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, 2001
COMMISSION FILE NUMBER 1-8291
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
(Exact name of registrant as specified in its charter)
Vermont 03-0127430
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
163 Acorn Lane
Colchester, VT 05446
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (802) 864-5731
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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 _____
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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 15, 2002, WAS APPROXIMATELY $102,348,759 BASED ON THE
CLOSING PRICE OF $17.98 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 15, 2002, WAS
5,692,367
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders to be held on May 16, 2002, 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, 2001
Table of contents Page
Part I, Item 1, Business 3
Item 2, Properties 17
Item 3, Legal Proceedings 19
Item 4, Submission of Matters To a Vote of 19
Security Holders
Part II, Item 5, Market for Registrant's Common
Equity and Related Shareholder Matters 19
Item 6, Selected Financial Data 21
Item 7, Management's Discussion and Analysis 22
Of Financial Condition and Results
Of Operations
Item 8, Index to Consolidated Financial Statements
and Notes 39
Item 9, Changes In and Disagreements with Accountants 74
On Accounting and Financial Disclosure
Items 10 through 13, Certain Officer information 74
Item 14, Exhibits, Financial Statement Schedules, 74
And Reports on Form 8-K
PART I
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 Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations ("MD and A"), in the 2001 Annual Report to Shareholders ("Annual
Report"), and in the accompanying Notes to Consolidated Financial Statements
("Notes"), all included herein.
ITEM 1. BUSINESS
THE COMPANY
Green Mountain Power Corporation (the "Company" or "GMP") is a public
utility operating company engaged in supplying electrical energy in the State of
Vermont ("State" or "Vermont") in a territory with approximately one quarter of
the State's population. We serve approximately 87,000 customers. The Company
was incorporated under the laws of the State on April 7, 1893.
Our sources of revenue for the year ended December 31, 2001 were as
follows:
* 24.6% from residential customers;
* 26.0% from small commercial and industrial customers;
* 18.2% from large commercial and industrial customers;
* 29.6% from sales to other utilities; and
* 1.6% from other sources.
See the Annual Report and M D and A for further information about revenues.
During 2001, our energy resources for retail and wholesale sales of
electricity, excluding sales made pursuant to the agreement with Morgan Stanley
Capital Group, Inc. ("MS") discussed under MD and A-Power Contract Commitments,
were obtained as follows:
* 37.4% from hydroelectric sources (2.4% Company-owned, 0.1% New York Power
Authority ("NYPA"), 33.2% Hydro-Quebec and 1.7% small power producers);
* 30.8% from a nuclear generating source (the Vermont Yankee nuclear plant
described below);
* 3.2% from wood;
* 2.0% from oil;
* 2.2% from natural gas; and
* 0.5% from wind.
The remaining 23.9% 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 2001, we purchased 93.0% of our energy resources to satisfy our retail
and wholesale sales of electricity (including energy purchased from Vermont
Yankee Nuclear Power Corporation ("Vermont Yankee" or "VY") and under other
long-term purchase arrangements). See Note K of Notes.
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 VY. 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
deregulated wholesale energy 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 such high usage periods such as 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 and towns of Montpelier, Barre, South Burlington, Vergennes,
Williston, Shelburne, 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. The
Company's right to distribute electrical service in its service territory is the
utility's most important asset. 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, tourism (particularly fall and winter
recreation), and dairy and general farming.
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,
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Total capability (MW) . . . . . . . . . . . . . . 408.0 411.1 393.2 396.9 416.9
Net system peak . . . . . . . . . . . . . . . . . 341.2 323.5 317.9 312.5 311.5
----------- ----------- ----------- ----------- -----------
Reserve (MW). . . . . . . . . . . . . . . . . . . 66.8 87.6 75.3 84.4 105.4
=========== =========== =========== =========== ===========
Reserve % of peak . . . . . . . . . . . . . . . . 19.6% 27.1% 23.7% 27.0% 33.8%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . . 951,146 1,053,223 1,095,738 972,723 1,073,246
Wind. . . . . . . . . . . . . . . . . . . . . . . 12,135 12,246 7,956 - -
Nuclear . . . . . . . . . . . . . . . . . . . . . 736,420 803,303 731,431 607,708 772,030
Conventional steam. . . . . . . . . . . . . . . . 2,670,249 2,704,427 2,328,267 750,602 560,504
Internal combustion . . . . . . . . . . . . . . . 18,291 35,699 12,312 40,148 4,827
Combined cycle. . . . . . . . . . . . . . . . . . 72,653 73,433 99,962 118,322 104,836
Total production. . . . . . . 4,460,894 4,682,331 4,275,666 2,489,503 2,515,443
Less non-firm sales to other utilities. . . . . . 2,365,809 2,573,576 2,152,781 499,409 524,192
----------- ----------- ----------- ----------- -----------
Production for firm sales . . . . . . . . . . . . 2,095,085 2,108,755 2,122,885 1,990,094 1,991,251
Less firm sales and lease transmissions. . . . . 1,956,232 1,954,898 1,920,257 1,883,959 1,870,914
----------- ----------- ----------- ----------- -----------
Losses and company use (MWH). . . . . . . . . . . 138,853 153,857 202,628 106,134 120,337
=========== =========== =========== =========== ===========
Losses as a % of total production . . . . . . . . 3.11% 3.29% 4.74% 4.26% 4.78%
System load factor (***). . . . . . . . . . . . . 70.1% 74.2% 76.2% 72.7% 73.0%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . . 21.3% 22.5% 25.6% 39.1% 42.7%
Wind. . . . . . . . . . . . . . . . . . . . . . . 0.3% 0.3% 0.2% 0.0% 0.0%
Nuclear . . . . . . . . . . . . . . . . . . . . . 16.5% 17.1% 17.1% 24.4% 30.6%
Conventional steam. . . . . . . . . . . . . . . . 59.9% 57.8% 54.5% 30.2% 22.3%
Internal combustion . . . . . . . . . . . . . . . 0.4% 0.8% 0.3% 1.6% 0.2%
Combined cycle. . . . . . . . . . . . . . . . . . 1.6% 1.6% 2.3% 4.8% 4.2%
----------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0%
=========== =========== =========== =========== ===========
Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . . 549,151 558,682 544,447 533,904 549,259
Commercial & industrial - small . . . . . . . . . 718,969 704,126 688,493 665,707 645,331
Commercial & industrial - large . . . . . . . . . 683,004 683,296 664,110 636,436 608,051
Other . . . . . . . . . . . . . . . . . . . . . . 2,030 6,713 3,138 3,476 3,939
----------- ----------- ----------- ----------- -----------
Total retail sales and lease transmissions. . . . 1,953,154 1,952,817 1,900,188 1,839,522 1,806,581
Sales to Municipals & Cooperatives (Rate W) . . . 3,078 2,081 20,069 44,437 64,333
----------- ----------- ----------- ----------- -----------
Total Requirements Sales. . . . . . . . . . . . . 1,956,232 1,954,898 1,920,257 1,883,959 1,870,914
Other Sales for Resale. . . . . . . . . . . . . . 2,365,809 2,573,576 2,152,781 499,409 524,192
----------- ----------- ----------- ----------- -----------
Total sales and lease transmissions(MWH) . . . . 4,322,041 4,528,474 4,073,038 2,383,368 2,395,106
=========== =========== =========== =========== ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . . 73,249 72,424 71,515 71,301 70,671
Commercial and industrial small . . . . . . . . . 12,984 12,746 12,438 12,170 11,989
Commercial and industrial large . . . . . . . . . 22 23 23 23 23
Other . . . . . . . . . . . . . . . . . . . . . . 65 65 66 70 75
----------- ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . . . . . 86,320 85,258 84,042 83,564 82,758
=========== =========== =========== =========== ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . . 13.33 12.50 12.32 11.56 11.18
Commercial & industrial - small . . . . . . . . . 10.83 10.00 9.88 9.29 9.10
Commercial & industrial - large . . . . . . . . . 7.69 6.51 6.55 6.32 6.22
Total retail including lease. . . . . . . . . . . 10.44 9.52 9.47 8.96 8.79
=========== =========== =========== =========== ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . . 7,497 7,717 7,617 7,488 7,772
Revenues including lease revenues . . . . . . . . $ 999 $ 965 $ 938 $ 865 $ 869
(*) 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.
STATE AND FEDERAL REGULATION
General. The Company is subject to the regulatory authority of the Vermont
Public Service Board ("VPSB"), which extends to retail rates, services 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,
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 International Business Machines Corporation ("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 1.0% of operating revenues for 2001.
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 2001.
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 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 expired August 31, 2001, renewal pending
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
Waterbury reservoir was drained in 2001 to prepare for repairs to the dam by the
State, presently estimated for completion in 2004. Once repairs are complete,
the Company expects the project to be relicensed for a 30 year term and does not
have any competition for the Waterbury license.
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
The Company reached a final settlement agreement with the Department in its
1998 rate case during November 2000. The final settlement agreement contained
the following provisions:
* The Company received a rate increase of 3.42 percent above existing rates,
beginning with bills rendered January 23, 2001, and prior temporary rate
increases became permanent;
* Rates were set at levels that recover the Company's Hydro-Quebec VJO
contract costs, effectively ending the regulatory disallowances experienced by
the Company from 1998 through 2000;
* The Company agreed not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a
request for additional rate relief if power supply costs increase in excess of
$3.75 million over forecasted levels;
* The Company agreed to write off in 2000 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 were eliminated in April 2001, which generated
approximately $8.5 million in additional cash flow in 2001 that can be utilized
to offset increased costs during 2002 and 2003;
* The Company agreed 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;
* The Company agreed to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in the 1997 rate case; and
* The Company agreed to an earnings limitation for its electric operations
in an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned over the limit being used to write off regulatory assets.
The Company earned approximately $30,000 in excess of its allowed rate of
return during 2001 before writing off regulatory assets in the same amount.
On January 23, 2001, the VPSB approved the Company's settlement (the
"Settlement Order") with the Department, with two additional conditions:
* The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to an $8.0 million limit on the customers' share; and
* The Company's further investment in non-utility operations is restricted.
For further information regarding recent rate developments, see Item 7. MD
and A - Rates, Liquidity and Capital Resources, and Note I of Notes.
SINGLE CUSTOMER DEPENDENCE
The Company had one major retail customer, IBM, metered at two locations
that accounted for 13.5 percent, 11.2 percent, and 11.8 percent of total
operating revenues, and 19.2 percent, 16.5 percent and 16.2 percent of the
Company's retail operating revenues in 2001, 2000 and 1999, respectively. IBM's
percent of total revenues and MWH sales in 2001 increased due to a rate increase
and a decrease in total operating revenues as a result of decreased sales for
resale pursuant to the MS agreement, which is discussed in greater detail in
Item 7 of the 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 could have a
material adverse effect on the Company and 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 Note A of the Notes.
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 a municipal public utility.
During 2001, the Town of Rockingham ("Rockingham"), Vermont initiated
inquiries and legal procedures to establish its own electric utility, seeking to
purchase an existing hydro-generation facility from a third party, and the
associated distribution plant owned by the Company within the town. In March
2002, voters in Rockingham approved an article authorizing Rockingham to create
a municipal utility by acting to acquire a municipal plant which would include
the Bellows Falls Hydroelectric facility and the electric distribution systems
of the Company and/or Central Vermont Public Service Corporation. The Company
receives annual revenues of approximately $4.0 million from its customers in
Rockingham. Should Rockingham create a municipal system, the Company would
vigorously pursue its right to receive just compensation from Rockingham. Such
compensation would include full reimbursement for Company assets, if acquired,
and full reimbursement of any other costs associated with the loss of customers
in Rockingham, to assure that our remaining customers do not subsidize a
Rockingham municipal 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 to residential and farm customers and the Department could sell only
power that it had purchased from the Niagara and St. Lawrence projects operated
by the New York Power Authority.
Under the 1987 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. Since 1987, 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.
CONSTRUCTION AND CAPITAL REQUIREMENTS
Our capital expenditures for 1999 through 2001 and projected for 2002 are
set forth in Item 7. MD and A - Liquidity and Capital Resources-Construction.
Construction projections are subject to continuing review and may be revised
from time-to-time in accordance with changes in the Company's financial
condition, load forecasts, the availability and cost of labor and materials,
licensing and other regulatory requirements, changing environmental standards
and other relevant factors.
For the period 1999-2001, internally generated funds, after payment of
dividends, provided approximately 82 percent of total capital requirements for
construction, sinking fund obligations and other requirements. Internally
generated funds provided 100 percent of such requirements for 2001. We
anticipate that for 2002, 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.
POWER RESOURCES
On February 11, 1999, the Company entered into a contract with Morgan
Stanley Capital Group, Inc. (MS). In January 2001, the MS contract was modified
and extended to December 31, 2003. The contract provides us a means of managing
price risks associated with changing fossil fuel prices. For additional
information on the MS contract, see Note K of Notes.
The Company generated, purchased or transmitted 2,393,194 MWh of energy for
retail and requirements wholesale customers for the twelve months ended December
31, 2001. The corresponding maximum one-hour integrated demand during that
period was 341.2 MW on August 9, 2001. This compares to the previous all-time
peak of 323.5 MW on January 17, 2000. 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.
Net Electricity Generated and Purchased and Capacity at Peak
Generated and Purchased Capacity
During year At time of
Ended 12/31/2001 of annual peak
MWH percent KW percent
---------------- -------- -------------- --------
Wholly-owned plants:
Hydro . . . . . . . . . . . . . . 59,050 2.4% 32,410 8.4%
Diesel and Gas Turbine. . . . . . 18,291 0.8% 54,578 14.1%
Wind. . . . . . . . . . . . . . . 12,135 0.5% 480 0.1%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . . 6,960 0.3% 7,013 1.8%
Stony Brook I . . . . . . . . . . 49,822 2.1% 24,561 6.3%
McNeil. . . . . . . . . . . . . . 21,133 0.9% 6,443 1.7%
Owned in association with Others:
Vermont Yankee Nuclear. . . . . . 736,420 30.8% 89,370 23.1%
Long Term Purchases:
Hydro-Quebec. . . . . . . . . . . 793,800 33.2% 114,200 29.5%
Stony Brook I . . . . . . . . . . 22,831 1.0% 12,060 3.1%
Other:
NYPA. . . . . . . . . . . . . . . 1,609 0.1% 300 0.1%
Small Power Producers . . . . . . 98,296 4.0% 20,388 5.3%
Short-term purchases. . . . . . . 572,847 23.9% 25,700 6.6%
---------------- -------- -------------- --------
Total . . . . . . . . . . . . . . 2,393,194 387,503
Less system sales energy. . . . . - -
---------------- --------------
Net Own Load. . . . . . . . . . . 2,393,194 100.00% 387,503 100.00%
================ ======== ============== ========
Vermont Yankee.
On August 15, 2001, VY agreed to sell its nuclear power plant to Entergy
Corporation for approximately $180 million. The FERC approved the Entergy
purchase on January 30, 2002. The sale is subject to approval of the VPSB, the
U.S. Nuclear Regulatory Commission and other regulatory bodies. A related
agreement calls for Entergy to provide the current output level of the plant to
VY's present sponsors, including GMP, at average annual prices ranging from $39
to $45 per megawatt hour through 2012, subject to a "low market adjuster"
effective November, 2005, that protects the Company and other sponsors in the
event that market prices for power drop significantly. No additional
decommission liability funding or any other financing by VY is anticipated to
complete the transaction. The sale, if completed, will lower projected costs
over the remaining ten-year license period for VY. The Company would continue
to own its equity interest in VY, whose primary role would consist of
administering the power supply contracts between Entergy and VY's present
sponsors. On March 4, 2002, the Department announced its endorsement of the
proposed sale of the Vermont Yankee nuclear plant to Entergy Corporation. A
Memorandum of Understanding was filed on March 4, 2002 with the VPSB by Entergy,
Vermont Yankee, certain owners of Vermont Yankee, and the Department.
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 Annual Performance Review and Inspection Plan
assessment for Vermont Yankee, which showed all inspection findings being
classified as having a very low safety significance, are for the period April 1,
2000 to March 31, 2001.
During periods when Vermont Yankee power is unavailable, we occasionally
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 2002 refueling outage is tentatively scheduled
to begin October 2002, 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 through 2000, and 4.25%
thereafter, is approximately $471 million, of which $297 million has been
funded. At December 31, 2001, our portion of the net non-funded liability was
$31 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, 2001, we used 736,420 MWh of Vermont
Yankee energy representing 30.8% of the net electricity generated and purchased
("net power supply") by the Company. The average cost of Vermont Yankee
electricity in 2001 was $0.043 per KWh. Vermont Yankee's annual capacity factor
for 2001 was 91.2% compared with 99.2% for 2000, 90.9% in 1999, and 73.6% in
1998. The 2001 capacity factor is the best ever for Vermont Yankee in a year
that included a refueling outage.
See Note B of Notes for additional information.
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, 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, 2001, the present
value of the Company's obligation was approximately $5,959,000. The Company's
projected future minimum payments under the Phase II support agreements are
approximately $426,000 for each of the years 2002-2006 and an aggregate of
$3,831,000 for the years 2007-2015.
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, 2001, the capital structure of such corporations was
approximately 42% common equity and 58% long-term debt. See Notes B and J of
Notes.
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 Expenses.
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 ("9601"), 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
2001 resulted in an increase of approximately $7.6 million of power supply
expenses to meet contractual obligations under the Company's December 1997
sell-back arrangement with Hydro-Quebec. See Item 7. MD and A - Power Supply
Expenses, and Note K of Notes.
During 2001, we used 434,012 MWh under Schedule B, 297,543 MWh under
Schedule C3, and 62,245 MWh under the Hydro-Quebec arrangements representing
33.2% of our net power supply. The average cost of Hydro-Quebec electricity in
2001 was approximately $0.063 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 2001, we used 72,653 MWh from this plant representing 3.1% of our
net power supply at an average cost of $0.068 per KWh. See Note I and K of
Notes.
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 2001, we used 6,960 MWh from this unit representing 0.3% of our net
power supply at an average cost of $0.064 per kWh, based only on operation,
maintenance, and fuel costs incurred during 2001. See Note I of Notes.
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 2001, we used 21,133 MWh from this unit representing 0.9% of our net
power supply at an average cost of $0.051 per kWh, based only on operation,
maintenance, and fuel costs incurred during 2001. See Note I of Notes.
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 ratemaking purposes.
Currently, the State purchasing agent, Vermont Electric Power Producers,
Inc. ("VEPPI"), is authorized to seek 150 MW of power from qualifying facilities
under PURPA, of which our average pro rata share in 2001 was approximately 33.5%
or 50.2 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 2001, through our direct contracts and VEPPI, we purchased 98,296 MWh of
qualifying facilities production representing 4.0% of our net power supply at an
average cost of $0.117 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 2001, we purchased 334,452 MWh pursuant to short term opportunity
purchases, representing 23.9% of our net power supply at an average cost of
$0.052 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 2001, Company owned hydroelectric plants provided 59,050 MWh of energy,
representing 2.4% of our net power supply at an average cost of $0.053 per kWh
based on total embedded costs and maintenance. Low river levels due to drought
and drainage of the Waterbury site reservoir in 2001 limited hydropower
production. 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.
Fuel. During 2001, our retail and requirements wholesale sales were
provided by the following fuel sources:
* 37.4% from hydroelectric sources (2.4% Company-owned, 0.1% NYPA, 33.2%
Hydro-Quebec and 1.7% small power producers);
* 30.8% from a nuclear generating source (the Vermont Yankee nuclear plant
described below);
* 3.2% from wood;
* 2.0% from oil;
* 2.2% from natural gas;
* 0.5% from wind power producers; and
* 23.9% purchased on a short-term basis from other utilities through the
ISO.
Vermont Yankee has several requirement-based contracts for the four
components (uranium, conversion, enrichment and fabrication) used to produce
nuclear fuel. These contracts are utilized only if the need or requirement for
fuel arises. Under these contracts, any disruption of operating activity would
allow VY to cancel or postpone deliveries until actually required. The
contracts extend through various time periods and contain clauses to allow VY
the option to extend the agreements. Negotiation of new contracts and
renegotiations of existing contracts routinely occur, often focusing on one of
the four components at a time. The 2001 reload cost approximately $20.2
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 2001 or
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 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 2001 Vermont Yankee accumulated approximately
$115.0 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 2001, and, while no
assurance can be given, we do not anticipate any such difficulty during 2002.
None of the utilities from which we expect to purchase oil- or gas-fired
capacity in 2002 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 254,510 tons of
wood chips and mill residue, 461,490 gallons of fuel oil, and 116,586 million
cubic feet of natural gas in 2001. The McNeil plant, assuming any needed
regulatory approvals are obtained, is forecasting year 2002 consumption of wood
chips to be 300,000 tons, fuel oil of 100,000 gallons and natural gas
consumption of 36,000 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 2001, the plant provided 12,135 MWh, representing 0.5% of the Company's
net power supply at an average cost of $0.07 per kWh.
SEGMENT INFORMATION
Financial information about the Company's primary industry segment, the
electric utility, is presented in Item 6, Selected Financial Data, and in the
Annual Report and Notes included herein.
The Company has partially sold or disposed of most of the operations and
assets of Northern Water Resources, Inc. ("NWR"), formerly known as Mountain
Energy, Inc., classified as discontinued operations in 1999. Industry segment
information relating to the Company's discontinued operations is presented in
Note L of the Notes.
SEASONAL NATURE OF BUSINESS
Winter recreational activities, longer hours of darkness and heating loads
from cold weather usually cause our average peak electric sales to occur in
December, January or February. Summer air conditioning loads have increased in
recent years as a result of steady economic growth in our service territory.
Our heaviest load in 2001, 341.2 MW, occurred on August 9, 2001.
Under NEPOOL market rules implemented in May 1999, the cost basis that had
supported the Company's previous seasonally differentiated rate design was
eliminated, making a seasonal rate structure no longer appropriate. The
elimination of the seasonal rate structure in all classes of service effective
April 2001 was approved by the VPSB in January 2001.
EMPLOYEES
As of December 31, 2001, the Company had 193 employees, exclusive of
temporary employees. The Company considers its relations with employees to be
excellent.
ENERGY EFFICIENCY
In 2001, GMP did not offer its own energy efficiency programs. Energy
efficiency services were provided to GMP's customers by a statewide Energy
Efficiency Utility ("EEU") known as "Efficiency Vermont", created by the VPSB in
1999. The EEU is funded by a separate energy efficiency charge that appears as
a line item on each customer bill. In 2001, the charge was 1.798 percent of
each customer's total electric bill. Some charges, such as late fees and
outdoor lighting, are excluded. The funds we collect are remitted to a fiscal
agent representing the State of Vermont. Since 1992, the Company's efficiency
programs have achieved a cumulative annual saving of 89,000 megawatthours,
saving approximately $7.9 million per year for our customers. In 2001, the
Company spent approximately $80,000 on management of energy efficiency programs
existing prior to the creation of the EEU.
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 1,882 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, 2001, approximately 1,495 of the Company's largest customers,
comprising 53% 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 eliminated seasonal rate differentials
effective April 2001.
DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS
In 2001, 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.
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 Barge Canal site and other
environmental matters, see Item 7. MD and A- Environmental Matters, and Note I
of Notes.
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. During 1999, the Company
discontinued operations of Northern Water Resources, Inc.("NWR"), a subsidiary
of the Company that invests in wastewater, energy efficiency and generation
businesses. The loss in 2000 reflects the sale of most of NWR's remaining energy
assets and the current estimated costs of winding down NWR's wastewater
businesses. For information regarding our remaining unregulated businesses, see
Item 7a. MD and A - Unregulated Businesses.
EXECUTIVE OFFICERS
The names, ages, and positions of the Company's Executive Officers as of March
15, 2002 are:
Christopher L. Dutton 53
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, CPA 45
Treasurer since February 2002. Controller since October 1996. Manager of
General Accounting from 1990 to 1996.
Walter S. Oakes 55
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 41
Senior Vice President-Chief Operating Officer since April 2001. 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,
Inc., 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 59
Senior Vice President-Corporate and Legal Affairs 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.
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.
Additional information regarding compensation, beneficial ownership of the
Company's stock, members of the board of directors, and other information is
presented in the Company's Proxy Statement to Shareholders dated March 29, 2002,
and is hereby incorporated by reference.
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, 2001, approximately 2 miles of 115 kV
transmission lines, 6 miles of 69 kV transmission lines, 3 miles of 44 kV and
185 miles of 34.5 kV transmission lines. Our distribution system includes
approximately 2,300 miles of overhead lines of 2.4 kV to 34.5 kV, and
approximately 460 miles of underground cable of 2.4 kV to 34.5 kV. At such
date, we owned approximately 159,000 kVa of substation transformer capacity in
transmission substations, 570,00 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. See Note M, Subsequent Events, for information on recent events
concerning First Mortgage Bonds.
GENERATING FACILITIES OWNED
The following table gives information with respect to generating
facilities presently available in which the Company has an ownership interest.
See also Item 1. Business - Power Resources.
Winter
Capability
Location Name Fuel MW
--------------- --------------- -------- -----
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 (1)
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) Reservoir has been drained, dam awaiting repairs by the State of Vermont.
(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.
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 its two service centers.
ITEM 3. LEGAL PROCEEDINGS
The Company is not involved in any material litigation at the present time.
See the discussion under Item 7. MD and A - Environmental Matters, Rates, and
Note I of Notes.
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 2000 and 2001:
HIGH LOW
-------- --------
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
2001
First Quarter. $ 19.50 $ 11.06
Second Quarter 16.65 14.88
Third Quarter. 17.74 15.56
Fourth Quarter 18.85 15.90
The number of common stockholders of record as of March 15, 2001 was 5,673.
Quarterly cash dividends were paid as follows during the past two years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- --------
2000 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1375
2001 $ 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. In addition, the
Settlement Order limits the dividend rate at its current level until short-term
credit facilities are replaced with long-term debt or equity.
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, the
Board of Directors would consider whether the current dividend level is
appropriate or if the dividend should be reduced or eliminated. See Item 7. MD
and A - Liquidity and Capital Resources-Dividend Policy, Future Outlook,
Competition and Restructuring, and Note C of Notes for a discussion of dividend
restrictions.
ITEM 6. SELECTED FINANCIAL DATA
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,
- --------------------------------------------------------------
2001 2000 1999 1998 1997
--------- --------- --------- --------- ---------
In thousands, except per share data
Operating Revenues . . . . . . . . . . . . . . . . . . . . . . . . . $283,464 $277,326 $251,048 $184,304 $179,323
Operating Expenses . . . . . . . . . . . . . . . . . . . . . . . . . 267,005 272,066 243,102 178,832 163,808
--------- --------- --------- --------- ---------
Operating Income . . . . . . . . . . . . . . . . . . . . . . . 16,459 5,260 7,946 5,472 15,515
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity . . . . . . . . . . . . . . . . . . . . . . . . 210 284 134 104 357
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,163 2,422 3,319 1,509 1,074
--------- --------- --------- --------- ---------
Total other income . . . . . . . . . . . . . . . . . . . . . . 2,373 2,706 3,453 1,613 1,431
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed . . . . . . . . . . . . . . . . . . . . . . . (188) (228) (91) (131) (315)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,227 7,485 7,274 8,007 7,965
--------- --------- --------- --------- ---------
Total interest charges . . . . . . . . . . . . . . . . . . 7,039 7,257 7,183 7,876 7,650
--------- --------- --------- --------- ---------
Net Income (Loss) from continuing operations before. . . . . . . . . 11,793 709 4,216 (791) 9,296
preferred dividends
Net Income (Loss) from discontinued operations, including
provisions for loss on disposal . . . . . . . . . . . . . . . . . (182) (6,549) (7,279) (2,086) 142
Dividends on Preferred Stock . . . . . . . . . . . . . . . . . . . . 933 1,014 1,155 1,296 1,433
--------- --------- --------- --------- ---------
Net Income (Loss)Applicable
to Common Stock. . . . . . . . . . . . . . . . . . . . . . . . $ 10,678 $ (6,854) $ (4,218) $ (4,173) $ 8,005
========= ========= ========= ========= =========
Common Stock Data
Basic earnings per share-continuing operations . . . . . . . . $ 1.93 $ (0.06) $ 0.57 $ (0.40) $ 1.54
Basic earnings per share-discontinued operations . . . . . . . (0.03) (1.19) (1.36) (0.40) 0.03
--------- --------- --------- --------- ---------
Basic earnings per share . . . . . . . . . . . . . . . . . . . $ 1.90 $ (1.25) $ (0.79) $ (0.80) $ 1.57
========= ========= ========= ========= =========
Diluted earnings (loss) per share from discontinued operations $ 1.88 $ (0.06) $ 0.57 $ (0.40) $ 1.54
Diluted earnings (loss) per share from continuing operations . (0.03) (1.19) (1.36) (0.40) 0.03
--------- --------- --------- --------- ---------
Diluted earnings (loss) per share. . . . . . . . . . . . . . . $ 1.85 $ (1.25) $ (0.79) $ (0.80) $ 1.57
========= ========= ========= ========= =========
Cash dividends declared per share. . . . . . . . . . . . . . . . . . $ 0.55 $ 0.55 $ 0.55 $ 0.96 $ 1.61
Weighted average shares outstanding-basic. . . . . . . . . . . 5,630 5,491 5,361 5,243 5,112
Weighted average share equivalents outstanding-diluted . . . . 5,789 5,491 5,361 5,243 5,112
FINANCIAL CONDITION AS OF DECEMBER 31
- ------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------
In thousands
ASSETS
Utility Plant, Net. . . . . . . . . . . $196,858 $194,672 $192,896 $195,556 $196,720
Other Investments . . . . . . . . . . . 20,945 20,730 20,665 20,678 21,997
Current Assets. . . . . . . . . . . . . 36,183 53,652 33,238 35,700 29,125
Deferred Charges. . . . . . . . . . . . 75,073 46,036 41,853 35,576 35,831
Non-Utility Assets. . . . . . . . . . . 1,075 1,518 11,099 27,314 42,060
-------- -------- -------- -------- --------
Total Assets. . . . . . . . . . . . . . $330,134 $316,608 $299,751 $314,824 $325,733
======== ======== ======== ======== ========
CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . . $101,277 $ 92,044 $100,645 $106,755 $114,377
Redeemable Cumulative Preferred Stock . 12,560 12,795 14,435 16,085 17,735
Long-Term Debt, Less Current Maturities 74,400 72,100 81,800 88,500 93,200
Capital Lease Obligation. . . . . . . . 5,959 6,449 7,038 7,696 8,342
Current Liabilities . . . . . . . . . . 38,841 68,109 36,708 28,825 25,286
Deferred Credits and Other. . . . . . . 95,396 61,794 59,125 59,889 53,723
Non-Utility Liabilities . . . . . . . . 1,701 3,317 - 7,074 13,070
-------- -------- -------- -------- --------
Total Capitalization and Liabilities. . $330,134 $316,608 $299,751 $314,824 $325,733
======== ======== ======== ======== ========
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.
Our critical accounting policies are discussed in Item 7a, "Quantitative
And Qualitative Disclosures About Market Risk, And Other Factors", and in Item
8, Note 1, "Significant Accounting Policies". Management believes the most
critical accounting policies include the regulatory accounting framework within
which we operate and the manner in which we account for certain power supply
arrangements that qualify as derivatives. These accounting policies, among
others, affect the Company's more significant judgments and estimates used in
the preparation of its consolidated financial statements.
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 the
captions "Power Contract Commitments", "Future Outlook", "Transmission
Expenses", "Environmental Matters", "Rates" and "Liquidity and Capital
Resources", in this Management Discussion and Analysis 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;
* changes in technology;
* 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
The Company reported consolidated earnings of $1.85 per share of common
stock, diluted, in 2001 compared to a loss of $1.25 per share in 2000 and a loss
of $0.79 per share in 1999. The 2001 earnings represent a consolidated return on
average common equity of 11.02 percent, and a return on regulated operations of
11.25 percent. The consolidated return on average common equity was negative
7.1 percent in 2000 and negative 4.0 percent in 1999. Income from continuing
operations was $1.88 per share, diluted, in 2001, compared with a loss of $0.06
per share in 2000 and earnings of $0.57 per share in 1999. Certain subsidiary
operations, classified as discontinued in 1999, lost $0.03 per share in 2001,
compared with a loss of $1.19 per share in 2000 and a loss of $1.36 per share in
1999.
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 granted the Company
an immediate 3.42 percent rate increase, and allowed full recovery of power
supply costs under the Hydro-Quebec Vermont Joint Owners ("VJO") contract. The
Settlement Order paved the way for restoration of the Company's first mortgage
bond credit rating to investment grade status (See "Rates-Retail Rate Cases" and
"Liquidity and Capital Resources" in this section) and along with lower power
supply costs, enabled the Company to earn its allowed rate of return of 11.25
percent on utility operations during 2001.
The improvement in earnings from continuing operations in 2001 compared
with the prior year resulted from several factors, primarily:
* power supply costs were $10.5 million lower than during 2000, principally
due to decreased costs associated with the management of the Company's long-term
power supply sale commitments to Hydro Quebec, and a decrease in lower margin
wholesale sales of electricity;
* the 3.42 percent retail rate increase under the Settlement Order resulted
in an increase of $9.1 million in retail operating revenues; and
* the write-off in 2000 of $3.2 million or $0.35 per share in regulatory
litigation costs.
The consolidated loss in 2000 was greater than the prior year consolidated
loss as a result of the VPSB Settlement Order that provided for the write-off of
$3.2 million or $0.35 per share in regulatory litigation costs and higher power
supply costs that were not recovered in rates. Power supply expense increased
$28.3 million in 2000, outpacing revenue growth of $26.3 million and reductions
in depreciation and amortization expense of $0.9 million.
The Company's discontinued operations lost $0.03 per share in 2001,
compared with a loss of $1.19 per share in 2000, and a loss of $1.36 per share
in 1999. During 1999, the Company discontinued operations of Northern Water
Resources, Inc.("NWR"), formerly known as Mountain Energy, Inc., a subsidiary of
the Company that invested in wastewater, energy efficiency and generation
businesses. The loss in 2000 reflects the sale of most of NWR's remaining
energy assets and the estimated costs of winding down NWR's wastewater
businesses.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, AND OTHER
RISK FACTORS- The primary concern affecting future operating results is the
volatility of the wholesale electricity market. 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 purchases and sales. Changes in the market value of derivatives
have a high correlation to the price changes of the hedged commodities.
The Company has a contract with Morgan Stanley Capital Group, Inc. ("MS"),
which is used to hedge against increases in fossil fuel prices. MS purchases
the majority of the Company's power supply resources at index (fossil fuel
resources) or specified (i.e., contracted resources) prices and then sells to us
at a fixed rate to serve pre-established load requirements. This contract
allows management to fix the cost of much of its power supply requirements,
subject to power resource availability and other risks. The MS contract is a
derivative under Statement of Financial Accounting Standards No. 133 ("SFAS
133") and is effective through December 31, 2003. Management's estimate of the
fair value of the future net cost of this arrangement at December 31, 2001 is
approximately $11.6 million.
We also sometimes use future contracts to hedge forecasted wholesale sales
of electric power, including material sales commitments as discussed in Note K.
We currently have an arrangement with Hydro-Quebec that grants them an option to
call power at prices that are expected to be below current and estimated future
market rates. This arrangement is a derivative and is effective through 2015.
Management's estimate of the fair value of the future net cost for this
arrangement at December 31, 2001 is approximately $25.7 million.
A sensitivity analysis has been prepared to estimate the exposure to the market
price risk of our electricity commodity positions, using the Black-Scholes
model, over the next 13 years. Our daily net commodity position consists of
purchased electric capacity. Assumptions used within the model include a
ten-year government bond risk-free interest rate of 5.02 percent, volatility
equivalent to the peer weighted average from NEPOOL which varies from 36 percent
in the first year to 18 percent in year 13, locked in forward commitment prices
for 2002 and 2003, and an average of approximately 71,500 MWh per year with a
forward market price of $54.29 per MWh for periods beyond 2003. Actual results
may differ materially from the table. Under an accounting order issued by the
VPSB, changes in the fair value of derivatives are not recognized in earnings
until the derivative positions are settled. The table below presents market
risk estimated as the potential loss in fair value resulting from a hypothetical
ten percent adverse change in prices which for the Company's derivatives
discussed above totals approximately $1.8 million.
Commodity Price Risk At December 31, 2001
Fair Value Market Risk
--------------- ------------
(in thousands)
Net short position $ 37,313 $ 1,789
The major risk factors for the Company potentially arising from electric
industry restructuring, if adopted in Vermont, 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 $167 million and $204
million over the life of the contracts. 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 currently complies with the provisions of SFAS 71. If the
Company had determined that it no longer met the criteria for following SFAS 71,
at December 31, 2001 the accounting impact would have been an extraordinary,
non-cash charge to operations of $74.2 million. Factors that could give rise to
the discontinuance of SFAS 71 include:
* deregulation;
* a change in the regulators' 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.
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. However, we currently believe that the continued application of
SFAS 71 is appropriate at this time.
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.
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 NWR, and report its results as loss from
operations of a discontinued segment. NWR, which invested in energy generation,
energy efficiency and wastewater treatment projects, lost approximately $0.2
million in 2001, compared with a loss of $6.5 million in 2000, and a loss of
$7.3 million in 1999. The 2001 loss resulted primarily from provisions to
recognize adjustments to liability estimates under warrantees for past equipment
sales.
Risk factors associated with the discontinuation of NWR 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 NWR, have commenced or threatened litigation against Micronair.
The ultimate loss remains subject to the disposition of remaining NWR assets and
liabilities, and could exceed the amounts recorded.
The Company's unregulated rental water heater business earned $0.3
million in 2001, essentially unchanged from the prior year.
RESULTS OF OPERATIONS
OPERATING REVENUES AND MWH SALES-Operating revenues and megawatthour ("MWh")
sales for the years ended 2001, 2000 and 1999 consisted of:
Years ended December 31,
2001 2000 1999
-------------------------- ---------- ----------
(dollars in thousands)
Operating Revenues
Retail . . . . . . . $ 195,093 $ 185,944 $ 179,997
Sales for Resale . . 83,804 88,333 68,305
Other. . . . . . . . 4,567 3,049 2,746
-------------------------- ---------- ----------
Total Operating Revenues $ 283,464 $ 277,326 $ 251,048
========================== ========== ==========
MWH Sales-Retail . . . . 1,948,131 1,947,857 1,900,188
MWH Sales for Resale . . 2,368,887 2,575,657 2,172,849
-------------------------- ---------- ----------
Total MWH Sales. . . . . 4,317,018 4,523,514 4,073,037
========================== ========== ==========
Average Number of Customers
Years ended December 31,
2001 2000 1999
------------------------ ------ ------
Residential . . . . . . . 73,270 72,424 71,515
Commercial and Industrial 13,006 12,769 12,461
Other . . . . . . . . . . 65 65 66
------------------------ ------ ------
Total Number of Customers. . 86,341 85,258 84,042
======================== ====== ======
Differences in operating revenues were due to changes in the following:
Change in Operating Revenues 2000 to 1999 to
2001 2000
--------------- -------
(In thousands)
Retail Rates . . . . . . . . . $ 9,122 $ 4,551
Retail Sales Volume. . . . . . 27 1,396
Resales and Other Revenues . . (3,011) 20,331
--------------- -------
Increase in Operating Revenues $ 6,138 $26,278
=============== =======
In 2001, total electricity sales decreased 4.6 percent compared with 2000 due
principally to reduced sales for resale executed pursuant to the MS agreement,
described in more detail below under the headings "Power Supply Expenses" and
"Power Contract Commitments". Total operating revenues increased $6.1 million
or 2.2 percent in 2001 compared with 2000 primarily due to increases in retail
and other operating revenues, partially offset by a decrease in lower margin
wholesale sales. Retail operating revenues increased $9.1 million or 4.9
percent in 2001 compared with 2000 due to a 3.42 percent retail rate increase
that went into effect January 2001 and an additional increase in revenues from
an industrial customer pursuant to revisions in a special contract with that
customer approved in the Settlement Order.
In 2000 total electricity sales increased 11.1 percent compared with 1999
due principally to sales for resale executed pursuant to the MS agreement,
described in more detail below under the headings "Power Supply Expenses" and
"Power Contract Commitments". Total operating revenues increased $26.3 million
or 10.5 percent primarily for the same reason. Total retail revenues increased
$5.9 million or 3.3 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.
International Business Machines Corporation ("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 approximately 26.6, 26.6, and 25.9 percent of the Company's retail
MWh sales in 2001, 2000, and 1999, respectively, and 19.2, 16.5, and 16.2
percent of the Company's retail operating revenues in 2001, 2000, and 1999,
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- Prior to 2001, our inability to recover our power supply
costs had been a primary reason for the poor performance of the Company's common
stock price during 1999 and 2000. The Settlement Order removed this obstacle by
allowing the Company rate recovery of its estimated power supply costs for 2001.
Furthermore, the Settlement Order allowed the Company to defer approximately
$8.5 million in rate levelization revenues for recognition in 2002 and 2003, if
necessary, to achieve its allowed rate of return. The deferred recognition of
rate levelization revenues provides us an opportunity to recover our power
supply costs in 2002 without further rate relief (See "Power Contract
Commitments", and "Rates-Retail Rate Cases" in this section).
Power supply expenses constituted 75.3, 77.7, and 75.4 percent of total
operating expenses for the years 2001, 2000, and 1999, respectively. Power
supply expenses decreased by $10.5 million or 5.0 percent in 2001 and increased
$28.3 million or 15.4 percent in 2000. The decrease in power supply expenses in
2001 compared with 2000 resulted from the following:
* a $7.7 million decrease in energy costs arising from a power supply
arrangement with Hydro-Quebec, discussed under the caption "Power Contract
Commitments", whereby Hydro-Quebec has an option to purchase energy at prices
that were below market replacement costs;
* a $5.9 million decrease in Vermont Yankee costs due primarily to the
timing of scheduled outages at the plant, where the outage costs including the
costs of replacement power are deferred and amortized over the subsequent
refueling cycle;
* a $4.5 million decrease from power purchased for resale, primarily under a
power supply agreement discussed under the caption "Power Contract Commitments"
below, whereby we buy power from MS that is sufficient to serve pre-established
load requirements at a pre-defined price; and
* a $3.0 million decrease in Company-owned generation costs reflecting a
reduction in generation used to maintain system reliability as compared to the
prior year when the unavailability of certain transmission equipment required
these units to run more frequently.
These amounts were partially offset by the disallowance in rates of 2000
Hydro Quebec power contract costs that required $7.5 million of those costs to
be charged in 1999 and amortized as a reduction of power supply expenses during
2000, $2.1 million in higher energy prices in 2001 under our MS agreement, and
higher capacity costs in 2001 of approximately $1.0 million.
Power supply expenses increased by $28.3 million or 15.4 percent from 1999
to 2000. 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
2001 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 expenses of $7.5 million for 2000 that had been recorded
in 1999. The power supply costs of Company-owned generation increased 39.3
percent or $2.2 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.
The Independent System Operator of New England ("ISO") was created to
manage the operations of the New England Power Pool ("NEPOOL") effective May 1,
1999. The ISO works as a clearinghouse for purchasers and sellers of electricity
in the deregulated wholesale energy 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 in 1999, which caused much greater volatility in spot prices for
electricity. The cost of securing future power supplies had also risen
substantially in tandem with higher summer power supply costs. The Company
cannot predict the extent to which future prices will 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 have been fulfilled. The PPSA
was filed with the Federal Energy Regulatory Commission ("FERC") and the VPSB
was notified as well. 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 anticipate that
arrangements we make to manage power supply risks will be on average more costly
than the expected cost of fuel during the periods being hedged because these
arrangements would typically incorporate a risk premium.
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 was 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 2001 to 2015 period, if documented drought conditions exist in
Qu bec.
Hydro-Quebec also has the right to reduce the load factor from 75 percent
to 65 percent a total three times over the life of the 1987 contract. The
Company can delay such reduction by one year under the same contract. During
2001, Hydro-Quebec exercised the first of these options for 2002 and the Company
delayed the effective date of this exercise until 2003. The Company estimates
that the net cost of Hydro-Quebec's exercise of its option will increase power
supply expense during 2003 by approximately $0.4 million. 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 were
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 were 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 varied based upon
conditions in effect when the purchases were made. 9601 also provided for
minimum payments by the Company to Hydro-Quebec for periods in which power was
not purchased under the arrangement. 9601 allowed 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. We estimate that 9601 has provided a benefit of approximately $3.0
million on a net present value basis over the past six years.
Under a separate arrangement executed on December 5, 1997 ("9701"),
Hydro-Quebec paid $8.0 million to the Company in 1997. In return for this
payment, we provided Hydro-Quebec options for the purchase of power. Commencing
April 1, 1998 and effective through the term of the 1987 Contract, which ends in
2015, Hydro-Quebec may purchase up to 52,500 MWh ("option A") on an annual
basis, at the 1987 Contract energy prices, which are substantially below current
market prices. The cumulative amount of energy that may be purchased under
option A shall not exceed 950,000 MWh.
Over the same period, Hydro-Quebec may exercise an option to