . . . . . . 6,357 6,120
-------- --------
Total other investments. . . . . . . . . . . 20,730 20,665
-------- --------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . 341 656
Certficate of deposit, pledged as collateral . 15,437 -
Accounts receivable, customers and others,
less allowance for doubtful accounts
of $463, and 398 . . . . . . . . . . . . . . 22,365 18,503
Accrued utility revenues . . . . . . . . . . . 7,093 6,969
Fuel, materials and supplies, at average cost. 4,056 3,290
Prepayments. . . . . . . . . . . . . . . . . . 2,525 2,197
Income tax receivable. . . . . . . . . . . . . 1,613 1,241
Other. . . . . . . . . . . . . . . . . . . . . 222 382
-------- --------
Total current assets . . . . . . . . . . . . 53,652 33,238
-------- --------
DEFERRED CHARGES
Demand side management programs. . . . . . . . 6,358 7,640
Purchased power costs. . . . . . . . . . . . . 11,789 7,435
Pine Street Barge Canal. . . . . . . . . . . . 12,370 8,700
Other. . . . . . . . . . . . . . . . . . . . . 15,519 19,521
-------- --------
Total deferred charges . . . . . . . . . . . 46,036 43,296
-------- --------
NON-UTILITY
Cash and cash equivalents. . . . . . . . . . . - 40
Other current assets . . . . . . . . . . . . . 8 8
Property and equipment . . . . . . . . . . . . 252 253
Business segment held for disposal . . . . . . - 9,477
Other assets . . . . . . . . . . . . . . . . . 1,258 1,321
-------- --------
Total non-utility assets . . . . . . . . . . 1,518 11,099
-------- --------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . $316,608 $301,194
======== ========
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31,
2000 1999
--------- ---------
(In thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock equity
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,582,552, and 5,425,571). . . . . . . . . . . . $ 18,608 $ 18,085
Additional paid-in capital . . . . . . . . . . . 73,321 72,594
Retained earnings. . . . . . . . . . . . . . . . 493 10,344
Treasury stock, at cost (15,856 shares). . . . . (378) (378)
--------- ---------
Total common stock equity. . . . . . . . . . . 92,044 100,645
Redeemable cumulative preferred stock. . . . . . 12,560 12,795
Long-term debt, less current maturities. . . . . 72,100 81,800
--------- ---------
Total capitalization . . . . . . . . . . . . . 176,704 195,240
--------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . 6,449 7,038
--------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . 235 1,640
Current maturities of long-term debt . . . . . . 9,700 6,700
Short-term debt. . . . . . . . . . . . . . . . . 15,500 7,900
Accounts payable, trade and accrued liabilities. 7,755 6,684
Accounts payable to associated companies . . . . 8,510 6,577
Dividends declared . . . . . . . . . . . . . . . 229 285
Customer deposits. . . . . . . . . . . . . . . . 696 361
Accrued purchased power option call. . . . . . . 8,276 -
Interest accrued . . . . . . . . . . . . . . . . 1,150 1,169
Power supply option obligation . . . . . . . . . 15,419 -
Other. . . . . . . . . . . . . . . . . . . . . . 874 8,475
--------- ---------
Total current liabilities. . . . . . . . . . . 68,344 39,791
--------- ---------
DEFERRED CREDITS
Accumulated deferred income taxes. . . . . . . . 25,644 25,201
Unamortized investment tax credits . . . . . . . 3,695 3,978
Pine Street Barge Canal site cleanup . . . . . . 11,554 8,815
Other. . . . . . . . . . . . . . . . . . . . . . 20,901 21,131
--------- ---------
Total deferred credits . . . . . . . . . . . . 61,794 59,125
--------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Liabilities of discontinued segment, net . . . . 3,317 -
--------- ---------
Total non-utility liabilities. . . . . . . . . 3,317 -
--------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . $316,608 $301,194
========= =========
The accompanying notes are an integral part of the consolidated financial
statements.
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION At December 31,
SHARES
ISSUED AND OUTSTANDING
----------------------
AUTHORIZED 2000 1999 2000 1999
------------ ---------- --------- ------ ------
(In thousands)
CAPITAL STOCK
Common Stock, $3.33 1/3 par value. 10,000,000 5,582,552 5,425,571 18,608 $18,085
====== =======
OUTSTANDING
AUTHORIZED ISSUED 2000 1999 2000 1999
- -------------------------------------- --------------- -------- ------- ------- ------
Shares (In thousands)
- --------------------------------------
REDEEMABLE CUMULATIVE PREFERRED STOCK,
$100 PAR VALUE
4.75%, Class B, redeemable at
$101 per share . . . . . . . . . 15,000 15,000 1,450 1,800 145 $ 180
7%, Class C, redeemable at
$101 per share . . . . . . . . . 15,000 15,000 3,300 3,750 330 375
9.375%, Class D, Series 1,
redeemable at $101 per share . . 40,000 40,000 3,200 4,800 320 480
8.625%, Class D, Series 3,
redeemable at $100916 per share. 70,000 70,000 0 14,000 0 1,400
7.32%, Class E, Series 1 . . . . . 200,000 120,000 120,000 120,000 12,000 12,000
------ -------
TOTAL PREFERRED STOCK. . . . . . . . . $ 12,795 $ 14,435
=============== ========
2000 1999
------- -------
(In thousands)
LONG-TERM DEBT
FIRST MORTGAGE BONDS
5.71% Series due 2000 . . . . . . . . . . . . . . . . . . . . . $ - $ 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. 6,800 8,500
7.05% Series due 2006 . . . . . . . . . . . . . . . . . . . . . 4,000 4,000
7.18% Series due 2006 . . . . . . . . . . . . . . . . . . . . . 10,000 10,000
6.7% Series due 2018. . . . . . . . . . . . . . . . . . . . . . 15,000 15,000
9.64% Series due 2020 . . . . . . . . . . . . . . . . . . . . . 9,000 9,000
8.65% Series due 2022 - Cash sinking fund, commences 2012 . . . 13,000 13,000
------- -------
Total Long-term Debt Outstanding. . . . . . . . . . . . . . . . . 81,800 88,500
Less Current Maturities (due within one year) . . . . . . . . . 9,700 6,700
------- -------
TOTAL LONG-TERM DEBT, NET . . . . . . . . . . . . . . . . . . . . $72,100 $81,800
======= =======
The accompanying notes are an integral part of these
consolidated financial statements.
Notes to Consolidated Financial Statements
A. SIGNIFICANT ACCOUNTING POLICIES
1. Organization and Basis of Presentation. Green Mountain Power
Corporation (the Company) is an investor-owned electric services company located
in Vermont that serves approximately one-quarter of Vermont's population. The
most significant portion of the Company's net income is generated from its
regulated electric utility operation, which purchases and generates electric
power and distributes it to approximately 86,000 retail and wholesale customers.
At December 31, 2000, the Company's primary subsidiary investment was Mountain
Energy, Inc. ("MEI"), which had invested in energy generation, energy efficiency
and wastewater treatment projects across the United States. In 1999, the
Company decided to sell or dispose of the assets of MEI, and report its results
as income (loss) from operations of a discontinued segment. MEI changed its
name to Northern Water Resources, Inc. ("NWR") in January 2001. In 1998, the
Company sold the assets of its wholly owned subsidiary, Green Mountain Propane
Gas Company ("GMPG"). The Company's remaining wholly-owned subsidiaries, which
are not regulated by the Vermont Public Service Board ("VPSB" or "the Board"),
are Green Mountain Resources, Inc. ("GMRI"), which sold its remaining interest
in Green Mountain Energy Resources in 1999 and is currently inactive, and GMP
Real Estate Corporation. The results of these subsidiaries, excluding MEI, and
the Company's unregulated rental water heater program are included in earnings
of affiliates and non-utility operations in the Other Income section of the
Consolidated Statements of Income. Summarized financial information for these
subsidiaries is as follows:
For the years ended December 31,
2000 1999 1998
------ ------ ------
(In thousands)
Revenue. . . . $1,034 $1,286 $2,876
Expense. . . . 495 184 2,857
------ ------ ------
Net Income . . $ 539 $1,102 $ 19
====== ====== ======
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 using the equity method of
accounting. The Company's share of the net earnings or losses of these
companies is also included in the Other Income section of the Consolidated
Statements of Income. See Note B and Note L for additional information.
2. Regulatory Accounting. 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") No. 71 ("SFAS 71"), Accounting for Certain Types of Regulation. Under
SFAS 71, the Company accounts for certain transactions in accordance with
permitted regulatory treatment. As such, regulators may permit incurred costs,
typically treated as expenses by unregulated entities, to be deferred and
expensed in future periods when recovered in future revenues. Conditions that
could give rise to the discontinuance of SFAS 71 include (1) increasing
competition that restricts the Company's ability to establish prices to recover
specific costs, and (2) a change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation. In the
event that the Company no longer meets the criteria under SFAS 71, the Company
would be required to write off related regulatory assets and liabilities. The
Company continues to believe, based on current regulatory circumstances, that
the use of regulatory accounting under SFAS 71 remains appropriate and that its
regulatory assets are probable of recovery. Regulatory entities that influence
the Company include the VPSB, the Vermont Department of Public Service ("DPS" or
the "Department"), and FERC, among other federal, state and local regulatory
agencies.
3. Impairment. The Company is required to evaluate long-lived assets,
including regulatory assets, for potential impairment. Assets that are no
longer probable of recovery through future revenues would be revalued based upon
future cash flows. Regulatory assets are charged to expense in the period in
which they are no longer probable of future recovery. As of December 31, 2000,
based upon the regulatory environment within which the Company currently
operates, the Company does not believe that an impairment loss need be recorded.
Competitive influences or regulatory developments may impact this status in the
future.
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"). As part of the rate agreement with the DPS,
the Company discontinued recording AFUDC on construction work in progress in
January 2001. The costs of renewals and improvements 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 over the estimated service life of the units.
5. Depreciation. The Company provides for depreciation using the
straight-line method based on the cost and estimated remaining service life of
the depreciable property outstanding at the beginning of the year and adjusted
for salvage value and cost of removal of the property.
The annual depreciation provision was approximately 3.5 percent of
total depreciable property at the beginning of 2000, 3.3 percent at the
beginning of 1999 and 3.4 percent at the beginning of 1998.
6. Cash and Cash equivalents. Cash and cash equivalents include short-term
investments with maturities less than ninety days.
7. Operating Revenues. Operating revenues consist principally of sales of
electric energy. The Company accrues 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.
8. 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
Power Corporation's generation 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 also defers and amortizes costs associated with its
investment in the demand side management program.
Other deferred charges totaled $15.5 million and $19.5 million at December
31, 2000 and 1999 respectively, consisting of regulatory deferrals of storm
damages, rights-of-way maintenance, other employee benefits, preliminary survey
and investigation charges, transmission interconnection charges and various
other projects and deferrals.
9. Earnings Per Share. Earnings per share are based on the weighted
average number of common and common stock equivalent shares outstanding during
each year. The Company established an stock incentive plan for all employees
during the year ended December 31, 2000, and granted 334,900 options exercisable
over vesting schedules of between one and four years. Since the Company
experienced a net loss in the year 2000, basic and diluted earnings per share
are the same.
10. Major Customers. The Company had one major retail customer, IBM,
metered at two locations, that accounted for 11.2 percent, 11.8 percent, and
14.7 percent of total operating revenues, and 16.5 percent, 16.4 percent and
17.1 percent of the Company's retail operating revenues in 2000, 1999 and 1998,
respectively. IBM's percent of total revenues in 2000 decreased due to an
increase in total operating revenues as a result of sales for resale pursuant to
the Morgan Stanley Capital Group, Inc. ("MS") agreement. See Note K for further
information regarding the MS agreement.
11. Fair Value of Financial Instruments. The present value of the first
mortgage bonds and preferred stock outstanding, if refinanced using prevailing
market rates of interest, would decrease from the balances outstanding at
December 31, 2000 by approximately 4.6 percent. In the event of such a
refinancing, there would be no gain or loss, because under established
regulatory precedent, any such difference would be reflected in rates and have
no effect upon income.
12. Deferred Credits. At December 31, 2000, the Company had other deferred
credits and long-term liabilities of $32.4 million, consisting of reserves for
damage claims and environmental liabilities, and accruals for employee benefits
compared with a balance of $30.4 million at December 31, 1999.
13. 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.
14. Reclassification. Certain items on the prior year's consolidated
financial statements have been reclassified to be consistent with the current
year presentation.
15. New Accounting Standards. In June 1998, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities, amended
by Statement No. 137, Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133 and
Statement 138, Accounting for Certain Derivatives and Certain Hedging Activities
(collectively "SFAS 133").
SFAS 133 establishes accounting and reporting standards requiring that
derivative instruments (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or a
liability and measured at their fair value. SFAS 133 requires that changes in
the derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting. SFAS 133 is effective for the Company beginning the first quarter
of 2001 and must be applied to derivative instruments and embedded derivatives
that were issued, acquired, or substantively modified on or after January 1,
1998 or January 1, 1999 (as elected by the Company).
We have not yet quantified all effects of adopting SFAS 133 on our
financial statements. However, a discussion of the Company's material
derivative obligations follows and includes estimates of the fair values of each
derivative. The Company has sought an accounting order from the VPSB to
determine regulatory treatment for recording derivatives at fair market value.
We believe it is probable that the VPSB will order that the Company defer
recognition of any earnings or other comprehensive income effect relating to
future periods caused by application of SFAS 133. We expect the VPSB to issue
the accounting order prior to reporting our first quarter results, and
consequently do not anticipate SFAS 133 to cause earnings volatility.
If the VPSB issues such an order, and if a derivative instrument is
terminated early because it is probable that a transaction or forecasted
transaction will not occur, any gain or loss will be recognized immediately. If
such derivative is terminated for other economic reasons, any gain or loss as of
the termination date is deferred and recorded when the associated transaction or
forecasted transaction affects earnings. For derivatives held to maturity, the
income statement impact of derivatives would be recognized in the period that
the derivative is sold or matures.
If the VPSB does not issue an order or issues an order that does not
require deferral of the earnings impacts resulting from application of SFAS 133,
management estimates that adoption would result in earnings/loss recognition
equivalent to the fair values of the respective assets/liabilities disclosed
below, as adjusted by future changes in estimates.
The Company has a contract with MS used to hedge against increases in
fossil fuel prices. MS purchases the majority of Company power supply resources
at index (fossil fuel resources) or specified (i.e. contracted resources) prices
and then sells to us at a fixed rate to serve pre-established load requirements.
This contract allows management to fix the cost of much of its power supply
requirements, subject to power resource availability and other risks. The MS
contract is a derivative under SFAS 133 and is effective through December 31,
2003. Management's current estimate of the fair value of the future net benefit
(cost) of this arrangement is between $7.2 million and ($14.0) million.
We also sometimes use future contracts to hedge forecasted wholesale
sales of electric power, including material sales commitments as discussed under
Note K. We currently have an arrangement with Hydro-Quebec that grants them an
option to call power at prices below current and estimated future market rates.
This arrangement is a derivative and is effective through 2016. Management's
current estimate of the fair value of the future net cost for this arrangement
is between $24.5 and $29.5 million.
B. INVESTMENTS IN ASSOCIATED COMPANIES
The Company accounts for investments in the following associated
companies by the equity method:
PERCENT INVESTMENT IN EQUITY
OWNERSHIP AT AT DECEMBER 31,
DECEMBER 31,2000 2000 1999
----------------------------------------- -------- -------
(IN THOUSANDS)
VELCO-common. . . . . . . . . . . . . . . 29.50% $ 1,916 $1,839
VELCO-preferred . . . . . . . . . . . . . 30.00% 540 690
------- ------
Total VELCO . . . . . . . . . . . . . . . 2,456 2,529
Vermont Yankee- Common. . . . . . . . . . 17.88% 9,713 9,641
New England Hydro Transmission-Common . . 3.18% 827 911
New England Hydro Transmission Electric-
Common. . . . . . . . . . . . . . . . 3.18% 1,377 1,464
------- ------
Total investment in associated companies. $14,373 $14,545
======== =======
Undistributed earnings in associated companies totaled $908,000 at December
31, 2000.
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, VELCO bills all costs, including interest on debt and a fixed
return on equity, to the State and others using VELCO's transmission system.
The Company's purchases of transmission services from VELCO were $9.7 million,
$7.9 million, and $7.1 million for the years 2000, 1999 and 1998, 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:
AT AND FOR THE YEARS ENDED
DECEMBER 31,
2000 1999 1998
------- ------- -------
(In thousands)
Company's equity in net income. $ 395 $ 357 $ 338
======= ======= =======
Total assets. . . . . . . . . . $82,123 $67,294 $67,658
Less:
Liabilities and long-term debt. 73,874 58,731 58,690
------- ------- -------
Net assets. . . . . . . . . . . $ 8,249 $ 8,563 $ 8,968
======= ======= =======
Company's equity in net assets. $ 2,456 $ 2,529 $ 2,657
======= ======= =======
Vermont Yankee. The Company is responsible for approximately 17.9 percent of
Vermont Yankee's expenses of operations, including costs of equity capital and
estimated costs of decommissioning, and is entitled to a similar share of the
power output of the nuclear plant, which has a net capacity of 531 megawatts.
Vermont Yankee's current estimate of decommissioning costs is approximately $430
million, using the 1993 FERC approved escalation rate of 5.4%, of which $247
million has been funded. At December 31, 2000, the Company's portion of the net
unfunded liability was $33 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 2000, the Company incurred
$27.8 million in Vermont Yankee annual capacity charges, which included $2.4
million for interest charges. The Company's share of Vermont Yankee's long-term
debt at December 31, 2000 was $17.1 million.
On October 15, 1999, the owners of Vermont Yankee Nuclear Power
Corporation accepted a bid from AmerGen Energy Company for the Vermont Yankee
generating plant, intending to complete the sale before December 2000. AmerGen
and the DPS then negotiated a revised offer in November 2000, which was
subsequently dismissed as insufficient by the VPSB in February 2001. Entergy
Nuclear Inc. has also made an offer, and two other companies have indicated they
would participate in an auction, if held. The plant is likely to be sold at
auction, the terms and conditions of which are unknown at this time.
The Price-Anderson Act currently limits public liability from a
single incident at a nuclear power plant to $9.5 billion. Any damages beyond
$9.5 billion are indemnified under the Price-Anderson Act, but subject to
congressional approval. The first $200 million of liability coverage is the
maximum provided by private insurance. The Secondary Financial Protection
Program is a retrospective insurance plan providing additional coverage up to
$9.3 billion per incident by assessing each of the 106 reactor units that are
currently subject to the Program in the United States a total of $88.1 million,
limited to a maximum assessment of $10 million per incident per nuclear unit in
any one year. The maximum assessment is adjusted at least every five years to
reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities
for bodily injury claims. Vermont Yankee retains a potential obligation for
retrospective adjustments due to past operations of several smaller facilities
that did not join the above insurance program. These exposures will cease to
exist no later than December 31, 2007. Vermont Yankee's maximum retrospective
obligation remains at $3.1 million. 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 $8.1 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:
At and for the years ended
December 31,
2000 1999 1998
-------- -------- --------
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . $178,294 $208,812 $195,249
Net income applicable to common stock. 6,583 6,471 7,125
Company's equity in net income . . . . $ 1,177 $ 1,165 $ 1,267
======== ======== ========
Total assets . . . . . . . . . . . . . . $706,984 $685,292 $635,874
Less:
Liabilities and long-term debt . . . . 652,663 631,365 581,231
-------- -------- --------
Net Assets . . . . . . . . . . . . . . . $ 54,321 $ 53,927 $ 54,643
======== ======== ========
Company's equity in net assets . . . . . $ 9,713 $ 9,641 $ 9,759
======== ======== ========
C. COMMON STOCK EQUITY
The Company maintains a Dividend Reinvestment and Stock Purchase Plan
("DRIP") under which 456,554 shares were reserved and unissued at December 31,
2000. The Company also funds an Employee Savings and Investment Plan ("ESIP").
At December 31, 2000, there were 174,263 shares reserved and unissued under the
ESIP.
During 2000, the Company's Board of Directors, with subsequent approval of
the Company's common shareholders, established a stock incentive plan. Under
this plan, options for up to 500,000 shares may be granted to any employee,
officer, consultant, contractor or Director providing services to the Company.
Outstanding options become exercisable at between one and four years after the
grant date and remain exercisable until 10 years from the grant date.
As permitted by Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation,"("SFAS 123") the Company has elected
to follow Accounting Principles Board Opinion No. 25 ("APB 25") "Accounting for
Stock Issued to Employees", and related interpretations in accounting for its
employee stock options. Under APB 25, because the exercise price equals the
market price of the underlying stock on the date of grant, no compensation
expense is recorded.
Disclosure of proforma information regarding net income and earnings
per share is required by SFAS 123. The information presented below has been
determined as if the Company accounted for its employee stock options under the
fair value method of that statement. The fair values of the options granted in
2000 are $2.03 per share. They were estimated at the grant date using the
Black-Scholes option-pricing model with the following weighted average
assumptions:
Assumptions
2000
------
Risk-free interest rate . 6.05%
Expected life in years. . 7
Expected stock volatility 30.58%
Dividend yield. . . . . . 4.50%
Proforma net earnings loss per share and a summary of options outstanding are as
follows:
Proforma net income (loss)
2000
-------
Net income (loss)per share
As reported. . . . . . . $(1.25)
Pro-forma. . . . . . . . $(1.25)
Diluted earnings per share
As reported. . . . . . . $(1.25)
Pro-forma. . . . . . . . $(1.25)
Weighted
Average
Options Price
-------- ------
Outstanding at 12/31/99 - $ -
Granted . . . . . . . . 334,900 7.90
Exercised . . . . . . . - -
Forfeited . . . . . . . 3,400 7.90
Outstanding at 12/31/00 331,500 $ 7.90
======== ======
No options granted in 2000 became exercisable in 2000. The pro-forma amounts
may not be representative of future disclosures since the estimated fair value
of stock options is amortized to expense over the vesting period and additional
options may be granted in future years. For 2000, the number of total shares
after giving effect to anti-dilutive common stock equivalents does not change.
The following summarizes the plan's stock options outstanding:
Weighted
average Outstanding Remaining
Plan exercise options Contractual
year price at 12/31/00 Life
--------- ----------- ----------- -----------
2000 $ 7.90 331,500 9.6 years
During 2000, the Compensation Program for Officers and Certain Key Management
personnel, that authorized payment of cash, restricted and unrestricted stock
grants based on corporate performance was replaced with the stock incentive plan
discussed above. Approximately 2000 restricted shares, issued during 1996 and
1997, remained unvested under this program.
Changes in common stock equity for the years ended December 31, 1998, 1999 and 2000 are as follows:
COMMON STOCK PAID-IN RETAINED TREASURY STOCK STOCK
----------------
SHARES AMOUNT CAPITAL EARNINGS SHARES AMOUNT EQUITY
---------------------- --------- ---------- ---------------- ------ -------- ---------
(Dollars in thousands)
BALANCE, DECEMBER 31, 1997 5,195,432 $ 17,318 $ 70,720 $ 26,717 15,856 $ (378) $114,377
---------------------- --------- ---------- ---------------- ------ -------- ---------
Common Stock Issuance:
DRIP . . . . . . . . . . 88,004 293 928 - - - 1,221
ESIP . . . . . . . . . . 36,391 121 427 - - - 548
Compensation Program:. . -
Restricted Shares . . (6,531) (21) (161) - - - (182)
Net Loss . . . . . . . . . - - - (2,877) - - (2,877)
Cash Dividends . . . . . . -
Common Stock . . . . . . - - - (5,036) - - (5,036)
Preferred Stock:
$4.75 per share. . . . . - - - (12) - - (12)
$7.00 per share. . . . . - - - (32) - - (32)
$9.375 per share . . . . - - - (72) - - (72)
$8.625 per share . . . . - - - (302) - - (302)
$7.32 per share. . . . . - - - (878) - - (878)
---------------------- --------- ---------- ---------------- ------ -------- ---------
BALANCE, DECEMBER 31, 1998 5,313,296 $ 17,711 $ 71,914 $ 17,508 15,856 $ (378) $106,755
---------------------- --------- ---------- ---------------- ------ -------- ---------
Common Stock Issuance:
DRIP . . . . . . . . . . 67,525 225 418 - - - 643
ESIP . . . . . . . . . . 48,277 161 345 - - - 506
Compensation Program:
Restricted Shares . . (3,527) (12) (83) - - - (95)
Net Loss . . . . . . . . . - - - (3,063) - - (3,063)
Cash Dividends
Common Stock . . . . . . - - - (2,946) - - (2,946)
Preferred Stock:
$4.75 per share. . . . . - - - (10) - - (10)
$7.00 per share. . . . . - - - (29) - - (29)
$9.375 per share . . . . - - - (57) - - (57)
$8.625 per share . . . . - - - (181) - - (181)
$7.32 per share. . . . . - - - (878) - - (878)
---------------------- --------- ---------- ---------------- ------ -------- ---------
BALANCE, DECEMBER 31, 1999 5,425,571 $ 18,085 $ 72,594 $ 10,344 15,856 $ (378) $100,645
---------------------- --------- ---------- ---------------- ------ -------- ---------
Common Stock Issuance:
DRIP . . . . . . . . . . 73,859 246 363 - - - 609
ESIP . . . . . . . . . . 83,931 280 401 - - - 681
Compensation Program:
Restricted Shares . . (809) (3) (37) - - - (40)
Net Loss . . . . . . . . . - - - (5,840) - - (5,840)
Cash Dividends
Common Stock . . . . . . - - - (2,997) - - (2,997)
Preferred Stock:
$4.75 per share. . . . . - - - (8) - - (8)
$7.00 per share. . . . . - - - (26) - - (26)
$9.375 per share . . . . - - - (42) - - (42)
$8.625 per share . . . . - - - (60) - - (60)
$7.32 per share. . . . . - - - (878) - - (878)
---------------------- --------- ---------- ---------------- ------ -------- ---------
BALANCE, DECEMBER 31, 2000 5,582,552 $ 18,608 $ 73,321 $ 493 15,856 $ (378) $ 92,044
====================== ========= ========== ================ ====== ======== =========
Dividend Restrictions. Certain restrictions on the payment of cash dividends on
common stock are contained in the Company's indentures relating to long-term
debt and in the Restated Articles of Association. Under the most restrictive of
such provisions, approximately $0.5 million of retained earnings were free of
restrictions at December 31, 2000.
The properties of the Company include several hydroelectric projects
licensed under the Federal Power Act, with license expiration dates ranging from
2001 to 2025. At December 31, 2000, $161,000 of retained deficit 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 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 the
year 2001 for certain classes of preferred stock are as follows:
Purchase and Sinking Fund
Shares to
Class Due dates Retire
4.750% Class B . . . . . December 1 300
7.000% Class C . . . . . December 1 450
9.375% Class D, Series 1 December 1 1,600
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 $235,000 each for 2001 and 2002,
$75,000 each for 2003 and 2004, $70,000 for 2005 and $105,000 thereafter.
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.
E. LONG-TERM DEBT
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 weighted average rate on long term borrowings outstanding was 7.6
percent and 7.5 percent at December 31, 2000 and 1999, respectively. 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
Fund Maturities Total
--------------- ----------- ------
(In thousands)
2001 $ 1,700 $ 8,000 $9,700
2002 1,700 8,000 9,700
2003 1,700 8,000 9,700
2004 1,700 1,700
2005 1,700 1,700
F. SHORT-TERM DEBT
The Company has a revolving credit agreement with Fleet Financial
Services and Citizens Bank of Massachusetts (the "Fleet agreement") in the
amount of $15.0 million, with borrowings outstanding of $500,000 and $7.9
million at December 31, 2000, and 1999 respectively. The 364-day Fleet
agreement expires June 2001. The weighted average interest rate on short-term
borrowings outstanding at December 31, 2000 and December 31, 1999 was 9.5
percent and 9.0 percent, respectively. There was no non-utility short-term debt
outstanding at December 31, 2000.
The Fleet agreement requires the Company to certify on a quarterly
basis that it has not suffered a "material adverse change". Similarly, as a
condition to further borrowings, the Company must certify that no event has
occurred or failed to occur that has had or would reasonably be expected to have
a materially adverse effect on the Company since the date of the last
borrowing under this agreement. The Fleet agreement allows the Company to
continue to borrow until such time that:
* a "material adverse effect" has occurred; or
* the Company no longer complies with all other provisions of the agreement,
in which case further borrowing will not be permitted; or
* there has been a "material adverse change", in which case the banks may
declare the Company in default.
Terms also call in part for a second priority mortgage lien and security
interest in the collateral pledged under the first mortgage bond indenture.
On September 20, 2000, we established a $15.0 million revolving credit
agreement ("KeyBank agreement") with KeyBank National Association ("KeyBank").
The KeyBank agreement is for a period of 364 days and will expire on September
19, 2001. Pursuant to a one year power supply option agreement between the
Company and Energy East Corporation ("EE"), EE made a payment of $15.0 million
to the Company. In exchange, the Company gave EE an option to purchase energy
from certain wholly owned production facilities, for a period not to exceed 15
years, if the funds are not returned to EE upon request after September 2001.
The Company was required to invest the funds provided by EE in a certificate of
deposit at KeyBank pledged by the Company to secure the repayment of
indebtedness issued under the Keybank agreement. At December 31, 2000, there
was $15.0 million outstanding on the KeyBank Agreement.
The Company anticipates that it will secure financing that replaces some or
all of its expiring facilities during 2001. The VPSB Order of January 23, 2001
(the "Settlement Order") will likely permit restoration of the Company's
investment grade debt ratings, allowing arrangement of such financing as the
Company needs during 2001. On March 5, 2001, Moody's Investors Service upgraded
the Company's first mortgage bond rating to Baa2 from Ba1, and upgraded the
Company's preferred stock rating to baa3 from ba3. The rating action reflected
Moody's earnings and cash flow expectations for the Company following the
Settlement Order.
G. INCOME TAXES
Utility. The Company accounts for income taxes using the liability method.
This method accounts for deferred income taxes by applying statutory rates to
the differences between the book and tax bases of assets and liabilities.
The regulatory tax assets and liabilities represent taxes that will be
collected from or returned to customers through rates in future periods. As of
December 31, 2000 and 1999, the net regulatory assets were $1,908,000 and
$1,805,000, respectively, and included in other deferred charges on the
Company's consolidated balance sheets.
The temporary differences which gave rise to the net deferred tax
liability at December 31, 2000 and December 31, 1999, were as follows:
AT DECEMBER 31,
2000 1999
------- -------
(In thousands)
DEFERRED TAX ASSETS
Contributions in aid of construction. $10,018 $ 9,056
Deferred compensation and
postretirement benefits. . . . . 4,122 3,372
Self insurance and other reserves . . - 3,664
Other . . . . . . . . . . . . . . . . 1,958 1,183
------- -------
$16,098 $17,275
------- -------
DEFERRED TAX LIABILITIES
Property related. . . . . . . . . . . $38,648 $37,921
Demand side management. . . . . . . . 1,810 2,328
Deferred purchased power costs. . . . 84 2,202
Pine Street reserve . . . . . . . . . 571 25
Other . . . . . . . . . . . . . . . . 629 -
------- -------
$41,742 $42,476
------- -------
Net accumulated deferred income
tax liability . . . . . . . . . . $25,644 $25,201
======= =======
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:
YEARS ENDED DECEMBER 31,
2000 1999 1998
----- ------ ------
(In thousands)
Net change in deferred income tax . . $ 443 $1,812 $(112)
liability
Change in income tax related
regulatory assets and liabilities . 184 176 510
Change in alternative minimum
tax credit. . . . . . . . . . . . . - - (70)
----- ------ ------
Deferred income tax expense (benefit) $ 627 $1,988 $ 328
===== ====== ======
The components of the provision for income taxes are as follows:
YEARS ENDED DECEMBER 31,
2000 1999 1998
-------- ------- --------
(In thousands)
Current federal income taxes . $ (786) $ (339) $(1,047)
Current state income taxes . . (249) (125) (366)
-------- ------- --------
Total current income taxes . . (1,035) (464) (1,413)
Deferred federal income taxes. 461 1,479 219
Deferred state income taxes. . 166 509 109
-------- ------- --------
Total deferred income taxes. . 627 1,988 328
Investment tax credits-net . . (283) (282) (282)
-------- ------- --------
Income tax provision (benefit) $ (691) $1,242 $(1,367)
======== ======= ========
Total income taxes differ from the amounts computed by applying the federal
statutory tax rate to income before taxes. The reasons for the differences are
as follows:
YEARS ENDED DECEMBER 31,
2000 1999 1998
-------- -------- --------
(In thousands)
Income (loss) before income taxes and
preferred dividends . . . . . . . . . . . . $(6,531) $(1,821) $(4,244)
Federal statutory rate. . . . . . . . . . . . 34.0% 34.0% 34.0%
Computed "expected" federal income
taxes . . . . . . . . . . . . . . . . . . . (2,221) (619) (1,443)
Increase (decrease) in taxes resulting from:
Tax versus book depreciation. . . . . . . . . 83 92 153
Dividends received and paid credit. . . . . . (435) (485) (480)
AFUDC-equity funds. . . . . . . . . . . . . . (33) (5) (36)
Amortization of ITC . . . . . . . . . . . . . (282) (282) (282)
State tax (benefit) . . . . . . . . . . . . . (83) 383 (256)
Excess deferred taxes . . . . . . . . . . . . (60) (60) (60)
Tax attributable to subsidiaries. . . . . . . 2,213 2,271 845
Other . . . . . . . . . . . . . . . . . . . . 127 (53) 192
-------- -------- --------
Total federal and state income tax (benefit). $ (691) $ 1,242 $(1,367)
======== ======== ========
Effective combined federal and state
income tax rate . . . . . . . . . . . . . . 10.6% (68.2%) 32.2%
Non-Utility. The Company's non-utility subsidiaries, excluding MEI, had
accumulated deferred income taxes of approximately $2,000 on their balance
sheets at December 31, 2000, attributable to depreciation timing differences.
The components of the provision for the income tax expense (benefit)
for the non-utility operations are:
YEARS ENDED DECEMBER 31,
2000 1999 1998
------------------------- ----- ------
(In thousands)
State income taxes . . . . . $ 7 $ 99 $(281)
Federal income taxes . . . . 21 310 (202)
------------------------- ----- ------
Income tax expense (benefit) $ 28 $ 409 $(483)
========================= ===== ======
The effective combined federal and state income tax rates for the
continuing non-utility operations were 34.0 percent, 34.0 percent, and 32.6
percent, for the years ended December 31, 2000, 1999 and 1998, respectively.
See Note L for income tax information on the discontinued operations of MEI.
H. PENSION AND RETIREMENT PLANS.
The Company has a defined benefit pension plan covering substantially all
of its employees. The retirement benefits are based on the employees' level of
compensation and length of service. The Company's policy is to fund all accrued
pension costs. The Company records annual expense and accounts for its pension
plan in accordance with Statement of Financial Accounting Standards No. 87,
Employers' Accounting for Pensions. 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. The pension plan assets consist primarily of cash
equivalent funds, fixed income securities and equity securities.
Accrued postretirement health care expenses are recovered in rates to
the extent those expenses are funded. In order to maximize the tax-deductible
contributions that are allowed under IRS regulations, the Company amended its
pension plan to establish a 401-h sub-account and separate VEBA trusts for its
union and non-union employees. The VEBA plan assets consist primarily of cash
equivalent funds, fixed income securities and equity securities. The following
provides a reconciliation of benefit obligations, plan assets, and funded status
of the plans as of December 31, 2000 and 1999.
At and for the years ended December 31,
Pension Benefits Other Post-retirement Benefits
---------------- ------------------------------
2000 1999 2000 1999
-------- --------- -------- --------
(In thousands)
Change in projected benefit obligation:
Projected benefit obligation as of prior year end. $22,444 $ 30,860 $11,955 $12,552
Service cost . . . . . . . . . . . . . . . . . . . 655 620 216 240
Interest cost. . . . . . . . . . . . . . . . . . . 1,658 1,780 1,049 855
Special termination benefit. . . . . . . . . . . . - 5,385 - 1,446
Change in actuarial assumptions. . . . . . . . . . - - 2,328 (1,372)
Settlements. . . . . . . . . . . . . . . . . . . . - (9,527) - -
Actuarial (gain) loss. . . . . . . . . . . . . . . 513 (2,080) 73 (70)
Benefits paid. . . . . . . . . . . . . . . . . . . (1,938) (4,312) (674) (864)
Curtailment. . . . . . . . . . . . . . . . . . . . - (282) - (832)
-------- --------- -------- --------
Projected benefit obligation as of year end. . . . $23,332 $ 22,444 $14,947 $11,955
======== ========= ======== ========
Change in plan assets:
Fair value of plan assets as of prior year end . . $31,477 $ 38,030 $11,062 $ 9,735
Contribution . . . . . . . . . . . . . . . . . . . - - - -
Actual return on plan assets . . . . . . . . . . . (1,779) 7,286 (118) 1,327
Benefits paid. . . . . . . . . . . . . . . . . . . (1,938) (13,839) - -
-------- --------- -------- --------
Fair value of plan assets as of year end . . . . . $27,760 $ 31,477 $10,944 $11,062
======== ========= ======== ========
Funded status as of year end . . . . . . . . . . . $ 4,428 $ 9,032 $(4,003) $ (893)
Unrecognized transition obligation (asset) . . . . (406) (571) 3,936 4,264
Unrecognized prior service cost. . . . . . . . . . 766 887 (577) (635)
Unrecognized net actuarial gain. . . . . . . . . . (6,848) (12,193) (130) (3,589)
-------- --------- -------- --------
Accrued benefits at year end . . . . . . . . . . . $(2,060) $ (2,845) $ (774) $ (853)
======== ========= ======== ========
The Company also has a supplemental pension plan for certain employees.
Pension costs for the years ended December 31, 2000, 1999, and 1998 were
$346,000, $556,000, and $397,000, respectively, under this plan. This plan is
funded in part through insurance contracts.
Net periodic pension expense and other postretirement benefit costs
include the following components:
For the years ended December 31,
Pension Benefits Other Postretirement Benefits
2000 1999 1998 2000 1999 1998
-------- -------- -------- ------- ------ ------
(In thousands)
Service cost . . . . . . . . . . . . . . . . . $ 655 $ 620 $ 787 $ 216 $ 240 $ 282
Interest cost. . . . . . . . . . . . . . . . . 1,658 1,780 2,043 1,049 855 799
Expected return on plan assets . . . . . . . . (2,580) (2,721) (3,081) (940) (834) (671)
Amortization of transition asset . . . . . . . (164) (196) (228) - - -
Amortization of net gain from earlier periods. - - - - - -
Amortization of prior service cost . . . . . . 121 128 134 (58) (60) (61)
Amortization of the transition obligation. . . - - - 328 340 351
Recognized net actuarial gain. . . . . . . . . (474) (196) (195) - (19) -
Special termination benefit. . . . . . . . . . - 3,122 2,026 - 888 27
Regulatory deferral. . . . . . . . . . . . . . - (3,122) (2,026) - (888) (27)
-------- -------- -------- ------- ------ ------
Net periodic benefit cost. . . . . $ (784) $ (585) $ (540) $ 595 $ 522 $ 700
======== ======== ======== ======= ====== ======
Assumptions used to determine postretirement benefit costs and the related
benefit obligation were:
For the years ended December 31,
Pension benefits Other Post-retirement Benefits
------------------------------
2000 1999 2000 1999
----- ----- ----- -----
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . . 7.50% 6.75% 7.50% 7.50%
Expected return on plan assets . . . . . . . 9.00% 9.00% 8.50% 8.50%
Rate of compensation increase. . . . . . . . 4.50% 4.00% - -
Medical inflation. . . . . . . . . . . . . . - - 6.00% 5.30%
For measurement purposes, a 6 percent annual rate of increase in the per
capita cost of covered medical benefits was assumed for 2000 and later years.
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 for all future years would increase the accumulated
postretirement benefit obligation as of December 31, 2000 by $1.9 million and
the total of the service and interest cost components of net periodic
postretirement cost for the year ended December 31, 2000 by $200,000.
Decreasing the trend rate by one percentage point for all future years would
decrease the accumulated postretirement benefit obligation at December 31, 2000
by $1.5 million, and the total of the service and interest cost components of
net periodic postretirement cost for 2000 by $157,000.
In 1999, the Company deferred special termination pension benefit
costs of $3,122,000 due to an early retirement program and other employee
separation activities. Curtailment and settlement gains of $2.3 million are
included in the special termination pension benefit cost. The special
termination benefit recorded in 1998 resulted from the early retirement option
offered to employees in 1998. Also in 1999, the Company deferred special
termination postretirement benefit costs of $888,000 due to an early retirement
program. Management believes that the amounts deferred are probable of
recovery.
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. Certain states, including all the New England states
except Vermont, have enacted legislation to allow retail customers to choose
their electric suppliers, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems. Recent power
supply management difficulties in some regulatory jurisdictions, such as
California, have dampened any immediate push towards de-regulation in Vermont.
There can be no assurance that any potential future restructuring plan ordered
by the VPSB, the courts, or through legislation will include a mechanism that
would allow for full recovery of our stranded costs and include a fair return on
those costs as they are being recovered.
2. ENVIRONMENTAL MATTERS. The electric industry typically uses or generates
a range of potentially hazardous products in its operations. The Company must
meet various land, water, air and aesthetic requirements as administered by
local, state and federal regulatory agencies. We believe that we are in
substantial compliance with those requirements, and that there are no
outstanding material complaints about our compliance with present environmental
protection regulations, except for developments related to the Pine Street Barge
Canal site. 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.
Pine Street Barge Canal Site. The Federal Comprehensive Environmental
Response, Compensation, and Liability Act ("CERCLA"), commonly known as the
"Superfund" law, generally imposes strict, joint and several liability,
regardless of fault, for remediation of property contaminated with hazardous
substances. The Company has been notified by the Environmental Protection
Agency ("EPA") that it is one of several potentially responsible parties
("PRPs") for cleanup of the Pine Street Barge Canal site in Burlington, Vermont,
where coal tar and other industrial materials were deposited.
In September 1999, we negotiated a final settlement with the United
States, the State of Vermont, and other parties over terms of a Consent Decree
that covers claims addressed in the earlier negotiations and implementation of
the selected remedy. In November 1999, the Consent Decree was filed in the
federal district court. The Consent Decree addresses claims by the EPA for past
Pine Street Barge Canal site costs, natural resource damage claims and claims
for past and future oversight costs. The Consent Decree also provides for the
design and implementation of response actions at the site.
As of December 31, 2000, the Company's total expenditures related to
the Pine Street Barge Canal site since 1982 were approximately $23.5 million.
This includes those amounts not recovered in rates, amounts recovered in rates,
and amounts for which rate recovery has been sought but which are presently
awaiting further VPSB action. The bulk of these expenditures consisted of
transaction costs. Transaction costs include legal and consulting costs
associated with the Company's opposition to the EPA's earlier, and more costly,
proposals for the site, as well as litigation and related costs necessary to
obtain settlements with insurers and other PRP's to provide amounts required to
fund the clean up (remediation costs) and to address liability claims at the
site. A smaller amount of past expenditures was for site-related response
costs, including costs incurred pursuant to the EPA and State orders that
resulted in funding response activities at the site, and to reimbursing the EPA
and the State for oversight and related response costs. The EPA and the State
have asserted and affirmed that all costs related to these orders are
appropriate costs of response under CERCLA for which the Company and other PRPs
were legally responsible.
We estimate that we have recovered or secured, or will recover,
through settlements of litigation claims against insurers and other parties,
amounts that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We currently estimate
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $12.4 million over the next 33
years. The estimated liability is not discounted, and it is possible that our
estimate of future costs could change by a material amount. We also have
recorded an offsetting regulatory asset and we believe that it is probable that
we will receive future revenues to recover these costs. Although it did not
eliminate the rate base deferral of these expenditures, or make any specific
order in this regard, the VPSB indicated that it was inclined to agree with
other parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance carriers
and other PRPs, should be shared between customers and shareholders of the
Company. In response to our Motion for Reconsideration, the VPSB on June 8,
1998 stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
The VPSB Order released January 23, 2001 regarding the Company's 1998 retail
rate request did not change the status of Pine Street cost recovery.
Clean Air Act. The Company purchases most of its power supply from
other utilities and does not anticipate that it will incur any material direct
costs as a result of the Federal Clean Air Act or proposals to make more
stringent regulations under that Act.
3. OPERATING LEASES. The Company terminated an operating lease for its
corporate headquarters building and two of its service center buildings in the
first quarter of 1999. During 1998, the Company recorded a loss of
approximately $1.9 million before applicable income taxes to reflect the
probable loss resulting from this transaction. The Company sold its corporate
headquarters building in 1999, but retained ownership of the two service
centers.
4. JOINTLY-OWNED FACILITIES. The Company has joint-ownership interests in
electric generating and transmission facilities at December 31, 2000, as
follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- --------- --------------- -------------
(In %) (In MWh) (In thousands)
Highgate . . . . . . . . 33.8 67.6 $ 10,299 $ 4,118
McNeil . . . . . . . . . 11.0 5.9 8,866 4,484
Stony Brook (No. 1). . . 8.8 31 10,339 7,636
Wyman (No. 4). . . . . . 1.1 6.8 1,980 1,192
Metallic Neutral Return. 59.4 - $ 1,563 $ 619
Metallic Neutral Return is a 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 its own financing.
5. RATE MATTERS.
RETAIL RATE CASES- On March 2, 1998, the VPSB released its Order dated February
27, 1998 in the then pending rate case. The VPSB authorized us to increase our
rates by 3.61 percent, which gave us increased annual revenues of $5.6 million.
The VPSB Order denied us the right to charge customers $5.48 million of the
annual costs for power purchased under our contract with Hydro-Quebec. The VPSB
denied recovery of these costs for the following reasons:
* the VPSB claimed that we had acted imprudently by committing to the power
contract with Hydro-Quebec in August 1991 (the imprudence disallowance); and
* to the extent that the costs of power to be purchased from Hydro-Quebec
were then higher than current estimates of market prices for power during the
contract term, after accounting for the imprudence disallowance, the contract
power was not "used and useful".
On May 8, 1998, we filed a request with the VPSB to increase our
retail rates by 12.93 percent due to higher power costs, the cost of the January
1998 ice storm, and investments in new plant and equipment.
On November 18, 1998, by Memorandum of Understanding ("MOU"), the
Company, the Department and IBM agreed to stay rate proceedings in the 1998 rate
case until or after September 1, 1999, or such earlier date as the parties may
later agree to or the VPSB may order. The agreement to suspend our 1998 rate
case delayed the date of a final decision on the 1998 rate case to December 15,
1999, and we recognized an additional loss of $5.25 million in the last quarter
of 1998 representing the effect of the continued disallowance of Hydro-Quebec
costs through December 15, 1999. The MOU provided for a 5.5% temporary retail
rate increase, to produce $8.9 million in annualized additional revenue,
effective with service rendered December 15, 1998. An additional surcharge was
permitted, without further VPSB order, in order to produce additional revenues
necessary to provide the Company with the capacity to finance 1999 Pine Street
Barge Canal site expenditures. The MOU was approved by the VPSB on December 11,
1998. The MOU did not provide for any specific disallowance of power costs under
our purchase power contract with Hydro-Quebec. Issues respecting recovery of
such power costs were preserved for future proceedings.
The stay and suspension of this pending rate case and the temporary rate
levels agreed to in the MOU were designed to allow us to continue to provide
adequate and efficient service to our customers while we sought mitigation of
power supply costs.
On September 7 and December 17, 1999, the VPSB issued Orders approving two
amendments to the MOU that the Company had entered into with the Department and
IBM. The two amendments continued the stay of proceedings until September 1,
2000, with a final decision expected by December 31, 2000. The amendments
maintained the other features of the original MOU, and the second amendment
provided for a temporary rate increase of 3 percent, in addition to the prior
temporary rate level, to become effective as of January 1, 2000.
The Company reached a final settlement agreement with the VDPS in the pending
rate case during November 2000. The final settlement agreement contains the
following provisions:
* A rate increase of 3.42 percent above existing rates, beginning with bills
rendered January 23, 2001, and prior temporary rate increases became permanent;
* Rates set at levels that recover the Company's Hydro-Quebec contract
costs, effectively ending the regulatory disallowances experienced by the
Company over the past three years;
* The Company agrees not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a
request for rate relief if power supply costs increase in excess of $3.75
million over forecasted levels;
* The Company agrees to write off approximately $3.2 million in unrecovered
rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
* Seasonal rates will be eliminated in April 2001, which is expected to
generate approximately $6.0 million in cash flow that can be utilized to offset
increased costs during 2001, 2002 and 2003; and
* The Company agrees to consult extensively with the DPS regarding capital
spending commitments for upgrading our electric distribution system and to adopt
customer care and reliability performance standards, in a first step toward
possible development of performance-based rate-making.
On January 23, 2001, the VPSB approved the Company's settlement with the
Department, with two additional conditions:
* The Settlement Order requires the Company and customers to share equally
any premium above book value realized by the Company, subject to an $8.0 million
limit on the customers' share, in any future merger, acquisition or asset sale;
and
* The second condition restricts Company investments in non-utility
operations.
6. TRANSMISSION. A FERC ruling in December 2000 required ISO New England
to revise its installed capability ("ICAP") deficiency charge of $0.17 per kw
month to $8.75 per kw month retroactive to August 1, 2000. On January 10, 2001,
the FERC suspended its order "to ensure that bills for past periods will not be
assessed until the Commission has considered the pending requests for rehearing,
which, if successful, would then require extensive refunds and surcharges".
Numerous requests for rehearing challenging the imposition of the new rate have
been filed by New England utilities and state commissions. If the FERC does not
change its initial order as a result of the rehearings, the Company would be
required to pay ISO New England approximately $1.4 million related to 2000.
Management does not believe that the retroactive application of the ICAP
revision is probable.
7. DEFERRED CHARGES NOT INCLUDED IN RATE BASE. The Company has incurred
and deferred approximately $3.0 million in costs for tree trimming, storm damage
and federal regulatory commission work of which $2.8 million will be amortized
over five years ending in December 2005. Currently, the Company amortizes such
costs based on historical averages and does not receive a return on amounts
deferred. Management expects to seek and receive ratemaking treatment for these
costs in future filings.
The Settlement Order directed the Company to write-off deferred
charges applicable to the state regulatory commission of $3.2 million as part of
the rate case agreement with the DPS. The charge is included in other operating
expense for the year ended December 31, 2000. The Settlement Order requires the
remaining balance and future expenditures of deferred regulatory commission
charges be amortized over seven years.
8. OTHER LEGAL MATTERS. The Company is involved in legal and
administrative proceedings in the normal course of business and does not believe
that the ultimate outcome of these proceedings will have a material effect on
the financial position or the results of operations of the Company.
J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT
Agreements executed in 1985 among the Company, VELCO and other NEPOOL
members and Hydro-Quebec provided for the construction of the second phase
(Phase II) of the interconnection between the New England electric systems and
that of Hydro-Quebec. Phase II expands the Phase I facilities from 690
megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec power
from the Phase I terminal in northern New Hampshire to Sandy Pond,
Massachusetts. Construction of Phase II commenced in 1988 and was completed in
late 1990. The Company is entitled to 3.2 percent of the Phase II power-supply
benefits. Total construction costs for Phase II were approximately $487
million. The New England participants, including the Company, have contracted
to pay monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs. As a
supporting participant, the Company must make support payments under thirty-year
agreements. These support agreements meet the capital lease accounting
requirements under SFAS 13. At December 31, 2000, the present value of the
Company's obligation is approximately $6.4 million.
Projected future minimum payments under the Phase II support
agreements are as follows:
YEAR ENDING DECEMBER 31,
--------------------------
(In thousands)
2001. . . . . . . . $ 430
2002. . . . . . . . 430
2003. . . . . . . . 430
2004. . . . . . . . 430
2005. . . . . . . . 430
Total for 2006-2020 4,299
Total . . . . . $ 6,449
==========================
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 whether or not the production plants are operating.
The cost of power obtained under such long-term contracts, including payments
required 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 2000 follows:
STONY VERMONT
BROOK YANKEE
---------------------- ----------
(Dollars in thousands)
Plant capacity. . . . . . . . . . 352.0 MW 531.0 MW
Company's share of output 4.40% 17.90%
Contract period (1) (2)
Company's annual share of:
Interest $ 189 $ 2,397
Other debt service 347
Other capacity 497 25,401
---------- --------
Total annual capacity $ 1,033 $27,798
========== ========
Company's share of long-term debt $ 3,194 $17,181
(1) Life of plant estimated to be 1981 - 2006.
(2) License for plant operations expires in 2012.
2. Hydro-Quebec System Power Purchase and Sale Commitments. 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, we were obligated to purchase $4.0
million (in 1994 dollars) worth of research and development work from
Hydro-Quebec over a period ending October 1999(which has since been extended),
and made an additional $6.5 million (plus accrued interest) payment to
Hydro-Quebec in 1995. Hydro-Quebec retains the right to curtail annual energy
deliveries by 10 percent up to five times, over the 2000 to 2015 period, if
documented drought conditions exist in Quebec. The period for completing the
research and development purchase was subsequently extended to March 2001.
During the first year of the July 1994 Agreement (the period from
November 1995 through October 1996), the average cost per kilowatt-hour of
Schedules B and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a
34 percent (or $16 million) cost reduction. Over the period from November 1996
through December 2000 and accounting for the payments to Hydro-Quebec, the
combined unit costs will be lowered from 6.5 to 5.9 cents per kilowatt-hour,
reducing unit costs by 10 percent and saving $20.7 million in nominal terms.
All of the Company's contracts with Hydro-Quebec call for the delivery
of system power and are not related to any particular facilities in the
Hydro-Quebec system. Consequently, there are no identifiable debt-service
charges associated with any particular Hydro-Quebec facility that can be
distinguished from the overall charges paid under the contracts.
A summary of the Hydro-Quebec contracts through the July 1994
Agreement, including historic and projected charges for the years indicated,
follows:
THE 1987 CONTRACT
SCHEDULE B SCHEDULE C3
------------- -------------
(Dollars in thousands except per KWh)
Capacity acquired 68 MW 46 MW
Contract period. . . . . 1995-2015 1995-2015
Minimum energy purchase. 75% 75%
(annual load factor)
Annual energy charge . . 2000 $ 10,471 $ 7,105
estimated. . . . . . . 2001-2015 13,506 * 9,320 *
Annual capacity charge . 2000 16,850 11,727
estimated. . . . . . . 2001-2015 16,686 * 11,523 *
Average cost per KWh . . 2000 $ 0.068 $ 0.069
estimated. . . . . . . 2001-2015 $ 0.070 ** $ 0.070 **
*Estimated average
**Estimated average in nominal dollars levelized over the period indicated
Includes amortization of payments to Hydro-Quebec for the July 1994 Agreement
Under a 1996 arrangement (the "9601 arrangement"), the Company is
required to shift up to 40 megawatts of its Schedule C3 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 were made. The 9601 arrangement also provides for minimum payments
by the Company to Hydro-Quebec for the periods in which power is not purchased
under the arrangement. The 9601 arrangement allows Hydro-Quebec to curtail
energy deliveries should it need to use certain resources to supplement
available supply. During the last three months of 2000, Hydro-Quebec did
curtail energy deliveries. Although the level of benefits to the Company will
depend on various factors, the Company estimates that the 9601 arrangement will
provide a benefit of approximately $3.0 million on a net present value basis.
Under a separate agreement executed on December 5, 1997 (the "9701
arrangement"), Hydro-Quebec provided a payment of $8.0 million to the Company in
1997. In return for this payment, the Company provided Hydro-Quebec an ongoing
option for the purchase of power. Commencing April 1, 1998, and effective
through October 2015, Hydro-Quebec can exercise an option to purchase up to
52,500 MWh ("option A") on an annual basis, at energy prices established in
accordance with the 1987 Contract. The cumulative amount of energy purchased
under the 9701 arrangement shall not exceed 950,000 MWh. Hydro-Quebec's option
to curtail energy deliveries pursuant to the July 1994 Agreement may be
exercised in addition to these purchase options.
Over the same period, Hydro-Quebec can exercise an option on an annual
basis to purchase a total of 600,000 MWh ("option B") at the 1987 Contract
energy price. Hydro-Quebec can purchase no more than 200,000 MWh in any given
contract year ending October 31. As of December 31, 2000, Hydro-Quebec had
purchased or called to purchase 349,000 MWh under option B, including calls for
January and February of 2001.
In 2000, Hydro-Quebec called for deliveries to third parties at a net
cost to the Company of approximately $14.0 million (including the cost of the
January and February 2001 calls and related financial positions), which was due
to higher energy replacement costs. Approximately $6.6 million of the 9701
arrangement costs are recovered currently in rates on an annual basis. The
VPSB, in the Settlement Order said, "The record does not demonstrate that any
other New England utility foresaw the extent and degree of volatility that has
developed in the New England wholesale power markets. Absent that volatility,
the 97-01 Agreement would not have had adverse effects." In conjunction with
the Settlement Order, Hydro-Quebec committed to the DPS that it would not call
any energy under option B of the 9701 arrangement during 2002. In 1999,
Hydro-Quebec called for deliveries to third parties at a net cost to the Company
of approximately $6.3 million. The Company's estimate of the fair value of the
future net cost for the 9701 arrangement, which is dependent upon the timing of
any exercise of options, and the market price for replacement power, is between
$24.5 and $29.5 million. Future estimates could change by a material amount.
In 1999, the Company and the other Vermont Joint Owners (VJO) of the
Hydro-Quebec contract initiated an arbitration against Hydro-Quebec, pursuant to
the 1987 Contract terms, to determine whether the suspension of deliveries of
power to Vermont during and after the January 1998 ice storm evidenced a default
by Hydro-Quebec under the terms of the contract. Hydro-Quebec maintains that
the "force majeure" (superior or irreversible force) provision in the 1987
Contract applies, which could excuse its non-delivery of power under these
circumstances. Arbitration of the dispute may lead to remedies having a
material impact on our contractual obligation, including the possibility that
the 1987 Contract be declared terminated or void. If arbitration results in a
cash payment, it will first be applied to a regulatory asset of $4.7 million for
arbitration litigation costs. If the 1987 Contract is declared terminated or
void, the Company would have to replace a substantial amount of its power needs
at terms which could materially exceed the 1987 Contract price for 2001. The
Company believes that it could contract replacement power at costs substantially
below the long term costs of the 1987 Contract. The Settlement Order provides
that the Company will not earn a return on these litigation costs, unless the
case results in lower power supply costs for ratepayers. A decision is expected
in this arbitration in April 2001.
3. Morgan Stanley Agreement - On February 11, 1999, the Company entered
into a contract with Morgan Stanley Capital Group, Inc. (MS). In January 2001,
the MS contract was modified and extended to December 31, 2003. The contract
provides us a means of managing price risks associated with changing fossil fuel
prices. On a daily basis, and at MS's discretion, the Company will sell power
to MS from either (i) all or part of our portfolio of power resources at
predefined operating and pricing parameters or (ii) any power resources
available to the Company, provided that sales of power from sources other than
Company-owned generation comply with the predefined operating and pricing
parameters. MS then sells to us, at a predefined price, power sufficient to
serve pre-established load requirements. MS is also responsible for scheduling
supply resources. The Company remains responsible for resource performance and
availability. MS provides no coverage against major unscheduled outages.
L. DISCONTINUED OPERATIONS.
The Company has decided to sell or otherwise dispose of the operations
and assets of MEI, which owns and invests in energy generation, energy
efficiency, and wastewater treatment projects. MEI has been reported as a
separate segment in 1998 and prior years, and appeared as a separate "Equity
investment in energy related business" caption in the nonutility section of the
consolidated balance sheet. Results of operations were previously included in
the section Other Income in the consolidating statements of income. In 1999 and
2000, assets and liabilities are presented net in the nonutility section as
"Business segment held for disposal", or "Liability of discontinued segment".
The provisions for loss from discontinued operations reflect management's
current estimate. Risk factors associated with the discontinuation of MEI
operations include the outcome of warranty litigation, and future cash
requirements necessary to minimize costs of winding down wastewater operations.
Several municipalities using wastewater treatment equipment have commenced or
threatened litigation. The ultimate loss remains subject to the disposition of
remaining assets and liabilities, and could exceed the amounts recorded. The
following illustrates the results and financial statement impact of MEI during
and at the periods shown:
2000 1999 1998
-------- -------- --------
(In thousands except per share)
Revenues . . . . . . . . . . . . . . $ 1,546 $ 2,296 $ 2,092
-------- -------- --------
Net income (loss) operations . . . . $ - $ (603) $(2,086)
Provisions for loss on disposal and
future operating losses. . . . . . (6,549) (6,676) -
Net income (loss). . . . . . . . . . $(6,549) $(7,279) $(2,086)
======== ======== ========
Net income (loss) per share. . . . . $ (1.19) $ (1.36) $ (0.40)
Income taxes for MEI for the years ended December 31, 2000, 1999 and 1998 are
summarized as:
YEARS ENDED DECEMBER 31,
2000 1999 1998
-------- -------- --------
(In thousands)
State income taxes . . . . . $(1,064) $ (281) $ (222)
Federal income taxes . . . . (3,349) (1,371) (1,130)
Investment tax credits . . . - - (111)
-------- -------- --------
Income tax expense (benefit) $(4,413) $(1,652) $(1,463)
======== ======== ========
M. 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.
2000 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
------- -------- ---------- ---------- ---------
(Amounts in thousands except per share data)
Operating revenues. . . . . . . . . . . . . . $67,712 $61,927 $ 78,143 $ 69,544 $277,326
Operating income (loss) . . . . . . . . . . . 4,613 (2,997) 3,271 373 5,260
Net income (loss) from continuing operations. $ 3,449 $(4,375) $ 1,961 $ (1,340) $ (305)
Net loss from
discontinued operations. . . . . . . . . . . - (1,530) - (5,019) (6,549)
Net Income (loss) applicable to common stock. $ 3,449 $(5,905) $ 1,961 $ (6,359) $ (6,854)
======= ======== ========== ========== =========
Earnings (loss) per average share from:
Continuing operations . . . . . . . . . . . . $ 0.63 $ (0.80) $ 0.36 $ (0.25) $ (0.06)
Discontinued operations . . . . . . . . . . . - (0.28) - (0.91) (1.19)
Basic and diluted . . . . . . . . . . . . . . $ 0.63 $ (1.08) $ 0.36 $ (1.16) $ (1.25)
======= ======== ========== ========== =========
Weighted average common shares outstanding. . 5,437 5,472 5,505 5,551 5,491
1999 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
-------- -------- ----------- ---------- ---------
(Amounts in thousands except per share data)
Operating revenues. . . . . . . . . . . . . . $59,018 $59,535 $ 68,478 $ 64,017 $251,048
Operating income. . . . . . . . . . . . . . . 3,906 977 1,412 1,651 7,946
Net income (loss) from continuing operations. $ 3,170 $ (412) $ (115) $ 418 $ 3,061
Net loss from
discontinued operations. . . . . . . . . . . (522) (81) (4,592) (2,084) (7,279)
Net Income (loss) applicable to common stock. $ 2,648 $ (493) $ (4,707) $ (1,666) $ (4,218)
======== ======== =========== ========== =========
Earnings (loss) per average share from:
Continuing operations . . . . . . . . . . . . $ 0.60 $ (0.08) $ (0.02) $ 0.07 $ 0.57
Discontinued operations . . . . . . . . . . . (0.10) (0.02) (0.85) (0.39) (1.36)
Basic and diluted . . . . . . . . . . . . . . $ 0.50 $ (0.10) $ (0.88) $ (0.31) $ (0.79)
======== ======== =========== ========== =========
Weighted average common shares outstanding. . 5,318 5,344 5,374 5,291 5,361
1998 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
-------- -------- ----------- ---------- ---------
(Amounts in thousands except per share data)
Operating revenues. . . . . . . . . . . . . . $46,932 $43,733 $ 47,984 $ 45,655 $184,304
Operating income. . . . . . . . . . . . . . . 316 2,811 3,147 (802) 5,472
Net income (loss) from continuing operations. $(2,648) $ 1,286 $ 1,811 $ (2,536) $ (2,087)
Net loss from
discontinued operations . . . . . . . . . . . (757) (355) (178) (796) (2,086)
Net income (loss) applicable to common stock. $(3,405) $ 931 $ 1,633 $ (3,332) $ (4,173)
======== ======== =========== ========== =========
Earnings (loss) per average share from:
Continuing operations . . . . . . . . . . . . $ (0.51) $ 0.25 $ 0.34 $ (0.48) $ (0.40)
Discontinued operations . . . . . . . . . . . (0.15) (0.06) (0.03) (0.16) (0.40)
Basic and diluted . . . . . . . . . . . . . . $ (0.66) $ 0.18 $ 0.31 $ (0.63) $ (0.80)
======== ======== =========== ========== =========
Weighted average common shares outstanding. . 5,196 5,222 5,261 5,291 5,243
69
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To the Board of Directors of
Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and consolidated
capitalization data of Green Mountain Power Corporation (a Vermont corporation)
and its subsidiaries as of December 31, 2000 and 1999, and the related
consolidated statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2000. 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 audit.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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 and its subsidiaries as of December 31, 2000 and 1999, and the
consolidated results of its operations and cash flows for each of the three
years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States.
/s/ Arthur Anderson
Boston, Massachusetts
February 2, 2001
Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2000, 1999, and 1998
Balance at Additions Additions Balance at
Beginning of Charged to Charged to End of
Period Cost & Expenses Other Accounts Deductions Period
------------- ---------------- --------------- ----------- -----------
Injuries and Damages (1)
2000 . . . . . . . . . . $ 10,129,130 $ 111,667 $ 3,193,383 $ 51,467 $13,382,713
1999 . . . . . . . . . . 7,898,785 100,000 3,814,874 1,684,529 10,129,130
1998 . . . . . . . . . . 663,785 2,735,000 5,000,000 500,000 7,898,785
Bad Debt Reserve
2000 . . . . . . . . . . 390,495 35,395 - - 425,890
1999 . . . . . . . . . . 400,000 261,697 12,762 283,964 390,495
1998(2). . . . . . . . . 493,405 393,949 83,299 570,653 400,000
(1) Includes Pine Street Barge Canal reserves
(2) Includes non-utility bad debt reserve.
71
Exhibit 23-a-1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
-----------------------------------------
As independent public accountants, we hereby consent to the incorporation of our
reports dated February 2, 2001 included in this Form 10-K into the Company's
previously filed Registration Statements on Form S-3, File Nos. 33-58411 and
33-59383, and into the Company's previously filed Registration Statements on
Form S-8, File Nos. 33-58413 and 33-60511. It should be noted that we have not
performed any audit procedures subsequent to December 31, 2000 or performed any
audit procedures subsequent to the date of our report.
Boston, Massachusetts
March 21, 2001 /s/ Arthur Andersen LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
We have audited, in accordance with generally accepted auditing standards, the
consolidated financial statements of Green Mountain Power Corporation included
in this Form 10-K and have issued our report thereon dated February 2, 2001. 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 accompanying index to
consolidated financial statements and schedules is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic consolidated financial statements. This schedule has been subjected to
the auditing procedures applied in the audit of the basic consolidated financial
statements, and in our opinion, fairly states, in all material respects, the
financial data required to be set forth therein in relation to the basic
consolidated financial statements taken as a whole.
Boston, Massachusetts
February 2, 2001 /s/ Arthur Andersen LLP
72
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 17, 2001. 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
March 2001.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
Item 14(a)1. Financial Statements and Schedules. The financial statements and
financial statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.
Item 14(b) The following filings on Form 8-K were filed by the company on
the topics and dates indicated:
November 13, 2000 announced the negotiation of a final rate settlement with the
Vermont Department of Public Service.
November 15, 2000 announced a revised offer for the purchase of the Vermont
Yankee nuclear generating plant was accepted by Vermont Yankee from AmerGen
Energy Company.
January 5, 2001 announced continued mediation with Local 300 of the
International Brotherhood of Electrical Workers, which had gone on strike that
week resulting in the need for a federal mediator.
January 23, 2001 announced the Vermont Public Service Board Order approving the
rate case settlement between the Company and the Vermont Department of Public
Service, allowing a 3.42 percent increase in electric rates, and making
permanent the two prior temporary rate increases.
January 26, 2001 announced Local 300 of the International Brotherhood of
Electrical Workers voted to end the strike and ratify the new proposed contract,
which included a provision for a second shift crew.
February 14, 2001 announced the Vermont Public Service Board Order Dismissing
Petition in Docket Number 6300, in which the Board determined that the revised
offer by AmerGen Energy Company for the purchase of Vermont Yankee's nuclear
generating plant did not reflect the fair market value of the plant, and
dismissed the petition for approval.
March 6, 2001 announced the credit rating upgrade by Moody's Investor Service of
the Company's first mortgage bonds from Ba1 to Baa2, and the upgrade of the
Company's preferred stock from ba3 to baa3.
The accompanying notes are an integral part of these consolidated financial
statements.
ITEM 14(A)3 AND ITEM 14(C). EXHIBITS SEC DOCKET
INCORPORATED BY
REFERENCE OR
DESCRIPTION EXHIBIT PAGE FILED HEREWITH
- ----------------------------------------------------- ---------------- --------------------
Restated Articles of Association, as certified. . . . 3-a Form 10-K 1993
June 6, 1991. (1-8291)
Amendment to 3-a above, dated as of May 20, 1993. . . 3-a-1 Form 10-K 1993
(1-8291)
Amendment to 3-a above, dated as of October 11, 1996. 3-a-2 Form 10-Q Sept.
1996 (1-8291)
By-laws of the Company, as amended. . . . . . . . . . 3-b Form 10-K 1996
February 10, 1997. (1-8291)
Indenture of First Mortgage and Deed of Trust . . . . 4-b 2-27300
dated as of February 1, 1955.
First Supplemental Indenture dated as of. . . . . . . 4-b-2 2-75293
April 1, 1961.
Second Supplemental Indenture dated as of . . . . . . 4-b-3 2-75293
January 1, 1966.
Third Supplemental Indenture dated as of. . . . . . . 4-b-4 2-75293
July 1, 1968.
Fourth Supplemental Indenture dated as of . . . . . . 4-b-5 2-75293
October 1, 1969.
Fifth Supplemental Indenture dated as of. . . . . . . 4-b-6 2-75293
December 1, 1973.
Seventh Supplemental Indenture dated as . . . . . . . 4-a-7 2-99643
August 1, 1976.
Eighth Supplemental Indenture dated as of . . . . . . 4-a-8 2-99643
December 1, 1979.
Ninth Supplemental Indenture dated as of. . . . . . . 4-b-9 2-99643
July 15, 1985.
Tenth Supplemental Indenture dated as of. . . . . . . 4-b-10 Form 10-K 1989
June 15, 1989. (1-8291)
Eleventh Supplemental Indenture dated as of . . . . . 4-b-11 Form 10-Q Sept.
September 1, 1990. 1990 (1-8291)
Twelfth Supplemental Indentrue dated as of. . . . . . 4-b-12 Form 10-K 1991
March 1, 1992. (1-8291)
Thirteenth Supplemental Indenture dated as of . . . . 4-b-13 Form 10-K 1991
March 1, 1992. (1-8291)
Fourteenth Supplemental Indenture dated as of . . . . 4-b-14 Form 10-K 1993
November 1, 1993. (1-8291)
Fifteenth Supplemental Indenture dated as of. . . . . 4-b-15 Form 10-K 1993
November 1, 1993. (1-8291)
Sixteenth Supplemental Indenture dated as of. . . . . 4-b-16 Form 10-K 1995
December 1, 1995. (1-8291)
Revised form of Indenture as filed as an Exhibit. . . 4-b-17 Form 10-Q Sept.
to Registration Statement No. 33-59383. 1995 (1-8291)
Credit Agreement by and among Green Mountain Power. . 4-b-18 Form 10-K 1997
The Bank of Nova Scotia, State Street Bank and (1-8291)
Trust Company, Fleet National Bank, and Fleet
National Bank, as Agent
Amendment to Exhibit 4-b-18 . . . . . . . . . . . . . 4-b-18(a) Form 10-Q Sept.
1998 (1-8291)
Form of Insurance Policy issued by Pacific. . . . . . 10-a 33-8146
Insurance Company, with respect to
indemnification of Directors and Officers.
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.
Power Contract, dated February 1, 1968, between . . . 13-d 2-34346
the Company and Vermont Yankee Nuclear Power
Corporation.
Amendment, dated June 1, 1972, to Power Contract. . . 13-f-1 2-49697
between the Company and Vermont Yankee Nuclear
Power Corporation.
Amendment, dated April 15, 1983, to Power . . . . . . 10-b-3(a) 33-8164
Contract between the Company and Vermont
Yankee Nuclear Power Corporation.
Additional Power Contract, dated. . . . . . . . . . . 10-b-3(b) 33-8164
February 1, 1984,between the Company and
Vermont Yankee Nuclear Power Corporation.
Capital Funds Agreement, dated February 1,. . . . . . 13-e 2-34346
1968, between the Company and Vermont
Yankee Nuclear Power Corporation.
Amendment, dated March 12, 1968, to Capital . . . . . 13-f 2-34346
Funds Agreement between the Company and
Vermont Yankee Nuclear Power Corporation.
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.
Three-Party Power Agreement among the Company,. . . . 13-i 2-49697
VELCO and Central Vermont Public Service
Corporation dated November 21, 1969.
Amendment to Exhibit 10-b-7, dated June 1, 1981.. . . 10-b-8 2-75293
Three-Party Transmission Agreement among the. . . . . 13-j 2-49697
Company, VELCO and Central Vermont Public
Service Corporation, dated November 21, 1969.
Amendment to Exhibit 10-b-9, dated June 1, 1981.. . . 10-b-10 2-75293
Agreement with Central Maine Power Company et 5.16 2-52900
al, to enter into joint ownership of Wyman
plant, dated November 1, 1974.
New England Power Pool Agreement as amended to 4.8 2-55385
November 1, 1975.
Bulk Power Transmission Contract between the. . . . . 13-v 2-49697
Company and VELCO dated June 1, 1968.
Amendment to Exhibit 10-b-16, dated June 1, 1970. . . 13-v-i 2-49697
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.
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.
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.
Bulk Power Purchase Contract dated April 7, . . . . . 10-b-32 2-75293
1976, between VELCO and the Company.
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-Qubec.
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-Qubec.
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-Qubec.
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-Qubec.
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-Qubec.
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-Qubec.
VETCO Capital Funds Support Agreement dated as. . . . 10-b-41 33-8164
of July 15, 1982, between VELCO and participating
Vermont utilities for allocation of VELCO's
obligation to VETCO under the Capital Funds
Agreement.
Energy Banking Agreement dated March 21, 1983,. . . . 10-b-42 33-8164
among Hydro-Qubec, 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-Qubec.
Interconnection Agreement dated March 21, 1983, . . . 10-b-43 33-8164
between Hydro-Qubec 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-Qubec.
Energy Contract dated March 21, 1983, between . . . . 10-b-44 33-8164
Hydro-Qubec and participating New England
utilities acting by and through the NEPOOL
Management Committee for purchase of
surplus energy from Hydro-Qubec.
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.
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.
Allocation Contract for Hydro-Qubec Firm Power. . . . 10-b-52 33-8164
dated July 25, 1984, between the State of
Vermont and various Vermont electric utilities,
including the Company.
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.
Agreements entered in connection with Phase II. . . . 10-b-61 33-8164
of the NEPOOL/Hydro-Qubec + 450 KV HVDC
Transmission Interconnection.
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.
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.
Firm Power and Energy Contract dated December 4,. . . 10-b-68 Form 10-K 1992
1987, between Hydro-Qubec and participating (1-8291)
Vermont utilities, including the Company, for
the purchase of firm power for up to thirty years.
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.
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.
Amendment to 10-b-70. . . . . . . . . . . . . . . . . 10-b-70(a) Form 10-K 1992
(1-8291)
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-Qubec.
Participation Agreement dated as of April 1, 1988,. . 10-b-72 Form 10-Q
between Hydro-Qubec 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).
Restatement of the Participation Agreement filed. . . 10-b-72(a) Form 10-K 1988
as Exhibit 10-b-72 on Form 10-Q for June 1988. (1-8291)
Agreement dated as of May 1, 1988, between. . . . . . 10-b-73 Form 10-Q
Rochester Gas and Electric Corporation and the. . . . September. 1988
Company, implementing the Company's purchase of up (1-8291)
to 50 MW of electric capacity and associated energy.
Firm Power and Energy Contract dated December 29, . . 10-b-77 Form 10-K 1988
1988, between Hydro-Qubec and participating (1-8291)
Vermont utilities, including the Company, for the
purchase of up to 54 MW of firm power and energy.
Transmission Agreement dated December 23, 1988, . . . 10-b-78 Form 10-K 1988
between the Company and Niagara Mohawk Power (1-8291)
Corporation (Niagara Mohawk), for Niagara
Mohawk to provide electric transmission to
the Company from Rochester Gas and Electric
and Central Hudson Gas and Electric.
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.
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.
Power Purchase and Sale Agreement between . . . . . . 10-b-85 Form 10-K 1998
Morgan Stanley Capital Group Inc. and the (1-8291)
Company
Revolving Credit Agreement with KeyBank . . . . . . . 10-b-86 Form 10-Q Sept.
2000 (1-8291)
Amendment to Fleet Revolving Credit Agreement . . . . 10-b-87 Form 10-Q Sept.
2000 (1-8291)
Energy East Power Purchase Option Agreement . . . . . 10-b-88 Form 10-Q Sept.
2000 (1-8291)
MANAGEMENT CONTRACTS OR COMPENSATORY PLANS OR ARRANGEMENTS
REQUIRED TO BE FILED AS EXHIBITS TO THIS FORM 10-K
PURSUANT TO ITEM 14(C)., ALL UNDER SEC DOCKET 1-8291
Green Mountain Power Corporation Second Amended. . . . . . 10-d-1b Form 10-K 1993
and Restated Deferred Compensation Plan for
Directors.
Green Mountain Power Corporation Second Amended. . . . . . 10-d-1c Form 10-K 1993
and Restated Deferred Compensation Plan for
Officers.
Amendment No. 93-1 to the Amended and Restated . . . . . . 10-d-1d Form 10-K 1993
Deferred Compensation Plan for Officers.
Amendment No. 94-1 to the Amended and Restated . . . . . . 10-d-1e Form 10-Q
Deferred Compensation Plan for Officers. . . . . . . . . . June 1994
Green Mountain Power Corporation Medical Expense . . . . . 10-d-2 Form 10-K 1991
Reimbursement Plan.
Green Mountain Power Corporation Officer . . . . . . . . . 10-d-4 Form 10-K 1991
Insurance Plan.
Green Mountain Power Corporation Officers' . . . . . . . . 10-d-4a Form 10-K 1990
Insurance Plan as amended.
Green Mountain Power Corporation Officers' . . . . . . . . 10-d-8 Form 10-K 1990
Supplemental Retirement Plan.
Green Mountain Power Corporation Compensation Program. . . 10-d-15b Form 10-K 1997
for Officers and Key Management Personnel as amended
August 4, 1997
Severance Agreement with N. R. Brock . . . . . . . . . . . 10-d-21 Form 10-K 1998
Severance Agreement with C. L. Dutton. . . . . . . . . . . 10-d-22 Form 10-K 1998
Severance Agreement with R. J. Griffin . . . . . . . . . . 10-d-23 Form 10-K 1998
Severance Agreement with M. H. Lipson. . . . . . . . . . . 10-d-25 Form 10-K 1998
Severance Agreement with C. T. Myotte. . . . . . . . . . . 10-d-26 Form 10-K 1998
Severance Agreement with W. S. Oakes . . . . . . . . . . . 10-d-27 Form 10-K 1998
Severance Agreement with M. G. Powell. . . . . . . . . . . 10-d-28 Form 10-K 1998
Severance Agreement with S. C. Terry . . . . . . . . . . . 10-d-29 Form 10-K 1998
Severance Agreement with J. H. Winer . . . . . . . . . . . 10-d-30 Form 10-K 1998
Subsidiaries of the Registrant 21 Form 10-K 1996
Consent of Arthur Andersen LLP . . . . . . . . . . . . . . 23-a-1
Limited Power of Attorney 24
79
EXHIBIT 24
POWER OF ATTORNEY
-----------------
We, the undersigned directors of Green Mountain Power Corporation, hereby
severally constitute Christopher L. Dutton, Nancy R. Brock, and Robert J.
Griffin, and each of them singly, our true and lawful attorney with full power
of substitution, to sign for us and in our names in the capacities indicated
below, the Annual Report on Form 10-K of Green Mountain Power Corporation for
the fiscal year ended December 31, 2000, and generally to do all such things in
our name and behalf in our capacities as directors to enable Green Mountain
Power Corporation to comply with the provisions of the Securities Exchange Act
of 1934, as amended, all requirements of the Securities and Exchange Commission,
and all requirements of any other applicable law or regulation, hereby ratifying
and confirming our signatures as they may be signed by our said attorney, to
said Annual Report.
SIGNATURE TITLE DATE
- --------- ----- ----
_/s/ Christopher L. Dutton President and Director February 5, 2001
- -----------------------------
Christopher L. Dutton (Principal Executive
Officer)
_/s/ Thomas P. Salmon____
- ----------------------------
Thomas P. Salmon Chairman of the Board February 5, 2001
_/s/ Nordahl L. Brue_______
- ------------------------------
Nordahl L. Brue Director February 5, 2001
_/s/ William H. Bruett_____
- ------------------------------
William H. Bruett Director February 5, 2001
_/s/ Merrill O. Burns_____
- -----------------------------
Merrill O. Burns Director February 5, 2001
_/s/ Lorraine E. Chickering
- ------------------------------
Lorraine E. Chickering Director February 5, 2001
_/s/ John V. Cleary________
- ------------------------------
John V. Cleary Director February 5, 2001
_/s/ David R. Coates________
- -------------------------------
David R. Coates Director February 5, 2001
_/s/ Euclid A. Irving______
- ------------------------------
Euclid A. Irving Director February 5, 2001
80
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
By: ____/s/ Christopher L. Dutton________
--------------------------
Christopher L. Dutton, President
and Chief Executive Officer
Date: March 28, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
__/s/ Christopher L. Dutton President and Director March 28, 2001
-------------------------
Christopher L. Dutton (Principal Executive Officer)
_/s/Nancy R. Brock_______ Vice President, Treasurer and March 28, 2001
---------------------
Nancy R. Brock Chief Financial Officer (Principal
Financial Officer)
/s/Robert J. Griffin_ Controller March 28, 2001
-----------------------
Robert J. Griffin (Principal Accounting Officer)
*Thomas P. Salmon Chairman of the Board
*Nordahl L. Brue )
*William H. Bruett )
*Merrill O. Burns )
*David R. Coates )
*Lorraine E. Chickering )
*John V. Cleary )
Directors
*Euclid A. Irving )
*By: _/s/ Christopher L. Dutton March 28, 2001
---------------------------
Christopher L. Dutton
(Attorney - in - Fact)