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, 2002
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 _____
-
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_
-
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes _X_ No
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THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE REGISTRANT AS OF MARCH 12, 2003, WAS APPROXIMATELY $100,939,195 BASED ON THE
CLOSING PRICE OF $20.35 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 12, 2003, WAS
4,960,157
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders to be held on May 15, 2003, 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, 2002
Table of contents Page
Part I
Item 1, Business 3
Item 2, Properties 17
Item 3, Legal Proceedings 18
Item 4, Submission of Matters To a Vote of 18
Security Holders
Part II
Item 5, Market for Registrant's Common
Equity and Related Shareholder Matters 19
Item 6, Selected Financial Data 20
Item 7, Management's Discussion and Analysis 21
Of Financial Condition and Results
Of Operations
Item 8, Index to Consolidated Financial Statements
and Notes 42
Item 9, Changes In and Disagreements with Accountants 79
On Accounting and Financial Disclosure
Items 10 through 13, Certain Officer information 79
Item 14, Controls and Procedures 79
Item 15, Exhibits, Financial Statement Schedules, 79
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 2002 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 88,000 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, 2002 were as
follows:
* 26.8 percent from residential customers;
* 28.4 percent from small commercial and industrial customers;
* 17.7 percent from large commercial and industrial customers;
* 25.8 percent from sales to other utilities; and
* 1.3 percent from other sources.
See the Annual Report and MD and A for further information about revenues.
During 2002, our energy resources for retail and wholesale sales of
electricity, excluding sales made pursuant to the contract with Morgan Stanley
Capital Group, Inc. ("MS") discussed under MD and A-Power Contract Commitments,
were obtained as follows:
* 40.8 percent from hydroelectric sources (32.8 percent Hydro Quebec, 5.0
percent Company-owned, 2.9 percent small power producers, and 0.1 percent New
York Power Authority ("NYPA"));
* 34.9 percent from a nuclear generating source (the Entergy nuclear plant
described below);
* 3.6 percent from wood;
* 2.5 percent from natural gas;
* 1.5 percent from oil; and
* 0.5 percent from wind.
The remaining 16.2 percent was purchased on a short-term basis from other
utilities through the Independent System Operator of New England ("ISO" or "ISO
New England"), formerly the New England Power Pool ("NEPOOL").
In 2002, we purchased 90.7 percent 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, but excluding purchases for resale under
the MS contract. 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) nuclear generating plant owned
and operated by Entergy Vermont Yankee Nuclear Corporation ("Entergy"). We have
an 18.99 percent equity interest in Vermont Yankee, which has a long-term power
supply contract with Entergy, that entitles us to 20 percent of plant output
through 2012 For further 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.
Our 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 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 Entergy nuclear 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,
2,002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
Total capability (MW) . . . . . . . . . . . . . . 406.9 408.0 411.1 393.2 396.9
Net system peak . . . . . . . . . . . . . . . . . 342.0 341.2 323.5 317.9 312.5
----------- ----------- ----------- ----------- -----------
Reserve (MW). . . . . . . . . . . . . . . . . . . 64.9 66.8 87.6 75.3 84.4
=========== =========== =========== =========== ===========
Reserve % of peak . . . . . . . . . . . . . . . . 19.0% 19.6% 27.1% 23.7% 27.0%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . . 901,998 951,146 1,053,223 1,095,738 972,723
Wind. . . . . . . . . . . . . . . . . . . . . . . 11,458 12,135 12,246 7,956 -
Nuclear . . . . . . . . . . . . . . . . . . . . . 771,781 736,420 803,303 731,431 607,708
Conventional steam. . . . . . . . . . . . . . . . 2,431,115 2,670,249 2,704,427 2,328,267 750,602
Internal combustion . . . . . . . . . . . . . . . 4,090 18,291 35,699 12,312 40,148
Combined cycle. . . . . . . . . . . . . . . . . . 81,362 72,653 73,433 99,962 118,322
----------- ----------- ----------- ----------- -----------
Total production. . . . . . . 4,201,804 4,460,894 4,682,331 4,275,666 2,489,503
Less non-firm sales to other utilities. . . . . . 2,104,172 2,365,809 2,573,576 2,152,781 499,409
----------- ----------- ----------- ----------- -----------
Production for firm sales . . . . . . . . . . . . 2,097,632 2,095,085 2,108,755 2,122,885 1,990,094
Less firm sales and lease transmissions. . . . . 1,951,959 1,956,232 1,954,898 1,920,257 1,883,959
----------- ----------- ----------- ----------- -----------
Losses and company use (MWH). . . . . . . . . . . 145,673 138,853 153,857 202,628 106,134
=========== =========== =========== =========== ===========
Losses as a % of total production . . . . . . . . 3.47% 3.11% 3.29% 4.74% 4.26%
System load factor (***). . . . . . . . . . . . . 70.0% 70.1% 74.2% 76.2% 72.7%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . . 21.5% 21.3% 22.5% 25.6% 39.1%
Wind. . . . . . . . . . . . . . . . . . . . . . . 0.3% 0.3% 0.3% 0.2% 0.0%
Nuclear . . . . . . . . . . . . . . . . . . . . . 18.3% 16.5% 17.1% 17.1% 24.4%
Conventional steam. . . . . . . . . . . . . . . . 57.9% 59.9% 57.8% 54.5% 30.2%
Internal combustion . . . . . . . . . . . . . . . 0.1% 0.4% 0.8% 0.3% 1.6%
Combined cycle. . . . . . . . . . . . . . . . . . 1.9% 1.6% 1.6% 2.3% 4.8%
----------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0%
=========== =========== =========== =========== ===========
Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . . 553,294 549,151 558,682 544,447 533,904
Commercial & industrial - small . . . . . . . . . 723,642 718,969 704,126 688,493 665,707
Commercial & industrial - large . . . . . . . . . 661,480 683,004 683,296 664,110 636,436
Other . . . . . . . . . . . . . . . . . . . . . . 9,773 2,030 6,713 3,138 3,476
----------- ----------- ----------- ----------- -----------
Total retail sales and lease transmissions. . . . 1,948,189 1,953,154 1,952,817 1,900,188 1,839,522
Sales to Municipals & Cooperatives (Rate W) . . . 3,770 3,078 2,081 20,069 44,437
----------- ----------- ----------- ----------- -----------
Total Requirements Sales. . . . . . . . . . . . . 1,951,959 1,956,232 1,954,898 1,920,257 1,883,959
Other Sales for Resale. . . . . . . . . . . . . . 2,104,172 2,365,809 2,573,576 2,152,781 499,409
----------- ----------- ----------- ----------- -----------
Total sales and lease transmissions(MWH) . . . . 4,056,131 4,322,041 4,528,474 4,073,038 2,383,368
=========== =========== =========== =========== ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . . 73,861 73,249 72,424 71,515 71,301
Commercial and industrial small . . . . . . . . . 13,173 12,984 12,746 12,438 12,170
Commercial and industrial large . . . . . . . . . 21 22 23 23 23
Other . . . . . . . . . . . . . . . . . . . . . . 65 65 65 66 70
----------- ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . . . . . 87,120 86,320 85,258 84,042 83,564
=========== =========== =========== =========== ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . . 12.96 13.33 12.50 12.32 11.56
Commercial & industrial - small . . . . . . . . . 10.35 10.83 10.00 9.88 9.29
Commercial & industrial - large . . . . . . . . . 7.28 7.69 6.51 6.55 6.32
Total retail including lease. . . . . . . . . . . 10.09 10.44 9.52 9.47 8.96
=========== =========== =========== =========== ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . . 7,491 7,497 7,717 7,617 7,488
Revenues including lease revenues . . . . . . . . $ 971 $ 999 $ 965 $ 938 $ 865
(*) 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. Political
or social organizations that represent certain classes of customers, neighbors
of our properties, or other persons or entities may petition the VPSB to be
granted intervener status in such proceedings.
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 percent of our operating revenues for 2002.
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 percent of our operating revenues for 2002.
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 FERC Order 889, we have 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 FERC Order 889. Our 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 hydroelectric projects we own:
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,
we expect the project to be relicensed for a 30 year term and we do 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
RETAIL RATE CASES- 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 our 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.
On January 23, 2001, the VPSB approved our settlement 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, adjusted for inflation; and
* The Company's further investment in non-utility operations is restricted.
The Company earned approximately $4.4 million less than its allowed rate of
return during 2002 before including in earnings deferred revenues in the same
amount. 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.
For further information regarding recent rate developments, see Item 7. MD
and A - Rates, and 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 12.8 percent, 13.5 percent, and 12.4 percent of total
operating revenues, and 17.3 percent, 19.2 percent and 16.5 percent of the
Company's retail operating revenues in 2002, 2001 and 2000, 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 contract, which is discussed in greater detail in Item
7 of MD and A-Power Contract Commitments. No other retail customer accounted
for more than 1.0 percent of our revenue during the past three years.
IBM reduced its Vermont workforce by 1,500 during 2002, to a level of
approximately 7,000 employees. If future significant losses in electricity
sales to IBM were to occur, the Company's earnings could be impacted adversely.
If earnings were materially reduced as a result of lower retail sales, we would
seek a retail rate increase from the VPSB. The Company is not aware of any
plans by IBM to further reduce production at its Vermont facility. We currently
estimate, based on a number of projected variables, the retail rate increase
required from all retail customers by a hypothetical shutdown of the IBM
facility to be in the range of five to ten percent, inclusive of projected
declines in sales to residential and commercial customers. See Item 7. MD and
A-Results of Operations, Operating Revenues and MWh, and Note A of 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 the Bellows Falls hydroelectric 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 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
neither our remaining customers nor our shareholders effectively 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. Alternate
forms of performance-based regulation currently appear as possible intermediate
steps towards deregulation. For further information regarding Competition and
Restructuring, See Item 7. MD and A - Future Outlook.
CONSTRUCTION AND CAPITAL REQUIREMENTS
Our capital expenditures for 2000 through 2002 and projected for 2003 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 2000-2002, internally generated funds, after payment of
dividends, provided approximately 68 percent of our total capital requirements
for construction, sinking fund obligations and other requirements. Internally
generated funds provided 49 percent of such requirements for 2002. We
anticipate that for 2003, internally generated funds will provide approximately
71 percent of our 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 August 2002, the MS contract was
modified and extended to December 31, 2006. 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.
We generated, purchased or transmitted 2,210,721 MWh of energy for retail
and requirements wholesale customers for the twelve months ended December 31,
2002. The corresponding maximum one-hour integrated demand during that period
was 342.0 MW on August 15, 2002. This compares to the previous all-time peak of
341.2 MW on August 9, 2001. 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 12/31/2002 of annual peak
MWH percent KW percent
--------- -------- ------- --------
Wholly-owned plants:
Hydro . . . . . . . . . . . . . 110,797 5.0% 32,870 8.9%
Diesel and Gas Turbine. . . . . 4,090 0.2% 50,623 13.6%
Wind. . . . . . . . . . . . . . 11,458 0.5% 480 0.1%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . 3,687 0.2% 6,968 1.9%
Stony Brook I . . . . . . . . . 55,595 2.5% 27,113 7.3%
McNeil. . . . . . . . . . . . . 19,832 0.9% 6,443 1.7%
Long Term Purchases:
Vermont Yankee Nuclear/Entergy. 771,781 34.9% 100,554 27.1%
Hydro-Quebec. . . . . . . . . . 724,708 32.8% 114,174 30.8%
Stony Brook I . . . . . . . . . 25,767 1.2% 12,382 3.3%
Other:
Small Power Producers . . . . . 123,996 5.6% 19,286 5.2%
NEPOOL and Short-term purchases 359,009 16.2% 400 0.1%
--------- -------- ------- --------
Net Own Load. . . . . . . . . . 2,210,720 100.0% 371,293 100.0%
========= ======== ======= ========
Vermont Yankee.
On July 31, 2002, Vermont Yankee completed the sale of its nuclear power
plant to Entergy Nuclear Vermont Yankee ("Entergy"). In addition to the sale of
the generating plant, the transaction calls for Entergy, through its power
contract with VY, to provide 20 percent of the plant output to the Company
through 2012, which represents approximately 35 percent of our projected energy
requirements. The Company continues to own approximately 19 percent of the
common stock of VY. Our benefits of the plant sale and the VY power contract
with Entergy include:
VY receives cash approximately equal to the book value of the plant assets,
removing the potential for stranded costs associated with the plant.
VY and its owners will no longer bear operating risks associated with
running the plant.
VY and its owners will no longer bear the risks associated with the
eventual decommissioning of the plant.
Prices under the Power Purchase Agreement between VY and Entergy (the
"PPA") range from $39 to $45 per megawatt-hour for the period beginning January
2003, substantially lower than the forecasted cost of continued ownership and
operation by VY. Contract prices ranged from $49 to $55 for 2002, higher than
the forecasted cost of continued ownership for 2002.
The PPA calls for a downward adjustment in the price if market prices for
electricity fall by defined amounts beginning no later than November 2005. If
market prices rise, however, contract prices are not adjusted upward.
The Company remains responsible for procuring replacement energy at market
prices during periods of scheduled or unscheduled outages at the Entergy plant.
The VY plant had fuel rods that required repair during May 2002, a maintenance
requirement that is not unique to VY. VY closed the plant for a twelve-day
period, beginning on May 11, 2002, to repair the rods. Our cost for the repair,
including incremental replacement energy costs, was approximately $2.0 million.
The Company received an accounting order from the VPSB on August 2, 2002,
allowing it to defer the additional costs related to the outage, and believes
that such amounts are probable of future recovery.
Our ownership share of VY has increased from approximately 17.9 percent last
year to approximately 19.0 percent currently, due to VY's purchase of certain
minority shareholders' interests. VY's primary role consists of administering
its power supply contract with Entergy and its contracts with VY's present
sponsors. Our entitlement to energy produced by the Entergy nuclear plant has
increased from approximately 18 percent to 20 percent of plant production
through a series of transactions in connection with the sale of the plant to
Entergy.
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 also entered into capital funds agreements with its sponsor utilities
that expired on December 31, 2002. Under our Capital Funds Agreement, we were
required, subject to obtaining necessary regulatory approvals, to provide 20% of
the capital requirements of Vermont Yankee not obtained from outside sources.
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. 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.
The Entergy nuclear plant's current operating license expires March 2012.
During the year ended December 31, 2002, we used 771,781 MWh of Vermont
Yankee energy representing 34.9 percent of the net electricity generated and
purchased ("net power supply") by the Company. The average cost of Vermont
Yankee electricity in 2002 was $0.045 per kWh. Vermont Yankee's annual capacity
factor for 2002 was 88.7 percent compared with 91.2 percent for 2001, 99.2
percent in 2000, and 90.9 percent in 1999.
See Note B and Note K 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 percent of the total power-supply benefits associated with the
NEPOOL/Hydro Quebec interconnection. The Company, in turn, receives
approximately 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 New England Electric System
and 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
percent 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, 2002, the
present value of the Company's obligation was approximately $5,287,000. The
Company's projected future minimum payments under the Phase II support
agreements are approximately $407,000 for each of the years 2003-2007 and an
aggregate of $3,253,000 for the years 2008-2015.
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 percent 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, 2002, the capital structure of such corporations was
approximately 43 percent common equity and 57 percent long-term debt. See Note
B and Note 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 power purchase
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. from Hydro Quebec. 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 arrangement (the "9701
arrangement", or "9701") with Hydro Quebec. See Item 7. MD and A - Power Supply
Expenses, and Note K of Notes.
During 2002, we used 432,171 MWh under Schedule B, and 292,537 MWh under
Schedule C3 of the Hydro Quebec arrangements representing 32.8 percent of our
net power supply. The average cost of Hydro Quebec electricity in 2002 was
approximately $0.066 per kWh.
NEPOOL and 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 purchase or sell 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.
NEPOOL is the New England Power Pool whereby participants are able to buy
and sell wholesale power, through the regional independent system operator,
known as ISO New England for the New England region, to meet current demand
conditions within New England's transmission system, and within each
participant's own distribution system. The Company uses power purchased from
NEPOOL and other short-term opportunity market purchases to fulfill occasional
changes in the demand and supply matrix. During 2002, the Company purchased
359,009 MWh representing 16.2 percent of the Company's net power supply at an
average cost of $0.05 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. In October 1997, we
entered into a Joint Ownership Agreement with MMWEC, whereby we acquired an 8.8
percent 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 2002, we used 81,362 MWh from this plant representing 3.7 percent of
our net power supply at an average cost of $0.06 per kWh. See Note I 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 percent (7.1 MW) in the Wyman #4 unit, which began
commercial operation in December 1978.
During 2002, we used 3,687 MWh from this unit representing 0.2 percent of
our net power supply at an average cost of $0.091 per kWh, based only on
operation, maintenance, and fuel costs incurred during 2002. 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 percent 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 2002, we used 19,832 MWh from this unit representing 0.9 percent of
our net power supply at an average cost of $0.049 per kWh, based only on
operation, maintenance, and fuel costs incurred during 2002. 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 2002 was approximately 33.5
percent 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 excess capacity in the
region has eliminated the need for and value of additional qualifying
facilities.
In 2002, through our direct contracts and VEPPI, we purchased 123,996 MWh
of qualifying facilities production representing 5.6 percent of our net power
supply at an average cost of $0.116 per kWh.
Company Hydroelectric Power. We wholly own and operate eight hydroelectric
generating facilities located on river systems within our service area, the
largest of which has a generating output of 7.8 MW.
In 2002, Company owned hydroelectric plants provided 110,797 MWh of
pollution free energy, representing 5.0 percent of our net power supply at an
average cost of $0.043 per kWh based on total embedded costs and maintenance.
See State and Federal Regulation - Licensing.
VELCO. The Company and six other Vermont electric distribution utilities
own VELCO. Since commencing operation in 1958, VELCO has transmitted power for
its owners in Vermont, including power from NYPA and other power contracted for
by Vermont utilities. VELCO also purchases bulk power for resale at cost to its
owners, and as a member of NEPOOL, represents all Vermont electric utilities in
pool arrangements and transactions. See Note B of Notes.
Fuel. During 2002, our retail and requirements wholesale sales were
provided by the following fuel sources:
* 40.8 percent from hydroelectric sources (32.8 percent Hydro Quebec, 5.0
percent Company-owned, 2.9 percent small power producers, and 0.1 percent NYPA);
* 34.9 percent from a nuclear generating source (the Entergy nuclear plant);
* 3.6 percent from wood;
* 2.5 percent from natural gas;
* 1.5 percent from oil;
* 0.5 percent from wind; and
* 16.2 percent purchased on a short-term basis from other utilities through
the ISO.
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 2002, however, we are
experiencing some difficulty during 2003 as a result of extended cold weather
that has affected fuel deliveriesNone of the utilities from which we expect to
purchase oil- or gas-fired capacity in 2003 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 257,268 tons of
wood chips and mill residue, 54,827 gallons of fuel oil, and 37,869 million
cubic feet of natural gas in 2002. The McNeil plant, assuming any needed
regulatory approvals are obtained, is forecasting 2003 consumption of wood chips
to be 300,000 tons, fuel oil of 70,000 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 Department of Energy ("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 2002, the project provided pollution free 11,458 MWh, representing 0.5
percent of the Company's net power supply at an approximate average cost of
$0.04 per kWh, based only on maintenance costs.
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 sold or disposed of substantially all 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 Notes.
SEASONAL NATURE OF BUSINESS
Winter recreational activities, longer hours of darkness and heating loads
from cold weather historically caused 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.
As a result, our heaviest load in 2002, 342.0 MW, occurred on August 15, 2002.
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, 2002, the Company had 194 employees, exclusive of
temporary employees. The Company considers its relations with employees to be
excellent.
ENERGY EFFICIENCY
In 2002, 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 2002, the charge was 2.0777 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. From 1992 through 1999, the Company's
efficiency programs achieved a cumulative annual saving of 89,000 megawatthours,
saving approximately $7.9 million per year for our customers.
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 1,904 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, 2002, approximately 1,657 of the Company's largest customers,
comprising 52 percent of retail revenues, received 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 2002, we had 27 dispatchable power contracts: 20 contracts were
year-round, while the 5 seasonal contracts included 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 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 invested in wastewater, energy efficiency and generation businesses. NWR's
remaining assets include an interest in a wind generation facility in
California, a note from a hydroelectric facility in New Hampshire, and a
wastewater businessin the process of completing dissolution. For information
regarding our remaining unregulated businesses, see Item 7a. MD and A -
Unregulated Businesses.
EXECUTIVE OFFICERS
The names, ages, and positions of our Executive Officers, in alphabetical order,
as of March 15, 2003 are:
Christopher L. Dutton 54
President and 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 46
Treasurer since February 2002. Controller since October 1996. Manager of
General Accounting from 1990 to 1996.
Walter S. Oakes 56
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 42
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.
Donald J. Rendall, 47
Vice President, General Counsel and Corporate Secretary since July 2002,
March 2002, and December 2002, respectively. Prior to joining the Company, he
was a principal in the Burlington, Vermont law firm of Sheehey, Furlong, Rendall
& Behm, P.C. from 1988 to February 2002.
Stephen C. Terry 60
Senior Vice President-Corporate and Legal Relations since August 1999.
Senior Vice President, Corporate Development from August 1997 to August 1999.
Vice President and General Manager, Retail Energy Services from 1995 to August
1997. Vice President-External Affairs from 1991 to January 1995.
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 28, 2003,
and is hereby incorporated by reference.
AVAILABLE INFORMATION
Our Internet website address is: www.Greenmountainpower.biz. We make
available free of charge through the website our annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended, as soon as reasonably practicable
after such documents are electronically filed with, or furnished to, the SEC.
The information on our website is not, and shall not be deemed to be, a part of
this report or incorporated into any other filings we make with the SEC.
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:
* 18.99 percent of the outstanding common stock of Vermont Yankee and,
through its contract with Entergy, we are entitled to 20.0 percent (106.2 MW of
a total 531 MW) of the capacity of the Entergy Nuclear Vermont Yankee plant,
* 1.1 percent (7.1 MW of a total 620 MW) joint-ownership share of the Wyman
#4 plant located in Maine,
* 8.8 percent (31.0 MW of a total 352 MW) joint-ownership share of the Stony
Brook I intermediate units located in Massachusetts, and
* 11.0 percent (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, 2002, approximately 2 miles of 115 kV
transmission lines, 10 miles of 69 kV transmission lines, 5 miles of 44 kV
transmission lines, 187 miles of 34.5 kV transmission lines, and 2 miles of 13.8
kV transmission lines. Our distribution system included approximately 2,340
miles of overhead lines of 2.4 to 34.5 kV and 455 miles of underground cable of
2.4 to 34.5 kV. At such date, we owned approximately 115,000 kV of substation
transformer capacity in transmission substations and 590,000 kV of substation
transformer capacity in distribution substations and approximately 872,000 kV of
transformers for step-down from distribution to customer use.
The Company owns 34.8 percent of the Highgate transmission inter-tie, a
225-MW converter and transmission line used to transmit power from Hydro Quebec.
We also own 28.4 percent of the common stock and 30 percent of the
preferred stock of VELCO, which operates a high-voltage transmission system
interconnecting electric utilities in the State of Vermont.
PROPERTY OWNERSHIP
Our 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 F, Long-Term Debt, for more information concerning our 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 . . . . . . . . . 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 162.5
========
(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
Our headquarters and main service center are located in Colchester Vermont,
one of the most rapidly growing areas of our service territory. The Company
terminated an operating lease for its former 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 our 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 2001 and 2002:
HIGH LOW
------ ------
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
2002
First Quarter. $19.00 $17.00
Second Quarter 19.50 17.54
Third Quarter. 18.25 15.75
Fourth Quarter 21.08 15.89
The number of common stockholders of record as of March 12, 2003 was
approximately 5,190.
Quarterly cash dividends were paid as follows during the past two years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- --------
2001 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1375
2002 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1900
Dividend Policy. The annual dividend rate was increased from $0.55 per
share to $0.76 per share beginning with the $0.19 quarterly dividend declared in
December 2002. The Company intends to increase the dividend in a measured
consistent manner until the payout ratio falls between 50 percent and 60 percent
of anticipated earnings. We believe this payout ratio to be consistent with
that of other utilities having similar risk profiles.
Our current dividend policy reflects changes affecting the electric utility
industry, which, in other jurisdictions, is moving away from the traditional
cost-of-service regulatory model to a competition based market for power supply.
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. Our 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. 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.
42
ITEM 6. SELECTED FINANCIAL DATA
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
2002 2001 2000 1999 1998
--------- --------- --------- --------- ---------
In thousands, except per share data
Operating Revenues . . . . . . . . . . . . . . . . . . . . . . . . . $274,608 $283,464 $277,326 $251,048 $184,304
Operating Expenses . . . . . . . . . . . . . . . . . . . . . . . . . 259,528 267,005 272,066 243,102 178,832
--------- --------- --------- ---------
Operating Income . . . . . . . . . . . . . . . . . . . . . . . 15,080 16,459 5,260 7,946 5,472
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity . . . . . . . . . . . . . . . . . . . . . . . . 233 210 284 134 104
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,252 2,163 2,422 3,319 1,509
Total other income . . . . . . . . . . . . . . . . . . . . . . 2,485 2,373 2,706 3,453 1,613
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed . . . . . . . . . . . . . . . . . . . . . . . (103) (188) (228) (91) (131)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,273 7,227 7,485 7,274 8,007
Total interest charges . . . . . . . . . . . . . . . . . . 6,170 7,039 7,257 7,183 7,876
--------- --------- --------- --------- ---------
Net Income (Loss) from continuing operations before. . . . . . . . . 11,395 11,793 709 4,216 (791)
preferred dividends
Net Income (Loss) from discontinued operations, including
provisions for loss on disposal . . . . . . . . . . . . . . . . . 99 (182) (6,549) (7,279) (2,086)
Dividends on Preferred Stock . . . . . . . . . . . . . . . . . . . . 96 933 1,014 1,155 1,296
--------- --------- --------- --------- ---------
Net Income (Loss)Applicable
to Common Stock. . . . . . . . . . . . . . . . . . . . . . . . $ 11,398 $ 10,678 $ (6,854) $ (4,218) $ (4,173)
========= ========= ========= ========= =========
Common Stock Data
Basic earnings per share-continuing operations . . . . . . . . $ 2.02 $ 1.93 $ (0.06) $ 0.57 $ (0.40)
Basic earnings per share-discontinued operations . . . . . . . 0.02 (0.03) (1.19) (1.36) (0.40)
--------- --------- --------- ---------
Basic earnings per share . . . . . . . . . . . . . . . . . . . $ 2.04 $ 1.90 $ (1.25) $ (0.79) $ (0.80)
========= ========= ========= ========= =========
Diluted earnings (loss) per share from discontinued operations $ 1.96 $ 1.88 $ (0.06) $ 0.57 $ (0.40)
Diluted earnings (loss) per share from continuing operations . 0.02 (0.03) (1.19) (1.36) (0.40)
Diluted earnings (loss) per share. . . . . . . . . . . . . . . $ 1.98 $ 1.85 $ (1.25) $ 0.79 $ (0.80)
========= ========= ========= ========= =========
Cash dividends declared per share. . . . . . . . . . . . . . . . . . $ 0.60 $ 0.55 $ 0.55 $ 0.55 $ 0.96
Weighted average shares outstanding-basic. . . . . . . . . . . 5,592 5,592 5,630 5,491 5,243
Weighted average share equivalents outstanding-diluted . . . . 5,756 5,756 5,789 5,491 5,243
FINANCIAL CONDITION AS OF DECEMBER 31
------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
In thousands
ASSETS
Utility Plant, Net. . . . . . . . . . . $203,529 $196,858 $194,672 $192,896 $195,556
Other Investments . . . . . . . . . . . 21,552 20,945 20,730 20,665 20,678
Current Assets. . . . . . . . . . . . . 31,432 36,183 53,652 33,238 35,700
Deferred Charges. . . . . . . . . . . . 51,594 72,468 46,036 41,853 35,576
Non-Utility Assets. . . . . . . . . . . 995 1,075 1,518 11,099 27,314
Total Assets. . . . . . . . . . . . . . $309,102 $327,529 $316,608 $299,751 $314,824
======== ======== ======== ======== ========
CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . . $ 91,722 $101,277 $ 92,044 $100,645 $106,755
Redeemable Cumulative Preferred Stock . 55 12,560 12,795 14,435 16,085
Long-Term Debt, Less Current Maturities 93,000 74,400 72,100 81,800 88,500
Capital Lease Obligation. . . . . . . . 5,287 5,959 6,449 7,038 7,696
Current Liabilities . . . . . . . . . . 38,491 38,841 68,109 36,708 28,825
Deferred Credits and Other. . . . . . . 78,606 92,791 61,794 59,125 59,889
Non-Utility Liabilities . . . . . . . . 1,941 1,701 3,317 - 7,074
Total Capitalization and Liabilities. . $309,102 $327,529 $316,608 $299,751 $314,824
======== ======== ======== ======== ========
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 timing of expense and revenue
recognition under 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;
* changes in regional market and transmission rules;
* 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 $1.98 per share of common
stock, diluted, in 2002, compared to earnings of $1.85 per share in 2001 and a
loss of $1.25 per share in 2000. The 2002 earnings represent a consolidated
return on average common equity of 11.03 percent, and a return on regulated
operations of 11.25 percent. The consolidated return on average common equity
was 11.02 percent in 2001 and negative 7.1 percent in 2000. Income from
continuing operations was $1.96 per share, diluted, in 2002, compared with $1.88
per share, diluted, in 2001, and a loss of $0.06 per share in 2000. The
Company's subsidiary Northern Water Resources, Inc. ("NWR"), classified as
discontinued in 1999, earned $0.02 per share in 2002 compared with a loss of
$0.03 per share in 2001, and a loss of $1.19 per share in 2000. A significant
portion of NWR's assets, which consisted of energy generation and efficiency
investments and wastewater treatment projects, have been sold, or otherwise
disposed. NWR's 2002 earnings resulted primarily from an adjustment to a
reserve for warranty claims.
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
"VJO Contract"). The Settlement Order paved the way for restoration of the
Company's first mortgage bond credit rating to investment grade status in 2001
(See "Rates-Retail Rate Cases" and "Liquidity and Capital Resources" in this
section) and enabled the Company to earn its allowed rate of return of 11.25
percent on regulated operations during 2002 and 2001.
The improvement in earnings from continuing operations in 2002 compared with
2001 resulted from reductions in the Company's cost of capital and other
operating expenses, partially offset by increases in maintenance and
transmission expenses and lower gross margins on the Company's sales. Lower
capital costs resulted from reduced interest rates and average debt levels,
which caused 2002 interest expense to decline by $0.9 million compared to 2001,
and the redemption of preferred stock which reduced 2002 preferred stock
dividends $0.8 million compared with 2001. Lower gross margins resulted from an
increase in power supply costs to serve retail customers, that was only
partially offset by recognition of $4.4 million in revenue deferred in 2001
under the Settlement Order.
The improvement in earnings from continuing operations in 2001, compared
with 2000, resulted primarily from several factors, including:
* 2001 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 2001 retail operating revenues; and
* the write-off in 2000 of $3.2 million, or $0.35 per share, in regulatory
litigation costs.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, AND OTHER
RISK FACTORS.
POWER SUPPLY RISK.
Our material power supply contracts and arrangements are principally with
Hydro Quebec, MS and Vermont Yankee Nuclear Power Corporation. At December 31,
2002, more than 90 percent of our estimated load requirements through 2006 are
expected to be met by these contracts and arrangements, and by our own
generation and other power supply resources, which reduces the Company's
exposure to market prices.
A primary factor affecting future operating results is the volatility of
the wholesale electricity market. Restructuring of the wholesale market for
electricity has brought increased price volatility to our power supply markets.
Inherent in our market risk sensitive instruments and positions are the
potential losses that may result from adverse changes in our commodity prices.
One objective of the Company's risk management program is to stabilize cash
flow and earnings by minimizing power supply risks. Transactions permitted by
the risk management program include futures, forward contracts, option
contracts, swaps and transmission congestion rights with counter-parties that
have at least investment grade ratings. These transactions are used to hedge
the risk of fossil fuel and spot market electricity price increases. The
Company's risk management policy specifies risk measures, the amount of
tolerable risk exposure, and authorization limits for transactions.
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 prices for fossil
fuel resources or specified prices for contracted resources and then sells to us
at a fixed rate to serve pre-established load requirements. This contract,
along with other power supply commitments, allows the Company 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,
2006. Management's estimate of the fair value of the future net benefit of this
arrangement at December 31, 2002 is approximately $8.8 million. Assumptions
used to calculate the future net benefit using the Blacks option valuation model
include a risk-free interest rate of 3.4 percent, volatility equivalent to a
weighted average from NEPOOL, which varies from 32 percent in the first year to
29 percent in the fourth year, locked in forward commitment prices for 2003,
with an estimated forward market price of approximately $43 per MWh for periods
beyond 2003. The forward price for electricity is consistent with the Company's
current long-term wholesale energy price forecast. Actual results may differ
materially from the table below.
We currently have an arrangement that grants Hydro Quebec an option
("9701") to call power at prices that are expected to be below 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, 2002 is approximately $27.2 million. We sometimes
use futures contracts to hedge forecasted sales of electric power under 9701.
A sensitivity analysis has been prepared to estimate exposure to the market
price risk of 9701, using the Black-Scholes model, over the next 13 years.
Assumptions used within the model include a risk-free interest rate of 5.02
percent, volatility equivalent to the weighted average from NEPOOL, which varies
from 48 percent in the first year to 26 percent in year 13, locked in forward
commitment prices for 2003, and an average of approximately 59,326 MWh per year,
with an estimated forward market price of $59.81 per MWh for periods beyond
2003. The forward price for electricity is consistent with the Company's
current long-term wholesale energy price forecast. Quoted forward market prices
for monthly peak power rates are not currently available beyond 2004. 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 $0.9 million.
Actual results may differ materially from the table below. 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.
Commodity Price Risk At December 31, 2002
Fair Value Market Risk
--------------- ------------
(in thousands)
Net short position $ 18,405 $ 880
REGULATORY RISK- There are currently no regulatory proceedings, court
actions or pending legislative proposals to adopt electric industry
restructuring in Vermont. However, if Vermont adopted such restructuring, the
major risk factors for the Company that may arise from electric industry
restructuring, including risks pertaining to the recovery of stranded costs,
are:
* regulatory and legal decisions;
* cost and amount of default service responsibility;
* the market price of power; and
* the amount of market share retained by the Company.
There can be no assurance that any potential future restructuring plan
ordered by the VPSB, the courts, or through legislation will include a mechanism
that would allow for full recovery of our stranded costs and include a fair
return on those costs as they are being recovered. If laws are enacted or
regulatory decisions are made that do not offer an adequate opportunity to
recover stranded costs, we believe we have compelling legal arguments to
challenge such laws or decisions.
The largest category of our potential stranded costs is future costs under
long-term power purchase contracts, which, based on current forecasts, are
above-market. The magnitude of our stranded costs is largely dependent upon the
future market price of power. We have discussed various market price scenarios
with interested parties for the purpose of identifying stranded costs.
Preliminary market price assumptions, which are likely to change, have resulted
in estimates by the Company of its stranded costs of between $203 million and
$224 million over the life of the contracts. 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 in Vermont have been based on a
utility's cost of service. As a result, Vermont electric utilities are subject
to certain accounting standards that apply only to regulated businesses.
Statement of Financial Accounting Standards No. 71 ("SFAS 71"), Accounting for
the Effects of Certain Types of Regulation, allows regulated entities, including
the Company, 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.
Regulatory assets represent incurred costs that have been deferred because
the Company has concluded that they are probable of future recovery in customer
rates. Regulatory liabilities generally represent obligations to make refunds
to customers for previous collections of costs. The Company's last retail rate
case was filed during 1998. Since that time a material amount of expenditures
have been deferred as regulatory assets pending consideration by the VPSB in a
future retail rate proceeding. These regulatory assets have been judged as
probable of recovery by management. The most significant regulatory assets that
are not being currently amortized in rates, or are being amortized at amounts
that could materially differ from future expenditure levels, include:
Regulatory assets
At December 31,
2002 2001
------- -------
(in thousands)
Pine Street Barge Canal. . . 13,019 12,425
Unscheduled VY outage costs. 2,002 -
Demand Side Management . . . 6,434 6,961
Storm damages. . . . . . . . 1,905 2,169
Tree Trimming. . . . . . . . 905 905
------- -------
Regulatory assets. . . . . . $24,265 $22,460
======= =======
Management's conclusion that these assets are probable of recovery is based on a
variety of factors, including benefits to customers, consistency with past
regulatory treatment, materiality of costs relative to normal cost levels,
similar rate case decisions in other jurisdictions applying cost of service
ratemaking principles, and opportunities to recover these costs over extended
periods of time. If the VPSB were to disallow any of these costs, the result
would be a pretax charge to current earnings in the amount of the disallowance.
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, 2002 the accounting impact would have been an extraordinary
non-cash charge to operations of $51.6 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. However, we believe that the
continued application of SFAS 71 is appropriate at this time.
We cannot predict whether restructuring legislation, if 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.
PENSION RISK-Other critical accounting policies involve the non-contributory
defined benefit pension and postretirement health care benefit plans of the
Company. The reported costs of these plans are dependent upon numerous factors
resulting from actual plan experience and assumptions of future experience.
Pension and postretirement health care costs are impacted by actual
employee demographics, the level of Company contributions to the plans, earnings
on plan assets, and health care cost trends (postretirement health care plan
only).
The Company's pension and postretirement health care benefit plan assets consist
of equity and fixed income investments. Fluctuations in actual equity market
returns, as well as changes in general interest rates, may result in increased
or decreased costs in future periods. Changes in assumptions regarding current
discount rates and expected rates of return on plan assets could also increase
or decrease recorded defined benefit plan costs. For example, the Company in
2003 expects to reduce the expected return on its plan assets by 50 basis points
to 8.5 percent, resulting in a $210,000 increase in plan expense. See Note H
for further information.
As a result of our plan asset experience, at December 31, 2002, the Company was
required to recognize an additional minimum liability of $2.4 million, net of
applicable income taxes, as prescribed by SFAS 87. The liability was recorded
as a reduction to common equity through a charge to Other Comprehensive Income
("OCI"), and did not affect net income for 2002. The charge to OCI may be
restored through common equity in future periods to the extent fair value of
trust assets exceeded the accumulated benefit obligation. Current changes to
plan assumptions, along with plan losses experienced during 2002, are expected
to result in increased pension and postretirement health benefit expenses of
approximately $0.6 million and $0.5 million, respectively, for 2003 compared
with 2002.
UNREGULATED BUSINESSES
Most of the assets of NWR, which invested in energy generation, energy
efficiency and wastewater treatment projects, have been sold. NWR earned $0.1
million in 2002, compared with a loss of approximately $0.2 million in 2001, and
a loss of $6.5 million in 2000. The 2002 earnings and 2001 loss resulted
primarily from provisions to recognize adjustments to liability estimates under
warranties 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 2002, essentially unchanged from the prior two years.
RESULTS OF OPERATIONS
OPERATING REVENUES AND MWH SALES-Operating revenues and megawatthour ("MWh")
sales for the years ended 2002, 2001 and 2000 consisted of:
Years ended December 31,
2002 2001 2000
------------------------- ---------- ----------
(dollars in thousands)
Operating Revenues
Retail. . . . . . . . $ 201,052 $ 195,093 $ 185,944
Sales for Resale. . . 70,646 83,804 88,333
Other . . . . . . . . 2,910 4,567 3,049
------------------------- ---------- ----------
Total Operating Revenues. $ 274,608 $ 283,464 $ 277,326
========================= ========== ==========
MWH Sales-Retail. . . . . 1,948,190 1,953,154 1,947,857
MWH Sales for Resale. . . 2,107,941 2,368,887 2,575,657
------------------------- ---------- ----------
Total MWH Sales . . . . . 4,056,131 4,322,041 4,523,514
========================= ========== ==========
Average Number of Customers
Years ended December 31,
2002 2001 2000
------------------------ ------ ------
Residential . . . . . . . 73,861 73,249 72,424
Commercial and Industrial 13,194 13,006 12,769
Other . . . . . . . . . . 65 65 65
------------------------ ------ ------
Total Number of Customers. . 87,120 86,320 85,258
======================== ====== ======
Differences in operating revenues were due to changes in the following:
Change in Operating Revenues 2001 to 2000 to
2002 2001
--------- --------
(In thousands)
Retail Rates . . . . . . . . . . . . . . . $ 6,471 $ 8,620
Retail Sales Volume. . . . . . . . . . . . (512) 529
Resales and Other Revenues . . . . . . . . (14,815) (3,011)
--------- --------
Increase (Decrease) in Operating Revenues. $ (8,856) $ 6,138
========= ========
In 2002, total electricity sales decreased 6.2 percent compared with 2001, due
to reduced sales for resale under the 9701 arrangement with Hydro Quebec and our
MS contract, described in more detail below under the headings "Power Supply
Expenses" and "Power Contract Commitments". Total operating revenues decreased
$8.9 million, or 3.1 percent, in 2002 compared with 2001, due to decreases in
sales for resale, partially offset by increased retail operating revenues.
Retail operating revenues increased $6.0 million, or 3.1 percent, in 2002
compared with 2001 due to the recognition of $4.4 million of revenue deferred
under the Settlement Order. Increased sales to residential and commercial
customers also contributed to higher retail revenues, partially offset by a
decline in revenues from International Business Machines Corporation ("IBM").
In 2001, total electricity sales decreased 4.5 percent compared with 2000,
due principally to reduced sales for resale executed pursuant to the MS
contract, 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 contract with
that customer approved in the Settlement Order.
IBM, the Company's largest customer, operates a manufacturing facility in
Essex Junction, Vermont. IBM's electricity requirements for its facility
accounted for approximately 25.7, 26.6, and 26.6 percent of the Company's retail
MWh sales in 2002, 2001, and 2000, respectively, and 17.3, 19.2, and 16.5
percent of the Company's retail operating revenues in 2002, 2001, and 2000,
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. During 2002, the VPSB approved a modification of this
agreement for the last year of the term, 2003. The price of power for the
three-year term of the agreement is above our marginal costs of providing
incremental service to IBM.
IBM reduced its Vermont workforce by 1,500 during 2002, to a level of
approximately 7,000 employees. If future significant losses in electricity
sales to IBM were to occur, the Company's earnings could be impacted adversely.
If earnings were materially reduced as a result of lower retail sales, the
Company would seek a retail rate increase from the VPSB. The Company is not
aware of any plans by IBM to further reduce production at its Vermont facility.
The Company currently estimates, based on a number of projected variables, the
retail rate increase required from all retail customers by a hypothetical
shutdown of the IBM facility to be in the range of five to ten percent,
inclusive of projected declines in sales to residential and commercial
customers.
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 Company recognized
approximately $4.4 million of these revenues in 2002 and expects to recognize
the remaining balance of $4.1 million during 2003. The deferred recognition of
rate levelization revenues allowed the Company to achieve our allowed rate of
return in 2002 without further rate relief and is expected to provide the
Company with the opportunity to achieve similar operating results in 2003
without further rate relief (See "Power Contract Commitments", and "Rates-Retail
Rate Cases" in this section).
Power supply expenses constituted 74.5, 75.3, and 77.7 percent of total
operating expenses for the years 2002, 2001, and 2000, respectively. Power
supply expenses decreased by $7.6 million or 3.8 percent in 2002 when compared
with 2001, and resulted from the following:
a $13.2 million decrease in power purchased for resale, primarily under the
9701 arrangement with Hydro Quebec and our MS contract;
a $3.5 million decrease in the net cost of the 9701 arrangement with Hydro
Quebec; and
a $2.1 million increase in the value of additional generation at the
Company's hydroelectric plants, that allowed the Company to purchase less power
during 2002.
These decreases were partially offset by increased power supply expense in 2002
when compared with 2001 for the following reasons:
a $6.2 million increase in the cost of power purchased from MS;
a $3.7 million net increase in the cost of power purchased from Vermont
Yankee, including an offset of $1.4 million for the increase in value of
additional generation purchased from the plant; and
a $2.9 million increase in power purchased from independent power
producers.
Power supply expenses decreased by $10.5 million or 5.0 percent in 2001
when compared with 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 are 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 in power purchased for resale, primarily under a
power supply contract discussed under the caption "Power Contract Commitments"
below, pursuant to which the Company purchases 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.
In 2001, 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
contract, and higher capacity costs in 2001 of approximately $1.0 million.
The Independent System Operator of New England ("ISO" or "ISO New England")
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 the 9701
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 markets continue to experience the volatility evident
since 1999, or the Company's power resources are unavailable during periods of
high market prices, 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") between the Company and MS defines
the general contract terms under which the parties may transact. 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 August 2002, the PPSA was modified and
extended to December 31, 2006.
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 typically incorporate a risk premium.
The Company's current purchases pursuant to the contract with Hydro
Quebec entered into December 4, 1987 (the "1987 Contract") are as follows: (1)
Schedule B -- 68 megawatts of firm capacity and associated energy to be
delivered at the Highgate interconnection for twenty years beginning in
September 1995; and (2) Schedule C3 -- 46 megawatts of firm capacity and
associated energy to be delivered at interconnections to be determined at any
time for 20 years, which began in November 1995.
Pursuant to the