SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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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, 2003
COMMISSION FILE NUMBER 1-8291
GREEN MOUNTAIN POWER CORPORATION
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(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 FEBRUARY 27, 2004, WAS APPROXIMATELY $132,657,931 BASED ON
THE CLOSING PRICE OF $26.27 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 FEBRUARY 27, 2004, WAS
5,049,788
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual Meeting of
Stockholders to be held on May 20, 2004, 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.
Green Mountain Power Corporation
Form 10-K for the fiscal year ended December 31, 2003
Table of contents Page
Part I
Item 1, Business 3
Item 2, Properties 16
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, Financial Statements and Supplementary Data 41
Item 9, Changes In and Disagreements with Accountants 79
On Accounting and Financial Disclosure
Item 9A, Controls and Procedures 79
Items 10 through 13, Certain Officer Information 79
Item 14, Principal Accountant Fees and Services 79
Item 15, Exhibits, Financial Statement Schedules, 80
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 2003 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 service territory with approximately one
quarter of Vermont's population. We serve approximately 89,000 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, 2003 were as
follows:
* 26.9 percent from residential customers;
* 26.4 percent from small commercial and industrial customers;
* 17.1 percent from large commercial and industrial customers;
* 28.1 percent from sales to other utilities; and
* 1.5 percent from other sources.
See the Annual Report and MD and A for further information about revenues.
During 2003, our energy resources for retail and wholesale sales of
electricity, excluding purchases made pursuant to the contract with Morgan
Stanley Capital Group, Inc. (the "Morgan Stanley Contract") discussed under MD
and A-Power Contract Commitments, were obtained as follows:
* 35.4 percent from hydroelectric sources (28.1 percent Hydro-Quebec, 4.5
percent Company-owned, and 2.8 percent independent power producers);
* 37.4 percent from a nuclear generating source (the Entergy Nuclear Vermont
Yankee, LLC ("ENVY") nuclear plant described below);
* 3.5 percent from wood;
* 1.3 percent from natural gas;
* 2.7 percent from oil; and
* 0.5 percent from wind.
The remaining 19.2 percent was purchased on a short-term basis from other
utilities through the Independent System Operator of New England ("ISO-NE" or
"ISO New England"), formerly the New England Power Pool ("NEPOOL").
In 2003, we estimate that we purchased or generated in excess of 90.0
percent of our energy resources to satisfy our retail and wholesale sales of
electricity under long-term arrangements, including the Morgan Stanley Contract.
Remaining retail and wholesale sales were met through short-term market
purchases and represent volumetric differences between purchase commitments and
our customers' retail demand. 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 ENVY. We have a 33.6 percent equity interest in Vermont Yankee
Nuclear Power Corporation ("Vermont Yankee" or "VY"), which has a long-term
power supply contract with ENVY 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 United States. The ISO-NE was created to manage the operations of
NEPOOL, effective May 1, 1999. ISO-NE operates a market for all New England
states 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, to replace energy repurchased by
Hydro-Quebec under an arrangement negotiated in 1997 and to replace power not
delivered under our contracts and entitlements due to outages, curtailments or
other events that result in reduced deliveries. 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 ENVY 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,
2003 2002 2001 2000 1999
----------- ----------- ----------- ----------- -----------
Total capability (MW) . . . . . . . . . . . . . . 393.9 406.9 408.0 411.1 393.2
Net system peak . . . . . . . . . . . . . . . . . 330.2 342.0 341.2 323.5 317.9
----------- ----------- ----------- ----------- -----------
Reserve (MW). . . . . . . . . . . . . . . . . . . 63.7 64.9 66.8 87.6 75.3
=========== =========== =========== =========== ===========
Reserve % of peak . . . . . . . . . . . . . . . . 19.3% 19.0% 19.6% 27.1% 23.7%
Net Production (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . . 838,855 901,998 951,146 1,053,223 1,095,738
Wind. . . . . . . . . . . . . . . . . . . . . . . 10,828 11,458 12,135 12,246 7,956
Nuclear . . . . . . . . . . . . . . . . . . . . . 884,585 771,781 736,420 803,303 731,431
Conventional steam. . . . . . . . . . . . . . . . 2,524,233 2,431,115 2,670,249 2,704,427 2,328,267
Internal combustion . . . . . . . . . . . . . . . 12,603 4,090 18,291 35,699 12,312
Combined cycle. . . . . . . . . . . . . . . . . . 68,488 81,362 72,653 73,433 99,962
----------- ----------- ----------- ----------- -----------
Total production. . . . . . . 4,339,592 4,201,804 4,460,894 4,682,331 4,275,666
Less non-firm sales to other utilities. . . . . . 2,284,003 2,104,172 2,365,809 2,573,576 2,152,781
----------- ----------- ----------- ----------- -----------
Production for firm sales . . . . . . . . . . . . 2,055,589 2,097,632 2,095,085 2,108,755 2,122,885
Less firm sales and lease transmissions. . . . . 1,937,376 1,951,959 1,956,232 1,954,898 1,920,257
----------- ----------- ----------- ----------- -----------
Losses and company use (MWH). . . . . . . . . . . 118,213 145,673 138,853 153,857 202,628
=========== =========== =========== =========== ===========
Losses as a % of total production . . . . . . . . 2.72% 3.47% 3.11% 3.29% 4.74%
System load factor (***). . . . . . . . . . . . . 71.1% 70.0% 70.1% 74.2% 76.2%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . . 19.3% 21.5% 21.3% 22.5% 25.6%
Wind. . . . . . . . . . . . . . . . . . . . . . . 0.2% 0.3% 0.3% 0.3% 0.2%
Nuclear . . . . . . . . . . . . . . . . . . . . . 20.4% 18.3% 16.5% 17.1% 17.1%
Conventional steam. . . . . . . . . . . . . . . . 58.2% 57.9% 59.9% 57.8% 54.5%
Internal combustion . . . . . . . . . . . . . . . 0.3% 0.1% 0.4% 0.8% 0.3%
Combined cycle. . . . . . . . . . . . . . . . . . 1.6% 1.9% 1.6% 1.6% 2.3%
----------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0%
=========== =========== =========== =========== ===========
Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . . 581,047 553,294 549,151 558,682 544,447
Commercial & industrial - small . . . . . . . . . 703,036 695,504 691,029 704,126 688,493
Commercial & industrial - large . . . . . . . . . 645,271 689,618 710,944 683,296 664,110
Other . . . . . . . . . . . . . . . . . . . . . . 4,986 9,773 2,030 6,713 3,138
----------- ----------- ----------- ----------- -----------
Total retail sales and lease transmissions. . . . 1,934,340 1,948,189 1,953,154 1,952,817 1,900,188
Sales to Municipals & Cooperatives (Rate W) . . . 3,036 3,770 3,078 2,081 20,069
----------- ----------- ----------- ----------- -----------
Total Requirements Sales. . . . . . . . . . . . . 1,937,376 1,951,959 1,956,232 1,954,898 1,920,257
Other Sales for Resale. . . . . . . . . . . . . . 2,284,003 2,104,172 2,365,809 2,573,576 2,152,781
----------- ----------- ----------- ----------- -----------
Total sales and lease transmissions(MWH) . . . . 4,221,379 4,056,131 4,322,041 4,528,474 4,073,038
=========== =========== =========== =========== ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . . 74,693 73,861 73,249 72,424 71,515
Commercial and industrial small . . . . . . . . . 13,344 13,165 12,976 12,746 12,438
Commercial and industrial large . . . . . . . . . 25 29 30 23 23
Other . . . . . . . . . . . . . . . . . . . . . . 65 65 65 65 66
----------- ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . . . . . 88,127 87,120 86,320 85,258 84,042
=========== =========== =========== =========== ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . . 12.98 12.96 13.33 12.50 12.32
Commercial & industrial - small . . . . . . . . . 10.40 10.44 10.90 10.00 9.88
Commercial & industrial - large . . . . . . . . . 7.41 7.31 7.70 6.51 6.55
----------- ----------- ----------- ----------- -----------
Total retail including lease. . . . . . . . . . . 10.22 10.09 10.44 9.52 9.47
=========== =========== =========== =========== ===========
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . . 7,779 7,491 7,497 7,717 7,617
Revenues including lease revenues . . . . . . . . $ 1,010 $ 971 $ 999 $ 965 $ 938
(*) 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", or the "Board"), which extends to retail rates,
services and facilities, securities issues and various other matters. The
separate Vermont Department of Public Service (the "Department," or the "DPS"),
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 the public advocate 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 certain loads. All such agreements must be approved by the VPSB. 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 2003.
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 2003.
On July 17, 1997, the FERC approved our Open Access Transmission Tariff,
and on August 30, 1997 we filed our compliance 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 have not
experienced 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. The amounts appropriated are not material.
The re-licensing 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 late 2004. When repairs are
complete, we expect the project to be re-licensed for a 30-year term. 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 August 14, 2003, we filed with the VPSB and the Department an integrated
resource plan pursuant to Vermont Statute 30 V.S.A. 218c. That filing is
pending before the VPSB.
RECENT RATE DEVELOPMENTS
The VPSB issued an order on December 22, 2003 approving the Company's 2003 Rate
Plan (the "2003 Rate Plan"), jointly proposed by the Company and the Department.
Principal terms of the 2003 Rate Plan include:
Allows the Company to raise rates 1.9 percent, effective January 1, 2005;
and 0.9 percent effective January 1, 2006, if the increases are supported by
cost of service schedules submitted 60 days prior to the effective dates.
Allows the Company the opportunity to file for rate increases during the
period from January 1, 2003 to January 1, 2007 if the Company experiences
extraordinary events, such as repair costs due to an ice storm or other natural
disaster.
Reduces the Company's allowed return on equity from 11.25 percent to 10.5
percent for the period beginning January 1, 2003 to January 1, 2007.
Approves a three-year economic development agreement for IBM, as long as
IBM does not reduce employment by more than five percent during the period.
Provides for recovery of various regulatory assets, including the
remediation of the Pine Street environmental superfund site in Burlington, VT.
SINGLE CUSTOMER DEPENDENCE
The Company had one major retail customer, IBM, metered at two locations
that accounted for 16.6 percent, 17.3 percent and 19.2 percent of the Company's
retail operating revenues in 2003, 2002 and 2001, respectively. No other retail
customer accounted for more than 1.0 percent of our revenue during the past
three years.
IBM has reduced its Vermont workforce by approximately 2,500 since 2001, to
a level of approximately 6,000 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 that would result from a
hypothetical shutdown of the IBM facility to be in the range of five to eight
percent, inclusive of projected declines in sales to other 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.
In March 2002, voters in the Town of Rockingham, Vermont ("Rockingham")
approved an article authorizing Rockingham to create a municipal utility and to
acquire the electric distribution systems of the Company and/or Central Vermont
Public Service Corporation located within the Rockingham. In November 2003,
Rockingham notified the Company that the town intended to initiate proceedings
before the town selectboard to condemn the Company's distribution and associated
property located within the town. The Company sought and obtained in December
2003 a preliminary injunction from the State Superior Court prohibiting the town
from proceeding with condemnation before the selectboard. The Company
successfully argued that Vermont law required Rockingham to pursue any such
municipalization effort by petition to the VPSB, which is required to determine
both the fair value of any assets subject to municipalization and the amount of
damages to the utility caused by severance of the property subject to
municipalization. The preliminary injunction remains in effect and Rockingham
has not filed any petition with the VPSB seeking to municipalize assets. 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. 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 other 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 could potentially 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.
There are currently no regulatory proceedings, court actions or pending
legislative proposals to adopt electric industry restructuring in Vermont.
Legislation has been introduced in the Vermont legislature that would permit
(but not require) the Company to negotiate with individual customers to permit
such customers to procure their own electric power supply requirements, subject
to VPSB approval. We cannot predict whether this legislation will be enacted.
If enacted, the Company would not negotiate any such arrangement unless, in our
estimation, the arrangement assured the Company of full recovery of any
resulting stranded costs and that the Company's financial condition would not
otherwise be adversely affected.
Regulatory and legislative authorities at the federal level and in some
states, including Vermont where legislation has not been enacted, are
considering how to facilitate competition for electricity sales. For further
information regarding Competition and Restructuring, See Item 7. MD and A -
Regulatory Risk and Other Risk.
CONSTRUCTION AND CAPITAL REQUIREMENTS
Our capital expenditures for 2001 through 2003 and projected for 2004 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. 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. ("Morgan Stanley"). In August 2002, the Morgan
Stanley 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 Morgan Stanley Contract, see Note K
of Notes.
We generated, purchased or transmitted 2,364,130 MWh of energy for retail
and requirements wholesale customers for the twelve months ended December 31,
2003. The corresponding maximum one-hour integrated demand during that period
was 330.2 MW on August 5, 2003. This compares to the previous all-time peak of
342.0 MW on August 15, 2002. 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 12/31/2003 of annual peak
MWH percent KW percent
--------- -------- ------- --------
Wholly-owned plants:
Hydro . . . . . . . . . . . . . 107,406 4.5% 32,870 8.9%
Diesel and Gas Turbine. . . . . 12,603 0.5% 50,623 13.6%
Wind. . . . . . . . . . . . . . 10,828 0.5% 480 0.1%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . 12,030 0.5% 6,968 1.9%
Stony Brook I . . . . . . . . . 43,833 1.9% 27,113 7.3%
McNeil. . . . . . . . . . . . . 25,328 1.1% 6,443 1.7%
Long Term Purchases:
Vermont Yankee/ENVY . . . . . . 884,585 37.4% 100,554 27.1%
Hydro Quebec. . . . . . . . . . 664,225 28.1% 114,174 30.8%
Stony Brook I . . . . . . . . . 24,655 1.0% 12,382 3.3%
Other:
Independent Power Producers . . 125,465 5.3% 19,286 5.2%
NEPOOL and Short-term purchases 453,172 19.2% 400 0.1%
--------- -------- ------- --------
Net Own Load. . . . . . . . . . 2,364,130 100.0% 371,293 100.0%
========= ======== ======= ========
Vermont Yankee.
On July 31, 2002, Vermont Yankee completed the sale of its nuclear power
plant to "ENVY". In addition to the sale of the generating plant, the
transaction calls for ENVY, 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.
Prices under the Power Purchase Agreement between VY and ENVY (the "PPA")
range from $39 to $45 per megawatt-hour for the period beginning January 2003.
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 ENVY plant.
Prior to the sale of the VY plant to ENVY, the 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. The Company expects to amortize
(recover) these costs beginning in 2005 under the Company's 2003 Rate Plan. The
Company received a credit of approximately $600,000 from VY and has requested
permission from the VPSB to apply this credit to reduce the $2.0 million
regulatory asset. Our ownership share of VY has increased from approximately
19.0 percent last year to approximately 33.6 percent currently, due to VY's
purchase of certain minority shareholders' interests. VY's primary role
consists of administering its power supply contract with ENVY and its contracts
with VY's present sponsors. Our entitlement to energy produced by the ENVY
nuclear plant has remained at 20 percent of plant production.
Under our Capital Funds Agreement with VY, we are 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 ENVY power is unavailable, the costs of replacement
power occasionally exceed those costs that we would have incurred for ENVY power
purchased from Vermont Yankee. Replacement power is available to us from the
ISO-NE and through contractual arrangements with other utilities. Replacement
power costs can adversely affect cash flow, and, unless deferred and/or
recovered in rates, such costs could 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 and recovery of such costs.
The ENVY nuclear plant's current operating license expires March 2012.
During the year ended December 31, 2003, we used 884,585 MWh of Vermont
Yankee energy (supplied by ENVY) representing 37.4 percent of the net
electricity generated and purchased ("net power supply") by the Company. The
average cost of Vermont Yankee electricity in 2003 was $0.043 per kWh.
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 approximately 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;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 originate at the Des Cantons Substation on the Hydro-Quebec system near
Sherbrooke, Canada and traverse a portion of eastern Vermont and extend to a
converter terminal located in Comerford, New Hampshire. VETCO was formed to
construct and operate the portion of Phase I within the United States. 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. 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. The
participants in this project, 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, 2003, the present value of the Company's obligation
was approximately $4,647,000. The Company's projected future minimum payments
under the Phase II support agreements are approximately $387,000 for each of the
years 2004-2008 and an aggregate of $2,712,000 for the years 2009-2015.
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 in such companies. 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, 2003, the capital structure of such
corporations was approximately 44 percent common equity and 56 percent long-term
debt. See Note B and Note J of Notes.
Hydro-Quebec
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 (the "VJO
Contract"). Under these two schedules, we purchase 114.2 MW from Hydro-Quebec.
In November 1996, we entered into an arrangement (the "9701 arrangement") with
Hydro-Quebec under which Hydro-Quebec paid $8,000,000 to the Company in exchange
for certain power purchase options. See Item 7. MD and A - Power Supply
Expenses, Power Contract Commitments and Note K of Notes.
During 2003, we used 392,990 MWh under Schedule B, and 271,235 MWh under
Schedule C3 of the VJO Contract, representing 28.1 percent of our net power
supply. The average cost of Hydro-Quebec electricity in 2003 was approximately
$0.07 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 power on short
notice and generally for brief periods of time when required to balance
electricity supply with demand. Opportunity purchases are also arranged when it
is possible to purchase power for less than it would cost us to generate the
power with our own sources. Purchases may also help us save on replacement
power costs during an outage of one of our base load sources. Opportunity sale
prices are generally set so as to recover all of the forecasted fuel or
production costs and to recover some, if not all, associated capacity costs.
During 2003, the Company purchased 453,172 MWh representing 19.2 percent of the
Company's net power supply at an average cost of $0.06 per kWh.
During 2002, the FERC accepted ISO-NE's request to implement a SMD
governing wholesale energy sales in New England. ISO-NE 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. ISO-NE and NEPOOL
have committed to facilitation of a stakeholder process to examine alternative
pricing options, including alternatives to nodal pricing, and to file their
report with FERC in July 2004. We believe that nodal pricing could result in a
material adverse impact on our power supply or transmission costs, if adopted.
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 2003, we used 68,488 MWh from this plant representing 2.9 percent of
our net power supply at an average cost of $0.087 per kWh. See Notes I and K of
Notes.
Wyman Unit #4. The W. F. Wyman Unit #4, which is located in Yarmouth,
Maine, is an oil-fired steam plant with a capacity of 620 MW. Central Maine
Power Company sponsored the construction of this plant. We have a
joint-ownership share of 1.1 percent (7.1 MW) in the Wyman #4 Unit, which began
commercial operation in December 1978.
During 2003, we used 12,030 MWh from this unit representing 0.5 percent of
our net power supply at an average cost of $0.06 per kWh, based only on
operation, maintenance, and fuel costs incurred during 2003. See Note I of
Notes.
McNeil Station. The J.C. McNeil station (the "McNeil Plant"), 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 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 2003, we used 25,328 MWh from this unit representing 1.1 percent of
our net power supply at an average cost of $0.055 per kWh, based only on
operation, maintenance, and fuel costs incurred during 2003. 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-appointed
purchasing agent under a variety of long-term 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's 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 2003 was approximately 34.03
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 2003, through our direct contracts and VEPPI, we purchased 125,465 MWh
of qualifying facilities production representing 5.3 percent of our net power
supply at an average cost of $0.122 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 2003, Company owned hydroelectric plants produced 107,406 MWh,
representing 4.5 percent of our net power supply at an average cost of $0.03 per
kWh based on operating and maintenance expenses, excluding depreciation expense
and amortization of licensing costs. 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 the New York Power Authority 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 2003, our retail and requirements wholesale sales were
provided by the following fuel sources:
* 35.4 percent from hydroelectric sources (28.1 percent Hydro-Quebec, 4.5
percent Company-owned, and 2.8 percent independent power producers;
* 37.4 percent from a nuclear generating source (the ENVY nuclear plant);
* 3.5 percent from wood;
* 1.3 percent from natural gas;
* 2.7 percent from oil;
* 0.5 percent from wind; and
* 19.2 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 2003. None 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 330,503 tons of
wood chips and mill residue, 423,310 gallons of fuel oil, and 31 million cubic
feet of natural gas in 2003. The McNeil plant, assuming any needed regulatory
approvals are obtained, is forecasting 2004 consumption of wood chips to be
400,000 tons, fuel oil of 70,000 gallons and natural gas consumption of 36
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 expenditures 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 2003, the project produced 10,828 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, 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, 2003, the Company had 196 employees, exclusive of
temporary employees. The Company considers its relations with employees to be
excellent.
ENERGY EFFICIENCY
In 2003, 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. A charge per KW and per KWH is applied. The
purpose of these charges is to apply equal efficiency charges across Vermont to
customers with similar usage, regardless of their local utility rates. The
charge represents two to three percent of each customer's total electric bill.
The funds we collect are remitted to a fiscal agent representing the State of
Vermont.
RATE DESIGN
The Company seeks to design rates to encourage efficient electrical use.
Since 1976, we have offered optional time-of-use rates for residential and
commercial customers. Currently, approximately 1,800 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.
At December 31, 2003, approximately 1,700 of the Company's largest customers,
comprising approximately 51 percent of retail revenues, received service on
mandatory time-of-use rates. As a result of the VPSB approval of the 2003
Rate Plan, the Company will file with the VPSB a new fully-allocated cost of
service study and rate re-design, which will allocate the Company's revenue
requirement among all customer classes on the basis of current costs. The new
rate design will be subject to VPSB approval and is not expected to adversely
affect operating results.
DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS
In 2003, we had 27 dispatchable power contracts: 22 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 business in the process of completing dissolution. For
information regarding our remaining unregulated businesses, see Note A and Note
L of Notes.
EXECUTIVE OFFICERS
The names, ages, and positions of our Executive Officers, in alphabetical order,
as of March 15, 2004 are:
Christopher L. Dutton 55
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 47
Chief Financial Officer since December 2003. Vice President since July
2003. Treasurer since February 2002. Controller from October 1996 to December
2003. Manager of General Accounting from 1990 to 1996.
Walter S. Oakes 57
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 43
Senior Vice President-Chief Operating Officer since April 2001. Senior
Vice President-Customer and Organizational Development from December 1999 to
April 2001. 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, Ms. Powell was President
of HRworks, Inc., a human resources management firm, from January 1997 to March
1998.
Donald J. Rendall 48
Vice President, General Counsel and Corporate Secretary since July 2002,
March 2002, and December 2002, respectively. Prior to joining the Company, Mr.
Rendall was a principal in the Burlington, Vermont law firm of Sheehey, Furlong,
Rendall & Behm, P.C. from 1988 to February 2002.
Stephen C. Terry 61
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.
The Board of Directors of the Company and its wholly owned subsidiaries, as
appropriate, elects officers for one-year terms to 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 67.6 MW
and an estimated aggregate claimed capability of 61.2 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:
* 33.6 percent of the outstanding common stock of Vermont Yankee and,
through its contract with ENVY, we are entitled to 20.0 percent (106.2 MW of a
total 531 MW) of the capacity of the ENVY nuclear generating 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, 2003, approximately 2 miles of 115 kV
transmission lines, 10 miles of 69 kV transmission lines, 5 miles of 44 kV
transmission lines, 244 miles of 34.5 kV transmission lines, and 2 miles of 13.8
kV transmission lines. Our distribution system included approximately 2,573
miles of overhead lines of 2.4 to 34.5 kV and 420 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 905,000 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 Turbine . . . . . . Berlin, VT Berlin #5 Oil 56.6
Turbine . . . . . . . . Colchester, VT Gorge #16 Oil 16.1
Wind. . . . . . . . . . Searsburg, VT Searsburg Wind 5.9
Jointly Owned
Steam . . . . . . . . . Yarmouth, ME Wyman #4 Oil 7.1
Steam . . . . . . . . . Burlington, VT McNeil Wood/Gas 6.6 (2)
Combined. . . . . . . . Ludlow, MA Stony Brook #1 Oil/Gas 31.0
Total Winter Capability 167.2
=====
(1) Reservoir has been drained, dam awaiting repairs by the State of Vermont.
(2) 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.
CORPORATE HEADQUARTERS
Our headquarters and main service center are located in Colchester Vermont,
one of the most rapidly growing areas of our service territory.
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 - Other Risks, 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 2002 and 2003:
HIGH LOW
------ ------
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
2003
First Quarter. $21.19 $19.02
Second Quarter 21.78 20.00
Third Quarter. 22.72 20.06
Fourth Quarter 23.84 21.98
The number of common stockholders of record as of February 18, 2004 was
approximately 5,119.
Quarterly cash dividends were paid as follows during the past two years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- --------
2002 $ 0.1375 $ 0.1375 $ 0.1375 $ 0.1900
2003 $ 0.1900 $ 0.1900 $ 0.1900 $ 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 increased its dividend from an annual rate of $0.76 per share
to $0.88 per share during February 2004, and intends to increase the dividend in
a measured consistent manner until the payout ratio falls between 50 percent and
70 percent of anticipated earnings, so long as financial and operating results
permit. We believe this payout ratio to be consistent with that of other
electric utilities having similar risk profiles.
ITEM 6. SELECTED FINANCIAL DATA
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
2003 2002 2001 2000 1999
--------- --------- --------- --------- ---------
In thousands, except per share data
Operating Revenues. . . . . . . . . . . . . . . . . . . . . . . $280,470 $274,608 $283,464 $277,326 $251,048
Operating Expenses. . . . . . . . . . . . . . . . . . . . . . . 265,164 259,528 267,005 272,066 243,102
Operating Income. . . . . . . . . . . . . . . . . . . . . 15,306 15,080 16,459 5,260 7,946
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity. . . . . . . . . . . . . . . . . . . . . . 387 233 210 284 134
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1,692 2,252 2,163 2,422 3,319
Total other income. . . . . . . . . . . . . . . . . . . . 2,079 2,485 2,373 2,706 3,453
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed. . . . . . . . . . . . . . . . . . . . . (267) (103) (188) (228) (91)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 7,324 6,273 7,227 7,485 7,274
Total interest charges. . . . . . . . . . . . . . . . 7,057 6,170 7,039 7,257 7,183
--------- --------- --------- --------- ---------
Net Income (Loss) from continuing operations before . . . . . . 10,328 11,395 11,793 709 4,216
preferred dividends
Net Income (Loss) from discontinued operations, including
provisions for loss on disposal. . . . . . . . . . . . . . . 79 99 (182) (6,549) (7,279)
Dividends on Preferred Stock. . . . . . . . . . . . . . . . . . 3 96 933 1,014 1,155
--------- --------- --------- --------- ---------
Net Income (Loss)Applicable
to Common Stock . . . . . . . . . . . . . . . . . . . . . $ 10,404 $ 11,398 $ 10,678 $ (6,854) $ (4,218)
========= ========= ========= ========= =========
Common Stock Data
Basic earnings per share-continuing operations . . . . . . . . $ 2.08 $ 2.02 $ 1.93 $ (0.06) $ 0.57
Basic earnings per share-discontinued operations . . . . . . . $ 0.01 $ 0.02 $ (0.03) $ (1.19) $ (1.36)
Basic earnings per share . . . . . . . . . . . . . . . . . . . $ 2.09 $ 2.04 $ 1.90 $ (1.25) $ (0.79)
========= ========= ========= ========= =========
Diluted earnings (loss) per share from continuing operations . $ 2.01 $ 1.96 $ 1.88 $ (0.06) $ 0.57
Diluted earnings (loss) per share from discontinued operations $ 0.01 $ 0.02 $ (0.03) $ (1.19) $ (1.36)
Diluted earnings (loss) per share. . . . . . . . . . . . . . . $ 2.02 $ 1.98 $ 1.85 $ (1.25) $ (0.79)
========= ========= ========= ========= =========
Cash dividends declared per share . . . . . . . . . . . . . . . $ 0.60 $ 0.60 $ 0.55 $ 0.55 $ 0.55
Weighted average shares outstanding-basic. . . . . . . . . . . 4,980 5,592 5,630 5,491 5,361
Weighted average share equivalents outstanding-diluted . . . . 5,140 5,756 5,789 5,491 5,361
FINANCIAL CONDITION AS OF DECEMBER 31
------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- -------- --------
In thousands
ASSETS
Utility Plant, Net. . . . . . . . . . . $228,862 $223,476 $196,858 $194,672 $192,896
Other Investments . . . . . . . . . . . 13,706 21,552 20,945 20,730 20,665
Current Assets. . . . . . . . . . . . . 31,688 31,432 36,183 53,652 33,238
Deferred Charges. . . . . . . . . . . . 55,590 60,390 72,468 46,036 41,853
Non-Utility Assets. . . . . . . . . . . 1,105 995 1,075 1,518 11,099
Total Assets. . . . . . . . . . . . . . $330,951 $337,845 $327,529 $316,608 $299,751
======== ======== ======== ======== ========
CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . . $ 99,915 $ 91,722 $101,277 $ 92,044 $100,645
Redeemable Cumulative Preferred Stock . - 55 12,560 12,795 14,435
Long-Term Debt, Less Current Maturities 93,000 93,000 74,400 72,100 81,800
Capital Lease Obligation. . . . . . . . 4,963 5,287 5,959 6,449 7,038
Current Liabilities . . . . . . . . . . 22,715 38,491 38,841 68,109 36,708
Deferred Credits and Other. . . . . . . 108,868 107,349 92,791 61,794 59,125
Non-Utility Liabilities . . . . . . . . 1,490 1,941 1,701 3,317 -
Total Capitalization and Liabilities. . $330,951 $337,845 $327,529 $316,608 $299,751
======== ======== ======== ======== ========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
EXECUTIVE OVERVIEW - Green Mountain Power Corporation (the "Company") generates
virtually all of its earnings from retail electricity sales. Our retail
electricity sales grow at an average annual rate of between one and two percent,
about average for most electric utility companies in New England. While
wholesale revenues are significant, they have relatively minor impact on our
operating results and financial condition. The Company is regulated and cannot
adjust prices of retail electricity sales without regulatory approval from the
Vermont Public Service Board ("VPSB").
The Company increased its dividend in February 2004 from an annual rate of
$0.76 per share to $0.88 per share. The Company's dividend payout ratio remains
comparatively low, at less than 45 percent of 2003 earnings. We expect to grow
our dividend payout ratio to between 50 and 70 percent over the next five years,
in line with other electric utilities having similar risk profiles, so long as
financial and operating results permit.
Fair regulatory treatment is fundamental to maintaining the Company's
financial stability. Rates must be set at levels to recover costs, including a
market rate of return to equity and debt holders. In December 2003, the Company
received approval from the VPSB of a new rate plan covering the period 2003
through 2006, which sets rates at levels the Company believes will provide an
improved opportunity to recover our costs, and to earn our allowed rate of
return.
Power supply expenses are equivalent to approximately 70 percent of total
revenues. The Company's need to seek rate increases from its customers
frequently moves in tandem with increases in our power supply costs. We have
entered into long-term power supply contracts for most of our energy needs. All
of our power supply contract costs are currently being recognized in the rates
we charge our customers. The risks associated with our power supply resources,
including outage, curtailment, and other delivery risks, the timing of contract
expirations, the volatility of wholesale prices, and other factors impacting our
power supply resources and how they relate to customer demand are discussed
below under Item 7a, "Quantitative and Qualitative Disclosure about Market Risk,
and Other Risk Factors."
We also discuss other risks, including load risk related to our largest
customer, International Business Machines Corporation ("IBM"), and contingencies
that could have a significant impact on future operating results and our
financial condition.
Growth opportunities beyond the Company's normal investment in its
infrastructure are also discussed, and include a planned increase in our equity
investment in Vermont Electric Power Company, Inc. ("VELCO") and a planned
increase in sales of utility services.
In this section, we explain the general financial condition and the results
of operations for 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 affect our overall financial condition.
Our critical accounting policies are discussed below under Item 7a,
"Quantitative And Qualitative Disclosures About Market Risk, And Other Factors,"
under "Liquidity and Capital Resources - Pension," in Note A, "Significant
Accounting Policies," and in Note H, "Pension and Retirement Plans." Management
believes the most critical accounting policies include the timing of expense and
revenue recognition under the regulatory accounting framework within which we
operate; the manner in which we account for certain power supply arrangements
that qualify as derivatives; the assumptions that we make regarding defined
benefit plans; and revenue recognition, particularly as it relates to unbilled
and deferred revenues. These accounting policies, among others, affect the
Company's significant judgments and estimates used in the preparation of its
consolidated financial statements.
There are statements in this section that contain projections or estimates
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 include:
regulatory and judicial decisions or legislation
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
industry restructuring and cost recovery (including stranded costs)
weather
We address these items in more detail below.
These forward-looking statements represent our estimates and assumptions only as
of the date of this report.
EARNINGS SUMMARY YEARS ENDED
2003 2002 2001
------- ------- -------
Consolidated earnings per share of common stock $ 2.02 $ 1.98 $ 1.85
Consolidated return on average common equity. . 10.76% 11.03% 11.02%
The Company reported consolidated earnings of $2.02 per share of common
stock, diluted, in 2003 compared to consolidated earnings of $1.98 per share,
diluted, in 2002. The improvement in earnings per share reflected reduced power
supply expenses to serve retail sales, an increase in sales to residential
customers and a reduction in the number of common stock shares outstanding.
These favorable developments more than offset increased administrative and
general costs, a reduction in the Company's allowed rate of return, increased
interest expense in 2003, and a decrease in the recognition of deferred
revenues, compared with 2002.
Our financial health improved during 2001 and 2002. As a result, we were
able to reduce significantly our cost of capital in the fourth quarter of 2002
by issuing new long-term debt and using a portion of the proceeds to acquire
approximately 812,000 shares of our common stock. Our 2003 earnings per share
improved by approximately $0.09 per share as a result of the stock buyback.
In December 2003, the VPSB approved a rate plan for the period 2003 through 2006
(the "2003 Rate Plan"), jointly proposed by the Company and the Vermont
Department of Public Service (the "Department" or the "DPS"). The 2003 Rate
Plan provides the Company with a stable, predictable rate path through 2006, a
plan for full recovery of the Company's principal regulatory assets, and an
improved opportunity for the Company to earn its allowed rate of return through
2006. The 2003 Rate Plan calls for no retail rate increases in 2003 or 2004,
then scheduled increases of 1.9 percent effective January 1, 2005, and 0.9
percent effective January 1, 2006. The 2003 Rate Plan sets the Company's
allowed return on equity from core utility operations at 10.5 percent, effective
with 2003, and provides for an earnings cap at that level through 2006. The
2003 Rate Plan is summarized in more detail below under "Rates."
The VPSB's January 2001 rate order (the "2001 Settlement Order") allowed the
Company to defer revenues of approximately $8.5 million, generated by leveling
winter/summer rates during 2001, to help offset costs and realize our allowed
rate of return during the 2001-2003 period. We recognized approximately $1.1
million of these deferred revenues to achieve our allowed rate of return during
2003, compared with approximately $4.4 million recognized in 2002. The VPSB has
permitted the Company to carry over unused deferred revenues totaling
approximately $3.0 million to 2004 as part of the 2003 Rate Plan.
The improvement in earnings from continuing operations in 2002, compared with
2001, resulted primarily from lower capital costs and other operating expenses,
including:
$0.9 million reduction in interest expense, reflecting lower interest rates
and average debt levels;
$0.8 million reduction in preferred stock dividends, reflecting the
Company's redemption of outstanding preferred stock; and
Recognition of $4.4 million in revenue deferred from 2001 under the 2001
Settlement Order.
These favorable results were partially offset by increased maintenance
expense, transmission expense and power supply expense to serve retail
customers, compared to 2001.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, AND OTHER
RISK FACTORS.
We consider our principal risks to include power supply risks, our
regulatory environment (particularly as it relates to the Company's periodic
need for rate relief), risks associated with our principal customer, IBM,
pension and postretirement healthcare costs and weather. Discussion of these
and other risks, as well as factors contributing to mitigation of these risks,
follows.
POWER SUPPLY RISK.
The Company's most significant power supply contracts are the Hydro-Quebec
Vermont Joint Owners ("VJO") Contract (the "VJO Contract") and the Vermont
Yankee Nuclear Power Corporation ("VY" or "Vermont Yankee") contract (the
"Vermont Yankee Contract") which are summarized in the following table.
2003 2003 2002 2002 Contract
MWh $/MWh MWh $/MWh Expires
------- ------ ------- ------ -------
VJO Contract. . . . . . 664,225 $69.81 724,708 $66.11 2015
Vermont Yankee Contract 884,585 $43.08 771,782 $44.55 2012
All of the Company's power supply contract costs are currently being
recovered through rates approved by the VPSB.
We expect approximately 90 percent of our estimated customer demand
("load") requirements through 2006 to be met by these contracts and by our
generation and other power supply resources. These contracts and resources
significantly reduce the Company's exposure to volatility in wholesale energy
market prices. The Company's power supply contracts are described in more
detail below under the heading "Power Contract Commitments."
A primary factor affecting future operating results is the volatility of
the wholesale electricity market. Implementation of New England's wholesale
market for electricity has increased volatility of wholesale power prices.
Periods frequently occur when weather, availability of power supply resources
and other factors cause significant differences between customer demand and
electricity supply. Because electricity cannot be stored, in these situations
the Company must buy or sell the difference into a marketplace that has
experienced volatile energy prices. Volatility and market price trends also
make it more difficult to extend or enter into new power supply contracts at
prices that avoid the need for rate relief.
During 2002, we estimate that the Company paid an additional $1.0 million
for replacement power as the result of an unscheduled outage at the Vermont
Yankee nuclear power plant. While the Vermont Yankee plant has had an excellent
operating record, future unscheduled outages could occur at times when
replacement energy costs are above Vermont Yankee Contract costs.
We sometimes experience energy delivery deficiencies under the VJO Contract
as a result of outages or other problems with the transmission interconnection
facilities over which we schedule deliveries. When such deficiencies occur, we
purchase replacement energy on the wholesale market, usually at prices that are
higher than VJO Contract costs.
Under the VJO 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
contract. Hydro-Quebec exercised the first of these load reduction options,
effective for the year 2003. The net cost of Hydro-Quebec's exercise of this
option increased power supply expense during 2003 by approximately $1.2 million.
During 2003, Hydro-Quebec exercised its second option to reduce the load factor
for 2004, which we estimate will increase power supply expense by approximately
$1.0 million. We expect Hydro-Quebec to exercise its third option in 2004 for
deliveries occurring principally during 2005, at an estimated cost of $1.0
million to $1.2 million, based on current wholesale market prices for 2005.
Hydro-Quebec also retains the right under the VJO Contract 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. Hydro-Quebec has not
exercised this right and has not communicated to the Company any present
intention to do so.
Under the VJO Contract, the VJO, including the Company, have two options to
adjust deliveries by a five percent load factor. These options cannot be used
to offset Hydro-Quebec's reductions through 2005, but may be used after 2005 to
manage power supply costs.
The Company has established a risk management program designed 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. These transactions are
used to hedge the risk of fossil fuel and spot market electricity price
increases. Some of these transactions present the risk of potential losses from
adverse changes in commodity prices. Our risk management policy specifies risk
measures, the amount of tolerable risk exposure, and authorization limits for
transactions. Our principal power supply contract counter-parties and
generators, Hydro-Quebec, Entergy Nuclear Vermont Yankee, LLC ("ENVY") and
Morgan Stanley Capital Group, Inc. ("Morgan Stanley"), all currently have
investment grade credit ratings.
The Company has a contract with Morgan Stanley (the "Morgan Stanley
Contract") that is used to hedge our power supply costs against increases in
fossil fuel prices. Morgan Stanley purchases the majority of the Company's
power supply resources at index prices for fossil fuel resources and specified
prices for contracted resources and then sells power to the Company at a fixed
rate to serve pre-established load requirements. This contract, along with
other power supply commitments, allows us to fix the cost of most of our power
supply requirements, subject to power resource availability and other risks.
The Morgan Stanley Contract is described in more detail below under the heading
"Power Contract Commitments." The Morgan Stanley Contract is a derivative under
Statement of Financial Accounting Standards No. 133 ("SFAS 133") and is
effective through December 31, 2006. Management has estimated the fair value of
the future net benefit of this arrangement at December 31, 2003, is
approximately $4.0 million.
We currently have an arrangement that grants Hydro-Quebec an option (the
"9701 arrangement") to call power at prices that are expected to be below
estimated future market rates. The 9701 arrangement is described in more detail
below under the heading "Power Supply Expenses." 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, 2003, is
approximately $23.7 million. We sometimes use forward contracts to hedge
forecasted calls by Hydro-Quebec under the 9701 arrangement.
The table below presents assumptions used to estimate the fair value of the
Morgan Stanley Contract and the 9701 arrangement. The forward prices for
electricity used in this analysis are consistent with the Company's current
long-term wholesale energy price forecast.
Option Value Risk Free Price Average Contract
Model Interest Rate Volatility Forward Price Expires
------------- -------------- ----------- -------------- -------
Morgan Stanley Contract Deterministic 3.4% 32%-29% $ 42 2006
9701 Arrangement. . . . Black-Scholes 4.6% 48%-27% $ 60 2015
The table below presents the Company's market risk of the Morgan Stanley and
Hydro-Quebec derivatives, estimated as the potential loss in fair value
resulting from a hypothetical ten percent adverse change in wholesale energy
prices, which nets to approximately $1.2 million. Actual results may differ
materially from the table illustration. Under an accounting order issued by the
VPSB, changes in the fair value of derivatives are deferred.
Commodity Price Risk At December 31, 2003
Fair Value(Cost) Market Risk
----------------- -------------
(in thousands)
Morgan Stanley Contract $ 3,990 $ 2,160
9701 Arrangement. . . . (23,724) (3,342)
----------------- -------------
(19,734) (1,182)
REGULATORY RISK
Management believes that fair regulatory treatment is crucial to
maintaining its financial stability, including its ability to attract capital.
Vermont is the only state in the New England region that has not adopted some
form of electric industry restructuring. The Company, like all other electric
utilities in Vermont, accordingly operates as a vertically integrated electric
utility, with the obligation to serve all customers in our service territory
with electrical transmission, distribution and energy supplies sufficient to
satisfy customer load requirements.
Vermont does not have a fuel or purchased-power adjustment clause that would
allow increases in power supply costs to be recovered immediately in the rates
we charge customers. Historically, however, the VPSB has allowed electric
utilities to defer material unexpected increases in power supply costs to future
periods to permit recovery in future rates. Vermont law also allows electric
utilities to seek temporary rate increases if deemed necessary by the VPSB to
provide adequate and efficient service or to preserve the viability of the
utility.
Electric utility rates in Vermont are set based on the 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 filed its last
retail rate case during 1998. Since that time we have deferred a material
amount of expenditures as regulatory assets. These regulatory assets have been
judged as probable of recovery by management. As of December 31, 2003, the most
significant regulatory assets not being recovered in current rates are the
following:
Regulatory assets
At December 31,
2003 2002
--------------- -------
(in thousands)
Pine Street barge canal . . $ 12,954 $13,019
Demand-side management. . . 6,713 6,434
Unscheduled VY outage costs 2,178 2,002
--------------- -------
Total . . . . . . . . . . . $ 21,845 $21,455
=============== =======
The 2003 Rate Plan, approved by the VPSB in December 2003, provides for
amortization and recovery of all of the regulatory assets listed above,
beginning January 1, 2005. The Pine Street Barge Canal regulatory asset will be
amortized over a period of 20 years without a return on the remaining balance of
the asset. The remaining assets will be amortized over a five-year period.
Both the demand-side management and the unscheduled VY outage costs accrue a
return defined by the Federal Energy Regulatory Commission ("FERC") based on the
capital structure of the utility ("AFUDC rate"). The AFUDC rate for 2003 for
the Company was approximately 8.5 percent.
The Company currently complies with the provisions of SFAS 71. If we had
determined that the Company no longer met the criteria for following SFAS 71, at
December 31, 2003, the accounting impact would have been an extraordinary
non-cash charge to operations of $55.5 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;
competition that limited our ability to sell utility services or products
at rates that will recover costs; or
regulatory actions that limit rate relief to a level insufficient to
recover costs.
There are currently no regulatory proceedings, court actions or pending
legislative proposals to adopt electric industry restructuring in Vermont.
Legislation has been introduced in the Vermont legislature that would permit
(but not require) the Company to negotiate with individual customers to permit
such customers to procure their own electric power supply requirements, subject
to VPSB approval. We cannot predict whether this legislation will be enacted.
If enacted, the Company would not negotiate any such arrangement unless, in our
estimation, the arrangement assured the Company of full recovery of any
resulting stranded costs and that the Company's financial condition would not
otherwise be adversely affected.
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 wholesale market price of power. We have discussed various market price
scenarios with interested parties for the purpose of identifying stranded costs.
Based on preliminary market price assumptions, which are likely to change, we
estimate the Company's stranded costs to be between $206 million and $252
million over the life of the Company's current contracts.
If Vermont adopted retail competition or some other form of electric industry
restructuring or if the VPSB issued a regulatory order containing provisions
that did not allow the Company to recover above-market power costs, the Company
could be required 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.
CUSTOMER CONCENTRATION RISK - IBM, the Company's largest customer, operates a
manufacturing facility in Essex Junction, Vermont. IBM's electricity
requirements for its facility accounted for approximately 24.1, 25.7, and 26.6
percent of the Company's retail MWh sales in 2003, 2002, and 2001, respectively,
and 16.6, 17.3, and 19.2 percent of the Company's retail operating revenues in
2003, 2002, and 2001, 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 22, 2003, the
VPSB approved a new three-year agreement between the Company and IBM, ending
December 31, 2006. The price of power under the agreement is above our marginal
costs of providing incremental service to IBM. The VPSB approval provides that
the agreement automatically terminates if IBM's full-time-equivalent employment
level at its Vermont facility served by the agreement drops by more than 5
percent from the level on the date of VPSB approval.
IBM has reduced its Vermont workforce by approximately 2,500 since 2001, to
a level of approximately 6,000 employees. Company revenue from sales of
electricity to IBM declined $1.8 million in 2003 compared with 2002. Our
operating results were not adversely impacted by the reduction in sales to IBM
due to continued revenue growth in other customer classes and because the gross
margin on sales to IBM is relatively low. If we experienced a material
reduction in earnings as a result of significantly lower retail sales, we would
seek a retail rate increase from the VPSB. The Company is permitted to seek
such a rate increase request under our approved 2003 Rate Plan. We are 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, that a
hypothetical shutdown of the IBM facility would require a retail rate increase
for all our remaining customers in the range of five to eight percent.
PENSION AND POSTRETIREMENT HEALTH CARE RISK - Other critical accounting policies
involve the Company's defined benefit pension and postretirement health care
benefit plans. The reported costs of these plans depend upon numerous factors
relating to actual plan experience and assumptions of future experience.
Pension and postretirement health care costs are affected by actual
employee demographics, Company contributions to the plans, earnings on plan
assets, and, for our postretirement health care plan, health care cost trends.
The Company contributed $1.0 million and $3.5 million to its pension plan during
2002 and 2003, respectively, and we expect to contribute between $2.0 and $3.0
million during 2004.
Our 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 increase or decrease 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.
On December 17, 2003, the Company's employees ratified a four-year labor
agreement that provides annual wage increases of between 3.5 and 4 percent and
improved 401(k) and pension benefits for employees. The new labor agreement
caps future postretirement healthcare employee benefits provided by the Company
for the majority of the present workforce. The cap on postretirement healthcare
benefits is set approximately 13 percent above 2003 costs and grows at a 3
percent annual rate. This cap should reduce the rate at which postretirement
healthcare expenses grow in the future.
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. The liability was recorded as a reduction to common
equity through a charge to Other Comprehensive Income ("OCI"). Favorable
pension plan investment returns during 2003 reduced the OCI charge and related
net liability by $587,000. The 2002 OCI charge and the 2003 OCI benefit had no
effect on net income for either year.
WEATHER - The Company now uses weather insurance to mitigate some of the risk of
lost electricity sales caused by unfavorable weather conditions. The Company
has purchased weather insurance coverage for 2004. Coverage is based on
cumulative variations from normal weather, measured in net heating and cooling
degree-days.
RESULTS OF OPERATIONS
OPERATING REVENUES AND MWH SALES - Operating revenues, megawatthour ("MWh")
sales and number of customers for the years ended 2003, 2002 and 2001 were as
follows:
Years ended December 31,
2003 2002 2001
----------------------- ---------- ----------
(dollars in thousands)
Operating Revenues
Retail*. . . . . . . $ 198,717 $ 201,052 $ 195,093
Sales for Resale . . 78,901 70,646 83,804
Other. . . . . . . . 2,852 2,910 4,567
----------------------- ---------- ----------
Total Operating Revenues $ 280,470 $ 274,608 $ 283,464
======================= ========== ==========
MWH Sales-Retail . . . . 1,934,340 1,948,190 1,953,154
MWH Sales for Resale . . 2,287,039 2,107,941 2,368,887
----------------------- ---------- ----------
Total MWH Sales. . . . . 4,221,379 4,056,131 4,322,041
======================= ========== ==========
*Retail revenues include $1.1 million, $4.4 million and $0.0 million of deferred
revenue recognized for 2003, 2002, and 2001, respectively.
Average Number of Customers
Years ended December 31,
2003 2002 2001
------ ------ ------
Residential . . . . . . . 74,693 73,861 73,249
Commercial and Industrial 13,369 13,194 13,006
Other . . . . . . . . . . 65 65 65
------ ------ ------
Total Number of Customers. . 88,127 87,120 86,320
====== ====== ======
Comparative changes in operating revenues are summarized below:
Change in Operating Revenues 2002 to 2001 to
2003 2002
--------------- ---------
(In thousands)
Retail Rates . . . . . . . . $ (912) $ 6,471
Retail Sales Volume. . . . . (1,423) (512)
Resales and Other Revenues . 8,197 (14,815)
--------------- ---------
Change in Operating Revenues $ 5,862 $ (8,856)
=============== =========
In 2003, total electricity sales increased 4.1 percent compared with 2002, due
to increased wholesale sales and sales to residential and commercial customers,
partially offset by decreased sales to industrial customers. Total operating
revenues increased $5.9 million, or 2.1 percent, compared with 2002 as a result
of the following:
Increased wholesale revenues of $8.3 million, primarily due to increased
system sales during peak demand periods and increased sales to Hydro-Quebec
under the 9701 arrangement;
Increased retail residential revenues of $3.2 million, or 4.5 percent,
arising from increased sales of electricity; and
Increased retail small commercial and industrial ("C&I") revenues of
$900,000, or 1.3 percent, arising from increased sales of electricity.
These increases were partially offset for the following reasons:
The Company recognized $1.1 million in deferred revenues under the 2001
Settlement Order, reduced from $4.4 million recognized in 2002.
Decreased retail large C&I revenues of $2.6 million, or 1.7 percent, when
compared with 2002, resulting from a decline in sales of electricity to this
customer class.
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 Morgan Stanley 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 2001 Settlement Order. Increased sales to residential and
commercial customers also contributed to higher retail revenues, partially
offset by a decline in revenues from IBM.
POWER SUPPLY EXPENSES - Power supply expenses constituted 74.4, 74.5 and 75.3
percent of total operating expenses for the years 2003, 2002, and 2001,
respectively.
Power supply expenses increased by $3.9 million, or 2.0 percent, in 2003
when compared with 2002, and resulted from the following:
an $8.3 million increase in the cost of power purchased for resale;
a $2.7 million increase in power supply expenses under agreements with
Hydro-Quebec;
higher costs of electricity supplied by independent power producers; and
higher wholesale prices for electricity.
These increases were partially offset by an $8.9 million decrease in the
cost of power under our contract with Morgan Stanley and lower unit prices from
Vermont Yankee.
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 Morgan Stanley 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:
a $6.2 million increase in the cost of power purchased from Morgan Stanley;
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 CONTRACT COMMITMENTS - On February 11, 1999, the Company entered into a
contract with Morgan Stanley (the "Morgan Stanley Contract") designed to manage
price risks associated with changing fossil fuel prices. In August 2002, the
Morgan Stanley Contract was modified and extended to December 31, 2006.
Under the Morgan Stanley Contract, on a daily basis, and at Morgan Stanley's
discretion, we sell power to Morgan Stanley 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. Morgan Stanley sells to the Company, at a predefined
price, power sufficient to serve pre-established load requirements. Morgan
Stanley is also responsible for scheduling supply resources. We remain
responsible for resource performance and availability. Morgan Stanley provides
no coverage against major unscheduled power supply outages. Beginning January
1, 2004, the Company will reduce the power that it sells to Morgan Stanley.
Some of our power-supply resources, including purchases pursuant to our
Hydro-Quebec and Vermont Yankee contracts, which were sold to Morgan Stanley
through 2003, will no longer be included in the Morgan Stanley Contract. This
reduction in sales to Morgan Stanley is expected to reduce wholesale revenues by
approximately $64 million and correspondingly to reduce power supply expense by
a similar amount. We do not expect this change to adversely affect the
Company's opportunity to earn its allowed rate of return during 2004.
The Company's current purchases under the VJO Contract with Hydro-Quebec
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, beginning in November 1995.
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 also parties to the contract would be required to purchase
their proportionate share of the power supply entitlement of any defaulting
utility. The Company is not aware of any instance where this provision has been
invoked by Hydro-Quebec.
Under the Company's 9701 arrangement, 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 VJO Contract, which ends in 2015, Hydro-Quebec may purchase up to
52,500 MWh on an annual basis ("option A") at the VJO Contract energy price,
which is substantially below current market prices. The cumulative amount of
energy that may be purchased under option A may not exceed 950,000 MWh (52,500
MWh in each contract year.)
Over the same period, Hydro-Quebec may exercise an option to purchase up to
200,000 MWh on an annual basis at the VJO Contract energy price ("option B").
The cumulative amount of energy that may be purchased under option B may not
exceed 600,000 MWh. As of December 31, 2003, Hydro-Quebec had purchased 513,000
MWh under option B. The Company expects Hydro-Quebec to call its remaining
entitlements under option B during 2004 and 2005.
In 2003, Hydro-Quebec exercised option A and option B, and called for
delivery to third parties at a net expense to the Company of approximately $4.5
million, including capacity charges.
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.
We believe that it is probable that Hydro-Quebec will call options A and B
for 2004, and the Company has purchased replacement power at a net cost of $3.2
million. The Company has also covered 54 percent of expected calls during 2005
at a net cost of $1.1 million.
VERMONT YANKEE NUCLEAR POWER CORPORATION
On July 31, 2002, Vermont Yankee completed the sale of its nuclear power
plant to ENVY. As part of the sale transaction, Vermont Yankee entered into a
Power Purchase Agreement ("PPA") with ENVY pursuant to which ENVY is obligated
to provide 20 percent of the plant output to the Company through 2012, which
represents approximately 35 percent of our energy requirements. Prices under
the PPA range from $39 to $45 per MWh for the period beginning January 2003,
substantially lower than our forecasted cost if Vermont Yankee had continued to
own and operate the plant facilities. In 2002, contract prices ranged from $49
to $55 under the PPA, higher than the forecasted cost of continued ownership.
The PPA contains a provision known as the "low market adjuster," which calls for
a downward adjustment in the price if market prices for electricity fall by
defined amounts beginning in November 2005. If market prices rise, however, PPA
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 ENVY plant.
The Company received $8.2 million in October 2003, representing its share
of the Vermont Yankee power plant sale proceeds, and used the proceeds to retire
debt.
The Vermont Yankee sale required various regulatory approvals, all of which
were granted on terms acceptable to the parties to the transaction. Certain
intervenor parties to the VPSB approval proceeding appealed the VPSB approval to
the Vermont Supreme Court. The Court rejected the appeal and affirmed the VPSB
approval during 2003.
OTHER OPERATING EXPENSES - Other operating expenses increased $3.5 million, or
24.5 percent, in 2003 compared with 2002 primarily due to increased employee
benefit expenses and expenses related to corporate governance. A cap on
post-retirement healthcare benefits, improved market returns and benefit plan
funding should reduce growth in administrative and general expenses in 2004.
Other operating expenses decreased $1.7 million, or 10.9 percent, in 2002
compared with 2001. The decrease was primarily due to reduced consulting
expenses of approximately $1.0 million and reduced distribution expenses of $0.6
million.
TRANSMISSION EXPENSES - Transmission expenses decreased $438,000, or 2.9
percent, in 2003 compared with 2002, due to decreased congestion costs allocated
by ISO New England to Vermont utilities in conjunction with transition to a new
standard market design ("SMD"). See discussion below.
Transmission expenses increased $1.1 million, or 7.7 percent, in 2002
compared with 2001. The Company's relative share of transmission expenses
varies with the peak demand recorded on Vermont's transmission system. The
Company's share of those expenses increased due to its increased load growth,
relative to other Vermont utilities, and also because of increased transmission
investment by VELCO.
The Independent System Operator of New England ("ISO-NE" or "ISO New
England") was created to manage the operations of the New England Power Pool
("NEPOOL"), effective May 1, 1999. ISO-NE operates a market for all New England
states 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.
During 2002, the FERC accepted ISO-NE's request to implement a SMD
governing wholesale energy sales in New England. ISO-NE 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. ISO-NE and NEPOOL
have committed to facilitation of a stakeholder process to examine alternative
pricing options, including alternatives to nodal pricing, and to file their
report with FERC in July 2004. We believe that nodal pricing could result in a
material adverse impact on our power supply and/or transmission costs, if
adopted.
On October 31, 2003, ISO-NE, together with New England's principal
transmission system owners including VELCO, filed a request for approval of a
regional transmission organization for New England ("RTO-NE"). The proposed
RTO-NE would become the provider of regional transmission service in New
England, with operational control of the bulk power system and responsibility
for administering markets currently operated and administered by ISO-NE. If the
RTO is approved by FERC, the current ISO-NE agreement with the New England Power
Pool ("NEPOOL"), the Restated NEPOOL Agreement, the NEPOOL Open Access
Transmission Tariff and individual local tariffs currently maintained by New
England transmission owners would terminate and be superseded by new RTO-NE
agreements. Also on October 31, 2003, certain transmission owners in New
England, including the Company, reached an agreement to submit a tariff,
agreements and other documents to FERC to include costs associated with certain
transmission facilities, known as the Highgate Facilities, of which the Company
is a part owner, in region-wide rates as set forth in the RTO-NE proposal. The
Company cannot predict whether or when FERC will approve the RTO-NE proposal, or
what modifications may be made to the proposal while pending before FERC.
VELCO, the owner and operator of Vermont's principal electric transmission
system assets, 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. We own
approximately 29 percent of VELCO. The proposed Northwest Reliability Project
must be approved by the VPSB. Several Vermont municipalities, citizen groups
and individuals have intervened in the VPSB proceedings to oppose or request
modifications to the project. If approved, the project is estimated to cost
approximately $130 million through 2007. VELCO intends to finance the costs of
constructing the Northwest Reliability Project in part through increased equity
investment. The Company plans to invest approximately $20 million in VELCO to
support this and other transmission projects through 2007. Under current NEPOOL
and ISO-NE rules, which require qualifying large transmission project costs to
be shared among all New England utilities, most of the costs of the Northwest
Reliability Project will be allocated throughout the New England region, with
Vermont utilities responsible for approximately five percent of allocated costs.
In August 2003, a coalition of New England public utility commissions and
other parties challenged the NEPOOL and ISO-NE transmission cost allocation
rules. On December 18, 2003, FERC rejected this challenge. FERC's order is
subject to pending requests for rehearing and has been appealed to the US Court
of Appeals for the D.C. Circuit. If the current transmission cost allocation
rules are modified or eliminated, Vermont utilities, including the Company,
could be required to bear a greater proportion, and potentially all, of the cost
of the Northwest Reliability Project.
MAINTENANCE EXPENSES - Maintenance expenses increased $211,000, or 2.4 percent,
in 2003 compared with 2002, due to increased expenditures related to
hydroelectric generation and transmission facilities.
Maintenance expenses increased $1.7 million, or 24.6 percent, in 2002
compared with 2001 due to increased expenditures related to storm damage and
right-of-way maintenance programs.
DEPRECIATION AND AMORTIZATION - Depreciation and amortization expense decreased
$348,000, or 2.5 percent, in 2003 compared with 2002 due to reductions in
amortization of conservation and software programs, partially offset by
increased depreciation of utility plant in service.
Depreciation and amortization expense decreased $143,000, 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.
TAXES OTHER THAN INCOME - Taxes other than income taxes decreased $201,000, or
2.6 percent, in 2003 compared with 2002 due to reductions in property taxes.
Taxes other than income taxes increased $87,000, or 1.2 percent, in 2002
compared with 2001 due to an increase in property taxes.
INCOME TAXES - Income tax expense decreased $923,000, or 15.2 percent, in 2003
compared with 2002 due to a decrease in the Company's taxable income, an
increase in non-taxable income and the use of tax credits. Income tax expense
decreased $905,000 in 2002 compared with 2001 due to a decrease in the Company's
taxable income.
OTHER INCOME - Other income decreased $406,000, or 16.4 percent, in 2003
compared with 2002 due primarily to reduced earnings on investment in Vermont
Yankee as a result of the sale of the Vermont Yankee plant in 2002.
Other income increased $112,000, or 4.7 percent, in 2002 compared with 2001
due primarily to Vermont Yankee recognition of deferred tax assets arising in
conjunction with the sale of the Vermont Yankee plant, offset in part by
payments made to Vermont Yankee owners located outside of Vermont necessary to
close the sale of the Vermont Yankee plant.
INTEREST EXPENSE - Interest expense increased $887,000, or 14.4 percent, in 2003
compared with 2002 primarily due to a $42 million long-term debt issuance in
December 2002.
Interest expense decreased $869,000, 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.
DIVIDENDS ON PREFERRED STOCK - Dividends on preferred stock decreased $93,000,
or 96.9 percent, in 2003 compared with 2002, due to the repurchase of all
outstanding preferred stock during 2003. Dividends on preferred stock decreased
$837,000, 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.
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.
PINE STREET BARGE CANAL SUPERFUND SITE - In 1999, the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the United States Environmental Protection Agency ("EPA"), the State of Vermont
and numerous other parties of claims relating to a federal Superfund site in
Burlington, Vermont, known as the "Pine Street Barge Canal." The consent decree
resolves claims by the EPA for past site costs, natural resource damage claims
and claims for past and future remediation costs. The consent decree also
provides for the design and implementation of response actions at the site. In
2003, the Company expended $2.6 million to cover its obligations under the
consent decree and we have estimated total future costs of the Company's future
obligations under the consent decree to be $8.5 million. The estimated
liability is not discounted, and it is possible that our estimate of future
costs could change by a material amount. We have recorded a regulatory asset of
$13.0 million to reflect unrecovered past and future Pine Street costs.
Pursuant to the Company's 2003 Rate Plan, as approved by the VPSB, the Company
will begin to amortize past unrecovered costs in 2005. The Company will
amortize the full amount of incurred costs over 20 years without a return. The
amortization will be allowed in future rates, without disallowance or
adjustment, until fully amortized.
RATES
-----
RETAIL RATE CASES - On December 22, 2003, the VPSB approved our 2003 Rate Plan,
jointly proposed earlier in the year by the Company and the Vermont Department
of Public Service. The 2003 Rate Plan covers the period from 2003 through 2006
and includes the following principal elements:
The Company's rates will remain unchanged through 2004. The 2003 Rate Plan
allows the Company to raise rates 1.9 percent, effective January 1, 2005,
and an additional 0.9 percent, effective January 1, 2006, if the increases are
supported by cost of service schedules submitted 60 days prior to the effective
dates. If the Company's cost of service filings in 2005 or 2006 establish that
a lesser rate increase is required for the Company to meet its revenue
requirements, the Company will implement the lesser rate increase.
The Company may seek additional rate increases in extraordinary
circumstances, such as severe storm repair costs, natural disasters, extended
unanticipated unit outages, or significant losses of customer load.
The Company's allowed return on equity is reduced from 11.25 percent to
10.5 percent, for the period January 1, 2003 through December 31, 2006. During
the same period, the Company's earnings on core utility operations are capped at
10.5 percent. Any excess earnings in 2004 will be applied to reduce regulatory
assets. Excess earnings in 2005 or 2006 will be refunded to customers as a
credit on customer bills or applied to reduce regulatory assets, as the
Department directs.
The Company will carry forward into 2004 $3.0 million in deferred revenue
remaining at December 31, 2003, from the Company's 2001 Settlement Order
(summarized below). These revenues will be applied in 2004 to offset increased
costs or, if applicable, reduce regulatory assets as determined by the DPS.
The Company will amortize (recover) certain regulatory assets, including
Pine Street Barge Canal environmental site costs and past demand-side management
program costs, beginning in January 2005, with those amortizations to be allowed
in future rates. Pine Street costs will be recovered over a twenty-year period
without a return.
The Company will file with the VPSB in early 2004 a new fully-allocated
cost of service study and rate re-design, which will allocate the Company's
revenue requirement among all customer classes on the basis of current costs.
The new rate design will be subject to VPSB approval and is not expected to
adversely affect operating results.
The Company and the Department have agreed to work cooperatively to develop
and propose an alternative regulation plan as authorized by legislation enacted
in Vermont in 2003. If the Company and Department agree on such a plan, and it
is approved by the VPSB, the alternative regulation plan would supersede the
2003 Rate Plan.
In January 2001, the VPSB issued the 2001 Settlement Order, which included the
following:
The Company received a rate increase of 3.42 percent above existing rates
and prior temporary rate increases became permanent;
Rates were set at levels that recover the Company's VJO Contract costs,
effectively ending the regulatory disallowances experienced by the Company from
1998 through 2000;
Seasonal rates were eliminated in April 2001, which generated approximately
$8.5 million in additional cash flow in 2001, which was deferred and available
to be used to offset increased costs during 2002 and 2003; and
The Company agreed to an earnings cap on core utility operations of 11.25
percent return on equity, with amounts earned over the limit being used to write
off regulatory assets.
The 2001 Settlement Order also imposed 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
until new rates go into effect, which will occur in January 2005.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------
CONSTRUCTION AND INVESTMENTS - Our capital requirements result from the need to
construct facilities or to invest in programs to meet anticipated customer
demand for electric service. The Company plans to invest up to $20 million in
VELCO through 2007, subject to regulatory approval of the Northwest Reliability
Project. See detailed discussion under "Transmission Expenses."
The Company offers utility services, primarily line construction and
electrical services, principally to municipal and business customers. Sales of
these services have grown from approximately $700,000 in 2001 to approximately
$2.5 million in 2003. Sales of these services have allowed the Company to serve
its customers more efficiently and have improved cash flow.
Future capital expenditures are expected to approximate $20 million annually.
Expected reductions in Pine Street remediation costs should be offset by
increased generation expenditures. Capital expenditures, net of customer
advances for construction, over the past three years and forecasted for 2004 are
as follows:
Generation Transmission Distribution Other* Total
----------- ------------- ------------- ------- -------
(In thousands)
Actual:
--------------
2001 . . . . . $ 2,323 $ 1,219 $ 8,567 $ 3,529 $15,638
2002 . . . . . 3,258 1,827 9,173 7,267 $21,525
2003 . . . . . 2,629 1,496 7,760 $ 7,064 $18,949
Forecast:
--------------
2004 . . . . . $ 4,122 $ 4,280 $ 6,036 $ 7,162 $21,600
* Other includes Pine Street Barge Canal expenditures of $1.5 million in 2001,
$1.8 million in 2002, $2.5 million in 2003 and an estimated $1.1 million in
2004.
DIVIDEND POLICY - The annual dividend was $0.60 per share for the year ended
December 31, 2002. The annual dividend rate was increased by the Company's
Board of Directors from $0.55 per share to $0.76 per share beginning with the
$0.19 quarterly dividend declared in December 2002. On February 9, 2004, the
annual dividend rate was increased from $0.76 per share to $0.88 per share, a
payout ratio of approximately 44 percent based on 2003 earnings. The Company
expects to increase the dividend in the first quarter of each year until the
payout ratio falls between 50 percent and 70 percent of anticipated earnings.
We believe this payout ratio to be consistent with that of other electric
utilities having similar risk profiles.
FINANCING AND CAPITALIZATION
At December 31, 2003, our capitalization consisted of approximately 51
percent common equity and 49 percent debt, inclusive of the Company's capital
lease obligations.
During June 2003, the Company negotiated a 364-day revolving credit
agreement (the "Fleet-Sovereign Agreement") with Fleet Financial Services
("Fleet") joined by Sovereign Bank. The Fleet-Sovereign Agreement is for $20.0
million, unsecured, and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There was $500,000
outstanding with a weighted average rate of 4.0 percent on the Fleet-Sovereign
Agreement at December 31, 2003. There was no non-utility short-term debt
outstanding at December 31, 2003 or 2002. The Company anticipates that it will
secure financing that replaces some or all of its expiring facilities during
2004.
During 2002, we redeemed $5.1 million of 10.0 percent first mortgage
bonds and $12.5 million of outstanding preferred stock. We also
completed a "Dutch Auction" self-tender offer and repurchased 811,783 shares, or
approximately 14 percent, of the Company's common stock outstanding for
approximately $16.3 million in November 2002.
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.
The credit ratings of the Company's first mortgage bonds at December 31,
2003 were:
Fitch Moody's Standard & Poor's
----- ------- -----------------
First mortgage bonds BBB+ Baa1 BBB
During August 2003, our rating agencies reviewed the Company's financial
position and concluded the following:
Moody's affirmed the Company' senior secured debt rating at Baa1, with a
stable outlook;
Fitch Ratings affirmed the ratings of the Company's first mortgage bonds at
BBB+ with a stable outlook; and
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 Morgan
Stanley 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, 2003.
Payments Due by Period
----------------------
2005 and 2007 and After
TOTAL 2004 2006 2008 2008
--------------- -------- -------- -------- --------
(In thousands)
Long-term debt. . . . . . . . . . . $ 93,000 $ - $ 14,000 $ - $ 79,000
Interest on long-term debt. . . . . 76,055 6,534 13,068 11,068 45,385
Capital lease obligations . . . . . 4,963 519 958 774 2,712
Hydro-Quebec power supply contracts 623,463 49,419 101,239 101,847 370,958
Morgan Stanley Contract . . . . . . 38,664 13,602 25,062 - -
Stony Brook contract. . . . . . . . 46,081 3,509 5,754 6,328 30,490
Vermont Yankee PPA. . . . . . . . . 288,410 35,808 67,672 67,767 117,163
--------------- -------- -------- -------- --------
Total . . . . . . . . . . . . . $ 1,170,636 $109,391 $227,753 $187,784 $645,708
=============== ======== ======== ======== ========
OFF-BALANCE SHEET ARRANGEMENTS - The Company does not use off-balance sheet
financing arrangements, such as securitization of receivables or obtaining
access to assets through special purpose entities. We 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, including its debt
service costs.
OTHER RISKS - In March 2002, voters in the Town of Rockingham, Vermont
("Rockingham") approved an article authorizing Rockingham to create a municipal
utility and to acquire the electric distribution systems of the Company and/or
Central Vermont Public Service Corporation located within the town. In November
2003, Rockingham notified the Company that the town intended to initiate
proceedings before the town selectboard to condemn the Company's distribution
and associated property located within the town. The Company sought and
obtained in December 2003 a preliminary injunction from the State Superior Court
prohibiting the town from proceeding with condemnation before the selectboard.
The Company successfully argued that Vermont law required Rockingham to pursue
any such municipalization effort by petition to the VPSB, which is required to
determine both the fair value of any assets subject to municipalization and the
amount of damages to the utility caused by severance of the property subject to
municipalization. The preliminary injunction remains in effect and Rockingham
has not filed any petition with the VPSB seeking to municipalize assets. 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 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
hydroelectric generating facility, filed an inquiry with the VPSB seeking review
of certain dam improvements made by the Company in 1995, alleging 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
in connection with this proceeding.
GOVERNANCE - During 2003, the Securities and Exchange Commission ("SEC") issued
a number of rules amending disclosure requirements for public company annual
reports. In order to comply with such rules, the Company makes the following
disclosures:
The Company's Board of Directors has determined that David Coates, who
serves on the Company's Audit Committee, qualifies as an independent financial
expert under SEC rules.
The Company has adopted a Code of Ethics and Conduct that applies to all
Company directors and employees, including the Company's principal executive
officer, principal financial officer, principal accounting officer and persons
performing similar functions. The Company's code of ethics is maintained on its
website at "www.greenmountainpower.biz", Who We Are, Investors, Corporate
Governance. Upon request, the Company will provide a copy of its code of ethics
to any person without charge. Please send your inquiries to attention of
investor relations for the Company, 163 Acorn Lane, Colchester, Vermont 05446.
Management believes the Company to be in compliance with all governance and
disclosure requirements of the New York Stock Exchange, the SEC, and applicable
federal and state laws, including the "Sarbanes-Oxley" Act.
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 does 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.
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 42
Income For the Years Ended December 31, 2003, 2002, and 2001
Consolidated Statements of Cash Flows For the 43
Years Ended December 31, 2003, 2002, and 2001
Consolidated Balance Sheets as of 44
December 31, 2003 and 2002
Consolidated Statements of Capitalization as of 46
December 31, 2003 and 2002
Consolidated Statements of Changes In Shareholders Equity 47
For the Years Ended December 31, 2003, 2002 and 2001
Notes to Consolidated Financial Statements 48
Quarterly Financial Information 73
Reports of Independent Public Accountants 74
Schedules
For the Years Ended December 31, 2003, 2002, and 2001:
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
Deloitte and Touche LLP 77
Arthur Andersen 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
2003 2002 2001
--------- --------- ---------
(In thousands, except per share data)
Retail revenues $201,569 $203,962 $199,660
Wholesale revenues 78,901 70,646 83,804
--------- --------- ---------
TOTAL OPERATING REVENUES 280,470 274,608 283,464
Operating expenses-Power Supply:
Purchases from others 189,450 188,381 196,323
Company-owned generation 7,856 5,067 4,742
Other operating 17,665 14,188 15,924
Transmission 14,783 15,221 14,130
Maintenance 9,065 8,854 7,108
Depreciation and amortization 13,803 14,151 14,294
Taxes other than income 7,422 7,623 7,536
Income taxes 5,120 6,043 6,948
--------- --------- ---------
Total operating expenses 265,164 259,528 267,005
--------- --------- ---------
OPERATING INCOME 15,306 15,080 16,459
--------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations 1,493 2,777 2,253
Allowance for equity funds used during construction 387 233 210
---------
Other income (deductions), net 199 (525) (90)
--------- --------- ---------
Total other income 2,079 2,485 2,373
--------- --------- ---------
INTEREST CHARGES
Long-term debt 7,021 5,214 6,073
Other 303 1,059 1,154
Allowance for borrowed funds used during construction (267) (103) (188)
--------- --------- ---------
Total interest charges 7,057 6,170 7,039
--------- --------- ---------
INCOME BEFORE PREFERRED DIVIDENDS AND
DISCONTINUED OPERATIONS 10,328 11,395 11,793
Dividends on preferred stock 3 96 933
--------- --------- ---------
INCOME FROM CONTINUING OPERATIONS 10,325 11,299 10,860
Income (Loss) from discontinued operations, net 79 99 (182)
--------- --------- ---------
NET INCOME APPLICABLE TO COMMON STOCK $ 10,404 $ 11,398 $ 10,678
========= ========= =========
EARNINGS PER SHARE
Basic earnings per share from continuing operations $ 2.08 $ 2.02 $ 1.93
Basic earnings per share from discontinued operations 0.01 0.02 (0.03)
--------- --------- ---------
Basic earnings per share $ 2.09 $ 2.04 $ 1.90
========= ========= =========
Diluted earnings per share from continuing operations $ 2.01 $ 1.96 $ 1.88
Diluted earnings per share from discontinued operations 0.01 0.02 (0.03)
--------- --------- ---------
Diluted earnings per share $ 2.02 $ 1.98 $ 1.85
========= ========= =========
Weighted average shares outstanding-basic 4,980 5,592 5,630
Weighted average equivalent shares outstanding-diluted 5,140 5,756 5,789
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 2003 2002 2001
--------- --------- ---------
Net income $ 10,404 $ 11,398 $ 10,678
Minimum pension liability adjustment, net of applicable income taxes 587 (2,374) -
of $400,000 expense and $1.6 million benefit, respectively -
---------
Other comprehensive income $ 10,991 $ 9,024 $ 10,678
========= ========= =========
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION FOR THE YEARS ENDED
CONSOLIDATED STATEMENTS OF CASH FLOWS DECEMBER 31
2003 2002 2001
--------- --------- ---------
OPERATING ACTIVITIES:
Income from continuing operations before preferred dividends . . . . . . . . . . . . . . $ 10,328 $ 11,395 $ 11,793
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,803 14,151 14,294
Dividends from associated companies less equity income . . . . . . . . . . . . . . . . . 884 45 (19)
Allowance for funds used during construction . . . . . . . . . . . . . . . . . . . . . . (654) (335) (398)
Amortization of deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . 318 3,236 3,767
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,479 3,577 345
Benefit plan contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,500) (1,000) -
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (570) (2,003) 1,126
Accrued purchase power contract option call. . . . . . . . . . . . . . . . . . . . . . . - - (8,276)
Arbitration costs recovered (deferred) . . . . . . . . . . . . . . . . . . . . . . . . . - - 3,229
Rate levelization liability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,121) (4,483) 8,527
Environmental and conservation deferrals, net. . . . . . . . . . . . . . . . . . . . . . (1,890) (2,194) (3,380)
Changes in:
Accounts receivable and accrued utility revenues . . . . . . . . . . . . . . . . . . . . (189) (896) 6,483
Prepayments, fuel and other current assets . . . . . . . . . . . . . . . . . . . . . . . (1,188) 850 300
Accounts payable and other current liabilities . . . . . . . . . . . . . . . . . . . . . (676) (55) 128
Accrued income taxes payable and receivable. . . . . . . . . . . . . . . . . . . . . . . (3,950) 5,010 1,187
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,776 (1,147) (2,512)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,141 2,458 (3,218)
--------- --------- ---------
Net cash provided by continuing operations . . . . . . . . . . . . . . . . . . . . . . . 20,991 28,609 33,376
Net change in discontinued segment . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 99 (182)
--------- --------- ---------
Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . . . . 21,070 28,708 33,194
INVESTING ACTIVITIES:
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (16,617) (19,543) (12,963)
Investment in associated companies . . . . . . . . . . . . . . . . . . . . . . . . . . . (108) (392) -
Return of Capital from associated companies. . . . . . . . . . . . . . . . . . . . . . . 7,615 370 299
Investment in nonutility property. . . . . . . . . . . . . . . . . . . . . . . . . . . . (198) (206) (212)
--------- --------- ---------
Net cash used in investing activities. . . . . . . . . . . . . . . . . . . . . . . . . . (9,308) (19,771) (12,876)
--------- --------- ---------
FINANCING ACTIVITIES:
Proceeds from issuance of long term debt . . . . . . . . . . . . . . . . . . . . . . . . - 42,000 -
Payments to acquire treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . (3) (16,320) -
(Reduction in) Proceeds from term loan . . . . . . . . . . . . . . . . . . . . . . . . . - (12,000) 12,000
Repurchase of preferred stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (85) (12,536) (235)
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 995 1,037 1,655
Proceeds (purchases) of certificate of deposit . . . . . . . . . . . . . . . . . . . . . - - 16,173
Power supply option obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - (16,012)
Reduction in long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8,000) (13,322) (9,700)
Short-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,000) 2,500 (15,500)
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,792) (3,393) (4,034)
--------- --------- ---------
Net cash used in financing activities. . . . . . . . . . . . . . . . . . . . . . . . . . (12,885) (12,034) (15,653)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . (1,123) (3,097) 4,665
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . 1,909 5,006 341
--------- --------- ---------
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . 786 1,909 5,006
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid year-to-date for:
Interest (net of amounts capitalized). . . . . . . . . . . . . . . . . . . . . . . . . . 7,120 6,048 6,936
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,915 2,349 9,622
SUPPLEMENTAL DISCLOSURE OF NON-CASH INFORMATION:
Minimum pension liability adjustment, net. . . . . . . . . . . . . . . . . . . . . . . . (587) 2,374 -
The accompanying notes are an integral part of these consolidated financial statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
2003 2002
--------------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost $ 324,900 $311,543
Less accumulated depreciation 110,111 102,250
--------------- --------
Net utility plant 214,789 209,293
Property under capital lease 5,047 5,287
Construction work in progress 9,026 8,896
--------------- --------
Total utility plant, net 228,862 223,476
--------------- --------
OTHER INVESTMENTS
Associated companies, at equity 5,896 14,101
Other investments 7,810 7,451
--------------- --------
Total other investments 13,706 21,552
--------------- --------
CURRENT ASSETS
Cash and cash equivalents 786 1,909
Accounts receivable, less allowance for
doubtful accounts of $690 and $547 17,331 17,253
Accrued utility revenues 6,729 6,618
Fuel, materials and supplies, at average cost 4,498 3,349
Prepayments 1,922 1,901
Other 422 402
--------------- --------
Total current assets 31,688 31,432
--------------- --------
DEFERRED CHARGES
Demand side management programs 6,713 6,434
Purchased power costs 2,574 2,323
Pine Street Barge Canal 12,954 13,019
Net power supply deferral 19,734 18,405
Power supply derivative asset 3,990 8,796
Other deferred charges 9,625 11,413
--------------- --------
Total deferred charges 55,590 60,390
--------------- --------
NON-UTILITY
Other current assets 217 8
Property and equipment 248 249
Other assets 640 738
--------------- --------
Total non-utility assets 1,105 995
--------------- --------
TOTAL ASSETS $ 330,951 $337,845
=============== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
2003 2002
--------- ---------
(in thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,860,854 and 5,782,496) . . . . . . . . . . . . . . $ 19,536 $ 19,276
Additional paid-in capital . . . . . . . . . . . . . 76,081 75,347
Retained earnings. . . . . . . . . . . . . . . . . . 22,786 16,171
Accumulated other comprehensive income . . . . . . . (1,787) (2,374)
Treasury stock, at cost (827,639 and 827,639 shares) (16,701) (16,698)
--------- ---------
Total common stock equity. . . . . . . . . . . . . . 99,915 91,722
Redeemable cumulative preferred stock. . . . . . . . - 55
Long-term debt, less current maturities. . . . . . . 93,000 93,000
--------- ---------
Total capitalization . . . . . . . . . . . . . . . . 192,915 184,777
--------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . . . 4,963 5,287
--------- ---------
CURRENT LIABILITIES
Current maturities of preferred stock. . . . . . . . - 30
Current maturities of long-term debt . . . . . . . . - 8,000
Short-term debt. . . . . . . . . . . . . . . . . . . 500 2,500
Accounts payable, trade and accrued liabilities. . . 8,493 7,431
Accounts payable to associated companies . . . . . . 6,821 8,940
Rate levelization liability. . . . . . . . . . . . . 2,970 4,091
Accrued income taxes . . . . . . . . . . . . . . . . 633 4,583
Customer deposits. . . . . . . . . . . . . . . . . . 968 898
Interest accrued . . . . . . . . . . . . . . . . . . 1,152 1,081
Other. . . . . . . . . . . . . . . . . . . . . . . . 1,178 937
--------- ---------
Total current liabilities. . . . . . . . . . . . . . 22,715 38,491
--------- ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . . . . 23,724 27,201
Accumulated deferred income taxes. . . . . . . . . . 34,009 26,471
Unamortized investment tax credits . . . . . . . . . 2,848 3,130
Pine Street Barge Canal cleanup liability. . . . . . 7,356 8,833
Accumulated cost of removal. . . . . . . . . . . . . 21,238 19,947
Other deferred liabilities . . . . . . . . . . . . . 19,693 21,767
--------- ---------
Total deferred credits . . . . . . . . . . . . . . . 108,868 107,349
--------- ---------
COMMITMENTS AND CONTINGENCIES
NON-UTILITY
Net liabilities of discontinued segment. . . . . . . 1,490 1,941
--------- ---------
Total non-utility liabilities. . . . . . . . . . . . 1,490 1,941
--------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . $330,951 $337,845
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
GREEN MOUNTAIN POWER CORPORATION At December 31,
SHARES
ISSUED AND OUTSTANDING
----------------------
AUTHORIZED 2003 2002 2003 2002
---------- --------- --------- --------------- -------
(In thousands)
COMMON STOCK
Common Stock, $3.33 1/3 par value 10,000,000 5,033,215 4,954,857 $ 19,536 $19,276
=============== =======
OUTSTANDING
-----------
AUTHORIZED ISSUED 2003 2002 2003 2002
---------- ------- ---- ---- --------------- -----
Shares (In thousands)
----------
REDEEMABLE CUMULATIVE PREFERRED STOCK,
100 PAR VALUE
4.75%, Class B, redeemable at
101 per share. . . . . . . . . . . . . 15,000 15,000 - 850 $ - $ 85
7%, Class C . . . . . . . . . . . . . . 15,000 15,000 - - - -
9.375%, Class D, Series 1,. . . . . . . 40,000 40,000 - - - -
7.32%, Class E, Series 1. . . . . . . . 200,000 120,000 - - - -
--------------- -----
TOTAL PREFERRED STOCK $ - $ 85
=============== =====
2003 2002
--------------- --------
(In thousands)
LONG-TERM DEBT
FIRST MORTGAGE BONDS
6.41% Series due 2003. . . . . . . . . . . . . . . . . . . - 8,000
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 42,000
--------------- --------
Total Long-term Debt Outstanding . . . . . . . . . . . . . 93,000 101,000
Less Current Maturities (due within one year). . . . . . . - 8,000
--------------- --------
TOTAL LONG-TERM DEBT, LESS CURRENT MATURITIES. . . . . . . $ 93,000 $ 93,000
=============== ========
The accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY ACCUMULATED TOTAL
COMMON STOCK PAID-IN RETAINED COMPREHENSIVE TREASURY COMMON
------------
SHARES AMOUNT CAPITAL EARNINGS OTHER INCOME STOCK EQUITY
---------- ------- -------- ----------------------- -------------- --------- ---------
(Dollars in thousands)
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. . . . . . 12,691 44 42 - - - 86
Net Income before dividends. . . - - - 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. . . . . . 52,804 177 342 - - - 519
Net Income before dividends. . . - - - 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
---------- ------- -------- ----------------------- -------------- --------- ---------
Common Stock Issuance:
Compensation Programs. . . . . . 78,358 260 734 994
Common stock repurchase (3) (3)
Net Income before dividends. . . - - - 10,407 - - 10,407
Other Comprehensive Income(Loss) - - - - 587 - 587
Common Stock Dividends . . . . . - - - (3,789) - - (3,789)
Preferred Stock Dividends: . . . - - - (3) - - (3)
---------- ------- -------- ----------------------- -------------- --------- ---------
BALANCE, DECEMBER 31, 2003 . . . 5,033,215 $19,536 $ 76,081 $ 22,786 $ (1,787) $(16,701) $ 99,915
---------- ------- -------- ----------------------- -------------- --------- ---------
The accompanying notes are an integral part of the 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 89,000 customer accounts. The Company's subsidiary, Green
Mountain Power Investment Company ("GMPIC"), was created in December 2002 to
hold the Company's investment in Vermont Yankee Nuclear Power Corporation
("Vermont Yankee" or "VY").
The Company's remaining active wholly-owned subsidiary, which is not
regulated by the Vermont Public Service Board ("VPSB" or the "Board"), is GMP
Real Estate Corporation. The results of GMP Real Estate Corporation and the
Company's unregulated rental water heater program are included in earnings of
affiliates and non-utility operations in the Other Income (Deductions) section
of the Consolidated Statements of Income. Summarized financial information for
these wholly-owned subsidiaries, and the Company's unregulated water heater
program, which earned approximately $386,000 in 2003 is as follows:
Years ended December 31,
2003 2002 2001
------------- ----- ------
In thousands
Revenue. . $ 1,087 $ 997 $1,012
Expense. . 704 744 $ 749
------------- ----- ------
Net Income $ 383 $ 253 $ 263
============= ===== ======
The Company accounts for its investments in VY, Vermont Electric Power Company,
Inc. ("VELCO"), New England Hydro-Transmission Corporation, and New England
Hydro-Transmission Electric Company using the equity method of accounting. The
Company's share of the net earnings or losses of these companies is also
included in the Other Income section of the Consolidated Statements of Income.
See Note B and Note L for additional information.
2. Regulatory Accounting. The Company's utility operations, including
accounting records, rates, operations and certain other practices of its
electric utility business, are subject to the regulatory authority of the
Federal Energy Regulatory Commission ("FERC") and the VPSB.
The accompanying consolidated financial statements conform to accounting
principles generally accepted in the United States of America 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 as summarized in the following
table:
SFAS 71 DEFERRED CHARGES
At December 31,
2003 2002
--------------- -------
(in thousands)
Regulatory commission costs . $ 2,181 $ 1,774
Restructuring costs . . . . . 943 2,216
Preliminary survey. . . . . . 1,423 1,202
Storm damages . . . . . . . . 1,129 1,905
Tree trimming . . . . . . . . 799 905
Other . . . . . . . . . . . . 3,150 3,411
--------------- -------
Other deferred charges. . . . 9,625 11,413
--------------- -------
Power supply. . . . . . . . . 2,574 2,323
Net power supply deferral . . 19,734 18,405
Pine Street barge canal . . . 12,954 13,019
Power supply derivative asset 3,990 8,796
Demand-side management. . . . 6,713 6,434
--------------- -------
Total Deferred Charges. . . . $ 55,590 $60,390
=============== =======
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 $9.6 million and $11.4 million at December
31, 2003 and 2002, 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.
In addition, the Company has regulatory liabilities of $25.1 million and
$24.0 million at December 31, 2003 and 2002, respectively, consisting of
accumulated removal costs, deferred revenue and insurance proceeds relating to
VY.
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 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, 2003,
based upon management's analysis of 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 capitalizing 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 are charged to accumulated depreciation. The
following table summarizes the Company's investments in utility plant.
Property Summary at December 31,
2003 2002
-------------- ----------
In thousands
Property Plant and Equipment:
Intangible. . . . . . . . . . . . . . . . $ 14,091 $ 12,580
Generation. . . . . . . . . . . . . . . . 68,532 66,913
Transmission. . . . . . . . . . . . . . . 37,093 36,846
Distribution. . . . . . . . . . . . . . . 178,292 170,655
General, including transportation . . . . 26,892 24,549
-------------- ----------
Total Plant in Service. . . . . . . . . 324,900 311,543
Accumulated Depreciation and Amortization (110,111) (102,250)
-------------- ----------
Net Plant in Service. . . . . . . . . . . 214,789 209,293
Capital Lease . . . . . . . . . . . . . . 5,047 5,287
Construction Work in Progress . . . . . . 9,026 8,896
-------------- ----------
Total Net Utility Plant . . . . . . . . . $ 228,862 $ 223,476
============== ==========
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. Other accumulated removal costs related to
utility plant, estimated at approximately $21.2 million and $19.9 million for
2003 and 2002, respectively, are included in Deferred Credits.
The annual depreciation provision was approximately 3.3 percent during
2003, 3.2 percent during 2002, and 3.5 percent of total depreciable property
during 2001.
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 retail
sales of electricity 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. Wholesale revenues represent sales
of electricity to other utilities, typically for resale, and to the Independent
System Operator of New England ("ISO New England") for amounts by which our
power supply resources exceed customer loads. The Company also recognizes
deferred revenues, when required to achieve its allowed rate of return, under a
VPSB order issued in 2001, and extended through 2004 under a subsequent VPSB
order. The Company recognized $1.1 million and $4.4 million in deferred
revenues during 2003 and 2002, respectively. No deferred revenues were
recognized in 2001. See Note I(4) for additional information.
8. 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 2003, 2002 and
2001, the Company granted additional options of 4,000, 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 Company adopted the prospective method of accounting for stock-based
compensation under SFAS 148 beginning January 1, 2003. The information
presented below has been determined as if the Company accounted for all past
employee and director stock options under the fair value method of that
statement.
Pro-forma net income For the years ended December 31,
2003 2002 2001
------- ------- -------
In thousands, except per share amounts
Net income reported. . . . . . . . . . $10,404 $11,398 $10,678
Pro-forma net income . . . . . . . . . $10,242 $11,114 $10,376
Net income per share
As reported-basic. . . . . . . . . . $ 2.09 $ 2.04 $ 1.90
Pro-forma basic. . . . . . . . . . . $ 2.06 $ 1.99 $ 1.84
As reported-diluted. . . . . . . . . $ 2.02 $ 1.98 $ 1.85
Pro-forma diluted. . . . . . . . . . $ 1.99 $ 1.93 $ 1.79
9. Major Customers. The Company had one major retail customer, International
Business Machines Corporation ("IBM"), that accounted for 24.1 percent, 25.7
percent, and 26.6 percent of retail MWh sales, and 16.6 percent, 17.3 percent,
and 19.2 percent of the Company's retail operating revenues in 2003, 2002 and
2001, respectively.
10. Fair Value of Financial Instruments. The carrying value and fair value
of the Company's first mortgage bonds and derivative contracts is summarized in
the following table:
Fair Value of Financial Instruments
As of December 31,
2003 2002
---- ----
Fair Value Carrying Value Fair Value Carrying Value
In thousands
Long-Term Debt, net $ 91,725 $ 92,113 $ 96,215 $ 99,942
Derivatives . . . . 19,773 19,773 18,405 18,405
The book value of accounts receivable, accrued utility revenues, other
investments, cash surrender value of life insurance, short-term debt, accounts
payable, customer deposits and accrued interest approximate fair value due to
their short-term, highly liquid nature.
11. 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.
12. Purchased Power. The Company records the annual cost of power obtained
under long-term contracts as operating expenses.
13. Derivative Instruments. SFAS 133, as amended, 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, was effective for the Company beginning 2001.
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 the application of SFAS 133 to
power supply arrangements that qualify as derivatives. We currently have an
arrangement (the "9701 arrangement") that grants Hydro-Quebec an option to call
power at prices below current and estimated future market rates. This
arrangement is effective through 2015. From time to time, we use forward
contracts to hedge the 9701 call option. At December 31, 2003, the Company had
a liability of $23.7 million reflecting the fair value of 9701 arrangement, and
an asset of $4.0 million, reflecting the fair value of a contract with Morgan
Stanley Capital Group, Inc. (the "Morgan Stanley Contract"). A corresponding
net regulatory asset of $19.7 million is also recorded. At December 31, 2002,
the Company had a liability of $27.2 million reflecting the fair value of 9701,
and an asset of $8.8 million, reflecting the fair value of the Morgan Stanley
Contract. A corresponding net regulatory asset of $18.4 million was also
recorded. The Company believes that the net regulatory asset is probable of
recovery in future rates. The net regulatory asset is based on current
estimates of future market prices that are likely to change by material amounts.
The Morgan Stanley Contract is used to hedge against increases in fossil
fuel prices. MS purchases the majority of the Company's power supply resources
at index (fossil fuel resources) or specified (i.e., contracted resources)
prices and then sells to us at a fixed rate to serve pre-established load
requirements. This contract allows management to fix the cost of much of its
power supply requirements, subject to power resource availability and other
risks.
14. Use of Estimates. The preparation of financial statements in
conformity with accounting principles generally accepted in the United States of
America 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.
15. Reclassifications. Certain items on the prior year's consolidated
financial statements have been reclassified to be consistent with the current
year presentation.
16. Other Comprehensive Income. Other comprehensive loss of $2.4 million,
net of a $1.6 million income tax benefit, was recognized during 2002 as a result
of a minimum pension funding liability. During 2003, an increase in the market
value of pension plan assets allowed a reduction in the minimum pension
liability of approximately $587,000, net of $400,000 income tax expense.
17. New Accounting Standards. 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 Company has
recognized, as a liability, an asset retirement obligation for accumulated costs
of removal, which totaled approximately $21.2 million and $19.9 million at
December 31, 2003 and 2002, respectively, and increased plant and equipment
balances by the same amount as a result of this accounting pronouncement.
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, did not 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
Company adopted the prospective method of accounting for stock-based
compensation under SFAS 148 beginning January 1, 2003. The application of this
accounting standard did not materially impact the Company's financial position
or results of operations during 2003.
In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150, "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity"("SFAS 150"). SFAS 150 establishes standards for
classifying and measuring financial instruments with characteristics of both
liabilities and equity. The guidance is effective for financial instruments
entered into or modified after May 31, 2003. This statement had no effect on
our financial position or results of operations during 2003.
In December 2003, the FASB issued Statement of Financial Accounting
Standards No. 132 (revised 2003), "Employers" Disclosures about Pensions and
Other Postretirement Benefits ("SFAS 132"). In an effort to provide the public
with better and more complete information, the standard requires that companies
provide more details about their plan assets, benefit obligations, cash flows,
benefit costs and other relevant information. The guidance is effective for
fiscal years ending December 15, 2003 and for quarters beginning after December
15, 2003. We have adopted all of the disclosures required by the standard.
In January 2003, the FASB issued FASB Interpretation No. ("FIN") 46, "
Consolidation of Variable Interest Entities." FIN 46 requires a company to
consolidate a variable interest entity if it is designated as the primary
beneficiary of that entity even if the company does not have a majority of
voting interests. The adoption of FIN 46 did not require the Company to
consolidate any variable interest entities.
In January 2003, the FASB issued FIN 45,"Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." FIN 45 requires a company to recognize a liability for
the obligations it has undertaken in issuing a guarantee. This liability would
be recorded at the inception of a guarantee and would be measured at fair value.
The Company adopted the measurement provisions of this statement in the first
quarter of 2003 and it did not have an effect on the financial statements during
2003.
The Company provides health care, life insurance, prescription drug and
other benefits, to retired employees who meet certain age and years of service
requirements. Under certain circumstances, eligible retirees are required to
make contributions for postretirement benefits.
In December 2003, the FASB issued Staff Position ("FSP") 106-1, "Accounting
and Disclosure Requirements related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003" (the "Act"). The Act provides for
drug benefits for certain retirees under a new Medicare Part D program. For
employers like the Company there are subsidies available which are inherent in
the Act. The FASB allowed, and the Company elected, a one-time deferral of the
recognition of the impact of the Act in the employer's accounting until formal
guidance is issued. As a result, the provisions of the Act are not reflected in
the other postretirement benefits disclosure (See Note H). The issuance of
formal accounting guidance may require a change to previously reported
information.
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,
2003 2002 2003 2002
------ ------ --------------- -------
(IN THOUSANDS)
VELCO-common . . . . . . . . . . . . . . 28.41% 28.41% $ 2,469 $ 2,309
VELCO-preferred. . . . . . . . . . . . . 30.00% 30.00% 246 305
--------------- -------
Total VELCO 2,715 2,614
Vermont Yankee- Common . . . . . . . . . 33.60% 18.99% 1,605 9,721
New England Hydro Transmission-Common. . 3.18% 3.18% 592 660
New England Hydro Transmission Electric-
Common . . . . . . . . . . . . . . . 3.18% 3.18% 984 1,106
--------------- -------
Total investment in associated companies $ 5,896 $14,101
=============== =======
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 $12.0 million,
$12.7 million, and $11.5 million for the years 2003, 2002 and 2001,
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. The
Company plans to make capital investments of up to $20 million in VELCO through
2007 in support of various transmission projects.
Summarized unaudited financial information for VELCO is as follows:
At and for the years ended December 31,
2003 2002 2001
--------------- -------- -------
(In thousands)
Net income . . . . . . . . . . $ 1,270 $ 1,094 $ 1,118
Company's equity in net income $ 418 $ 319 $ 308
=============== ======== =======
Total assets . . . . . . . . . $ 126,793 $106,613 $89,322
Less:
Liabilities and long-term debt 117,393 97,417 81,335
--------------- -------- -------
Net assets . . . . . . . . . . $ 9,400 $ 9,196 $ 7,987
=============== ======== =======
Company's equity in net assets $ 2,715 $ 2,614 $ 2,352
=============== ======== =======
VERMONT YANKEE. On July 31, 2002, Vermont Yankee Nuclear Power Corporation
("VY" or "Vermont Yankee") announced that the sale of its nuclear power plant to
Entergy Nuclear Vermont Yankee ("ENVY") 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 ENVY, 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 received a credit from VY
and has requested permission from the VPSB to apply the credit to reduce the
$2.0 million regulatory asset.
The Company's ownership share of VY has increased from approximately 19.0
percent in 2002 to approximately 33.6 percent currently, due to VY's purchase of
certain minority shareholders' interests. The Company's entitlement to energy
produced by the ENVY nuclear plant remains at approximately 20 percent of plant
production.
The 2003 decrease in equity in net assets of VY resulted from a
distribution of proceeds, in the form of dividends to VY owners, from the sale
of the VY nuclear power plant.
Summarized unaudited financial information for Vermont Yankee is as follows:
At and for the years ended December 31,
2003 2002 2001
-------- --------------- --------
(In thousands)
Earnings:
Operating revenues. . . . . . . . . . $187,123 $ 175,722 $178,840
Net income applicable to common stock 2,536 9,454 6,119
Company's equity in net income. . . . $ 498 $ 1,745 $ 1,131
======== =============== ========
Total assets. . . . . . . . . . . . . . $150,720 $ 201,426 $723,815
Less:
Liabilities and long-term debt. . . . 145,946 150,413 669,640
-------- --------------- --------
Net Assets. . . . . . . . . . . . . . . $ 4,774 $ 51,203 $ 54,175
======== =============== ========
Company's equity in net assets. . . . . $ 1,605 $ 9,721 $ 9,725
======== =============== ========
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,
2003. The Company also funds an Employee Savings and Investment Plan ("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,
or its subsidiaries. Outstanding options become exercisable at between one and
four years after the grant date and remain exercisable until 10 years from the
grant date.
Prior to 2003, as permitted by Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation ("SFAS 123"), the Company had
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 issued through 2002. Under APB 25,
because the exercise price equals the market price of the underlying stock on
the date of grant, no compensation expense was recorded. Effective January 1,
2003, the Company elected to expense the fair value of options granted beyond
that date. The amount of expense recorded during 2003 was immaterial. Options
have been issued only to employees and directors.
The fair values of the options granted in 2003, 2002, and 2001 are $1.33,
$2.27, and $4.16 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, 2003:
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. $ 7.90 192,200 6.6 6.05% 5 30.58 4.5%
2001. $16.72 35,150 7.6 5.25% 6 32.69 4.0%
2002. $17.84 69,500 8.6 4.50% 6.5 16.89 4.5%
2003. $20.55 4,000 9.3 2.48% 6 13.68 4.5%
Total $11.39 300,850
====== =======
Options granted are not exercisable until one year after the date of grant.
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,
2003 2002 2001
--------------- ------- -------
(in thousands)
Net income (loss) before preferred dividends $ 10,407 $11,494 $11,611
Preferred stock dividend requirement . . . . 3 96 933
--------------- ------- -------
Net income (loss) applicable to common
stock . . . . . . . . . . . . . . . . . . $ 10,404 $11,398 $10,678
=============== ======= =======
Average number of common shares-basic. . . . 4,980 5,592 5,630
Dilutive effect of stock options . . . . . . 160 164 159
--------------- ------- -------
Average number of common shares-diluted. . . 5,140 5,756 5,789
=============== ======= =======
Weighted Range of
Total Average Exercise Options
Options Price Prices Exercisable
------- ------ ------------- -----------
Outstanding at December 31, 2000 331,900 $ 7.90 $ 7.90-$7.90 0
Granted. . . . . . . . . . . . . 55,450 16.67 $14.50-$16.78
Granted. . . . . . . . . . . . . 1,000 12.28 $12.28-$12.28
Exercised. . . . . . . . . . . . 17,400 7.90 $ 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-$18.67
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
------- ------ ------------- -----------
Granted. . . . . . . . . . . . . 4,000 20.55 $20.22-$22.62
Exercised. . . . . . . . . . . . 64,550 10.63 $ 7.90-$18.67
Forfeited. . . . . . . . . . . . 4,400 17.36 $16.78-$18.12
Outstanding at December 31, 2003 300,850 $11.39 $ 7.90-$22.62 193,700
======= ====== ============= ===========
As part of our long-term stock incentive program, 13,300 shares of unrestricted
common stock were granted to employees other than the Company's executives
during December 2003, resulting in compensation expense of approximately
$300,000. Directors were granted 8,800 deferred stock units during 2003,
resulting in compensation expense of approximately $196,000. The Company also
granted 35,200 deferred stock units to senior management on February 9, 2004.
Each deferred stock unit is convertible into one share of common stock. The
total market value of the shares will be charged to compensation expense over a
two-year vesting period.
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 $19.9 million of retained earnings
were free of restrictions at December 31, 2003.
D. PREFERRED STOCK
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 repurchased the remaining $0.2 million of the 9.375 percent
Class D preferred stock outstanding. All remaining preferred stock was
repurchased during 2003.
E. SHORT-TERM DEBT
The Company has a $20.0 million 364-day revolving credit agreement with
Fleet Financial Services ("Fleet") joined by Sovereign Bank ("Sovereign"),
expiring June 2004 (the "Fleet-Sovereign Agreement"). The Fleet-Sovereign
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 $500,000
outstanding at a weighted average rate of 4 percent under the Fleet-Sovereign
Agreement at December 31, 2003. There was no non-utility short-term debt
outstanding at December 31, 2003 or 2002.
The Fleet-Sovereign Agreement requires the Company to certify on a
quarterly basis that it has not suffered a "material adverse change". The
agreement also requires the Company to comply with certain covenants. The
Company was in compliance with all covenants at December 31, 2003.
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
for both December 31, 2003 and 2002. 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, 2003, are:
Sinking
Fund and
Maturities
-----------
2004 . . . . . . . . $ -
2005 . . . . . . . . -
2006 . . . . . . . . 14,000
2007 . . . . . . . . -
2008 . . . . . . . . -
Thereafter . . . . . 79,000
Total Long-term debt $ 93,000
===========
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, 2003 and 2002, the net regulatory assets were $924,000 and
$1,042,000, 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, 2003 and December 31, 2002, were as follows:
AT DECEMBER 31,
2003 2002
--------------- -------
(In thousands)
DEFERRED TAX ASSETS
Contributions in aid of construction $ 11,841 $11,130
Deferred compensation and
postretirement benefits 5,205 4,570
Self insurance and other reserves 365 1,369
Other 1,277 3,032
--------------- -------
$ 18,689 $20,101
--------------- -------
DEFERRED TAX LIABILITIES
Property related $ 43,924 $41,967
Demand side management 1,746 1,870
Deferred purchased power costs 809 943
Pine Street reserve 2,425 1,792
Other 3,794 -
--------------- -------
$ 52,698 $46,572
--------------- -------
Net accumulated deferred income tax liability $ 34,009 $26,471
=============== =======
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,
2003 2002 2001
--------------- -------- --------
(In thousands)
Net change in deferred income tax $ 7,539 $ 2,712 $(1,885)
liability
Change in income tax related
regulatory assets and liabilities (6,175) 2,759 (1,149)
Change in tax effect of accumulated
other comprehensive income 398 (1,612) -
--------------- -------- --------
Deferred income tax expense (benefit) $ 1,761 $ 3,859 $(3,034)
=============== ======== ========
The components of the provision for income taxes are as follows:
YEARS ENDED DECEMBER 31,
2003 2002 2001
--------------- ------- --------
(In thousands)
Current federal income taxes. $ 2,434 $1,873 $ 7,846
Current state income taxes. . 1,207 593 2,418
--------------- ------- --------
Total current income taxes. . 3,641 2,466 10,264
Deferred federal income taxes 1,307 2,920 (2,296)
Deferred state income taxes . 454 939 (738)
--------------- ------- --------
Total deferred income taxes . 1,761 3,859 (3,034)
Investment tax credits-net. . (282) (282) (282)
--------------- ------- --------
Income tax expense. . . . . . $ 5,120 $6,043 $ 6,948
=============== ======= ========
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,
2003 2002 2001
--------------- -------- --------
(In thousands)
Income before income taxes and
preferred dividends. . . . . . . . . . . . $ 15,527 $17,537 $18,559
Federal statutory rate . . . . . . . . . . . 34.0% 34.0% 35.0%
Computed "expected" federal income
taxes. . . . . . . . . . . . . . . . . . . 5,279 5,963 6,496
Increase (decrease) in taxes resulting from:
Tax versus book depreciation . . . . . . . . 41 41 45
Dividends received and paid credit . . . . . (465) (575) (440)
AFUDC-equity funds . . . . . . . . . . . . . (129) (80) (72)
Amortization of ITC. . . . . . . . . . . . . (282) (282) (282)
State tax. . . . . . . . . . . . . . . . . . 797 1,011 1,705
Excess deferred taxes. . . . . . . . . . . . (60) (60) (60)
Tax attributable to subsidiaries . . . . . . (25) (31) 63
Other. . . . . . . . . . . . . . . . . . . . (36) 56 (507)
--------------- -------- --------
Total federal and state income tax . . . . . $ 5,120 $ 6,043 $ 6,948
=============== ======== ========
Effective combined federal and state
income tax rate. . . . . . . . . . . . . . 33.0% 34.5% 37.4%
NON-UTILITY. The Company's non-utility subsidiaries, excluding Northern Water
Resources, Inc. ("NWR"), had accumulated deferred income taxes of approximately
$2,000 on their balance sheets at December 31, 2003, attributable to
depreciation timing differences.
The components of the provision for the income tax expense (benefit) for
the non-utility operations were not significant.
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, 2003, 2002 and 2001. 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 equity
securities, fixed income securities, hedge funds and cash equivalent funds.
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 to meet or exceed the minimum funding requirements of
ERISA or Pension Benefit Guaranty Corporation, 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 during 2002 and made voluntary
contributions totaling $3.5 million during 2003. The Company currently plans to
contribute between $2.0 and $3.0 million of additional funds during 2004. The
Company's pension costs and cash funding requirements could increase in future
years in the absence of further recovery in the equity markets.
During 2002, the Company's retirement plan asset return experience required
the Company to recognize a minimum pension liability of $4.0 million, and a $1.6
million tax benefit, as prescribed by generally accepted accounting principles.
Common equity was reduced in the amount of $2.4 million through a charge to
other comprehensive income.
During 2003, market value appreciation of pension plan investments resulted
in the reduction of the previously recognized minimum pension liability to $3.0
million. Common equity increased approximately $587,000, net of applicable
income tax, through a credit to other comprehensive income.
Accrued postretirement health care expenses are recovered in rates. 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, 2003 and 2002.
At and for the years ended December 31,
Pension Benefits Other Postretirement Benefits
---------------- -----------------------------
2003 2002 2003 2002
--------------- -------- --------- ---------
(In thousands)
Change in projected benefit obligation:
Projected benefit obligation as of prior year end. $ 29,937 $25,895 $ 20,707 $ 16,491
Service cost . . . . . . . . . . . . . . . . . . . 755 668 496 296
Interest cost. . . . . . . . . . . . . . . . . . . 1,900 1,849 1,316 1,119
Participant contributions. . . . . . . . . . . . . - - 136 147
Plan change. . . . . . . . . . . . . . . . . . . . - - (1,812) -
Change in actuarial assumptions. . . . . . . . . . 292 - 2,095 -
Actuarial (gain) loss. . . . . . . . . . . . . . . 2,789 3,230 (25) 3,619
Benefits paid. . . . . . . . . . . . . . . . . . . (1,629) (1,650) (1,007) (965)
Administrative expense . . . . . . . . . . . . . . (64) (55) - -
--------------- -------- --------- ---------
Projected benefit obligation as of year end. . . . $ 33,980 $29,937 $ 21,906 $ 20,707
=============== ======== ========= =========
Change in plan assets:
Fair value of plan assets as of prior year end . . $ 21,104 $24,341 $ 8,760 $ 10,016
Administrative expenses paid . . . . . . . . . . . (64) (55) - -
Participant contributions. . . . . . . . . . . . . - - 136 147
Employer contributions . . . . . . . . . . . . . . 3,500 1,000 782 819
Actual return on plan assets . . . . . . . . . . . 4,956 (2,532) 1,558 (1,257)
Benefits paid. . . . . . . . . . . . . . . . . . . (1,629) (1,650) (1,007) (965)
--------------- -------- --------- ---------
Fair value of plan assets as of year end . . . . . $ 27,867 $21,104 $ 10,229 $ 8,760
=============== ======== ========= =========
Funded status as of year end . . . . . . . . . . . $ (6,113) $(8,833) $(11,677) $(11,948)
Unrecognized transition obligation (asset) . . . . - (77) 2,952 3,280
Unrecognized prior service cost. . . . . . . . . . 984 839 (2,216) (462)
Unrecognized net actuarial loss. . . . . . . . . . 6,372 6,982 9,250 8,379
--------------- -------- --------- ---------
Prepaid (accrued) benefits at year end . . . . . . $ 1,243 $(1,089) $ (1,691) $ (751)
=============== ======== ========= =========
The Company also has a supplemental pension plan for certain employees.
Pension costs for the years ended December 31, 2003, 2002, and 2001 were
$392,000, $408,000, and $340,000, 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
2003 2002 2001 2003 2002 2001
--------------- -------- -------- ------- ------- -------
(In thousands)
Service cost . . . . . . . . . . . . . . . $ 755 $ 668 $ 537 $ 496 $ 296 $ 241
Interest cost. . . . . . . . . . . . . . . 1,900 1,849 1,737 1,316 1,119 1,043
Expected return on plan assets . . . . . . (1,851) (2,112) (2,379) (740) (851) (892)
Amortization of transition asset . . . . . (77) (164) (164) - -
Amortization of prior service cost . . . . 147 147 147 (58) (58) (58)
Amortization of the transition obligation. - - - 328 328 328
Recognized net actuarial gain. . . . . . . 294 - (237) 381 60 -
--------------- -------- -------- ------- ------- -------
Net periodic benefit cost (income) . . $ 1,168 $ 388 $ (359) $1,723 $ 894 $ 662
=============== ======== ======== ======= ======= =======
Assumptions used to determine pension and postretirement benefit costs and the
related benefit obligations were:
Assumptions used in benefit obligation measurement
For the years ended December 31,
Pension benefits Other Postretirement Benefits
---------------- -----------------------------
2003 2002 2003 2002
----- ----- ----- ------
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . . 6.00% 6.50% 6.00% 6.50%
Expected return on plan assets . . . . . . . 8.50% 9.00% 8.50% 8.50%
Rate of compensation increase. . . . . . . . 4.25% 4.25% 4.25% 4.25%
Medical inflation. . . . . . . . . . . . . . - - 9.25% 10.00%
Assumptions used in periodic cost measurement
For the years ended December 31,
Pension benefits Other Postretirement Benefits
---------------- -----------------------------
2003 2002 2003 2002
----- ----- ------ -----
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . . 6.50% 7.00% 6.50% 7.00%
Expected return on plan assets . . . . . . . 8.50% 9.00% 8.50% 8.50%
Rate of compensation increase. . . . . . . . 4.25% 4.25% 4.25% 4.25%
Medical inflation. . . . . . . . . . . . . . - - 10.00% 7.50%
For measurement purposes, a 9.25 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, 2003 by $4.8 million and the total of the service
and interest cost components of net periodic postretirement cost for the year
ended December 31, 2003 by $434,000. Decreasing the trend rate by one
percentage point for all future years would decrease the accumulated
postretirement benefit obligation at December 31, 2003 by $3.8 million, and the
total of the service and interest cost components of net periodic postretirement
cost for 2003 by $339,000.
The Company's defined benefit plan investment policy seeks to achieve
sufficient growth to enable the pension plan to meet its future obligations and
to maintain certain funded ratios and minimize near-term cost volatility.
Current guidelines specify generally that 65 percent of plan assets be invested
in equity securities, 30 percent of plan assets be invested in debt securities
and the remainder be invested in alternative investments.
The Company expects an annual long-term return for the defined benefit plan
asset portfolios of 8.25 percent, based on a representative allocation within
the target asset allocation described above. In formulating this assumed rate
of return, the Company considered historical returns by asset category and
expectations for future returns by asset category based, in part, on expected
capital market performance of the next ten years.
Pension Assets
Weighted Average Asset Allocation For the years ended December 31,
2004 TARGET 2003 2002
------------ ------- -------
Asset Category
Equity Securities . . . 65.00% 63.10% 59.61%
Debt Securities . . . . 30.00% 24.92% 31.65%
Real Estate . . . . . . 0.00% 0.00% 0.00%
Other . . . . . . . . . 0.00% 6.60% 8.74%
Alternative investments 5.00% 5.38% 0.00%
------------ ------- -------
total . . . . . . . . . 100.00% 100.00% 100.00%
============ ======= =======
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 deregulation in Vermont. Legislation has been
introduced in the Vermont legislature that would permit (but not require) the
Company to negotiate with individual customers to permit such customers to
procure their own electric power supply requirements, subject to VPSB approval.
We cannot predict whether this legislation will be enacted. If enacted, the
Company would not negotiate any such arrangement unless in the Company's
estimation, the arrangement assured the Company of full recovery of any
resulting stranded costs and that the Company's financial condition would not
otherwise be adversely affected. 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. 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.
PINE STREET BARGE CANAL SUPERFUND SITE - In 1999 the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the United States Environmental Protection Agency ("EPA"), the State of Vermont
and numerous other parties of claims relating to a federal superfund site in
Burlington, Vermont, known as the Pine Street Barge Canal. The consent decree
resolves claims by the EPA for past site costs, natural resource damage claims
and claims for past and future remediation costs. The consent decree also
provides for the design and implementation of response actions at the site. In
2003, the Company expended $2.6 million to cover its obligations under the
consent decree and we have estimated total future costs of the Company's net
future obligations through 2033 under the consent decree to be $8.5 million.
The estimated liability is not discounted, and it is possible that our estimate
of future costs could change by a material amount. We have also recorded a
regulatory asset of $13.0 million to reflect future recovery of these costs, as
well as past unrecovered costs. Pursuant to the Company's 2003 Rate Plan, as
approved by the VPSB, the Company will begin to amortize past unrecovered costs
in 2005. The Company will amortize the full amount of these costs, as they are
incurred, over 20 years without a return. The amortization will be allowed in
future rates, without disallowance or adjustment, until fully amortized.
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, 2003, as follows:
Share of Share of
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- --------- --------------- -------------
(In %) (In MWh) (In thousands)
Highgate . . . . . . . . 33.8 67.6 $ 10,296 $ 4,926
McNeil . . . . . . . . . 11.0 5.9 8,989 5,379
Stony Brook (No. 1). . . 8.8 31 10,377 8,965
Wyman (No. 4). . . . . . 1.1 6.8 1,980 1,380
Metallic Neutral Return. 59.4 - 1,563 806
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 - On December 22, 2003, the VPSB approved a three-year rate
plan (the "2003 Rate Plan") jointly proposed earlier in the year by the Company
and the Department. The 2003 Rate Plan, as approved, covers the period through
2006 and includes the following principal elements.
The Company's rates will remain unchanged through 2004. The 2003 Rate Plan
allows the Company to raise rates 1.9 percent, effective January 1, 2005, and an
additional 0.9 percent, effective January 1, 2006, if the increases are
supported by cost of service schedules submitted 60 days prior to the effective
dates. If the Company's cost of service filings in 2005 or 2006 establish that
a lesser rate increase in required for the Company to meet its revenue
requirements, the Company will implement the lesser rate increase.
The Company may seek additional rate increases in extraordinary
circumstances, such as severe storm repair costs, natural disasters, extended
unanticipated unit outages, or significant losses of customer load.
The Company's allowed return on equity is reduced from 11.25 percent to
10.5 percent, for the period January 1, 2003 through December 31, 2006. During
the same period, the Company's earnings on core utility operations are capped at
10.5 percent. If excess earnings result in 2004, they will be applied to
reduce regulatory assets. Excess earnings in 2005 or 2006 will be refunded to
customers as a credit on customer bills or applied to reduce regulatory assets,
as the Department directs.
The Company will carry forward into 2004 $3.0 million in deferred revenue
remaining at December 31, 2003 from the Company's 2001 rate case settlement
summarized below. The Company will amortize (recover) certain regulatory
assets, including Pine Street Barge Canal environmental site costs and past
demand-side management program costs, beginning in January 2005, with those
amortizations to be allowed in future rates. Pine Street costs will be
recovered over a twenty-year period without a return.
The Company will file with the VPSB in early 2004 a new fully allocated
cost of service study and rate re-design, which will allocate the Company's
revenue requirement among all customer classes on the basis of current costs.
The new rate design will be subject to VPSB approval.
The Company and the Department have agreed to work cooperatively to develop
and propose an alternative regulation plan as authorized by legislation enacted
in Vermont in 2003. The target for filing such a plan is April 2004. If the
Company and Department agree on such a plan, and it is approved by the VPSB, the
alternative regulation plan would supersede the 2003 Rate Plan.
In January 2001, the VPSB approved a rate case settlement between the
Company and the Department (the "2001 Settlement Order"). The final settlement,
as approved, included the following:
* 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 $30,000 in excess of its allowed rate of
return during 2001 before writing off regulatory assets in the same amount.
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.
5. DEFERRED CHARGES NOT INCLUDED IN RATE BASE.
The Company has incurred and deferred approximately $11.1 million in costs
for Pine Street, tree trimming, storm damage, and regulatory commission work of
which approximately $408,000 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 amounts deferred. Management expects to recover these costs
over periods ranging from five to twenty years beginning January 1, 2005,
pursuant to the 2003 Rate Plan. The 2001 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 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.
In November 2003, Rockingham notified the Company that the town intended to
initiate proceedings before the town selectboard to condemn the Company's
distribution and associated property located within the town. The Company
sought and obtained in December 2003 a preliminary injunction from the State
Superior Court prohibiting the town from proceeding with condemnation before the
selectboard. The Company successfully argued that Vermont law required
Rockingham to pursue any such municipalization effort by petition to the VPSB,
which is required to determine both the fair value of any assets subject to
municipalization and the amount of damages to the utility caused by severance of
the property subject to municipalization. The preliminary injunction remains in
effect and Rockingham has not filed any petition with the VPSB seeking to
municipalize assets. 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.
7. OTHER LEGAL MATTERS.
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
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
in connection with this proceeding.
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, 2003, the present value of the Company's
obligation is approximately $4.6 million.
Projected future minimum payments under the Phase II support agreements are
as follows:
Year ending
December 31
---------------
(In thousands)
2004. . . . . . . . $ 387
2005. . . . . . . . 387
2006. . . . . . . . 387
2007. . . . . . . . 387
2008. . . . . . . . 387
Total for 2009-2015 2,712
Total . . . . . $ 4,647
===============
The Phase II portion of the project is owned by New England Hydro-Transmission
Electric Company and New England Hydro-Transmission Corporation, subsidiaries of
National Grid USA. Certain of the Phase II participating utilities, including
the Company, own equity interests in such companies. The Company holds
approximately 3.2 percent of the equity of the corporations owning the Phase II
facilities and accounts for its ownership under the equity method of accounting.
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 2003 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 $ 128
Other debt service 444
Other capacity 535
Total annual capacity $ 1,107
=======================
Company's share of long-term debt $ 1,817
2. VERMONT YANKEE
The Company has a long-term power purchase contract with VY, which sold its
nuclear power plant to ENVY on July 31, 2002. The Company is no longer required
to pay its proportionate share of fixed costs associated with the ENVY 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 ENVY also calls for ENVY, 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.
A summary of the Purchase Power Agreement, 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 2003 $ 37,288
estimated 2004-2015 $ 32,377
Average cost per KWh 2003 $ 0.042
estimated 2004-2015 $ 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 ENVY to finalize the VY sale.
The Company received its share of the VY power plant sale proceeds,
approximately $8.2 million, during October 2003, and used the proceeds to retire
debt.
3. HYDRO-QUEBEC
Under various contracts, summarized 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 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
increased power supply expense during 2003 by approximately $1.2 million.
During 2003, Hydro-Quebec exercised its second option to reduce the load
factor for 2004, and we expect Hydro-Quebec to exercise its third option in 2004
for deliveries occurring principally during 2005. Hydro-Quebec also 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.
Under the 1987 Contract, Vermont joint owners, including the Company, have two
remaining options to adjust deliveries by a five percent load factor. These
cannot be used to offset Hydro-Quebec's reductions through 2005, but may be used
after 2005 to manage power supply costs.
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, 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 65%-75% 65%-75%
(annual load factor)
Annual energy charge 2003 $ 10,565 $ 7,219
estimated 2004-2015 13,756 (1) 9,400 (1)
Annual capacity charge 2003 $ 16,857 $ 11,519
estimated 2004-2015 $ 17,122 (1) $ 11,699 (1)
Average cost per KWh 2003 $ 0.071 $ 0.071
estimated 2004-2015 $ 0.064 (2) $ 0.064 (2)
(1)Estimated average includes load factor reduction to 65 percent in 2004
(2)Estimated average in nominal dollars levelized over the period indicated
includes amortization of payments to Hydro-Quebec
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 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, 2003, Hydro-Quebec had
purchased or called to purchase 513,000 MWh under option B.
In 2003, Hydro-Quebec exercised option A and option B, and called for
delivery to third parties at a net expense to the Company of approximately $4.5
million, including capacity charges.
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.
The Company believes that it is probable that Hydro-Quebec will call
options A and B for 2004, and has purchased replacement power at an incremental
cost of $3.2 million. The Company has also covered 54 percent of expected calls
during 2005 at an incremental cost of $1.1 million.
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.
Beginning January 1, 2004, the Company will reduce the power that it sells
to MS. The reduction in sales is expected to reduce wholesale revenues by
approximately $65 million, and power supply expense by a similar
amount. The Company does not expect the change to adversely affect its
opportunity to earn its allowed rate of return during 2004.
The Company and MS have agreed to the protocols that are used to schedule
power sales and purchases and to secure necessary transmission. The MS contract
is a derivative that includes a risk premium above expected future costs of
electricity.
L. DISCONTINUED OPERATIONS.
The Company has 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 net reserve for loss
from discontinued operations reflects management's current estimate. The
residual operations earned $0.01 per share in 2003 and $0.02 per share in 2002,
primarily as a result of adjustments to a reserve for warranty claims. At
December 31, 2003, 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 against NWR. The ultimate loss remains subject to the
disposition of remaining assets and liabilities, and could exceed the amounts
recorded. The following illustrates the results and financial statement impact
of discontinued operations during and at the periods shown:
2003 2002 2001
-------------------------------- ------ -------
(In thousands except per share)
Revenues . . . . . . . . . . . . . $ - $ 88 $ 156
-------------------------------- ------ -------
Gain (loss) on disposal. . . . . . 79 99 (182)
Net income (loss). . . . . . . . . $ 79 $ 99 $ (182)
================================ ====== =======
Net income (loss) per share-basic. $ 0.01 $ 0.02 $(0.03)
Proceeds from asset sales. . . . . $ - $ - $ -
Total assets . . . . . . . . . . . $ 1,488 $1,622 $2,700
State income taxes . . . . . . . . $ 12 $ 19 $ (175)
Federal income taxes . . . . . . . 39 52 (550)
Investment tax credits . . . . . . - - -
-------------------------------- ------ -------
Income tax expense (benefit) . . . $ 51 $ 71 $ (725)
================================ ====== =======
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.
2003 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
-------- -------- ---------- --------- --------
(Amounts in thousands except per share data)
Operating revenues . . . . . . . . . . . . . . $72,945 $64,455 $ 71,975 $ 71,095 $280,470
Operating income . . . . . . . . . . . . . . . 5,231 2,425 4,302 3,348 15,306
Net income-continuing operations . . . . . . . $ 4,084 $ 1,120 $ 3,034 $ 2,087 $ 10,325
Net income-discontinued operations . . . . . . (13) (8) 6 94 79
Net Income applicable to common stock. . . . . $ 4,071 $ 1,112 $ 3,040 $ 2,181 $ 10,404
======== ======== ========== ========= ========
Basic earnings per share from:
Continuing operations. . . . . . . . . . . . . $ 0.82 $ 0.22 $ 0.61 0.43 $ 2.08
Discontinued operations. . . . . . . . . . . . - - - 0.01 0.01
Basic earnings per share . . . . . . . . . . . $ 0.82 $ 0.22 $ 0.61 $ 0.44 $ 2.09
======== ======== ========== ========= ========
Weighted average common shares outstanding . . 4,959 4,969 4,982 5,009 4,980
Diluted earnings per share from:
Continuing operations. . . . . . . . . . . . . $ 0.80 $ 0.22 $ 0.59 0.40 $ 2.01
Discontinued operations. . . . . . . . . . . . - - - 0.01 0.01
Diluted earnings per share . . . . . . . . . . $ 0.80 $ 0.22 $ 0.59 $ 0.41 $ 2.02
======== ======== ========== ========= ========
Weighted average common and common equivalent. 5,118 5,129 5,141 5,165 5,140
shares outstanding
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 5,756
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
Independent Auditors' Report
To the Board of Directors of
Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Green Mountain Power Corporation and
subsidiaries (the Company) as of December 31, 2003, and 2002, and the related
consolidated statements of income, comprehensive income, changes in stockholders
equity and cash flows for each of the two years in the period ended December 31,
2003. The financial statements of Green Mountain Power Corporation and
subsidiaries as of December 31, 2001 and for the year 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 audits in accordance with auditing standards generally accepted
in the United States of America. 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 financial statements referred to above present fairly, in
all material respects, the financial position of Green Mountain Power
Corporation and subsidiaries as of December 31, 2003 and 2002, and the results
of their operations and their cash flows for each of the two years then ended in
conformity with accounting principles generally accepted in the United States.
Deloitte & Touche, LLP
/s/Deloitte & Touche, LLP
Boston, Massachusetts
February 25, 2004
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, 2003, 2002, and 2001
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)
----------------------------------------------
2003 . . . . . . . . . . . . . . . . . . . . . $10,489,506 (521,493) - 1,522,330 $ 8,445,683
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
Allowance for Doubtful Accounts
----------------------------------------------
2003 . . . . . . . . . . . . . . . . . . . . . 547,316 143,214 - - 690,530
2002 . . . . . . . . . . . . . . . . . . . . . 575,890 - 37,270 65,844 547,316
2001 . . . . . . . . . . . . . . . . . . . . . 425,890 150,000 575,890
(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, 2003 and 2002 and for each of the two years in the period ended
December 31, 2003, and have issued our report thereon dated February 25, 2004;
such report is included elsewhere in this Form 10-K. Our audit also included
the 2003 and 2002 information included in the financial statement schedule 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 audits. In our opinion,
such 2003 and 2002 information included in the 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. The
financial statement schedule of Green Mountain Power Corporation and
subsidiaries as of December 31, 2001 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.
/s/DELOITTE & TOUCHE LLP
Boston, MA
February 25, 2004
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.
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 year ended December 31, 2001 did not contain
any qualification, modification, or disclaimers.
ITEM 9A. CONTROLS AND PROCEDURES
Pursuant to Rule 13a-15(b) under the Securities and Exchange Act of 1934,
we carried out an evaluation, with the participation of our management,
including Christopher L. Dutton, President and Chief Executive Officer and
Robert J. Griffin, Chief Financial Officer, Vice President and Treasurer
(principal financial officer), of the effectiveness of our disclosure controls
and procedures (as defined under Rule 13a-15(e) under the Securities Exchange
Act of 1934) as of the end of the period covered by this report. Based upon
that evaluation, our President and Chief Executive Officer, and our Chief
Financial Officer, Vice President and Treasurer (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 has been no change in our internal control over financial reporting
during the quarter ended December 31, 2003 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.
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 20,
2004. 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 2004.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees Paid to Deloitte & Touche
During the fiscal year ended December 31, 2003, Deloitte & Touche was employed
principally to perform the annual audit and to render other services. Fees paid
to Deloitte & Touche for services rendered in fiscal years 2002 and 2003 are
listed in the following table.
Years ended December 31,
2003 2002
-------- --------
Audit Fees . . . . . . . . . . $160,471 $162,484
Audit-Related Fees . . . . . . 7,000 -
Tax Services Fees. . . . . . . 36,577 54,147
All other fees . . . . . . . . - -
Total Deloitte and Touche fees $204,048 $216,631
======== ========
Fees paid during 2002 include audit fees of $9,000 and tax fees of $6,050 paid
to Arthur Andersen for services rendered during 2002.
Audit Fees include fees for services performed to comply with Generally Accepted
Auditing Standards (GAAS), including the recurring audit of the Company's
financial statements. This category also includes fees for audits provided in
connection with statutory filings or services that generally only the principal
auditor reasonably can provide to a client, such as procedures related to audit
of income tax provisions and related reserves, consents and assistance with and
review of documents filed with the Securities and Exchange Commission.
Audit-Related Fees include fees associated with assurance and related services
that are reasonably related to the performance of the audit or review of the
Company's financial statements. This category includes fees related to
assistance with implementation of the new Securities and Exchange Commission and
Sarbanes-Oxley Act of 2002 requirements. Audit-related fees also include audits
of employee benefit plans.
Tax Fees primarily include fees associated with tax audits, tax compliance, tax
consulting, as well as tax planning.
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:
On December 23, 2003, a Form 8-K filing announced the VPSB approval of a
Memorandum of Understanding with the DPS regarding rate stability, rate
increases, and the amortization of the Pine Street Barge Canal costs.
On December 10, 2003, a Form 8-K filing announced that the Board of Directors
had approved changes to the Company's Bylaws.
On December 3, 2003, a Form 8-K filing announced a presentation by Christopher
L. Dutton, the President and CEO, and Robert J. Griffin, CFO, at an electric
industry conference entitled "Investing in the Electric Utilities Industry".
The accompanying notes are an integral part of these consolidated financial
statements.
ITEM 15(A)3 AND ITEM 15C. EXHIBITS SEC DOCKET
, INCORPORATED BY
EXHIBIT REFERENCE OR
NUMBER DESCRIPTION EXHIBIT PAGE FILED HEREWITH
---------- -------------------------------------------------------------- ---------- -----------------------
3-A RESTATED ARTICLES OF ASSOCIATION, AS CERTIFIED . . . . . . . . 3-A FORM 10-K 1993
JUNE 6, 1991. (1-8291)
3-A-1 AMENDMENT TO 3-A ABOVE, DATED AS OF MAY 20, 1993.. . . . . . . 3-A-1 FORM 10-K 1993
(1-8291)
3-A-2 AMENDMENT TO 3-A ABOVE, DATED AS OF OCTOBER 11, 1996.. . . . . 3-A-2 FORM 10-Q SEPT.
1996 (1-8291)
3-B BY-LAWS OF THE COMPANY, AS AMENDED . . . . . . . . . . . . . . 3-B FORM 10-K 1996
FEBRUARY 10, 1997. (1-8291)
3-C BY-LAWS OF THE COMPANY, AS AMENDED . . . . . . . . . . . . . . 3-C FORM 8-K DEC. 12, 2004
DECEMBER 8, 2004 (1-8291)
4-B-1 INDENTURE OF FIRST MORTGAGE AND DEED OF TRUST. . . . . . . . . 4-B 2-27300
DATED AS OF FEBRUARY 1, 1955.
4-B-2 FIRST SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . . 4-B-2 2-75293
APRIL 1, 1961.
4-B-3 SECOND SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . . 4-B-3 2-75293
JANUARY 1, 1966.
4-B-4 THIRD SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . . 4-B-4 2-75293
JULY 1, 1968.
4-B-5 FOURTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . . 4-B-5 2-75293
OCTOBER 1, 1969.
4-B-6 FIFTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . . 4-B-6 2-75293
DECEMBER 1, 1973.
4-B-7 SEVENTH SUPPLEMENTAL INDENTURE DATED AS. . . . . . . . . . . . 4-A-7 2-99643
AUGUST 1, 1976.
4-B-8 EIGHTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . . 4-A-8 2-99643
DECEMBER 1, 1979.
4-B-9 NINTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . . 4-B-9 2-99643
JULY 15, 1985.
4-B-10 TENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . . 4-B-10 FORM 10-K 1989
JUNE 15, 1989. (1-8291)
4-B-11 ELEVENTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . . 4-B-11 FORM 10-Q SEPT.
SEPTEMBER 1, 1990. 1990 (1-8291)
4-B-12 TWELFTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . . 4-B-12 FORM 10-K 1991
MARCH 1, 1992. (1-8291)
4-B-13 THIRTEENTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . 4-B-13 FORM 10-K 1991
MARCH 1, 1992. (1-8291)
4-B-14 FOURTEENTH SUPPLEMENTAL INDENTURE DATED AS OF. . . . . . . . . 4-B-14 FORM 10-K 1993
NOVEMBER 1, 1993. (1-8291)
4-B-15 FIFTEENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . 4-B-15 FORM 10-K 1993
NOVEMBER 1, 1993. (1-8291)
4-B-16 SIXTEENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . . 4-B-16 FORM 10-K 1995
DECEMBER 1, 1995. (1-8291)
4-B-17 REVISED FORM OF INDENTURE AS FILED AS AN EXHIBIT . . . . . . . 4-B-17 FORM 10-Q SEPT.
TO REGISTRATION STATEMENT NO. 33-59383. 1995 (1-8291)
4-B-18 CREDIT AGREEMENT BY AND AMONG GREEN MOUNTAIN POWER . . . . . . 4-B-18 FORM 10-K 1997
THE BANK OF NOVA SCOTIA, STATE STREET BANK AND (1-8291)
TRUST COMPANY, FLEET NATIONAL BANK, AND FLEET
NATIONAL BANK, AS AGENT
4-B-18(A) AMENDMENT TO EXHIBIT 4-B-18. . . . . . . . . . . . . . . . . . 4-B-18(A) FORM 10-Q SEPT.
1998 (1-8291)
4-B-19 SEVENTEENTH SUPPLEMENTAL INDENTURE DATED AS OF . . . . . . . . 4-B-19 FORM 10-K 2002
DECEMBER 1, 2002 (1-8291)
10-A FORM OF INSURANCE POLICY ISSUED BY PACIFIC . . . . . . . . . . 10-A 33-8146
INSURANCE COMPANY, WITH RESPECT TO
INDEMNIFICATION OF DIRECTORS AND OFFICERS.
10-B-1 FIRM POWER CONTRACT DATED SEPTEMBER 16, 1958,. . . . . . . . . 13-B 2-27300
BETWEEN THE COMPANY AND THE STATE OF VERMONT
AND SUPPLEMENTS THERETO DATED SEPTEMBER 19,
1958; NOVEMBER 15, 1958; OCTOBER 1, 1960 AND
FEBRUARY 1, 1964.
10-B-2 POWER CONTRACT, DATED FEBRUARY 1, 1968, BETWEEN THE COMPANY. . 13-D 2-34346
AND VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-3 AMENDMENT, DATED JUNE 1, 1972, TO POWER CONTRACT . . . . . . . 13-F-1 2-49697
BETWEEN THE COMPANY AND VERMONT YANKEE NUCLEAR
POWER CORPORATION.
10-B-3(A) AMENDMENT, DATED APRIL 15, 1983, TO POWER. . . . . . . . . . . 10-B-3(A) 33-8164
CONTRACT BETWEEN THE COMPANY AND VERMONT
YANKEE NUCLEAR POWER CORPORATION.
10-B-3(B) ADDITIONAL POWER CONTRACT, DATED . . . . . . . . . . . . . . . 10-B-3(B) 33-8164
FEBRUARY 1, 1984,BETWEEN THE COMPANY AND
VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-4 CAPITAL FUNDS AGREEMENT, DATED FEBRUARY 1, . . . . . . . . . . 13-E 2-34346
1968, BETWEEN THE COMPANY AND VERMONT
YANKEE NUCLEAR POWER CORPORATION.
10-B-5 AMENDMENT, DATED MARCH 12, 1968, TO CAPITAL. . . . . . . . . . 13-F 2-34346
FUNDS AGREEMENT BETWEEN THE COMPANY AND
VERMONT YANKEE NUCLEAR POWER CORPORATION.
10-B-6 GUARANTEE AGREEMENT, DATED NOVEMBER 5, 1981, OF THE. . . . . . 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 THREE-PARTY POWER AGREEMENT AMONG THE COMPANY, . . . . . . . . 13-I 2-49697
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-8 2-75293
10-B-9 THREE-PARTY TRANSMISSION AGREEMENT AMONG THE . . . . . . . . . 13-J 2-49697
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-10 2-75293
10-B-14 AGREEMENT WITH CENTRAL MAINE POWER COMPANY ET. . . . . . . . . 5.16 2-52900
AL, TO ENTER INTO JOINT OWNERSHIP OF WYMAN
PLANT, DATED NOVEMBER 1, 1974.
10-B-15 NEW ENGLAND POWER POOL AGREEMENT AS AMENDED TO . . . . . . . . 4.8 2-55385
NOVEMBER 1, 1975.
10-B-16 BULK POWER TRANSMISSION CONTRACT BETWEEN THE . . . . . . . . . 13-V 2-49697
COMPANY AND VELCO DATED JUNE 1, 1968.
10-B-17 AMENDMENT TO EXHIBIT 10-B-16, DATED JUNE 1, 1970.. . . . . . . 13-V-I 2-49697
10-B-20 POWER SALES AGREEMENT, DATED AUGUST 2, 1976, AS. . . . . . . . 10-B-20 33-8164
AMENDED OCTOBER 1, 1977, AND RELATED
TRANSMISSION AGREEMENT, WITH THE MASSACHUSETTS
MUNICIPAL WHOLESALE ELECTRIC COMPANY.
10-B-21 AGREEMENT DATED OCTOBER 1, 1977, FOR JOINT OWNERSHIP,. . . . . 10-B-21 33-8164
CONSTRUCTION AND OPERATION OF THE MMWEC PHASE I
INTERMEDIATE UNITS, DATED OCTOBER 1, 1977
10-B-28 CONTRACT DATED FEBRUARY 1, 1980, PROVIDING FOR . . . . . . . . 10-B-28 33-8164
THE SALE OF FIRM POWER AND ENERGY BY THE POWER
AUTHORITY OF THE STATE OF NEW YORK TO THE
VERMONT PUBLIC SERVICE BOARD.
10-B-30 BULK POWER PURCHASE CONTRACT DATED APRIL 7,. . . . . . . . . . 10-B-32 2-75293
1976, BETWEEN VELCO AND THE COMPANY.
10-B-33 AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT. . . . . . 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 PHASE I TRANSMISSION LINE SUPPORT AGREEMENT. . . . . . . . . . 10-B-34 33-8164
DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
VETCO AND PARTICIPATING NEW ENGLAND UTILITIES
FOR CONSTRUCTION, USE AND SUPPORT OF VERMONT
FACILITIES OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-35 PHASE I TERMINAL FACILITY SUPPORT AGREEMENT. . . . . . . . . . 10-B-35 33-8164
DATED AS OF DECEMBER 1, 1981, AND AMENDMENT
NO. 1 DATED AS OF JUNE 1, 1982, BETWEEN
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
AND PARTICIPATING NEW ENGLAND UTILITIES FOR
CONSTRUCTION, USE AND SUPPORT OF NEW HAMPSHIRE
FACILITIES OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-36 AGREEMENT WITH RESPECT TO USE OF QUEBEC. . . . . . . . . . . . 10-B-36 33-8164
INTERCONNECTION DATED AS OF DECEMBER 1, 1981,
AMONG PARTICIPATING NEW ENGLAND UTILITIES
FOR USE OF TRANSMISSION INTERCONNECTION
BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-39 VERMONT PARTICIPATION AGREEMENT FOR QUEBEC . . . . . . . . . . 10-B-39 33-8164
INTERCONNECTION DATED AS OF JULY 15, 1982,
BETWEEN VELCO AND PARTICIPATING VERMONT
UTILITIES FOR ALLOCATION OF VELCO'S RIGHTS
AND OBLIGATIONS AS A PARTICIPATING NEW
ENGLAND UTILITY IN THE TRANSMISSION INTER-
CONNECTION BETWEEN NEW ENGLAND AND HYDRO-QUEBEC.
10-B-40 VERMONT ELECTRIC TRANSMISSION COMPANY, INC.. . . . . . . . . . 10-B-40 33-8164
CAPITAL FUNDS AGREEMENT DATED AS OF JULY 15,
1982, BETWEEN VETCO AND VELCO FOR VELCO TO PROVIDE
CAPITAL TO VETCO FOR CONSTRUCTION OF THE VERMONT FACILITIES
OF THE TRANSMISSION INTER-CONNECTION BETWEEN NEW
ENGLAND AND HYDRO-QUEBEC.
10-B-41 VETCO CAPITAL FUNDS SUPPORT AGREEMENT DATED AS . . . . . . . . 10-B-41 33-8164
OF JULY 15, 1982, BETWEEN VELCO AND PARTICIPATING VERMONT
UTILITIES FOR ALLOCATION OF VELCO'S OBLIGATION TO VETCO
UNDER THE CAPITAL FUNDS AGREEMENT.
10-B-42 ENERGY BANKING AGREEMENT DATED MARCH 21, 1983, . . . . . . . . 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 INTERCONNECTION AGREEMENT DATED MARCH 21, 1983,. . . . . . . . 10-B-43 33-8164
BETWEEN HYDRO-QUBEC AND PARTICIPATING NEW
ENGLAND UTILITIES ACTING BY AND THROUGH THE
NEPOOL MANAGEMENT COMMITTEE FOR TERMS AND
CONDITIONS OF ENERGY TRANSMISSION BETWEEN
NEW ENGLAND AND HYDRO-QUEBEC.
10-B-44 ENERGY CONTRACT DATED MARCH 21, 1983, BETWEEN. . . . . . . . . 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 AGREEMENT FOR JOINT OWNERSHIP, CONSTRUCTION AND. . . . . . . . 10-B-50 33-8164
OPERATION OF THE HIGHGATE TRANSMISSION
INTERCONNECTION, DATED AUGUST 1, 1984,
BETWEEN CERTAIN ELECTRIC DISTRIBUTION
COMPANIES, INCLUDING THE COMPANY.
10-B-51 HIGHGATE OPERATING AND MANAGEMENT AGREEMENT, . . . . . . . . . 10-B-51 33-8164
DATED AS OF AUGUST 1, 1984, AMONG VELCO AND
VERMONT ELECTRIC-UTILITY COMPANIES, INCLUDING
THE COMPANY.
10-B-52 ALLOCATION CONTRACT FOR HYDRO-QUEBEC FIRM POWER. . . . . . . . 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 HIGHGATE TRANSMISSION AGREEMENT DATED AS OF. . . . . . . . . . 10-B-53 33-8164
AUGUST 1, 1984, BETWEEN THE OWNERS OF THE
PROJECT AND VARIOUS VERMONT ELECTRIC
DISTRIBUTION COMPANIES.
10-B-61 AGREEMENTS ENTERED IN CONNECTION WITH PHASE II . . . . . . . . 10-B-61 33-8164
OF THE NEPOOL/HYDRO-QUEBEC + 450 KV HVDC
TRANSMISSION INTERCONNECTION.
10-B-62 AGREEMENT BETWEEN UNITIL POWER CORP. AND THE . . . . . . . . . 10-B-62 33-8164
COMPANY TO SELL 23 MW CAPACITY AND ENERGY FROM
STONY BROOK INTERMEDIATE COMBINED CYCLE UNIT.
10-B-68 FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 4, . . . . . . . 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 FIRM POWER AGREEMENT DATED AS OF OCTOBER 26, 1987, . . . . . . 10-B-69 FORM 10-K 1992
BETWEEN ONTARIO HYDRO AND VERMONT DEPARTMENT OF (1-8291)
PUBLIC SERVICE.
10-B-70 FIRM POWER AND ENERGY CONTRACT DATED AS OF . . . . . . . . . . 10-B-70 FORM 10-K 1992
FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT (1-8291)
OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-
QUEBEC FOR UP TO 50 MW OF CAPACITY.
10-B-70(A) AMENDMENT TO 10-B-70.. . . . . . . . . . . . . . . . . . . . . 10-B-70(A) FORM 10-K 1992
(1-8291)
10-B-71 INTERCONNECTION AGREEMENT DATED AS OF. . . . . . . . . . . . . 10-B-71 FORM 10-K 1992
FEBRUARY 23, 1987, BETWEEN THE VERMONT JOINT (1-8291)
OWNERS OF THE HIGHGATE FACILITIES AND HYDRO-QUEBEC.
10-B-72 PARTICIPATION AGREEMENT DATED AS OF APRIL 1, 1988, . . . . . . 10-B-72 FORM 10-Q
BETWEEN HYDRO-QUEBEC AND PARTICIPATING VERMONT JUNE 1988
UTILITIES, INCLUDING THE COMPANY, IMPLEMENTING (1-8291)
THE PURCHASE OF FIRM POWER FOR UP TO 30 YEARS
UNDER THE FIRM POWER AND ENERGY CONTRACT DATED
DECEMBER 4, 1987 (PREVIOUSLY FILED WITH THE
COMPANY'S ANNUAL REPORT ON FORM 10-K FOR 1987,
EXHIBIT NUMBER 10-B-68).
10-B-72(A) RESTATEMENT OF THE PARTICIPATION AGREEMENT FILED . . . . . . . 10-B-72(A) FORM 10-K 1988
AS EXHIBIT 10-B-72 ON FORM 10-Q FOR JUNE 1988. (1-8291)
10-B-77 FIRM POWER AND ENERGY CONTRACT DATED DECEMBER 29,. . . . . . . 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 TRANSMISSION AGREEMENT DATED DECEMBER 23, 1988,. . . . . . . . 10-B-78 FORM 10-K 1988
BETWEEN THE COMPANY AND NIAGARA MOHAWK POWER (1-8291)
CORPORATION (NIAGARA MOHAWK), FOR NIAGARA
MOHAWK TO PROVIDE ELECTRIC TRANSMISSION TO
THE COMPANY FROM ROCHESTER GAS AND ELECTRIC
AND CENTRAL HUDSON GAS AND ELECTRIC.
10-B-81 SALES AGREEMENT DATED MAY 24, 1989, BETWEEN. . . . . . . . . . 10-B-81 FORM 10-Q
THE TOWN OF HARDWICK, HARDWICK ELECTRIC DEPARTMENT JUNE 1989
AND THE COMPANY FOR THE COMPANY TO PURCHASE (1-8291)
ALL OF THE OUTPUT OF HARDWICK'S GENERATION AND
TRANSMISSION SOURCES AND TO PROVIDE HARDWICK
WITH ALL-REQUIREMENTS ENERGY AND CAPACITY EXCEPT
FOR THAT PROVIDED BY THE VERMONT DEPARTMENT OF
PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
10-B-82 SALES AGREEMENT DATED JULY 14, 1989, BETWEEN . . . . . . . . . 10-B-82 FORM 10-Q
NORTHFIELD ELECTRIC DEPARTMENT AND THE COMPANY JUNE 1989
FOR THE COMPANY TO PURCHASE ALL OF THE OUTPUT (1-8291)
OF NORTHFIELD'S GENERATION AND TRANSMISSION
SOURCES AND TO PROVIDE NORTHFIELD WITH ALL-
REQUIREMENTS ENERGY AND CAPACITY EXCEPT FOR
THAT PROVIDED BY THE VERMONT DEPARTMENT OF
PUBLIC SERVICE OR FEDERAL PREFERENCE POWER.
10-B-85 POWER PURCHASE AND SALE AGREEMENT BETWEEN. . . . . . . . . . . 10-B-85 FORM 10-K 1998
MORGAN STANLEY CAPITAL GROUP INC. AND THE (1-8291)
COMPANY
10-B-86 REVOLVING CREDIT AGREEMENT WITH KEYBANK. . . . . . . . . . . . 10-B-86 FORM 10-Q SEPT.
2000 (1-8291)
10-B-87 AMENDMENT TO FLEET REVOLVING CREDIT AGREEMENT. . . . . . . . . 10-B-87 FORM 10-Q SEPT.
2000 (1-8291)
10-B-88 ENERGY EAST POWER PURCHASE OPTION AGREEMENT. . . . . . . . . . 10-B-88 FORM 10-Q SEPT.
2000 (1-8291)
10-B-89 SECOND AMENDED AND RESTATED CREDIT AGREEMENT BETWEEN . . . . . 10-B-89 FORM 10-K 2001
KEYBANK NATIONAL ASSOCIATION, FLEET NATIONAL BANK, AND
THE COMPANY DATED JUNE 20, 2001
10-B-90 PURCHASE POWER AGREEMENT BETWEEN ENTERGY NUCLEAR VERMONT . . . 10-B-90 FORM 10-Q JUNE 2002
YANKEE LLC AND VERMONT YANKEE NUCLEAR POWER CORPORATION (1-8291)
10-B-91 FIRST AMENDMENT TO PURCHASE POWER AGREEMENT LISTED AS. . . . . 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 AMENDMENT TO POWER PURCHASE AND SALE AGREEMENT . . . . . . . . 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 FORM 10-K 1993
AND RESTATED DEFERRED COMPENSATION PLAN FOR DIRECTORS.
10-D-1C. GREEN MOUNTAIN POWER CORPORATION SECOND AMENDED 10-D-1C FORM 10-K 1993
AND RESTATED DEFERRED COMPENSATION PLAN FOR
OFFICERS.
10-D-1D. AMENDMENT NO. 93-1 TO THE AMENDED AND RESTATED 10-D-1D FORM 10-K 1993
DEFERRED COMPENSATION PLAN FOR OFFICERS.
10-D-1E. AMENDMENT NO. 94-1 TO THE AMENDED AND RESTATED 10-D-1E FORM 10-Q
DEFERRED COMPENSATION PLAN FOR OFFICERS. JUNE 1994
10-D-2 . GREEN MOUNTAIN POWER CORPORATION MEDICAL EXPENSE 10-D-2 FORM 10-K 1991
REIMBURSEMENT PLAN.
10-D-4 . GREEN MOUNTAIN POWER CORPORATION OFFICER 10-D-4 FORM 10-K 1991
INSURANCE PLAN.
10-D-4A. GREEN MOUNTAIN POWER CORPORATION OFFICERS' 10-D-4A FORM 10-K 1990
INSURANCE PLAN AS AMENDED.
10-D-8 . GREEN MOUNTAIN POWER CORPORATION OFFICERS' 10-D-8 FORM 10-K 1990
SUPPLEMENTAL RETIREMENT PLAN.
10-D-15B GREEN MOUNTAIN POWER CORPORATION COMPENSATION PROGRAM 10-D-15B FORM 10-K 1997
FOR OFFICERS AND KEY MANAGEMENT PERSONNEL AS AMENDED
AUGUST 4, 1997
10-D-15C GREEN MOUNTAIN POWER 2000 STOCK INCENTIVE PLAN 10-D-15C FORM 10-K 2001
10-D-40. SEVERANCE AGREEMENT WITH C. L. DUTTON 10-D-40 FORM 10-K 2003
10-D-41. SEVERANCE AGREEMENT WITH D.J. RENDALL 10-D-41 FORM 10-K 2003
10-D-42. SEVERANCE AGREEMENT WITH R. J. GRIFFIN 10-D-42 FORM 10-K 2003
10-D-43. SEVERANCE AGREEMENT WITH W. S. OAKES 10-D-43 FORM 10-K 2003
10-D-44. SEVERANCE AGREEMENT WITH M. G. POWELL 10-D-44 FORM 10-K 2003
10-D-45. SEVERANCE AGREEMENT WITH S. C. TERRY 10-D-45 FORM 10-K 2003
10-D-46. DEFERRED STOCK UNIT AGREEMENT WITH D.J. RENDALL 10-D-46 FORM 10-K 2003
10-D-47. DEFERRED STOCK UNIT AGREEMENT WITH C. L. DUTTON 10-D-47 FORM 10-K 2003
10-D-48. DEFERRED STOCK UNIT AGREEMENT WITH S. C. TERRY 10-D-48 FORM 10-K 2003
10-D-49. DEFERRED STOCK UNIT AGREEMENT WITH R. J. GRIFFIN 10-D-49 FORM 10-K 2003
10-D-50. DEFERRED STOCK UNIT AGREEMENT WITH W. S. OAKES 10-D-50 FORM 10-K 2003
10-D-51. DEFERRED STOCK UNIT AGREEMENT WITH M. G. POWELL 10-D-51 FORM 10-K 2003
10-D-52. DEFERRED STOCK UNIT AGREEMENT WITH E. A. BANKOWSKI 10-D-52 FORM 10-K 2004
10-D-53. DEFERRED STOCK UNIT AGREEMENT WITH N. L. BRUE 10-D-53 FORM 10-K 2003
10-D-54. DEFERRED STOCK UNIT AGREEMENT WITH W. H. BRUETT 10-D-54 FORM 10-K 2003
10-D-55. DEFERRED STOCK UNIT AGREEMENT WITH M. O. BURNS 10-D-55 FORM 10-K 2003
10-D-56. DEFERRED STOCK UNIT AGREEMENT WITH L. E. CHICKERING 10-D-56 FORM 10-K 2003
10-D-57. DEFERRED STOCK UNIT AGREEMENT WITH J. V. CLEARY 10-D-57 FORM 10-K 2003
10-D-58. DEFERRED STOCK UNIT AGREEMENT WITH D.R. COATES 10-D-58 FORM 10-K 2003
10-D-59. DEFERRED STOCK UNIT AGREEMENT WITH E. A. IRVING 10-D-59 FORM 10-K 2003
10-D-60. DIRECTOR DEFERRAL AGREEMENT WITH E. A. BANKOWSKI 10-D-60 FORM 10-K 2003
10-D-61. DIRECTOR DEFERRAL AGREEMENT WITH M. O. BURNS 10-D-61 FORM 10-K 2003
10-D-62. DIRECTOR DEFERRAL AGREEMENT WITH D. R. COATES 10-D-62 FORM 10-K 2003
10-D-63. DIRECTOR DEFERRAL AGREEMENT WITH E. A. IRVING 10-D-63 FORM 10-K 2003
*23-A-1. CONSENT OF ARTHUR ANDERSEN LLP 23-A-1
23-A-2 . CONSENT OF DELOITTE AND TOUCHE LLP 23-A-2
24 . . . LIMITED POWER OF ATTORNEY 24
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, 2003, and generally to do all such things in
our name and behalf in our capacities as directors to enable Green Mountain
Power Corporation to comply with the provisions of the Securities Exchange Act
of 1934, as amended, all requirements of the Securities and Exchange Commission,
and all requirements of any other applicable law or regulation, hereby ratifying
and confirming our signatures as they may be signed by our said attorney, to
said Annual Report.
SIGNATURE TITLE DATE
--------- ----- ----
/s/Christopher L. Dutton President and Director February 25, 2004
--------------------------
Christopher L. Dutton (Principal Executive
Officer)
/s/Nordahl L. Brue March 4, 2004
--------------------
Nordahl L. Brue Chairman of the Board
/s/Elizabeth A. Bankowski March 1, 2004
---------------------------
Elizabeth A. Bankowski Director
/s/William H. Bruett March 3, 2004
----------------------
William H. Bruett Director
/s/Merrill O. Burns March 1, 2004
---------------------
Merrill O. Burns Director
/s/Lorraine E. Chickering March 2, 2004
---------------------------
Lorraine E. Chickering Director
/s/John V. Cleary March 4, 2004
-------------------
John V. Cleary Director
/s/David R. Coates March 4, 2004
--------------------
David R. Coates Director
/s/Euclid A. Irving March 1, 2004
---------------------
Euclid A. Irving Director
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: February 25, 2004 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 February 25, 2004
------------------------------
Christopher L. Dutton Officer, and Director
/s/ Mary G. Powell_______ Chief Operating Officer, March 10, 2004
-----------------------------
Mary G. Powell Senior Vice President
/s/ Robert J. Griffin Chief Financial Officer, Vice February 25, 2004
-------------------------
Robert J. Griffin President and Treasurer
*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 February 25, 2004
---------------------------
Christopher L. Dutton
(Attorney - in - Fact)