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 1987 Contract, Hydro Quebec has the right to reduce the
load factor from 75 percent to 65 percent a total three times over the life of
the 1987 Contract. The Company has the contractual right to delay any such
reduction by one year under the 1987 Contract. During 2001, Hydro Quebec
exercised the first of these options for 2002 and the Company delayed the
effective date of this exercise until 2003. The Company estimates that the net
cost of Hydro Quebec's exercise of its option will increase power supply expense
during 2003 by approximately $0.4 million.
Our contracts with Hydro Quebec contain cross default provisions that allow
Hydro Quebec to invoke "step-up" provisions under which the other Vermont
utilities that are party to the contract would be required to purchase their
proportionate share of the power supply entitlement of the defaulting utility.
The Company is not aware of any instance where this provision has been invoked
by Hydro Quebec.
During 1994, we negotiated an arrangement with Hydro Quebec that reduced
the cost under our 1987 Contract with Hydro Quebec over the November 1995
through October 1999 period (the "July 1994 Agreement").
As part of the July 1994 Agreement, we were obligated to purchase $4.0
million (in 1994 dollars) worth of research and development work from Hydro
Quebec over a four-year period (which was extended to 2003), and made a $6.5
million (in 1994 dollars) payment to Hydro Quebec in 1995. Hydro Quebec retains
the right to curtail annual energy deliveries by 10 percent up to five times,
over the 2001 to 2015 period, if documented drought conditions exist in Qu bec.
Under the 9701 arrangement established in December 1997 `, Hydro Quebec
paid $8.0 million to the Company in 1997. In return for this payment, we
provided Hydro Quebec options for the purchase of power. Commencing April 1,
1998 and effective through the term of the 1987 Contract, which ends in 2015,
Hydro Quebec may purchase up to 52,500 MWh ("option A") on an annual basis, at
the 1987 Contract energy prices, which are substantially below current market
prices. The cumulative amount of energy that may be purchased under option A
shall not exceed 950,000 MWh.
Over the same period, Hydro Quebec may exercise an option to purchase a
total of 600,000 MWh ("option B") at the 1987 Contract energy price. Under
option B, Hydro Quebec may purchase no more than 200,000 MWh in any year. As of
December 31, 2002, Hydro Quebec had purchased or called to purchase 458,000 MWh
under option B.
In 2002, Hydro Quebec exercised option A and called for deliveries to third
parties at a net expense to the Company of approximately $3.0 million including
capacity charges.
In 2001, Hydro Quebec exercised option A and option B, and called for
deliveries to third parties at a net expense to the Company of approximately
$6.5 million, including capacity charges.
In 2000, Hydro Quebec exercised option A and option B, and called for
deliveries to third parties at a net expense to the Company of approximately
$14.0 million (including the cost of January and February, 2001 calls, and the
cost of related financial positions), which was due to higher energy replacement
costs incurred by the Company. Approximately $6.6 million of the $14.0 million
net 9701 costs were recovered in rates in 2000.
The Company believes that it is probable that Hydro Quebec will call
options A and B for 2003, and has purchased replacement power at a net cost of
$4.7 million.
The VPSB, in the Settlement Order stated, "The record does not demonstrate
that any other New England utility foresaw the extent and degree of volatility
that has developed in the New England wholesale power markets. Absent that
volatility, the 97-01 Agreement would not have had adverse effects." In
conjunction with the Settlement Order, Hydro Quebec committed to the Department
that it would not call any energy under option B of 9701 during the contract
year ending October 31, 2002.
On April 17, 2001, an Arbitration Tribunal issued its decision in the
arbitration brought by a group of Vermont electric companies and municipal
utilities, known as the Vermont Joint Owners ("VJO"), against Hydro Quebec for
its failure to deliver electricity pursuant to the VJO contract during the 1998
ice storm. The Company is a member of the VJO.
On July 23, 2001, the Company received approximately $3.2 million
representing its share of refunded capacity payments from Hydro Quebec. These
proceeds reduced related deferred assets leaving a deferred balance of
unrecovered arbitration costs of approximately $1.4 million. We believe it is
probable that this balance will ultimately be recovered in rates.
Vermont Yankee Nuclear Power Corporation ("VY")
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 the Company's 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, the 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.
Payments totaling $0.5 million were made to VY's non-Vermont sponsors in return
for guarantees those sponsors made to Entergy to finalize the VY sale.
Although the sale closed on July 31, 2002, the Company's distribution of the
sale proceeds and final accounting for the sale are pending certain regulatory
approvals and the resolution of certain closing items between VY and Entergy.
The Company expects its share of the VY power plant sale proceeds, estimated at
between $7 million and $8 million, to be distributed in the latter part of 2003.
The sale required various regulatory approvals, all of which were granted on
terms acceptable to the parties to the transaction. Certain intervener parties
to the VPSB approval proceeding appealed the VPSB approval to the Vermont
Supreme Court. That appeal is pending. If the appellants prevail on their
appeal, the VPSB could be required to conduct additional proceedings or to
reconsider its order approving the sale.
OTHER OPERATING EXPENSES- Other operating expenses decreased $1.7 million, or
10.9 percent in 2002 compared with 2001. The decrease was primarily due to
reduced consulting costs of approximately $1.0 million and reduced distribution
expenses of $0.6 million. Other operating expenses are not expected to increase
significantly during 2003.
Other operating expenses decreased $1.7 million, or 9.7 percent in 2001
compared with 2000. The decrease was primarily due to a $3.2 million charge
during 2000 for disallowed regulatory litigation costs, ordered by the VPSB as
part of the Settlement Order, offset in part by increased outside service
expense during 2001.
TRANSMISSION EXPENSES-Transmission expenses increased $1.1 million, or 7.7
percent, in 2002 compared with 2001. The Company's relative share of
transmission costs varies with the peak demand recorded on Vermont's
transmission system. The Company's share of those costs increased due to its
increased load growth, relative to other Vermont utilities, and also because of
increased transmission investment by VELCO.
Transmission expenses decreased $0.1 million or 0.8 percent in 2001
compared with 2000.
During 2002, the Federal Energy Regulatory Commission ("FERC") accepted ISO
New England's request to implement a standard market design ("SMD") governing
wholesale energy sales in New England. The ISO implemented its SMD plan on
March 1, 2003. SMD includes a system of locational marginal pricing of energy,
under which prices are determined by zone, and based in part on transmission
congestion experienced in each zone. Currently, the State of Vermont
constitutes a single zone under the plan, although pricing may eventually be
determined on a more localized ("nodal") basis. The Company does not expect the
implementation of this SMD in its current form, which denominates Vermont as a
single pricing zone, to have a material impact on the Company's power supply or
transmission costs. The FERC has suggested that change to nodal pricing might
be appropriate as early as 18 months after the implementation of SMD. The
Company believes that this could result in a material adverse impact on its
power supply or transmission costs.
On July 31, 2002, FERC issued a Notice of Proposed Rulemaking to amend its
regulations and modify its existing pro forma open access transmission tariff to
require that all public utilities with open access transmission tariffs modify
their tariffs to reflect non-discriminatory, standardized transmission service
and standard wholesale electric market design. This rulemaking, known as the
"SMD NOPR," proposes to implement standard market design and locational marginal
pricing in all regions of the United States, including New England. The SMD
NOPR is currently in the rulemaking comment period. It is uncertain whether or
how implementation of FERC's SMD NOPR, if and when approved, may differ from the
ISO New England SMD plan, or how implementation of the SMD NOPR could impact the
Company's power supply or transmission costs, although the impacts could be
material.
During 2002, ISO New England and the New York Independent System Operator
filed and then withdrew their petition with the FERC proposing to establish a
single Northeastern Regional Transmission Organization ("NERTO") encompassing
the six New England states and New York. ISO New England has indicated an
intention to file a petition with FERC to create a regional transmission
organization comprising six New England states now part of the ISO.
VELCO has proposed a project to substantially upgrade Vermont's
transmission system (the "Northwest Reliability Project"), principally to
support reliability and eliminate transmission constraints in northwestern
Vermont, including most of the Company's service territory. The proposed
Northwest Reliability Project must be approved by the VPSB. If approved, the
project is estimated to cost approximately $150 million over a seven to ten year
period. Under current NEPOOL and ISO New England rules, which require
qualifying large transmission project costs to be shared among all New England
utilities, the Company would expect the costs of this project to be allocated
throughout the New England region, with Vermont utilities responsible for
approximately five percent of the total project costs. However, in response to
FERC's SMD NOPR and as part of ISO New England's SMD plan, ISO New England is
considering changes to the transmission cost allocation rules which could modify
or eliminate the opportunity to allocate costs associated with the Northwest
Reliability Project to the New England region as a whole. The Company has
vigorously advocated for continuation of the current cost allocation rules. If
these rules are modified or eliminated, the Company and other Vermont utilities
could be required to bear a greater proportion, and potentially all, of the cost
of the Northwest Reliability Project.
MAINTENANCE EXPENSES-Maintenance expenses increased $1.7 million or 25.0 percent
in 2002 compared with 2001, due to increased expenditures related to storm
damage and increased right-of-way maintenance programs.
Maintenance expenses increased $0.5 million or 7.2 percent in 2001 compared
with 2000 due to increased expenditures on right-of-way maintenance programs.
DEPRECIATION AND AMORTIZATION-Depreciation and amortization expense
decreased $0.1 million or 1.0 percent in 2002 compared with 2001 due to
reductions in depreciation of utility plant in service, partially offset by
increased amortization of software costs.
Depreciation and amortization expense decreased $1.0 million or 6.6 percent
in 2001 compared with 2000 due to reductions in amortization of demand side
management costs that were only partially offset by increased depreciation of
utility plant in service.
INCOME TAXES-Income tax expense decreased $0.9 million in 2002 compared with
2001 due to a decrease in the Company's taxable income. Income tax expense
increased $7.6 million in 2001 when compared with that of 2000 due to an
increase in the Company's taxable income.
OTHER INCOME-Other income increased $0.4 million in 2002 compared with 2001 due
primarily to the VY recognition of deferred tax assets arising in conjunction
with the sale of the VY plant,, offset in part by payments made to out-of-state
VY sponsors necessary to close the sale of the VY plant.
Other income decreased $0.3 million in 2001 compared with 2000 due in part
to reduced interest income from the reduced investment returns available in
2001.
INTEREST EXPENSE-Interest expense decreased $0.9 million or 12.3 percent in 2002
compared with 2001 primarily due to scheduled and early redemptions of long-term
debt and reduced short-term borrowing rates offset in part by higher average
balances for short-term borrowings. Interest expense on long-term debt is
expected to rise approximately $0.9 million in 2003 due to increased average
debt levels from long-term bonds issued in December 2002.
Interest expense decreased $0.2 million or 3.0 percent in 2001 compared
with 2000 primarily due to scheduled reductions in long-term debt offset in part
by a $12 million term loan made on August 24, 2001.
DIVIDENDS ON PREFERRED STOCK- Dividends on preferred stock decreased $0.8
million, or 90 percent in 2002 compared with 2001 due to the repurchase of all
outstanding preferred stock other than the 4.75 percent Class B shares.
Dividends on preferred stock are expected to be negligible during 2003. See the
discussion under the caption, "Liquidity and Capital Resources-Financing and
Capitalization".
Dividends on preferred stock decreased $81,000 or 8.0 percent in 2001
compared with 2000 due to repurchases of preferred stock.
ENVIRONMENTAL MATTERS
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air and
aesthetic requirements as administered by local, state and federal regulatory
agencies. We believe that we are in substantial compliance with these
requirements, and that there are no outstanding material complaints about our
compliance with present environmental protection regulations, except for
developments related to the Pine Street Barge Canal site.
PINE STREET BARGE CANAL SITE-The Federal Comprehensive Environmental Response,
Compensation, and Liability Act ("CERCLA"), commonly known as the "Superfund"
law, generally imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous substances. We have
previously been notified by the Environmental Protection Agency ("EPA") that we
are one of several potentially responsible parties ("PRPs") for cleanup of the
Pine Street Barge Canal site in Burlington, Vermont, where coal tar and other
industrial materials were deposited.
In September 1999, we negotiated a final settlement with the United States
EPA, the State of Vermont (the "State"), and other parties to a Consent Decree
that covers claims with respect to the site and implementation of the selected
site cleanup remedy. In November 1999, the Consent Decree was filed in the
federal district court. The Consent Decree addresses claims by the EPA for past
Pine Street Barge Canal site costs, natural resource damage claims and claims
for past and future oversight costs. The Consent Decree also provides for the
design and implementation of response actions at the site.
As of December 31, 2002, our total expenditures related to the Pine Street
Barge Canal site since 1982 were approximately $27.2 million. This includes
amounts not recovered in rates, amounts recovered in rates, and amounts for
which rate recovery has been sought but which are presently waiting further VPSB
action. The bulk of these expenditures consisted of transaction costs.
Transaction costs include legal and consulting costs associated with the
Company's opposition to the EPA's earlier proposals for a more expensive remedy
at the site, litigation and related costs necessary to obtain settlements with
insurers and other PRPs to provide amounts required to fund the clean up
("remediation costs"), and to address liability claims at the site. A smaller
amount of past expenditures was for site-related response costs, including costs
incurred pursuant to EPA and State orders that resulted in funding response
activities at the site, and to reimburse the EPA and the State for oversight and
related response costs. The EPA and the State have asserted and affirmed that
all costs related to these orders are appropriate costs of response under CERCLA
for which the Company and other PRPs were legally responsible.
We estimate that we have recovered or secured, or will recover, through
settlements of litigation claims against insurers and other parties, amounts
that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We currently estimate
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $13.0 million over the next 32
years. The estimated liability is not discounted, and it is possible that our
estimate of future costs could change by a material amount. We also have
recorded an offsetting regulatory asset and we believe that it is probable that
we will receive future revenues to recover these costs.
Through rate cases filed in 1991, 1993, 1994, and 1995, we sought and
received recovery for ongoing expenses associated with the Pine Street Barge
Canal site. While reserving the right to argue in the future about the
appropriateness of full rate recovery of the site-related costs, the Company and
the Department, and as applicable, other parties, reached agreements in these
cases that the full amount of the site-related costs reflected in those rate
cases should be recovered in rates.
We proposed in our rate filing made on June 16, 1997 recovery of an
additional $3.0 million in such expenditures. In an Order in that case released
March 2, 1998, the VPSB suspended the amortization of expenditures associated
with the Pine Street Barge Canal site pending further proceedings. Although it
did not eliminate the rate base deferral of these expenditures, or make any
specific order in this regard, the VPSB indicated that it was inclined to agree
with other parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance carriers
and other PRPs, should be shared between customers and shareholders of the
Company. In some other jurisdictions, "sharing" has been accomplished by
allowing utilities to recover costs over time without a rate of return. In
response to our Motion for Reconsideration, the VPSB on June 8, 1998 stated its
intent was "to reserve for a future docket issues pertaining to the sharing of
remediation-related costs between the Company and its customers". The
Settlement Order released January 23, 2001 did not change the status of Pine
Street Barge Canal site cost recovery.
CLEAN AIR ACT-Because we purchase most of our power supply from other utilities,
we do not anticipate that we will incur any material direct cost increases as a
result of the Federal Clean Air Act or proposals to make more stringent
regulations under that Act. Furthermore, only one of our power supply purchase
contracts, which expired in early 1998, related to a generating plant that was
affected by Phase I of the acid rain provisions of this legislation, which went
into effect January 1, 1995.
RATES
RETAIL RATE CASES- 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 a 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 the Company's 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.
The VPSB, in its order approving VY's sale of its nuclear power plant to
Entergy, ordered the Company and Central Vermont Public Service each to file on
or before April 15, 2003, a cost-of-service study based on actual 2002 data, to
enable the VPSB to determine whether an adjustment to rates is justified in 2003
or 2004. The Company believes this filing will support the Company's current
rates and does not intend to request a rate increase or decrease when this
filing is made. The VPSB could initiate an investigation of the Company's rates
based on this filing, requiring the Company to complete a rate case, and the
VPSB could order an adjustment to the Company's rates based on its findings and
conclusions. If the VPSB ordered the Company to reduce its rates in 2003 or
2004, this could have a material adverse effect on our operating results, cash
flows and ability to pay dividends at current levels.
LIQUIDITY AND CAPITAL RESOURCES
CONSTRUCTION-Our capital requirements result from the need to construct
facilities or to invest in programs to meet anticipated customer demand for
electric service. Capital expenditures, net of customer advances for
construction, over the past three years and forecasted for 2003 are as follows:
Generation Transmission Distribution Conservation Other* Total
----------- ------------- ------------- ------------ ------- -------
(In thousands)
Actual:
- --------------
2000 . . . . . $ 1,937 $ 348 $ 7,316 ** $ 5,876 $15,477
2001 . . . . . 2,323 1,219 8,567 ** 3,529 15,638
2002 . . . . . 3,258 1,827 9,173 ** 7,267 21,525
Forecast:
- ------------
2003 . . . . . $ 2,578 $ 3,200 $ 8,638 ** $ 8,088 $22,504
* Other includes $1.3 million in 2000, $1.5 million in 2001, $1.8 million in
2002, and an estimated $2.3 million in 2003 for the Pine Street Barge Canal
site.
**A statewide Energy Efficiency Utility set up by the VPSB in 1999 manages all
energy efficiency programs, receiving funds the Company bills to its customers
as a separate charge.
DIVIDEND POLICY- The annual dividend was $0.60 per share for the year ended
December 31, 2002. The Settlement Order had limited the annual dividend rate at
its then current level of $0.55 per share until short-term credit facilities
were replaced with long-term debt or equity financing. The Company used
proceeds of a $42 million long-term debt issue in December 2002 to replace all
short-term borrowings, satisfying the conditions in the Settlement Order and
permitting the Company to raise its dividend. 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. The Company believes
this payout ratio to be consistent with that of other utilities having similar
risk profiles.
FINANCING AND CAPITALIZATION-Internally-generated funds provided approximately
49 percent, 100 percent, and 41 percent, of requirements for 2002, 2001 and
2000, respectively. The 2002 rate of internally generated funding requirements
was reduced because of accelerated redemptions of preferred stock and common
stock repurchases described in more detail below. Internally generated funds,
after payment of dividends, provide capital requirements for construction,
sinking funds and other requirements. We anticipate that for 2003, internally
generated funds will provide approximately 71 percent of total capital
requirements for regulated operations, the remainder to be derived from bank
loans.
The Company is not dependent on the use of off-balance sheet financing
arrangements, such as securitization of receivables or obtaining access to
assets through special purpose entities. We do have material power supply
commitments that are discussed in detail under the captions "Power Contract
Commitments" and "Power Supply Expenses". We also own an equity interest in
VELCO, which requires the Company to contribute capital when required and to pay
a portion of VELCO's operating costs.
At December 31, 2002, our capitalization consisted of 47.6 percent common
equity and 52.4 percent long-term debt.
The Company has a $20.0 million 364-day revolving credit agreement with
Fleet Financial Services ("Fleet") joined by KeyBank National Association
("KeyBank"), expiring June 2003 (the "Fleet-Key Agreement"). The Fleet-Key
Agreement is unsecured and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There was $2.5 million
outstanding with a weighted average rate of 4.25 percent on the Fleet-Key
Agreement at December 31, 2002. There was no non-utility short-term debt
outstanding at December 31, 2002 or 2001.
The Company negotiated a $12.0 million, two-year, unsecured loan agreement
with Fleet, joined by KeyBank, on August 24, 2001. The $12.0 million loan was
repaid on December 16, 2002.
On March 15, 2002, the Company redeemed $5.1 million of the 10.0 percent
first mortgage bonds due June 1, 2004.
During March and June 2002, the Company repurchased $11.0 and $1.0 million,
respectively, of the 7.32 percent Class E preferred stock outstanding. On May
1, 2002, the Company redeemed $0.3 million of the 7.0 percent Class C preferred
stock outstanding. During November 2002, the Company redeemed $0.2 million of
the 9.375 percent Class D preferred stock outstanding.
On November 19, 2002, the Company completed a "Dutch Auction"
self-tender offer and repurchased 811,783 shares, or approximately 14 percent,
of its common stock outstanding for approximately $16.3 million.
See Note D, Preferred Stock, and Note F, Long Term Debt for additional
information.
The Company anticipates that it will secure financing that replaces some or
all of its expiring facilities during 2003.
The credit ratings of the Company's securities at December 31, 2002 are:
Fitch Moody's Standard & Poor's
First mortgage bonds BBB+ Baa1 BBB
Preferred stock BBB Ba1 BB
On August 29, 2002, Moody's upgraded the Company's senior secured debt rating to
Baa1 from Baa2. The outlook for the rating is stable. On September 29, 2002,
Fitch Ratings upgraded the rating of the Company's first mortgage bonds to BBB+
from BBB, with a stable outlook. On September 23, 2002, Standard and Poor's
Ratings Services affirmed its BBB rating of the Company's senior secured debt,
with a stable outlook.
In the event of a change in the Company's first mortgage bond credit
rating to below investment grade, scheduled payments under the Company's first
mortgage bonds would not be affected. Such a change would require the Company
to post what would currently amount to a $4.3 million bond under our remediation
agreement with the EPA regarding the Pine Street Barge Canal site. The MS
contract requires credit assurances if the Company's first mortgage bond credit
ratings are lowered to below investment grade by any two of the three credit
rating agencies listed above.
The following table presents a summary of certain material contractual
obligations existing as of December 31, 2002.
Payments Due by Period
----------------------
2004 and 2006 and After
TOTAL 2003 2005 2007 2007
- ------------------------------------ ---------- -------- -------- --------
(In thousands)
Long-term debt . . . . . . . . . . . $ 101,000 $ 8,000 $ - $ 14,000 $ 79,000
Interest on long-term debt . . . . . 72,797 7,047 13,068 12,068 40,614
Preferred stock. . . . . . . . . . . 85 30 55 - -
Capital lease obligations. . . . . . 5,287 407 814 814 3,252
Hydro-Quebec power supply contracts. 671,268 47,285 101,368 101,872 420,743
MS power supply contract . . . . . . 184,108 55,884 83,941 44,283 -
Vermont Yankee . . . . . . . . . . . 296,909 36,308 64,421 64,130 132,050
---------- -------- -------- -------- --------
Total. . . . . . . . . . . . . . $1,331,454 $154,961 $263,667 $237,167 $675,659
========== ======== ======== ======== ========
PENSION. Due to sharp declines in the equity markets during 2001 and 2002, the
value of assets held in trusts to satisfy the Company's pension plan obligations
has decreased. The Company's pension plan assets are primarily made up of
public 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 pension costs in future periods.
The Company's funding policy is to make voluntary contributions to its
defined benefit plans before ERISA or Pension Benefit Guaranty Corporation
requirements mandate such contributions under minimum funding rules, and so long
as the Company's liquidity needs do not preclude such investments. The Company
made voluntary pension plan contributions totaling $1.0 million between
September 1, 2002 and December 31, 2002. The Company plans to make additional
voluntary contributions totaling $1.0 million before June 30, 2003. The
Company's pension costs and cash funding requirements could increase in future
years in the absence of recovery in the equity markets.
OTHER REGULATORY PROCEEDINGS AND LITIGATION-In a series of Vermont regulatory
proceedings, the Company has agreed to undertake a process known as "distributed
utility planning" as part of its transmission and distribution planning process.
Distributed utility planning requires the Company to evaluate
conservation-related alternatives and distributed generation alternatives to
typical transmission and distribution capital investments. In certain
circumstances, the Company may be required to implement conservation or
distributed generation alternatives in lieu of, or in addition to, traditional
transmission and distribution capital investments, where societal cost savings
associated with conservation or distributed generation, including the costs
associated with avoided electricity sales, justify the expenditures. The
Company is uncertain of the potential magnitude of future spending requirements
for this program, but note they could be material. Costs associated with
conservation measures or distributed generation facilities not owned by the
Company would be deferred as regulatory assets pending future rate proceedings.
In 2002, the owners of property along the shoreline of Joe's Pond, an
impoundment located in Danville, Vermont, created by the Company's West Danville
Dam hydroelectric generating facility, filed an inquiry with the VPSB seeking
review of certain dam improvements made by the Company in 1995, complaining that
the Company did not obtain all necessary regulatory approvals for the 1995
improvements and that the Company's improvements and subsequent operation of the
dam have caused flooding of the shoreline and property damage. The Company has
petitioned the VPSB to make additional dam improvements at the facility at an
estimated cost of $350,000. The VPSB must approve the Company's petition before
the proposed improvements can be implemented. This regulatory proceeding is
pending and the Company is unable to predict whether the Company's petition will
be approved or whether the VPSB will impose regulatory conditions or penalties.
FUTURE OUTLOOK
COMPETITION AND RESTRUCTURING-The electric utility business are experiencing
rapid and substantial changes. These changes are the result of the following
trends:
* disparity in electric rates, transmission, and generating capacity among
and within various regions of the country;
* improvements in generation efficiency;
* increasing demand for customer choice;
* new regulations and legislation intended to foster competition, also known
as restructuring; and
* increasing volatility of wholesale market prices for electricity.
Electric utilities historically have had exclusive franchises for the
retail sale of electricity in specified service territories. As a result,
competition for retail customers has been limited to:
* competition with alternative fuel suppliers, primarily for heating and
cooling;
* competition with customer-owned generation; and
* direct competition among electric utilities to attract major new
facilities to their service territories.
These competitive pressures have led the Company and other utilities to
offer, from time to time, special discounts or service packages to certain large
customers.
In certain states across the country, including all the New England states
except Vermont, legislation has been enacted to allow retail customers to choose
their electricity suppliers, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems (also known as
retail wheeling). Increased pressure in the electric utility industry may
restrict the Company's ability to charge energy prices sufficient to recover
costs of service, such as the cost of purchased power obligations or of
generation facilities owned by the Company. The amount by which such costs
might exceed market prices is commonly referred to as stranded costs.
Regulatory and legislative authorities at the federal level and in some
states, including Vermont (where legislation has not been enacted), are
considering whether, when and how to facilitate competition for electricity
sales at the retail level. Recent difficulties in some regulatory
jurisdictions, such as California, have dampened any immediate push towards
deregulation in Vermont. Alternate forms of performance-based regulation
currently appear as possible intermediate steps towards deregulation. However,
in the future, the Vermont General Assembly through legislation, or the VPSB
through a subsequent report, action or proceeding, may allow customers to choose
their electric supplier. If this happens without providing for recovery of the
costs associated with our power supply obligations and other costs of providing
vertically integrated service, the Company's franchise, including our operating
results, cash flows and ability to pay dividends at the current level, would be
adversely affected.
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.
NUCLEAR DECOMMISSIONING-The staff of the SEC has questioned certain current
accounting practices of the electric utility industry regarding the recognition,
measurement and classification of decommissioning costs for nuclear generating
units in financial statements. In response to these questions, the Financial
Accounting Standards Board ("FASB") had agreed to review the accounting for
closure and removal costs, including decommissioning. The FASB issued a new
statement in August 2001 for "Accounting for Asset Retirement Obligations",
which provides guidance on accounting for nuclear plant decommissioning costs,
as well as other asset retirement costs. The Company has not yet determined
what impact, if any, the new accounting standard will have on its investment in
VY. We do not believe that changes in such accounting, if required, would have
an adverse effect on the results of our operations due to our current and future
ability to recover decommissioning costs through rates.
EFFECTS OF INFLATION-Financial statements are prepared in accordance with
generally accepted accounting principles and report operating results in terms
of historic costs. This accounting provides reasonable financial statements but
does not always take inflation into consideration. As rate recovery is based on
these historical costs and known and measurable changes, the Company is able to
receive some rate relief for inflation. It does not receive immediate rate
recovery relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation on
plant costs are generally offset by the fact that these assets are financed
through long-term debt.
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Financial Statements Page
Consolidated Statements of Income and Other Comprehensive 43
Income For the Years Ended December 31, 2002, 2001, and 2000
Consolidated Statements of Cash Flows For the 44
Years Ended December 31, 2002, 2001, and 2000
Consolidated Balance Sheets as of 45
December 31, 2002 and 2001
Consolidated Statement of Changes In Shareholders Equity 47
For the Years Ended December 31, 2002, 2001 and 2000
Consolidated Capitalization Data as of 48
December 31, 2002 and 2001
Notes to Consolidated Financial Statements 49
Quarterly Financial Information 73
Reports of Independent Public Accountants 74
Schedules
For the Years Ended December 31, 2002, 2001, and 2000:
II Valuation and Qualifying Accounts and Reserves 76
All other schedules are omitted as they are either
not required, not applicable or the information is
otherwise provided.
Consent and Report of Independent Public Accountants
Arthur Andersen LLP 77
Deloitte and Touche LLP
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31
2002 2001 2000
--------- --------- ---------
(In thousands, except per share data)
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . $274,608 $283,464 $277,326
OPERATING EXPENSES
Power Supply
Vermont Yankee Nuclear Power Corporation . . . . . . . . . . . . . . . 35,252 30,114 34,813
Company-owned generation . . . . . . . . . . . . . . . . . . . . . . . 5,067 4,742 7,777
Purchases from others. . . . . . . . . . . . . . . . . . . . . . . . . 153,129 166,209 168,947
Other operating. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,188 15,924 17,644
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,221 14,130 14,237
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,854 7,108 6,633
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . 14,151 14,294 15,304
Taxes other than income. . . . . . . . . . . . . . . . . . . . . . . . . 7,623 7,536 7,402
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,043 6,948 (691)
--------- --------- ---------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . 259,528 267,005 272,066
--------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,080 16,459 5,260
--------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. . . . . . . 2,777 2,253 2,495
Allowance for equity funds used during construction. . . . . . . . . . . 233 210 284
---------
Other (deductions) income, net . . . . . . . . . . . . . . . . . . . . . (525) (90) (73)
--------- --------- ---------
Total other income . . . . . . . . . . . . . . . . . . . . . . . . . 2,485 2,373 2,706
--------- --------- ---------
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 17,565 18,832 7,966
--------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,214 6,073 6,499
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,059 1,154 986
Allowance for borrowed funds used during construction. . . . . . . . . . (103) (188) (228)
--------- --------- ---------
Total interest charges . . . . . . . . . . . . . . . . . . . . . . . 6,170 7,039 7,257
--------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND
DISCONTINUED OPERATIONS. . . . . . . . . . . . . . . . . . . . . . . . . 11,395 11,793 709
Dividends on preferred stock . . . . . . . . . . . . . . . . . . . . . . 96 933 1,014
--------- --------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS . . . . . . . . . . . . . . . . 11,299 10,860 (305)
Income (Loss) on disposal, including provisions for
operating losses during phaseout period, net of applicable income taxes. 99 (182) (6,549)
--------- --------- ---------
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . . . . . . . $ 11,398 $ 10,678 $ (6,854)
========= ========= =========
EARNINGS PER SHARE
Basic earnings (loss) per share from continuing operations . . . . . . . $ 2.02 $ 1.93 $ (0.06)
Basic earnings (loss) per share from discontinued operations . . . . . . 0.02 (0.03) (1.19)
--------- --------- ---------
Basic earnings (loss) per share. . . . . . . . . . . . . . . . . . . . . $ 2.04 $ 1.90 $ (1.25)
========= ========= =========
Diluted earnings (loss) per share from continuing operations . . . . . . $ 1.96 $ 1.88 $ (0.06)
Diluted earnings (loss) per share from discontinued operations . . . . . 0.02 (0.03) (1.19)
--------- --------- ---------
Diluted earnings (loss) per share. . . . . . . . . . . . . . . . . . . . $ 1.98 $ 1.85 $ (1.25)
========= ========= =========
Cash dividends declared per share. . . . . . . . . . . . . . . . . . . . $ 0.60 $ 0.55 $ 0.55
Weighted average shares outstanding-basic. . . . . . . . . . . . . . . . 5,592 5,630 5,491
Weighted average equivalent shares outstanding-diluted . . . . . . . . . 5,756 5,789 5,491
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME . . . . . . . . . . . . . 2002 2001 2000
--------- --------- ---------
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 11,398 $ 10,678 $ (6,854)
Minimum pension liability adjustment, net of $1,612 related income tax . (2,374) - -
--------- --------- ---------
Other comprehensive income, net of tax . . . . . . . . . . . . . . . . $ 9,024 $ 10,678 $ (6,854)
========= ========= =========
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED
(in thousands) DECEMBER 31,
2002 2001 2000
--------- --------- ---------
OPERATING ACTIVITIES:
Net income (loss) before preferred dividends. . . . . . $ 11,494 $ 11,611 $ (5,840)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization . . . . . . . . . . . . . 14,151 14,294 15,304
Dividends from associated companies less equity income. 415 280 (26)
Allowance for funds used during construction. . . . . . (335) (398) (512)
Amortization of deferred purchased power costs. . . . . 3,236 3,767 5,575
Deferred income taxes . . . . . . . . . . . . . . . . . 2,430 (2,167) 161
Provision for chargeoff of deferred regulatory asset. . - - 3,229
Deferred purchased power costs. . . . . . . . . . . . . (2,003) 1,126 (6,692)
Accrued purchase power contract option call . . . . . . - (8,276) 8,276
Adjustment to provision for loss on segment disposal. . (99) 182 6,549
Arbitration costs recovered (deferred). . . . . . . . . - 3,229 (3,184)
Rate levelization liability . . . . . . . . . . . . . . (4,483) 8,527 -
Environmental and conservation deferrals, net . . . . . (2,194) (3,380) (2,073)
Changes in:
Accounts receivable and accrued utility revenues. . . . (896) 6,483 (3,987)
Prepayments, fuel and other current assets. . . . . . . 850 300 (931)
Accounts payable and other current liabilities. . . . . (55) 128 (4,337)
Accrued income taxes payable and receivable . . . . . . 5,010 1,187 (372)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 1,556 (1,603) (181)
--------- --------- ---------
Net cash provided by continuing operations. . . . . . . 29,077 35,290 10,959
Net change in discontinued segment. . . . . . . . . . . - (1,797) 245
--------- --------- ---------
Net cash provided by operating activities . . . . . . . 29,077 33,493 11,204
INVESTING ACTIVITIES:
Construction expenditures . . . . . . . . . . . . . . . (19,543) (12,963) (13,853)
Investment in associated companies. . . . . . . . . . . (392) - -
Proceeds from subsidiary sales. . . . . . . . . . . . . - - 6,000
Investment in nonutility property . . . . . . . . . . . (206) (212) (187)
--------- --------- ---------
Net cash used in investing activities . . . . . . . . . (20,141) (13,175) (8,041)
--------- --------- ---------
FINANCING ACTIVITIES:
Proceeds from issuance of long term debt. . . . . . . . 42,000 - -
Payments to acquire treasury stock. . . . . . . . . . . (16,319) - -
(Reduction in) Proceeds from term loan. . . . . . . . . (12,000) 12,000 -
Repurchase of preferred stock . . . . . . . . . . . . . (12,536) (235) (1,640)
Issuance of common stock. . . . . . . . . . . . . . . . 1,037 1,655 1,250
Proceeds (purchases) of certificate of deposit. . . . . - 16,173 (15,437)
Power supply option obligation. . . . . . . . . . . . . - (16,012) 15,419
Reduction in long-term debt . . . . . . . . . . . . . . (13,322) (9,700) (6,700)
Short-term debt, net. . . . . . . . . . . . . . . . . . 2,500 (15,500) 7,600
Cash dividends. . . . . . . . . . . . . . . . . . . . . (3,393) (4,034) (4,011)
--------- --------- ---------
Net cash used in financing activities . . . . . . . . . (12,033) (15,653) (3,520)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents. . (3,097) 4,665 (356)
Cash and cash equivalents at beginning of period. . . . 5,006 341 696
--------- --------- ---------
Cash and cash equivalents at end of period. . . . . . . $ 1,909 $ 5,006 $ 341
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized) . . . . . . . . . $ 6,048 $ 6,936 $ 7,185
Income taxes. . . . . . . . . . . . . . . . . . . . . . 2,349 9,622 1,191
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Minimum pension liability adjustment, net . . . . . . . $ 2,374 $ - $ -
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
2002 2001
-------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost. . . . . . . . $311,543 $302,489
Less accumulated depreciation. . . . . . . . . 122,197 119,054
-------- --------
Net utility plant. . . . . . . . . . . . . . . 189,346 183,435
Property under capital lease . . . . . . . . . 5,287 5,959
Construction work in progress. . . . . . . . . 8,896 7,464
-------- --------
Total utility plant, net . . . . . . . . . . . 203,529 196,858
-------- --------
OTHER INVESTMENTS
Associated companies, at equity. . . . . . . . 14,101 14,093
Other investments. . . . . . . . . . . . . . . 7,451 6,852
-------- --------
Total other investments. . . . . . . . . . . . 21,552 20,945
-------- --------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . 1,909 5,006
Accounts receivable, less allowance for
doubtful accounts of $547 and $613 . . . . . . 17,253 17,111
Accrued utility revenues . . . . . . . . . . . 6,618 5,864
Fuel, materials and supplies, at average cost. 3,349 4,058
Prepayments. . . . . . . . . . . . . . . . . . 1,901 1,976
Income tax receivable. . . . . . . . . . . . . - 1,699
Other. . . . . . . . . . . . . . . . . . . . . 402 469
-------- --------
Total current assets . . . . . . . . . . . . . 31,432 36,183
-------- --------
DEFERRED CHARGES
Demand side management programs. . . . . . . . 6,434 6,961
Purchased power costs. . . . . . . . . . . . . 2,323 3,504
Pine Street Barge Canal. . . . . . . . . . . . 13,019 12,425
Power supply derivative deferral . . . . . . . 18,405 37,313
Other. . . . . . . . . . . . . . . . . . . . . 11,413 12,265
-------- --------
Total deferred charges . . . . . . . . . . . . 51,594 72,468
-------- --------
NON-UTILITY
Other current assets . . . . . . . . . . . . . 8 8
Property and equipment . . . . . . . . . . . . 249 250
Other assets . . . . . . . . . . . . . . . . . 738 817
-------- --------
Total non-utility assets . . . . . . . . . . . 995 1,075
-------- --------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . $309,102 $327,529
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
2002 2001
--------- ---------
(in thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,782,496 and 5,701,010 ) . . . . . . . . . . . . . $ 19,276 $ 19,004
Additional paid-in capital. . . . . . . . . . . . . 75,347 74,581
Retained earnings . . . . . . . . . . . . . . . . . 16,171 8,070
Accumulated other comprehensive income. . . . . . . (2,374) -
Treasury stock, at cost (827,639 and 15,856 shares) (16,698) (378)
--------- ---------
Total common stock equity . . . . . . . . . . . . . 91,722 101,277
Redeemable cumulative preferred stock . . . . . . . 55 12,325
Long-term debt, less current maturities . . . . . . 93,000 74,400
--------- ---------
Total capitalization. . . . . . . . . . . . . . . . 184,777 188,002
--------- ---------
CAPITAL LEASE OBLIGATION. . . . . . . . . . . . . . 5,287 5,959
--------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock . . . . . . . 30 235
Current maturities of long-term debt. . . . . . . . 8,000 9,700
Short-term debt . . . . . . . . . . . . . . . . . . 2,500 -
Accounts payable, trade and accrued liabilities . . 7,431 7,237
Accounts payable to associated companies. . . . . . 8,940 8,361
Rate levelization liability . . . . . . . . . . . . 4,091 8,527
Customer deposits . . . . . . . . . . . . . . . . . 898 971
Interest accrued. . . . . . . . . . . . . . . . . . 1,081 1,100
Other . . . . . . . . . . . . . . . . . . . . . . . 5,520 2,945
--------- ---------
Total current liabilities . . . . . . . . . . . . . 38,491 39,076
--------- ---------
DEFERRED CREDITS
Power supply derivative liability . . . . . . . . . 18,405 37,313
Accumulated deferred income taxes . . . . . . . . . 26,471 23,759
Unamortized investment tax credits. . . . . . . . . 3,130 3,413
Pine Street Barge Canal cleanup liability . . . . . 8,833 10,059
Other . . . . . . . . . . . . . . . . . . . . . . . 21,767 18,247
--------- ---------
Total deferred credits. . . . . . . . . . . . . . . 78,606 92,791
--------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Net liabilities of discontinued segment . . . . . . 1,941 1,701
--------- ---------
Total non-utility liabilities . . . . . . . . . . . 1,941 1,701
--------- ---------
TOTAL CAPITALIZATION AND LIABILITIES. . . . . . . . $309,102 $327,529
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
ACCUMULATED
COMMON STOCK PAID-IN RETAINED COMPREHENSIVE TREASURY STOCK
SHARES AMOUNT CAPITAL EARNINGS OTHER INCOME STOCK EQUITY
---------------------- -------- --------- ---------- -------------- --------- ---------
(Dollars in thousands)
BALANCE, DECEMBER 31, 1999 . . . 5,409,715 $18,085 $ 72,594 $ 10,344 $ - $ (378) $100,645
---------------------- -------- --------- ---------- -------------- --------- ---------
Common Stock Issuance:
DRIP and ESIP. . . . . . . . . . 157,790 526 764 - - - 609
Compensation Program:
Restricted Shares . . . . . . (809) (3) (37) - - - (40)
Net Loss . . . . . . . . . . . . - - - (5,840) - - (5,840)
Other Comprehensive Income . . . -
Common Stock Dividends . . . . . - - - (2,997) - - (2,997)
Preferred Stock Dividends: . . . - - - (1,014) - - (1,014)
---------------------- -------- --------- ---------- -------------- --------- ---------
BALANCE, DECEMBER 31, 2000 . . . 5,566,696 18,608 73,321 493 - (378) 92,044
---------------------- -------- --------- ---------- -------------- --------- ---------
Common Stock Issuance:
DRIP and ESIP. . . . . . . . . . 105,767 352 1,218 - - - 1,570
Compensation Programs:
Restricted Shares and ISOP. . 12,691 44 42 - - - 86
Net Income . . . . . . . . . . . - - - 11,611 - - 11,611
Other Comprehensive Income
Common Stock Dividends . . . . . - - - (3,101) - - (3,101)
Preferred Stock Dividends: . . . - - - (933) - - (933)
---------------------- -------- --------- ---------- -------------- --------- ---------
BALANCE, DECEMBER 31, 2001 . . . 5,685,154 19,004 74,581 8,070 - (378) 101,277
---------------------- -------- --------- ---------- -------------- --------- ---------
Common Stock Issuance:
DRIP and ESIP. . . . . . . . . . 28,682 95 424 - - - 519
Common stock repurchase. . . . . (811,783) - - - - (16,320) (16,320)
Compensation Programs:
Restricted Shares and ISOP. . 52,804 177 342 - - - 519
Net Income . . . . . . . . . . . - - - 11,494 - - 11,494
Other Comprehensive Income(Loss) - - - - (2,374) - (2,374)
Common Stock Dividends . . . . . - - - (3,297) - - (3,297)
Preferred Stock Dividends: . . . - - - (96) - - (96)
---------------------- -------- --------- ---------- -------------- --------- ---------
BALANCE, DECEMBER 31, 2002 . . . 4,954,857 $19,276 $ 75,347 $ 16,171 $ (2,374) $(16,698) $ 91,722
---------------------- -------- --------- ---------- -------------- --------- ---------
The accompanying notes are an integral part of the consolidated financial
statements.
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION At December 31,
SHARES
ISSUED AND OUTSTANDING
----------------------
AUTHORIZED 2002 2001 2002 2001
- ---------------------------------- ---------- --------- --------- -------
(In thousands)
COMMON STOCK
Common Stock, $3.33 1/3 par value. 10,000,000 4,954,857 5,685,154 $19,276 $19,004
======= =======
OUTSTANDING
-----------
AUTHORIZED ISSUED 2002 2001 2002 2001
- --------------------------------------- --------------- -------- ---- ------- -----
Shares (In thousands)
---------------------------------------
REDEEMABLE CUMULATIVE PREFERRED STOCK,
100 PAR VALUE
4.75%, Class B, redeemable at
101 per share. . . . . . . . . . . . . 15,000 15,000 850 1,150 $ 85 $ 115
7%, Class C . . . . . . . . . . . . . . 15,000 15,000 - 2,850 - 285
9.375%, Class D, Series 1,. . . . . . . 40,000 40,000 - 1,600 - 160
7.32%, Class E, Series 1. . . . . . . . 200,000 120,000 - 120,000 - 12,000
----- -------
TOTAL PREFERRED STOCK . . . . . . . . . $ 85 $ 12,560
=============== ========
2002 2001
-------- -------
(In thousands)
LONG-TERM DEBT
Fleet/Key Term Loan due August 2003. . . . . . . . . . . . $ - $12,000
FIRST MORTGAGE BONDS
6.29% Series due 2002. . . . . . . . . . . . . . . . . . . - 8,000
6.41% Series due 2003. . . . . . . . . . . . . . . . . . . 8,000 8,000
10.0% Series due 2004. . . . . . . . . . . . . . . . . . . - 5,100
7.05% Series due 2006. . . . . . . . . . . . . . . . . . . 4,000 4,000
7.18% Series due 2006. . . . . . . . . . . . . . . . . . . 10,000 10,000
6.7% Series due 2018 . . . . . . . . . . . . . . . . . . . 15,000 15,000
9.64% Series due 2020. . . . . . . . . . . . . . . . . . . 9,000 9,000
8.65% Series due 2022 - Cash sinking fund, commences 2012. 13,000 13,000
6.04 % Series due 2017-Cash sinking fund commences 2011. . 42,000 -
-------- -------
Total Long-term Debt Outstanding . . . . . . . . . . . . . 101,000 84,100
Less Current Maturities (due within one year). . . . . . . 8,000 9,700
-------- -------
TOTAL LONG-TERM DEBT, LESS CURRENT MATURITIES. . . . . . . $ 93,000 $74,400
======== =======
The accompanying notes are an integral part of these consolidated financial
statements.
Notes to Consolidated Financial Statements
A. SIGNIFICANT ACCOUNTING POLICIES
1. Organization and Basis of Presentation. Green Mountain Power
Corporation (the "Company") is an investor-owned electric services company
located in Vermont with a principal service territory that includes
approximately one-quarter of Vermont's population. Nearly all of the Company's
net income is generated from retail sales in its regulated electric utility
operation, which purchases and generates electric power and distributes it to
approximately 88,000 customers. At December 31, 2002, the Company's primary
unregulated subsidiary investment was Northern Water Resources, Inc. ("NWR"),
which had invested in energy generation, energy efficiency and wastewater
treatment projects across the United States. In 2000, the Company disposed of
most of the assets of NWR. Green Mountain Power Investment Company ("GMPIC")
was created in December 2002 to hold the Company's investments in Vermont Yankee
Nuclear Power Corporation ("Vermont Yankee" or "VY") and Vermont Electric Power
Company, Inc. ("VELCO"). The Company's remaining wholly owned subsidiaries,
which are not regulated by the Vermont Public Service Board ("VPSB" or the
"Board"), are Green Mountain Resources, Inc. ("GMRI"), which sold its remaining
interest in Green Mountain Energy Resources in 1999 and is currently inactive,
Green Mountain Propane Gas Company ("GMPG") and GMP Real Estate Corporation.
The results of these subsidiaries and the Company's unregulated rental water
heater program, excluding NWR, are included in earnings of affiliates and
non-utility operations in the Other (Deductions) Income section of the
Consolidated Statements of Income. Summarized financial information for these
subsidiaries, and the Company's unregulated water heater program, which earned
approximately $0.3 million in 2002 is as follows:
Years ended December 31,
2002 2001 2000
----- ------ ------
In thousands
Revenue. . . $ 997 $1,012 $1,034
Expense. . . 744 749 $ 696
----- ------ ------
Net Income . $ 253 $ 263 $ 338
===== ====== ======
The Company accounts for its investments in VY, VELCO, New England
Hydro-Transmission Corporation, and New England Hydro-Transmission Electric
Company using the equity method of accounting. The Company's share of the net
earnings or losses of these companies is also included in the Other Income
section of the Consolidated Statements of Income. See Note B and Note L for
additional information.
2. Regulatory Accounting. The Company's utility operations, including
accounting records, rates, operations and certain other practices of its
electric utility business, are subject to the regulatory authority of the
Federal Energy Regulatory Commission ("FERC") and the VPSB.
The accompanying consolidated financial statements conform to
accounting principles generally accepted in the United States applicable to
rate-regulated enterprises in accordance with Statement of Financial Accounting
Standards No. ("SFAS") 71 ("SFAS 71"), "Accounting for Certain Types of
Regulation". Under SFAS 71, the Company accounts for certain transactions in
accordance with permitted regulatory treatment. As such, regulators may permit
incurred costs, typically treated as expenses by unregulated entities, to be
deferred and expensed in future periods when recovered in future revenues.
Conditions that could give rise to the discontinuance of SFAS 71 include
increasing competition that restricts the Company's ability to recover specific
costs, and a change in the manner in which rates are set by regulators from
cost-based regulation to another form of regulation. In the event that the
Company no longer meets the criteria under SFAS 71, the Company would be
required to write off related regulatory assets and liabilities as summarized in
the following table:
SFAS 71 Deferred charges
At December 31,
2002 2001
------- -------
(in thousands)
Power Supply Derivative. . . $18,405 $37,313
Pine Street Barge Canal. . . 13,019 12,425
Power Supply . . . . . . . . 4,492 6,112
Demand Side Management . . . 6,434 6,961
Preliminary Survey . . . . . 1,202 1,094
Storm Damages. . . . . . . . 1,905 2,169
Regulatory Commission costs. 1,774 873
Tree Trimming. . . . . . . . 905 905
Restructuring Costs. . . . . 2,216 3,502
Other. . . . . . . . . . . . 1,242 1,114
------- -------
Total Deferred Charges . . . $51,594 $72,468
======= =======
The Company continues to believe, based on current regulatory circumstances,
that the use of regulatory accounting under SFAS 71 remains appropriate and that
its regulatory assets are probable of recovery. Regulatory entities that
influence the Company include the VPSB, the Vermont Department of Public Service
("DPS" or the "Department"), and the Federal Energy Regulatory Commission
("FERC"), among other federal, state and local regulatory agencies.
3. Impairment. The Company is required to evaluate long-lived assets,
including regulatory assets, for potential impairment. Assets that are no
longer probable of recovery through future revenues would be revalued based upon
future cash flows. Regulatory assets are charged to expense in the period in
which they are no longer probable of future recovery. As of December 31, 2002,
based upon the regulatory environment within which the Company currently
operates, the Company does not believe that an impairment loss should be
recorded. Competitive influences or regulatory developments may impact this
status in the future.
4. Utility Plant. The cost of plant additions includes all
construction-related direct labor and materials, as well as indirect
construction costs, including the cost of money ("Allowance for Funds Used
During Construction" or "AFUDC"). As part of a rate agreement with the DPS, the
Company discontinued recording AFUDC on construction work in progress in January
2001. The costs of renewals and improvements of property units are capitalized.
The costs of maintenance, repairs and replacements of minor property items are
charged to maintenance expense. The costs of units of property removed from
service, net of removal costs and salvage, are charged to accumulated
depreciation.
5. Depreciation. The Company provides for depreciation using the
straight-line method based on the cost and estimated remaining service life of
the depreciable property outstanding at the beginning of the year and adjusted
for salvage value and cost of removal of the property.
The annual depreciation provision was approximately 3.2 percent at the
beginning of 2002, 3.5 percent of total depreciable property at the beginning of
2001, and 3.5 percent at the beginning of 2000.
6. Cash and Cash Equivalents. Cash and cash equivalents include short-term
investments with original maturities less than ninety days.
7. Operating Revenues. Operating revenues consist principally of sales of
electric energy at regulated rates. Revenue is recognized when electricity is
delivered. The Company accrues utility revenues, based on estimates of electric
service rendered and not billed at the end of an accounting period, in order to
match revenues with related costs.
8. Deferred Charges. Prior to the sale of the Vermont Yankee ("VY")
nuclear generating plant (See Note B) the Company deferred and amortized certain
replacement power, maintenance and other costs associated with outages at the VY
generating plant. In addition, the Company accrued and amortized other
replacement power expenses to reflect more accurately its cost of service to
better match revenues and expenses consistent with regulatory treatment. The
Company also defers and amortizes costs associated with its investment in its
demand side management program and other regulatory assets, in a manner
consistent with authorized or expected ratemaking treatment.
Other deferred charges totaled $11.4 million and $12.3 million at December
31, 2002 and 2001, respectively, consisting of regulatory deferrals of storm
damages, rights-of-way maintenance, other employee benefits, preliminary survey
and investigation charges, transmission interconnection charges, regulatory tax
assets and various other projects and deferrals.
9. Earnings Per Share. Earnings per share are based on the weighted
average number of common and common stock equivalent shares outstanding during
each year. During the year ended December 31, 2000, the Company established a
stock incentive plan for all employees, and granted 335,300 options exercisable
over vesting schedules of between one and four years. During 2002 and 2001, the
Company granted additional options of 80,300 and 56,450, respectively. See Note
C for additional information. SFAS 123 requires disclosure of pro-forma
information regarding net income and earnings per share. The information
presented below has been determined as if the Company accounted for its employee
and director stock options under the fair value method of that statement.
Pro-forma net income (loss) For the years ended December 31,
2002 2001 2000
------- ------- --------
In thousands, except per share amounts
Net income (loss) reported. . . . . . . $11,398 $10,678 $(6,854)
Pro-forma net income (loss) . . . . . . $11,246 $10,527 $(6,911)
Net income (loss) per share
As reported-basic . . . . . . . . . . $ 2.04 $ 1.90 $ (1.25)
Pro-forma basic . . . . . . . . . . . $ 2.01 $ 1.87 $ (1.26)
As reported-diluted . . . . . . . . . $ 1.98 $ 1.85 $ (1.25)
Pro-forma diluted . . . . . . . . . . $ 1.95 $ 1.82 $ (1.26)
10. Major Customers. The Company had one major retail customer, International
Business Machines Corporation ("IBM"), that accounted for 25.7 percent, 26.6
percent, and 26.6 percent of retail MWh sales, and 17.3 percent, 19.2 percent
and 16.5 percent of the Company's retail operating revenues in 2002, 2001 and
2000, respectively.
11. Fair Value of Financial Instruments. The present value of the
Company's first mortgage bonds and preferred stock outstanding, if refinanced
using prevailing market rates of interest, would decrease from the balances
outstanding at December 31, 2002 by approximately 4.7 percent. In the event of
such a refinancing, there would be no gain or loss because under established
regulatory precedent, any such difference would be reflected in rates and have
no effect upon net income.
12. Deferred Credits. At December 31, 2002, the Company had other deferred
credits and long-term liabilities of $21.8 million, consisting of reserves for
damage claims and accruals for employee benefits, compared with a balance of
$18.2 million at December 31, 2001.
13. Environmental Liabilities. The Company is subject to federal,
state and local regulations addressing air and water quality, hazardous and
solid waste management and other environmental matters. Only those site
investigation, characterization and remediation costs currently known and
determinable can be considered "probable and reasonably estimable" under SFAS 5,
"Accounting for Contingencies". As costs become probable and reasonably
estimable, reserves are adjusted as appropriate. As reserves are recorded,
regulatory assets are recorded to the extent environmental expenditures are
expected to be recovered in rates. Estimates are based on studies provided by
third parties.
14. Income Taxes. The Company recognizes tax assets and liabilities
according to SFAS 109, "Accounting for Income Taxes", for the cumulative effect
of all temporary differences between financial statement carrying amounts and
the tax basis of assets and liabilities. Investment tax credits associated with
utility plant are deferred and amortized over the lives of the related assets.
Valuation allowances are provided when necessary against certain deferred tax
assets.
15. Purchased Power. The Company records the annual cost of power
obtained under long-term contracts as operating expenses.
SFAS 133 establishes accounting and reporting standards requiring
that every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded on the balance sheet as either an asset
or liability measured at its fair value. SFAS 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. SFAS 133, as amended by SFAS 137, was
effective for the Company beginning 2001.
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
mitigate 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.
On April 11, 2001, the VPSB issued an accounting order that requires the
Company to defer recognition of any earnings or other comprehensive income
effects relating to future periods caused by application of SFAS 133. At
December 31, 2002, the Company had a liability reflecting the net negative fair
value of the two derivatives described below, as well as a corresponding
regulatory asset of approximately $18.4 million. The Company believes that the
regulatory asset, determined using the Black's or Black-Scholes option valuation
method, is probable of recovery in future rates. The regulatory liability is
based on current estimates of future market prices that are likely to change by
material amounts.
If a derivative instrument is terminated early because it is probable
that a transaction or forecasted transaction will not occur, any gain or loss
would be recognized in earnings immediately. For derivatives held to maturity,
the earnings impact would be recorded in the period that the derivative is sold
or matures.
The Company has a contract with Morgan Stanley Capital Group,
Inc. ("MS") used to hedge against increases in fossil fuel prices. MS purchases
the majority of the Company's power supply resources at index (fossil fuel
resources) or specified (i.e., contracted resources) prices and then sells to us
at a fixed rate to serve pre-established load requirements. This contract
allows management to fix the cost of much of its power supply requirements,
subject to power resource availability and other risks. The MS contract is a
derivative under SFAS 133 and is effective through December 31, 2006.
Management's estimate of the fair value of the future net benefit of this
contract at December 31, 2002 is approximately $8.8 million.
We currently have an arrangement that grants Hydro-Quebec an option
("9701") to call power at prices below current and estimated future market
rates. This arrangement is a derivative and is effective through 2015.
Management's estimate of the fair value of the future net cost for this
arrangement at December 31, 2002 is approximately $27.2 million. We use futures
contracts to hedge the 9701 call option.
16. Use of Estimates. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States
requires the use of estimates and assumptions that affect assets and
liabilities, the disclosure of contingent assets and liabilities, and revenues
and expenses. Actual results could differ from those estimates.
17. Reclassifications. Certain items on the prior year's consolidated
financial statements have been reclassified to be consistent with the current
year presentation.
18. New Accounting Standards. In June 2001, the FASB issued Statement
of Financial Accounting Standards No. 141, Business Combinations ("SFAS 141"),
and Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets ("SFAS 142"). SFAS 141 requires the use of the purchase
method to account for business combinations initiated after June 30, 2001 and
uses a non-amortization approach to purchased goodwill and other
indefinite-lived intangible assets. Under SFAS 142, effective for 2002,
goodwill and intangible assets deemed to have indefinite lives will no longer be
amortized and will be subject to annual impairment tests. The application of
these accounting standards does not materially impact the Company's financial
position or results of operations.
In August 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"),
effective for fiscal years beginning after June 15, 2002, which provides
guidance on accounting for nuclear plant decommissioning and other asset
retirement costs. SFAS 143 prescribes fair value accounting for asset
retirement liabilities, including nuclear decommissioning obligations, and
requires recognition of such liabilities at the time incurred. The application
of this accounting standard is not expected to materially impact the Company's
financial position or results of operations.
In October 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, "Accounting for the Impairment or Disposal of Long-lived
Assets" ("SFAS 144"). SFAS 144 specifies accounting and reporting for the
impairment or disposal of long-lived assets. The application of this accounting
standard does not materially impact the Company's financial position or results
of operations.
In June 2002, the FASB issued Statement of Financial Accounting
Standards No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities" ("SFAS 146"). SFAS 146 specifies accounting and reporting for costs
associated with exit or disposal activities. The application of this accounting
standard, which is effective for us during 2003, is not expected to materially
impact the Company's financial position or results of operations.
In December 2002, the FASB issued Statement of Financial Accounting
Standards No. 148, "Accounting for Stock-based Compensation-Transition and
Disclosure" ("SFAS 148"). SFAS 148 amends Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation", to provide
alternative methods of transition for a voluntary change to the fair value based
method of accounting and reporting for stock-based employee compensation. The
application of this accounting standard is not expected to materially impact the
Company's financial position or results of operations.
B. INVESTMENTS IN ASSOCIATED COMPANIES
The Company accounts for investments in the following associated
companies by the equity method:
PERCENT OWNERSHIP INVESTMENT IN EQUITY
AT DECEMBER 31, AT DECEMBER 31,
2002 2001 2002 2001
-------- -------- ------ ------
(IN THOUSANDS)
VELCO-common. . . . . . . . . . . . . . . 28.41% 29.50% $2,309 $1,932
VELCO-preferred . . . . . . . . . . . . . 30.00% 30.00% 305 420
------ ------
Total VELCO . . . . . . . . . . . . . . . 2,614 2,352
Vermont Yankee- Common. . . . . . . . . . 18.99% 17.88% 9,721 9,725
New England Hydro Transmission-Common . . 3.18% 3.18% 660 761
New England Hydro Transmission Electric-
Common. . . . . . . . . . . . . . . . 3.18% 3.18% 1,106 1,255
------ ------
Total investment in associated companies. $14,101 $14,093
======== ========
Undistributed earnings in associated companies totaled approximately $484,000 at
December 31, 2002.
VELCO. VELCO is a corporation engaged in the transmission of electric
power within the State of Vermont. VELCO has entered into transmission
agreements with the State of Vermont and other electric utilities, and under
these agreements, VELCO bills all costs, including interest on debt and a fixed
return on equity, to the State and others using VELCO's transmission system.
The Company's purchases of transmission services from VELCO were $12.7 million,
$11.5 million, and $9.8 million for the years 2002, 2001 and 2000, respectively.
Pursuant to VELCO's Amended Articles of Association, the Company is entitled to
approximately 29 percent of the dividends distributed by VELCO. The Company has
recorded its equity in earnings on this basis and also is obligated to provide
its proportionate share of the equity capital requirements of VELCO through
continuing purchases of its common stock, if necessary.
Summarized unaudited financial information for VELCO is as follows:
At and for the years ended December 31,
2002 2001 2000
-------- ------- -------
(In thousands)
Net income applicable to common stock. $ 1,094 $ 1,118 $ 1,257
Company's equity in net income . . . . $ 319 $ 308 $ 395
======== ======= =======
Total assets . . . . . . . . . . . . . $106,613 $89,322 $82,123
Less:
Liabilities and long-term debt . . . . 97,417 81,335 73,874
-------- ------- -------
Net assets . . . . . . . . . . . . . . $ 9,196 $ 7,987 $ 8,249
======== ======= =======
Company's equity in net assets . . . . $ 2,614 $ 2,352 $ 2,456
======== ======= =======
VERMONT YANKEE. On July 31, 2002, Vermont Yankee ("VY") announced that the sale
of its nuclear power plant to Entergy Nuclear Vermont Yankee ("Entergy") had
been completed. See Note K for further information concerning our long-term
power contract with VY.
During May 2002, prior to the sale of the plant to Entergy, the VY plant
had fuel rods that required repair, 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. The Company's share of the 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.
The Company's ownership share of VY has increased from approximately 17.9
percent in 2001 to approximately 19.0 percent currently, due to VY's purchase of
certain minority shareholders' interests. The Company's entitlement to energy
produced by the Entergy Vermont Yankee 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 increase in equity in earnings of VY resulted from VY's recognition of
certain deferred tax assets as a result of the sale of the nuclear plant.
Summarized unaudited financial information for Vermont Yankee is as follows:
At and for the years ended December 31,
2002 2001 2000
-------- -------- --------
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . $175,722 $178,840 $178,294
Net income applicable to common stock. 9,454 6,119 6,583
Company's equity in net income . . . . $ 1,745 $ 1,131 $ 1,177
======== ======== ========
Total assets . . . . . . . . . . . . . . $201,616 $723,815 $706,984
Less:
Liabilities and long-term debt . . . . 150,413 669,640 652,663
-------- -------- --------
Net Assets . . . . . . . . . . . . . . . $ 51,203 $ 54,175 $ 54,321
======== ======== ========
Company's equity in net assets . . . . . $ 9,721 $ 9,725 $ 9,641
======== ======== ========
C. COMMON STOCK EQUITY
The Company maintains a Dividend Reinvestment and Stock Purchase Plan
("DRIP") under which 416,328 shares were reserved and unissued at December 31,
2002. The Company also funds an Employee Savings and Investment Plan ("ESIP").
At December 31, 2002, there were 82,754 shares reserved and unissued under the
ESIP.
During 2000, the Company's Board of Directors, with subsequent approval of
the Company's common shareholders, established a stock incentive plan. Under
this plan, options for a total of 500,000 shares may be granted to any employee,
officer, consultant, contractor or director providing services to the Company.
Outstanding options become exercisable at between one and four years after the
grant date and remain exercisable until 10 years from the grant date.
As permitted by Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation ("SFAS 123"), the Company has elected
to follow Accounting Principles Board Opinion No. 25 ("APB 25") "Accounting for
Stock Issued to Employees", and related interpretations in accounting for its
employee stock options. Under APB 25, because the exercise price equals the
market price of the underlying stock on the date of grant, no compensation
expense is recorded. Options have only been issued to employees and directors.
The fair values of the options granted in 2002, 2001 and 2000 are
$2.27 $4.16 and $2.03 per share, respectively. They were estimated at the grant
date using the Black-Scholes option-pricing model. The following table presents
information about the assumptions that were used for each plan year, and a
summary of the options outstanding at December 31, 2002:
Weighted Assumptions used in option pricing model
---------------------------------------------
average Remaining Risk Free Expected Expected
Plan exercise Outstanding Contractual Interest Life in Stock Dividend
year price options Life rate Years Volatility Yield
------- ----------- ------- ------- - ---- ----------- -----
2000 $ 7.90 236,900 7.6 years 6.05% 5 30.58 4.5%
2001 $16.63 50,400 8.6 years 5.25% 6 32.69 4.0%
2002 $17.37 78,500 9.6 years 4.50% 6.5 16.89 4.5%
Total . . . $11.14 365,800
======= =======
Weighted Range of
Total Average Exercise Options
Options Price Prices Exercisable
------- ------ ------------- -----------
Outstanding at January 1, 2000 . - $ -
Granted. . . . . . . . . . . . . 335,300 7.90 $ 7.90
Exercised. . . . . . . . . . . . - -
Forfeited. . . . . . . . . . . . 3,400 7.90
Outstanding at December 31, 2000 331,900 $ 7.90 $ 7.90 -
------- ------ ------------- -----------
Granted. . . . . . . . . . . . . 55,450 $16.67 $14.50-$16.78
Granted. . . . . . . . . . . . . 1,000 12.28 $ 12.28
Exercised. . . . . . . . . . . . 17,400 7.90 $ 7.90
Forfeited. . . . . . . . . . . . 6,800 10.61 $ 7.90-$16.78
Outstanding at December 31, 2001 364,150 $ 9.20 $ 7.90-$16.78 95,350
------- ------ ------------- -----------
Granted. . . . . . . . . . . . . 80,300 17.82 $16.78-$17.83
Exercised. . . . . . . . . . . . 53,250 8.12 $ 7.90-$16.78
Forfeited. . . . . . . . . . . . 25,400 9.35 $ 7.90-$18.67
Outstanding at December 31, 2002 365,800 $11.23 $ 7.90-$17.82 151,775
======= ====== ============= ===========
Options granted are not exercisable until one year after the date of grant. The
pro-forma amounts may not be representative of future results and additional
options may be granted in future years. For 2000, the number of total shares
after giving effect to anti-dilutive common stock equivalents does not change.
The following table presents a reconciliation of net income to net
income available to common shareholders, and the average common shares to
average common equivalent shares outstanding:
Reconciliation of net income available For the years ended
for common shareholders and average shares December 31,
2002 2001 2000
------- ------- --------
(in thousands)
Net income (loss) before preferred dividends. $11,397 $11,611 $(5,840)
Preferred stock dividend requirement. . . . . 96 933 1,014
------- ------- --------
Net income (loss) applicable to common
stock. . . . . . . . . . . . . . . . . . . $11,493 $10,678 $(6,854)
======= ======= ========
Average number of common shares-basic . . . . 5,592 5,630 5,491
Dilutive effect of stock options. . . . . . . 164 159 -
------- ------- --------
Average number of common shares-diluted . . . 5,756 5,789 5,491
======= ======= ========
During 2000, the Compensation Program for Officers and Certain Key Management
personnel, that authorized payment of cash, restricted and unrestricted stock
grants based on corporate performance, was replaced with the stock incentive
plan discussed above. Approximately 1,262 restricted shares, issued during 1996
and 1997, became vested under this program during 2002, and no shares remain
unvested or unissued at December 31, 2002.
On November 19, 2002, the Company completed a "Dutch Auction"
self-tender offer and repurchased 811,783 common shares, or approximately 14
percent, of its common stock outstanding for approximately $16.3 million.
Dividend Restrictions. Certain restrictions on the payment of cash
dividends on common stock are contained in the Company's indentures relating to
long-term debt and in the Restated Articles of Association. Under the most
restrictive of such provisions, approximately $12.1 million of retained earnings
were free of restrictions at December 31, 2002.
The properties of the Company include several hydroelectric projects
licensed under the Federal Power Act, with license expiration dates ranging from
2001 to 2025. At December 31, 2002, $220,000 of retained deficit had been
appropriated as excess earnings on hydroelectric projects as required by Section
10(d) of the Federal Power Act.
D. PREFERRED STOCK
The holders of the preferred stock are entitled to specific voting
rights with respect to certain types of corporate actions. They are also
entitled to elect the smallest number of directors necessary to constitute a
majority of the Board of Directors in the event of preferred stock dividend
arrearages equivalent to or exceeding four quarterly dividends. Similarly, the
holders of the preferred stock are entitled to elect two directors in the event
of default in any purchase and sinking fund requirements provided for any class
of preferred stock.
The outstanding Class B preferred stock is subject to annual purchase and
sinking fund requirements. The sinking fund requirement is mandatory. The
purchase fund requirement is mandatory, but holders may elect not to accept the
purchase offer. The redemption or purchase price to satisfy these requirements
may not exceed $100 per share plus accrued dividends. All shares redeemed or
purchased in connection with these requirements must be canceled and may not be
reissued. The annual purchase and sinking fund requirements for the outstanding
Class B preferred stock is 300 shares in 2003 and 2004, and 250 shares in 2005.
Under the Restated Articles of Association relating to Redeemable
Cumulative Preferred Stock, the annual aggregate amount of purchase and sinking
fund requirements for the next three years are $30,000 each for 2003 and 2004,
and $25,000 for 2005.
Class B preferred stock is redeemable at the option of the Company or,
in the case of voluntary liquidation, at various prices on various dates. The
prices include the par value of the issue plus any accrued dividends and an
early redemption premium. The redemption premium for Class B is $1.00 per
share. During 2002, the Company repurchased all $12.0 million of the 7.32
percent Class E preferred stock outstanding. On May 1, 2002, the Company
redeemed $0.3 million of the 7.0 percent Class C preferred stock outstanding.
During November 2002, the Company redeemed the remaining $0.2 million of the
9.375 percent Class D preferred stock outstanding.
E. SHORT-TERM DEBT
The Company has a $20.0 million 364-day revolving credit agreement
with Fleet Financial Services ("Fleet") joined by KeyBank National Association
("KeyBank"), expiring June 2003 (the "Fleet-Key Agreement"). The Fleet-Key
Agreement is unsecured, and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There was $2.5 million
outstanding at a weighted average rate of 4.25 percent under the Fleet-Key
Agreement at December 31, 2002. There was no non-utility short-term debt
outstanding at December 31, 2002 or 2001.
The Fleet-Key Agreement requires the Company to certify on a quarterly
basis that it has not suffered a "material adverse change". Similarly, as a
condition to further borrowings, the Company must certify that no event has
occurred or failed to occur that has had or would reasonably be expected to have
a materially adverse effect on the Company since the date of the last borrowing
under this agreement. The Fleet-Key Agreement allows the Company to continue to
borrow until such time that:
* a "material adverse effect" has occurred; or
* the Company no longer complies with all other provisions of the agreement,
in which case further borrowing will not be permitted; or
* there has been a "material adverse change," in which case the banks may
declare the Company in default.
F. LONG-TERM DEBT
On December 16, 2002, the Company issued through private placement $42
million principal amount of first mortgage bonds bearing interest at 6.04
percent per year and maturing on December 1, 2017. The average duration of the
bond issuance is twelve years and the bonds are subject to seven equal annual
principal payments beginning on December 1, 2011. Proceeds were used to retire
all of the Company's short and intermediate term debt, and to repurchase 811,783
shares of the Company's common stock.
Substantially all of the property and franchises of the Company are
subject to the lien of the indenture under which first mortgage bonds have been
issued. The weighted average rate on long-term borrowings outstanding was 7.0
percent and 7.1 percent at December 31, 2002 and 2001, respectively. The annual
sinking fund requirements (excluding amounts that may be satisfied by property
additions) and long-term debt maturities for the next five years, as of December
31, 2002, are:
Sinking
Fund and
Maturities
-----------
2003 . . . . . . . . $ 8,000
2004 . . . . . . . . -
2005 . . . . . . . . -
2006 . . . . . . . . 14,000
2007 . . . . . . . . -
Thereafter . . . . . 79,000
Total Long-term debt $ 101,000
===========
On March 15, 2002, the Company redeemed the outstanding $5.1 million, 10.0%
first mortgage bonds due June 1, 2004.
The Company executed and delivered a $12.0 million, two-year,
unsecured loan agreement with Fleet, joined by KeyBank, on August 24, 2001.
This $12.0 million loan was repaid on December 16, 2002.
On August 29, 2002, Moody's upgraded the Company's senior secured debt
rating to Baa1 from Baa2. The outlook for the rating is stable. On September
29, 2002, Fitch Ratings upgraded the rating of the Company's first mortgage
bonds to BBB+ from BBB, with a stable outlook. On September 23, 2002, Standard
and Poor's Ratings Services affirmed its BBB rating of the Company's senior
secured debt, with a stable outlook.
G. INCOME TAXES
Utility. The Company accounts for income taxes using the liability method.
This method accounts for deferred income taxes by applying statutory rates to
the differences between the book and tax bases of assets and liabilities.
The regulatory tax assets and liabilities represent taxes that will be
collected from or returned to customers through rates in future periods. As of
December 31, 2002 and 2001, the net regulatory assets were $1,042,000 and
$1,096,000, respectively, and included in Other Deferred Charges on the
Company's consolidated balance sheets.
The temporary differences which gave rise to the net deferred tax
liability at December 31, 2002 and December 31, 2001, were as follows:
AT DECEMBER 31,
2002 2001
------- -------
(In thousands)
DEFERRED TAX ASSETS
Contributions in aid of construction. $11,130 $10,435
Deferred compensation and
postretirement benefits. . . . . 4,570 4,382
Self insurance and other reserves . . 1,369 -
Other . . . . . . . . . . . . . . . . 3,032 5,525
------- -------
$20,101 $20,342
------- -------
DEFERRED TAX LIABILITIES
Property related. . . . . . . . . . . $41,967 $39,518
Demand side management. . . . . . . . 1,870 2,059
Deferred purchased power costs. . . . 943 1,450
Pine Street reserve . . . . . . . . . 1,792 855
Other . . . . . . . . . . . . . . . . - 219
------- -------
$46,572 $44,101
------- -------
Net accumulated deferred income
tax liability . . . . . . . . . . $26,471 $23,759
======= =======
The following table reconciles the change in the net accumulated deferred income
tax liability to the deferred income tax expense included in the income
statement for the periods presented:
YEARS ENDED DECEMBER 31,
2002 2001 2000
-------- -------- -----
(In thousands)
Net change in deferred income tax . . $ 2,712 $(1,885) $ 443
liability
Change in income tax related
regulatory assets and liabilities . 2,759 (1,149) 184
Change in alternative minimum
tax credit. . . . . . . . . . . . . - - -
Change in tax effect of accumulated
other comprehensive income. . . . . (1,612) - -
-------- -------- -----
Deferred income tax expense (benefit) $ 3,859 $(3,034) $ 627
======== ======== =====
The components of the provision for income taxes are as follows:
YEARS ENDED DECEMBER 31,
2002 2001 2000
------- -------- --------
(In thousands)
Current federal income taxes . $1,873 $ 7,846 $ (786)
Current state income taxes . . 593 2,418 (249)
------- -------- --------
Total current income taxes . . 2,466 10,264 (1,035)
Deferred federal income taxes. 2,920 (2,296) 461
Deferred state income taxes. . 939 (738) 166
------- -------- --------
Total deferred income taxes. . 3,859 (3,034) 627
Investment tax credits-net . . (282) (282) (283)
------- -------- --------
Income tax provision (benefit) $6,043 $ 6,948 $ (691)
======= ======== ========
Total income taxes differ from the amounts computed by applying the federal
statutory tax rate to income before taxes. The reasons for the differences are
as follows:
YEARS ENDED DECEMBER 31,
2002 2001 2000
-------- -------- --------
(In thousands)
Income (loss) before income taxes and
preferred dividends . . . . . . . . . . . . $17,537 $18,559 $(6,531)
Federal statutory rate. . . . . . . . . . . . 34.0% 35.0% 34.0%
Computed "expected" federal income
taxes . . . . . . . . . . . . . . . . . . . 5,963 6,496 (2,221)
Increase (decrease) in taxes resulting from:
Tax versus book depreciation. . . . . . . . . 41 45 83
Dividends received and paid credit. . . . . . (575) (440) (435)
AFUDC-equity funds. . . . . . . . . . . . . . (80) (72) (33)
Amortization of ITC . . . . . . . . . . . . . (282) (282) (282)
State tax (benefit) . . . . . . . . . . . . . 1,011 1,705 (83)
Excess deferred taxes . . . . . . . . . . . . (60) (60) (60)
Tax attributable to subsidiaries. . . . . . . (31) 63 2,213
Other . . . . . . . . . . . . . . . . . . . . 56 (507) 127
-------- -------- --------
Total federal and state income tax (benefit). $ 6,043 $ 6,948 $ (691)
======== ======== ========
Effective combined federal and state
income tax rate . . . . . . . . . . . . . . 34.5% 37.4% 10.6%
Non-Utility. The Company's non-utility subsidiaries, excluding NWR, had
accumulated deferred income taxes of approximately $2,000 on their balance
sheets at December 31, 2002, attributable to depreciation timing differences.
The components of the provision for the income tax expense (benefit)
for the non-utility operations, excluding NWR, are:
YEARS ENDED DECEMBER 31,
2002 2001 2000
-------------------------- ------ -----
(In thousands)
State income taxes . . . . . $ (1) $ - $ 7
Federal income taxes . . . . (3) (1) 21
-------------------------- ------ -----
Income tax expense (benefit) $ (4) $ (1) $ 28
========================== ====== =====
The effective combined federal and state income tax rate for the
continuing non-utility operations was approximately 40 percent for each of the
years ended December 31, 2002, 2001 and 2000. See Note L for income tax
information on the discontinued operations of NWR.
H. PENSION AND RETIREMENT PLANS.
The Company has a defined benefit pension plan covering substantially all
of its employees. The retirement benefits are based on the employees' level of
compensation and length of service. The Company's policy is to fund all accrued
pension costs. The Company records annual expense and accounts for its pension
plan in accordance with Statement of Financial Accounting Standards No. 87,
Employers' Accounting for Pensions. The Company provides certain health care
benefits for retired employees and their dependents. Employees become eligible
for these benefits if they reach retirement age while working for the Company.
The Company accrues the cost of these benefits during the service life of
covered employees. The pension plan assets consist primarily of cash equivalent
funds, fixed income securities and equity securities.
Due to sharp declines in the equity markets during 2001 and 2002, the value
of assets held in trusts to satisfy the Company's pension plan obligations has
decreased. Fluctuations in actual equity market returns as well as changes in
general interest rates may result in increased or decreased pension costs in
future periods.
The Company's funding policy is to make voluntary contributions to its
defined benefit plans before ERISA or Pension Benefit Guaranty Corporation
requirements mandate such contributions under minimum funding rules, and so long
as the Company's liquidity needs do not preclude such investments. The Company
made voluntary pension plan contributions totaling $1.0 million between
September 1, 2002 and December 31, 2002 and plans to make voluntary
contributions totaling an additional $1.0 million by June 30, 2003. The
Company's pension costs and cash funding requirements could increase in future
years in the absence of recovery in the equity markets.
As a result of GMP's retirement plan asset return experience, at December
31, 2002, the Company has recognized an additional minimum liability of $2.4
million, net of applicable income taxes, as prescribed by generally accepted
accounting principles. The liability is recorded as a reduction to common
equity through a charge to other comprehensive income and did not affect net
income for 2002.
Accrued postretirement health care expenses are recovered in rates to
the extent those expenses are funded. In order to maximize the tax-deductible
contributions that are allowed under IRS regulations, the Company amended its
postretirement health care plan to establish a 401-h sub-account and separate
VEBA trusts for its union and non-union employees. The VEBA plan assets consist
primarily of cash equivalent funds, fixed income securities and equity
securities. The following provides a reconciliation of benefit obligations,
plan assets, and funded status of the plans as of December 31, 2002 and 2001.
At and for the years ended December 31,
Pension Benefits Other Postretirement Benefits
---------------- -----------------------------
2002 2001 2002 2001
-------- -------- --------- --------
(In thousands)
Change in projected benefit obligation:
Projected benefit obligation as of prior year end. $25,895 $23,332 $ 16,491 $14,947
Service cost . . . . . . . . . . . . . . . . . . . 668 537 296 241
Interest cost. . . . . . . . . . . . . . . . . . . 1,849 1,737 1,119 1,043
Participant contributions. . . . . . . . . . . . . - - 147 151
Change in actuarial assumptions. . . . . . . . . . - 367 - -
Actuarial (gain) loss. . . . . . . . . . . . . . . 3,230 1,650 3,619 1,021
Benefits paid. . . . . . . . . . . . . . . . . . . (1,650) (1,670) (965) (912)
Administrative expense . . . . . . . . . . . . . . (55) (58) - -
-------- -------- --------- --------
Projected benefit obligation as of year end. . . . $29,937 $25,895 $ 20,707 $16,491
======== ======== ========= ========
Change in plan assets:
Fair value of plan assets as of prior year end . . $24,341 $27,760 $ 10,016 $10,944
Administrative expenses paid . . . . . . . . . . . (55) (58) - -
Participant contributions. . . . . . . . . . . . . - - 147 151
Employer contributions . . . . . . . . . . . . . . 1,000 - 819 761
Actual return on plan assets . . . . . . . . . . . (2,532) (1,691) (1,257) (928)
Benefits paid. . . . . . . . . . . . . . . . . . . (1,650) (1,670) (965) (912)
-------- -------- --------- --------
Fair value of plan assets as of year end . . . . . $21,104 $24,341 $ 8,760 $10,016
======== ======== ========= ========
Funded status as of year end . . . . . . . . . . . $(8,833) $(1,554) $(11,948) $(6,475)
Unrecognized transition obligation (asset) . . . . (77) (241) 3,280 3,608
Unrecognized prior service cost. . . . . . . . . . 839 986 (462) (519)
Unrecognized net actuarial (gain) loss . . . . . . 6,982 (892) 8,379 2,711
-------- -------- --------- --------
Accrued benefits at year end . . . . . . . . . . . $(1,089) $(1,701) $ (751) $ (675)
======== ======== ========= ========
The Company also has a supplemental pension plan for certain employees. Pension
costs for the years ended December 31,2002, 2001, and 2000 were $408,000,
$340,000, and $346,000, respectively, under this plan. This plan is funded in
part through insurance contracts.
Net periodic pension expense and other postretirement benefit costs
include the following components:
For the years ended December 31,
Pension Benefits Other Postretirement Benefits
2002 2001 2000 2002 2001 2000
-------- -------- -------- ------- ------- -------
(In thousands)
Service cost . . . . . . . . . . . . . . . $ 668 $ 537 $ 655 $ 296 $ 241 $ 216
Interest cost. . . . . . . . . . . . . . . 1,849 1,737 1,658 1,119 1,043 1,049
Expected return on plan assets . . . . . . (2,112) (2,379) (2,580) (851) (892) (940)
Amortization of transition asset . . . . . (164) (164) (164) - - -
Amortization of prior service cost . . . . 147 147 121 (58) (58) (58)
Amortization of the transition obligation. - - - 328 328 328
Recognized net actuarial gain. . . . . . . - (237) (474) 60 - -
-------- -------- -------- ------- ------- -------
Net periodic benefit cost (income) . . $ 388 $ (359) $ (784) $ 894 $ 662 $ 595
======== ======== ======== ======= ======= =======
Assumptions used to determine postretirement benefit costs and the
related benefit obligation were:
For measurement purposes, a 10.0 percent annual rate of increase in the per
capita cost of covered medical benefits was assumed for 2003. This rate of
increase gradually declines to 5.5 percent in 2009. The medical trend rate
assumption has a significant effect on the amounts reported. For example,
increasing the assumed health care cost trend rate by one percentage point for
all future years would increase the accumulated postretirement benefit
obligation as of December 31, 2002 by $3.4 million and the total of the service
and interest cost components of net periodic postretirement cost for the year
ended December 31, 2002 by $257,000. Decreasing the trend rate by one
percentage point for all future years would decrease the accumulated
postretirement benefit obligation at December 31, 2002 by $2.7 million, and the
total of the service and interest cost components of net periodic postretirement
cost for 2002 by $202,000.
I. COMMITMENTS AND CONTINGENCIES
1. INDUSTRY RESTRUCTURING. The electric utility business is being
subjected to rapidly increasing competitive pressures stemming from a
combination of trends. Certain states, including all the New England states
except Vermont, have enacted legislation to allow retail customers to choose
their electric suppliers, with incumbent utilities required to deliver that
electricity over their transmission and distribution systems. Recent power
supply management difficulties in some regulatory jurisdictions, such as
California, have dampened any immediate push towards de-regulation in Vermont.
Alternative forms of performance-based regulation currently appear as possible
intermediate steps towards deregulation. There can be no assurance that any
potential future restructuring plan ordered by the VPSB, the courts, or through
legislation will include a mechanism that would allow for full recovery of our
stranded costs and include a fair return on those costs as they are being
recovered.
2. ENVIRONMENTAL MATTERS. The electric industry typically uses or generates
a range of potentially hazardous products in its operations. The Company must
meet various land, water, air and aesthetic requirements as administered by
local, state and federal regulatory agencies. We believe that we are in
substantial compliance with those requirements, and that there are no
outstanding material complaints about our compliance with present environmental
protection regulations, except for developments related to the Pine Street Barge
Canal site. The Company maintains an environmental compliance and monitoring
program that includes employee training, regular inspection of Company
facilities, research and development projects, waste handling and spill
prevention procedures and other activities.
Pine Street Barge Canal Site. The Federal Comprehensive Environmental
Response, Compensation, and Liability Act ("CERCLA"), commonly known as the
"Superfund" law, generally imposes strict, joint and several liability,
regardless of fault, for remediation of property contaminated with hazardous
substances. The Company has been notified by the Environmental Protection
Agency ("EPA") that it is one of several potentially responsible parties
("PRPs") for cleanup of the Pine Street Barge Canal site in Burlington, Vermont
where coal tar and other industrial materials were deposited.
In September 1999, we negotiated a final settlement with the United
States, the EPA, the State of Vermont, and other parties over terms of a Consent
Decree that covers claims addressed in the earlier negotiations and
implementation of the selected remedy. In November 1999, the Consent Decree was
filed in the federal district court. The Consent Decree addresses claims by the
EPA for past Pine Street Barge Canal site costs, natural resource damage claims
and claims for past and future oversight costs. The Consent Decree also
provides for the design and implementation of response actions at the site.
As of December 31, 2002, the Company's total expenditures related to
the Pine Street Barge Canal site since 1982 were approximately $27.1 million.
This includes those amounts not recovered in rates, amounts recovered in rates,
and amounts for which rate recovery has been sought but which are presently
waiting further VPSB action. The bulk of these expenditures consisted of
transaction costs. Transaction costs include legal and consulting costs
associated with the Company's opposition to the EPA's earlier and more costly
proposals for the site, as well as litigation and related costs necessary to
obtain settlements with insurers and other PRP's to provide amounts required to
fund the clean up (remediation costs) and to address liability claims at the
site. A smaller amount of past expenditures was for site-related response
costs, including costs incurred pursuant to the EPA and State orders that
resulted in funding response activities at the site, and to reimburse the EPA
and the State for oversight and related response costs. The EPA and the State
have asserted and affirmed that all costs related to these orders are
appropriate costs of response under CERCLA for which the Company and other PRPs
were legally responsible.
We estimate that we have recovered or secured, or will recover,
through settlements of litigation claims against insurers and other parties,
amounts that exceed estimated future remediation costs, future federal and state
government oversight costs and past EPA response costs. We currently estimate
our unrecovered transaction costs mentioned above, which were necessary to
recover settlements sufficient to remediate the site, to oppose much more costly
solutions proposed by the EPA, and to resolve monetary claims of the EPA and the
State, together with our remediation costs, to be $13.0 million over the next 32
years. The estimated liability is not discounted, and it is possible that our
estimate of future costs could change by a material amount. We also have
recorded an offsetting regulatory asset, and we believe that it is probable that
we will receive future revenues to recover these costs. Although it did not
eliminate the rate base deferral of these expenditures, or make any specific
order in this regard, the VPSB indicated that it was inclined to agree with
other parties in the case that the ultimate costs associated with the Pine
Street Barge Canal site, taking into account recoveries from insurance carriers
and other PRPs, should be shared between customers and shareholders of the
Company. In response to our Motion for Reconsideration, the VPSB on June 8,
1998 stated its intent was "to reserve for a future docket issues pertaining to
the sharing of remediation-related costs between the Company and its customers".
The VPSB Settlement Order regarding the Company's 1998 retail rate request did
not change the status of Pine Street cost recovery.
Clean Air Act. The Company purchases most of its power supply from
other utilities and does not anticipate that it will incur any material direct
costs as a result of the Federal Clean Air Act or proposals to make more
stringent regulations under that Act.
3. JOINTLY-OWNED FACILITIES. The Company has joint-ownership interests in
electric generating and transmission facilities at December 31, 2002, as
follows:
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- --------- --------------- -------------
(In %) (In MWh) (In thousands)
Highgate . . . . . . . . 33.8 67.6 $ 10,296 $ 4,657
McNeil . . . . . . . . . 11.0 5.9 8,989 5,078
Stony Brook (No. 1). . . 8.8 31 10,377 8,521
Wyman (No. 4). . . . . . 1.1 6.8 1,980 1,318
Metallic Neutral Return. 59.4 - 1,563 744
Metallic Neutral Return is a neutral conductor for NEPOOL/Hydro-Quebec
Interconnection
The Company's share of expenses for these facilities is reflected in the
Consolidated Statements of Income. Each participant in these facilities must
provide its own financing.
4. RATE MATTERS.
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 Vermont
Joint Owners ("VJO") contract costs, effectively ending the regulatory
disallowances experienced by the Company from 1998 through 2000;
* The Company agreed not to seek any further increase in electric rates
prior to April 2002 (effective in bills rendered January 2003) unless certain
substantially adverse conditions arise, including a provision allowing a request
for additional rate relief if power supply costs increase in excess of $3.75
million over forecasted levels;
* The Company agreed to write off in 2000 approximately $3.2 million in
unrecovered rate case litigation costs, and to freeze its dividend rate until it
successfully replaces short-term credit facilities with long-term debt or equity
financing;
* Seasonal rates were eliminated in April 2001, which generated
approximately $8.5 million in additional cash flow in 2001 that can be utilized
to offset increased costs during 2002 and 2003;
* The Company agreed to consult extensively with the Department regarding
capital spending commitments for upgrading our electric distribution system and
to adopt customer care and reliability performance standards, in a first step
toward possible development of performance-based rate-making;
* The Company agreed to withdraw its Vermont Supreme Court appeal of the
VPSB's Order in the 1997 rate case; and
* The Company agreed to an earnings limitation for its electric operations
in an amount equal to its allowed rate of return of 11.25 percent, with amounts
earned over the limit being used to write off regulatory assets.
On January 23, 2001, the VPSB approved the Company's 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 recognition of deferred revenues in the same amount.
The VPSB, in its order approving VY's sale of its nuclear power plant
to Entergy, ordered the Company and Central Vermont Public Service each to file
on or before April 15, 2003, a cost-of-service study based on actual 2002 data,
to enable the VPSB to determine whether an adjustment to rates is justified in
2003 or 2004. The Company believes this filing will support the Company's
current rates and does not intend to request a rate increase or decrease when
this filing is made. The VPSB could initiate an investigation of the Company's
rates based on this filing, requiring the Company to complete a rate case, and
the VPSB could order an adjustment to the Company's rates based on its findings
and conclusions. If the VPSB ordered the Company to reduce its rates in 2003
or 2004, this could have a material adverse effect on our operating results,
cash flows and ability to pay dividends at current levels.
5. OTHER DEFERRED CHARGES NOT INCLUDED IN RATE BASE. The Company has
incurred and deferred approximately $11.1 million in costs for demand side
conservation programs, tree trimming, storm damage, unscheduled VY outage costs
and federal regulatory commission work of which $1.2 million is being amortized
on an annual basis. Currently, the Company amortizes such costs based on
amounts being recovered and does not receive a return on certain amounts
deferred. Management expects to seek and receive ratemaking treatment for these
costs in future filings.
The Settlement Order directed the Company to write-off deferred
charges applicable to the state regulatory commission of $3.2 million as part of
the rate case agreement with the Department. The charge is included in other
operating expense for the year ended December 31, 2000. The Settlement Order
requires the remaining balance and future expenditures of deferred regulatory
commission charges be amortized over seven years.
6. COMPETITION. During 2001, the Town of Rockingham ("Rockingham"),
Vermont initiated inquiries and legal procedures, and on March 5, 2002, voters
in Rockingham authorized the town to establish its own electric utility, by
acting to acquire an existing hydro-generation facility from a third party, and
the associated distribution plant owned by the Company within Rockingham. 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 reimbursement such that neither our remaining
customers nor our shareholders subsidize Rockingham.
7. OTHER LEGAL MATTERS. In a series of Vermont regulatory proceedings, the
Company has agreed to undertake a process known as "distributed utility
planning" as part of its transmission and distribution planning process.
Distributed utility planning requires the Company to evaluate
conservation-related alternatives and distributed generation alternatives to
typical transmission and distribution capital investments. In certain
circumstances, the Company may be required to implement conservation or
distributed generation alternatives in lieu of, or in addition to, traditional
transmission and distribution capital investments, where societal cost savings
associated with conservation or distributed generation, including the costs
associated with avoided electricity sales, justify the expenditures. The
Company is uncertain of the potential magnitude of future spending requirements
for this program, but note they could be material. Costs associated with
conservation measures or distributed generation facilities not owned by the
Company would be deferred as regulatory assets pending future rate proceedings.
In 2002, the owners of property along the shoreline of Joe's Pond, an
impoundment located in Danville, Vermont, created by the Company's West Danville
Dam hydroelectric generating facility, filed an inquiry with the VPSB seeking
review of certain dam improvements made by the Company in 1995, complaining that
the Company did not obtain all necessary regulatory approvals for the 1995
improvements and that the Company's improvements and subsequent operation of the
dam have caused flooding of the shoreline and property damage. The Company has
petitioned the VPSB to make additional dam improvements at the facility at an
estimated cost of $350,000. The VPSB must approve the Company's petition before
the proposed improvements can be implemented. This regulatory proceeding is
pending and the Company is unable to predict whether the Company's petition will
be approved or whether the VPSB will impose regulatory conditions or penalties.
The Company is involved in other legal and administrative proceedings
in the normal course of business and does not believe that the ultimate outcome
of these proceedings will have a material effect on the financial position or
the results of operations of the Company.
J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT
Agreements executed in 1985 among the Company, VELCO and other NEPOOL
members and Hydro-Quebec provided for the construction of the second phase
(Phase II) of the interconnection between the New England electric systems and
that of Hydro-Quebec. Phase II expands the Phase I facilities from 690
megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec power
from the Phase I terminal in northern New Hampshire to Sandy Pond,
Massachusetts. Construction of Phase II commenced in 1988 and was completed in
late 1990. The Company is entitled to 3.2 percent of the Phase II power-supply
benefits. Total construction costs for Phase II were approximately $487
million. The New England participants, including the Company, have contracted
to pay monthly their proportionate share of the total cost of constructing,
owning and operating the Phase II facilities, including capital costs. As a
supporting participant, the Company must make support payments under thirty-year
agreements. These support agreements meet the capital lease accounting
requirements. At December 31, 2002, the present value of the Company's
obligation is approximately $5.3 million.
Projected future minimum payments under the Phase II support
agreements are as follows:
Year ending
December 31
---------------
(In thousands)
2003. . . . . . . . $ 407
2004. . . . . . . . 407
2005. . . . . . . . 406
2006. . . . . . . . 407
2007. . . . . . . . 407
Total for 2008-2015 3,253
Total . . . . . $ 5,287
===============
The Phase II portion of the project is owned by New England
Hydro-Transmission Electric Company and New England Hydro-Transmission
Corporation, subsidiaries of New England Electric System, in which certain of
the Phase II participating utilities, including the Company, own equity
interests. The Company holds approximately 3.2 percent of the equity of the
corporations owning the Phase II facilities.
K. LONG-TERM POWER PURCHASES
1. Unit Purchases. Under long-term contracts with various electric
utilities in the region, the Company is purchasing certain percentages of the
electrical output of production plants constructed and financed by those
utilities. Such contracts obligate the Company to pay certain minimum annual
amounts representing the Company's proportionate share of fixed costs, including
debt service requirements whether or not the production plants are operating.
The cost of power obtained under such long-term contracts, including payments
required when a production plant is not operating, is reflected as "Power Supply
Expenses" in the accompanying Consolidated Statements of Income.
Information (including estimates for the Company's portion of certain
minimum costs and ascribed long-term debt) with regard to significant purchased
power contracts of this type in effect during 2002 follows:
STONY
BROOK
-----------------------
(Dollars in thousands)
Plant capacity. . . . . . . . . . 352.0 MW
Company's share of output . . . . 4.40%
Contract period expires:. . . . . 2006
Company's annual share of:
Interest. . . . . . . . . . . . $ 140
Other debt service. . . . . . . 435
Other capacity. . . . . . . . . 306
Total annual capacity . . . . . . $ 881
=======================
Company's share of long-term debt $ 2,314
2. Vermont Yankee
The Company has a long-term power purchase contract with Vermont
Yankee Nuclear Power Corporation, which sold its nuclear power plant to Entergy
Nuclear Vermont Yankee on July 31, 2002. The Company is no longer required to
pay its proportionate share of fixed costs associated with the Entergy plant,
including when the plant is not operating, though the Company is responsible for
finding replacement power at such times.
The VY sale of its nuclear power plant to Entergy also 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
the Company's 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, the contract prices are not adjusted upward.
A summary of the PPA, including projected charges for the years
indicated, follows:
Vermont Yankee
Contract
--------------
(Dollars in thousands except per KWh)
Capacity acquired . . . . . . . . . . 106 MW
Contract period expires . . . . . . . 2012
Company's share of output . . . . . . 20%
Annual energy charge. . . . . . . . . 2002(5 months) $15,965
estimated . . . . . . . . . . . . . 2003-2015 33,352
Average cost per KWh. . . . . . . . . 2002 0.052
estimated . . . . . . . . . . . . . 2003-2015 0.042
Payments totaling $0.5 million were made in 2002 to VY's non-Vermont
sponsors in return for guarantees those sponsors made to Entergy to finalize the
VY sale.
Although the sale closed on July 31, 2002, the Company's distribution of the
sale proceeds and final accounting for the sale are pending certain regulatory
approvals and the resolution of certain closing items between VY and Entergy.
The Company expects its share of the VY power plant sale proceeds, currently
estimated at between $7 million and $8 million, to be distributed in the latter
part of 2003.
The sale required various regulatory approvals, all of which were granted on
terms acceptable to the parties to the transaction. Certain intervener parties
to the VPSB approval proceeding appealed the VPSB approval to the Vermont
Supreme Court. That appeal is pending. If the appellants prevail on their
appeal, the VPSB could be required to conduct additional proceedings or to
reconsider its order approving the sale.
3. Hydro-Quebec System Power Purchase and Sale Commitments. Under various
contracts, the details of which are described in the table below, the Company
purchases capacity and associated energy produced by the Hydro-Quebec system.
Such contracts obligate the Company to pay certain fixed capacity costs whether
or not energy purchases above a minimum level set forth in the contracts are
made. Such minimum energy purchases must be made whether or not other, less
expensive energy sources might be available. These contracts are intended to
complement the other components in the Company's power supply to achieve the
most economic power supply mix reasonably available. The Company's current
purchases pursuant to the contract with Hydro-Quebec entered into in December
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. There are specific step-up provisions that provide that in the
event any 1987 Contract participant fails to meet its obligation under the 1987
Contract with Hydro-Quebec, the remaining contract participants, including the
Company, will "step-up" to the defaulting participant's share on a prorated
basis.
Hydro-Quebec also has the right to reduce the load factor from 75
percent to 65 percent under the 1987 Contract a total of three times over the
life of the contract. The Company can delay such reduction by one year under
the 1987 Contract. During 2001, Hydro-Quebec exercised the first of these
options for 2002, and the Company delayed the effective date of this exercise
until 2003. The Company estimates that the net cost of Hydro-Quebec's exercise
of its option will increase power supply expense during 2003 by approximately
$0.4 million.
During 1994, the Company negotiated an arrangement with Hydro-Quebec
that reduced the cost impacts associated with the purchase of Schedules B and C3
under the 1987 Contract, over the November 1995 through October 1999 period (the
"July 1994 Agreement"). Under the July 1994 Agreement, the Company, in essence,
will take delivery of the amounts of energy as specified in the 1987 Contract,
but the associated fixed costs will be significantly reduced from those
specified in the 1987 Contract.
As part of the July 1994 Agreement, we were obligated to purchase $4.0
million (in 1994 dollars) worth of research and development work from
Hydro-Quebec over a period ending October 1999, which has since been extended,
and made an additional $6.5 million (plus accrued interest) payment to
Hydro-Quebec in 1995. Hydro-Quebec retains the right to curtail annual energy
deliveries by 10 percent up to five times, over the 2001 to 2015 period, if
documented drought conditions exist in Quebec. The period for completing the
research and development purchase was subsequently extended to March 2003.
During the first year of the July 1994 Agreement (the period from
November 1995 through October 1996), the average cost per kilowatt-hour of
Schedules B and C3 combined was cut from 6.4 to 4.2 cents per kilowatt-hour, a
34 percent or $16 million cost reduction. Over the period from November 1996
through December 2000 and accounting for the payments to Hydro-Quebec, the
combined unit costs were lowered from 6.5 to 5.9 cents per kilowatt-hour,
reducing unit costs by 10 percent and saving $20.7 million in nominal terms.
All of the Company's contracts with Hydro-Quebec call for the delivery
of system power and are not related to any particular facilities in the
Hydro-Quebec system. Consequently, there are no identifiable debt-service
charges associated with any particular Hydro-Quebec facility that can be
distinguished from the overall charges paid under the contracts.
A summary of the Hydro-Quebec contracts through the July 1994
Agreement, including historic and projected charges for the years indicated,
follows:
THE 1987 CONTRACT
SCHEDULE B SCHEDULE C3
------------------------------------- -------------
(Dollars in thousands except per KWh)
Capacity acquired. . . . 68 MW 46 MW
Contract period. . . . . 1995-2015 1995-2015
Minimum energy purchase. 75% 75%
(annual load factor)
Annual energy charge . . 2002 $ 11,946 $ 8,163
estimated. . . . . . . 2003-2015 13,362 (1) 9,131 (1)
Annual capacity charge . 2002 $ 16,850 $11,514
estimated. . . . . . . 2003-2015 $ 17,122 (1) $11,700 (1)
Average cost per KWh . . 2002 $ 0.065 $ 0.065
estimated. . . . . . . 2003-2015 $ 0.069 (2) $ 0.069 (2)
(1)Estimated average includes load factor reduction to 65 percent in 2003
(2)Estimated average in nominal dollars levelized over the period indicated
includes amortization of payments to Hydro-Quebec for the July 1994 Agreement
Under a separate arrangement established in December 1997 (the "9701
arrangement"), Hydro-Quebec provided a payment of $8.0 million to the Company in
1997. In return for this payment, the Company provided Hydro-Quebec an option
for the purchase of power. Commencing April 1, 1998, and effective through
October 2015, Hydro-Quebec can exercise an option to purchase up to 52,500 MWh
("option A") on an annual basis, at energy prices established in accordance with
the 1987 Contract. The cumulative amount of energy purchased under the 9701
arrangement shall not exceed 950,000 MWh. Hydro-Quebec's option to curtail
energy deliveries pursuant to the 1987 Contract and the July 1994 Agreement may
be exercised in addition to these purchase options.
Over the same period, Hydro-Quebec can exercise an option on an annual
basis to purchase a total of 600,000 MWh ("option B") at the 1987 Contract
energy price. Hydro-Quebec can purchase no more than 200,000 MWh in any given
contract year ending October 31. As of December 31, 2002, Hydro-Quebec had
purchased or called to purchase 458,000 MWh under option B.
In 2002, Hydro-Quebec exercised option A and called for deliveries to
third parties at a net expense to the Company of approximately $3.0 million,
including capacity charges.
In 2001, Hydro-Quebec exercised option A and option B, and called for
deliveries to third parties at a net expense to the Company of approximately
$6.5 million, including capacity charges.
In 2000, Hydro-Quebec called for deliveries to third parties at a net
expense to the Company of approximately $14.0 million (including the cost of the
January and February 2001 calls and related financial positions), which was due
to higher energy replacement costs. The 9701 arrangement costs are currently
being recovered in rates on an annual basis. The VPSB, in the Settlement Order
stated, "The record does not demonstrate that any other New England utility
foresaw the extent and degree of volatility that has developed in the New
England wholesale power markets. Absent that volatility, the 97-01 Agreement
would not have had adverse effects." In conjunction with the Settlement Order,
Hydro-Quebec committed to the Department that it would not call any energy under
option B of the 9701 arrangement during the contract year ending October 31,
2002. The Company's estimate of the fair value of the future net cost for the
9701 arrangement, which is dependent upon the timing of any exercise of options,
and the market price for replacement power, is approximately $27.2 million.
Future estimates could change by a material amount.
The Company believes that it is probable that Hydro-Quebec will call
options A and B for 2003, and has purchased replacement power at a net cost of
$4.7 million.
On April 17, 2001, an Arbitration Tribunal issued its decision in the
arbitration brought by a group of Vermont electric companies and municipal
utilities, known as the Vermont Joint Owners ("VJO"), against Hydro-Quebec for
its failure to deliver electricity pursuant to the VJO/Hydro-Quebec power supply
contract during the 1998 ice storm. The Company is a member of the VJO.
On July 23, 2001, the Company received approximately $3.2 million
representing its share of refunded capacity payments from Hydro-Quebec. These
proceeds reduced related deferred assets. At December 31, 2002, the remaining
unamortized balance of unrecovered arbitration costs is approximately $0.9
million. We believe it is probable that this balance will ultimately be
recovered in rates.
4. Morgan Stanley Contract - In February 1999, the Company entered into a
contract with MS. In August 2002, the MS contract was modified and extended to
December 31, 2006. The contract provides the Company a means of managing price
risks associated with changing fossil fuel prices. On a daily basis, and at
MS's discretion, the Company will sell power to MS from either (i) all or part
of our portfolio of power resources at predefined operating and pricing
parameters or (ii) any power resources available to the Company, provided that
sales of power from sources other than Company-owned generation comply with the
predefined operating and pricing parameters. MS then sells to us, at a
predefined price, power sufficient to serve pre-established load requirements.
MS is also responsible for scheduling supply resources. The Company remains
responsible for resource performance and availability. MS provides no coverage
against major unscheduled outages.
The Company and MS have agreed to the protocols that are used to
schedule power sales and purchases and to secure necessary transmission. We
anticipate that arrangements we make to manage power supply risks will be on
average more costly than the expected cost of fuel during the periods being
hedged because these arrangements would typically incorporate a risk premium.
L. DISCONTINUED OPERATIONS.
The Company sold or otherwise disposed of a significant portion of the
operations and assets of NWR, which owned and invested in energy generation,
energy efficiency, and wastewater treatment projects. The provisions for loss
from discontinued operations reflect management's current estimate. At December
31, 2002, assets remaining include a wind power partnership investment, a note
receivable from a regional hydro-power project, and notes receivable and equity
investments with two wastewater treatment projects, one of which has risk
factors that include the outcome of warranty litigation, and future cash
requirements necessary to minimize costs of winding down wastewater operations.
Several municipalities using wastewater treatment equipment have commenced or
threatened litigation. The ultimate loss remains subject to the disposition of
remaining assets and liabilities, and could exceed the amounts recorded. The
residual operations earned $0.02 per share in 2002, primarily as a result of an
adjustment to a reserve for warranty claims. The following illustrates the
results and financial statement impact of discontinued operations during and at
the periods shown:
2002 2001 2000
------ ------- --------
(In thousands except per share)
Revenues . . . . . . . . . . . . . $ 88 $ 156 $ 1,546
------ ------- --------
Gain (loss) on disposal. . . . . . 99 (182) (6,549)
Net income (loss). . . . . . . . . $ 99 $ (182) $(6,549)
====== ======= ========
Net income (loss) per share-basic. $ 0.02 $(0.03) $ (1.19)
Proceeds from asset sales. . . . . $ - $ - $ 6,000
Total assets . . . . . . . . . . . $2,619 $3,697 $ 8,411
State income taxes . . . . . . . . $ 19 $ (175) $(1,064)
Federal income taxes . . . . . . . 52 (550) (3,349)
Investment tax credits . . . . . . - - -
------ ------- --------
Income tax expense (benefit) . . . $ 71 $ (725) $(4,413)
====== ======= ========
M. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following quarterly financial information, in the opinion of
management, includes all adjustments necessary to a fair statement of results of
operations for such periods. Variations between quarters reflect the seasonal
nature of the Company's business and the timing of rate changes.
2002 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
------- ------- ---------- --------- --------
(Amounts in thousands except per share data)
Operating revenues . . . . . . . . . . . . . . $68,866 $65,135 $ 73,477 $ 67,130 $274,608
Operating income . . . . . . . . . . . . . . . 4,441 2,814 3,745 4,080 15,080
Net income-continuing operations . . . . . . . $ 3,354 $ 1,875 $ 3,042 $ 3,028 $ 11,299
Net income-discontinued operations . . . . . . - - - 99 99
Net Income applicable to common stock. . . . . $ 3,354 $ 1,875 $ 3,042 $ 3,127 $ 11,398
======= ======= ========== ========= ========
Basic earnings per share from:
Continuing operations. . . . . . . . . . . . . $ 0.59 $ 0.33 $ 0.53 0.57 $ 2.02
Discontinued operations. . . . . . . . . . . . - - - 0.02 0.02
Basic earnings per share . . . . . . . . . . . $ 0.59 $ 0.33 $ 0.53 $ 0.59 $ 2.04
======= ======= ========== ========= ========
Weighted average common shares outstanding . . 5,691 5,711 5,723 5,333 5,592
Diluted earnings per share from:
Continuing operations. . . . . . . . . . . . . $ 0.57 $ 0.32 $ 0.52 0.55 $ 1.96
Discontinued operations. . . . . . . . . . . . - - - 0.02 0.02
Diluted earnings per share . . . . . . . . . . $ 0.57 $ 0.32 $ 0.52 $ 0.57 $ 1.98
======= ======= ========== ========= ========
Weighted average common and common equivalent. 5,870 5,877 5,879 5,497 5,756
shares outstanding
2001 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
------- -------- ---------- ---------- ---------
(Amounts in thousands except per share data)
Operating revenues . . . . . . . . . . . . . . $74,796 $67,471 $ 76,051 $ 65,146 $283,464
Operating income . . . . . . . . . . . . . . . 4,575 4,275 4,573 3,036 16,459
Net income-continuing operations . . . . . . . $ 2,914 $ 2,884 $ 3,387 $ 1,675 $ 10,860
Net loss-discontinued operations . . . . . . . - (150) - (32) (182)
Net Income applicable to common stock. . . . . $ 2,914 $ 2,734 $ 3,387 $ 1,643 $ 10,678
======= ======== ========== ========== =========
Basic earnings (loss) per share from:
Continuing operations. . . . . . . . . . . . . $ 0.52 $ 0.52 $ 0.60 $ 0.29 $ 1.93
Discontinued operations. . . . . . . . . . . . - (0.03) - - (0.03)
Basic earnings per share . . . . . . . . . . . $ 0.52 $ 0.49 $ 0.60 $ 0.29 $ 1.90
======= ======== ========== ========== =========
Weighted average common shares outstanding . . 5,588 5,615 5,644 5,672 5,630
Diluted earnings (loss) per share from:
Continuing operations. . . . . . . . . . . . . $ 0.51 $ 0.50 $ 0.58 $ 0.29 $ 1.88
Discontinued operations. . . . . . . . . . . . - (0.03) - - (0.03)
Diluted earnings (loss) per share: . . . . . . $ 0.51 $ 0.47 $ 0.58 $ 0.29 $ 1.85
======= ======== ========== ========== =========
Weighted average common and common equivalent. 5,741 5,777 5,814 5,848 -
shares outstanding
2000 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
------- -------- ---------- ---------- ---------
(Amounts in thousands except per share data)
Operating revenues. . . . . . . . . . . . . . $67,712 $61,927 $ 78,143 $ 69,544 $277,326
Operating income (loss) . . . . . . . . . . . 4,613 (2,997) 3,271 373 5,260
Net income (loss)-continuing operations . . . $ 3,449 $(4,375) $ 1,961 $ (1,340) $ (305)
Net loss-discontinued operations. . . . . . . - (1,530) - (5,019) (6,549)
Net Income (loss) applicable to common stock. $ 3,449 $(5,905) $ 1,961 $ (6,359) $ (6,854)
======= ======== ========== ========== =========
Earnings (loss) per share from:
Continuing operations . . . . . . . . . . . . $ 0.63 $ (0.80) $ 0.36 $ (0.25) $ (0.06)
Discontinued operations . . . . . . . . . . . - (0.28) - (0.91) (1.19)
Basic and diluted . . . . . . . . . . . . . . $ 0.63 $ (1.08) $ 0.36 $ (1.16) $ (1.25)
======= ======== ========== ========== =========
Weighted average common shares outstanding. . 5,437 5,472 5,505 5,551 5,491
74
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS OF
GREEN MOUNTAIN POWER CORPORATION:
We have audited the accompanying consolidated balance sheet of Green
Mountain Power Corporation and subsidiaries (the Company) as of December 31,
2002, and the related consolidated statements of income, changes in common stock
equity and cash flows for the year then ended December 31, 2002. The financial
statements of Green Mountain Power Corporation and subsidiaries as of December
31, 2001 and 2000 and for the years then ended were audited by other auditors
who have ceased operations. Those auditors expressed an unqualified opinion
which included an emphasis of matter paragraph on those financial statements in
their report dated March 12, 2002. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Green Mountain
PowerCorporation and subsidiaries as of December 31, 2002 and the results of
their operations and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States.
Deloitte & Touche, LLP
Boston, Massachusetts
February 7, 2003
75
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and consolidated
capitalization data of Green Mountain Power Corporation (a Vermont corporation)
and its subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Green Mountain Power
Corporation and its subsidiaries as of December 31, 2001 and 2000, and the
consolidated results of its operations and cash flows for each of the three
years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.
As discussed in Note A to the financial statements, effective January 1, 2001,
the company adopted Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended.
/s/ Arthur Andersen LLP
Boston, Massachusetts
March 12, 2002
The above report of Arthur Andersen LLP is a copy of the previously issued
report, and the report has not been reissued by Arthur Andersen LLP.
Schedule II
GREEN MOUNTAIN POWER CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2002, 2001, and 2000
Balance at Additions Additions Balance at
Beginning of Charged to Charged to End of
Period Cost & Expenses Other Accounts Deductions Period
----------- --------------- -------------- ---------- -----------
Injuries and Damages (1)
- ----------------------------------------------
2002 . . . . . . . . . . . . . . . . . . . . . $12,064,548 325,000 134,505 2,034,547 $10,489,506
2001 . . . . . . . . . . . . . . . . . . . . . 13,382,713 212,555 312,229 1,842,949 12,064,548
2000 . . . . . . . . . . . . . . . . . . . . . 10,129,130 111,667 3,193,383 51,467 13,382,713
Bad Debt Reserve
- ----------------------------------------------
2002 . . . . . . . . . . . . . . . . . . . . . 575,890 - - 65,844 510,046
2001 . . . . . . . . . . . . . . . . . . . . . 425,890 150,000 575,890
2000 . . . . . . . . . . . . . . . . . . . . . 390,495 35,395 - - 425,890
(1) Includes Pine Street Barge Canal reserves
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Green Mountain Power Corporation
Colchester, VT
We have audited the financial statements of Green Mountain Power Corporation as
of December 31, 2002 and for the year then ended, and have issued our report
thereon dated February 7, 2003; such report is included elsewhere in this Form
10-K. Our audit also included the financial statement schedules of Green
Mountain Power Corporation, listed in Item 8. This financial statement schedule
is the responsibility of the Corporation's management. Our responsibility is to
express an opinion based on our audit. The financial statement schedule of
Green Mountain Power Corporation and subsidiaries as of December 31, 2001 and
2000 was audited by other auditors who have ceased operations. Those auditors
expressed an unqualified opinion on that schedule in their report dated March
12, 2002. In our opinion, such financial statement schedule, when considered in
relation to the basic financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Boston, MA
February 7, 2003
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited, in accordance with auditing standards generally accepted in the
United States, the consolidated financial statements of Green Mountain Power
Corporation included in this Form 10-K and have issued our report thereon dated
March 12, 2002. Our report included an explanatory paragraph indicating that
effective January 1, 2001, Green Mountain Power Corporation adopted Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended. Our audit was made for the purpose of
forming an opinion on the basic financial statements taken as a whole. The
schedule listed in the accompanying index to consolidated financial statements
and schedule is presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic consolidated financial
statements. This schedule has been subjected to the auditing procedures applied
in the audit of the basic consolidated financial statements, and in our opinion,
fairly states, in all material respects, the financial data required to be set
forth therein in relation to the basic consolidated financial statements taken
as a whole.
/s/ Arthur Andersen LLP
Boston, Massachusetts
March 12, 2002
The above report of Arthur Andersen LLP is a copy of the previously issued
report, and the report has not been reissued by Arthur Andersen LLP.
75
79
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
The July 17, 2002 decision to engage Deloitte & Touche LLP was made after
careful consideration by the Green Mountain Power Corporation Board of Directors
and senior management. The decision was not the result of any disagreement
between Green Mountain Power and Arthur Andersen on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure, for any periods audited and reported on by Arthur Andersen. Arthur
Anderson's audit reports for the years ended December 31, 2001 and 2000 did not
contain any qualification, modification, or disclaimers.
PART III
ITEMS 10, 11, 12 AND 13
Certain information regarding executive officers called for by Item 10,
"Directors and Executive Officers of the Registrant," is furnished under the
caption, "Executive Officers" in Item 1 of Part I of this Report. The other
information called for by Item 10, as well as that called for by Items 11, 12,
and 13, "Executive Compensation," "Security Ownership of Certain Beneficial
Owners and Management" and "Certain Relationships and Related Transactions,"
will be set forth under the captions "Election of Directors," Board
Compensation, Meetings, Committees and Other Relationships, "Section 16(a)
Beneficial Ownership Reporting Compliance," "Executive Compensation and Other
Information", "Compensation Committee Report on Executive Compensation",
"Pension Plan Information and Other Benefits" and "Securities Ownership of
Certain Beneficial Owners and Management" in the Company's definitive proxy
statement relating to its annual meeting of stockholders to be held on May 15,
2003. Such information is incorporated herein by reference. Such proxy
statement pertains to the election of directors and other matters. Definitive
proxy materials will be filed with the Securities and Exchange Commission
pursuant to Regulation 14A in March 2003.
ITEM 14. CONTROLS AND PROCEDURES
Within the 90 days prior to the filing date of this report, we carried out
an evaluation, under the supervision and with the participation of our
management, including Christopher L. Dutton, President and Chief Executive
Officer and Robert J. Griffin, Treasurer and Controller (principal financial
officer), of the effectiveness of the design and operation of our disclosure
controls and procedures pursuant to Rule 13a-14 under the Securities Exchange
Act of 1934, as amended. Based upon that evaluation, our President and Chief
Executive Officer, and Treasurer and Controller (principal financial officer)
concluded that our disclosure controls and procedures are effective in timely
alerting them to material information relating to us (including our consolidated
subsidiaries) required to be included in our periodic SEC filings.
There have been no significant changes in internal controls or in other
factors that could significantly affect these controls subsequent to the date of
their evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Item 15(a)1. Financial Statements and Schedules. The financial statements and
financial statement schedules of the Company are listed on the Index to
financial statements set forth in Item 8 hereof.
Item 15(b) The following filings on Form 8-K were filed by the Company on
the topic and date indicated:
A Form 8-K was filed on December 16, 2002 announcing the private placement of
$42.0 million in long term bonds maturing in 2017 with an interest rate of 6.04
percent.
The accompanying notes are an integral part of these consolidated financial
statements.
ITEM 14(A)3 AND ITEM 14(C). EXHIBITS SEC DOCKET
, INCORPORATED BY
EXHIBIT REFERENCE OR
NUMBER
-----------------------------------------------------------
3-A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . RESTATED ARTICLES OF ASSOCIATION, AS CERTIFIED
JUNE 6, 1991.
3-A-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO 3-A ABOVE, DATED AS OF MAY 20, 1993.
3-A-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO 3-A ABOVE, DATED AS OF OCTOBER 11, 1996.
3-B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BY-LAWS OF THE COMPANY, AS AMENDED
FEBRUARY 10, 1997.
4-B-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . INDENTURE OF FIRST MORTGAGE AND DEED OF TRUST
DATED AS OF FEBRUARY 1, 1955.
4-B-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRST SUPPLEMENTAL INDENTURE DATED AS OF
APRIL 1, 1961.
4-B-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SECOND SUPPLEMENTAL INDENTURE DATED AS OF
JANUARY 1, 1966.
4-B-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . THIRD SUPPLEMENTAL INDENTURE DATED AS OF
JULY 1, 1968.
4-B-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FOURTH SUPPLEMENTAL INDENTURE DATED AS OF
OCTOBER 1, 1969.
4-B-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIFTH SUPPLEMENTAL INDENTURE DATED AS OF
DECEMBER 1, 1973.
4-B-7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SEVENTH SUPPLEMENTAL INDENTURE DATED AS
AUGUST 1, 1976.
4-B-8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . EIGHTH SUPPLEMENTAL INDENTURE DATED AS OF
DECEMBER 1, 1979.
4-B-9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NINTH SUPPLEMENTAL INDENTURE DATED AS OF
JULY 15, 1985.
4-B-10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TENTH SUPPLEMENTAL INDENTURE DATED AS OF
JUNE 15, 1989.
4-B-11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ELEVENTH SUPPLEMENTAL INDENTURE DATED AS OF
SEPTEMBER 1, 1990.
4-B-12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TWELFTH SUPPLEMENTAL INDENTURE DATED AS OF
MARCH 1, 1992.
4-B-13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . THIRTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
MARCH 1, 1992.
4-B-14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FOURTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
NOVEMBER 1, 1993.
4-B-15. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIFTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
NOVEMBER 1, 1993.
4-B-16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SIXTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
DECEMBER 1, 1995.
4-B-17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REVISED FORM OF INDENTURE AS FILED AS AN EXHIBIT
TO REGISTRATION STATEMENT NO. 33-59383.
4-B-18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CREDIT AGREEMENT BY AND AMONG GREEN MOUNTAIN POWER
THE BANK OF NOVA SCOTIA, STATE STREET BANK AND
TRUST COMPANY, FLEET NATIONAL BANK, AND FLEET
NATIONAL BANK, AS AGENT
4-B-18(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO EXHIBIT 4-B-18
4-B-19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SEVENTEENTH SUPPLEMENTAL INDENTURE DATED AS OF
DECEMBER 1, 2002
10-A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FORM OF INSURANCE POLICY ISSUED BY PACIFIC
INSURANCE COMPANY, WITH RESPECT TO
INDEMNIFICATION OF DIRECTORS AND OFFICERS.
10-B-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRM POWER CONTRACT DATED SEPTEMBER 16, 1958,
BETWEEN THE COMPANY AND THE STATE OF VERMONT
AND SUPPLEMENTS THERETO DATED SEPTEMBER 19,
1958; NOVEMBER 15, 1958; OCTOBER 1, 1960 AND
FEBRUARY 1, 1964.
10-B-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . POWER CONTRACT, DATED FEBRUARY 1, 1968, BETWEEN THE COMPANY
AND VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT, DATED JUNE 1, 1972, TO POWER CONTRACT
BETWEEN THE COMPANY AND VERMONT YANKEE NUCLEAR
POWER CORPORATION.
10-B-3(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT, DATED APRIL 15, 1983, TO POWER
CONTRACT BETWEEN THE COMPANY AND VERMONT
YANKEE NUCLEAR POWER CORPORATION.
10-B-3(B) . . . . . . . . . . . . . . . . . . . . . . . . . . . . ADDITIONAL POWER CONTRACT, DATED
FEBRUARY 1, 1984,BETWEEN THE COMPANY AND
VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-4. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CAPITAL FUNDS AGREEMENT, DATED FEBRUARY 1,
1968, BETWEEN THE COMPANY AND VERMONT
YANKEE NUCLEAR POWER CORPORATION.
10-B-5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT, DATED MARCH 12, 1968, TO CAPITAL
FUNDS AGREEMENT BETWEEN THE COMPANY AND
VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . GUARANTEE AGREEMENT, DATED NOVEMBER 5, 1981, OF THE
COMPANY FOR ITS PROPORTIONATE SHARE OF THE OBLIGATIONS
OF VERMONT YANKEE NUCLEAR POWER CORPORATION
UNDER A $40 MILLION LOAN ARRANGEMENT.
10-B-7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . THREE-PARTY POWER AGREEMENT AMONG THE COMPANY,
VELCO AND CENTRAL VERMONT PUBLIC SERVICE
CORPORATION DATED NOVEMBER 21, 1969.
10-B-8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO EXHIBIT 10-B-7, DATED JUNE 1, 1981.
10-B-9. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . THREE-PARTY TRANSMISSION AGREEMENT AMONG THE
COMPANY, VELCO AND CENTRAL VERMONT PUBLIC
SERVICE CORPORATION, DATED NOVEMBER 21, 1969.
10-B-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO EXHIBIT 10-B-9, DATED JUNE 1, 1981.
10-B-14 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENT WITH CENTRAL MAINE POWER COMPANY ET
AL, TO ENTER INTO JOINT OWNERSHIP OF WYMAN
PLANT, DATED NOVEMBER 1, 1974.
10-B-15 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NEW ENGLAND POWER POOL AGREEMENT AS AMENDED TO
NOVEMBER 1, 1975.
10-B-16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BULK POWER TRANSMISSION CONTRACT BETWEEN THE
COMPANY AND VELCO DATED JUNE 1, 1968.
10-B-17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO EXHIBIT 10-B-16, DATED JUNE 1, 1970.
10-B-20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . POWER SALES AGREEMENT, DATED AUGUST 2, 1976, AS
AMENDED OCTOBER 1, 1977, AND RELATED
TRANSMISSION AGREEMENT, WITH THE MASSACHUSETTS
MUNICIPAL WHOLESALE ELECTRIC COMPANY.
10-B-21 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENT DATED OCTOBER 1, 1977, FOR JOINT OWNERSHIP,
CONSTRUCTION AND OPERATION OF THE MMWEC PHASE I
INTERMEDIATE UNITS, DATED OCTOBER 1, 1977
10-B-28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . CONTRACT DATED FEBRUARY 1, 1980, PROVIDING FOR
THE SALE OF FIRM POWER AND ENERGY BY THE POWER
AUTHORITY OF THE STATE OF NEW YORK TO THE
VERMONT PUBLIC SERVICE BOARD.
10-B-30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . BULK POWER PURCHASE CONTRACT DATED APRIL 7,
1976, BETWEEN VELCO AND THE COMPANY.
10-B-33 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT
DATED AS OF DECEMBER 1, 1981, PROVIDING FOR USE OF
TRANSMISSION INTER-CONNECTION BETWEEN NEW ENGLAND
AND HYDRO-QUEBEC.
10-B-34 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PHASE I TRANSMISSION LINE SUPPORT AGREEMENT
DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
VETCO AND PARTICIPATING NEW ENGLAND UTILITIES
FOR CONSTRUCTION, USE AND SUPPORT OF VERMONT
FACILITIES OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-35 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PHASE I TERMINAL FACILITY SUPPORT AGREEMENT
DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
AND PARTICIPATING NEW ENGLAND UTILITIES FOR
CONSTRUCTION, USE AND SUPPORT OF NEW HAMPSHIRE
FACILITIES OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-36 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENT WITH RESPECT TO USE OF QUEBEC
INTERCONNECTION DATED AS OF DECEMBER 1, 1981,
AMONG PARTICIPATING NEW ENGLAND UTILITIES
FOR USE OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-39 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VERMONT PARTICIPATION AGREEMENT FOR QUEBEC
INTERCONNECTION DATED AS OF JULY 15, 1982,
BETWEEN VELCO AND PARTICIPATING VERMONT
UTILITIES FOR ALLOCATION OF VELCO'S RIGHTS
AND OBLIGATIONS AS A PARTICIPATING NEW
ENGLAND UTILITY IN THE TRANSMISSION INTER-
CONNECTION BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-40 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VERMONT ELECTRIC TRANSMISSION COMPANY, INC.
CAPITAL FUNDS AGREEMENT DATED AS OF JULY 15,
1982, BETWEEN VETCO AND VELCO FOR VELCO TO PROVIDE
CAPITAL TO VETCO FOR CONSTRUCTION OF THE VERMONT FACILITIES
OF THE TRANSMISSION INTER-CONNECTION BETWEEN NEW
ENGLAND AND HYDRO-QUEBEC.
10-B-41 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VETCO CAPITAL FUNDS SUPPORT AGREEMENT DATED AS
OF JULY 15, 1982, BETWEEN VELCO AND PARTICIPATING VERMONT
UTILITIES FOR ALLOCATION OF VELCO'S OBLIGATION TO VETCO
UNDER THE CAPITAL FUNDS AGREEMENT.
10-B-42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ENERGY BANKING AGREEMENT DATED MARCH 21, 1983,
AMONG HYDRO-QUEBEC, VELCO, NEET AND PARTI-
CIPATING NEW ENGLAND UTILITIES ACTING BY AND
THROUGH THE NEPOOL MANAGEMENT COMMITTEE FOR
TERMS OF ENERGY BANKING BETWEEN PARTICIPATING
NEW ENGLAND UTILITIES AND HYDRO-QUEBEC.
10-B-43 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . INTERCONNECTION AGREEMENT DATED MARCH 21, 1983,
BETWEEN HYDRO-QUBEC AND PARTICIPATING NEW
ENGLAND UTILITIES ACTING BY AND THROUGH THE
NEPOOL MANAGEMENT COMMITTEE FOR TERMS AND
CONDITIONS OF ENERGY TRANSMISSION BETWEEN
NEW ENGLAND AND HYDRO-QUEBEC.
10-B-44 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ENERGY CONTRACT DATED MARCH 21, 1983, BETWEEN
HYDRO-QUEBEC AND PARTICIPATING NEW ENGLAND
UTILITIES ACTING BY AND THROUGH THE NEPOOL
MANAGEMENT COMMITTEE FOR PURCHASE OF
SURPLUS ENERGY FROM HYDRO-QUEBEC.
10-B-50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENT FOR JOINT OWNERSHIP, CONSTRUCTION AND
OPERATION OF THE HIGHGATE TRANSMISSION
INTERCONNECTION, DATED AUGUST 1, 1984,
BETWEEN CERTAIN ELECTRIC DISTRIBUTION
COMPANIES, INCLUDING THE COMPANY.
10-B-51 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . HIGHGATE OPERATING AND MANAGEMENT AGREEMENT,
DATED AS OF AUGUST 1, 1984, AMONG VELCO AND
VERMONT ELECTRIC-UTILITY COMPANIES, INCLUDING
THE COMPANY.
10-B-52 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ALLOCATION CONTRACT FOR HYDRO-QUEBEC FIRM POWER
DATED JULY 25, 1984, BETWEEN THE STATE OF
VERMONT AND VARIOUS VERMONT ELECTRIC UTILITIES,
INCLUDING THE COMPANY.
10-B-53 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . HIGHGATE TRANSMISSION AGREEMENT DATED AS OF
AUGUST 1, 1984, BETWEEN THE OWNERS OF THE
PROJECT AND VARIOUS VERMONT ELECTRIC
DISTRIBUTION COMPANIES.
10-B-61 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENTS ENTERED IN CONNECTION WITH PHASE II
OF THE NEPOOL/HYDRO-QUEBEC + 450 KV HVDC
TRANSMISSION INTERCONNECTION.
10-B-62 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AGREEMENT BETWEEN UNITIL POWER CORP. AND THE
COMPANY TO SELL 23 MW CAPACITY AND ENERGY FROM
STONY BROOK INTERMEDIATE COMBINED CYCLE UNIT.
10-B-68 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 4,
1987, BETWEEN HYDRO-QUEBEC AND PARTICIPATING
VERMONT UTILITIES, INCLUDING THE COMPANY, FOR
THE PURCHASE OF FIRM POWER FOR UP TO THIRTY YEARS.
10-B-69 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRM POWER AGREEMENT DATED AS OF OCTOBER 26, 1987,
BETWEEN ONTARIO HYDRO AND VERMONT DEPARTMENT OF
PUBLIC SERVICE.
10-B-70 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRM POWER AND ENERGY CONTRACT DATED AS OF
FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT
OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-
QUEBEC FOR UP TO 50 MW OF CAPACITY.
10-B-70(A). . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO 10-B-70.
10-B-71 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . INTERCONNECTION AGREEMENT DATED AS OF
FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT
OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-QUEBEC.
10-B-72 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PARTICIPATION AGREEMENT DATED AS OF APRIL 1, 1988,
BETWEEN HYDRO-QUEBEC AND PARTICIPATING VERMONT. . . . . . . . . JUNE 1988
UTILITIES, INCLUDING THE COMPANY, IMPLEMENTING
THE PURCHASE OF FIRM POWER FOR UP TO 30 YEARS
UNDER THE FIRM POWER AND ENERGY CONTRACT DATED
DECEMBER 4, 1987 (PREVIOUSLY FILED WITH THE
COMPANY'S ANNUAL REPORT ON FORM 10-K FOR 1987,
EXHIBIT NUMBER 10-B-68).
10-B-72(A). . . . . . . . . . . . . . . . . . . . . . . . . . . . RESTATEMENT OF THE PARTICIPATION AGREEMENT FILED
AS EXHIBIT 10-B-72 ON FORM 10-Q FOR JUNE 1988.
10-B-77 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 29,
1988, BETWEEN HYDRO-QUEBEC AND PARTICIPATING
VERMONT UTILITIES, INCLUDING THE COMPANY, FOR THE
PURCHASE OF UP TO 54 MW OF FIRM POWER AND ENERGY.
10-B-78 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TRANSMISSION AGREEMENT DATED DECEMBER 23, 1988,
BETWEEN THE COMPANY AND NIAGARA MOHAWK POWER
CORPORATION (NIAGARA MOHAWK), FOR NIAGARA
MOHAWK TO PROVIDE ELECTRIC TRANSMISSION TO
THE COMPANY FROM ROCHESTER GAS AND ELECTRIC
AND CENTRAL HUDSON GAS AND ELECTRIC.
10-B-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SALES AGREEMENT DATED MAY 24, 1989, BETWEEN
THE TOWN OF HARDWICK, HARDWICK ELECTRIC DEPARTMENT. . . . . . . JUNE 1989
AND THE COMPANY FOR THE COMPANY TO PURCHASE
ALL OF THE OUTPUT OF HARDWICK'S GENERATION AND
TRANSMISSION SOURCES AND TO PROVIDE HARDWICK
WITH ALL-REQUIREMENTS ENERGY AND CAPACITY EXCEPT
FOR THAT PROVIDED BY THE VERMONT DEPARTMENT OF
PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
10-B-82 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SALES AGREEMENT DATED JULY 14, 1989, BETWEEN
NORTHFIELD ELECTRIC DEPARTMENT AND THE COMPANY. . . . . . . . . JUNE 1989
FOR THE COMPANY TO PURCHASE ALL OF THE OUTPUT
OF NORTHFIELD'S GENERATION AND TRANSMISSION
SOURCES AND TO PROVIDE NORTHFIELD WITH ALL-
REQUIREMENTS ENERGY AND CAPACITY EXCEPT FOR
THAT PROVIDED BY THE VERMONT DEPARTMENT OF
PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
10-B-85 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . POWER PURCHASE AND SALE AGREEMENT BETWEEN
MORGAN STANLEY CAPITAL GROUP INC. AND THE
COMPANY
10-B-86 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . REVOLVING CREDIT AGREEMENT WITH KEYBANK
10-B-87 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO FLEET REVOLVING CREDIT AGREEMENT
10-B-88 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ENERGY EAST POWER PURCHASE OPTION AGREEMENT
10-B-89 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SECOND AMENDED AND RESTATED CREDIT AGREEMENT BETWEEN
KEYBANK NATIONAL ASSOCIATION, FLEET NATIONAL BANK, AND
THE COMPANY DATED JUNE 20, 2001
10-B-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PURCHASE POWER AGREEMENT BETWEEN ENTERGY NUCLEAR VERMONT
YANKEE LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION
10-B-91 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . FIRST AMENDMENT TO PURCHASE POWER AGREEMENT LISTED AS
EXHIBIT NUMBER 10-B-90, BETWEEN ENTERGY NUCLEAR VERMONT YANKEE
LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION
10-B-92 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO POWER PURCHASE AND SALE AGREEMENT
BETWEEN MORGAN STANLEY CAPITAL GROUP, INC. AND THE
COMPANY
DESCRIPTION EXHIBIT PAGE FILED HEREWITH
------------ -------------------- --------------------
3-A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-A FORM 10-K 1993
JUNE 6, 1991. (1-8291)
3-A-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-A-1 FORM 10-K 1993
(1-8291)
3-A-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-A-2 FORM 10-Q SEPT.
1996 (1-8291)
3-B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-B FORM 10-K 1996
FEBRUARY 10, 1997. (1-8291)
4-B-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B 2-27300
DATED AS OF FEBRUARY 1, 1955.
4-B-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-2 2-75293
APRIL 1, 1961.
4-B-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-3 2-75293
JANUARY 1, 1966.
4-B-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-4 2-75293
JULY 1, 1968.
4-B-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-5 2-75293
OCTOBER 1, 1969.
4-B-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-6 2-75293
DECEMBER 1, 1973.
4-B-7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-A-7 2-99643
AUGUST 1, 1976.
4-B-8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-A-8 2-99643
DECEMBER 1, 1979.
4-B-9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-9 2-99643
JULY 15, 1985.
4-B-10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-10 FORM 10-K 1989
JUNE 15, 1989. (1-8291)
4-B-11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-11 FORM 10-Q SEPT.
SEPTEMBER 1, 1990. 1990 (1-8291)
4-B-12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-12 FORM 10-K 1991
MARCH 1, 1992. (1-8291)
4-B-13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-13 FORM 10-K 1991
MARCH 1, 1992. (1-8291)
4-B-14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-14 FORM 10-K 1993
NOVEMBER 1, 1993. (1-8291)
4-B-15. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-15 FORM 10-K 1993
NOVEMBER 1, 1993. (1-8291)
4-B-16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-16 FORM 10-K 1995
DECEMBER 1, 1995. (1-8291)
4-B-17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-17 FORM 10-Q SEPT.
TO REGISTRATION STATEMENT NO. 33-59383. 1995 (1-8291)
4-B-18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-18 FORM 10-K 1997
THE BANK OF NOVA SCOTIA, STATE STREET BANK AND (1-8291)
TRUST COMPANY, FLEET NATIONAL BANK, AND FLEET
NATIONAL BANK, AS AGENT
4-B-18(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-18(A) FORM 10-Q SEPT.
1998 (1-8291)
4-B-19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-B-19 FORM 10-K 2002
DECEMBER 1, 2002 (1-8291)
10-A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-A 33-8146
INSURANCE COMPANY, WITH RESPECT TO
INDEMNIFICATION OF DIRECTORS AND OFFICERS.
10-B-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-B 2-27300
BETWEEN THE COMPANY AND THE STATE OF VERMONT
AND SUPPLEMENTS THERETO DATED SEPTEMBER 19,
1958; NOVEMBER 15, 1958; OCTOBER 1, 1960 AND
FEBRUARY 1, 1964.
10-B-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-D 2-34346
AND VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-F-1 2-49697
BETWEEN THE COMPANY AND VERMONT YANKEE NUCLEAR
POWER CORPORATION.
10-B-3(A) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-3(A) 33-8164
CONTRACT BETWEEN THE COMPANY AND VERMONT
YANKEE NUCLEAR POWER CORPORATION.
10-B-3(B) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-3(B) 33-8164
FEBRUARY 1, 1984,BETWEEN THE COMPANY AND
VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-4. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-E 2-34346
1968, BETWEEN THE COMPANY AND VERMONT
YANKEE NUCLEAR POWER CORPORATION.
10-B-5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-F 2-34346
FUNDS AGREEMENT BETWEEN THE COMPANY AND
VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-6 2-75293
COMPANY FOR ITS PROPORTIONATE SHARE OF THE OBLIGATIONS
OF VERMONT YANKEE NUCLEAR POWER CORPORATION
UNDER A $40 MILLION LOAN ARRANGEMENT.
10-B-7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-I 2-49697
VELCO AND CENTRAL VERMONT PUBLIC SERVICE
CORPORATION DATED NOVEMBER 21, 1969.
10-B-8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-8 2-75293
10-B-9. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-J 2-49697
COMPANY, VELCO AND CENTRAL VERMONT PUBLIC
SERVICE CORPORATION, DATED NOVEMBER 21, 1969.
10-B-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-10 2-75293
10-B-14 5.16 2-52900
AL, TO ENTER INTO JOINT OWNERSHIP OF WYMAN
PLANT, DATED NOVEMBER 1, 1974.
10-B-15 4.8 2-55385
NOVEMBER 1, 1975.
10-B-16 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-V 2-49697
COMPANY AND VELCO DATED JUNE 1, 1968.
10-B-17 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13-V-I 2-49697
10-B-20 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-20 33-8164
AMENDED OCTOBER 1, 1977, AND RELATED
TRANSMISSION AGREEMENT, WITH THE MASSACHUSETTS
MUNICIPAL WHOLESALE ELECTRIC COMPANY.
10-B-21 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-21 33-8164
CONSTRUCTION AND OPERATION OF THE MMWEC PHASE I
INTERMEDIATE UNITS, DATED OCTOBER 1, 1977
10-B-28 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-28 33-8164
THE SALE OF FIRM POWER AND ENERGY BY THE POWER
AUTHORITY OF THE STATE OF NEW YORK TO THE
VERMONT PUBLIC SERVICE BOARD.
10-B-30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-32 2-75293
1976, BETWEEN VELCO AND THE COMPANY.
10-B-33 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-33 33-8164
DATED AS OF DECEMBER 1, 1981, PROVIDING FOR USE OF
TRANSMISSION INTER-CONNECTION BETWEEN NEW ENGLAND
AND HYDRO-QUEBEC.
10-B-34 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-34 33-8164
DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
VETCO AND PARTICIPATING NEW ENGLAND UTILITIES
FOR CONSTRUCTION, USE AND SUPPORT OF VERMONT
FACILITIES OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-35 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-35 33-8164
DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
AND PARTICIPATING NEW ENGLAND UTILITIES FOR
CONSTRUCTION, USE AND SUPPORT OF NEW HAMPSHIRE
FACILITIES OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-36 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-36 33-8164
INTERCONNECTION DATED AS OF DECEMBER 1, 1981,
AMONG PARTICIPATING NEW ENGLAND UTILITIES
FOR USE OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-39 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-39 33-8164
INTERCONNECTION DATED AS OF JULY 15, 1982,
BETWEEN VELCO AND PARTICIPATING VERMONT
UTILITIES FOR ALLOCATION OF VELCO'S RIGHTS
AND OBLIGATIONS AS A PARTICIPATING NEW
ENGLAND UTILITY IN THE TRANSMISSION INTER-
CONNECTION BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-40 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-40 33-8164
CAPITAL FUNDS AGREEMENT DATED AS OF JULY 15,
1982, BETWEEN VETCO AND VELCO FOR VELCO TO PROVIDE
CAPITAL TO VETCO FOR CONSTRUCTION OF THE VERMONT FACILITIES
OF THE TRANSMISSION INTER-CONNECTION BETWEEN NEW
ENGLAND AND HYDRO-QUEBEC.
10-B-41 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-41 33-8164
OF JULY 15, 1982, BETWEEN VELCO AND PARTICIPATING VERMONT
UTILITIES FOR ALLOCATION OF VELCO'S OBLIGATION TO VETCO
UNDER THE CAPITAL FUNDS AGREEMENT.
10-B-42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-42 33-8164
AMONG HYDRO-QUEBEC, VELCO, NEET AND PARTI-
CIPATING NEW ENGLAND UTILITIES ACTING BY AND
THROUGH THE NEPOOL MANAGEMENT COMMITTEE FOR
TERMS OF ENERGY BANKING BETWEEN PARTICIPATING
NEW ENGLAND UTILITIES AND HYDRO-QUEBEC.
10-B-43 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-43 33-8164
BETWEEN HYDRO-QUBEC AND PARTICIPATING NEW
ENGLAND UTILITIES ACTING BY AND THROUGH THE
NEPOOL MANAGEMENT COMMITTEE FOR TERMS AND
CONDITIONS OF ENERGY TRANSMISSION BETWEEN
NEW ENGLAND AND HYDRO-QUEBEC.
10-B-44 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-44 33-8164
HYDRO-QUEBEC AND PARTICIPATING NEW ENGLAND
UTILITIES ACTING BY AND THROUGH THE NEPOOL
MANAGEMENT COMMITTEE FOR PURCHASE OF
SURPLUS ENERGY FROM HYDRO-QUEBEC.
10-B-50 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-50 33-8164
OPERATION OF THE HIGHGATE TRANSMISSION
INTERCONNECTION, DATED AUGUST 1, 1984,
BETWEEN CERTAIN ELECTRIC DISTRIBUTION
COMPANIES, INCLUDING THE COMPANY.
10-B-51 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-51 33-8164
DATED AS OF AUGUST 1, 1984, AMONG VELCO AND
VERMONT ELECTRIC-UTILITY COMPANIES, INCLUDING
THE COMPANY.
10-B-52 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-52 33-8164
DATED JULY 25, 1984, BETWEEN THE STATE OF
VERMONT AND VARIOUS VERMONT ELECTRIC UTILITIES,
INCLUDING THE COMPANY.
10-B-53 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-53 33-8164
AUGUST 1, 1984, BETWEEN THE OWNERS OF THE
PROJECT AND VARIOUS VERMONT ELECTRIC
DISTRIBUTION COMPANIES.
10-B-61 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-61 33-8164
OF THE NEPOOL/HYDRO-QUEBEC + 450 KV HVDC
TRANSMISSION INTERCONNECTION.
10-B-62 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-62 33-8164
COMPANY TO SELL 23 MW CAPACITY AND ENERGY FROM
STONY BROOK INTERMEDIATE COMBINED CYCLE UNIT.
10-B-68 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-68 FORM 10-K 1992
1987, BETWEEN HYDRO-QUEBEC AND PARTICIPATING (1-8291)
VERMONT UTILITIES, INCLUDING THE COMPANY, FOR
THE PURCHASE OF FIRM POWER FOR UP TO THIRTY YEARS.
10-B-69 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-69 FORM 10-K 1992
BETWEEN ONTARIO HYDRO AND VERMONT DEPARTMENT OF (1-8291)
PUBLIC SERVICE.
10-B-70 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-70 FORM 10-K 1992
FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT (1-8291)
OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-
QUEBEC FOR UP TO 50 MW OF CAPACITY.
10-B-70(A). . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-70(A) FORM 10-K 1992
(1-8291)
10-B-71 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-71 FORM 10-K 1992
FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT (1-8291)
OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-QUEBEC.
10-B-72 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-72 FORM 10-Q
BETWEEN HYDRO-QUEBEC AND PARTICIPATING VERMONT
UTILITIES, INCLUDING THE COMPANY, IMPLEMENTING (1-8291)
THE PURCHASE OF FIRM POWER FOR UP TO 30 YEARS
UNDER THE FIRM POWER AND ENERGY CONTRACT DATED
DECEMBER 4, 1987 (PREVIOUSLY FILED WITH THE
COMPANY'S ANNUAL REPORT ON FORM 10-K FOR 1987,
EXHIBIT NUMBER 10-B-68).
10-B-72(A). . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-72(A) FORM 10-K 1988
AS EXHIBIT 10-B-72 ON FORM 10-Q FOR JUNE 1988. (1-8291)
10-B-77 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-77 FORM 10-K 1988
1988, BETWEEN HYDRO-QUEBEC AND PARTICIPATING (1-8291)
VERMONT UTILITIES, INCLUDING THE COMPANY, FOR THE
PURCHASE OF UP TO 54 MW OF FIRM POWER AND ENERGY.
10-B-78 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-78 FORM 10-K 1988
BETWEEN THE COMPANY AND NIAGARA MOHAWK POWER (1-8291)
CORPORATION (NIAGARA MOHAWK), FOR NIAGARA
MOHAWK TO PROVIDE ELECTRIC TRANSMISSION TO
THE COMPANY FROM ROCHESTER GAS AND ELECTRIC
AND CENTRAL HUDSON GAS AND ELECTRIC.
10-B-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-81 FORM 10-Q
THE TOWN OF HARDWICK, HARDWICK ELECTRIC DEPARTMENT
AND THE COMPANY FOR THE COMPANY TO PURCHASE (1-8291)
ALL OF THE OUTPUT OF HARDWICK'S GENERATION AND
TRANSMISSION SOURCES AND TO PROVIDE HARDWICK
WITH ALL-REQUIREMENTS ENERGY AND CAPACITY EXCEPT
FOR THAT PROVIDED BY THE VERMONT DEPARTMENT OF
PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
10-B-82 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-82 FORM 10-Q
NORTHFIELD ELECTRIC DEPARTMENT AND THE COMPANY
FOR THE COMPANY TO PURCHASE ALL OF THE OUTPUT (1-8291)
OF NORTHFIELD'S GENERATION AND TRANSMISSION
SOURCES AND TO PROVIDE NORTHFIELD WITH ALL-
REQUIREMENTS ENERGY AND CAPACITY EXCEPT FOR
THAT PROVIDED BY THE VERMONT DEPARTMENT OF
PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
10-B-85 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-85 FORM 10-K 1998
MORGAN STANLEY CAPITAL GROUP INC. AND THE (1-8291)
COMPANY
10-B-86 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-86 FORM 10-Q SEPT.
2000 (1-8291)
10-B-87 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-87 FORM 10-Q SEPT.
2000 (1-8291)
10-B-88 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-88 FORM 10-Q SEPT.
2000 (1-8291)
10-B-89 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-89 FORM 10-K 2001
KEYBANK NATIONAL ASSOCIATION, FLEET NATIONAL BANK, AND
THE COMPANY DATED JUNE 20, 2001
10-B-90 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-90 FORM 10-Q JUNE 2002
YANKEE LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION (1-8291)
10-B-91 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-90 FORM 10-Q JUNE 2002
EXHIBIT NUMBER 10-B-90, BETWEEN ENTERGY NUCLEAR VERMONT YANKEE (1-8291)
LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION
10-B-92 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10-B-92 FORM 10-K 2002
BETWEEN MORGAN STANLEY CAPITAL GROUP, INC. AND THE (1-8291)
COMPANY
MANAGEMENT CONTRACTS OR COMPENSATORY PLANS OR ARRANGEMENTS
REQUIRED TO BE FILED AS EXHIBITS TO THIS FORM 10-K
PURSUANT TO ITEM 14(C)., ALL UNDER SEC DOCKET 1-8291
-----------------------------------------------------
10-D-1B. . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED 10-D-1B
AND RESTATED DEFERRED COMPENSATION PLAN FOR DIRECTORS.
10-D-1C. . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED 10-D-1C
AND RESTATED DEFERRED COMPENSATION PLAN FOR
OFFICERS.
10-D-1D. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT NO. 93-1 TO THE AMENDED AND RESTATED 10-D-1D
DEFERRED COMPENSATION PLAN FOR OFFICERS.
10-D-1E. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT NO. 94-1 TO THE AMENDED AND RESTATED 10-D-1E
DEFERRED COMPENSATION PLAN FOR OFFICERS. . . . . . . . JUNE 1994
10-D-2 . . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION MEDICAL EXPENSE 10-D-2
REIMBURSEMENT PLAN.
10-D-4 . . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION OFFICER 10-D-4
INSURANCE PLAN.
10-D-4A. . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION OFFICERS' 10-D-4A
INSURANCE PLAN AS AMENDED.
10-D-8 . . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION OFFICERS' 10-D-8
SUPPLEMENTAL RETIREMENT PLAN.
10-D-15B . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER CORPORATION COMPENSATION PROGRAM 10-D-15B
FOR OFFICERS AND KEY MANAGEMENT PERSONNEL AS AMENDED
AUGUST 4, 1997
10-D-15C . . . . . . . . . . . . . . . . . . . . . . . . GREEN MOUNTAIN POWER 2000 STOCK INCENTIVE PLAN 10-D-15C
10-D-21. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH N. R. BROCK 10-D-21
10-D-22. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH C. L. DUTTON 10-D-22
10-D-23. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH R. J. GRIFFIN 10-D-23
10-D-27. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH W. S. OAKES 10-D-27
10-D-28. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH M. G. POWELL 10-D-28
10-D-29. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH S. C. TERRY 10-D-29
10-D-31. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO SEVERANCE AGREEMENT WITH N. R. BROCK 10-D-31
10-D-32. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO SEVERANCE AGREEMENT WITH C. L. DUTTON 10-D-32
10-D-33. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO SEVERANCE AGREEMENT WITH R. J. GRIFFIN 10-D-33
10-D-34. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO SEVERANCE AGREEMENT WITH W. S. OAKES 10-D-34
10-D-35. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO SEVERANCE AGREEMENT WITH M. G. POWELL 10-D-35
10-D-36. . . . . . . . . . . . . . . . . . . . . . . . . AMENDMENT TO SEVERANCE AGREEMENT WITH S. C. TERRY 10-D-36
10-D-37. . . . . . . . . . . . . . . . . . . . . . . . . SEVERANCE AGREEMENT WITH D.J. RENDALL 10-D-37
*23-A-1. . . . . . . . . . . . . . . . . . . . . . . . . CONSENT OF ARTHUR ANDERSEN LLP 23-A-1
23-A-2 . . . . . . . . . . . . . . . . . . . . . . . . . CONSENT OF DELOITTE AND TOUCHE LLP 23-A-2
10-D-1B. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1993
AND RESTATED DEFERRED COMPENSATION PLAN FOR DIRECTORS.
10-D-1C. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1993
AND RESTATED DEFERRED COMPENSATION PLAN FOR
OFFICERS.
10-D-1D. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1993
DEFERRED COMPENSATION PLAN FOR OFFICERS.
10-D-1E. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-Q
DEFERRED COMPENSATION PLAN FOR OFFICERS.
10-D-2 . . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1991
REIMBURSEMENT PLAN.
10-D-4 . . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1991
INSURANCE PLAN.
10-D-4A. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1990
INSURANCE PLAN AS AMENDED.
10-D-8 . . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1990
SUPPLEMENTAL RETIREMENT PLAN.
10-D-15B . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1997
FOR OFFICERS AND KEY MANAGEMENT PERSONNEL AS AMENDED
AUGUST 4, 1997
10-D-15C . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-21. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1998
10-D-22. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1998
10-D-23. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1998
10-D-27. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1998
10-D-28. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1998
10-D-29. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 1998
10-D-31. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-32. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-33. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-34. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-35. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-36. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-K 2001
10-D-37. . . . . . . . . . . . . . . . . . . . . . . . . FORM 10-Q MARCH 2002
21 SUBSIDIARIES OF THE REGISTRANT 21 FORM 10-K 1996
*23-A-1
23-A-2
24 LIMITED POWER OF ATTORNEY 24
Exhibit 23.1
Independent Auditors' Consent
We consent to the incorporation by reference in Registration Statement Nos.
333-38722, 333-39822 and 333-42356 of Green Mountain Power Corporation of our
report dated February 7, 2003 relating to the consolidated financial statements
of Green Mountain Power Corporation as of and for the year ended December 31,
2002 appearing in this Annual Report on Form 10-K of Green Mountain Power
Corporation for the year ended December 31, 2002.
/s/DELOITTE & TOUCHE LLP
March 21, 2003
Exhibit 23.2
Statement of Company Concerning Consent of Arthur Andersen LLP
Prior to 2002, Arthur Andersen LLP was our independent accountants. As a result
of the 2002 closing of the applicable Arthur Andersen LLP offices, we were
unable to obtain the consent of Arthur Andersen LLP to the incorporation by
reference of their report in this Form 10-K with respect to our financial
statements as of December 31, 2001, and for the fiscal years ended December 31,
2001 and 2000. We have dispensed with the requirement under Section 7 of the
Securities Act of 1933, as amended (the "Securities Act"), to file their consent
in reliance on Rule 437(a) promulgated under the Securities Act. Because Arthur
Andersen LLP has not consented to the incorporation by reference of their report
in this Form 10-K, a person who purchases the Company's securities in reliance
upon such report may be unable to recover against Arthur Andersen LLP under
Section 11 of the Securities Act for any untrue statements of a material fact
contained in the financial statements audited by Arthur Andersen LLP
incorporated by reference or any omissions to state a material fact required to
be stated therein.
89
89
EXHIBIT 24
POWER OF ATTORNEY
-----------------
We, the undersigned directors of Green Mountain Power Corporation, hereby
severally constitute Christopher L. Dutton, Mary G. Powell, and Robert J.
Griffin, and each of them singly, our true and lawful attorney with full power
of substitution, to sign for us and in our names in the capacities indicated
below, the Annual Report on Form 10-K of Green Mountain Power Corporation for
the fiscal year ended December 31, 2002, and generally to do all such things in
our name and behalf in our capacities as directors to enable Green Mountain
Power Corporation to comply with the provisions of the Securities Exchange Act
of 1934, as amended, all requirements of the Securities and Exchange Commission,
and all requirements of any other applicable law or regulation, hereby ratifying
and confirming our signatures as they may be signed by our said attorney, to
said Annual Report.
SIGNATURE TITLE DATE
- --------- ----- ----
/s/Christopher L. Dutton President and Director March 6, 2003
- --------------------------
Christopher L. Dutton (Principal Executive
Officer)
/s/Nordahl L. Brue March 13, 2003
- --------------------
Nordahl L. Brue Chairman of the Board
/s/Elizabeth A. Bankowski March 11, 2003
- ---------------------------
Elizabeth A. Bankowski Director
/s/William H. Bruett March 17, 2003
- ----------------------
William H. Bruett Director
/s/Merrill O. Burns March 14, 2003
- ---------------------
Merrill O. Burns Director
/s/Lorraine E. Chickering March 12, 2003
- ---------------------------
Lorraine E. Chickering Director
/s/John V. Cleary March 10, 2003
- -------------------
John V. Cleary Director
/s/David R. Coates March 4, 2003
- --------------------
David R. Coates Director
/s/Euclid A. Irving March 10, 2003
- ---------------------
Euclid A. Irving Director
91
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
Date: March 24, 2003 By: /s/ Christopher L. Dutton
-
Christopher L. Dutton, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- ----------------- ---------------- --------
/s/ Christopher L. Dutton_ President, Chief Executive March 24, 2003
- ---------------------------
Christopher L. Dutton Officer, and Director
/s/ Mary G. Powell_______ Chief Operating Officer, March 24, 2003
- ---------------------------
Mary G. Powell Senior Vice President
/s/ Robert J. Griffin Controller, Treasurer March 24, 2003
- -------------------------
Robert J. Griffin (Principal Accounting Officer)
*Nordahl L. Brue ) Chairman of the Board
*Elizabeth Bankowski
*William H. Bruett )
*Merrill O. Burns )
*David R. Coates )
*Lorraine E. Chickering )
*John V. Cleary )
Directors
*Euclid A. Irving )
*By: _/s/ Christopher L. Dutton March 24, 2003
--------------------------
Christopher L. Dutton
(Attorney - in - Fact)
I, Christopher L. Dutton, certify that:
1. I have reviewed this annual report on Form 10-K of Green Mountain Power
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or person performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses
Date: March 24, 2003
/s/Christopher L. Dutton
- --------------------------
Christopher L. Dutton, Chief Executive Officer and President
I, Robert J. Griffin, certify that:
1. I have reviewed this annual report on Form 10-K of Green Mountain Power
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or person performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses
Date: March 24, 2003
/s/Robert J. Griffin
- ----------------------
Robert J. Griffin, Treasurer and Controller (Principal Financial Officer)