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, 2004
COMMISSION FILE NUMBER 1-8291
GREEN MOUNTAIN POWER CORPORATION
--------------------------------
(Exact name of registrant as specified in its charter)
Vermont 03-0127430
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(State or other jurisdiction of (I.R.S. Employer Identification
No.)
incorporation or organization)
163 Acorn Lane
Colchester, VT 05446
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (802) 864-5731
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Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each exchange on which registered
COMMON STOCK, PAR VALUE NEW YORK STOCK EXCHANGE
$3.33-1/3 PER SHARE
______________________________________________________________________________
Securities registered pursuant to Section 12 (g) of the Act: None
______________________________________________________________________________
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes __X__ No _____
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. _X_
-
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 JUNE 30, 2004, WAS APPROXIMATELY $132,535,487 BASED ON THE
CLOSING PRICE OF $26.10 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 17, 2005, WAS
5,164,205.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's Definitive Proxy Statement relating to its Annual
Meeting of Stockholders to be held on May 23, 2005, to be filed with the
Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934,
are 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, 2004
Table of contents Page
Part I
Item 1, Business 3
Item 2, Properties 18
Item 3, Legal Proceedings 19
Item 4, Submission of Matters To a Vote of 19
Security Holders
Part II
Item 5, Market for Registrant's Common
Equity and Related Shareholder Matters 19
Item 6, Selected Financial Data 20
Item 7, Management's Discussion and Analysis 21
Of Financial Condition and Results
Of Operations
Item 8, Financial Statements and Supplementary Data 43
Item 9, Changes In and Disagreements with Accountants 83
On Accounting and Financial Disclosure
Item 9A, Controls and Procedures 83
Item 10 Certain Officer Information 85
Items 11, 12, 13 and 14 Executive Compensation, Security 85
Ownership of Certain Beneficial Owners and
Management, Certain Relationships and Related
Transactions and Principal Accounting Fees
and Services
Item 15, Exhibits and Financial Statement Schedules, 86
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 2004 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 that transmits, distributes and sells electricity and
utility construction services in the State of Vermont ("State" or "Vermont") in
a service territory with approximately one quarter of Vermont's population. We
serve approximately 90,000 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, 2004 were as
follows:
* 33.4 percent from residential customers;
* 33.2 percent from small commercial and industrial customers;
* 21.7 percent from large commercial and industrial customers;
* 9.9 percent from sales to other utilities; and
* 1.8 percent from other sources.
Approximately 98 percent of our revenue has resulted from the sale of
electricity over the period 2002 - 2004.
See the Company's Annual Report and MD and A, Item 7 below, for further
information about revenues.
During 2004, our energy resources for retail sales of electricity were
obtained as follows:
* 37.5 percent from hydroelectric sources (29.2 percent Hydro Quebec, 4.9
percent Company-owned, and 3.4 percent independent power producers);
* 36.9 percent from a nuclear generating source (the Entergy Nuclear Vermont
Yankee, LLC ("ENVY") nuclear plant described below);
* 3.9 percent from wood;
* 2.5 percent from natural gas or oil; and
* 0.5 percent from wind.
The remaining 18.7 percent was purchased on a short-term basis from
generators through the wholesale market operated by ISO New England, Inc.
formerly the New England Power Pool ("NEPOOL").
In 2004, we estimate that we purchased under existing contracts or
generated approximately 90 percent of our energy resources to satisfy our retail
and wholesale sales of electricity under long-term arrangements, including our
contract with Morgan Stanley Capital Group, Inc. (the "Morgan Stanley Contract")
described below. Remaining retail and wholesale sales were met through
short-term market purchases and represent primarily 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 Entergy Vermont Yankee Nuclear LLC ("ENVY") (the "Vermont
Yankee" or "VY" plant). We have a 33.6 percent equity interest in Vermont
Yankee Nuclear Power Corporation ("VYNPC"), which has a long-term power supply
contract with ENVY that entitles us to 20 percent of Vermont Yankee plant output
through 2012. For further information concerning Vermont Yankee, see Power
Resources - Vermont Yankee, below.
The Company owns approximately 29.2 percent of common stock and 30.0
percent of the preferred stock of Vermont Electric Power Company, Inc.
("VELCO"). VELCO owns the high-voltage transmission system in Vermont. VELCO's
wholly-owned subsidiary, Vermont Electric Transmission Company, Inc. ("VETCO"),
was formed to finance, construct and operate the Vermont portion of the 450 kV
DC transmission line connecting the Province of Quebec with Vermont and New
England. For further information concerning VELCO, see VELCO below.
The Company participates in the New England regional wholesale electric
power markets operated by ISO New England, Inc. ("ISO-NE") the regional bulk
power transmission organization established to assure reliable and economical
power supply in New England. The Federal Energy Regulatory Commission ("FERC")
has granted approval to ISO-NE to become a regional transmission organization
("RTO") for New England. On February 1, 2005, ISO-NE commenced operations as
the RTO, providing regional transmission service in New England, with
operational control of the bulk power system and responsibility for
administering wholesale markets. 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 agreement 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 VELCO and others.
Included in these areas are the communities of Vernon (where the Vermont Yankee
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 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,
2004 2003 2002 2001 2000
----------- ----------- ----------- ----------- -----------
Net system peak (MW*) . . . . . . . . . . . . . . 326.7 330.2 342.0 341.2 323.5
----------- ----------- ----------- ----------- -----------
Production and purchases (MWH**)
Hydro . . . . . . . . . . . . . . . . . . . . . . 777,292 838,855 901,998 951,146 1,053,223
Wind. . . . . . . . . . . . . . . . . . . . . . . 11,023 10,828 11,458 12,135 12,246
Nuclear . . . . . . . . . . . . . . . . . . . . . 764,010 884,585 771,781 736,420 803,303
Conventional steam. . . . . . . . . . . . . . . . 89,622 100,402 85,910 33,194 53,066
Internal combustion . . . . . . . . . . . . . . . 13,026 12,603 4,090 18,291 35,699
Combined cycle. . . . . . . . . . . . . . . . . . 32,224 68,488 81,362 72,653 73,433
Bilateral and system purchases. . . . . . . . . . 793,939 2,423,831 2,345,205 2,637,055 2,651,361
----------- ----------- ----------- ----------- -----------
Total production. . . . . . . 2,481,136 4,339,592 4,201,804 4,460,894 4,682,331
Less non-firm sales to other utilities. . . . . . 408,601 2,284,003 2,104,172 2,365,809 2,573,576
----------- ----------- ----------- ----------- -----------
Production for firm sales . . . . . . . . . . . . 2,072,535 2,055,589 2,097,632 2,095,085 2,108,755
Less firm sales and lease transmissions. . . . . 1,973,093 1,937,376 1,951,959 1,956,232 1,954,898
----------- ----------- ----------- ----------- -----------
Losses and company use (MWH). . . . . . . . . . . 99,442 118,213 145,673 138,853 153,857
=========== =========== =========== =========== ===========
Losses as a % of total production . . . . . . . . 4.01% 2.72% 3.47% 3.11% 3.29%
System load factor (***). . . . . . . . . . . . . 72.4% 71.1% 70.0% 70.1% 74.2%
Net Production (% of Total)
Hydro . . . . . . . . . . . . . . . . . . . . . . 31.3% 19.3% 21.5% 21.3% 22.5%
Wind. . . . . . . . . . . . . . . . . . . . . . . 0.4% 0.2% 0.3% 0.3% 0.3%
Nuclear . . . . . . . . . . . . . . . . . . . . . 30.8% 20.4% 18.3% 16.5% 17.1%
Conventional steam. . . . . . . . . . . . . . . . 3.6% 2.3% 2.0% 0.7% 1.1%
Internal combustion . . . . . . . . . . . . . . . 0.5% 0.3% 0.1% 0.4% 0.8%
Combined cycle. . . . . . . . . . . . . . . . . . 1.3% 1.6% 1.9% 1.6% 1.6%
Bilateral and system purchases. . . . . . . . . . 32.1% 55.9% 55.8% 59.1% 56.6%
----------- ----------- ----------- ----------- -----------
Total . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0%
=========== =========== =========== =========== ===========
Sales and Lease Transmissions(MWH)
Residential - GMPC. . . . . . . . . . . . . . . . 580,710 581,047 553,294 549,151 558,682
Commercial & industrial - small . . . . . . . . . 715,602 703,036 695,504 691,029 704,126
Commercial & industrial - large . . . . . . . . . 666,503 645,271 689,618 710,944 683,296
Other . . . . . . . . . . . . . . . . . . . . . . 7,112 4,986 9,773 2,030 6,713
----------- ----------- ----------- ----------- -----------
Total retail sales and lease transmissions. . . . 1,969,927 1,934,340 1,948,189 1,953,154 1,952,817
Sales to Municipals & Cooperatives (Rate W) . . . 3,166 3,036 3,770 3,078 2,081
----------- ----------- ----------- ----------- -----------
Total Requirements Sales. . . . . . . . . . . . . 1,973,093 1,937,376 1,951,959 1,956,232 1,954,898
Other Sales for Resale. . . . . . . . . . . . . . 408,601 2,284,003 2,104,172 2,365,809 2,573,576
----------- ----------- ----------- ----------- -----------
Total sales and lease transmissions(MWH) . . . . 2,381,694 4,221,379 4,056,131 4,322,041 4,528,474
=========== =========== =========== =========== ===========
Average Number of Electric Customers
Residential . . . . . . . . . . . . . . . . . . . 75,507 74,693 73,861 73,249 72,424
Commercial and industrial small . . . . . . . . . 13,515 13,344 13,165 12,976 12,746
Commercial and industrial large . . . . . . . . . 24 25 29 30 23
Other . . . . . . . . . . . . . . . . . . . . . . 62 65 65 65 65
----------- ----------- ----------- ----------- -----------
Total. . . . . . . . . . . . . . . . 89,108 88,127 87,120 86,320 85,258
=========== =========== =========== =========== ===========
Average Revenue Per KWH (Cents)
Residential including lease revenues. . . . . . . 13.15 12.98 12.96 13.33 12.50
Commercial & industrial - small . . . . . . . . . 10.63 10.40 10.44 10.90 10.00
Commercial & industrial - large . . . . . . . . . 7.44 7.41 7.31 7.70 6.51
Total retail. . . . . . . . . . . . . . . . . . . 10.32 10.22 10.09 10.44 9.52
Average Use and Revenue Per Residential Customer
KWh's including lease transmissions . . . . . . . 7,691 7,779 7,491 7,497 7,717
Revenues including lease revenues . . . . . . . . $ 1,012 $ 1,010 $ 971 $ 999 $ 965
(*) 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 ("DPS" or the "Department"),
created by statute in 1981, acts as the public advocate in rate and other state
regulatory proceedings and 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.
Certain components of the businesses of the Company and VELCO, including
certain rates, are subject to the jurisdiction of the FERC as follows: the
Company as a licensee of hydroelectric developments under Part I of the Federal
Power Act, and the Company and VELCO as interstate public utilities under Parts
II and III of the Federal Power Act, as amended and supplemented by the National
Energy Act.
Our transmission assets and the wholesale rate on sales to two wholesale
customers are regulated by the FERC. Revenues from sales to these customers
were less than 1.0 percent of our operating revenues for 2004.
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 2004.
On July 17, 1997, the FERC approved our Open Access Transmission Tariff.
On November 26, 2004, we received from FERC an exemption from the standards of
conduct requirements of FERC Order 2004, governing separation of transmission
operations. 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 VYNPC, VELCO and VETCO. 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 . . July 30, 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 2005. When repairs and
re-licensing proceedings 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. On January 19,
2005, the Department adopted a new 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.
On 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. The
Company filed a cost of service schedule pursuant to the plan in November 2004
and received approval from the VPSB to implement the plan's 2005 1.9 percent
rate increase, effective January 1, 2005.
Allows the Company the opportunity to file for rate increases during the
period from January 1, 2003 to December 31, 2006 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.
For further discussion of the Company's 2003 Rate Plan, see Item 7a.
Quantitative and Qualitative Disclosures About Market Risk, and Other Risk
Factors - Rates.
SINGLE CUSTOMER DEPENDENCE
The Company had one major retail customer, IBM, metered at two locations
that accounted for 16.4 percent, 16.6 percent and 17.3 percent of the Company's
retail operating revenues in 2004, 2003 and 2002, 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 approximately five percent,
inclusive of projected declines in sales to other residential and commercial
customers. See Item 7a. Quantitative and Qualitative Disclosures About Market
Risk, and Other Risk Factors - Customer Concentration Risk, and Note A of Notes.
COMPETITION AND RESTRUCTURING
Competition currently takes several forms. At the wholesale level New
England has implemented its version of FERC's "standard market design ("SMD"),
which is a detailed competitive market framework that has resulted in bid-based
competition of power suppliers rather than prices set under cost of service
regulation. At the retail level, customers have long had energy options such as
propane, natural gas or oil for heating, cooling and water heating, and
self-generation. Another competitive threat is the potential for customers to
form municipally owned utilities in the Company's service territory.
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. 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 $56 million and $96 million over the life of the
Company's current contracts.
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. There are
currently no regulatory proceedings, court actions or pending legislative
proposals to adopt electric industry restructuring in Vermont. For further
information regarding Competition and Restructuring, See Item 7a. Quantitative
and Qualitative Disclosures About Market Risk, and Other Risk Factors -
Regulatory Risk.
The Town of Rockingham, Vermont, located in the southeastern portion of our
service territory, has exercised an option to purchase a hydro-electric facility
partially located in the town (the "Bellows Falls facility"). If Rockingham or
its assignee is successful in arranging for purchase of the Bellows Falls
facility, we expect to conclude an agreement to permit Rockingham to be
responsible for its own power supply needs, with the Company providing
distribution and other services to the town. In any such agreement the Company
would continue to own its distribution plant located in the town and receive
distribution services revenues sufficient to cover all costs of providing
services and all stranded costs associated with the Company's present obligation
to provide integrated electric service to customers in Rockingham. Such an
arrangement would require VPSB approval. The Company receives annual revenues
of approximately $3 million from its customers in Rockingham.
CONSTRUCTION AND CAPITAL REQUIREMENTS
Our capital expenditures for 2002 through 2004 and projected for 2005 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
We generated, purchased or transmitted 2,072,535 MWh of energy for retail
and requirements wholesale customers for the twelve months ended December 31,
2004. The corresponding maximum one-hour integrated demand during that period
was 326.7 MW on December 21, 2004. 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 12/31/2004 of annual peak
MWH percent KW percent
--------- -------- ------- --------
Wholly-owned plants:
Hydro . . . . . . . . . . . . . 101,517 4.9% 23,370 6.3%
Diesel and Gas Turbine. . . . . 13,026 0.6% 58,550 15.8%
Wind. . . . . . . . . . . . . . 11,023 0.5% 960 0.3%
Jointly-owned plants:
Wyman #4. . . . . . . . . . . . 5,830 0.3% 6,470 1.7%
Stony Brook I . . . . . . . . . 22,117 1.1% 30,936 8.3%
McNeil. . . . . . . . . . . . . 24,171 1.2% 5,770 1.6%
Long Term Purchases:
Vermont Yankee/ENVY . . . . . . 764,010 36.9% 97,451 26.3%
Hydro Quebec. . . . . . . . . . 605,718 29.2% 107,391 29.0%
Stony Brook I . . . . . . . . . 10,107 0.5% 14,124 3.8%
Other:
Independent Power Producers . . 124,617 6.0% 25,610 6.9%
Morgan Stanley. . . . . . . . . 193,158 9.3% - -
ISO-NE and Short-term purchases 197,241 9.5% - -
--------- -------- ------- --------
Net Own Load. . . . . . . . . . 2,072,535 100.0% 370,632 100.0%
========= ======== ======= ========
VERMONT YANKEE.
On July 31, 2002, VYNPC 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 VYNPC, 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 VYNPC 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 Vermont Yankee plant.
Our ownership share of VYNPC increased from approximately 19.0 percent in
2003 to approximately 33.6 percent currently, due to VYNPC's purchase last year
of certain minority shareholders' interests. VYNPC's primary role consists of
administering its power supply contract with ENVY and its contracts with VYNPC's
present sponsors. Our entitlement to energy produced by the Vermont Yankee
nuclear plant has remained at 20 percent of plant production.
During periods when Vermont Yankee power is unavailable, the costs of
replacement power occasionally exceed those costs that we would have incurred
for power purchased pursuant to our power supply agreement with VYNPC.
Replacement power is available to us from the wholesale market 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.
Vermont Yankee's current operating license expires March 2012. Since the
Company no longer owns an interest in the Vermont Yankee nuclear plant, we no
longer bear the operating costs and risks associated with running and
decommissioning the plant.
During the year ended December 31, 2004, we used 764,010 MWh of Vermont
Yankee energy (supplied by ENVY) representing 36.9 percent of the net
electricity generated and purchased ("net power supply") by the Company.
See Item 7a. Quantitative and Qualitative Disclosures About Market Risk,
and Other Risk Factors - Other Power Supply Risks, and Notes B and 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. Commencing with implementation of New
England's RTO, the Highgate facilities are now controlled and operated by
ISO-NE. We do not expect ISO-NE's operation or control of these facilities to
affect the Company's deliveries of power from Hydro Quebec under our current
power contract commitments.
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
National Grid, successor to New England Electric System.
Phase II. Phase II provides 2,000 MW of capacity for transmission of Hydro
Quebec power 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, 2004, the
present value of the Company's obligation was approximately $4.2 million. The
Company's projected future minimum payments under the Phase II support
agreements are approximately $383,000 for each of the years 2005-2009 and an
aggregate of $2,299,000 for the years 2010-2015.
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 National Grid, successor to New England Electric
System, in which certain of the Phase II participating utilities, including the
Company, own equity interests. The Company owns approximately 3.2 percent of
the equity of the corporations owning the Phase II facilities. See Note B and
Note J of Notes.
Hydro Quebec Power Supply Contracts. The bulk of our purchases from Hydro
Quebec are pursuant to two schedules, B and C3, of 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 agreement (the
"9701 agreement") with Hydro Quebec under which Hydro Quebec paid $8,000,000 to
the Company in exchange for certain power purchase options. See Item 7a.
Quantitative and Qualitative Disclosures About Market Risk, and Other Risk
Factors - Power Contract Commitments, and Note K of Notes.
During 2004, we used 363,849 MWh under Schedule B, and 241,869 MWh under
Schedule C3 of the VJO Contract, representing 29.2 percent of our net power
supply.
MORGAN STANLEY CONTRACT - 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 7a. Quantitative and Qualitative Disclosures About Market Risk,
and Other Risk Factors - Power Contract Commitments and Note K of Notes.
ISO-NE 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 to recover all of the forecasted fuel or production costs and to recover
some, if not all, associated capacity costs. During 2004, the Company purchased
197,241 MWh representing 9.5 percent of the Company's net power supply.
During 2002, the FERC accepted ISO-NE's request to implement a Standard
Market Design ("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. 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 2004, we used 32,224 MWh from this plant representing 1.6 percent of
our net power supply. 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. Florida Power &
Light is the principal owner and operator of the 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 2004, we used 5,830 MWh from this unit representing 0.3 percent of
our net power supply. 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 2004, we used 24,171 MWh from this unit representing 1.2 percent of
our net power supply. See Note I of Notes. The Burlington Electric Department
is the principal owner and operator of the McNeil plant.
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 2004 was approximately 34.3
percent or 51.5 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 currently under development.
In 2004, through our direct contracts and VEPPI, we purchased 124,617 MWh
of qualifying facilities production representing 6.0 percent of our net power
supply.
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 2004, Company owned hydroelectric plants produced 101,517 MWh,
representing 4.9 percent of our net power supply. See State and Federal
Regulation - Licensing.
VELCO. The Company and fifteen 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 matters. See Note B
of Notes.
FUEL. During 2004, our retail and requirements wholesale sales were
provided by the following fuel sources:
* 37.5 percent from hydroelectric sources (29.2 percent Hydro Quebec, 4.9
percent Company-owned, and 3.4 percent independent power producers;
* 36.9 percent from a nuclear generating source (the Vermont Yankee nuclear
plant);
* 3.9 percent from wood;
* 2.5 percent from natural gas and oil;
* 0.5 percent from wind; and
* 18.7 percent purchased on a short-term basis from other utilities through
the ISO-NE and Morgan Stanley.
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 2004. None of the
utilities from which we expect to purchase oil- or gas-fired capacity in 2005
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 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.
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 2004, the project produced 11,023 MWh, representing 0.5
percent of the Company's net power supply.
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 A 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, 2004, the Company had 192 employees, exclusive of
temporary employees. The Company considers its relations with employees to be
excellent. The current labor contract expires December 31, 2007.
ENERGY EFFICIENCY
In 2004, 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 1,715 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 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, 2004, approximately 1,587 of the Company's largest customers,
comprising approximately 51 percent of retail revenues, received service on
mandatory time-of-use rates. Pursuant to the Company's 2003 Rate Plan, in March
2004, the Company filed with the VPSB a new fully-allocated cost of service
study and rate re-design, which re-allocates the Company's revenue requirement
among all customer classes on the basis of current costs. The Company's new
proposed rate design is subject to VPSB approval. We do not expect the proposed
rate design to adversely affect operating results.
DISPATCHABLE AND INTERRUPTIBLE SERVICE CONTRACTS
In 2004, we had 26 dispatchable power contracts: 22 contracts were
year-round, and 4 customers had seasonal contracts. 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
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
non-performing note from a hydroelectric facility in New Hampshire, and a
wastewater business in the process of completing dissolution. For information
regarding our unregulated businesses, see Note A of the Notes.
EXECUTIVE OFFICERS
The names, ages, and positions of our Executive Officers, in alphabetical
order, as of March 15, 2005 are:
Christopher L. Dutton 56
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 48
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 58
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 44
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 49
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 62
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 April 12, 2005,
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.
We also make available on the website the Company's Corporate Governance
Guidelines, Code of Ethics and Conduct, Bylaws, and the Charters of the Audit,
Compensation and Governance Committees of the Company. 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 35.3 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 58.5 MW. We have two diesel
generating stations with an aggregate nameplate rating of 8.0 MW and an
estimated aggregate claimed capability of 6.3 MW. We also have a wind
generating facility with a nameplate rating of 6.1 MW and a claimed capability
of 5.9 MW.
We also own:
* 33.6 percent of the outstanding common stock of Vermont Yankee Nuclear
Power Corporation 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 Vermont Yankee
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, 2004, approximately 2 miles of 115 kV
transmission lines, 10 miles of 69 kV transmission lines, 5 miles of 44 kV
transmission lines, 196 miles of 34.5 kV transmission lines, and 2 miles of 13.8
kV transmission lines. Our distribution system included approximately 2,657
miles of overhead lines of 2.4 to 34.5 kV and 433 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 949,000 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.
The Company also owns 59.4 percent of the metallic neutral return, a neutral
conductor for the NEPOOL/Hydro Quebec interconnection.
We also own 29.2 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.
VELCO's properties consist of about 573 miles of high voltage overhead
transmission lines and associated substations. The lines connect on the west
with the lines of Niagara Mohawk Power Corporation at the Vermont-New York state
line near Whitehall, New York, and Bennington, Vermont, and with the submarine
cable of NYPA near Plattsburgh, New York; on the south and east with the lines
of New England Power Company and PSNH; on the south with the facilities of
Vermont Yankee; and on the north with lines of Hydro Quebec through a converter
station and tie line jointly owned by the Company and several other Vermont
utilities.
VELCO's wholly-owned subsidiary, VETCO, has about 52 miles of high voltage
DC transmission line connecting with the transmission line of Hydro Quebec at
the Quebec-Vermont border in the Town of Norton, Vermont; and connecting with
the transmission line of New England Electric Transmission Corporation, a
subsidiary of National Grid USA, at the Vermont-New Hampshire border near New
England Power Company's Moore hydro-electric generating station.
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 claimed
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 (1) Hydro 5.0
Hydro . . . . . . . . . Bolton, VT DeForge #1 Hydro 7.8
Diesel. . . . . . . . . Vergennes, VT Vergennes #9 Oil 4.1
Diesel. . . . . . . . . Essex Jct., VT Essex #19 Oil 2.2
Gas Turbine . . . . . . Berlin, VT Berlin #5 Oil 45.0
Turbine . . . . . . . . Colchester, VT Gorge #16 Oil 13.5
Wind. . . . . . . . . . Searsburg, VT Searsburg Wind 5.9
Jointly Owned
Steam . . . . . . . . . Yarmouth, ME Wyman #4 Oil 6.9
Steam . . . . . . . . . Burlington, VT McNeil (2) Wood/Gas 6.6
Combined. . . . . . . . Ludlow, MA Stony Brook #1 Oil/Gas 31.0
Total Winter Capability 150.5
========
(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 2004 and 2003:
HIGH LOW
------ ------
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
2004
First Quarter. $26.29 $22.60
Second Quarter 26.10 24.40
Third Quarter. 26.82 25.08
Fourth Quarter 29.15 24.80
The number of common stockholders of record as of February 18, 2004 was
approximately 5,119, $3.33333 par value.
Quarterly cash dividends were paid as follows during the past two years:
First Second Third Fourth
Quarter Quarter Quarter Quarter
-------- -------- -------- --------
2003 $ 0.19 $ 0.19 $ 0.19 $ 0.19
2004 $ 0.22 $ 0.22 $ 0.22 $ 0.22
Dividend Policy. The Company increased its dividend in February 2005 from an
annual rate of $0.88 per share to $1.00 per share. The Company's dividend
payout ratio remains comparatively low, at approximately 48 percent of 2004
earnings from continuing operations. We expect to grow our dividend payout
ratio to the middle of a payout range of 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.
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.
ITEM 6. SELECTED FINANCIAL DATA
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,
- --------------------------------------------------------------
2004 2003 2002 2001 2000
--------- --------- --------- --------- ---------
In thousands, except per share data
Operating Revenues. . . . . . . . . . . . . . . . . . . . . . . $228,816 $280,470 $274,608 $283,464 $277,326
Operating Expenses. . . . . . . . . . . . . . . . . . . . . . . 213,338 265,164 259,528 267,005 272,066
Operating Income. . . . . . . . . . . . . . . . . . . . . 15,478 15,306 15,080 16,459 5,260
--------- --------- --------- --------- ---------
Other Income
AFUDC - equity. . . . . . . . . . . . . . . . . . . . . . 449 387 233 210 284
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1,638 1,692 2,252 2,163 2,422
Total other income. . . . . . . . . . . . . . . . . . . . 2,087 2,079 2,485 2,373 2,706
--------- --------- --------- --------- ---------
Interest Charges
AFUDC - borrowed. . . . . . . . . . . . . . . . . . . . . (285) (267) (103) (188) (228)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,791 7,324 6,273 7,227 7,485
Total interest charges. . . . . . . . . . . . . . . . 6,506 7,057 6,170 7,039 7,257
--------- --------- --------- --------- ---------
Net Income (Loss) from continuing operations before . . . . . . 11,059 10,328 11,395 11,793 709
preferred dividends
Net Income (Loss) from discontinued operations, including
provisions for loss on disposal. . . . . . . . . . . . . . . 525 79 99 (182) (6,549)
Dividends on Preferred Stock. . . . . . . . . . . . . . . . . . - 3 96 933 1,014
--------- --------- --------- --------- ---------
Net Income (Loss)Applicable
to Common Stock . . . . . . . . . . . . . . . . . . . . . $ 11,584 $ 10,404 $ 11,398 $ 10,678 $ (6,854)
========= ========= ========= ========= =========
Common Stock Data
Basic earnings per share-continuing operations . . . . . . . . $ 2.18 $ 2.08 $ 2.02 $ 1.93 $ (0.06)
Basic earnings per share-discontinued operations . . . . . . . $ 0.10 $ 0.01 $ 0.02 $ (0.03) $ (1.19)
Basic earnings per share . . . . . . . . . . . . . . . . . . . $ 2.28 $ 2.09 $ 2.04 $ 1.90 $ (1.25)
========= ========= ========= ========= =========
Diluted earnings (loss) per share from continuing operations . $ 2.10 $ 2.01 $ 1.96 $ 1.88 $ (0.06)
Diluted earnings (loss) per share from discontinued operations $ 0.10 $ 0.01 $ 0.02 $ (0.03) $ (1.19)
Diluted earnings (loss) per share. . . . . . . . . . . . . . . $ 2.20 $ 2.02 $ 1.98 $ 1.85 $ (1.25)
========= ========= ========= ========= =========
Cash dividends declared per share . . . . . . . . . . . . . . . $ 0.88 $ 0.76 $ 0.60 $ 0.55 $ 0.55
Weighted average shares outstanding-basic. . . . . . . . . . . 5,083 4,980 5,592 5,630 5,491
Weighted average equivalent shares outstanding-diluted . . . . 5,254 5,140 5,756 5,789 5,491
FINANCIAL CONDITION AS OF DECEMBER 31
- ------------------------------------------
2004 2003 2002 2001 2000
-------- -------- -------- -------- --------
In thousands
ASSETS
Utility Plant, Net. . . . . . . . . . . $232,712 $228,862 $223,476 $196,858 $194,672
Other Investments . . . . . . . . . . . 18,959 13,706 21,552 20,945 20,730
Current Assets. . . . . . . . . . . . . 35,462 31,688 31,432 36,183 53,652
Deferred Charges. . . . . . . . . . . . 53,731 55,590 60,390 72,468 46,036
Non-Utility Assets. . . . . . . . . . . 755 1,105 995 1,075 1,518
Total Assets. . . . . . . . . . . . . . $341,619 $330,951 $337,845 $327,529 $316,608
======== ======== ======== ======== ========
CAPITALIZATION AND LIABILITIES
Common Stock Equity . . . . . . . . . . $109,581 $ 99,915 $ 91,722 $101,277 $ 92,044
Redeemable Cumulative Preferred Stock . - - 55 12,560 12,795
Long-Term Debt, Less Current Maturities 93,000 93,000 93,000 74,400 72,100
Capital Lease Obligation. . . . . . . . 4,493 4,963 5,287 5,959 6,449
Current Liabilities . . . . . . . . . . 24,468 22,715 38,491 38,841 68,109
Deferred Credits and Other. . . . . . . 107,906 108,281 107,349 92,791 61,794
Non-Utility Liabilities . . . . . . . . 2,171 2,077 1,941 1,701 3,317
Total Capitalization and Liabilities. . $341,619 $330,951 $337,845 $327,529 $316,608
======== ======== ======== ======== ========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS ("MD AND A").
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 substantial, 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 2005 from an annual rate of
$0.88 per share to $1.00 per share. The Company's dividend payout ratio remains
comparatively low, at approximately 48 percent of 2004 earnings from continuing
operations. We expect to grow our dividend payout ratio to the middle of a
payout range of 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 order to attract capital.
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 costs, and to earn its
allowed rate of return. In accordance with the rate plan, the VPSB approved,
and the Company implemented, a 1.9 percent rate increase, effective January 1,
2005.
Power supply expenses were equivalent to approximately 63 percent of total
revenues in 2004. 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 included 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 customer concentration 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.
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
2004 2003 2002
------- ------- -------
Consolidated diluted earnings per share of common stock . . . . . . . . . . . $ 2.20 $ 2.02 $ 1.98
Consolidated diluted earnings per share of common stock-continuing operations $ 2.10 $ 2.01 $ 1.96
Consolidated return on average common equity. . . . . . . . . . . . . . . . . 11.06% 10.76% 11.03%
Earnings from continuing operations improved in 2004 primarily as a result of
increased recognition of revenues previously deferred under a VPSB order
described below, and from growth in retail sales of electricity to large and
small commercial and industrial customers. Higher transmission expenses
partially offset these benefits.
Earnings from discontinued operations totaled $.10 per share in 2004
compared with $.01 per share in the prior year, reflecting diminished exposure
to outstanding litigation against an inactive Northern Water Resources
subsidiary that led to reversal of previously recorded reserves.
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 (generating approximately $4 million in
added annual revenues) effective January 1, 2005, and 0.9 percent (generating
approximately $2 million in added annual revenues) effective January 1, 2006.
The first of these rate increases has been implemented effective January 1,
2005. 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. The 2003 Rate Plan
permitted us to continue to defer and recognize these revenues in 2004. We
recognized approximately $3.0 million of these deferred revenues to achieve our
allowed rate of return during 2004, compared with approximately $1.1 and $4.5
million recognized in 2003 and 2002, respectively.
Retail operating revenues in 2004 increased by $4.5 million or 2.3 percent
compared with 2003, reflecting an improving economy, including a modest growth
in the number of customers served, and increased recognition of revenues
deferred under the 2003 Rate Plan discussed above. Total retail megawatt hour
sales of electricity increased by 1.8 percent in 2004, compared with the same
period in 2003. Megawatt hour sales of electricity to large and small
commercial and industrial customers increased by 3.3 percent and 2.0 percent,
respectively, while sales to residential customers were flat when compared with
2003, reflecting milder and more normal weather conditions in 2004.
Wholesale revenues in 2004 decreased by $56.2 million compared with 2003,
reflecting reduced sales of electricity to Morgan Stanley Capital Group, Inc.,
under a contract designed to manage price risks associated with changing fossil
fuel prices. The reduction in wholesale revenues did not adversely affect
Company earnings in 2004 and is not expected to adversely affect future
operating results.
Power supply expenses in 2004 decreased $53.3 million compared with 2003
due to decreased wholesale sales of electricity, principally those associated
with the Morgan Stanley contract. Power supply expense also decreased due to
reduced expenses to supply an option contract with Hydro Quebec, and an increase
in credits resulting from monthly financial transmission rights ("FTR") auctions
conducted by ISO New England designed to make regions with inadequate
transmission and generation pay a premium for energy delivery.
The Company accounts for its wholly-owned subsidiary, Northern Water
Resources ("NWR"), as a discontinued operation. NWR's assets and liabilities
consist primarily of deferred tax assets and liabilities relating to a number of
investments that the Company has discontinued, deactivated, sold in part or
retained as passive minority interests. Remaining holdings include a minority
equity investment in a wind project that usually, but not always, generates tax
losses; minority interest in a manufacturer of waste treatment equipment; and
some non-performing loans. The Company recognized income of $.10 per share from
Discontinued Operations during 2004, compared with earnings of $.01 in 2003,
primarily reflecting diminished exposure to outstanding litigation that led to
reversal of previously recorded reserves. All of these investments have been
written off except for associated deferred tax amounts, net of applicable
valuation allowances.
In 2003, the Company reported consolidated earnings of $2.02 per share of
common stock, diluted, 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 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 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.
CRITICAL ACCOUNTING POLICIES
Management believes our 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.
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. 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. Costs are
deferred as regulatory assets when the Company concludes that future revenue
will be provided to permit recovery of the previously incurred cost. The
Company analyzes evidence supporting deferral, including provisions for recovery
in regulatory orders, past regulatory precedent, other regulatory correspondence
and legal representations. 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 some other 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 its regulatory assets, net of
regulatory liabilities as set forth in the table below:
REGULATORY ASSETS AND LIABILITIES
At December 31,
2004 2003
--------------- -------
Regulatory assets: (in thousands)
Demand-side management programs . . . . . . . . $ 7,293 $ 6,713
Purchased power costs . . . . . . . . . . . . . 2,322 2,574
Pine Street barge canal . . . . . . . . . . . . 13,250 12,954
Net power supply deferral . . . . . . . . . . . 12,085 19,734
Other regulatory assets . . . . . . . . . . . . 6,932 8,439
--------------- -------
Total regulatory assets . . . . . . . . . . . . 41,882 50,414
--------------- -------
Regulatory liabilities:
Rate levelization liability . . . . . . . . . . - 2,970
Accumulated cost of removal . . . . . . . . . . 19,806 21,238
Other regulatory liabilities. . . . . . . . . . 4,012 2,643
--------------- -------
Total regulatory liabilities. . . . . . . . . . 23,818 26,851
--------------- -------
Regulatory assets net of regulatory liabilities $ 18,064 $23,563
=============== =======
The 2003 Rate Plan, approved by the VPSB in December 2003, provides for
amortization and recovery of nearly 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.
The net power supply deferral represents the net value of certain power
supply contracts that must be marked to fair value as derivatives under current
accounting rules. The Company records contract specified prices for electricity
as expense in the period used, as opposed to fair market values reflected in the
above table, in accordance with accounting required by a VPSB order. The power
supply contract expenses are fully recovered in the rates we charge, and are
discussed in detail under Power Supply Derivatives.
Regulatory assets represent incurred costs that have been deferred because
the Company has concluded that they are probable of future recovery in customer
rates. Management's conclusions represent a critical accounting estimate.
Regulatory liabilities generally represent obligations to reduce future rates.
Our 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 and net of estimates
of electricity lost during transmission, in order to match revenues with related
costs.
The Company's defined benefit plan cost can vary significantly based on
plan assumptions and results including the following factors: interest rates,
healthcare cost trends, return on assets and compensation cost trends.
Management also exercises judgments about the expected outcome of
litigation for contingencies. If the Company determines that it is probable
that it will sustain a loss associated with pending litigation, regulatory
proceedings or tax matters, and if it can estimate the likely amount of such
loss, it will record a liability for that amount.
Our critical accounting policies are discussed further 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," in Note H, "Pension and Retirement Plans" and in Note I,
"Commitments and Contingencies."
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,
benefit plan cost sensitivity to interest rates and healthcare cost inflation
and weather. Discussion of these and other risks, as well as factors
contributing to mitigation of these risks, follows.
POWER SUPPLY RISKS.
POWER CONTRACT COMMITMENTS - 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 ("VYNPC") Contract
(the "VYNPC Contract"), which together supply approximately 75 percent of our
retail load. The Company has also entered into a contract with Morgan Stanley
Capital Group, Inc. (the "Morgan Stanley Contract") designed to manage wholesale
electricity price risks associated with changing fossil fuel prices. The Morgan
Stanley Contract supplies an additional 16 percent of our load and expires
December 31, 2006. The VJO and VYNPC contracts are summarized in the following
table.
2004 2004 2003 2003 Contract
MWh $/MWh MWh $/MWh Expires
------- ------ ------- ------ -------
VJO Contract. . . . . . 605,718 $74.47 664,225 $69.81 2015
Vermont Yankee Contract 764,010 $43.63 884,585 $43.08 2012
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.
On July 31, 2002, VYNPC completed the sale of its nuclear power plant to
Entergy Nuclear Vermont Yankee LLC ("ENVY"). As part of the sale transaction,
VYNPC entered into a Power Purchase Agreement ("PPA") with ENVY under 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 generally range from $39 to $45 per MWh. 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. We no longer bear the operating costs and risks
associated with running and decommissioning the plant. If market prices rise,
however, PPA prices are not adjusted upward in excess of the contract price.
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.
In addition to the VJO and VYNPC contracts, the Company entered into the
Morgan Stanley Contract in 1999. In August 2002, the Morgan Stanley Contract
was modified and extended to December 31, 2006. The Morgan Stanley Contract
price is substantially below current market prices. The Morgan Stanley Contract
currently supplies approximately 16 percent of the Company's estimated customer
demand ("load").
Under the Morgan Stanley Contract, on a daily basis, and at Morgan
Stanley's discretion, we sell power to Morgan Stanley from part of our portfolio
of power resources at pre-defined operating and pricing parameters. Morgan
Stanley sells to the Company, at a pre-defined price, power sufficient to serve
pre-established load requirements. We remain responsible for resource
performance and availability. The Morgan Stanley Contract provides no coverage
against major unscheduled power supply outages. Beginning January 1, 2004, the
Company reduced the power that it sells pursuant to the Morgan Stanley Contract.
The output of some of our power-supply resources, including purchases pursuant
to our Hydro Quebec and VYNPC contracts, which were sold to Morgan Stanley
through 2003, are no longer included in the Morgan Stanley Contract. This
reduction in sales to Morgan Stanley reduced wholesale revenues by approximately
$56.2 million during 2004 when compared with 2003, and correspondingly reduced
power supply expense by a similar amount. This change did not adversely affect
the Company's operating results or its opportunity to earn its allowed rate of
return during 2004.
In 1996, the Company entered into an agreement with Hydro Quebec ("the 9701
agreement") under which Hydro Quebec paid $8.0 million to the Company in 1997
and we provided Hydro Quebec options for the purchase of power in specified
maximum amounts through 2015, as discussed below under "Power Supply Risk."
POWER SUPPLY PRICE RISK - All of the Company's power supply contract costs are
currently being recovered through rates approved by the VPSB. The Company
records the annual cost of power obtained under long-term contracts as operating
expenses. The Company meets the majority of its customer demand through a
series of long-term physical and financial contracts. There are occasions when
the available supply of electricity is insufficient to meet customer demand.
During those periods, electricity is purchased at market prices.
We expect approximately 90 percent of our estimated load requirements
through 2006 to be met by our contracts and generation and other power supply
resources. These contracts and resources significantly reduce the Company's
exposure to volatility in wholesale energy market prices.
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 from or sell the difference into a marketplace that has
experienced volatile energy prices. Market price trends also may make it more
difficult to extend or enter into new power supply contracts at prices that
avoid the need for rate relief. Vermont does not have an automatic fuel
adjustment clause or similar mechanism to adjust rates for higher energy costs
without prior regulatory approval.
The Company has established a risk management program designed to mitigate
some of the potential adverse cash flow and income statement effects caused by
power supply risks, including credit risks associated with counterparties.
Transactions permitted by the risk management program include futures, forward
contracts, option contracts, swaps and the sale or purchase of 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, ENVY and Morgan Stanley, all
currently have investment grade credit ratings.
POWER SUPPLY DERIVATIVES.
The Morgan Stanley Contract is used to hedge our power supply costs against
increases in fossil fuel prices. The Morgan Stanley Contract is a derivative
under Statement of Financial Accounting Standards No. 133 ("SFAS 133").
Management has estimated the fair value of the future net benefit of this
agreement at December 31, 2004 to be approximately $10.7 million.
The Company is unable to predict the price, contract duration or terms of
any future power supply contract that could replace the Morgan Stanley Contract
after it expires on December 31, 2006.
The Company's 9701 agreement with Hydro Quebec grants Hydro Quebec an
option to call power at prices that are now expected to be below estimated
future wholesale market prices. 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.
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, 2004, Hydro Quebec had purchased 566,000
MWh under option B. The Company expects Hydro Quebec to call its remaining
entitlements of approximately 34,000 MWh under option B during 2005.
Hydro Quebec exercised options A and B for 2004, and the Company 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. 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. The 9701 agreement is a derivative and is effective
through 2015. Management's estimate of the fair value of the future net cost
for this agreement at December 31, 2004 is approximately $22.8 million. We
sometimes use forward contracts to hedge forecasted calls by Hydro Quebec under
the 9701 agreement and treat such contracts as derivatives under SFAS 133.
The table below presents assumptions used to estimate the fair value of the
Morgan Stanley Contract and the 9701 agreement. 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 2.0% 32%-29% $ 62 2006
9701 Arrangement. . . . Black-Scholes 4.3% 46%-27% $ 66 2015
The table below presents the Company's estimated 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 $1.5 million. Actual results may differ materially
from the table illustration.
Commodity Price Risk December 31, 2004
Fair Value(Cost) Market Risk
----------------- -------------
(in thousands)
Morgan Stanley Contract $ 10,736 $ 1,953
9701 agreement. . . . . (22,821) (3,487)
----------------- -------------
$ (12,085) $ (1,534)
Under an accounting order issued by the VPSB, changes in the fair value of
derivatives are deferred. If a derivative instrument were terminated early
because it is probable that a transaction or forecasted transaction will not
occur, any gain or loss would be recognized in earnings immediately. For
derivatives held to maturity, the earnings impact is recorded in the period that
the derivative is sold or matures.
OTHER POWER SUPPLY RISK.
Under the VJO Contract, Hydro Quebec has the right to reduce the load
factor from 75 percent to 65 percent a total of three times over the life of the
contract. Hydro Quebec exercised the first of these load reduction options,
effective for the year 2003. 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 increased power supply expense in 2004 by approximately $1.8 million.
Hydro Quebec exercised its third and final option in 2004 to reduce deliveries
occurring principally during 2005, resulting in an estimated cost of replacement
power of $1.8 million, based on current wholesale market prices for 2005. It is
possible our estimate of future power supply costs could differ materially from
actual results. The Vermont Joint Owners, including the Company, retain two
options to increase the load factor to 80 percent from 75 percent after 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.
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 energy costs.
Our VJO contract contains 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.
In accordance with guidance set forth in FASB Interpretation No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others ("FIN 45"), the Company is
required to disclose the "maximum potential amount of future payments
(undiscounted) the guarantor could be required to make under the guarantee."
Such disclosure is required even if the likelihood of triggering the guarantee
is remote. In regards to the "step-up" provision in the VJO Contract, the
Company must assume that all members of the VJO simultaneously default in order
to estimate the "maximum potential" amount of future payments. The Company
believes this is a highly unlikely scenario given that the majority of VJO
members are regulated utilities with regulated cost recovery. Each VJO
participant has received regulatory approval to recover the cost of this
purchased power. Despite the remote chance that such an event could occur, the
Company estimates that its undiscounted purchase obligation would be
approximately $880 million for the remainder of the contract, assuming that all
members of the VJO defaulted by January 1, 2005 and remained in default for the
duration of the contract. In such a scenario, the Company would then own the
power and could seek to recover its costs from the defaulting members, its
retail customers, and/or resell the power in the wholesale power markets in New
England. The range of outcomes (full cost recovery, potential loss or potential
profit) would be highly dependent on Vermont regulation and wholesale market
prices at the time.
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. During 2003, another unscheduled outage resulted in
the Company's deferral of approximately $500,000 of added power supply costs.
While the Vermont Yankee plant has had an excellent operating record, future
unscheduled outages could occur at times when replacement energy costs are above
VYNPC Contract costs. Historically, the VPSB has allowed the Company to defer,
rather than expense, the higher costs resulting from extraordinary outages at
the plant. Since the Company no longer owns an interest in the Vermont Yankee
nuclear plant, we are not responsible for any fixed costs at the plant, the
costs of decommissioning the plant, nor are we responsible for any plant repairs
or maintenance costs during outages.
On June 18, 2004, a fire in the electrical conduits leading to a
transformer outside the plant resulted in a shutdown of the ENVY plant. The
outage ended on July 7, 2004. In response to the Company's request, the VPSB
issued a final accounting order allowing the Company to defer its incremental
replacement power costs during the outage totaling approximately $500,000. The
order also instructs the Company to apply any proceeds received under a
Ratepayer Protection Plan ("RPP") to reduce the balance of deferred replacement
power costs. ENVY disputes that the fire was uprate-related. The Company has
petitioned the VPSB to resolve the dispute.
The RPP was a part of ENVY's request to uprate or increase the output of
the VY nuclear plant that was approved by the VPSB. Under the RPP, we have
indemnification rights to between approximately $550,000 and $1.6 million to
recover uprate-related reductions in output for the three-year period beginning
in May 2004 and ending after completion of the uprate (or a maximum of three
years), depending on future wholesale energy market prices.
ENVY has announced that, under current operating parameters, it will
exhaust the capacity of its existing nuclear waste storage pool in 2007 or 2008
and will need to store nuclear waste in so-called "dry fuel storage" facilities
to be constructed on the site. Current Vermont law appears to require ENVY to
obtain approval of the Vermont State legislature, in addition to VPSB approval,
to construct and use such dry fuel storage facilities. If ENVY is unsuccessful
in receiving favorable legislative action and/or regulatory approval, ENVY has
announced that it could be required to shut down the VY plant between 2007 and
2008. If the VY plant is shut down in 2007 or 2008, we would have to acquire
substitute baseload power resources, comprising approximately 35 percent of our
load. At currently projected market prices, we estimate the annual incremental
cost (in excess of the projected costs of power under our power supply contract
for output from the VY facility) would be approximately $9 million per year.
Recovery of those increased costs in rates would require a rate increase of
approximately 5 percent.
In April 2004, ENVY reported that two short spent fuel rod segments were
not in what ENVY believed to be their documented location in the spent fuel
pool. After initial review and visual inspection of the spent fuel pool, ENVY
did not locate the fuel rod segments. By letter dated May 5, 2004, ENVY
notified VYNPC that based on the terms of the Purchase and Sale Agreement dated
August 1, 2001, and facts at that time, it was ENVY's view that costs associated
with the spent fuel rod segment inspection effort were the responsibility of
VYNPC. VYNPC responded that based on the information at that time, there was no
basis for ENVY to claim the inspection was VYNPC's responsibility.
Subsequently, ENVY discovered the fuel rod segments in a container in the spent
fuel pool. We cannot predict the outcome of this matter at this time.
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. "SFAS 71" 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.
The Company has recognized revenues deferred under previous regulatory
orders to help it earn its allowed rate of return (see "Earnings Summary"). The
Company's ability consistently to achieve its allowed rate of return is likely
to be more uncertain prospectively due to the absence of available deferred
revenues, unless it secures appropriate and adequate rate increases to cover its
costs of operation.
The Company invests in its utility infrastructure to serve its customers.
Obtaining a return on that investment is a component in a rate increase
proceeding that typically lasts for a period of approximately eight and one-half
months. Uncertainty regarding the outcome of rate proceedings contributes to
the risk that we will not achieve our allowed rate of return in any given year.
Regulatory risk is also affected by the amount of rate relief that the
Company needs to achieve its allowed rate of return. Since 2001, the Company
has not needed any substantial rate relief. In August 2002 we extended