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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
_X_ Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
___ Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
FOR THE 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. Comm