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 our
Morgan Stanley Contract before wholesale market power supply prices increased
and we have been able to pass those benefits along to our customers. Our retail
revenue needs through 2006 are covered by our 2003 Rate Plan. The current
Morgan Stanley Contract expires on December 31, 2006. We estimate that we will
need a rate increase of approximately 5 to 6 percent effective January 1, 2007,
driven primarily by replacement power costs for our Morgan Stanley Contract (if
the Morgan Stanley Contract was replaced at current market prices), and higher
projected transmission expenses.
Central Vermont Public Service Corporation ("CVPS") is currently subject to
a rate investigation by the VPSB. In that case, the DPS has advocated positions
that, if adopted by the VPSB and applied to the Company, could adversely affect
our cash flows and operating results. Areas of risk include:
* The Department's advocacy for an earnings cap calculation that would
potentially subject all items on the balance sheet and income statement to a
retroactive review in order to determine whether the Company has met or exceeded
the earnings cap. Our 2003 Rate Plan provides that the Company operate under an
earnings cap through 2006. The Company calculates its earnings under the cap in
a manner that differs from the methodology advocated by the DPS in the CVPS rate
proceeding.
* DPS advocacy for elimination or reduction of costs of future removal that
are currently embedded in depreciation rates and reflected in our cash flows.
The methodology we currently employ is consistent with that used in most other
regulatory jurisdictions.
* DPS advocacy for reduced rates of return on equity for CVPS.
The Company currently complies with the provisions of SFAS 71. If we had
determined that the Company no longer met the criteria for following SFAS 71, at
December 31, 2004, the Company would write-off its regulatory assets, net of
regulatory liabilities (see above discussion "Critical Accounting Policies").
Factors that could give rise to the discontinuance of SFAS 71 include:
deregulation;
a change in the regulators' approach to setting rates from cost-based
regulation to another form of regulation;
competition that limited our ability to sell utility services or products
at rates that will recover costs; or
regulatory actions that limit rate relief to a level insufficient to recover
costs.
There are currently no regulatory proceedings, court actions or pending
legislative proposals to adopt electric industry restructuring in Vermont. The
largest category of costs that could be subject to the risk of non-recovery in
rates in the event of electric utility restructuring in Vermont ("stranded
costs") are those relating to our future costs under long-term power purchase
contracts, which, based on current forecasts, are above market. The magnitude
of our stranded costs is largely dependent upon the future wholesale market
price of power. We have discussed various market price scenarios with
interested parties for the purpose of identifying stranded costs. Based on
preliminary market price assumptions, which are likely to change, we estimate
the Company's stranded costs to be between $56 million and $96 million over the
life of the Company's current contracts.
If Vermont adopted retail competition or some other form of electric
industry restructuring or if the VPSB issued a regulatory order containing
provisions that did not allow the Company to recover above-market power costs,
the Company could be required to estimate and record losses immediately, on an
undiscounted basis, for any above-market power purchase contracts and other
costs which are probable of not being recoverable from customers, to the extent
that those costs can be estimated.
CUSTOMER CONCENTRATION RISK - IBM, the Company's largest customer, operates a
manufacturing facility in Essex Junction, Vermont. IBM's electricity
requirements for its facility accounted for approximately 24.1, 24.1 and 25.7
percent of the Company's retail MWh sales in 2004, 2003 and 2002, respectively,
and 16.4, 16.6 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 one percent of the Company's revenue in any year.
Since 1995, the Company has had agreements with IBM with respect to
electricity sales above agreed-upon base-load levels. On December 22, 2003, the
VPSB approved a new three-year agreement between the Company and IBM, ending
December 31, 2006. The price of power under the agreement is above our marginal
costs of providing incremental service to IBM.
IBM has reduced its Vermont workforce by approximately 2,500 since 2001, to
a level of approximately 6,000 employees. Company revenue from sales of
electricity to IBM increased by approximately $350,000 in 2004 compared with
2003. Company revenue from sales of electricity to IBM declined $1.8 million in
2003 compared with 2002. Our operating results were not adversely impacted by
the reduction in sales to IBM due to continued revenue growth in other customer
classes and because the gross margin on sales to IBM is relatively low. If we
experienced a material reduction in earnings as a result of significantly lower
retail sales, we would seek a retail rate increase from the VPSB. The Company
is permitted to seek such a rate increase request under our approved 2003 Rate
Plan. We are not aware of any plans by IBM to further reduce production at its
Vermont facility. We currently estimate, based on a number of projected
variables, that a hypothetical shutdown of the IBM facility would necessitate a
retail rate increase for all our remaining customers of approximately five
percent.
PENSION AND POSTRETIREMENT HEALTH CARE RISK - Other critical accounting policies
involve the Company's defined benefit pension and postretirement health care
benefit plans. The reported costs of these plans depend upon numerous factors
relating to actual plan experience and assumptions of future experience.
Pension and postretirement health care costs are affected by actual
employee demographics, Company contributions to the plans, earnings on plan
assets and, for our postretirement health care plan, health care cost trends.
The Company contributed approximately $2.2 million and $3.5 million to its
defined benefit plans during 2004 and 2003, respectively, and we expect to
contribute between $2.0 and $3.0 million during 2005.
Our pension and postretirement health care benefit plan assets consist of
equity and fixed income investments. Fluctuations in actual equity market
returns, as well as changes in general interest rates, may increase or decrease
costs in future periods. Changes in assumptions regarding current discount
rates and expected rates of return on plan assets could also increase or
decrease recorded defined benefit plan costs.
On December 17, 2003, the Company's employees ratified a four-year labor
agreement that provides annual wage increases of between 3.5 and 4 percent and
improved 401(k) and pension benefits for employees. The new labor agreement
caps future postretirement healthcare employee benefits provided by the Company
for the majority of the present workforce. The cap on postretirement healthcare
benefits is set approximately 13 percent above 2003 costs and grows at a 3
percent annual rate. This cap should reduce the rate at which postretirement
healthcare expenses grow in the future.
As a result of our plan asset experience, at December 31, 2002, the Company
was required to recognize an additional minimum liability of $2.4 million, net
of applicable income taxes. The liability was recorded as a reduction to common
equity through a charge to Other Comprehensive Income ("OCI"). Favorable
pension plan investment returns during 2003 reduced the OCI charge and related
net liability by $587,000. In 2004, a reduction in the pension plan's discount
rate was primarily responsible for increasing the OCI charge and related net
liability by approximately $566,000. The 2002 and 2004 OCI charge and the 2003
OCI benefit had no effect on net income.
WEATHER - The Company now uses weather insurance to mitigate some of the risk of
lost electricity sales caused by unfavorable weather conditions. The Company
has purchased weather insurance coverage for 2005. Coverage is based on
cumulative variations from normal weather, measured in net heating and cooling
degree-days.
RESULTS OF OPERATIONS
OPERATING REVENUES AND MWH SALES - Operating revenues, megawatt hour ("MWh")
sales and number of customers for the years ended 2004, 2003 and 2002 were as
follows:
Years ended December 31,
2004 2003 2002
------------------------- ---------- ----------
(dollars in thousands)
Operating Revenues
Retail* . . . . . . . $ 203,218 $ 198,717 $ 201,052
Sales for Resale. . . 22,652 78,901 70,646
Other . . . . . . . . 2,946 2,852 2,910
------------------------- ---------- ----------
Total Operating Revenues. $ 228,816 $ 280,470 $ 274,608
========================= ========== ==========
MWH Sales-Retail. . . . . 1,969,925 1,934,340 1,948,190
MWH Sales for Resale. . . 411,769 2,287,039 2,107,941
------------------------- ---------- ----------
Total MWH Sales . . . . . 2,381,694 4,221,379 4,056,131
========================= ========== ==========
*Retail revenues include $3.0 million, $1.1 million and $4.5 million of deferred
revenue recognized for 2004, 2003, and 2002, respectively.
Comparative changes in operating revenues are summarized below:
Average Number of Customers
Years ended December 31,
2004 2003 2002
------ ------ ------
Residential . . . . . . . 75,507 74,693 73,861
Commercial and Industrial 13,539 13,369 13,194
Other . . . . . . . . . . 62 65 65
------ ------ ------
Total Number of Customers. . 89,108 88,127 87,120
====== ====== ======
Change in Operating Revenues 2003 to 2002 to 2001 to
2004 2003 2002
--------------- -------- ---------
(In thousands)
Retail Rates. . . . . . . . . . . . . . . $ 830 $ (912) $ 6,471
Retail Sales Volume . . . . . . . . . . . 3,671 (1,423) (512)
Resales and Other Revenues. . . . . . . . (56,155) 8,197 (14,815)
--------------- -------- ---------
Increase (Decrease) in Operating Revenues $ (51,654) $ 5,862 $ (8,856)
=============== ======== =========
Nearly all of the Company's earnings from continuing operations are typically
generated by retail sales of electricity. In 2004, retail revenues increased
$4.5 million or 2.3 percent compared with 2003, due to
An increase of $1.9 million in recognition of revenues deferred under the
2003 Rate Plan;
A 3.3 percent increase in megawatt hour sales to large commercial and
industrial customers resulting in a $1.4 million increase in revenue; and
A 2.0 percent increase in megawatt hour sales to small commercial and
industrial customers resulting in a $1.0 million increase in revenue.
Residential retail revenues and megawatt hour sales of electricity were up
only 0.1 percent in 2004, compared with 2003. We experienced residential
customer growth in 2004, but 2004 weather conditions were less favorable for
electricity sales than 2003.
Wholesale revenues decreased in 2004 by $56.2 million, or 71.3 percent,
compared with 2003, reflecting reduced sales of electricity under the Morgan
Stanley Contract. The reduction in sales under the Morgan Stanley Contract did
not adversely affect the Company's earnings in 2004 and is not expected to
adversely affect the Company's earnings in future years.
In 2003, total electricity sales increased 4.1 percent compared with 2002,
due to increased wholesale sales and sales to residential and small commercial
and industrial customers, partially offset by decreased sales to large
commercial and industrial customers. Total operating revenues increased $5.9
million, or 2.1 percent, compared with 2002 as a result of the following:
Increased wholesale revenues of $8.3 million, primarily due to increased
system sales during peak demand periods and increased sales to Hydro Quebec
under the 9701 agreement;
Increased retail residential revenues of $3.2 million, or 4.5 percent,
arising from increased sales of electricity; and
Increased retail small commercial and industrial ("C&I") revenues of
$900,000, or 1.3 percent, arising from increased sales of electricity.
These increases were partially offset for the following reasons:
The Company recognized $1.1 million in deferred revenues under the 2001
Settlement Order, reduced from $4.5 million recognized in 2002; and
Decreased retail large C&I revenues of $2.6 million, or 1.7 percent, when
compared with 2002, resulting from a decline in sales of electricity to this
customer class.
POWER SUPPLY EXPENSES - Power supply expenses constituted 67.5, 74.4 and 74.5
percent of total operating expenses for the years 2004, 2003 and 2002,
respectively. The decreased 2004 percentage reflects reduced purchases and
sales of electricity under the Morgan Stanley Contract.
Power supply expenses decreased by $53.3 million or 27.0 percent in 2004
when compared with 2003, and resulted from the following:
An estimated $56.2 million decrease in the cost of power purchased for
resale resulting primarily from the restructuring of the Morgan Stanley Contract
described above;
A $1.8 million increase in credits from the ISO New England ("ISO-NE")
resulting from FTR auctions designed to make congested regions pay a premium for
energy delivery, and credits for certain Company generation; and
A $1.3 million decrease in the net cost of our 9701 agreement with Hydro
Quebec.
These decreases were partially offset by increased power supply expenses
from the following:
A $1.9 million increase in purchases to supply increased retail sales;
An estimated $1.5 million in purchases to replace reduced energy deliveries
under the VJO Contract as a result of problems with the transmission
interconnection facilities over which we schedule deliveries; and
An $851,000 increase in the contract price per megawatt hour of electricity
purchased under the Morgan Stanley Contract.
Power supply expenses increased by $3.9 million, or 2.0 percent, in 2003
when compared with 2002, and resulted from the following:
An $8.3 million increase in the cost of power purchased for resale;
A $2.7 million increase in power supply expenses under agreements with
Hydro Quebec;
Higher costs of electricity supplied by independent power producers; and
Higher wholesale prices for electricity.
These increases were partially offset by an $8.9 million decrease in the
cost of power under our contract with Morgan Stanley and lower unit prices from
Vermont Yankee.
OTHER OPERATING EXPENSES - Other operating expenses in 2004 were essentially
unchanged from the prior year.
Other operating expenses increased $3.7 million, or 26.6 percent, in 2003
compared with 2002 primarily due to increased employee benefit expenses and
expenses related to corporate governance.
TRANSMISSION EXPENSES - Transmission expenses increased $873,000, or 5.9
percent, in 2004 compared with 2003, due to increased charges allocated by
ISO-NE for system support in the greater Boston area and expensed engineering
studies related to substation and transmission design evaluations. The
Company's relative share of transmission expenses varies with the peak demand
recorded on Vermont's transmission system. The Company's share of those
expenses increased due to its increased load growth, relative to other Vermont
utilities, and also because of increased transmission investment by VELCO.
In 2004, we experienced an increase of approximately $750,000 in
transmission expense resulting from system-wide allocation of costs associated
with voltage control and reactive power ("VAR") in the greater Boston area. We
expect this increased transmission expense to continue in 2005. The Company and
other affected load serving entities have requested ISO-NE to modify the
applicable market rules to allocate VAR-related costs to the reliability regions
responsible for the applicable VAR-related costs.
Transmission expenses decreased $438,000, or 2.9 percent, in 2003 compared
with 2002, due to decreased congestion costs allocated by ISO-NE to Vermont
utilities in conjunction with transition to a new standard market design
("SMD"). See discussion below.
ISO-NE was created to manage the operations of the New England Power Pool
("NEPOOL"), effective May 1, 1999. ISO-NE operates a market for all New England
states for purchasers and sellers of electricity in the deregulated wholesale
energy markets. Sellers place bids for the sale of their generation or
purchased power resources and if demand is high enough the output from those
resources is sold.
ISO-NE implemented its Standard Market Design ("SMD") plan governing
wholesale energy sales in New England 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 could eventually be determined on a more localized ("nodal")
basis. In December 2004, FERC reaffirmed the zone pricing system for New
England's SMD, subject to FERC's periodic re-analysis of alternative load zones,
based on changes in system conditions. We believe that nodal pricing could
result in a material adverse impact on our power supply and/or transmission
costs, if adopted.
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. Commencing with implementation of the RTO,
costs associated with certain transmission facilities, known as the Highgate
Facilities, of which the Company is a part owner, will be phased into
region-wide rates over a 5-year period. When fully phased in, we estimate that
this "roll-in" of the Highgate facilities will achieve approximately $1.4
million in annual transmission costs savings for the Company.
VELCO, the owner and operator of Vermont's principal electric transmission
system assets, has proposed a project to substantially upgrade Vermont's
transmission system (the "Northwest Reliability Project"), principally to
support reliability and eliminate transmission constraints in northwestern
Vermont, including most of the Company's service territory. We own
approximately 29 percent of VELCO. In January 2005, the project received
regulatory approval from the VPSB. The project is estimated to cost
approximately $150 million through 2007. VELCO intends to finance the costs of
constructing the Northwest Reliability Project in part through increased equity
investment. In October 2004, the Company invested $4.6 million in VELCO to
support this project and other transmission projects. The Company plans to
invest at least $15 million additionally in VELCO through 2007 for the same
purpose. Under current NEPOOL and ISO-NE rules, which require qualifying large
transmission project costs to be shared among all New England utilities,
approximately 95 percent of the pool transmission facility costs of the
Northwest Reliability Project will be allocated throughout the New England
region, with Vermont utilities responsible for approximately 5 percent of
allocated costs. Vermont utilities are required to pay 5 percent of pool
transmission facility upgrades in other New England states.
MAINTENANCE EXPENSES - Maintenance expenses increased $25,000, or 0.2 percent,
in 2004 compared with 2003 due to increased expenditures on right-of-way
maintenance programs offset by decreased expenditures related to gas turbine
maintenance.
Maintenance expenses decreased $151,000, or 1.5 percent, in 2003 compared
with 2002, due to decreased expenditures related to maintenance of our Searsburg
wind generation facility.
DEPRECIATION AND AMORTIZATION - Depreciation and amortization expense increased
$129,000, or 0.9 percent, in 2004 compared with 2003 due to increases in
depreciation of utility plant in service partially offset by decreased
amortization of software costs.
Depreciation and amortization expense decreased $348,000, or 2.5 percent,
in 2003 compared with 2002 due to reductions in amortization of conservation and
software programs, partially offset by increased depreciation of utility plant
in service.
TAXES OTHER THAN INCOME - Taxes other than income taxes decreased $210,000, or
3.0 percent, in 2004 compared with 2003 due to decreased property tax expense.
Taxes other than income taxes decreased $45,000, or 0.6 percent, in 2003
compared with 2002 for the same reason.
INCOME TAXES - Income tax expense increased $642,000, or 12.5 percent, primarily
due to an increase in pre-tax income in 2004 compared with 2003.
Income tax expense decreased $923,000, or 15.2 percent, in 2003 compared
with 2002 due to a decrease in the Company's pre-tax income, an increase in
non-taxable income and the use of tax credits.
OTHER INCOME AND DEDUCTIONS - Other income and deductions increased $8,000 in
2004 compared with 2003 due primarily to sales of non-utility property offset by
reduced earnings on investment in Vermont Yankee.
Other income decreased $406,000, or 16.3 percent, in 2003 compared with
2002 due primarily to VYNPC recognition of deferred tax assets arising in
conjunction with the sale of the Vermont Yankee plant and reduced earnings on
investment in VYNPC as a result of the sale of the Vermont Yankee plant in 2002.
INTEREST EXPENSE - Interest expense decreased $551,000, or 7.8 percent, in 2004
compared with 2003 primarily due to scheduled redemptions of long-term debt in
December 2003.
Interest expense increased $887,000, or 14.4 percent, in 2003 compared with
2002 primarily due to a $42 million long-term debt issuance in December 2002.
ENVIRONMENTAL MATTERS
----------------------
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air and
aesthetic requirements as administered by local, state and federal regulatory
agencies. We believe that we are in substantial compliance with these
requirements, and that there are no outstanding material complaints about our
compliance with present environmental protection regulations.
The Company joined the Chicago Climate Exchange ("CCX"), a self-regulatory
exchange that administers a market for reducing and trading greenhouse gas
emission credits. We are the first utility in the northeast to join the CCX,
and have committed voluntarily to reduce our emissions by 4 percent below our
1998 - 2001 baseline average by 2006, either directly or by purchasing credits.
PINE STREET BARGE CANAL SUPERFUND SITE - In 1999, the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the United States Environmental Protection Agency ("EPA"), the State of Vermont
and numerous other parties of claims relating to a federal Superfund site in
Burlington, Vermont, known as the "Pine Street Barge Canal." The consent decree
resolves claims by the EPA for past site costs, natural resource damage claims
and claims for past and future remediation costs. The consent decree also
provides for the design and implementation of response actions at the site. In
2004 and 2003, the Company expended $1.5 and $2.6 million, respectively, to
cover its obligations under the consent decree and we have estimated total
future costs of the Company's future obligations under the consent decree to be
$6.5 million. The estimated liability is not discounted, and it is possible
that our estimate of future costs could change by a material amount. We have
recorded a regulatory asset of $13.3 million to reflect unrecovered past and
future Pine Street costs. Pursuant to the Company's 2003 Rate Plan, as approved
by the VPSB, the Company will begin to amortize past unrecovered costs in 2005.
The Company will amortize the full amount of incurred costs over 20 years
without a return. The amortization will be allowed in future rates, without
disallowance or adjustment, until fully amortized.
RATES
-----
RETAIL RATE CASES - On December 22, 2003, the VPSB approved our 2003 Rate Plan,
jointly proposed by the Company and the DPS. The 2003 Rate Plan covers the
period from 2003 through 2006 and includes the following principal elements:
The Company's rates remained unchanged through 2004. The 2003 Rate Plan
allows the Company to raise rates 1.9 percent, effective January 1, 2005, and an
additional 0.9 percent, effective January 1, 2006, if the increases are
supported by cost of service schedules submitted 60 days prior to the effective
dates. We submitted a cost of service schedule supporting the 1.9 percent rate
increase for 2005 in accordance with the plan. The increase became effective on
January 1, 2005 in accordance with the plan. If the Company's cost of service
filing in 2006 established that a rate increase of less than 0.9 percent is
required for the Company to meet its revenue requirements, the Company would
implement the lesser rate increase. The VPSB retains the discretion to open an
investigation of the Company's rates at any time, at the request of the DPS, the
request of ratepayers, or on its own volition. Certain ratepayers requested the
VPSB to open such an investigation in connection with the Company's 1.9 percent
rate increase for 2005. The VPSB granted the request in December 2004, and
then, at our request, closed and terminated its investigation in January 2005,
with no adverse impact on the Company's rates.
The Company may seek additional rate increases in extraordinary
circumstances, such as severe storm repair costs, natural disasters, extended
unanticipated unit outages, or significant losses of customer load.
The Company's allowed return on equity is 10.5 percent for the period
January 1, 2003 through December 31, 2006. During the same period, the
Company's earnings on core utility operations are capped at 10.5 percent. The
Company did not experience excess earnings in 2004. Excess earnings in 2005 or
2006 will be refunded to customers as a credit on customer bills or applied to
reduce regulatory assets, as the Department directs.
The Company carried forward into 2004 $3.0 million in deferred revenue
remaining at December 31, 2003, from the Company's 2001 Settlement Order
(summarized below). These revenues were applied in 2004 to offset increased
costs.
The Company will amortize (recover) certain regulatory assets, including
Pine Street Barge Canal environmental site costs and past demand-side management
program costs, beginning in January 2005, with those amortizations to be allowed
in future rates. Pine Street costs will be recovered over a twenty-year period
without a return.
The Company filed with the VPSB in 2004 a new fully-allocated cost of
service study and rate re-design, which allocates the Company's revenue
requirement among all customer classes on the basis of current costs. The new
rate design is subject to VPSB approval and is not expected to adversely affect
operating results.
The Company and the Department have agreed to work cooperatively to develop
and propose an alternative regulation plan as authorized by legislation enacted
in Vermont in 2003. If the Company and Department agree on such a plan, and it
is approved by the VPSB, the alternative regulation plan would supersede the
2003 Rate Plan.
In January 2001, the VPSB issued the 2001 Settlement Order, which included
the following:
The Company received a rate increase of 3.42 percent above existing rates
and prior temporary rate increases became permanent;
Rates were set at levels that recover the Company's VJO Contract costs,
effectively ending the regulatory disallowances experienced by the Company from
1998 through 2000;
Seasonal rates were eliminated in April 2001, which generated approximately
$8.5 million in additional cash flow in 2001, which was deferred and available
to be used to offset increased costs during 2002 and 2003; and
The Company agreed to an earnings cap on core utility operations of 11.25
percent return on equity, with amounts earned over the limit being used to write
off regulatory assets.
The 2001 Settlement Order also imposed two additional conditions:
The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to an $8.0 million limit on the customers' share, adjusted for inflation;
and
The Company's further investment in non-utility operations was restricted
until new rates went into effect, which occurred in January 2005. Although this
restriction has expired, we have no plans to make material investments in
non-utility operations.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------
Our cash, net working capital and net operating cash flows are as follows:
At December 31,
2004 2003
------- -------
(In thousands)
Cash and cash equivalents. . . . . . . . . $ 1,720 $ 786
------- -------
Current assets . . . . . . . . . . . . . . $35,462 $31,688
Less current liabilities . . . . . . . . . 24,468 22,715
------- -------
Net working capital. . . . . . . . . . . . $10,994 $ 8,973
Net cash provided by operating activities. $26,162 $21,070
We expect most of our construction expenditures and dividends to be financed by
net cash provided by operating activities. We anticipate that we will issue
long-term debt of approximately $25 million in 2006 for scheduled first mortgage
bond redemptions of $14 million and to refinance accumulated short-term debt.
Material risks to cash flow from operations include regulatory risk, our
customer concentration risk with IBM, slower than anticipated load growth,
unfavorable economic conditions and increases in net power costs.
CONSTRUCTION AND INVESTMENTS - Our capital requirements result from the need to
construct facilities or to invest in programs to meet anticipated customer
demand for electric service. The Company plans to invest up to $20 million in
VELCO through 2007, including $4.6 million invested during 2004. Our planned
investments will fund in part an increase in the amount of equity in VELCO's
capital structure and increased investment, principally driven by construction
of the Northwest Reliability Project and other Vermont construction projects.
See detailed discussion under "Transmission Expenses."
Future capital expenditures are expected to approximate $20 million
annually. Expected reductions in Pine Street remediation costs should be offset
by increased generation expenditures. Capital expenditures over the past three
years and forecasted for 2005 are as follows:
Generation Transmission Distribution Other* Total
----------- ------------- ------------- ------- -------
(In thousands)
Actual:
--------------
2002 . . . . . $ 3,258 $ 1,827 $ 9,173 $ 7,479 $21,737
2003 . . . . . 2,629 1,496 7,760 6,622 18,507
2004 . . . . . 3,053 2,898 10,908 5,005 21,864
Forecast:
--------------
2005 . . . . . $ 3,264 $ 3,234 $ 10,156 $ 6,122 $22,776
* Other includes Pine Street Barge Canal net expenditures of $1.8 million in
2002, $2.5 million in 2003, $1.2 million in 2004 and an estimated $750,000 in
2005.
DIVIDEND POLICY - On February 14, 2005, the annual dividend rate was increased
from $0.88 per share to $1.00 per share, a payout ratio of approximately 48
percent based on 2004 earnings from continuing operations. On February 9, 2004,
the annual dividend rate was increased from $0.76 per share to $0.88 per share,
a payout ratio of approximately 44 percent based on 2003 earnings. The annual
dividend was $0.60 per share for the year ended December 31, 2002. The annual
dividend rate was increased by the Company's Board of Directors from $0.55 per
share to $0.76 per share beginning with the $0.19 quarterly dividend declared in
December 2002. The Company expects to increase the dividend in the first
quarter of each year until the payout ratio falls in the middle of a payout
range of between 50 percent and 70 percent of anticipated earnings, so long as
financial and operating results permit. We believe this payout ratio to be
consistent with that of other electric utilities having similar risk profiles.
FINANCING AND CAPITALIZATION
------------------------------
During June 2004, the Company negotiated a 364-day revolving credit
agreement (the "Fleet-Sovereign Agreement") with Fleet Financial Services
("Fleet") joined by Sovereign Bank. The Fleet-Sovereign Agreement is for $30.0
million, unsecured, and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There was $3.0 million
outstanding on the Fleet-Sovereign Agreement at December 31, 2004 at an average
rate of 5.25 percent. There was no non-utility short-term debt outstanding at
December 31, 2004 or 2003. The Fleet-Sovereign Agreement expires June 15, 2005.
The Company anticipates that it will secure financing that replaces some or all
of its expiring facilities during 2005.
During 2002, we redeemed $5.1 million of 10.0 percent first mortgage bonds
and $12.5 million of outstanding preferred stock.
In 2002, we also completed a "Dutch Auction" self-tender offer and
repurchased 811,783 shares, or approximately 14 percent, of the Company's common
stock outstanding for approximately $16.3 million.
The credit ratings of the Company's first mortgage bonds at December 31,
2004 were:
Moody's Standard & Poor's
-------------------- -----------------
First mortgage bonds Baa1 BBB
On June 18, 2004 Moody's affirmed the Company' senior secured debt rating at
Baa1, with a stable outlook. On November 3, 2004, Standard and Poor's Ratings
Services upgraded the Company's issuer credit rating to BBB from BBB-, citing an
improved regulatory climate in Vermont. Standard and Poor's Ratings Services
also affirmed its BBB rating of the Company's senior secured debt, with a stable
outlook.
In the event of a change in the Company's first mortgage bond credit rating
to below investment grade, scheduled payments under the Company's first mortgage
bonds would not be affected. Such a change would require the Company to post
what would currently amount to a $4.3 million bond under our remediation
agreement with the EPA regarding the Pine Street Barge Canal site. The Morgan
Stanley Contract requires credit assurances if the Company's first mortgage bond
credit ratings are lowered to below investment grade by either of the credit
rating agencies listed above.
The following table presents a summary of certain material contractual
obligations existing as of December 31, 2004.
Payments Due by Period
----------------------
At December 31, 2004 2006 and 2008 and After
TOTAL 2005 2007 2009 2009
------------------------------------ ---------- -------- -------- --------
(In thousands)
Long-term debt . . . . . . . . . . . $ 93,000 $ - $ 14,000 $ - $ 79,000
Interest on long-term debt . . . . . 70,170 6,534 12,068 11,068 40,500
Capital lease obligations. . . . . . 4,516 572 879 766 2,299
Hydro-Quebec power supply contracts. 574,044 50,960 100,986 102,723 319,375
Morgan Stanley Contract. . . . . . . 22,718 12,561 10,157 - -
Independent Power Producers. . . . . 183,217 15,905 33,923 32,808 100,581
Stony Brook contract . . . . . . . . 46,808 2,876 6,024 6,506 31,402
VYNPC PPA. . . . . . . . . . . . . . 255,588 33,047 68,090 71,590 82,861
---------- -------- -------- -------- --------
Total. . . . . . . . . . . . . . $1,250,061 $122,455 $246,127 $225,461 $656,018
========== ======== ======== ======== ========
See the captions "Power Supply Expense" and "Power Contract Commitments" for
additional information about the Hydro-Quebec and MS power supply contracts
OFF-BALANCE SHEET ARRANGEMENTS - The Company does not use off-balance sheet
financing arrangements, such as securitization of receivables or obtaining
access to assets through special purpose entities. We have material power
supply commitments that are discussed in detail under the captions "Power
Contract Commitments" and "Power Supply Expenses." We also own an equity
interest in VELCO, which requires the Company to pay a portion of VELCO's
operating costs, including its debt service costs.
OTHER RISKS - 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.
In 2002, the owners of property along the shoreline of Joe's Pond, an
impoundment located in Danville, Vermont, created by the Company's West Danville
hydroelectric generating facility, filed an inquiry with the VPSB seeking review
of certain dam improvements made by the Company in 1995, alleging that the
Company did not obtain all necessary regulatory approvals for the 1995
improvements and that the Company's improvements and subsequent operation of the
dam have caused flooding of the shoreline and property damage. The Company
received VPSB approval for, and has made additional dam improvements, at the
facility. The VPSB has pending a regulatory proceeding to determine whether to
impose regulatory penalties in connection with the 1995 dam improvements.
EFFECTS OF INFLATION - Financial statements are prepared in accordance with
generally accepted accounting principles and report operating results in terms
of historic costs. This accounting provides reasonable financial statements but
does not always take inflation into consideration. As rate recovery is based on
these historical costs and known and measurable changes, the Company is able to
receive some rate relief for inflation. It does not receive immediate rate
recovery relating to fixed costs associated with Company assets. Such fixed
costs are recovered based on historic figures. Any effects of inflation on
plant costs are generally offset by the fact that these assets are financed
through long-term debt.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Financial Statements Page
Consolidated Statements of Income 44
For the Years Ended December 31, 2004, 2003, and 2002
Consolidated Statements of Cash Flows For the 45
Years Ended December 31, 2004, 2003, and 2002
Consolidated Balance Sheets as of 46
December 31, 2004 and 2003
Consolidated Statements of Changes In Shareholders Equity 48
And Comprehensive Income For the Years Ended December 31,
2004, 2003, and 2002
Notes to Consolidated Financial Statements 49
Quarterly Financial Information (Unaudited) 79
Consent and Reports of Independent Registered Public Accounting Firm 80
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31
2004 2003 2002
--------- --------- ---------
(In thousands, except per share data)
Retail and other revenues. . . . . . . . . . . . . . . . . . $206,164 $201,569 $203,962
Wholesale revenues . . . . . . . . . . . . . . . . . . . . . 22,652 78,901 70,646
--------- --------- ---------
TOTAL OPERATING REVENUES . . . . . . . . . . . . . . . . . . 228,816 280,470 274,608
Operating expenses-Power Supply:
Purchases from others. . . . . . . . . . . . . . . . . . . 137,503 189,450 188,381
Company-owned generation . . . . . . . . . . . . . . . . . 6,516 7,856 5,067
Other operating. . . . . . . . . . . . . . . . . . . . . . . 17,537 17,534 13,851
Transmission . . . . . . . . . . . . . . . . . . . . . . . . 15,656 14,783 15,221
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 9,746 9,721 9,872
Depreciation and amortization. . . . . . . . . . . . . . . . 13,931 13,803 14,151
Taxes other than income. . . . . . . . . . . . . . . . . . . 6,687 6,897 6,942
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . 5,762 5,120 6,043
--------- --------- ---------
Total operating expenses . . . . . . . . . . . . . . . . 213,338 265,164 259,528
--------- --------- ---------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 15,478 15,306 15,080
--------- --------- ---------
OTHER INCOME
Equity in earnings of affiliates and non-utility operations. 1,232 1,493 2,777
Allowance for equity funds used during construction. . . . . 449 387 233
---------
Other income . . . . . . . . . . . . . . . . . . . . . . . . 714 409 393
---------
Other deductions . . . . . . . . . . . . . . . . . . . . . . (308) (210) (918)
--------- --------- ---------
Total other income . . . . . . . . . . . . . . . . . . . 2,087 2,079 2,485
--------- --------- ---------
INTEREST CHARGES
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 6,534 7,021 5,214
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . 257 303 1,059
Allowance for borrowed funds used during construction. . . . (285) (267) (103)
--------- --------- ---------
Total interest charges . . . . . . . . . . . . . . . . . 6,506 7,057 6,170
--------- --------- ---------
INCOME FROM CONTINUING OPERATIONS
BEFORE PREFERRED DIVIDENDS . . . . . . . . . . . . . . . . . 11,059 10,328 11,395
Dividends on preferred stock . . . . . . . . . . . . . . . . - 3 96
--------- --------- ---------
INCOME FROM CONTINUING OPERATIONS. . . . . . . . . . . . . . 11,059 10,325 11,299
Income from discontinued operations, net . . . . . . . . . . 525 79 99
--------- --------- ---------
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 11,584 $ 10,404 $ 11,398
========= ========= =========
EARNINGS PER SHARE
Basic earnings per share from continuing operations. . . . . $ 2.18 $ 2.08 $ 2.02
Basic earnings per share from discontinued operations. . . . 0.10 0.01 0.02
--------- --------- ---------
Basic earnings per share . . . . . . . . . . . . . . . . . . $ 2.28 $ 2.09 $ 2.04
========= ========= =========
Diluted earnings per share from continuing operations. . . . $ 2.10 $ 2.01 $ 1.96
Diluted earnings per share from discontinued operations. . . 0.10 0.01 0.02
--------- --------- ---------
Diluted earnings per share . . . . . . . . . . . . . . . . . $ 2.20 $ 2.02 $ 1.98
========= ========= =========
Weighted average shares outstanding-basic. . . . . . . . . . 5,083 4,980 5,592
Weighted average equivalent shares outstanding-diluted . . . 5,254 5,140 5,756
The accompanying notes are an integral part of the consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION For the Years Ended
CONSOLIDATED STATEMENTS OF CASH FLOWS December 31
-----------
2004 2003 2002
--------------- --------- ---------
OPERATING ACTIVITIES (in thousands)
Income from continuing operations before preferred dividends . . . . . $ 11,059 $ 10,328 $ 11,395
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . 13,931 13,803 14,151
Dividends from associated companies. . . . . . . . . . . . . . . . . . 863 2,081 2,400
Equity in undistributed earnings of associated companies . . . . . . . (880) (1,197) (2,355)
Allowance for funds used during construction . . . . . . . . . . . . . (733) (654) (335)
Amortization of deferred purchased power costs . . . . . . . . . . . . 318 318 3,236
Deferred income tax expense, net of investment tax credit amortization 3,699 1,479 3,577
Deferred purchased power costs . . . . . . . . . . . . . . . . . . . . (667) (570) (2,003)
Rate levelization liability. . . . . . . . . . . . . . . . . . . . . . (2,970) (1,121) (4,483)
Environmental and conservation deferrals, net. . . . . . . . . . . . . (1,041) (1,890) (2,194)
Cash in advance of construction. . . . . . . . . . . . . . . . . . . . 2,246 1,222 1,690
Gain on sale of property . . . . . . . . . . . . . . . . . . . . . . . (402) - -
Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . 1,244 - -
Changes in:
Accounts receivable and accrued utility revenues . . . . . . . . . . . (1,120) (189) (896)
Prepayments, fuel and other current assets . . . . . . . . . . . . . . (418) (1,188) 850
Accounts payable and other current liabilities . . . . . . . . . . . . 1,567 (676) (55)
Income taxes payable and receivable. . . . . . . . . . . . . . . . . . (2,069) (2,183) 3,863
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,009 1,428 (232)
--------------- --------- ---------
Net cash provided by continuing operations . . . . . . . . . . . . . . 25,637 20,991 28,609
Net income from discontinued operations. . . . . . . . . . . . . . . . 525 79 99
--------------- --------- ---------
Net cash provided by operating activities. . . . . . . . . . . . . . . 26,162 21,070 28,708
--------------- --------- ---------
INVESTING ACTIVITIES
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . (20,823) (16,617) (19,543)
Restriction of cash for renewable energy investments . . . . . . . . . (354) - -
Proceeds from sale of property . . . . . . . . . . . . . . . . . . . . 648 - -
Investment in associated companies . . . . . . . . . . . . . . . . . . (4,579) (108) (392)
Return of capital from associated companies. . . . . . . . . . . . . . 314 7,615 370
Investment in nonutility property. . . . . . . . . . . . . . . . . . . (338) (198) (206)
--------------- --------- ---------
Net cash used in investing activities. . . . . . . . . . . . . . . . . (25,132) (9,308) (19,771)
--------------- --------- ---------
FINANCING ACTIVITIES
Proceeds from issuance of long-term debt . . . . . . . . . . . . . . . - - 42,000
Repurchase of preferred stock. . . . . . . . . . . . . . . . . . . . . - (85) (12,536)
Payments to acquire treasury stock . . . . . . . . . . . . . . . . . . - (3) (16,320)
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . 1,885 995 1,037
Reduction in long-term debt and term loan. . . . . . . . . . . . . . . - (8,000) (25,322)
Short-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,500 (2,000) 2,500
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,481) (3,792) (3,393)
--------------- --------- ---------
Net cash provided by (used in) financing activities. . . . . . . . . . (96) (12,885) (12,034)
--------------- --------- ---------
Net increase in cash and cash equivalents. . . . . . . . . . . . . . . 934 (1,123) (3,097)
Cash and cash equivalents at beginning of period . . . . . . . . . . . 786 1,909 5,006
--------------- --------- ---------
blank
Cash and cash equivalents at end of period . . . . . . . . . . . . . . $ 1,720 $ 786 $ 1,909
=============== ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,691 $ 7,120 $ 6,048
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,043 2,915 2,349
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
2004 2003
-------- --------
(in thousands)
ASSETS
UTILITY PLANT
Utility plant, at original cost . . . . . . . . $339,269 $324,900
Less accumulated depreciation . . . . . . . . . 119,633 110,111
-------- --------
Utility plant, net of accumulated depreciation. 219,636 214,789
Property under capital lease. . . . . . . . . . 4,731 5,047
Construction work in progress . . . . . . . . . 8,345 9,026
-------- --------
Total utility plant, net. . . . . . . . . . . . 232,712 228,862
-------- --------
OTHER INVESTMENTS
Associated companies, at equity . . . . . . . . 10,179 5,896
Other investments . . . . . . . . . . . . . . . 8,780 7,810
-------- --------
Total other investments . . . . . . . . . . . . 18,959 13,706
-------- --------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . 1,720 786
Accounts receivable, less allowance for
doubtful accounts of $620 and $690. . . . . . . 18,216 17,331
Accrued utility revenues. . . . . . . . . . . . 6,964 6,729
Fuel, materials and supplies, average cost. . . 4,848 4,498
Prepayments . . . . . . . . . . . . . . . . . . 1,674 1,922
Income tax receivable . . . . . . . . . . . . . 1,717 422
Other . . . . . . . . . . . . . . . . . . . . . 323 -
-------- --------
Total current assets. . . . . . . . . . . . . . 35,462 31,688
-------- --------
DEFERRED CHARGES
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
Power supply derivative asset . . . . . . . . . 10,736 3,990
Other regulatory assets . . . . . . . . . . . . 6,932 8,439
Other deferred charges. . . . . . . . . . . . . 1,113 1,186
-------- --------
Total deferred charges. . . . . . . . . . . . . 53,731 55,590
-------- --------
NON-UTILITY
Other current assets. . . . . . . . . . . . . . - 217
Property and equipment. . . . . . . . . . . . . 247 248
Other assets. . . . . . . . . . . . . . . . . . 508 640
-------- --------
Total non-utility assets. . . . . . . . . . . . 755 1,105
-------- --------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . . $341,619 $330,951
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
GREEN MOUNTAIN POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
2004 2003
--------- ---------
(in thousands except share data)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock, $3.33 1/3 par value,
authorized 10,000,000 shares (issued
5,968,118 and 5,860,854) . . . . . . . . . . . . $ 19,894 $ 19,536
Additional paid-in capital . . . . . . . . . . . 78,852 76,081
Retained earnings. . . . . . . . . . . . . . . . 29,889 22,786
Accumulated other comprehensive income . . . . . (2,353) (1,787)
Treasury stock, at cost (827,639 shares) . . . . (16,701) (16,701)
--------- ---------
Total common stock equity. . . . . . . . . . . . 109,581 99,915
Long-term debt, less current maturities. . . . . 93,000 93,000
--------- ---------
Total capitalization . . . . . . . . . . . . . . 202,581 192,915
--------- ---------
CAPITAL LEASE OBLIGATION . . . . . . . . . . . . 4,493 4,963
--------- ---------
CURRENT LIABILITIES
Short-term debt. . . . . . . . . . . . . . . . . 3,000 500
Accounts payable, trade and accrued liabilities. 9,437 8,493
Accounts payable to associated companies . . . . 7,391 6,821
Rate levelization liability. . . . . . . . . . . - 2,970
Accrued taxes. . . . . . . . . . . . . . . . . . 1,290 633
Customer deposits. . . . . . . . . . . . . . . . 1,063 968
Interest accrued . . . . . . . . . . . . . . . . 1,136 1,152
Other. . . . . . . . . . . . . . . . . . . . . . 1,151 1,178
--------- ---------
Total current liabilities. . . . . . . . . . . . 24,468 22,715
--------- ---------
DEFERRED CREDITS
Power supply derivative liability. . . . . . . . 22,821 23,724
Accumulated deferred income taxes. . . . . . . . 32,223 30,000
Unamortized investment tax credits . . . . . . . 2,564 2,848
Pine Street Barge Canal cleanup liability. . . . 6,458 7,356
Accumulated cost of removal. . . . . . . . . . . 19,806 21,238
Deferred compensation. . . . . . . . . . . . . . 8,872 8,936
Other regulatory liabilities . . . . . . . . . . 4,012 2,643
Other deferred liabilities . . . . . . . . . . . 11,150 11,536
--------- ---------
Total deferred credits . . . . . . . . . . . . . 107,906 108,281
--------- ---------
COMMITMENTS AND CONTINGENCIES, NOTE 3
NON-UTILITY
Net liabilities of discontinued segment. . . . . 2,171 2,077
--------- ---------
Total non-utility liabilities. . . . . . . . . . 2,171 2,077
--------- ---------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . $341,619 $330,951
========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY ACCUMULATED
AND COMPREHENSIVE INCOME OTHER TOTAL
COMMON STOCK PAID-IN RETAINED COMPREHENSIVE TREASURY COMMON
------------
SHARES AMOUNT CAPITAL EARNINGS INCOME STOCK EQUITY
---------- ------- -------- ---------- -------- --------- ---------
(In thousands except share data)
BALANCE, DECEMBER 31, 2001. . . . . . . 5,685,154 $19,004 $ 74,581 $ 8,070 $ - $ (378) $101,277
---------- ------- -------- ---------- -------- --------- ---------
Common stock issuance:
DRIP and ESIP . . . . . . . . . . . . . 28,682 95 424 - - - 519
Common stock repurchase . . . . . . . . (811,783) - - - - (16,320) (16,320)
Compensation programs . . . . . . . . . 52,804 177 342 - - - 519
Income before preferred dividends . . . - - - 11,494 - - 11,494
Other comprehensive income(loss). . . . - - - - (2,374) - (2,374)
Common stock dividends-$0.60 per share. - - - (3,297) - - (3,297)
Preferred stock dividends . . . . . . . - - - (96) - - (96)
---------- ------- -------- ---------- -------- --------- ---------
BALANCE, DECEMBER 31, 2002. . . . . . . 4,954,857 19,276 75,347 16,171 (2,374) (16,698) 91,722
---------- ------- -------- ---------- -------- --------- ---------
Common stock issuance:
Compensation programs . . . . . . . . . 78,358 260 734 - - - 994
Common stock repurchase . . . . . . . . - - - - - (3) (3)
Income before preferred dividends . . . - - - 10,407 - - 10,407
Other comprehensive income(loss). . . . - - - - 587 - 587
Common stock dividends-$0.76 per share. - - - (3,789) - - (3,789)
Preferred stock dividends . . . . . . . - - - (3) - - (3)
---------- ------- -------- ---------- -------- --------- ---------
BALANCE, DECEMBER 31, 2003. . . . . . . 5,033,215 19,536 76,081 22,786 (1,787) (16,701) 99,915
---------- ------- -------- ---------- -------- --------- ---------
Common stock issuance:
Compensation programs . . . . . . . . . 107,264 358 2,771 - - - 3,129
Net income. . . . . . . . . . . . . . . - - - 11,584 - - 11,584
Other comprehensive income(loss). . . . - - - - (566) - (566)
Common stock dividends-$0.88 per share. - - - (4,481) - - (4,481)
---------- ------- -------- ---------- -------- --------- ---------
BALANCE, DECEMBER 31, 2004. . . . . . . 5,140,479 $19,894 $ 78,852 $ 29,889 $(2,353) $(16,701) $109,581
---------- ------- -------- ---------- -------- --------- ---------
The accompanying notes are an integral part of the consolidated financial
statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the years ended December 31,
--------------------------------
2004 2003 2002
-------- ------- --------
In thousands
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $11,584 $10,404 $11,398
Minimum pension liability adjustment, net of applicable income taxes (566) 587 (2,374)
of $391 benefit, $400 expense and $1.6 million benefit, respectively -
--------
Other comprehensive income. . . . . . . . . . . . . . . . . $11,018 $10,991 $ 9,024
======== ======= ========
The accompanying notes are an integral part of the consolidated financial
statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND BASIS OF PRESENTATION. Green Mountain Power Corporation (the
"Company") is an investor-owned electric utility that transmits, distributes and
sells electricity and utility construction services in Vermont with a principal
service territory that includes approximately one quarter of Vermont's
population. Nearly all of the Company's net income is generated from retail
sales in its regulated electric utility operation, which purchases and generates
electric power and distributes electricity to approximately 90,000 customer
accounts. The Company's subsidiary, Green Mountain Power Investment Company
("GMPIC"), was created in December 2002 to hold the Company's investment in
Vermont Yankee Nuclear Power Corporation ("Vermont Yankee" or "VYNPC").
The Company's remaining active wholly-owned subsidiary, which is not
regulated by the Vermont Public Service Board ("VPSB" or the "Board"), is GMP
Real Estate Corporation. The results of GMP Real Estate Corporation and the
Company's unregulated rental water heater program are included in earnings of
affiliates and non-utility operations in the Other Income section of the
Consolidated Statements of Income. Summarized financial information for GMP
Real Estate Corporation and the Company's unregulated water heater program is as
follows:
Years ended December 31,
2004 2003 2001
----- ------ -----
In thousands
Revenue. . . $ 961 $1,087 $ 997
Expense. . . 594 704 744
----- ------ -----
Net Income . $ 367 $ 253 $ 263
===== ====== =====
The Company accounts for its investments in VYNPC, Vermont Electric Power
Company, Inc. ("VELCO"), New England Hydro-Transmission Corporation, and New
England Hydro-Transmission Electric Company using the equity method of
accounting. The Company's share of the net earnings or losses of these
companies is also included in the Other Income section of the Consolidated
Statements of Income. See Note B for additional information.
The Company's interests in jointly-owned generating and transmission
facilities are accounted for on a pro-rata basis using the Company's ownership
percentages and are recorded in the Company's Consolidated Balance Sheets. The
Company's share of operating expenses for these facilities is included in the
corresponding operating accounts on the Consolidated Statements of Income.
USE OF ESTIMATES. In preparing the Financial Statements, management is required
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and contingent liabilities at
the date of the Financial Statements, and the reported amounts of revenues and
expenses during the reporting period. Changes to these assumptions and
estimates could have a material affect on the Company's Financial Statements
particularly as they relate to unbilled revenue, pension expense and
contingencies. However, the Company believes it has taken reasonable positions,
where assumptions and estimates are used, in order to minimize the impact to the
Company that could result if actual results vary from the assumptions and
estimates. In management's opinion, the areas of the Company where the most
significant judgment is exercised is in the valuation of unbilled revenue,
pension plan assumptions, contingency reserves, accumulated removal obligations,
regulatory assets and liabilities, the allowance for uncollectible accounts
receivable and derivative valuation.
REGULATORY ACCOUNTING. The Company's utility operations, including accounting
records, rates, operations and certain other practices of its electric utility
business, are subject to the regulatory authority of the Federal Energy
Regulatory Commission ("FERC") and the VPSB.
The accompanying consolidated financial statements conform to accounting
principles generally accepted in the United States of America applicable to
rate-regulated enterprises in accordance with Statement of Financial Accounting
Standards No. ("SFAS") 71 ("SFAS 71"), "Accounting for Certain Types of
Regulation." Under SFAS 71, the Company accounts for certain transactions in
accordance with permitted regulatory treatment. As such, regulators may permit
incurred costs, typically treated as expenses by unregulated entities, to be
deferred and expensed in future periods when recovered in future revenues.
Incurred 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 another form of regulation. In the event that the
Company no longer meets the criteria under SFAS 71, the Company would be
required to write off related regulatory assets, net of regulatory liabilities
as summarized in the following table:
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
=============== =======
*Substantially all regulatory assets are being recovered in current rates
effective January 1, 2005 and, with the exception of Pine Street Barge Canal and
certain power contract related costs, include an associated return on
investment.
The net power supply deferral results from 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. The
power supply contract expenses are fully recovered in the rates we charge, and
are discussed in detail under Power Supply Derivatives.
The Company defers and amortizes replacement power costs associated with
unscheduled outages at the Vermont Yankee nuclear power plant owned by Entergy
Nuclear Vermont Yankee LLC ("ENVY') and other extraordinary losses. The Company
also defers and amortizes extraordinary costs associated with natural disaster,
severe storms costs or significant loss of load under a rate plan (see Note I,
Commitments and Contingencies).
Other regulatory assets totaled $6.9 million and $8.4 million at December
31, 2004 and 2003, respectively, and consist of regulatory deferrals of storm
damages, rights-of-way maintenance, other employee benefits, preliminary survey
and investigation charges, transmission interconnection charges, regulatory tax
assets and various other projects and deferrals.
The Company continues to believe, based on current regulatory
circumstances, that the use of regulatory accounting under SFAS 71 remains
appropriate and that its regulatory assets are probable of recovery. The
Company provides for regulatory disallowances when management believes it is
both probable and estimable that a regulatory liability exists.
Accumulated costs of removal represent asset retirement costs previously
recovered from ratepayers for other than legal obligations. In accordance with
SFAS 143, "Accounting for Asset Retirement Obligations," the Company reflects
these amounts as a regulatory liability. Prior to SFAS 143, these amounts were
recorded as a part of the Company's Accumulated Depreciation. We expect, over
time, to recover or settle through future revenues any under- or over-collected
net cost of removal.
DISCONTINUED OPERATIONS. 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, inactivated, sold in
part or retains 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 non-performing loans. The Company recognized income of $.10 per
share from Discontinued Operations during 2004, compared with earnings of $.01
and $.02 in 2003 and 2002, respectively, reflecting diminished exposure to
outstanding litigation that led to reversal of previously recorded reserves.
Substantially all of NWR's investments have been written off except for
associated deferred tax amounts, net of applicable valuation allowances.
IMPAIRMENT. The Company is required to evaluate long-lived assets, including
regulatory assets, for potential impairment. Assets that are no longer probable
of recovery through future cash flows would be re-valued based upon future cash
flows. Regulatory assets are charged to expense in the period in which they are
no longer probable of future recovery. As of December 31, 2004, based upon
management's analysis of the regulatory environment within which the Company
currently operates, the Company does not believe that an impairment loss should
be recorded. Competitive influences or regulatory developments may impact this
status in the future.
UTILITY PLANT. The cost of plant additions is recorded at original cost and
includes all construction-related direct labor and materials, as well as
indirect construction costs. The cost of plant additions includes the cost of
money ("Allowance for Funds Used During Construction" or "AFUDC") when costs
applicable to construction work in progress have not otherwise been provided a
return through regulatory proceedings. The costs of renewals and improvements
of property units are capitalized. The costs of maintenance, repairs and
replacements of minor property items are charged to maintenance expense. The
costs of units of property removed from service, net of salvage value, are
charged to accumulated depreciation. The following table summarizes the
Company's investments in utility plant.
Property Summary at December 31,
2004 2003
---------- ----------
In thousands
Property, Plant and Equipment:
Intangible. . . . . . . . . . . . . . . . $ 12,390 $ 14,091
Generation. . . . . . . . . . . . . . . . 72,156 68,532
Transmission. . . . . . . . . . . . . . . 39,368 37,093
Distribution. . . . . . . . . . . . . . . 186,863 178,292
General, including transportation . . . . 28,492 26,892
---------- ----------
Total Plant in Service. . . . . . . . . 339,269 324,900
Accumulated Depreciation and Amortization (119,633) (110,111)
---------- ----------
Net Plant in Service. . . . . . . . . . . 219,636 214,789
Capital Lease . . . . . . . . . . . . . . 4,731 5,047
Construction Work in Progress . . . . . . 8,345 9,026
---------- ----------
Total Net Utility Plant . . . . . . . . . $ 232,712 $ 228,862
========== ==========
DEPRECIATION. The Company provides for depreciation using the straight-line
method based on the cost and estimated remaining service life of the depreciable
property outstanding at the beginning of the year and adjusted for salvage value
and cost of removal of the property.
The annual depreciation provision was approximately 3.3 percent during
2004, 3.3 percent during 2003 and 3.2 percent during 2002 of total depreciable
property.
DISPOSAL OF ASSETS. During 2004, the Company sold non-utility property
consisting of land and buildings for $648,000. The Company recognized a gain of
approximately $402,000 related to the sale of these assets, which is recorded in
Other Income in the Consolidated Statement of Income.
CASH AND CASH EQUIVALENTS. Cash and cash equivalents include short-term
investments with original maturities less than ninety days.
RESTRICTED CASH. The Company has set aside $354,000, included in Other
Investments, as of December 31, 2004, for renewable generation development under
a VPSB regulatory order.
OPERATING REVENUES. Operating revenues consist principally of retail sales of
electricity at regulated rates. Revenue is recognized when electricity is
delivered. The Company accrues utility revenues, based on estimates of electric
service rendered and not billed at the end of an accounting period, in order to
match revenues with related costs. Wholesale revenues represent sales of
electricity to other utilities, typically for resale, and to ISO New England for
amounts by which our power supply resources exceed customer loads. The Company
also recognizes deferred revenues, when required to achieve its allowed rate of
return, under a VPSB order issued in 2001, and extended through 2004 under a
subsequent VPSB order. The Company recognized $3.0 million, $1.1 million and
$4.5 million in deferred revenues during 2004, 2003 and 2002, respectively. At
December 31, 2004, the Company has recognized all revenues deferred under the
VPSB orders. See Note I for additional information.
ALLOWANCE FOR DOUBTFUL ACCOUNTS. The Company estimates the amount of accounts
receivable that will not be collected and records these amounts as a reduction
to accounts receivable.
Allowance for Doubtful Accounts
Balance at Additions Additions Balance at
Beginning of Charged to Charged to End of
Period Cost & Expenses Other Accounts Deductions Period
------- ---------------- --------------- ----------- -------
In thousands
2004 . . . . $ 691 $ - $ - $ 71 $ 620
2003 . . . . 547 144 - - 691
2002 . . . . 576 - 37 66 547
EARNINGS PER SHARE. Basic earnings per share ("EPS") is calculated by dividing
net income, after deductions for preferred dividends, by the weighted-average
common shares outstanding for the period. SFAS No. 128, Earnings Per Share,
requires the disclosure of diluted EPS, which is similar to the calculation of
basic EPS except that the weighted-average common shares is increased by the
number of potential dilutive common shares. Diluted EPS reflects the impact of
the issuance of common shares for all potential dilutive common shares
outstanding during the period, including stock options.
During the year ended December 31, 2000, the Company granted 335,300
options under its 2000 Stock Plan exercisable over vesting schedules of between
one and four years. During 2003, 2002 and 2001, the Company granted additional
options of 4,000, 80,300 and 56,450, respectively. SFAS 123 requires disclosure
of pro-forma information regarding net income and earnings per share. The
Company adopted the prospective method of accounting for stock-based
compensation under SFAS 148 beginning January 1, 2003. The information
presented below has been determined as if the Company accounted for all past
employee and director stock options under the fair value method of that
statement.
Pro-forma net income
For the years ended December 31,
2004 2003 2002
------- ------- -------
In thousands, except per share amounts
Net income reported. . . . . . . . . . $11,584 $10,404 $11,398
Pro-forma net income . . . . . . . . . $11,503 $10,242 $11,114
Net income per share
As reported-basic. . . . . . . . . . $ 2.28 $ 2.09 $ 2.04
Pro-forma basic. . . . . . . . . . . $ 2.26 $ 2.06 $ 1.99
As reported-diluted. . . . . . . . . $ 2.20 $ 2.02 $ 1.98
Pro-forma diluted. . . . . . . . . . $ 2.19 $ 1.99 $ 1.93
MAJOR CUSTOMERS AND OTHER CONCENTRATION RISKS. The Company has one major retail
customer, International Business Machines Corporation ("IBM"), that accounted
for 24.1 percent, 24.1 percent and 25.7 percent of retail MWh sales, and 16.4
percent, 16.6 percent and 17.3 percent of the Company's retail operating
revenues in 2004, 2003 and 2002, respectively.
We currently estimate, based on a number of projected variables, that a
hypothetical shutdown of the IBM facility would necessitate a retail rate
increase for all remaining customers of approximately five percent, including
secondary and tertiary impacts of such a shutdown on other customer sales.
Our material power supply contracts are principally with Hydro Quebec and
Vermont Yankee Nuclear Power Corporation ("VYNPC"). These contracts are
expected to meet approximately 75 percent of our anticipated annual demand
requirements during the next five years. These supplier concentrations could
have a material impact on the Company's net power costs, if one or both of these
sources were unavailable over an extended period of time. We also have a power
supply contract with Morgan Stanley Capital Group, Inc. (the "Morgan Stanley
Contract") for approximately 16 percent of our annual load that expires December
31, 2006.
FAIR VALUE OF FINANCIAL INSTRUMENTS. The fair value and carrying value of the
Company's first mortgage bonds and derivative contracts is summarized in the
following table:
Fair Value of Financial Instruments
As of December 31,
2004 2003
---- ----
Calculated Amount carried Calculated Amount carried
In thousands Fair Value on balance sheet Fair Value on balance sheet
Long-Term Debt, net,(Note F) $ 91,274 $ 93,000 $ 91,725 $ 93,000
Derivatives, net . . . . . . 12,085 12,085 19,773 19,773
The book value of accounts receivable, accrued utility revenues, other
investments, cash surrender value of life insurance, short-term debt, accounts
payable, customer deposits and accrued interest approximate fair value due to
their short-term, highly liquid nature.
The fair value of derivatives is discussed below under "Derivative
Instruments."
ENVIRONMENTAL LIABILITIES. The Company is subject to federal, state and local
regulations addressing air and water quality, hazardous and solid waste
management and other environmental matters. Only those site investigation,
characterization and remediation costs currently known and determinable can be
considered "probable and reasonably estimable" under SFAS 5, "Accounting for
Contingencies." As costs become probable and reasonably estimable, reserves are
adjusted as appropriate. As reserves are recorded, regulatory assets are
recorded to the extent environmental expenditures are expected to be recovered
in rates. Estimates are based on studies provided by third parties.
PURCHASED POWER. The Company records the annual cost of power obtained under
long-term executory contracts as operating expenses. The contracts do not
convey to the Company the right to use the related property plant, or equipment.
DERIVATIVE INSTRUMENTS. The Company utilizes derivative instruments primarily
to reduce power supply risk. The Company does not hold derivative trading
positions. The Company has continued to record expense related to derivatives
in the period settled consistent with an accounting order issued by the VPSB.
SFAS 133, as amended, establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance sheet as
either an asset or liability measured at its fair value. SFAS 133 requires that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS 133, as amended, was
effective for the Company beginning 2001.
On April 11, 2001, the VPSB issued an accounting order that requires the
Company to defer recognition of any earnings or other comprehensive income
effects relating to future periods caused by the application of SFAS 133 to
power supply arrangements that qualify as derivatives.
We currently have an agreement (the "9701 agreement") that grants Hydro
Quebec an option to call power at prices below current and estimated future
market rates. This agreement is effective through 2015. From time to time, we
use forward contracts to hedge the 9701 agreement. Since we are required under
VPSB order to defer recognition of any SFAS 133 earnings effect until settled,
we do not evaluate derivatives for hedge accounting treatment. If the Company
were to terminate or sell any of its derivative contracts, it would immediately
record the gain or loss on that contract, absent a regulatory order to do
otherwise.
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
At December 31, 2004, the Company had a liability in deferred credits of $22.8
million reflecting the fair value of the 9701 agreement, and an asset of $10.7
million, reflecting the fair value of the Morgan Stanley Contract. A
corresponding net regulatory asset of $12.1 million is also recorded in deferred
charges. At December 31, 2003, the Company had a liability of $23.7 million,
reflecting the fair value of the 9701 agreement, and an asset of $4.0 million,
reflecting the fair value of the Morgan Stanley Contract. A corresponding net
regulatory asset of $19.7 million was also recorded. The Company believes that
the net regulatory asset is probable of recovery in future rates. The net
regulatory asset is based on current estimates of future market prices that are
likely to change by material amounts.
The Morgan Stanley Contract is used to hedge against increases in fossil
fuel prices. Morgan Stanley purchases a portion of the Company's power supply
resources at index (fossil fuel resources) or specified (i.e., contracted
resources) prices and then sells to us at a fixed rate to serve pre-established
load requirements. This contract allows management to fix the cost of much of
its power supply requirements, subject to power resource availability and other
risks. The Morgan Stanley Contract expires December 31, 2006.
RECLASSIFICATIONS. The Company changed the classification of certain previously
reported amounts in the accompanying balance sheet as of December 31, 2003 to
correct immaterial errors related to the accounting for income taxes. The
effect of the changes was to decrease accumulated deferred income taxes by $4.0
million, increase other deferred credits by $3.4 million, and increase net
liabilities of discontinued operations by approximately $600,000. We made
conforming changes to the tax footnote and cash flow statement. In addition,
certain prior years amounts have been reclassified for consistent presentation
with the current year.
OTHER COMPREHENSIVE INCOME. Certain negative scenarios and unfavorable market
conditions (asset returns are lower than expected, reductions in discount rates,
and liability experience losses) may cause the Pension Plan's accumulated
benefit obligation ("ABO") to exceed the fair value of Pension Plan assets as of
the measurement date and would result in an unfunded minimum liability. If that
occurs, and the minimum liability exceeds the accrued benefit cost, an
additional minimum pension liability may be required to be recorded, net of tax,
as a non-cash charge to Other Comprehensive Income, included in Common Stock
Equity on the Consolidated Balance Sheet. The ABO represents the present value
of benefits earned without considering future salary increases.
Other comprehensive loss of $2.4 million, net of a $1.6 million income tax,
was recognized during 2002 as a result of a minimum pension funding liability.
During 2003, an increase in the market value of pension plan assets resulted in
a reduction in other comprehensive loss of approximately $587,000, net of
$400,000 income tax. During 2004, due principally to a decline in the discount
rate used for pension calculations, we recorded an increase in other
comprehensive loss of $566,000, net of $391,000 income tax.
RECENT ACCOUNTING PRONOUNCEMENTS. In January 2003, the FASB issued FIN
45,"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." FIN 45 requires a company to
recognize a liability for the obligations it has undertaken in issuing a
guarantee. This liability would be recorded at the inception of a guarantee and
would be measured at fair value. The Company adopted the measurement provisions
of this statement in the first quarter of 2003 and it did not impact the
Company's financial position or results of operations. See FIN 45 discussion
related to Hydro Quebec under Note K.
In December 2003, the FASB issued Statement of Financial Accounting
Standards No. 132 (revised 2003), "Employers Disclosures about Pensions and
Other Postretirement Benefits" ("SFAS 132"). In an effort to provide the public
with better and more complete information, the standard requires that companies
provide more details about their plan assets, benefit obligations, cash flows,
benefit costs and other relevant information. The guidance is effective for
fiscal years ending December 15, 2003 and for quarters beginning after December
15, 2003. We have adopted all of the disclosures required by the standard.
In January 2003 and December 2003, the Financial Accounting Standards Board
issued Interpretation 46 and 46R (Revised), respectively, "Consolidation of
Variable Interest Entities" ("VIEs"). This interpretation clarified application
of Accounting Research Bulletin No. 51, "Consolidated Financial Statements," and
replaced current accounting guidance relating to consolidation of certain
special purpose entities. FIN 46 and FIN 46R define VIEs as entities that are
unable to finance their ongoing operations without additional subordinated
financing. FIN 46R requires identification of the Company's participation in
VIEs and consolidation of those VIEs of which the Company is the primary
beneficiary. The Company adopted FIN 46 at December 31, 2003 and FIN 46R at
March 31, 2004, and was not required to consolidate any existing interests
pursuant to the requirements of FIN 46 or FIN 46R.
On December 8, 2003, President Bush signed into law the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 ("the Act"). The
Act expanded Medicare to include, for the first time, coverage for prescription
drugs, generally effective January 1, 2006. The Company provides health care,
life insurance, prescription drug and other benefits to retired employees who
meet certain age and years of service requirements. The Company elected to
defer recognition of any impact under FSP 106-1, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003."
On May 19, 2004, the FASB issued FASB Staff Position No. FAS 106-2,
"Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003," which requires employers to
provide certain disclosures regarding the effect of the federal subsidy provided
by the Act.
Pending the release of final regulations, the Company was unable to
conclude whether the benefits provided by the plan were actuarially equivalent
to Medicare Part D under the Act, and to accurately measure the effect of the
change on the accumulated postretirement benefit obligation ("APBO") or the net
periodic postretirement benefit cost ("net periodic cost"). This was a result
of uncertainty with treatment under the Act of contributions made by certain
retirees and the Company's cap on employer medical premiums. Regulations and
their interpretations were finalized in January 2004, and the reduction in APBO
at December 31, 2004, was determined to be approximately $3.5 million. The
expected subsidy will impact annual net periodic cost in 2005 and beyond.
In November 2004, the FASB issued SFAS No. 151, "Inventory Costs" ("SFAS
151"), which clarifies the accounting for abnormal amounts of idle facility
expense, freight, handling costs and wasted material. SFAS 151 is effective for
inventory costs incurred during fiscal years beginning after June 15, 2005. The
Company does not believe the adoption of SFAS 151 will have a material effect on
its respective financial statements.
In December 2004, the FASB issued a revision to SFAS No. 123R, "Share-Based
Payments," which replaces SFAS No. 123, "Accounting for Stock-Based
Compensation." The revision determines how the Company will measure the cost of
employee services received in exchange for share-based payments. The cost of
share-based payments will be based on the grant date fair value of the award.
The guidance is effective as of the beginning of the first interim or annual
reporting period after June 15, 2005. The Company has not yet determined what
the impact of this new standard will be on its financial position or results of
operations.
In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary
Assets, as amended of APB Opinion No. 29" ("SFAS 153"), which addresses the
measurement of exchanges of nonmonetary assets and redefines the scope of
transactions that should be measured based on the fair value of the assets
exchanged. SFAS 153 is effective for nonmonetary asset exchanges occurring in
fiscal periods beginning after June 15, 2005. The Company does not believe the
adoption of SFAS 153 will have a material effect on its respective financial
statements.
In December 2004, the FASB issued FASB Staff Position 109-1 ("FSP 109-1"),
which was effective upon issuance, to provide guidance of the application of
SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"), to the provision
within the American Jobs Creation Act of 2004 ("Jobs Act") that provides a tax
deduction on qualified production activities. The Jobs Act includes a tax
deduction of up to 9 percent (when fully phased-in) of the lesser of (a)
"qualified production activities income," as defined in the Jobs Act, or (b)
taxable income (after the deduction for the utilization of any net operating
loss carryforwards). The tax deduction is limited to 50 percent of W-2 wages
paid by the taxpayer. FSP 109-1 clarifies that the manufacturer's deduction
provided for under the Jobs Act should be accounted for as a special deduction
in accordance with SFAS 109 and not as a tax rate reduction. The adoption of
FSB 109-1 had no impact on the Company's financial statements. The Company is
evaluating the effect that the manufacturer's deduction will have in subsequent
years.
B. INVESTMENTS IN ASSOCIATED COMPANIES
The Company accounts for investments in the following associated companies
by the equity method:
PERCENT OWNERSHIP INVESTMENT IN EQUITY
AT DECEMBER 31, AT DECEMBER 31,
2004 2003 2004 2003
-------- ------- ------ ------
(IN THOUSANDS)
VELCO-common. . . . . . . . . . . . . . . 29.17% 28.41% $7,041 $2,469
VELCO-preferred . . . . . . . . . . . . . 30.00% 30.00% 158 246
------ ------
Total VELCO . . . . . . . . . . . . . . . 7,199 2,715
VYNPC- Common . . . . . . . . . . . . . . 33.60% 33.60% 1,612 1,605
New England Hydro Transmission-Common . . 3.18% 3.18% 515 592
New England Hydro Transmission Electric-
Common. . . . . . . . . . . . . . . . 3.18% 3.18% 853 984
------ ------
Total investment in associated companies. $10,179 $5,896
======== =======
VELCO. VELCO and its wholly-owned subsidiary, Vermont Electric Transmission
Company, own and operate transmission systems in Vermont over which bulk power
is delivered to all electric utilities in the state. VELCO operates under the
terms of the 1985 Four-Party Agreement (as amended) with the Company and two
other major distribution companies in Vermont.
VELCO has entered into transmission agreements with the State of Vermont
and other electric utilities including the Company, and under these agreements,
VELCO bills all costs, including interest on debt and a fixed return on equity,
to the State and others using VELCO's transmission system. The Company is
entitled to approximately 29 percent of the dividends distributed by VELCO. The
Company has recorded its equity in earnings on this basis and also is required
to pay for its share of VELCO's operating costs including debt service costs.
The Company plans to make capital investments of up to $20 million in VELCO
through 2007 in support of various transmission projects, including a $4.6
million investment made in the last quarter of 2004.
Summarized unaudited financial information for VELCO is as follows:
At and for the years ended December 31,
2004 2003 2002
--------- --------- ---------
(In thousands)
Net income. . . . . . . . . . . $ 1,683 $ 1,270 $ 1,094
Company's equity in net income. $ 472 $ 418 $ 319
========= ========= =========
Total assets. . . . . . . . . . $145,632 $126,793 $106,613
Liabilities and long-term debt. 120,983 117,393 97,417
--------- --------- ---------
Net assets. . . . . . . . . . . $ 24,649 $ 9,400 $ 9,196
========= ========= =========
Company's equity in net assets. $ 7,199 $ 2,715 $ 2,614
========= ========= =========
Amounts due from (to) VELCO . . $ (4,068) $ (4,190) $ (5,550)
Included in VELCO's revenues shown above are transmission services to the
Company (reflected as transmission expenses in the accompanying Consolidated
Statements of Income) amounting to $12.3 million in 2004, $12.0 million in 2003
and $12.7 million in 2002, respectively.
VERMONT YANKEE NUCLEAR POWER CORPORATION ("VYNPC"). The Company's ownership
share of VYNPC has increased from approximately 19.0 percent in 2002 to
approximately 33.6 percent currently, due to VYNPC's purchase of certain
minority shareholders' interests. The Company's entitlement to energy produced
by the Vermont Yankee nuclear plant owned by ENVY remains at approximately 20
percent of plant production.
Summarized unaudited financial information for VYNPC is as follows:
At and for the years ended December 31,
2004 2003* 2002
--------- --------- ---------
(In thousands)
Earnings:
Operating revenues . . . . . . . . . . $167,399 $187,123 $175,722
Net income applicable to common stock. 538 2,536 9,454
Company's equity in net income . . . . $ 181 $ 498 $ 1,745
========= ========= =========
Total assets . . . . . . . . . . . . . . $151,542 $150,720 $201,426
Liabilities and long-term debt . . . . 146,747 145,946 150,413
--------- --------- ---------
Net Assets . . . . . . . . . . . . . . . $ 4,795 $ 4,774 $ 51,203
========= ========= =========
Company's equity in net assets . . . . . $ 1,612 $ 1,605 $ 9,721
========= ========= =========
Amounts due from (to) VYNPC. . . . . . . $ (3,324) $ (2,648) $ (3,487)
*The 2003 decrease in equity in net assets of VYNPC resulted from a distribution
of proceeds, in the form of dividends to VYNPC owners, from the sale of the
VYNPC nuclear power plant.
On July 31, 2002, VYNPC announced that the sale of the Vermont Yankee
nuclear power plant to ENVY had been completed. Since the Company no longer
owns an interest in the Vermont Yankee nuclear plant, we are not responsible for
the costs of decommissioning the plant, nor are we responsible for any plant
repairs or maintenance costs during outages. See Note K for further information
concerning our long-term power contract with VYNPC.
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 would be required to shut down the Vermont Yankee plant. If
the Vermont Yankee plant is shut down, we would have to acquire substitute
baseload power resources, comprising approximately 35 percent of our estimated
total power supply needs. 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 Vermont Yankee facility) would be
approximately $9 million annually. 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's
continuing documentation review led to the discovery of the fuel rod segments in
a container in the spent fuel pool. We cannot predict the outcome of this
matter at this time.
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 Proposal ("RPP") to reduce the balance of deferred
replacement power costs.
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 disputes that
the fire was uprate-related. The Company has petitioned the VPSB to resolve the
dispute.
C. COMMON STOCK EQUITY AND STOCK AWARD PLANS
The Company maintains a Dividend Reinvestment and Stock Purchase Plan
("DRIP") under which 416,328 shares were reserved and unissued at December 31,
2004. The Company also funds an Employee Savings and Investment Plan ("ESIP")
under which the Company may contribute shares of common stock.
During 2000, the Company's Board of Directors, with subsequent approval of
the Company's common shareholders, established a stock incentive plan (the "2000
Stock Plan"). Under this plan, up to 500,000 shares of common stock may be
issued in the form of options, stock grants, stock appreciation rights,
restricted stock, restricted stock units, performance awards and other
stock-based awards to any employee, officer, consultant, contractor or director
providing services to the Company, or its subsidiaries. The Company has issued
stock options, stock awards and deferred stock units to employees and directors
under the plan. Outstanding options become exercisable at between one and four
years after the grant date and remain exercisable until 10 years from the grant
date. As of December 31, 2004, 23,023 shares are unissued under the 2000 Stock
Plan.
During 2004, the Company's Board of Directors, with subsequent approval of
the Company's common shareholders, established the 2004 Stock Incentive Plan,
under which 225,000 shares in the form of stock grants, options, stock
appreciation rights, restricted stock and restricted stock units, performance
awards or other stock-based awards can be granted to any employee, officer,
consultant, contractor or director providing services to the Company, or its
subsidiaries. As of December 31, 2004, no shares have been issued under the
2004 Stock Incentive Plan.
Prior to 2003, as permitted by Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), the Company had
elected to follow Accounting Principles Board Opinion No. 25 ("APB 25")
"Accounting for Stock Issued to Employees," and related interpretations in
accounting for its employee stock options issued through 2002. Under APB 25,
because the exercise price equals the market price of the underlying stock on
the date of grant, no compensation expense was recorded. Effective January 1,
2003, the Company elected to expense the fair value of options granted beyond
that date. The amount of expense recorded during 2003 was immaterial, and no
options were granted in 2004. Options have been issued only to employees and
directors.
The fair values of options granted in 2003, and 2002 are $1.33 and $2.27
per share, respectively. They were estimated at the grant date using the
Black-Scholes option-pricing model. The following table presents information
about the assumptions that were used for each plan year, and a summary of the
options outstanding at December 31, 2004:
Weighted Assumptions used in option pricing model
---------------------------------------------
average Remaining Risk Free Expected Expected
Plan exercise Outstanding Contractual Interest Life in Stock Dividend
year price options Life rate Years Volatility Yield
------ ------- ----------- ------- ------- ----- ----------- -----
2000 $ 7.90 145,600 5.6 years 6.05% 5 30.58 4.5%
2001 $16.77 18,100 6.6 years 5.25% 6 32.69 4.0%
2002 $17.90 49,300 7.6 years 4.50% 6.5 16.89 4.5%
2003 $20.64 2,300 8.3 years 2.48% 6 13.68 4.5%
------ -------
Total $11.07 215,300
======= =======
Weighted Range of
Total Average Exercise Options
Options Price Prices Exercisable
------- ------ ------------- -----------
Outstanding at December 31, 2001 364,150 $ 9.20 $ 7.90-$16.78 95,350
Granted. . . . . . . . . . . . . 80,300 17.82 $16.78-$18.67
Exercised. . . . . . . . . . . . 53,250 8.12 $ 7.90-$16.78
Forfeited. . . . . . . . . . . . 25,400 9.35 $ 7.90-$18.67
------- ------ -------------
Outstanding at December 31, 2002 365,800 11.23 $ 7.90-$17.82 151,775
------- ------ ------------- -----------
Granted. . . . . . . . . . . . . 4,000 20.55 $20.22-$22.62
Exercised. . . . . . . . . . . . 64,550 10.63 $ 7.90-$18.67
Forfeited. . . . . . . . . . . . 4,400 17.36 $16.78-$18.12
------- ------ -------------
Outstanding at December 31, 2003 300,850 11.39 $ 7.90-$22.62 193,700
------- ------ ------------- -----------
Granted. . . . . . . . . . . . . - - -
Exercised. . . . . . . . . . . . 84,150 12.11 $ 7.90-$20.96
Forfeited. . . . . . . . . . . . 1,400 18.65 $17.54-$20.96
------- ------ -------------
Outstanding at December 31, 2004 215,300 $11.07 $ 7.90-$22.62 213,500
======= ====== ============= ===========
The following table presents a reconciliation of net income to net income
available to common shareholders, and the average common shares to average
common equivalent shares outstanding:
Reconciliation of net income available For the Years Ended
for common shareholders and average shares December 31
2004 2003 2002
--------------- ------- -------
(in thousands)
Net income before preferred dividends . $ 11,584 $10,407 $11,494
Preferred stock dividend requirement. . - 3 96
--------------- ------- -------
Net income applicable to common
stock. . . . . . . . . . . . . . . . $ 11,584 $10,404 $11,398
=============== ======= =======
Average number of common shares-basic . 5,083 4,980 5,592
Dilutive effect of stock options. . . . 171 160 164
--------------- ------- -------
Average number of common shares-diluted 5,254 5,140 5,756
=============== ======= =======
As part of our long-term stock incentive program, unrestricted stock grants and
deferred stock unit grants have been made to employees, senior management and
directors. Unrestricted stock grants are recognized as compensation expense
based on the fair value of the awards at the grant date. Deferred stock units
are recognized as deferred compensation based on the fair value of the award at
the grant date and charged to expense over the required service period for each
award. Awards to senior management vest over a two year service period. Total
compensation expense from all stock awards to directors, employees and senior
management totaled $1.2 million in 2004 and $422,000 in 2003.
On November 19, 2002, the Company completed a "Dutch Auction" self-tender
offer and repurchased 811,783 common shares, or approximately 14 percent, of its
common stock outstanding for approximately $16.3 million.
Appropriated Retained Earnings. The Company had appropriated retained
earnings of $353,000 and $277,000 at December 31, 2004 and 2003, respectively,
relating to regulatory requirements arising from ownership of hydro-electric
facilities.
Dividend Restrictions. Certain restrictions on the payment of cash
dividends on common stock are contained in the Company's indentures relating to
long-term debt and in the Amended and Restated Articles of Incorporation. Under
the most restrictive of such provisions, approximately $28.6 million of retained
earnings were free of restrictions at December 31, 2004.
D. PREFERRED STOCK
During 2002, the Company repurchased all $12.0 million of the 7.32 percent
Class E preferred stock outstanding. On May 1, 2002, the Company redeemed
$300,000 of the 7.0 percent Class C preferred stock outstanding. During
November 2002, the Company repurchased the remaining $200,000 of the 9.375
percent Class D preferred stock outstanding. All remaining preferred stock was
repurchased during 2003.
E. SHORT-TERM DEBT
The Company has a $30.0 million 364-day revolving credit agreement with
Fleet Financial Services ("Fleet") joined by Sovereign Bank ("Sovereign"),
expiring June 2005 (the "Fleet-Sovereign Agreement"). The Fleet-Sovereign
Agreement is unsecured, and allows the Company to choose any blend of a daily
variable prime rate and a fixed term LIBOR-based rate. There was $3.0 million
outstanding at a weighted average rate of 5.25 percent, and $500,000 outstanding
at a weighted average rate of 4 percent, under the Fleet-Sovereign Agreement at
December 31, 2004 and 2003, respectively. There was no non-utility short-term
debt outstanding at December 31, 2004 or 2003.
The Fleet-Sovereign Agreement requires the Company to certify on a
quarterly basis that it has not suffered a "material adverse change." The
agreement also requires the Company to comply with certain covenants. The
Company was in compliance with all covenants at December 31, 2004.
F. LONG-TERM DEBT
Substantially all of the property and franchises of the Company are subject
to the lien of the indenture under which first mortgage bonds have been issued.
The weighted average rate on long-term borrowings outstanding was 7.0 percent
for both December 31, 2004 and 2003. The annual sinking fund requirements
(excluding amounts that may be satisfied by property additions) are included in
the following table with interest rates and maturities as of December 31 for the
years presented.
LONG-TERM DEBT
FIRST MORTGAGE BONDS (In thousands)
Interest rate-Maturity Annual Sinking Fund 2004 2003
------- -------
7.05%-Dec. 15, 2006. . . . . . . . . . . . . . - $ 4,000 $ 4,000
7.18%-Nov. 6, 2006 . . . . . . . . . . . . . . - 10,000 10,000
6.04%-Dec. 1, 2017 . . . . . . . . . . . . . . 6,000,000 begins 2011 42,000 42,000
6.7%-Nov. 1, 2018. . . . . . . . . . . . . . . - 15,000 15,000
9.64%-Sept. 1, 2020. . . . . . . . . . . . . . - 9,000 9,000
8.65%-Mar. 1, 2022 . . . . . . . . . . . . . . $ 500,000 begins 2012 13,000 13,000
------- -------
Total Long-term Debt Outstanding . . . . . . . 93,000 93,000
Less Current Maturities (due within one year). - -
TOTAL LONG-TERM DEBT, LESS CURRENT MATURITIES. $ 93,000 $93,000
====================== =======
On December 16, 2002, the Company issued through private placement $42 million
principal amount of first mortgage bonds bearing interest at 6.04 percent per
year and maturing on December 1, 2017. The average duration of the bond
issuance is twelve years and the bonds are subject to seven equal annual
principal payments beginning on December 1, 2011. Proceeds were used to retire
all of the Company's short and intermediate term debt, and to repurchase 811,783
shares of the Company's common stock.
G. INCOME TAXES
UTILITY. The Company accounts for income taxes using the liability method.
This method accounts for deferred income taxes by applying statutory rates to
the differences between the book and tax bases of assets and liabilities.
The temporary differences, which gave rise to the net deferred tax
liability at December 31, 2004 and December 31, 2003, were as follows:
AT DECEMBER 31,
2004 2003
------- -------
(In thousands)
DEFERRED TAX ASSETS
Contributions in aid of construction. $ 2,155 $ 896
Deferred compensation and
postretirement benefits. . . . . 4,972 4,303
Self insurance and other reserves . . 639 637
Other . . . . . . . . . . . . . . . . 1,654 2,602
------- -------
$ 9,420 $ 8,438
------- -------
DEFERRED TAX LIABILITIES
Property related. . . . . . . . . . . $32,453 $29,230
Demand side management. . . . . . . . 2,955 2,558
Deferred purchased power costs. . . . 1,033 792
Pine Street reserve . . . . . . . . . 2,753 2,410
Other . . . . . . . . . . . . . . . . 2,449 3,448
------- -------
$41,643 $38,438
------- -------
Net accumulated deferred income
tax liability . . . . . . . . . . $32,223 $30,000
======= =======
The following table reconciles the change in the net accumulated deferred income
tax liability to the deferred income tax expense included in the income
statement for the periods presented:
YEARS ENDED DECEMBER 31,
2004 2003 2002
------- -------- --------
(In thousands)
Net change in deferred income tax . . $2,223 $ 3,529 $ 2,712
liability
Change in income tax related
regulatory assets and liabilities . 2,151 (2,166) 2,759
Change in tax effect of accumulated
other comprehensive income. . . . . (391) 398 (1,612)
------- -------- --------
Deferred income tax expense (benefit) $3,983 $ 1,761 $ 3,859
======= ======== ========
The components of the provision for income taxes are as follows:
YEARS ENDED DECEMBER 31,
2004 2003 2002
------- ------- -------
(In thousands)
Current federal income taxes . $ 461 $2,434 $1,873
Current state income taxes . . 1,602 1,207 593
------- ------- -------
Total current income taxes . . 2,063 3,641 2,466
Deferred federal income taxes. 3,843 1,307 2,920
Deferred state income taxes. . 140 454 939
------- ------- -------
Total deferred income taxes. . 3,983 1,761 3,859
Investment tax credits-net . . (284) (282) (282)
------- ------- -------
Income tax expense . . . . . . $5,762 $5,120 $6,043
======= ======= =======
Total income taxes differ from the amounts computed by applying the federal
statutory tax rate to income before taxes. The reasons for the differences are
as follows:
YEARS ENDED DECEMBER 31,
2004 2003 2002
-------- -------- --------
(In thousands)
Income before income taxes and
preferred dividends. . . . . . . . . . . . . $17,346 $15,527 $17,537
Federal statutory rate . . . . . . . . . . . . 35.0% 34.0% 34.0%
-------- -------- --------
Computed "expected" federal income taxes . . . $ 6,071 $ 5,279 $ 5,963
Increase (decrease) in taxes resulting from:
Tax versus book depreciation basis difference. (149) 41 41
Dividends received credit. . . . . . . . . . . (452) (465) (575)
Amortization of ITC. . . . . . . . . . . . . . (284) (282) (282)
State tax. . . . . . . . . . . . . . . . . . . 1,133 1,082 1,011
Excess deferred taxes. . . . . . . . . . . . . (123) (60) (60)
Wind energy production credit. . . . . . . . . (125) (130) -
Other. . . . . . . . . . . . . . . . . . . . . (309) (345) (55)
-------- -------- --------
Total federal and state income tax . . . . . . $ 5,762 $ 5,120 $ 6,043
======== ======== ========
Effective combined federal and state
income tax rate. . . . . . . . . . . . . . . 33.2% 33.0% 34.5%
H. PENSION AND RETIREMENT PLANS.
The Company has a qualified non-contributory defined benefit pension plan
(the "Pension Plan") covering substantially all of its employees. The
retirement benefits are based on the employees' level of compensation and length
of service. Under the terms of the Pension Plan, employees are vested after
completing five years of service, and can retire when they reach age 55 with a
minimum of 10 years of service. The Company records annual expense and accounts
for its pension plan in accordance with Statement of Financial Accounting
Standards No. 87, Employers' Accounting for Pensions. The Company provides
certain health care benefits for retired employees and their dependents.
Employees become eligible for these benefits if they reach retirement age while
working for the Company. The Company accrues the cost of these benefits during
the service life of covered employees. The pension plan and postretirement
health care assets consist primarily of equity securities, fixed income
securities, hedge funds and cash equivalent funds.
Due to sharp declines in the equity markets during 2001 and 2002, the value
of assets held in trusts to satisfy the Company's pension plan obligations has
decreased. Fluctuations in actual equity market returns as well as changes in
general interest rates may result in increased or decreased pension costs in
future periods.
The Company's funding policy is to make voluntary contributions to its
defined benefit plans to meet or exceed the minimum funding requirements of
ERISA or the Pension Benefit Guaranty Corporation, and so long as the Company's
liquidity needs do not preclude such investments. The Company made voluntary
defined benefit plan contributions totaling $3.5 million during 2003 and $2.25
million during 2004. The Company currently plans to contribute between $2.0 and
$3.0 million of additional funds during 2005.
During 2002, the Company's retirement plan asset return experience required
the Company to recognize a minimum pension liability of $4.0 million, and $1.6
million tax benefit, as prescribed by generally accepted accounting principles.
Common equity was reduced in the amount of $2.4 million through a charge to
other comprehensive income.
During 2003, market value appreciation of pension plan investments resulted
in the reduction of the previously recognized minimum pension liability to $3.0
million. Common equity increased approximately $587,000, net of applicable
income tax, through a credit to other comprehensive income.
During 2004, the Company increased its previously recognized minimum
pension liability by $1 million to approximately $4 million, primarily as a
result of a decrease in the pension plan discount rate. Common equity decreased
approximately $566,000, net of applicable income tax, through a charge to
comprehensive income.
Accrued postretirement health care expenses are recovered in rates. In
order to maximize the tax-deductible contributions that are allowed under IRS
regulations, the Company amended its postretirement health care plan to
establish a 401-h sub-account and separate VEBA trusts for its union and
non-union employees. The VEBA plan assets consist primarily of cash equivalent
funds, fixed income securities and equity securities. The following provides a
reconciliation of benefit obligations, plan assets and funded status of the
plans as of December 31, 2004 and 2003.
At and for the years ended December 31,
Pension Benefits Other Postretirement Benefits
-----------------------------
2004 2003 2004 2003
-------- -------- -------- ---------
(In thousands)
Change in projected benefit obligation:
Projected benefit obligation prior year end . . $33,980 $29,937 $21,906 $ 20,707
Service cost. . . . . . . . . . . . . . . . . . 991 755 335 496
Interest cost . . . . . . . . . . . . . . . . . 2,005 1,900 1,165 1,316
Participant contributions . . . . . . . . . . . - - 115 136
Plan change . . . . . . . . . . . . . . . . . . - 292 - (1,812)
Change in actuarial assumptions . . . . . . . . - - - -
Actuarial (gain) loss . . . . . . . . . . . . . 1,225 2,789 (3,595) 2,070
Benefits paid . . . . . . . . . . . . . . . . . (1,614) (1,629) (947) (1,007)
Administrative expense. . . . . . . . . . . . . (74) (64) - -
-------- -------- -------- ---------
Projected benefit obligation as of year end . . $36,513 $33,980 $18,979 $ 21,906
======== ======== ======== =========
Accumulated benefit obligation. . . . . . . . . $33,032 $30,459 $18,979 $ 21,906
Change in plan assets:
Fair value of plan assets as of prior year end. $27,867 $21,104 $10,229 $ 8,760
Administrative expenses paid. . . . . . . . . . (74) (64) - -
Participant contributions . . . . . . . . . . . - - - -
Employer contributions. . . . . . . . . . . . . 1,550 3,500 700 -
Actual return on plan assets. . . . . . . . . . 2,201 4,956 852 1,558
Benefits paid . . . . . . . . . . . . . . . . . (1,614) (1,629) (110) (89)
-------- -------- -------- ---------
Fair value of plan assets as of year end. . . . $29,930 $27,867 $11,671 $ 10,229
======== ======== ======== =========
Funded status as of year end. . . . . . . . . . $(6,584) $(6,113) $(7,307) $(11,677)
Unrecognized transition obligation. . . . . . . - - 2,624 2,952
Unrecognized prior service cost . . . . . . . . 815 984 (1,977) (2,216)
Unrecognized net actuarial loss . . . . . . . . 7,438 6,372 5,322 9,250
-------- -------- -------- ---------
Prepaid (accrued) benefits at year end. . . . . $ 1,669 $ 1,243 $(1,338) $ (1,691)
======== ======== ======== =========
The Company also has a supplemental pension plan for certain employees. Pension
costs for the years ended December 31, 2004, 2003 and 2002 were $475,000,
$392,000 and $408,000, respectively, under this plan. This plan is funded in
part through insurance contracts.
Net periodic pension expense and other postretirement benefit costs include
the following components:
For the years ended December 31,
Pension Benefits Other Postretirement Benefits
2004 2003 2002 2004 2003 2002
-------- -------- -------- ------- ------- -------
(In thousands)
Service cost . . . . . . . . . . . . . . . $ 991 $ 755 $ 668 $ 335 $ 496 $ 296
Interest cost. . . . . . . . . . . . . . . 2,005 1,900 1,849 1,165 1,316 1,119
Expected return on plan assets . . . . . . (2,285) (1,851) (2,112) (857) (740) (851)
Amortization of transition asset . . . . . - (77) (164) - - -
Amortization of prior service cost . . . . 169 147 147 (239) (58) (58)
Amortization of the transition obligation. - - - 328 328 328
Recognized net actuarial gain. . . . . . . 243 294 - 338 381 60
-------- -------- -------- ------- ------- -------
Net periodic benefit cost. . . . . . . $ 1,123 $ 1,168 $ 388 $1,070 $1,723 $ 894
======== ======== ======== ======= ======= =======
Assumptions used to determine pension and postretirement benefit costs and the
related benefit obligations were:
Assumptions used in For the years ended December 31,
benefit obligation measurement Pension benefits Other Postretirement Benefits
2004 2003 2004 2003
----------- ----------- ----------- -----------
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . . 5.75% 6.00% 5.75% 6.00%
Expected return on plan assets . . . . . . . 8.25% 8.50% 8.25% 8.50%
Rate of compensation increase. . . . . . . . 4.00% 4.25% 4.00% 4.25%
Medical inflation. . . . . . . . . . . . . . - - 10.75% 9.25%
Measurement date . . . . . . . . . . . . . . 12/31/2004 12/31/2003 12/31/2004 12/31/2003
Census date. . . . . . . . . . . . . . . . . 1/1/2004 1/1/2003 1/1/2004 1/1/2003
Assumptions used in For the years ended December 31,
periodic cost measurement Pension benefits Other Postretirement Benefits
2004 2003 2004 2003
----- ----- ----- ------
Weighted average assumptions as of year end:
Discount rate. . . . . . . . . . . . . . . . 6.00% 6.50% 6.00% 6.50%
Expected return on plan assets . . . . . . . 8.25% 8.50% 8.25% 8.50%
Rate of compensation increase. . . . . . . . 4.25% 4.25% 4.25% 4.25%
Current year trend . . . . . . . . . . . . . - - 9.25% 10.00%
Ultimate year trend. . . . . . . . . . . . . 5.50% 5.50%
Year of ultimate trend . . . . . . . . . . . 2009 2009
For measurement purposes, a 10.75 percent annual rate of increase in the per
capita cost of covered medical benefits was assumed for 2004. This rate of
increase gradually declines to 5.0 percent in 2011. The medical trend rate
assumption has a significant effect on the amounts reported. For example,
increasing the assumed health care cost trend rate by one percentage point for
all future years would increase the accumulated postretirement benefit
obligation as of December 31, 2004 by 12.0 percent or $2.3 million and the total
of the service and interest cost components of net periodic postretirement cost
for the year ended December 31, 2004 by $190,000. Decreasing the trend rate by
one percentage point for all future years would decrease the accumulated
postretirement benefit obligation at December 31, 2004 by 9.3 percent or $1.8
million, and the total of the service and interest cost components of net
periodic postretirement cost for 2004 by $156,000.
The Company's defined benefit plan investment policy seeks to achieve
sufficient growth to enable the defined benefit plans to meet their future
obligations and to maintain certain funded ratios and minimize near-term cost
volatility. Current guidelines specify generally that 65 percent of plan assets
be invested in equity securities, 30 percent of plan assets be invested in debt
securities and the remainder be invested in alternative investments.
The Company expects an annual long-term return for the defined benefit plan
asset portfolios of 8.25 percent, based on a representative allocation within
the target asset allocation described above. In formulating this assumed rate
of return, the Company considered historical returns by asset category and
expectations for future returns by asset category based, in part, on expected
capital market performance of the next ten years.
Weighted Average Asset Allocation
Pension Assets Other Postretirement Benefit Assets
Asset Category For the years ended December 31,
2005 TARGET 2004* 2003 2005 TARGET 2004 2003
----------------------- ------- ------- ------------ ------- -------
Equity Securities . . . 65.00% 48.96% 63.10% 65.00% 63.00% 62.00%
Debt Securities . . . . 30.00% 25.80% 24.92% 35.00% 32.00% 36.00%
Real Estate . . . . . . 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%
Other . . . . . . . . . 0.00% 19.94% 6.60% 0.00% 5.00% 2.00%
Alternative investments 5.00% 5.30% 5.38% 0.00% 0.00% 0.00%
------- ------- ------------ ------- ------- -------
Total . . . . . . . . . 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
======= ======= ============ ======= ======= =======
*The large difference between the target and actual allocations is due to a $5
million cash transfer between funds at December 31, 2004
Pension benefits Other Postretirement Benefits
---------------- -----------------------------
Projected Projected
Benefit Benefit
Contributions payments Contributions payments
-------------- --------- -------------- ---------
In Thousands
2005. . . . . . . $ 1,500 $ 1,623 $ 1,362 $ 962
2006. . . . . . . 1,500 1,639 1,000 885
2007. . . . . . . 1,500 1,657 1,000 942
2008. . . . . . . 1,500 1,736 1,000 978
2009. . . . . . . 1,500 1,796 1,000 1,001
2010 through 2014 7,500 10,362 5,000 5,580
I. COMMITMENTS AND CONTINGENCIES
Other contingencies are discussed under Note A, Regulatory Accounting and
Major Customers and Other Concentration Risks and Note B, Vermont Yankee Nuclear
Power Corporation ("VYNPC") and Note K Long-Term Power Purchases.
INDUSTRY RESTRUCTURING
-----------------------
The electric utility business is being subjected to rapidly increasing
competitive pressures stemming from a combination of trends. Certain states,
including all the New England states except Vermont, have enacted legislation to
allow retail customers to choose their electric suppliers, with incumbent
utilities required to deliver that electricity over their transmission and
distribution systems. There are no current legislative or regulatory
initiatives pending or anticipated in Vermont to pursue deregulation.
Alternative forms of performance-based regulation currently appear as possible
intermediate steps towards deregulation. There can be no assurance that any
potential future restructuring plan ordered by the VPSB, the courts, or through
legislation would include a mechanism that would allow for full recovery of our
stranded costs and include a fair return on those costs as they are being
recovered.
ENVIRONMENTAL MATTERS
----------------------
The electric industry typically uses or generates a range of potentially
hazardous products in its operations. We must meet various land, water, air and
aesthetic requirements as administered by local, state and federal regulatory
agencies. We believe that we are in substantial compliance with these
requirements, and that there are no outstanding material complaints about our
compliance with present environmental protection regulations.
PINE STREET BARGE CANAL SUPERFUND SITE - In 1999, the Company entered into a
United States District Court Consent Decree constituting a final settlement with
the United States Environmental Protection Agency ("EPA"), the State of Vermont
and numerous other parties of claims relating to a federal Superfund site in
Burlington, Vermont, known as the "Pine Street Barge Canal." The consent decree
resolves claims by the EPA for past site costs, natural resource damage claims
and claims for past and future remediation costs. The consent decree also
provides for the design and implementation of response actions at the site. We
have estimated total future costs of the Company's future obligations under the
consent decree to be approximately $6.5 million. The estimated liability is not
discounted, and it is possible that our estimate of future costs could change by
a material amount. We have recorded a regulatory asset of $13.3 million to
reflect unrecovered past and future Pine Street costs. Pursuant to the
Company's 2003 Rate Plan, as approved by the VPSB, the Company will begin to
amortize past unrecovered costs in 2005. The Company will amortize the full
amount of incurred costs over 20 years without a return. The amortization is
expected to be allowed in future rates, without disallowance or adjustment,
until fully amortized.
CLEAN AIR ACT - The Company purchases most of its power supply from other
utilities and does not anticipate that it will incur any material direct costs
as a result of the Federal Clean Air Act or proposals to make more stringent
regulations under that Act.
JOINTLY-OWNED FACILITIES
-------------------------
The Company has joint-ownership interests in electric generating and
transmission facilities at December 31, 2004, as follows:
Share of Share of
Ownership Share of Utility Accumulated
Interest Capacity Plant Depreciation
--------- --------- --------------- -------------
(In %) (In MW) (In thousands)
Highgate . . . . . . . . 33.8 67.6 $ 10,296 $ 5,196
McNeil . . . . . . . . . 11.0 5.9 9,109 5,665
Stony Brook (No. 1). . . 8.8 31.0 10,377 9,408
Wyman (No. 4). . . . . . 1.1 6.8 1,980 1,443
Metallic Neutral Return. 59.4 - 1,563 867
Metallic Neutral Return is a neutral conductor for NEPOOL/Hydro-Quebec
Interconnection.
The Company's share of expenses for these facilities is reflected in Operating
Expenses in the Consolidated Statements of Income under Company-owned generation
for the three listed generation plants and under Transmission for the Metallic
Neutral Return and Highgate facilities. Each participant in these facilities
must provide its own financing.
RATE MATTERS
-------------
RETAIL RATE CASES - On December 22, 2003, the VPSB approved our 2003 Rate Plan,
jointly proposed by the Company and the Vermont Department of Public Service
("DPS"). The 2003 Rate Plan covers the period from 2003 through 2006 and
includes the following principal elements:
The Company's rates remained unchanged through 2004. The 2003 Rate Plan
allows the Company to raise rates 1.9 percent, effective January 1, 2005, and an
additional 0.9 percent, effective January 1, 2006, if the increases are
supported by cost of service schedules submitted 60 days prior to the effective
dates. We submitted a cost of service schedule supporting the 1.9 percent rate
increase for 2005 in accordance with the plan. That increase became effective
on January 1, 2005 in accordance with the plan. If the Company's cost of
service filing in 2006 establishes that a rate increase of less than 0.9 percent
is required for the Company to meet its revenue requirement, including an
allowed return on equity of 10.5 percent, the Company will implement the lesser
rate increase. The VPSB retains the discretion to open an investigation of the
Company's rates at any time, at the request of the DPS, the request of
ratepayers, or on its own volition. Certain ratepayers requested the VPSB to
open such an investigation in connection with the Company's 1.9 percent rate
increase for 2005. The VPSB granted the request in December 2004, and then, at
our request, closed and terminated its investigation in January 2005, with no
adverse impact on the Company's rates.
The Company may seek additional rate increases in extraordinary
circumstances, such as severe storm repair costs, natural disasters,
unanticipated unit outages, or significant losses of customer load.
The Company's allowed return on equity is 10.5 percent for the period
January 1, 2003 through December 31, 2006. During the same period, the
Company's earnings on utility operations are capped at 10.5 percent. The
Company did not experience excess earnings in 2004. Excess earnings in 2005 or
2006 will be refunded to customers as a credit on customer bills or applied to
recover regulatory assets, as the Department directs.
The Company carried forward into 2004 $3.0 million in deferred revenue
remaining at December 31, 2003, from the Company's 2001 Settlement Order
(summarized below). These revenues were applied in 2004 to offset increased
costs.
The Company will amortize (recover) certain regulatory assets, including
Pine Street Barge Canal environmental site costs and past demand-side management
program costs, beginning in January 2005, with those amortizations to be allowed
in future rates. Pine Street costs will be recovered over a twenty-year period
without a return.
The Company filed with the VPSB in 2004 a new fully allocated cost of
service study and rate re-design, which allocates the Company's revenue
requirement among all customer classes on the basis of current costs. The new
rate design is subject to VPSB approval and is not expected to adversely affect
operating results.
The Company and the Department have agreed to work cooperatively to develop
and propose an alternative regulation plan as authorized by legislation enacted
in Vermont in 2003. If the Company and Department agree on such a plan, and it
is approved by the VPSB, the alternative regulation plan would supersede the
2003 Rate Plan.
In January 2001, the VPSB issued the 2001 Settlement Order, which included
the following:
The Company received a rate increase of 3.42 percent above existing rates
and prior temporary rate increases became permanent;
Rates were set at levels that recover the Company's VJO Contract costs,
effectively ending the regulatory disallowances experienced by the Company from
1998 through 2000;
Seasonal rates were eliminated in April 2001, which generated approximately
$8.5 million in additional cash flow in 2001, which was deferred and available
to be used to offset increased costs during 2002 and 2003; and
The Company agreed to an earnings cap on core utility operations of 11.25
percent return on equity, with amounts earned over the limit being used to write
off regulatory assets.
The 2001 Settlement Order also imposed two additional conditions:
The Company and customers shall share equally any premium above book value
realized by the Company in any future merger, acquisition or asset sale, subject
to an $8.0 million limit on the customers' share, adjusted for inflation;
and
The Company's further investment in non-utility operations was restricted
until new rates went into effect, which occurred in January 2005. Although this
restriction has expired, we have no plans to make material investments in
non-utility operations.
COMPETITION
-----------
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's electric department. 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 agreement would require VPSB approval. The Company
receives annual revenues of approximately $3 million from its customers in
Rockingham.
OTHER REGULATORY MATTERS
--------------------------
Central Vermont Public Service Corporation ("CVPS") is currently subject to
a rate investigation by the VPSB. In that proceeding, the DPS has advocated
positions that, if adopted by the VPSB and applied to the Company, could
adversely affect our cash flows and operating results. Areas of risk include:
* The Department's advocacy for an earnings cap calculation that would
potentially subject all items on the balance sheet and income statement to a
retroactive review in order to determine whether the Company has met or exceeded
the earnings cap. Our 2003 Rate Plan provides that the Company operate under an
earnings cap through 2006. The Company calculates its earnings under the cap in
a manner that differs from the methodology advocated by the DPS in the CVPS rate
proceeding.
* DPS advocacy for elimination or reduction of costs of future removal that
are currently embedded in depreciation rates and reflected in our cash flows.
The methodology we currently employ is consistent with that used in most other
regulatory jurisdictions.
* DPS advocacy for reduced rates of return on equity for CVPS.
OTHER LEGAL MATTERS
---------------------
In 2002, the owners of property along the shoreline of Joe's Pond, an
impoundment located in Danville, Vermont, created by the Company's West Danville
hydro-electric generating facility, filed an inquiry with the VPSB seeking
review of certain dam improvements made by the Company in 1995, alleging that
the Company did not obtain all necessary regulatory approvals for the 1995
improvements and that the Company's improvements and subsequent operation of the
dam have caused flooding of the shoreline and property damage. The Company
received VPSB approval for, and has made additional dam improvements at the
facility. The VPSB has pending a regulatory proceeding to determine whether to
impose regulatory penalties in connection with the 1995 dam improvements.
J. OBLIGATIONS UNDER TRANSMISSION INTERCONNECTION SUPPORT AGREEMENT AND
OTHER LEASES
Agreements executed in 1985 among the Company, VELCO and other NEPOOL
members and Hydro Quebec provided for the construction of the second phase
(Phase II) of the interconnection between the New England electric systems and
that of Hydro Quebec. Phase II provides 2,000 megawatts of capacity for
transmission of Hydro Quebec power to Sandy Pond, Massachusetts. Construction
of Phase II commenced in 1988 and was completed in late 1990. The Company is
entitled to 3.2 percent of the Phase II power-supply benefits. Total
construction costs for Phase II were approximately $487 million. The New
England participants, including the Company, have contracted to pay monthly
their proportionate share of the total cost of constructing, owning and
operating the Phase II facilities, including capital costs. As a supporting
participant, the Company must make support payments under thirty-year
agreements. These support agreements meet the capital lease accounting
requirements. At December 31, 2004, the present value of the Company's
obligation is approximately $4.2 million.
Projected future minimum payments under the Phase II support agreements are
as follows:
Years ending
December 31
---------------
(In thousands)
2005. . . . . . . . $ 383
2006. . . . . . . . 383
2007. . . . . . . . 383
2008. . . . . . . . 383
2009. . . . . . . . 383
Total for 2010-2015 2,299
Total . . . . . $ 4,216
===============
The Phase II portion of the project is owned by New England Hydro-Transmission
Electric Company and New England Hydro-Transmission Corporation, subsidiaries of
National Grid USA. Certain of the Phase II participating utilities, including
the Company, own equity interests in such companies. The Company holds
approximately 3.2 percent of the equity of the corporations owning the Phase II
facilities and accounts for its ownership under the equity method of accounting.
K. LONG-TERM POWER PURCHASES
UNIT PURCHASES.
Under long-term contracts with various electric utilities in the region,
the Company is purchasing certain percentages of the electrical output of
production plants constructed and financed by those utilities. Such contracts
obligate the Company to pay certain minimum annual amounts representing the
Company's proportionate share of fixed costs, including debt service
requirements, whether or not the production plants are operating. The cost of
power obtained under such long-term contracts, including payments required when
a production plant is not operating, is reflected as "Power Supply Expenses" in
the accompanying Consolidated Statements of Income.
Purchased power expense by significant contract supplier
for the Years ended December 31,
2004 2003 2002
------- ------- -------
In thousands
Hydro Quebec. . . . . $48,309 $46,367 $47,914
Morgan Stanley. . . . 11,106 59,311 71,259
VYNPC . . . . . . . . 33,331 38,109 34,385
Small Power Producers 15,832 15,277 14,393
Stony Brook . . . . . 1,696 2,222 1,766
Information, including estimates for the Company's portion of certain minimum
costs, with regard to significant purchased power contracts of this type in
effect during 2004 follow.
VERMONT YANKEE.
The Company has a long-term power purchase contract with VYNPC, which sold
its nuclear power plant to ENVY on July 31, 2002. The Company is no longer
required to pay its proportionate share of fixed costs, including costs to
decommission the plant, associated with the ENVY plant, including when the plant
is not operating, though the Company is responsible for finding replacement
power at such times.
The VYNPC sale of its nuclear power plant to ENVY also 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 the
Company's energy requirements.
A summary of the Purchase Power Agreement ("PPA"), including projected
charges for the years indicated, follows:
VYNPC
Contract
----------
(Dollars in thousands except per KWh)
Capacity acquired . . . . . . . . . . 106 MW
Contract period expires . . . . . . . 2012
Company's share of output . . . . . . 20%
Annual energy charge. . . . . . . . . 2004 $32,838
estimated . . . . . . . . . . . . . 2005-2012 $31,949
Average cost per KWh. . . . . . . . . 2004 $ 0.044
estimated . . . . . . . . . . . . . 2005-2012 $ 0.041
Prices under the PPA range from $39 to $45 per megawatt hour. The PPA contains
a provision known as the "low market adjuster," which calls for a downward
adjustment in the contract price if market prices for electricity fall by
defined amounts beginning November 2005. If market prices rise, however, PPA
prices are not adjusted upward in excess of the PPA 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 its share of the Vermont Yankee power plant sale
proceeds, approximately $8.2 million, during October 2003, and used the proceeds
to retire debt.
HYDRO QUEBEC.
Under various contracts, summarized in the table below, the Company
purchases capacity and associated energy produced by the Hydro Quebec system.
Such contracts obligate the Company to pay certain fixed capacity costs whether
or not energy purchases above a minimum level set forth in the contracts are
made. Such minimum energy purchases must be made whether or not other, less
expensive, energy sources might be available. These contracts are intended to
complement the other components in the Company's power supply to achieve the
most economic power supply mix available. The Company's current purchases
pursuant to the contract with Hydro Quebec entered into in December 1987 (the
"VJO Contract") are as follows: (1) Schedule B -- 68 megawatts of firm capacity
and associated energy to be delivered at the Highgate interconnection for twenty
years beginning in September 1995; and (2) Schedule C3 -- 46 megawatts of firm
capacity and associated energy to be delivered at interconnections to be
determined at any time for 20 years, which began in November 1995. There are
specific step-up provisions that provide that in the event any VJO Contract
participant fails to meet its obligation under the VJO Contract with Hydro
Quebec, the remaining contract participants, including the Company, will step-up
to the defaulting participant's share on a prorated basis.
In accordance with guidance set forth in 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, 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.
Hydro Quebec also has the right to reduce the load factor from 75 percent
to 65 percent under the VJO Contract a total of three times over the life of the
contract. The Company can delay such reduction by one year under the VJO
Contract. During 2001, Hydro Quebec exercised the first of these options for
2002, and the Company delayed the effective date of this exercise until 2003.
The net cost of Hydro Quebec's exercise of its option increased power supply
expense during 2003 by approximately $4.5 million.
During 2003, Hydro Quebec exercised its second option to reduce the load
factor for 2004 at an incremental expense of approximately $1.8 million. Hydro
Quebec exercised its third option in 2004 for deliveries occurring principally
during 2005 that we estimate will result in an incremental expense of $1.8
million based on current market prices that could change by a material amount.
Hydro Quebec also retains the right to curtail annual energy deliveries by 10
percent up to five times, over the 2001 to 2015 period, if documented drought
conditions exist in Quebec. Under the VJO Contract, Vermont Joint Owners,
including the Company, have two remaining options to adjust deliveries by a five
percent load factor. These cannot be used to offset Hydro Quebec's reductions
through 2005, but may be used after 2005 to manage power supply costs.
The Company's contracts with Hydro Quebec call for the delivery of system
power and are not related to any particular facilities in the Hydro Quebec
system. Consequently, there are no identifiable debt-service charges associated
with any particular Hydro Quebec facility that can be distinguished from the
overall charges paid under the contracts, and there are no generation plant
outage risks, though there are outage risks related to the operation of the
transmission system.
A summary of the Hydro Quebec contracts, including historic and projected
charges for the years indicated, follows:
THE VJO CONTRACT
SCHEDULE B SCHEDULE C3
------------------------------------- -------------
(Dollars in thousands except per KWh)
Capacity acquired. . . . 68 MW 46 MW
Contract period. . . . . 1995-2015 1995-2015
Minimum energy purchase. 65%-75% 65%-75%
(annual load factor)
Annual energy charge . . 2004 $ 9,868 $ 6,812
estimated. . . . . . . 2005-2015 $ 13,756 (1) $ 9,400 (1)
Annual capacity charge . 2004 $ 16,813 $11,613
estimated. . . . . . . 2005-2015 $ 17,121 (1) $11,699 (1)
Average cost per KWh . . 2004 $ 0.073 $ 0.076
estimated. . . . . . . 2005-2015 $ 0.064 (2) $ 0.064 (2)
(1) Estimated average includes load factor reduction to 65 percent in 2005.
(2) Estimated average in nominal dollars levelized over the period indicated
includes amortization of payments to Hydro Quebec.
Under a separate arrangement established in 1996 (the "9701 agreement"),
Hydro Quebec provided a payment of $8.0 million to the Company in 1997. In
return for this payment, the Company provided Hydro Quebec an option for the
purchase of power. Commencing April 1, 1998, and effective through October
2015, Hydro Quebec can exercise an option to purchase up to 52,500 MWh ("option
A") on an annual basis, at energy prices established in accordance with the VJO
Contract. The cumulative amount of energy purchased under the 9701 agreement
shall not exceed 950,000 MWh. Hydro Quebec's option to curtail energy
deliveries pursuant to the VJO Contract may be exercised in addition to these
purchase options.
Over the same period, Hydro Quebec can exercise an option on an annual
basis to purchase a total of 600,000 MWh ("option B") at the VJO Contract energy
price. Hydro Quebec can purchase no more than 200,000 MWh in any given contract
year ending October 31. As of December 31, 2004, Hydro Quebec had purchased or
called to purchase 566,000 MWh under option B.
The Company believes that it is probable that Hydro Quebec will call
options A and B for 2005, and has purchased replacement power for approximately
half of the expected call at an incremental cost of $1.1 million.
In 2004, Hydro Quebec exercised option A and option B, and called for
deliveries to third parties at a net expense to the Company of approximately
$3.2 million, including capacity charges.
In 2003, Hydro Quebec exercised option A and option B, and called for
delivery to third parties at a net expense to the Company of approximately $4.5
million, including capacity charges.
In 2002, Hydro Quebec exercised option A and called for deliveries to third
parties at a net expense to the Company of approximately $3.0 million, including
capacity charges.
MORGAN STANLEY CONTRACT.
In February 1999, the Company entered into a contract with Morgan Stanley
Capital Group, Inc. (the "Morgan Stanley Contract"). 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 predefined operating and pricing parameters. Morgan
Stanley sells to the Company, at a predefined 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.
The Company purchased or expects to purchase the following amounts from
Morgan Stanley for the years indicated:
The Morgan Stanley
Contract
-------------
Capacity acquired*. . . 1-182 MW
Contract period expires 2006
Annual energy charge :.
2004 $11.1 million
2005 estimate . . . . . $12.6 million
2006 estimate . . . . . $10.2 million
*Capacity ranges between 0 and 182 MW over the remaining contract life depending
on the scheduled hour.
Beginning January 1, 2004, the Company reduced the power that it sells to
Morgan Stanley under the contract. The reduction in sales lowered wholesale
revenues by approximately $56 million, and power supply expense by a similar
amount. The change did not adversely affect the Company's opportunity to earn
its allowed rate of return during 2004.
The Company and Morgan Stanley have agreed to the protocols that are used
to schedule power sales and purchases and to secure necessary transmission. The
Morgan Stanley Contract is a derivative that includes a risk premium above
expected future costs of electricity.
UNIT PURCHASES.
Under a long-term contract with Massachusetts Municipal Wholesale Electric
Company ("MMWEC"), the Company is purchasing a percentage of the electrical
output of the Stony Brook production plant constructed by MMWEC. The contract
obligates the Company to pay certain minimum annual amounts representing the
Company's proportionate share of fixed costs, including debt service
requirements, whether or not the production plant is operating, for the life of
the unit. The cost of power obtained under this long-term contract, including
payments required when the production plant is not operating, is reflected as
"Power Supply Expenses" in the accompanying Consolidated Statements of Income.
Information (including estimates for the Company's portion of certain
minimum costs and ascribed long-term debt) with regard to this purchased power
contract in effect during 2004 follows:
STONY
BROOK
-----------------------
(Dollars in thousands)
Plant capacity. . . . . . . . . . 352.0 MW
Company's share of output . . . . 4.40%
Company's annual share of:
Interest. . . . . . . . . . . . $ 107
Other debt service. . . . . . . 466
Other capacity. . . . . . . . . 537
Total annual capacity . . . . . . $ 1,110
=======================
Company's share of long-term debt $ 1,304
INDEPENDENT POWER PRODUCERS.
The Company receives power from several independent power producers
("IPPs"). These plants use water, biomass and trash as fuel. Most of the power
comes through a state-appointed purchasing agent, Vermont Electric Power
Producers Inc. ("VEPPI"), which assigns power to all Vermont utilities under
VPSB rules. In 2004, the Company received 124,617 MWh under these long-term
contracts at a cost of $15.8 million. These IPP purchases amount to 6.0 percent
of the Company's total MWh purchased and 11.5 percent of purchase power
expenses. Estimated purchases from IPPs are expected to be $15.9 million in
2005, $16.5 million in 2006, $17.4 million in 2007, $17.3 million in 2008 and
$15.5 million in 2009.
L. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following quarterly financial information, in the opinion of
management, includes all adjustments necessary to a fair statement of results of
operations for such periods. Variations between quarters reflect the seasonal
nature of the Company's business and the timing of rate changes.
Amounts in thousands except per share data 2004 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
-------- -------- ----------- --------- --------
Operating revenues. . . . . . . . . . . . . . . $63,123 $54,585 $ 54,926 $ 56,182 $228,816
Operating income. . . . . . . . . . . . . . . . 5,019 2,776 4,595 3,088 15,478
Net income-continuing operations. . . . . . . . $ 3,740 $ 1,783 $ 3,392 $ 2,144 $ 11,059
Net income-discontinued operations. . . . . . . (6) (1) (2) 534 525
Net Income applicable to common stock . . . . . $ 3,734 $ 1,782 $ 3,390 $ 2,678 $ 11,584
======== ======== =========== ========= ========
Basic earnings per share from:
Continuing operations . . . . . . . . . . . . $ 0.74 $ 0.35 $ 0.67 $ 0.42 $ 2.18
Discontinued operations . . . . . . . . . . . - - - 0.10 0.10
Basic earnings per share. . . . . . . . . . . $ 0.74 $ 0.35 $ 0.67 $ 0.52 $ 2.28
======== ======== =========== ========= ========
Weighted average common shares outstanding. . 5,046 5,072 5,089 5,124 5,083
Diluted earnings per share from:
Continuing operations . . . . . . . . . . . . $ 0.72 $ 0.34 $ 0.65 $ 0.39 $ 2.10
Discontinued operations . . . . . . . . . . . - - - 0.10 0.10
Diluted earnings per share. . . . . . . . . . $ 0.72 $ 0.34 $ 0.65 $ 0.49 $ 2.20
======== ======== =========== ========= ========
Weighted average common and common equivalent 5,205 5,228 5,251 5,282 5,254
shares outstanding
2003 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
-------- -------- ---------- --------- --------
Operating revenues. . . . . . . . . . . . . . $72,945 $64,455 $ 71,975 $ 71,095 $280,470
Operating income. . . . . . . . . . . . . . . 5,231 2,425 4,302 3,348 15,306
Net income-continuing operations. . . . . . . $ 4,084 $ 1,120 $ 3,034 $ 2,087 $ 10,325
Net income-discontinued operations. . . . . . (13) (8) 6 94 79
Net Income applicable to common stock . . . . $ 4,071 $ 1,112 $ 3,040 $ 2,181 $ 10,404
======== ======== ========== ========= ========
Basic earnings per share from:
Continuing operations . . . . . . . . . . . . $ 0.82 $ 0.22 $ 0.61 $ 0.43 $ 2.08
Discontinued operations . . . . . . . . . . . - - - 0.01 0.01
Basic earnings per share. . . . . . . . . . . $ 0.82 $ 0.22 $ 0.61 $ 0.44 $ 2.09
======== ======== ========== ========= ========
Weighted average common shares outstanding. . 4,959 4,969 4,982 5,009 4,980
Diluted earnings per share from:
Continuing operations . . . . . . . . . . . . $ 0.80 $ 0.22 $ 0.59 $ 0.40 $ 2.01
Discontinued operations . . . . . . . . . . . - - - 0.01 0.01
Diluted earnings per share. . . . . . . . . . $ 0.80 $ 0.22 $ 0.59 $ 0.41 $ 2.02
======== ======== ========== ========= ========
Weighted average common and common equivalent 5,118 5,129 5,141 5,165 5,140
shares outstanding
2002 Quarter ended
MARCH JUNE SEPTEMBER DECEMBER TOTAL
------- ------- ---------- --------- --------
Operating revenues. . . . . . . . . . . . . . $68,866 $65,135 $ 73,477 $ 67,130 $274,608
Operating income. . . . . . . . . . . . . . . 4,441 2,814 3,745 4,080 15,080
Net income-continuing operations. . . . . . . $ 3,354 $ 1,875 $ 3,042 $ 3,028 $ 11,299
Net income-discontinued operations. . . . . . - - - 99 99
Net Income applicable to common stock . . . . $ 3,354 $ 1,875 $ 3,042 $ 3,127 $ 11,398
======= ======= ========== ========= ========
Basic earnings per share from:
Continuing operations . . . . . . . . . . . . $ 0.59 $ 0.33 $ 0.53 $ 0.57 $ 2.02
Discontinued operations . . . . . . . . . . . - - - 0.02 0.02
Basic earnings per share. . . . . . . . . . . $ 0.59 $ 0.33 $ 0.53 $ 0.59 $ 2.04
======= ======= ========== ========= ========
Weighted average common shares outstanding. . 5,691 5,711 5,723 5,333 5,756
Diluted earnings per share from:
Continuing operations . . . . . . . . . . . . $ 0.57 $ 0.32 $ 0.52 $ 0.55 $ 1.96
Discontinued operations . . . . . . . . . . . - - - 0.02 0.02
Diluted earnings per share. . . . . . . . . . $ 0.57 $ 0.32 $ 0.52 $ 0.57 $ 1.98
======= ======= ========== ========= ========
Weighted average common and common equivalent 5,870 5,877 5,879 5,497 5,756
shares outstanding
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Green Mountain Power Corporation
We have audited the accompanying consolidated balance sheets of Green Mountain
Power Corporation and subsidiaries (the "Company") as of December 31, 2004 and
2003, and the related consolidated statements of income, changes in
shareholders' equity and comprehensive income, and cash flows for each of the
three years in the period ended December 31, 2004. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Green Mountain Power Corporation
and subsidiaries as of December 31, 2004 and 2003, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2004, in conformity with accounting principles generally accepted
in the United States of America.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004, based on the
criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated March 21, 2005 expressed an unqualified opinion on management's assessment
of the effectiveness of the Company's internal control over financial reporting
and an adverse opinion on the effectiveness of the Company's internal control
over financial reporting because of a material weakness.
DELOITTE & TOUCHE LLP
Boston, Massachusetts
March 21, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Green Mountain Power Corporation
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that Green
Mountain Power Corporation and subsidiaries (the "Company") did not maintain
effective internal control over financial reporting as of December 31, 2004,
because of the effect of the material weakness identified in management's
assessment based on the criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company's management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express an opinion on management's assessment and an opinion on the
effectiveness of the Company's internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
A material weakness is a significant deficiency, or combination of significant
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be prevented
or detected. The following material weakness has been identified and included
in management's assessment: Deficiencies existed in both the design and
operating effectiveness of controls associated with the Company's accounting for
income taxes. These deficiencies include a failure to timely reconcile account
balances including the preparation of a tax balance sheet, incorrect accounting
for tax accounts related to the contributions in advance of construction,
certain tax credits and non-regulated tax accounts, and insufficient dedication
of resources to the preparation, supervision and review of tax accounting. The
deficiencies resulted in an immaterial adjustment to properly present the
financial statements in accordance with generally accepted accounting
principles. The deficiencies were concluded to represent a material weakness in
the aggregate due to the potential for additional misstatements and the lack of
mitigating controls to detect the misstatements. This material weakness was
considered in determining the nature, timing, and extent of audit tests applied
in our audit of the consolidated financial statements as of and for the year
ended December 31, 2004, of the Company and this report does not affect our
report on such financial statements.
In our opinion, management's assessment that the Company did not maintain
effective internal control over financial reporting as of December 31, 2004, is
fairly stated, in all material respects, based on the criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, because of the
effect of the material weakness described above on the achievement of the
objectives of the control criteria, the Company has not maintained effective
internal control over financial reporting as of December 31, 2004, based on the
criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2004, of the Company and
our report dated March 21, 2005 expressed an unqualified opinion on those
financial statements.
DELOITTE & TOUCHE LLP
Boston, Massacusetts
March 21, 2005
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
-----------------------------------------------------
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, we
carried out an evaluation, with the participation of our management, including
our chief executive officer and chief financial officer, of the effectiveness of
our disclosure controls and procedures (as defined under Rule 13a-15(e) under
the Securities Exchange Act of 1934) as of the end of the period covered by this
report. Based upon that evaluation, our chief executive officer and chief
financial officer concluded that our disclosure controls and procedures were not
effective as of such date because we identified a material weakness in our
internal control over financial reporting in our accounting for income taxes, as
described below. Due to this material weakness, in preparing our financial
statements at and for the year ended December 31, 2004, we performed additional
procedures relating to our accounting for income taxes to ensure that such
financial statements were stated fairly in all material respects in accordance
with generally accepted accounting principles in the United States.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Rules
13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.
Under the supervision and with the participation of our management, including
our chief executive officer and chief financial officer, we conducted an
evaluation of the effectiveness of our internal control over financial reporting
based on the framework in "Internal Control - Integrated Framework" issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on
this assessment under the criteria for effective internal control over financial
reporting described in "Internal Control - Integrated Framework," issued by the
Committee of Sponsoring Organizations of the Treadway Commission, management
determined that as of December 31, 2004, we did not maintain effective internal
control over financial reporting, due to a material weakness as a result of
deficiencies in both the design and operating effectiveness of controls
associated with our accounting for income taxes. These deficiencies include a
failure to timely reconcile account balances including the preparation of a tax
balance sheet, incorrect accounting for tax accounts related to the
contributions in advance of construction, certain tax credits and non-regulated
tax accounts, and insufficient dedication of resources for the preparation,
supervision and review of tax accounting. The material weakness identified by
management resulted in an immaterial reclassification of certain deferred tax
liabilities to other deferred credit accounts on the Company's balance sheet as
of December 31, 2003. These deficiencies were concluded to represent a material
weakness due to the potential for additional misstatements and the lack of other
mitigating controls to detect the misstatements.
Management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004 has been audited by Deloitte &
Touche LLP, an independent registered public accounting firm, as stated in their
report which is included herein.
Management's Remediation Plans
In addition to the required use of a tax balance sheet in accordance with
FAS 109, we intend to take the following actions to improve and remediate the
material weakness in our internal control over financial reporting:
We will implement additional and enhanced internal reviews in the tax area,
including tax rate reconciliations, commencing in the first quarter of 2005.
We will retain and implement an additional review by outside experts on tax
accounting, including regulatory tax items, on a periodic basis commencing in
the first quarter of 2005.
We will implement new tax accounting software to improve controls over
complex spreadsheet models during the latter half of 2005.
We believe these actions will strengthen our internal control over
financial reporting and address the material weakness identified by management.
Our management has committed what it believes to be sufficient resources to this
remediation plan, but there can be no assurance that all control deficiencies
will be remediated on a timely basis. The Audit Committee will monitor the
progress of our remediation efforts.
Any failure to implement and maintain the improvements in the controls over
our financial reporting, or difficulties encountered in the implementation of
these improvements in our controls, could cause us not to meet our reporting
obligations.
Changes in Internal Controls
We continue to review, revise and improve the effectiveness of our internal
control over financial reporting, including strengthening our internal controls
relating to accounting for income taxes as described above. Except as described
above, we have made no significant change in our internal control over financial
reporting in connection with our fourth quarter evaluation that would materially
affect, or is reasonably likely to materially affect, our internal control over
financial reporting.
PART III
ITEM 10
Certain information regarding executive officers called for by Item 10,
"Directors and Executive Officers of the Registrant," is furnished under the
caption, "Executive Officers" in Item 1 of Part I of this Report. The other
information called for by Item 10 will be set forth under the captions "Election
of Directors," "Nominees for Election to the Board of Directors," "Information
About Our Board of Directors" and "Section 16(a) Beneficial Ownership Reporting
Compliance," in the Company's definitive proxy statement relating to its annual
meeting of stockholders to be held on May 23, 2005. Such information is
incorporated herein by reference. Such proxy statement pertains to the election
of directors and other matters. Definitive proxy materials will be filed with
the Securities and Exchange Commission pursuant to Regulation 14A in April 2005.
Because our common stock is listed on the New York Stock Exchange (the
"NYSE"), our chief executive officer is required to make, and he has made, an
annual certification to the NYSE stating that he was not aware of any violation
by us of the corporate governance listing standards of the NYSE. Our chief
executive officer made his annual certification to that effect to the NYSE as of
June 7, 2004. In addition, we have filed, as exhibits to this Annual Report on
Form 10-K, the certifications of our principal executive officer and principal
financial officer required under Sections 906 and 302 of the Sarbanes Oxley Act
of 2002 to be filed with the SEC regarding the quality of our public disclosure.
ITEMS 11, 12, 13 AND 14
The information called for by Items 11, 12, 13 and 14, "Executive
Compensation," "Security Ownership of Certain Beneficial Owners and Management,"
"Certain Relationships and Related Transactions," and "Principal Accounting Fees
and Services," will be set forth under the captions "Executive Compensation and
Other Information," "Compensation Committee Report on Executive Compensation,"
"Pension Plan Information and Other Benefits," "Equity Compensation Plan
Information," "Securities Ownership of Certain Beneficial Owners and
Management," and "Audit Committee Report" in the Company's definitive proxy
statement relating to its annual meeting of stockholders to be held on May 23,
2005. Such information is incorporated herein by reference. Such proxy
statement pertains to the election of directors and other matters. Definitive
proxy materials will be filed with the Securities and Exchange Commission
pursuant to Regulation 14A in April 2005.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
List of documents filed as part of this Form 10-K:
(1) Financial Statements. See the Index to the Company's financial
statements set forth in Item 8 hereof.
(2) Financial Statement Schedules. N/A.
(3) Exhibits. See the Exhibit Index set forth at the end of this Form 10-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
GREEN MOUNTAIN POWER CORPORATION
Date: March 28, 2005 By:/s/ Christopher L. Dutton______
----------------------------------
Christopher L. Dutton, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
------------------------------------------- --------
/s/ Christopher L. Dutton_ President, Chief Executive March 28, 2005
-----------------------------
Christopher L. Dutton Officer, and Director
/s/ Mary G. Powell_______ Chief Operating Officer, March 28, 2005
-----------------------------
Mary G. Powell Senior Vice President
/s/ Robert J. Griffin Chief Financial Officer, Vice March 28, 2005
-------------------------
Robert J. Griffin President and Treasurer
*Nordahl L. Brue ) Chairman of the Board
*Elizabeth Bankowski )
*William H. Bruett )
*Merrill O. Burns )
*David R. Coates ) Directors
*Kathleen C. Hoyt )
*Euclid A. Irving )
*Marc A. vanderHeyden )
*By: _/s/ Christopher L. Dutton March 28, 2005
---------------------------
Christopher L. Dutton
(Attorney - in - Fact)
ITEM 15(A)3 AND ITEM 15C. EXHIBITS SEC docket
incorporated
by reference
Exhibit or Page filed
Number Description Exhibit herewith
---------- ----------------------------------------------------------------- ---------- ----------------
3-1 Amended and Restated Articles of Incorporation dated. . . . . . . 3A Form 10-Q
May 27, 2004. June 2004
3.b By-laws of the Company, as amended February 10, 1997. . . . . . . 3.b Form 10-K 1996
(1-8291)
3.c By-laws of the Company, as amended December 8, 2003.. . . . . . . 3 Form 8-K Dec. 8
2003 (1-8291)
4.b.1 Indenture of First Mortgage and Deed of Trust dated . . . . . . . 4.b 2-27300
as of February 1, 1955.
4.b.2 First Supplemental Indenture dated as of April 1, 1961. . . . . . 4.b.2 2-75293
4.b.3 Second Supplement Indenture dated as of January 1, 1966.. . . . . 4.b.3 2-75293
4.b.4 Third Supplemental Indenture dated as of July 1, 1968.. . . . . . 4.b.4 2-75293
4.b.5 Fourth Supplemental Indenture dated as of October 1, 1969.. . . . 4.b.5 2-75293
4.b.6 Fifth Supplemental Indenture dated as of December 1, 1973.. . . . 4.b.6 2-75293
4.b.7 Seventh Supplemental Indenture dated as of August 1, 1976.. . . . 4.b.7 2-99643
4.b.8 Eighth Supplemental Indenture dated as of December 1, 1979. . . . 4.b.8 2-99643
4.b.9 Ninth Supplemental Indenture dated as of July 15, 1985. . . . . . 4.b.9 2-99643
4.b.10 Tenth Supplemental Indenture dated as of June 15, 1989. . . . . . 4.b.10 Form 10-K 1989
(1-8291)
4.b.11 Eleventh Supplemental Indenture dated as of September 1, 1990.. . 4.b.11 Form 10-Q Sept.
1990 (1-8291)
4.b.12 Twelfth Supplemental Indenture dated as of March 1, 1992. . . . . 4.b.12 Form 10-K 1991
(1-8291)
4.b.13 Thirteenth Supplemental Indenture dated as of March 1, 1992.. . . 4.b.13 Form 10-K 1991
(1-8291)
4.b.14 Fourteenth Supplemental Indenture dated as of November 1, 1993. . 4.b.14 Form 10-K 1993
(1-8291)
4.b.15 Fifteenth Supplemental Indenture dated as of November 1, 1993.. . 4.b.15 Form 10-K 1993
(1-8291)
4.b.16 Sixteenth Supplemental Indenture dated as of December 1, 1995.. . 4.b.16 Form 10-K 1995
(1-8291)
4.b.17 Revised form of Indenture as filed as an Exhibit to . . . . . . . 4.b.17 Form 10-Q Sept.
Registration Statement No. 33-59383. 1995 (1-8291)
4.b.18 Credit Agreement by and among Green Mountain Power, The Bank. . . 4.b.18 Form 10-K 1997
of Nova Scotia, State Street Bank and Trust Company, Fleet (1-8291)
National Bank, and Fleet National Bank, as Agent.
4.b.18(a) Amendment to Exhibit 4.b.18.. . . . . . . . . . . . . . . . . . . 4.b.18(a) Form 10-Q Sept.
1998 (1-8291)
4.b.19 Seventeenth Supplemental Indenture dated as of December 1, 2002.. 4.b.19 Form 10-K 2002
(1-8291)
10.a Form of Insurance Policy issued by Pacific Insurance Company, . . 10.a 33-8146
with respect to indemnification of Directors and Officers.
10.b.1 Firm Power Contract dated September 16, 1958, between the . . . . 13.d 2-27300
Company and the State of Vermont and supplements
thereto dated September 19, 1958; November 15, 1958;
October 1, 1960 and February 1, 1964.
10.b.2 Power Contract, dated February 1, 1968, between the Company . . . 13.d 2-34346
and Vermont Yankee Nuclear Power Corporation.
10.b.3 Amendment, dated June 1, 1972, to Power Contract between the. . . 13.f.1 2-49697
Company and Vermont Yankee Nuclear Power Corporation.
10.b.3(a) Amendment, dated April 15, 1983, to Power Contract between the. . 10.b.3(a) 33-8164
Company and Vermont Yankee Nuclear Power Corporation.
10.b.3(b) Additional Power Contract, dated February 1, 1984, between the. . 10.b.3(b) 33-8164
Company and Vermont Yankee Nuclear Power Corporation.
10.b.4 Capital Funds Agreement, dated February 1, 1968, between the. . . 13.e 2-34346
Company and Vermont Yankee Nuclear Power Corporation.
10.b.5 Amendment, dated March 12, 1968, to Capital Funds Agreement . . . 13.f 2-34346
between the Company and Vermont Yankee Nuclear Power Corporation.
10.b.6 Guarantee Agreement, dated November 5, 1981, of the Company for . 10.b.6 2-75293
its proportionate share of the obligations of Vermont Yankee
Nuclear Power Corporation under a $40 million loan arrangement.
10.b.7 Three-Party Power Agreement among the Company, VELCO and. . . . . 13.i 2-49697
Central Vermont Public Service Corporation
dated November 19, 1969.
10.b.8 Amendment to Exhibit 10.b.7, dated June 1, 1981.. . . . . . . . . 10.b.8 2-75293
10.b.9 Three-Party Transmission Agreement among the Company, VELCO . . . 10.b.9 2-49697
and Central Vermont Public Service Corporation, dated
November 21, 1969.
10.b.10 Amendment to Exhibit 10.b.9, dated June 1, 1981.. . . . . . . . . 10.b.10 2-75293
10.b.14 Agreement with Central Maine Power Company et al, to enter. . . . 5.16 2-52900
into joint ownership of Wyman plant, dated November 1, 1974.
10.b.15 New England Power Pool Agreement as amended to. . . . . . . . . . 4.8 2-55385
November 1, 1975.
10.b.16 Bulk Power Transmission Contract between the Company and. . . . . 13.v 2-49697
VELCO dated June 1, 1968.
10.b.17 Amendment to Exhibit 10.b.16, dated June 1, 1970. . . . . . . . . 13.v.i 2-49697
10.b.20 Power Sales Agreement, dated August 2, 1976, as amended . . . . . 10.b.20 33-8164
October 1, 1977, and related Transmission Agreement, with
the Massachusetts Municipal Wholesale Electric Company.
10.b.21 Agreement dated October 1, 1977, for Joint Ownership, . . . . . . 10.b.21 33-8164
Construction and Operation of the MMWEC Phase I Intermediate
Units, dated October 1, 1977.
10.b.28 Contract dated February 1, 1980, providing for the sale of firm . 10.b.28 33-8164
power and energy by the Power Authority of the State of
New York to the Vermont Public Service Board.
10.b.30 Bulk Power Purchase Contract dated April 7, 1976, between . . . . 10.b.32 2-75293
VELCO and the Company.
10.b.33 Agreement amending New England Power Pool Agreement dated as. . . 10.b.33 33-8164
of December 1, 1981, providing for use of transmission inter-
connection between New England and Hydro Quebec.
10.b.34 Phase I Transmission Line Support Agreement dated . . . . . . . . 10.b.34 33-8164
as of December 1, 1981, and Amendment No. 1 dated as of
June 1, 1982, between VETCO and participating New England
utilities for construction, use and support of Vermont
facilities of transmission interconnection between
New England and Hydro Quebec.
10.b.35 Phase I Terminal Facility Support Agreement dated as of . . . . . 10.b.35 33-8164
December 1, 1981, and Amendment No. 1 dated as of June 1,
1982, between New England Electric Transmission Corporation
and participating New England utilities for construction,
use and support of New Hampshire facilities of transmission
interconnection between New England and Hydro Quebec.
10.b.36 Agreement with respect to use of Quebec Interconnection . . . . . 10.b.36 33-8164
dated as of December 1, 1981, among participating New England
utilities for use of transmission interconnection between
New England and Hydro Quebec.
10.b.39 Vermont Participation Agreement for Quebec Interconnection. . . . 10.b.39 33-8164
dated as of July 15, 1982, between VELCO and participating
Vermont utilities for allocation of VELCO's rights and
obligations as a participating New England utility in the trans-
mission interconnection between New England and Hydro Quebec.
10.b.40 Vermont Electric Transmission Company, Inc. Capital Funds . . . . 10.b.40 33-8164
Agreement dated as of July 15, 1982, between VETCO and VELCO
for VELCO to provide capital to VETCO for construction of the
Vermont facilities of the transmission interconnection between
New England and Hydro Quebec.
10.b.41 VETCO Capital Funds Support Agreement dated as of July 15,. . . . 10.b.41 33-8164
1982, between VELCO and participating Vermont utilities for
allocation of VELCO's obligation to VETCO under the Capital
Funds Agreement.
10.b.42 Energy Banking Agreement dated March 21, 1983, among Hydro. . . . 10.b.42 33-8164
Quebec, VELCO, NEET and participating New England utilities
acting by and through the NEPOOL Management Committee for
terms of energy banking between participating New England
utilities and Hydro Quebec.
10.b.43 Interconnection Agreement dated March 21, 1983, between . . . . . 10.b.43 33-8164
Hydro Quebec and participating New England utilities acting
by and through the NEPOOL Management Committee for terms and
conditions of energy transmission between New England and
Hydro Quebec.
10.b.44 Energy Contract dated March 21, 1983, between Hydro Quebec. . . . 10.b.44 33-8164
and participating New England utilities acting by and through
the NEPOOL Management Committee for purchase of surplus energy
from Hydro Quebec.
10.b.50 Agreement for Joint Ownership, Construction and Operation of. . . 10.b.50 33-8164
the Highgate Transmission Interconnection, dated August 1,
1984, between certain electric distribution companies,
including the Company.
10.b.51 Highgate Operating and Management Agreement, dated as of. . . . . 10.b.51 33-8164
August 1, 1984, among VELCO and Vermont electric-utility
companies, including the Company.
10.b.52 Allocation Contract for Hydro Quebec Firm Power dated July 25,. . 10.b.52 33-8164
1984, between the State of Vermont and various Vermont
electric utilities, including the Company.
10.b.53 Highgate Transmission Agreement dated as of August 1, 1984, . . . 10.b.53 33-8164
between the Owners of the Project and various Vermont electric
distribution companies.
10.b.61 Agreements entered in connection with Phase II of the NEPOOL/ . . 10.b.61 33-8164
Hydro Quebec + 450 KV HVDC Transmission Interconnection.
10.b.62 Agreement between UNITIL Power Corp. and the Company to sell. . . 10.b.62 33-8164
23 MW capacity and energy from Stony Brook Intermediate
Combined Cycle Unit.
10.b.68 Firm Power and Energy Contract dated December 4, 1987, between. . 10.b.68 Form 10-K 1992
Hydro Quebec and participating Vermont utilities, including (1-8291)
the Company, for the purchase of firm power for up to
thirty years.
10.b.69 Firm Power Agreement dated as of October 26, 1987, between. . . . 10.b.69 Form 10-K 1992
Ontario Hydro and Vermont Department of Public Service. (1-8291)
10.b.70 Firm Power and Energy Contract dated as of February 23, 1987, . . 10.b.70 Form 10-K 1992
between the Vermont Joint Owners of the Highgate facilities (1-8291)
and Hydro Quebec for up to 50 MW of capacity.
10.b.70(a) Amendment to 10.b.70. . . . . . . . . . . . . . . . . . . . . . . 10.b.70(a) Form 10-K 1992
(1-8291)
10.b.71 Interconnection Agreement dated as of February 23, 1987,. . . . . 10.b.71 Form 10-K 1992
between the Vermont Joint Owners of the Highgate facilities (1-8291)
and Hydro Quebec.
10.b.72 Participation Agreement dated as of April 1, 1988, between. . . . 10.b.72 Form 10-Q
Hydro Quebec and participating Vermont utilities, including June 1988
the Company, implementing the purchase of firm power for up (1-8291)
to 30 years under the Firm Power and Energy Contract dated
December 4, 1987 (previously filed with the Company's Annual
Report on Form 10-K for 1987, Exhibit Number 10.b.68).
10.b.72(a) Restatement of the Participation Agreement filed as Exhibit . . . 10.b.72(a) Form 10-K 1988
10.b.72 on Form 10-Q for June 1988. (1-8291)
10.b.77 Firm Power and Energy Contract dated December 29, 1988, . . . . . 10.b.77 Form 10-K 1988
between Hydro Quebec and participating Vermont utilities, (1-8291)
including the Company, for the purchase of up to 54 MW of
firm power and energy.
10.b.78 Transmission Agreement dated December 23, 1988, between the . . . 10.b.78 Form 10-K 1988
Company and Niagara Mohawk Power Corporation (Niagara Mohawk), (1-8291)
for Niagara Mohawk to provide electric transmission to the
Company from Rochester Gas and Electric and Central Hudson
Gas and Electric.
10.b.81 Sales Agreement dated May 24, 1989, between the Town of . . . . . 10.b.81 Form 10-Q
Hardwick, Hardwick Electric Department and the Company for June 1989
the Company to purchase all of the output of Hardwick's
generation and (1-8291)
transmission sources and to provide Hardwick with all-
requirements energy and capacity except for that provided by
the Vermont Department of Public Service or Federal
Preference Power.
10.b.82 Sales Agreement dated July 14, 1989, between Northfield . . . . . 10.b.82 Form 10-Q
Electric Department and the Company for the Company to June 1989
purchase all of the output of Northfield's generation and (1-8291)
transmission sources and to provide Northfield with all-
requirements energy and capacity except for that provided
by the Vermont Department of Public Service or Federal
Preference Power.
10.b.85 Power Purchase and Sale Agreement between Morgan Stanley. . . . . 10.b.85 Form 10-K 1998
Capital Group Inc. and the Company. (1-8291)
10.b.90 Power Purchase Agreement between Entergy Nuclear Vermont. . . . . 10.b.90 Form 10-Q June
Yankee LLC and Vermont Yankee Nuclear Power Corporation. 2002 (1-8291)
10.b.91 First Amendment to Purchase Power Agreement listed as Exhibit . . 10.b.91 Form 10-Q June
Number 10.b.90, between Entergy Nuclear Vermont Yankee LLC 2002 (1-8291)
and Vermont Yankee Nuclear Power Corporation.
10.b.92 Amendment to Power Purchase and Sale Agreement between Morgan . . 10.b.92 Form 10-K 2002
Stanley Capital Group, Inc. and the Company. (1-8291)
10.b.93 2001 Amendatory Agreement Power Supply Agreement between. . . . . 10.b.93 Form 10-K 2004
the Company and Vermont Yankee Nuclear Power Corporation.
10.b.94 Fourth Amended and Restated Credit Agreement by and among . . . . 10.b.94 Form 10-K 2004
Green Mountain Power Corporation, Fleet National Bank,
Sovereign Bank and Fleet National Bank as Agent dated
June 16, 2004.
Management contracts or compensatory plans or arrangements required
Exhibit to be filed as exhibits to this Form 10-K pursuant to Item 14(c).,
Number all under SEC Docket 1-8291 Exhibit
-------- ------------------------------------------------------------ ----------
10.d.1b Green Mountain Power Corporation Second Amended and. . . . . 10.d.1b Form 10-K 1993
Restated Deferred Compensation Plan for Directors.
10.d.1c Green Mountain Power Corporation Second Amended and Restated 10.d.1c Form 10-K 1993
Deferred Compensation Plan for Officers.
10.d.1d Amendment No. 93.1 to the Amended and Restated Deferred. . . 10.d.1d Form 10-K 1993
Compensation Plan for Officers.
10.d.1e Amendment No. 94.1 to the Amended and Restated Deferred. . . 10.d.1e Form 10-Q
Compensation Plan for Officers. June 1994
10.d.2 Green Mountain Power Corporation Medical Expense . . . . . . 10.d.2 Form 10-K 1991
Reimbursement Plan.
10.d.4 Green Mountain Power Corporation Officers' Insurance Plan. . 10.d.4 Form 10-K 1991
10.d.4a Green Mountain Power Corporation Officers' Insurance . . . . 10.d.4a Form 10-K 1990
Plan as amended.
10.d.8 Green Mountain Power Corporation Officers' Supplemental. . . 10.d.8 Form 10-K 1990
Retirement Plan.
10.d.15c Green Mountain Power 2000 Stock Incentive Plan.. . . . . . . 10.d.15c Form 10-K 2001
10.d.40 Severance Agreement with C. L. Dutton. . . . . . . . . . . . 10.d.40 Form 10-K 2003
10.d.41 Severance Agreement with D. J. Rendall, Jr.. . . . . . . . . 10.d.41 Form 10-K 2003
10.d.42 Severance Agreement with R. J. Griffin . . . . . . . . . . . 10.d.42 Form 10-K 2003
10.d.43 Severance Agreement with W. S. Oakes . . . . . . . . . . . . 10.d.43 Form 10-K 2003
10.d.44 Severance Agreement with M. G. Powell. . . . . . . . . . . . 10.d.44 Form 10-K 2003
10.d.45 Severance Agreement with S. C. Terry . . . . . . . . . . . . 10.d.45 Form 10-K 2003
10.d.46 Deferred Stock Unit Agreement with D. J. Rendall, Jr.. . . . 10.d.46 Form 10-K 2003
10.d.47 Deferred Stock Unit Agreement with C. L. Dutton. . . . . . . 10.d.47 Form 10-K 2003
10.d.48 Deferred Stock Unit Agreement with S. C. Terry . . . . . . . 10.d.48 Form 10-K 2003
10.d.49 Deferred Stock Unit Agreement with R. J. Griffin . . . . . . 10.d.49 Form 10-K 2003
10.d.50 Deferred Stock Unit Agreement with W. S. Oakes . . . . . . . 10.d.50 Form 10-K 2003
10.d.51 Deferred Stock Unit Agreement with M. G. Powell. . . . . . . 10.d.51 Form 10-K 2003
10.d.52 Deferred Stock Unit Agreement with E. A. Bankowski . . . . . 10.d.52 Form 10-K 2003
10.d.53 Deferred Stock Unit Agreement with N. L. Brue. . . . . . . . 10.d.53 Form 10-K 2003
10.d.54 Deferred Stock Unit Agreement with W. H. Bruett. . . . . . . 10.d.54 Form 10-K 2003
10.d.55 Deferred Stock Unit Agreement with M. O. Burns . . . . . . . 10.d.55 Form 10-K 2003
10.d.56 Deferred Stock Unit Agreement with L. E. Chickering. . . . . 10.d.56 Form 10-K 2003
10.d.57 Deferred Stock Unit Agreement with J. V. Cleary. . . . . . . 10.d.57 Form 10-K 2003
10.d.58 Deferred Stock Unit Agreement with D. R. Coates. . . . . . . 10.d.58 Form 10-K 2003
10.d.59 Deferred Stock Unit Agreement with E. A. Irving. . . . . . . 10.d.59 Form 10-K 2003
10.d.60 Director Deferral Agreement with E. A. Bankowski . . . . . . 10.d.60 Form 10-K 2003
10.d.61 Director Deferral Agreement with M. O. Burns . . . . . . . . 10.d.61 Form 10-K 2003
10.d.62 Director Deferral Agreement with D. R. Coates. . . . . . . . 10.d.62 Form 10-K 2003
10.d.63 Director Deferral Agreement with E. A. Irving. . . . . . . . 10.d.63 Form 10-K 2003
10.d.64 Deferred Stock Unit Agreement with E. A. Bankowski . . . . . 10.d.64 Form 10-Q
June 2004
10.d.65 Deferred Stock Unit Agreement with N. L. Brue. . . . . . . . 10.d.65 Form 10-Q
June 2004
10.d.66 Deferred Stock Unit Agreement with W. H. Bruett. . . . . . . 10.d.66 Form 10-Q
June 2004
10.d.67 Deferred Stock Unit Agreement with M. O. Burns . . . . . . . 10.d.67 Form 10-Q
June 2004
10.d.68 Deferred Stock Unit Agreement with D. R. Coates. . . . . . . 10.d.68 Form 10-Q
June 2004
10.d.69 Deferred Stock Unit Agreement with K. C. Hoyt. . . . . . . . 10.d.69 Form 10-Q
June 2004
10.d.70 Deferred Stock Unit Agreement with E. A. Irving. . . . . . . 10.d.70 Form 10-Q
June 2004
10.d.71 Deferred Stock Unit Agreement with M. A. vanderHeyden. . . . 10.d.71 Form 10-Q
June 2004
10.d.72 Director Deferral Agreement with E. A. Bankowski . . . . . . 10.1 Form 8-K
Dec. 2, 2004
10.d.73 Director Deferral Agreement with M. O. Burns . . . . . . . . 10.2 Form 8-K
Dec. 2, 2004
10.d.74 Director Deferral Agreement with E. A. Irving. . . . . . . . 10.3 Form 8-K
Dec. 2, 2004
10.d.75 Officer Deferral Agreement with S. C. Terry. . . . . . . . . 10.4 Form 8-K
Dec. 2, 2004
10.d.76 Officer Deferral Agreement with W. S. Oakes. . . . . . . . . 10.5 Form 8-K
Dec. 2, 2004
10.d.77 Board of Directors' Resolutions Amending Deferred. . . . . . 10.1, 10.2 Form 8-K
Compensation Plan Dec. 30, 2004
10.d.78 Officer Compensation Table . . . . . . . . . . . . . . . . . 10.d.78 Form 10-K 2004
10.d.79 2005 Management Compensation Plan Description. . . . . . . . 10.d.79 Form 10-K 2004
10.d.80 Green Mountain Power Corporations Officers' Supplemental . . 10.d.80 Form 10-K 2004
Retirement Plan with C. L. Dutton
10.d.81 Green Mountain Power Corporations Officers' Supplemental . . 10.d.81 Form 10-K 2004
Retirement Plan with R. J. Griffin
10.d.82 Green Mountain Power Corporations Officers' Supplemental . . 10.d.82 Form 10-K 2004
Retirement Plan with W. S. Oakes
10.d.83 Green Mountain Power Corporations Officers' Supplemental . . 10.d.83 Form 10-K 2004
Retirement Plan with M. G. Powell
10.d.84 Green Mountain Power Corporations Officers' Supplemental . . 10.d.84 Form 10-K 2004
Retirement Plan with D. J. Rendall, Jr.
10.d.85 Green Mountain Power Corporations Officers' Supplemental . . 10.d.85 Form 10-K 2004
Retirement Plan with S. C. Terry
10.d.86 Green Mountain Power Corporation 2004 Stock Incentive Plan . 10.d.86 Form 10-K 2004
10.d.87 Green Mountain Power Corporation Third Amended and Restated. 10.d.87 Form 10-K 2004
Deferred Compensation Plan for Certain Officers.
14 Green Mountain Power Corporation's Code of Ethics. . . . . . 14 Form 10-K 2004
and Conduct dated October 6, 2003.
23.a.2 Consent of Deloitte and Touche LLP . . . . . . . . . . . . . 23.a.2
24 Limited Power of Attorney. . . . . . . . . . . . . . . . . . 24