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0000043704-07-000012.txt : 20070313
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20070313122239
ACCESSION NUMBER: 0000043704-07-000012
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 11
CONFORMED PERIOD OF REPORT: 20061231
FILED AS OF DATE: 20070313
DATE AS OF CHANGE: 20070313
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: GREEN MOUNTAIN POWER CORP
CENTRAL INDEX KEY: 0000043704
STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911]
IRS NUMBER: 030127430
STATE OF INCORPORATION: VT
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-08291
FILM NUMBER: 07689813
BUSINESS ADDRESS:
STREET 1: 163 ACORN LANE
STREET 2: .
CITY: COLCHESTER
STATE: VT
ZIP: 05446
BUSINESS PHONE: 8028645731
MAIL ADDRESS:
STREET 1: 163 ACORN LANE
STREET 2: .
CITY: COLCHESTER
STATE: VT
ZIP: 05446
10-K
1
form_10-k.htm
FORM 10-K 12312006
Form 10-K 12312006
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
[X] ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
For
the
fiscal year ended December 31, 2006
[
] TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
For
the
transition period from
to
Commission
file number: 001-08291
GREEN
MOUNTAIN POWER CORPORATION
(Exact
name of registrant as specified in its charter)
|
VERMONT
State
or other jurisdiction of
Incorporation
or organization
|
03-0127430
(I.R.S.
Employer
Identification
No.)
|
COLCHESTER
VT
(Address
of principal
Executive
offices)
|
05446
(Zip
Code)
|
Registrant’s
telephone number, including area code
(802) 864-5731
|
Securities
registered pursuant to Section 12(b) of the Act:
|
Title
of each class
COMMON
STOCK, PAR VALUE
$3.33-1/3
PER SHARE
|
Name
of each exchange on which registered
NEW
YORK STOCK EXCHANGE
|
Securities
registered pursuant to Section 12(g) of the Act:
None
|
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act. oYes þNo
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. oYes þNo
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. þYes oNo
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) 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. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check
one):
Large
accelerated filero Accelerated
filerþNon-accelerated
filero
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). oYes þNo
The
aggregate market value of the voting stock held by non-affiliates of the
registrant as of June 30, 2006, was approximately $179,174,308 based on the
closing price of $33.99 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 28,
2007, was
5,307,592.
DOCUMENTS
INCORPORATED BY REFERENCE
Certain
portions of Part III of this Form 10-K (Items 10, 11, 12, 13 and 14) will be
incorporated by reference to the Company’s Definitive Proxy Statement relating
to its Annual Meeting of Stockholders to be filed with the Commission pursuant
to Regulation 14A.
Green
Mountain Power Corporation
Form
10-K
for the fiscal year ended December 31, 2006
Table
of Contents
|
|
Page
|
Part
I
|
|
|
Item
1,
|
Business
|
3
|
Item
1A,
|
Risk
Factors
|
17
|
Item
1B,
|
Unresolved
Staff Comments
|
17
|
Item
2,
|
Properties
|
17
|
Item
3,
|
Legal
Proceedings
|
20
|
Item
4,
|
Submission
of Matters to a Vote of Security Holders
|
20
|
Part
II
|
|
|
Item
5,
|
Market
and Registrant’s Common Equity, Related
Stockholder
Matters and Issuer Purchases of
Equity
Securities
|
20
|
Item
6,
|
Selected
Financial Data
|
22
|
Item
7,
|
Management’s
Discussion and Analysis of Financial Condition
and
Results of Operations
|
23
|
Item
7A,
|
Quantitative
and Qualitative Disclosures About Market Risk
|
40
|
Item
8,
|
Financial
Statements and Supplementary Data
|
48
|
Item
9,
|
Changes
in and Disagreements with Accountants
on
Accounting and Financial Disclosure
|
83
|
Item
9A,
|
Controls
and Procedures
|
83
|
Item
9B,
|
Other
Information
|
87
|
Part
III
|
|
|
Item
10,
|
Directors
and Executive Officers of the Registrant
|
87
|
Item
11,
|
Executive
Compensation
|
87
|
Item
12,
|
Ownership
of Certain Beneficial Owners and
Management
and Related Stockholder Matters
|
87
|
Item
13,
|
Certain
Relationships and Related Transactions
|
87
|
Item
14,
|
Principal
Accounting Fees and Services
|
87
|
Part
IV
|
|
|
Item
15,
|
Exhibits
and Financial Statement Schedules
|
87
|
PART
I
FORWARD-LOOKING
STATEMENTS
This
report contains statements that may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act and Section 21E of
the
Securities Exchange Act of 1934. You can identify these statements by
forward-looking words such as "may," "could,” "should," "would," "intend,"
"will," "expect," “forecast,” "anticipate," "believe," "estimate," "continue" or
similar words. We intend these forward-looking statements to be covered by
the
safe harbor provisions for forward-looking statements contained in the Private
Securities Reform Act of 1995 and are included in this statement for purposes
of
complying with these safe harbor provisions. You should read statements that
contain these words carefully because they discuss the Company's future
expectations, contain projections of the Company's future results of operations
or financial condition, or state other "forward-looking" information.
There
may
be events in the future that we are not able to predict accurately or control
and that may cause actual results to differ materially from the expectations
described in forward-looking statements. Investors are cautioned that all
forward-looking statements involve risks and uncertainties, and actual results
may differ materially from those discussed in this document, including the
documents incorporated by reference in this document. These differences may
be
the result of various factors, including changes in general, national, regional,
or local economic conditions, changes in fuel or wholesale power supply costs,
regulatory or legislative action or decisions, and other risk factors identified
from time to time in our periodic filings with the Securities and Exchange
Commission.
The
factors referred to above include many, but not all, of the factors that could
impact the Company's ability to achieve the results described in any
forward-looking statements. You should not place undue reliance on
forward-looking statements. You should be aware that the occurrence of the
events described above and elsewhere in this document, including the documents
incorporated by reference, could harm the Company's business, prospects,
operating results or financial condition. We do not undertake any obligation
to
update any forward-looking statements as a result of future events or
developments. There
are
risks, uncertainties and other factors that could cause actual results to be
different from those projected. Some of the reasons that 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") 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 92,000 customers. The Company was incorporated under the
laws of Vermont on April 7, 1893.
Our
sources of retail and wholesale revenue for the year ended December 31, 2006
were as follows:
· |
31.3
percent from residential customers;
|
· |
31.1
percent from small commercial and industrial
customers;
|
· |
20.5
percent from large commercial and industrial
customers;
|
· |
11.1
percent from sales to other utilities;
and
|
· |
6.0
percent from other sources.
|
Approximately
94.3 percent of all of our revenue resulted from the sale of electricity for
the
period 2006 compared to 96.1 percent in 2005.
See
MD
and A, Item 7 below, for further information about revenues.
During
2006, our energy resources for retail sales of electricity were obtained as
follows:
· |
50.8
percent from hydroelectric sources (38.4 percent Hydro Quebec, 7.8
percent
Company-owned, and 4.6 percent independent power
producers);
|
· |
47.3
percent from a nuclear generating source (the Entergy Nuclear Vermont
Yankee, LLC ("ENVY") nuclear plant described below);
|
· |
2.2
percent from natural gas or oil;
and
|
· |
measurably
no percent from wind after sales of renewable energy
certificates.
|
The
4.6
percent excess of resources obtained was sold on a short-term basis through
the
wholesale market operated by ISO New England, Inc., formerly the New England
Power Pool ("NEPOOL").
In
2006,
we estimate that we purchased under existing contracts or generated
approximately 105 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. The excess of supply is sold, or in years when our demand
is
greater than our generation and long term contract resources, remaining retail
and wholesale sales were met, through short-term market purchases and sales
and
represent primarily volumetric differences between purchase commitments and
our
customers' retail demand. See Note J of Notes.
A
major
source of the Company’s power supply is our entitlement to a share of the power
generated by the 620 megawatt ("MW") nuclear generating plant owned and operated
by 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 approximately
100MW to 106MW 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 the common stock of Vermont Electric
Power Company, Inc. ("VELCO"). VELCO, through its investment in Vermont Transco
LLC (“Transco”), owns the high-voltage transmission system in Vermont. On June
30, 2006, substantially all of VELCO’s assets were transferred to Transco in
exchange for 2.4 million Class A Membership Units and Transco’s assumption of
VELCO’s debt. VELCO has a 30.8 percent ownership interest in Transco. Transco
now owns and operates the transmission system in Vermont over which bulk power
is delivered to all electric utilities in the State. The Company owns
approximately 21.9 percent of the membership units of Transco. For further
information concerning Transco, see Transco below.
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. As a RTO, ISO-NE provides 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, such as warmer than normal
temperatures in summer months, 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
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,
Colchester, 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 Transco 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,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
system peak in MW (1)
|
|
|
365.5
|
|
|
351.9
|
|
|
326.7
|
|
|
330.2
|
|
|
342.0
|
|
MWH
Production and purchases (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hydro
|
|
|
1,038,129
|
|
|
879,147
|
|
|
777,292
|
|
|
838,855
|
|
|
901,998
|
|
Wind,
net of renewable energy credits sold
|
|
|
821
|
|
|
1,484
|
|
|
-
|
|
|
8,568
|
|
|
9,577
|
|
Nuclear
|
|
|
965,080
|
|
|
816,989
|
|
|
764,010
|
|
|
884,585
|
|
|
771,781
|
|
Conventional
steam
|
|
|
87,993
|
|
|
93,258
|
|
|
89,622
|
|
|
100,402
|
|
|
85,910
|
|
Internal
combustion
|
|
|
6,239
|
|
|
7,547
|
|
|
13,026
|
|
|
12,603
|
|
|
4,090
|
|
Combined
cycle
|
|
|
38,081
|
|
|
22,328
|
|
|
32,224
|
|
|
68,488
|
|
|
81,362
|
|
Bilateral
and system purchases(3)
|
|
|
344,534
|
|
|
647,094
|
|
|
804,962
|
|
|
2,426,091
|
|
|
2,347,086
|
|
Total
production
|
|
|
2,480,877
|
|
|
2,467,847
|
|
|
2,481,136
|
|
|
4,339,592
|
|
|
4,201,804
|
|
Less:
non-firm sales to other utilities
|
|
|
439,542
|
|
|
365,000
|
|
|
408,601
|
|
|
2,284,003
|
|
|
2,104,172
|
|
Production
for firm sales
|
|
|
2,041,335
|
|
|
2,102,847
|
|
|
2,072,535
|
|
|
2,055,589
|
|
|
2,097,632
|
|
Less
firm sales
|
|
|
1,966,159
|
|
|
2,011,568
|
|
|
1,973,093
|
|
|
1,937,376
|
|
|
1,951,959
|
|
Losses
and company use (MWH)
|
|
|
75,176
|
|
|
91,279
|
|
|
99,442
|
|
|
118,213
|
|
|
145,673
|
|
Losses
as a % of total production
|
|
|
3.03
|
%
|
|
3.70
|
%
|
|
4.01
|
%
|
|
2.72
|
%
|
|
3.47
|
%
|
System
load factor (4)
|
|
|
63.8
|
%
|
|
68.2
|
%
|
|
72.4
|
%
|
|
71.1
|
%
|
|
70.0
|
%
|
Net
Production (% of Total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hydro
|
|
|
41.8
|
%
|
|
35.6
|
%
|
|
31.3
|
%
|
|
19.3
|
%
|
|
21.5
|
%
|
Wind
|
|
|
0.0
|
%
|
|
0.1
|
%
|
|
0.0
|
%
|
|
0.2
|
%
|
|
0.2
|
%
|
Nuclear
|
|
|
38.9
|
%
|
|
33.1
|
%
|
|
30.8
|
%
|
|
20.4
|
%
|
|
18.3
|
%
|
Conventional
steam
|
|
|
3.5
|
%
|
|
3.8
|
%
|
|
3.6
|
%
|
|
2.3
|
%
|
|
2.0
|
%
|
Internal
combustion
|
|
|
0.3
|
%
|
|
0.3
|
%
|
|
0.5
|
%
|
|
0.3
|
%
|
|
0.1
|
%
|
Combined
cycle
|
|
|
1.5
|
%
|
|
0.9
|
%
|
|
1.3
|
%
|
|
1.6
|
%
|
|
1.9
|
%
|
Bilateral
and system purchases
|
|
|
13.9
|
%
|
|
26.2
|
%
|
|
32.5
|
%
|
|
56.0
|
%
|
|
56.0
|
%
|
Total
|
|
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
(MWH)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
583,228
|
|
|
598,606
|
|
|
580,710
|
|
|
581,047
|
|
|
553,294
|
|
Commercial
& industrial - small
|
|
|
707,031
|
|
|
717,451
|
|
|
698,000
|
|
|
696,598
|
|
|
695,504
|
|
Commercial
& industrial - large
|
|
|
668,522
|
|
|
686,260
|
|
|
684,104
|
|
|
651,709
|
|
|
689,618
|
|
Other
|
|
|
4,143
|
|
|
5,935
|
|
|
7,112
|
|
|
4,986
|
|
|
9,773
|
|
Total
retail sales
|
|
|
1,962,924
|
|
|
2,008,252
|
|
|
1,969,926
|
|
|
1,934,340
|
|
|
1,948,189
|
|
Sales
to Municipals & Cooperatives (Rate W)
|
|
|
3,235
|
|
|
3,316
|
|
|
3,166
|
|
|
3,036
|
|
|
3,770
|
|
Total
Requirements Sales
|
|
|
1,966,159
|
|
|
2,011,568
|
|
|
1,973,093
|
|
|
1,937,376
|
|
|
1,951,959
|
|
Other
Sales for Resale
|
|
|
439,542
|
|
|
365,000
|
|
|
408,601
|
|
|
2,284,003
|
|
|
2,104,172
|
|
Total
sales (MWH)
|
|
|
2,405,701
|
|
|
2,376,568
|
|
|
2,381,694
|
|
|
4,221,379
|
|
|
4,056,131
|
|
Average
Number of Electric Customers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
77,862
|
|
|
76,481
|
|
|
75,507
|
|
|
74,693
|
|
|
73,861
|
|
Commercial
and industrial small
|
|
|
13,951
|
|
|
13,752
|
|
|
13,515
|
|
|
13,344
|
|
|
13,165
|
|
Commercial
and industrial large
|
|
|
27
|
|
|
27
|
|
|
24
|
|
|
25
|
|
|
29
|
|
Other
|
|
|
62
|
|
|
60
|
|
|
62
|
|
|
65
|
|
|
65
|
|
Total
|
|
|
91,902
|
|
|
90,320
|
|
|
89,108
|
|
|
88,127
|
|
|
87,120
|
|
Average
Revenue Per KWH (Cents)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
12.90
|
|
|
13.12
|
|
|
13.15
|
|
|
12.98
|
|
|
12.96
|
|
Commercial
& industrial - small
|
|
|
10.57
|
|
|
10.66
|
|
|
10.63
|
|
|
10.40
|
|
|
10.44
|
|
Commercial
& industrial - large
|
|
|
7.36
|
|
|
7.55
|
|
|
7.44
|
|
|
7.41
|
|
|
7.31
|
|
Total
retail
|
|
|
10.20
|
|
|
10.38
|
|
|
10.32
|
|
|
10.22
|
|
|
10.09
|
|
Average
Use and Revenue Per Residential Customer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
KWh's
|
|
|
7,491
|
|
|
7,827
|
|
|
7,691
|
|
|
7,779
|
|
|
7,491
|
|
Revenues
|
|
$
|
966
|
|
$
|
1,027
|
|
$
|
1,012
|
|
$
|
1,010
|
|
$
|
971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
MW - Megawatt is one thousand kilowatts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
MWH - Megawatt hour is one thousand kilowatt hours.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)Includes
MWh generated for renewable energy credits sold
|
|
(4)
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 also 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. Customers, 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. 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 Transco, 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 Transco as interstate public utilities under Parts II
and
III of the Federal Power Act, as amended and supplemented by the National
Energy
Act.
We
provide transmission service to ten 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 2006.
On
July
17, 1997, the FERC approved our Open Access Transmission Tariff. 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.
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.
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. When
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 was approved by the
VPSB in December, 2003. We are required to file a new, updated integrated
resource plan on or before May 15, 2007.
RECENT
RATE DEVELOPMENTS
On
December 22, 2006, the VPSB approved a rate increase of 9.09%, effective
January
1, 2007, and an Alternative Regulation Plan (the “2007 Alternative Regulation
Plan”) for the Company to be effective for three years beginning February 1,
2007. The rate increase allows us to recover increases in power and transmission
costs in 2007 compared to 2006. The 2007 Alternative Regulation Plan’s principal
components include a power supply adjustment mechanism that allows the Company
to adjust rates on a quarterly basis to reflect power supply cost changes
in
excess of $300,000 plus 90 percent of amounts in excess of $300,000 per quarter
and an earnings sharing mechanism to permit sharing of earnings in excess
of the
Company's allowed return on equity and earnings shortfalls below the Company's
allowed return on equity. The earnings sharing proposal allows the Company
to
earn up to 75 basis points above its allowed return on equity and to recover
earnings shortfalls in excess of 100 basis points below its allowed return
on
equity. Under the 2007 Alternative Regulation Plan, the Company’s allowed return
on equity is 10.25 percent for 2007. We believe the 2007 Alternative Regulation
Plan creates opportunities and incentives for the Company to become more
efficient, improve customer service, decouple earnings from increased
electricity sales, streamline cost recovery, share efficiency savings with
customers, increase credit quality, and reduce regulatory and borrowing costs
borne by customers.
During
February 2006, we requested that the VPSB grant an accounting order to allow us
to defer up to approximately $3.7 million in incremental hurricane-related
power
supply expenses incurred in the first quarter of 2006, and to also allow
us to
defer and amortize $1.3 million of incremental hurricane-related benefits
realized in the fourth quarter of 2005 against these costs. The accounting
order
was approved by the VPSB in February 2006, and allowed the Company to defer
power supply expenses of $2.1 million in the first quarter of 2006.
The
VPSB
issued an order on December 22, 2003 approving the Company's 2003 Rate Plan
(the
"2003 Rate Plan"). The 2003 Rate Plan was in effect from January 1, 2004
through
December 31, 2006. The 2003 Rate Plan:
· |
Allowed
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 cost of service schedules pursuant to the plan in November
2004, November 2005, and December 2006 respectively, and received
approval
from the VPSB to implement the plan's 1.9 percent rate increase,
effective
January 1, 2005, and the plan’s 0.9 percent rate increase, effective
January 1, 2006.
|
· |
The
2003 Rate Plan set and capped the Company's allowed return on equity
at
10.5 percent for the period beginning January 1, 2003 through December
31,
2006 and provided 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 2007 Alternative Regulation Plan and
the
2003 Rate Plan, see Item 7A. Quantitative and Qualitative Disclosures About
Market Risk - Rates and 2007 Rate Plan.
MERGERS
AND ACQUISITIONS
On
June
22, 2006, the Company announced that it had entered into an Agreement and
Plan
of Merger, dated as of June 21, 2006 (the “Merger Agreement”), among Northern
New England Energy Corporation, a Vermont corporation (“NNEEC”), Northstars
Merger Subsidiary Corporation, a Vermont corporation and wholly-owned subsidiary
of NNEEC (the “Merger Sub”), and the Company, pursuant to which Merger Sub will
be merged with and into the Company (the “Merger”). The Company will be the
surviving company in the Merger as a wholly-owned subsidiary of NNEEC. NNEEC
is
a wholly owned subsidiary of GazMétro Limited Partnership (“GazMétro”), a
limited partnership organized under the laws of the Province of
Québec.
Under
the
terms of the Merger Agreement, at the effective time of the Merger, each
issued
and outstanding share of the Company’s common stock,
including all deferred stock and stock options issued but not
exercised,
par
value $3.33 1/3 per share (other than shares which are held by any wholly-owned
subsidiary of the Company or in the treasury of the Company or which are
held by
NNEEC or Merger Sub, or any direct or indirect wholly-owned subsidiary of
NNEEC,
all of which shall cease to be outstanding and shall be canceled and none
of
which shall receive any payment with respect thereto, and other than dissenting
shares), will be converted into the right to receive $35.00 in cash, without
interest thereon.
The
Company and NNEEC have made customary representations, warranties and covenants
in the Merger Agreement. In particular, the Company covenants to NNEEC, subject
to certain exceptions, (1) not to solicit or knowingly encourage or facilitate
the making or submission of any alternative acquisition proposal nor initiate,
encourage, or participate in any discussions or negotiations with, or furnish
any non-public information to, any person (other than NNEEC or Merger Sub)
in
connection with any acquisition proposal; (2) for its Board of Directors
not to
withdraw or modify the Board's action to recommend the Merger in a manner
adverse to NNEEC; and (3) to use its best efforts to convene a special meeting
of the Company’s shareholders to consider and vote upon the approval of the
Merger Agreement and the Merger.
On
June
21, 2006, Merger Sub entered into employment agreements with the following
employees of the Company: Christopher L. Dutton, Robert J. Griffin, Mary
G.
Powell, Donald J. Rendall, Jr., Walter Oakes and Dawn D. Bugbee. These
agreements generally provide that they shall become effective upon consummation
of the Merger and that the employees subject to the employment agreements
will
continue to be employed by the Company for a period of at least three years
thereafter. Each agreement contains provisions relating to compensation,
benefits, the applicable employee’s rights upon a Change of Control (as such
term is defined in the employment agreement), confidentiality and the effect
of
the termination of an employee’s employment.
A
more
complete description of the terms of the proposed Merger is set forth in
the
Company's Current Report on Form 8-K dated June 22, 2006 and in the Company’s
Proxy Statement on Schedule 14A dated September 20, 2006.
On
October 31, 2006, a special meeting of the Company’s shareholders was held in
Colchester, Vermont to vote on the proposal to approve the Merger Agreement
so
that the Merger can occur. At such meeting, the Company’s shareholders approved
the Merger Agreement.
A
petition for approval of the Merger was filed with the VPSB on August 7,
2006
and remains pending. The VPSB completed hearings on the Merger in January
2007
and the petition is presently under advisement by the VPSB. We currently
expect
a VPSB decision whether to approve the Merger to be issued by the end of
March
2007 and, if approval is granted, what conditions to impose. A decision could
be
issued before or after the expected time; there is no deadline for issuance
of
the decision. All other regulatory approvals required for the Merger have
been
obtained.
SINGLE
CUSTOMER DEPENDENCE
The
Company’s one major retail customer, IBM, accounted for 15.0 percent, 15.3
percent and 16.4 percent of the Company’s retail operating revenues in 2006,
2005 and 2004, respectively. No other retail customer accounted for more
than
1.0 percent of our revenue during the past three years.
We
believe, based on a number of projected variables, that a hypothetical shutdown
of the IBM facility, inclusive of the tertiary effects on commercial and
residential customers, may necessitate a modest retail rate increase because
the
Company could sell some of the contracted power supply resources into the
wholesale market at prices in excess of those charged to IBM. The amount
of such
an increase would change materially as a result of any significant reductions
in
wholesale energy prices or increases in retail rates paid by IBM.
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 energy options such as propane, natural
gas or
oil for heating, cooling and water heating, and self-generation. Another
competitive risk 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 the VPSB and other State
officials determine that the public good will be served by such sales. Since
1987, the Department has made limited retail sales of electricity.
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. There are currently no regulatory proceedings,
court actions or pending legislative proposals to adopt electric industry
restructuring in Vermont.
CONSTRUCTION
AND CAPITAL REQUIREMENTS
Our
capital expenditures for 2004 through 2006 and projected for 2007 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 2,041,335 MWh of energy for retail and
requirements wholesale customers for the twelve months ended December 31,
2006.
The corresponding maximum one-hour integrated demand during that period was
365.5 MW on August 2, 2006. This compares to the previous all-time peak of
351.9
MW on July 19, 2005. 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 J of Notes.
Net
Electricity Generated and Purchased and Capacity at Peak
|
|
|
|
Generated
and Purchased
|
|
Capacity
|
|
|
|
for
the year ended
|
|
At
time of
|
|
|
|
December
31, 2006
|
|
of
annual peak
|
|
|
|
MWH
|
|
percent
|
|
KW
|
|
percent
|
|
|
|
|
|
|
|
|
|
|
|
Wholly-owned
plants:
|
|
|
|
|
|
|
|
|
|
Hydro
|
|
|
160,140
|
|
|
7.8
|
%
|
|
23,370
|
|
|
6.4
|
%
|
Diesel
and Gas Turbine
|
|
|
6,239
|
|
|
0.3
|
%
|
|
58,550
|
|
|
15.9
|
%
|
Wind*
|
|
|
821
|
|
|
0.0
|
%
|
|
960
|
|
|
0.3
|
%
|
Jointly-owned
plants:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wyman
#4
|
|
|
583
|
|
|
0.0
|
%
|
|
6,470
|
|
|
1.8
|
%
|
Stony
Brook I
|
|
|
26,116
|
|
|
1.3
|
%
|
|
30,936
|
|
|
8.4
|
%
|
McNeil
|
|
|
29,099
|
|
|
1.4
|
%
|
|
5,770
|
|
|
1.6
|
%
|
Long
Term Purchases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vermont
Yankee/ENVY
|
|
|
965,080
|
|
|
47.3
|
%
|
|
97,451
|
|
|
26.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hydro
Quebec
|
|
|
784,098
|
|
|
38.4
|
%
|
|
107,391
|
|
|
29.2
|
%
|
Stony
Brook I
|
|
|
11,965
|
|
|
0.6
|
%
|
|
14,124
|
|
|
3.8
|
%
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Independent
Power Producers
|
|
|
151,382
|
|
|
7.4
|
%
|
|
22,593
|
|
|
6.1
|
%
|
-
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
ISO-NE
and Short-term purchases, net
|
|
|
(94,188
|
)
|
|
-4.7
|
%
|
|
-
|
|
|
-
|
|
Net
Own Load
|
|
|
2,041,335
|
|
|
100.0
|
%
|
|
367,615
|
|
|
100.0
|
%
|
*Net
of renewable energy certificates sold representing
10,000MWh
|
|
|
Vermont
Yankee Nuclear Power Corporation Contract
On
July
31, 2002, VYNPC completed the sale of its nuclear power plant to ENVY. ENVY,
through its power contract with VYNPC, provides approximately 100MW to 106MW
of
the plant output to the Company through 2012, adjusted for uprate, which
is
expected to represent approximately 35 percent of our projected energy
requirements.
Prices
under the Power Purchase Agreement (the "PPA") between VYNPC and ENVY 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 in 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 is 33.6 percent. VYNPC's primary role consists of
administering its power supply contract with ENVY and its contracts with
VYNPC's
present sponsors.
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. The Company remains
responsible for procuring replacement energy at market prices during periods
of
scheduled or unscheduled outages at the ENVY plant. 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. The Company maintains insurance for unscheduled
outages for the Vermont Yankee plant and those costs are included in rates.
The
Company’s outage insurance coverage is for 60 days and includes a $1 million
deductible amount and is limited to $6 million total coverage for incremental
on-peak energy replacement costs. 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, net of insurance recoveries.
Vermont
Yankee's current operating license expires March 2012. Since the Company
no
longer owns an interest in the 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.
During
the year ended December 31, 2006, we used 965,080 MWh of Vermont Yankee energy
(supplied by ENVY) representing 47.3 percent of the net electricity generated
and purchased ("net power supply") by the Company.
See
Item
7A. Quantitative and Qualitative Disclosures About Market Risk - Other Power
Supply Risks, and Notes B and J of Notes for additional
information.
Hydro
Quebec Power Supply Contracts
Highgate
Interconnection. 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 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 control or operation of these facilities to affect the Company’s
deliveries of power from Hydro Quebec under our current power contract
commitments.
Hydro
Quebec Interconnection. VELCO and certain other ISO-NE members have entered
into
agreements with Hydro Quebec, which constructed in two phases 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, derive approximately 9.0 percent of the
total power-supply benefits associated with the ISO-NE/Hydro Quebec
interconnection. The Company, in turn, receives approximately one-third of
the
Vermont share of those benefits. The benefits of the interconnection
include:
· |
deliveries
of a portion of our contract power supply entitlements from Hydro
Quebec;
|
· |
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 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 I facilities are schedule to be retired in
2007.
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, 2006, the present
value of the Company's obligation was approximately $3.6 million. The Company's
projected future minimum payments under the Phase II support agreements are
approximately $354,000 for each of the years 2007-2011 and an aggregate of
$1.8
million for the years 2012-2015.
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 Notes B and I of Notes.
The
bulk
of our purchases from Hydro Quebec are pursuant to two power supply contract
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 $8.0 million to the Company in exchange
for
certain power purchase options. See Item 7A. Quantitative and Qualitative
Disclosures About Market Risk - Power Contract Commitments, and Note J of
Notes.
During
2006, we used 464,139 MWh under Schedule B, and 319,959 MWh under Schedule
C3 of
the VJO Contract, representing 38.4 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"). The Morgan Stanley Contract expired
on
December 31, 2006. The contract provided 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 - Power Contract Commitments and Note J of Notes.
JP
Morgan Contract
-The
Company entered into a contract with JP Morgan Ventures Energy Corporation
(the
“JP Morgan Contract”) during 2006 to purchase approximately 10 percent of the
Company’s retail load requirements for a four-year period commencing January 1,
2007 and ending December 31, 2010. The JP Morgan Contract will help the Company
cover a portion of its retail load requirements. Approximately 10 percent
of our
off-peak load remains exposed to market prices during the period 2007 - 2010,
as
well as peak and off-peak load variances caused by weather variations or
other
factors. Management will continue to monitor the markets for opportunities
to
cover the Company’s open position or purchase this energy in the spot market.
The power costs reflected in the JP Morgan Contract and the forecasted costs
of
the Company’s remaining open position are included in the Company’s 2007
rates.
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 2006, the
Company
sold 94,188 MWh representing 4.7 percent of the Company's net power
supply.
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 the ownership 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
2006, we used 38,081 MWh from this plant, representing 1.9 percent of our
net
power supply. See Notes H and J of Notes.
Wyman
Unit #4.
The W.
F. Wyman Unit #4, 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
2006, we used 583 MWh from this unit, representing less than 1.0 percent
of our
net power supply. See Note H of Notes.
McNeil
Station.
The J.C.
McNeil station (the "McNeil Plant"), located in Burlington, Vermont, is a
wood
chip and gas-fired steam plant with a capacity of 53.0 MW. The Burlington
Electric Department is the principal owner and operator of the McNeil Plant.
We
have an 11.0 percent or 5.8 MW joint ownership 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
2006, we used 29,099 MWh from this unit, representing 1.4 percent of our
net
power supply. See Note H of Notes.
Independent
Power Producers.
The VPSB
has adopted rules that implement for Vermont the purchase requirements
established by federal law in the Public Utility Regulatory Policies Act
of 1978
("PURPA"). Under the rules, qualifying facilities have the option to sell
their
output to a central state-appointed purchasing agent under a variety of
long-term and short-term, firm and non-firm pricing schedules. Each of these
schedules is based upon the projected Vermont composite system's power costs
that would be required but for the purchases from independent producers.
The
State's purchasing agent assigns the energy so purchased, and the costs of
purchase, to each Vermont retail electric utility based upon the utility’s 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' rates.
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 2006 was approximately 34.1 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
2006,
through our direct contracts and VEPPI, we purchased 151,382 MWh of qualifying
facilities production, representing 7.4 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
2006,
Company-owned hydroelectric plants produced 160,140 MWh, representing 7.8
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 transmitted power for its owners
in
Vermont, including power from the New York Power Authority and other power
contracted for by Vermont utilities. VELCO is a member of ISO-NE and represents
Vermont electric utilities in some pool and RTO matters. See Note B of Notes
and
Transco.
Transco.
In
June
2006, VELCO transferred substantially all of its assets to Transco in exchange
for 2.4 million Class A Membership Units and Transco’s assumption of VELCO’s
debt. VELCO has a 30.8 percent ownership interest in Transco. Transco now
owns
and operates the transmission system in Vermont over which bulk power is
delivered to all electric utilities in the State. The Company owns approximately
21.9 percent of the membership units of Transco. See Note B of
Notes.
Fuel.
See the
discussion about energy resources under the description of the Company in
Item
1.
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 these units during 2006. None of the utilities
from which we expect to purchase oil- or gas-fired capacity in 2006 has advised
us of any expected difficulties in securing 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.
Searsburg
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 in Searsburg, Vermont. 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 2006, the project produced 10,821 MWh,
and
the Company sold renewable energy certificates representing 10,000 MWh. Net
of
renewable energy credit sales, the wind-powered facility output represented
less
than 1.0 percent of the Company’s net power supply.
SEGMENT
INFORMATION
Financial
information about the Company's industry segment, the electric utility, is
presented in Item 6, Selected Financial Data, and in the 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.
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, 365.5 MW, occurred on August 2, 2006.
EMPLOYEES
As
of
December 31, 2006, 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
2006,
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. 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 rate design was approved by the VPSB in 2005. The new rate
design has not adversely affected operating results. The Company’s rate design
objectives are to provide a stable pricing structure and to reflect accurately
the cost of providing electric services. Our current rate design helps to
achieve these goals. Because 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.
CURTAILABLE
SERVICE
At
December 31, 2006, we had 18 customers receiving service under a curtailable
power tariff. This tariff allows customers to receive a portion of their
electricity at favorable rates except during times when energy prices or
demand
are high. 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. This program is 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 H 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. The net liability of the discontinued
segment
consists primarily of deferred tax liabilities. For information regarding
our
unregulated businesses, see Note A of Notes.
EXECUTIVE
OFFICERS
The
names, ages, and positions of our Executive Officers, in alphabetical order,
as
of March 8, 2007 are:
Dawn
D.
Bugbee 50
Vice
President, Chief Financial Officer and Treasurer since March 2006. Ms. Bugbee
was previously Chief Financial Officer at the Northwestern Medical Center,
Inc.
in St. Albans, Vermont since 1996.
Christopher
L. Dutton 58
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 50
Vice
President, Power Supply and Risk Management since March 2006. Mr. Griffin
was
Chief Financial Officer and Principal Accounting Officer from December 2003
to
March 2006. Vice President since July 2003. Treasurer from February 2002
until
March 2006. Controller from October 1996 to December 2003. Manager of General
Accounting from 1990 to 1996.
Walter
S.
Oakes 60
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 46
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. Prior to HRworks, Inc. Ms. Powell was Senior Vice President of Community
Banking for Key Bank of Vermont, from 1992 to 1997.
Donald
J.
Rendall 51
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.
The
Board
of Directors of the Company and its wholly-owned subsidiaries, as appropriate,
elect 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 will be presented
in
the Company's Proxy Statement to Shareholders, 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
1A. RISK FACTORS
The
risk
factors included in Item 7A - Quantitative and Qualitative Disclosures About
Market Risk - are incorporated by reference herein.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM
2. PROPERTIES
GENERATING
FACILITIES
Our
Vermont properties are located in five areas and are interconnected by
transmission lines of Transco and New England Power Company. We own and operate
eight hydroelectric generating stations with a total nameplate rating of
36.1
MW. We also own two gas-turbine generating stations with an aggregate nameplate
rating of 63.6 MW. We own two diesel generating stations with an aggregate
nameplate rating of 6.0 MW. We also own a wind generating facility with a
nameplate rating of 6.1 MW.
We
also
own:
· |
33.6
percent of the outstanding common stock of Vermont Yankee Nuclear
Power
Corporation and, through its contract with ENVY, we are entitled
to 106.2
MW of the capacity of the Vermont Yankee nuclear generating plant,
|
· |
1.1
percent (7.0 MW of a total 620 MW) joint-ownership share of the Wyman
#4
plant located in Maine,
|
· |
8.8
percent (30.2 MW of a total 352 MW) joint-ownership share of the
Stony Brook I intermediate units located in Massachusetts,
and
|
· |
11.0
percent (5.5 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 owned, at December 31, 2006, approximately 287 miles of overhead
transmission lines consisting of 1.5 miles of 115 kV, 10.5 miles of 69 kV,
5.4
miles of 46 kV, 267.6 miles of 34.5 kV and 2.0 miles of 13.8 kV lines. Our
distribution system included approximately 2,500 miles of overhead lines
of 2.4
to 34.5 kV and approximately 442 miles of underground cable of 2.4 to 34.5
kV.
We own approximately 104,800 kVA of substation transformer capacity in
transmission substations and 416,200 kVA of substation transformer capacity
in
distribution substations and approximately 1,025,000 kVA of transformers
for
step-down from distribution to customer use.
The
Company owns 34.8 percent of the Highgate transmission facilities, consisting
of
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 ISO-NE/Hydro Quebec interconnection.
We
also
own 29.2 percent of the common stock and 30 percent of the preferred stock
of
VELCO. The Company also owns approximately 21.9 percent of the membership
units
of Transco. VELCO has a 30.8 percent ownership interest in Transco, which
owns
and operates the high-voltage transmission system interconnecting electric
utilities in the State of Vermont.
The
VELCO/Transco properties consist of approximately 580 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 National Grid; on the south with the facilities of Vermont Yankee;
and on the north with lines of Hydro Quebec through the Highgate converter
station and tie line jointly owned by the Company and several other Vermont
utilities.
VELCO's
wholly-owned subsidiary, VETCO, owns approximately 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
E, 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.
|
|
|
|
Name
Plate
|
|
|
|
Energy
|
Rating
|
|
Location
|
Name
|
Source
|
MW
|
|
|
|
|
|
Wholly
Owned
|
|
|
|
|
Hydro
|
Middlesex,
VT
|
Middlesex
#2
|
Hydro
|
3.6
|
|
Marshfield,
VT
|
Marshfield
#6
|
Hydro
|
5.0
|
|
Vergennes,
VT
|
Vergennes
#9
|
Hydro
|
2.6
|
|
W.
Danville, VT
|
W.
Danville #15
|
Hydro
|
1.0
|
|
Colchester,
VT
|
Gorge
#18
|
Hydro
|
3.0
|
|
Essex
Jct., VT
|
Essex
#19
|
Hydro
|
7.2
|
|
Waterbury,
VT
|
Waterbury
#22 (1)
|
Hydro
|
5.5
|
|
Bolton,
VT
|
DeForge
#1
|
Hydro
|
8.4
|
Diesel
|
Vergennes,
VT
|
Vergennes
#9
|
Oil
|
4.0
|
|
Essex
Jct., VT
|
Essex
#19
|
Oil
|
2.0
|
Gas
Turbine
|
Berlin,
VT
|
Berlin
#5
|
Oil
|
46.6
|
|
Colchester,
VT
|
Gorge
#16
|
Oil
|
17.0
|
Wind
|
Searsburg,
VT
|
Searsburg
|
Wind
|
6.1
|
Jointly
Owned
|
|
|
|
|
Steam
|
Yarmouth,
ME
|
Wyman
#4
|
Oil
|
7.0
|
|
Burlington,
VT
|
McNeil
(2)
|
Wood/Gas
|
5.5
|
Combined
|
Ludlow,
MA
|
Stony
Brook #1
|
Oil/Gas
|
30.2
|
Total
Winter Capability
|
|
|
|
154.7
|
(1) Repairs
to dam are complete. Our generation facility is awaiting
re-licensing.
(2) The
Company's entitlement in McNeil is 5.5 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 H of Notes.
ITEM
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At
a
special meeting of shareholders held on October 31, 2006, there were 5,289,161
shares of common stock outstanding and entitled to vote, of which 3,921,722
were
represented in person or by proxy. The following matters were submitted to
a
vote of the Company's shareholders at the special meeting with the voting
results designated below each such matter:
1. |
Shareholders
were asked to approve or disapprove the Agreement and Plan of Merger
by
and among the Company, Northern New England Energy Corporation and
Northstars Merger Subsidiary Corporation with 3,815,744 votes for,
85,694
votes against, and 20,284 votes
abstaining.
|
2. |
Shareholders
were asked to approve or disapprove granting authority to proxy holders
to
vote in their discretion with respect to the approval of any proposal
to
postpone or adjourn the special meeting to a later date for a reasonable
business purpose, including to solicit additional proxies in favor
of the
approval of the Agreement and Plan Of Merger if there are not sufficient
votes for approval of the Agreement and Plan of Merger at the special
meeting, with 3,680,489 votes for, 212,081 votes against, and 29,152
votes
abstaining.
|
3. |
There
were no broker non-votes with respect to the matters voted upon by
shareholders at the special meeting.
|
PART
II
ITEM
5. MARKET
FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
OF EQUITY SECURITIES
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 2006 and
2005:
|
HIGH
|
LOW
|
2006
|
|
|
First
Quarter
|
$
30.50
|
$
27.10
|
Second
Quarter
|
34.00
|
27.74
|
Third
Quarter
|
34.00
|
33.00
|
Fourth
Quarter
|
34.10
|
33.22
|
2005
|
|
|
First
Quarter
|
$
30.88
|
$
27.87
|
Second
Quarter
|
30.00
|
28.85
|
Third
Quarter
|
33.03
|
28.75
|
Fourth
Quarter
|
33.08
|
26.62
|
The
number of common stockholders of record as of February 28, 2007 was
approximately 4,256, $3.33333 par value.
Quarterly
cash dividends were paid as follows during the past two years:
|
First
|
Second
|
Third
|
Fourth
|
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
2005
|
$0.25
|
$0.25
|
$0.25
|
$0.25
|
2006
|
$0.28
|
$0.28
|
$0.28
|
$0.28
|
PERFORMANCE
GRAPH
The
following performance graph presents the yearly percentage change in the
cumulative total shareholder return on the Company's Common Stock, as compared
to the cumulative total returns of the Standard and Poor's 500 Stock Index
and
that of the members of Edison Electric Institute's Index.
|
|
12/01
|
|
12/02
|
|
12/03
|
|
12/04
|
|
12/05
|
|
12/06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Green
Mountain Power Corporation
|
|
|
100.00
|
|
|
116.10
|
|
|
135.35
|
|
|
171.01
|
|
|
176.43
|
|
|
215.52
|
|
S
& P 500
|
|
|
100.00
|
|
|
77.90
|
|
|
100.24
|
|
|
111.15
|
|
|
116.61
|
|
|
135.03
|
|
EEI
Investor-Owned Electrics
|
|
|
100.00
|
|
|
85.27
|
|
|
105.30
|
|
|
129.34
|
|
|
150.09
|
|
|
181.25
|
|
ITEM
6. SELECTED FINANCIAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
Results
of Operations for the years ended December 31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
2002
|
|
In
thousands, except per share data
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
|
|
$
|
240,476
|
|
$
|
245,860
|
|
$
|
230,574
|
|
$
|
280,470
|
|
$
|
274,608
|
|
Operating
Expenses
|
|
|
224,355
|
|
|
229,779
|
|
|
215,096
|
|
|
265,164
|
|
|
259,528
|
|
Operating
Income
|
|
|
16,121
|
|
|
16,081
|
|
|
15,478
|
|
|
15,306
|
|
|
15,080
|
|
Other
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC
- equity
|
|
|
106
|
|
|
29
|
|
|
449
|
|
|
387
|
|
|
233
|
|
Other
|
|
|
1,117
|
|
|
1,696
|
|
|
1,638
|
|
|
1,692
|
|
|
2,252
|
|
Total
other income
|
|
|
1,223
|
|
|
1,725
|
|
|
2,087
|
|
|
2,079
|
|
|
2,485
|
|
Interest
Charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AFUDC
- borrowed
|
|
|
(48
|
)
|
|
(18
|
)
|
|
(285
|
)
|
|
(267
|
)
|
|
(103
|
)
|
Other
|
|
|
7,461
|
|
|
6,778
|
|
|
6,791
|
|
|
7,324
|
|
|
6,273
|
|
Total
interest charges
|
|
|
7,413
|
|
|
6,760
|
|
|
6,506
|
|
|
7,057
|
|
|
6,170
|
|
Net
Income from continuing operations before
|
|
|
9,931
|
|
|
11,046
|
|
|
11,059
|
|
|
10,328
|
|
|
11,395
|
|
preferred
dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss) from discontinued operations, including
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
provisions
for loss on disposal
|
|
|
192
|
|
|
134
|
|
|
525
|
|
|
79
|
|
|
99
|
|
Dividends
on Preferred Stock
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3
|
|
|
96
|
|
Net
Income Applicable to Common Stock
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
$
|
10,404
|
|
$
|
11,398
|
|
Common
Stock Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share-continuing operations
|
|
$
|
1.88
|
|
$
|
2.12
|
|
$
|
2.18
|
|
$
|
2.08
|
|
$
|
2.02
|
|
Basic
earnings per share-discontinued operations
|
|
$
|
0.04
|
|
$
|
0.03
|
|
$
|
0.10
|
|
$
|
0.01
|
|
$
|
0.02
|
|
Basic
earnings per share
|
|
$
|
1.92
|
|
$
|
2.15
|
|
$
|
2.28
|
|
$
|
2.09
|
|
$
|
2.04
|
|
Diluted
earnings per share from continuing operations
|
|
$
|
1.85
|
|
$
|
2.09
|
|
$
|
2.10
|
|
$
|
2.01
|
|
$
|
1.96
|
|
Diluted
earnings (loss) per share from discontinued operations
|
|
$
|
0.04
|
|
$
|
0.03
|
|
$
|
0.10
|
|
$
|
0.01
|
|
$
|
0.02
|
|
Diluted
earnings per share
|
|
$
|
1.89
|
|
$
|
2.12
|
|
$
|
2.20
|
|
$
|
2.02
|
|
$
|
1.98
|
|
Cash
dividends declared per share
|
|
$
|
1.12
|
|
$
|
1.00
|
|
$
|
0.88
|
|
$
|
0.76
|
|
$
|
0.60
|
|
Weighted
average shares outstanding-basic
|
|
|
5,270
|
|
|
5,195
|
|
|
5,083
|
|
|
4,980
|
|
|
5,592
|
|
Weighted
average equivalent shares outstanding-diluted
|
|
|
5,348
|
|
|
5,284
|
|
|
5,254
|
|
|
5,140
|
|
|
5,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Condition as of December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
In
thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Plant, Net
|
|
$
|
246,992
|
|
$
|
236,911
|
|
$
|
232,712
|
|
$
|
228,862
|
|
$
|
223,476
|
|
Other
Investments
|
|
|
37,262
|
|
|
20,663
|
|
|
18,959
|
|
|
13,706
|
|
|
21,552
|
|
Current
Assets
|
|
|
44,256
|
|
|
64,312
|
|
|
44,809
|
|
|
31,688
|
|
|
31,432
|
|
Deferred
Charges
|
|
|
57,223
|
|
|
51,729
|
|
|
55,120
|
|
|
55,590
|
|
|
60,390
|
|
Non-Utility
Assets
|
|
|
229
|
|
|
653
|
|
|
755
|
|
|
1,105
|
|
|
995
|
|
Total
Assets
|
|
$
|
385,962
|
|
$
|
374,268
|
|
$
|
352,355
|
|
$
|
330,951
|
|
$
|
337,845
|
|
Capitalization
and Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock Equity
|
|
|
126,636
|
|
$
|
117,374
|
|
$
|
109,581
|
|
$
|
99,915
|
|
$
|
91,722
|
|
Redeemable
Cumulative Preferred Stock
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
55
|
|
Long-Term
Debt, Less Current Maturities
|
|
|
109,000
|
|
|
79,000
|
|
|
93,000
|
|
|
93,000
|
|
|
93,000
|
|
Capital
Lease Obligation
|
|
|
3,562
|
|
|
3,944
|
|
|
4,493
|
|
|
4,963
|
|
|
5,287
|
|
Current
Liabilities
|
|
|
31,219
|
|
|
63,156
|
|
|
33,815
|
|
|
22,715
|
|
|
38,491
|
|
Deferred
Credits and Other
|
|
|
113,004
|
|
|
108,420
|
|
|
109,295
|
|
|
108,281
|
|
|
107,349
|
|
Non-Utility
Liabilities
|
|
|
2,541
|
|
|
2,374
|
|
|
2,171
|
|
|
2,077
|
|
|
1,941
|
|
Total
Capitalization and Liabilities
|
|
$
|
385,962
|
|
$
|
374,268
|
|
$
|
352,355
|
|
$
|
330,951
|
|
$
|
337,845
|
|
ITEM
7. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
("MD and A")
From
time
to time in this report, we may make statements that constitute “forward-looking
statements” within the meaning of the “safe-harbor” provisions of the Private
Securities Litigation Reform Act of 1995. Such statements are based on our
then
current expectations and are subject to a number of risks and uncertainties
that
could cause actual results to differ materially from those addressed in the
forward-looking statements. 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 and other regulatory
risks
|
· |
energy
supply and demand, outages and other power supply volume
risks
|
· |
power
supply price risks
|
· |
customer
concentration risks
|
· |
pension
and postretirement health care risks
|
· |
customer
service quality
|
· |
changes
in regional market and transmission rules
|
· |
contingent
obligations or rights contained in contractual
commitments
|
· |
credit
risks, including availability, terms, and use of capital and counterparty
credit quality
|
· |
general
economic and business environment
|
· |
nuclear
and environmental issues
|
· |
alternative
regulation and cost recovery (including stranded
costs)
|
· |
customer
growth and changes in customer demands,
and
|
Additional
risk factors that may cause such a difference are discussed in Item 7A,
“Quantitative and Qualitative Disclosures About Market Risk” and elsewhere
herein and are incorporated herein.
These
forward-looking statements represent our estimates and assumptions only as
of
the date of this report.
Executive
Overview
- Green
Mountain Power Corporation (the "Company") typically generates most of its
earnings from retail electricity sales. Our retail customer base typically
grows
at an average annual rate of between one and two percent, about average for
most
electric utility companies in New England. In periods of very high energy
prices, wholesale revenues and expenses arising primarily from sales and
purchases to accommodate volumetric difference between energy supplies and
customer demand can affect earnings to a significant degree. The Company’s
prices for retail electricity sales are regulated by the Vermont Public Service
Board (“VPSB”).
On
June
22, 2006, the Company announced that it had entered into an Agreement and
Plan
of Merger, dated as of June 21, 2006 (the “Merger Agreement”) under which the
Company has agreed to become a wholly-owned subsidiary of Northern New England
Energy Corporation (“NNEEC”), which is a wholly-owned subsidiary of GazMetro
Limited Partnership(“GazMetro”); a Quebec-domiciled gas distribution enterprise.
Under the Merger Agreement, all issued and outstanding shares of common stock,
including all deferred stock and stock options issued but not exercised,
of the
Company will be acquired for $35.00 per share upon closing. The merger is
summarized below under “Mergers and Acquisitions.”
The
Company increased its common stock dividend in February 2006 from an annual
rate
of $1.00 per share to $1.12 per share. The Company’s dividend payout ratio
during 2006 was approximately 60 percent of 2006 earnings from continuing
operations. The Company’s dividend payout ratio during 2005 was approximately 47
percent of 2005 earnings from continuing operations. The Merger Agreement
permits the Company to pay quarterly dividends of $0.28 per share. Under
the
Merger Agreement, the Company has agreed not to increase the dividend prior
to
the closing of the Merger without the permission of NNEEC.
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. The Company’s
allowed rate of return on its regulated operations was capped at 10.5 percent
in
2006, reduced by amounts normally excluded for purposes of setting rates
determined by the VPSB. Nearly all of the Company’s continuing operations are
treated for ratemaking purposes as regulated operations. Due principally
to
transaction costs related to the merger and exclusions mentioned above, the
Company’s 2006 return on equity was 8.35 percent. The Company operated through
December 31, 2006 under a three-year rate plan approved by the VPSB in December
2003 (the “2003 Rate Plan"). The 2003 Rate Plan covers the period 2004 - 2006
and has provided the Company with a stable, predictable rate path through
2006
and a plan for full recovery of the Company’s principal regulatory assets. The
2003 Rate Plan is described in more detail below under “Rates.”
On
December 22, 2006, the VPSB approved a rate increase of 9.09%, effective
January
1, 2007, and an Alternative Regulation Plan (the “2007 Alternative Regulation
Plan”) for the Company to be effective for three years beginning February 1,
2007. The rate increase allows the Company to recover increases in power
and
transmission costs in 2007 compared to 2006. The 2007 Alternative Regulation
Plan’s principal components include a power supply adjustment mechanism and an
earnings sharing mechanism to permit sharing of earnings in excess of the
Company's allowed return on equity and earnings shortfalls below the Company's
allowed return on equity.
For
further discussion of the Company's 2007 Alternative Regulation Plan, see
Item
7A. Quantitative and Qualitative Disclosures About Market Risk -
Rates.
MERGERS
AND ACQUISITIONS
On
June
22, 2006, the Company announced that it had entered into the Merger Agreement
with NNEEC, Northstars Merger Subsidiary Corporation, a Vermont corporation
and
a wholly-owned subsidiary of NNEEC (the “Merger Sub”), and the Company, pursuant
to which Merger Sub will be merged with and into the Company. The Company
will
be the surviving company in the Merger as a wholly-owned subsidiary of NNEEC.
NNEEC is a wholly owned subsidiary of GazMétro.
Under
the
terms of the Merger Agreement, at the effective time of the Merger, each
issued
and outstanding share of the Company’s common stock, including all deferred
stock grants and stock options issued but unexercised, par value $3.33 1/3
per
share (other than shares which are held by any wholly-owned subsidiary of
the
Company or in the treasury of the Company or which are held by NNEEC or Merger
Sub, or any direct or indirect wholly-owned subsidiary of NNEEC, all of which
shall cease to be outstanding and shall be canceled and none of which shall
receive any payment with respect thereto, and other than dissenting shares),
will be converted into the right to receive $35.00 in cash, without interest
thereon.
The
Company and NNEEC have made customary representations, warranties and covenants
in the Merger Agreement. In particular, the Company covenants to NNEEC, subject
to certain exceptions, (1) not to solicit or knowingly encourage or facilitate
the making or submission of any alternative acquisition proposal nor initiate,
encourage, or participate in any discussions or negotiations with, or furnish
any non-public information to, any person (other than NNEEC or Merger Sub)
in
connection with any acquisition proposal; (2) for its Board of Directors
not to
withdraw or modify the Board's action to recommend the Merger in a manner
adverse to NNEEC; and (3) to use its best efforts to convene a special meeting
of the Company’s shareholders to consider and vote upon the approval of the
Merger Agreement and the Merger.
On
June
21, 2006, Merger Sub entered into employment agreements with the following
employees of the Company: Christopher L. Dutton, Robert J. Griffin, Mary
G.
Powell, Donald J. Rendall, Jr., Walter Oakes and Dawn D. Bugbee. These
agreements generally provide that they shall become effective upon consummation
of the Merger and that the employees subject to the employment agreements
will
continue to be employed by the Company for a period of at least three years
thereafter. Each agreement contains provisions relating to compensation,
benefits, the applicable employee’s rights upon a Change of Control (as such
term is defined in the employment agreement), confidentiality and the effect
of
the termination of an employee’s employment.
A
more
complete description of the terms of the proposed Merger is set forth in
the
Company's Current Report on Form 8-K dated June 22, 2006 and in the Company’s
Proxy Statement on Schedule 14A dated September 20, 2006.
On
October 31, 2006, a special meeting of the Company’s shareholders was held in
Colchester, Vermont to vote on the proposal to approve the Merger Agreement
so
that the Merger can occur. At such meeting, the Company’s shareholders approved
the Merger Agreement.
A
petition for approval of the Merger was filed with the VPSB on August 7,
2006
and still remains pending. The VPSB completed hearings on the Merger in January
2007 and the petition is presently under advisement by the VPSB. We currently
expect a VPSB decision whether to approve the Merger petition to be issued
by
the end of March 2007 and, if approval is granted, what conditions to impose.
A
decision could be issued before or after the expected time; there is no deadline
for issuance of the decision.
In
2001,
as part of an order approving a retail rate settlement, the VPSB ordered
that
the Company and customers share equally any premium above book value realized
by
the Company’s shareholders in any merger, subject to an $8 million limit,
adjusted for inflation. As part of the merger approval petition, the Company
and
NNEEC proposed to satisfy this order through creation of the Green Mountain
Power Efficiency Fund (the “Efficiency Fund”), under which the Company will
invest in efficiency, renewable energy and new technology programs what will
return to our customers benefits covering the full amount required by the
2001
order. As proposed, the Company will earn a return of and on Efficiency Fund
investments. The Department of Public Service has filed testimony supporting
the
Efficiency Fund proposal. One intervener, International Business Machines
Corporation (“IBM”), filed testimony on November 21, 2006, opposing the
Efficiency Fund and requested the Board to order a refund of $8 million,
adjusted by inflation since 2001, to customers. If the VPSB rejects the proposed
Efficiency Fund and orders a refund as proposed by IBM, NNEEC could assert
such
a condition constitutes a material adverse event under the Merger Agreement.
All
other
regulatory approvals required for the Merger have been obtained.
OTHER
Power
supply expenses were equivalent to approximately 62.6 percent of total operating
expenses in 2006. 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."
We
also
discuss other risks, including customer concentration risk related to our
largest customer, 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 Transco, LLC (“Transco”), the operating subsidiary of Vermont Electric
Power Company, Inc. ("VELCO"), and an opportunity for increased 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.
|
Earnings
Summary
Earnings
Summary
|
|
For
the Years Ended
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Consolidated
diluted earnings per share of common stock
|
|
$
|
1.89
|
|
$
|
2.12
|
|
$
|
2.20
|
|
Consolidated
diluted earnings per share of common stock-continuing
operations
|
|
$
|
1.85
|
|
$
|
2.09
|
|
$
|
2.10
|
|
Consolidated
return on average common equity
|
|
|
8.35
|
%
|
|
9.85
|
%
|
|
11.06
|
%
|
Discussion
for Year Ending 2006 compared to 2005:
Earnings
per share decreased primarily as a result of $1.6 million in merger related
transactions costs incurred during 2006 in which NNEEC, an affiliate
of
GazMetro, has agreed to acquire the Company at $35.00 per common share.
The
Company's regulated earnings were capped in 2006 and 2005 to the allowed
rate of
return on equity of 10.5 percent under the Company’s rate plan, approved in
2003. The regulated earnings cap calculation excludes costs that are
not allowed
for rate setting purposes, which reduce the Company's earning potential
and
limit the Company's ability to achieve its allowed rate of return on
equity for
its operations as a whole. Revenues in excess of allowed costs are deferred
and
appear in the Company’s financial statements under the caption “Deferred
Regulatory Revenues.” The following table shows the comparative impact of the
earnings cap and merger costs on net income:
|
|
Green
Mountain Power Consolidated Earnings
|
|
|
|
Full
Year Comparative Results
|
|
|
|
2006,
2005 and 2004
|
|
|
|
Income
(in thousands)
|
|
Diluted
Earnings per Share
|
|
|
2006
|
|
2005
|
|
2004
|
|
2006
|
|
2005
|
|
2004
|
|
Net
Income
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
|
1.89
|
|
|
2.12
|
|
|
2.20
|
|
Impact
of Earnings Cap
|
|
$
|
5,732
|
|
$
|
582
|
|
$
|
0
|
|
|
|
|
|
|
|
|
|
|
Less:
Tax Effect
|
|
|
(2,293
|
)
|
|
(233
|
)
|
|
0
|
|
|
|
|
|
|
|
|
|
|
Impact
of Earnings Cap, net of taxes
|
|
|
3,439
|
|
|
349
|
|
|
0
|
|
|
0.64
|
|
|
0.07
|
|
|
0.00
|
|
Merger
Costs
|
|
$
|
1,621
|
|
$
|
0
|
|
$
|
0
|
|
|
0.30
|
|
|
0.00
|
|
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Avg Shares-Fully Diluted (in thous)
|
|
|
|
|
|
|
|
5,348
|
|
|
5,285
|
|
|
5,254
|
|
Any
deferred regulatory revenues will be applied in future years as a reduction
to
regulatory assets, or possibly refunded to customers as a credit on customer
bills, as directed by the Department of Public Service.
Retail
and other operating revenues for 2006 decreased by $3.7 million compared
with
2005, reflecting the deferral of regulatory revenues of approximately
$5.7
million, which is recorded as a reduction to revenue. The milder summer
and
winter weather caused consumption to decrease resulting in a reduction
in
revenue of $4.0 million. These impacts were partially offset by an increase
of
$3.7 million in sales of utility services to other utilities and municipalities
and approximately $2 million in additional revenue generated from the
0.9
percent rate increase that took effect in January 2006, along with a
slight
increase in the number of customers.
Total
retail megawatt hour sales of electricity decreased by 2.3 percent in
2006
compared with 2005. Sales to residential, small commercial and industrial,
and
large commercial and industrial customers in 2006 decreased by 2.7, 1.5
and 2.7
percent, respectively, compared with 2005, a year that was affected by
warmer
than normal summer temperatures. Increased revenues from the sale of
utility
services to other utilities and large industrial customers in 2006 contributed
approximately $3.7 million more to retail revenue growth than in 2005.
Other
operating expenses increased by $4.1 million in 2006, reflecting an increase
of
$3.6 million in utility services expense, compared to 2005. These sales
of
utility services are intended to build strategic expertise and revenue
to the
benefit of both customers and shareholders. The remaining $500,000 increase
in
other operating expenses related to an increase in distribution expenses.
Power
supply expenses decreased $9.5 million in 2006 compared with 2005, reflecting
increased entitlements under long-term contracts and greater output from
the
Company’s hydroelectric generating facilities, which reduced reliance on
expensive wholesale market purchases. This significant cost savings was
the major driver contributing to the amount of deferred regulatory revenues.
The
Company exercised an option to purchase more power in 2006 under its
long-term
contract with Hydro-Quebec. A temporary increase in the Company’s
entitlement from the Entergy Nuclear Vermont Yankee (“ENVY”) nuclear power plant
(the “Vermont Yankee plant”) also reduced dependence on market purchases.
Prices for additional 2006 contract entitlements and Company hydroelectric
generation were below wholesale market prices for 2006 and substantially
below
2005 wholesale market prices. Market prices in 2005 were abnormally high,
reflecting the interruption of gas supplies in the Gulf caused by hurricane
activity and warmer than normal summer temperatures.
Depreciation
and amortization expenses were $704,000 lower in 2006 compared to the
previous
year, reflecting the impact of a new depreciation schedule adopted as
a result
of a study that was completed in 2005 and implemented in 2006.
Provisions
for income taxes increased by approximately $823,000 in 2006 compared
to the
same period last year, reflecting an increase in pretax book income and
an
increase in the effective tax rate due to nondeductible merger expenses,
which
were partially offset by a 8.7% decrease in the Vermont state corporate
income
tax rate.
Equity
in
earnings of affiliates and non-utility operations increased by $1.2 million
in
2006 compared to 2005 as a result of the Company’s additional $17.1 million in
equity investments in Transco, which owns and operates most of the transmission
grid in Vermont.
The
increase in other expenses of $1.6 million in 2006 related to costs incurred
in
connection with the proposed Merger.
Earnings
from discontinued operations totaled $.04 per share in 2006, compared
with $.03
per share in 2005, primarily as a result of adjustments to tax valuation
allowances arising from the realization of tax capital losses.
On
June
30, 2006, VELCO’s assets were transferred to Transco in exchange for 2.4 million
Class A Membership Units and Transco’s assumption of VELCO’s debt. VELCO and its
employees will manage the operations of Transco under an operating agreement
that includes the Company, Central Vermont Public Service Corporation
and most
of Vermont’s electric utilities. We own approximately 29 percent of VELCO and
21.9 percent of Transco.
On
December 22, 2006 the Company received approval from the VPSB for a rate
increase of 9.09 percent effective January 1, 2007, with an allowed rate
of
return of 10.25 percent. The Company also received approval to implement
the
2007 Alternative Regulation Plan.
For
further discussion of the Company's 2007 Alternative Regulation Plan,
see Item
7A. Quantitative and Qualitative Disclosures about Market Risk -
Rates.
Discussion
for Year Ending 2005 compared to 2004:
Total
retail megawatt hour sales of electricity increased by 1.9 percent in
2005,
compared with the same period in 2004. Sales to residential and small
commercial
and industrial customers increased by 3.0 percent and 2.7 percent, respectively,
while sales to large commercial and industrial customers increased by
0.3
percent in 2005. Revenues from the sale of utility services to other
utilities
and large industrial and commercial customers increased by approximately
$4.3
million in 2005, compared with the prior year. Wholesale revenues in
2005 also
increased by $5.6 million compared with 2004, reflecting substantially
higher
wholesale energy prices in 2005. Other operating expenses increased by
$5.5
million in 2005, reflecting an increase of $4.3 million in utility services
expense. The Company’s utility services business is designed to recover some of
its administrative and staffing costs from other parties, ultimately
reducing
costs to customers and improving financial results between rate
cases.
Power
supply expenses increased $6.0 million in 2005 compared with 2004 due
to
increased costs of market purchases to serve marginal load, increased
purchases
of power under the contract with Hydro Quebec, an increase in the cost
of power
under the power supply contract with Morgan Stanley Capital Group, Inc.
(the
“Morgan Stanley Contract”), and increased costs of transmission line losses and
congestion charges allocated within the New England power pool by ISO
New
England (“ISO-NE”), the regional system operator. Congestion charges represent
the cost of delivering energy to customers and reflect energy prices,
customer
demand, and the demands on transmission and generation resources. The
Company
paid an average market price of approximately $95 per megawatt hour for
system
purchases during hours when customer demand exceeded supply during 2005,
compared to $57 per megawatt hour in the same period last year, inclusive
of the
effects of congestion and line losses. Our cost of market purchases in
2005 rose
approximately $2.3 million accordingly. Increased hydro production and
deliveries under long-term power supply contracts with Hydro Quebec and
Vermont
Yankee Nuclear Power Corporation (“VYNPC”) had a significant dampening effect on
the increase in power supply expenses the Company experienced in
2005.
Maintenance
expenses, depreciation and amortization, and transmission expenses also
increased during 2005 compared with 2004. Maintenance expenses increased
by $1.5
million, reflecting an increase in transmission and distribution line
maintenance and maintenance of our gas turbines. Depreciation and amortization
were $1.1 million higher than in the previous year, reflecting increased
plant
investments and a $539,000 increase in amortization of regulatory assets.
Transmission expenses increased by $797,000 during 2005, compared with
the prior
year, as a result of an increase in charges allocated for system support
in New
England by ISO-NE, increased retail sales of energy and an increase in
investments by VELCO, the entity that in 2005 owned and operated most
of the
transmission grid in Vermont.
Earnings
from discontinued operations totaled $.03 per share in 2005 compared
with $.10
per share in the prior year, reflecting diminished exposure to outstanding
litigation against an inactive Northern Water Resources (“NWR”) subsidiary that
led to reversal of previously recorded reserves in 2004.
Critical
Accounting Policies
We
believe 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 contracts
that
qualify as derivatives; revenue recognition, particularly as it relates
to
unbilled and deferred revenues; the assumptions that we make regarding
our
defined benefit pension and postretirement health care plans; the assumptions
that we make about derivatives; and management judgments about the expected
outcome of litigation for contingencies. These accounting policies, among
others, affect significant judgments and estimates used in the preparation
of
our consolidated financial statements.
Regulatory
Accounting
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 or
benefits,
typically treated as expenses or income by unregulated entities, to be
deferred
and expensed or benefited in future periods. Costs are deferred as regulatory
assets when the Company concludes that future revenue will be provided
to permit
recovery of the previously incurred cost. Revenue may also be deferred
as
regulatory liabilities that would be returned to customers by reducing
future
revenue requirements. The Company analyzes evidence supporting deferral,
including provisions for recovery in regulatory orders, past regulatory
precedent, other regulatory correspondence and legal representations.
Management’s conclusions on the recovery of regulatory assets represent a
critical accounting estimate.
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 satisfies the criteria under SFAS 71,
the
Company would be required to write off its regulatory assets, net of
regulatory
liabilities.
|
|
|
|
|
|
Amortizable
|
|
Regulatory
assets and liabilities
|
|
Total
|
|
|
|
2006
balances
|
|
|
|
At
December 31,
|
|
|
|
included
in rates
|
|
|
|
2006
|
|
2005
|
|
in
2007
|
|
Regulatory
assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
Demand-side
management programs
|
|
$
|
4,376
|
|
$
|
5,835
|
|
$
|
4,376
|
|
Purchased
power costs
|
|
|
3,683
|
|
|
1,812
|
|
|
3,683
|
|
Pine
Street barge canal
|
|
|
12,070
|
|
|
12,861
|
|
|
6,732
|
|
Derivative
liability regulatory assets
|
|
|
22,526
|
|
|
30,135
|
|
|
-
|
|
Pension
funding regulatory asset
|
|
|
11,789
|
|
|
-
|
|
|
-
|
|
Other
regulatory assets
|
|
|
5,954
|
|
|
5,809
|
|
|
3,559
|
|
Total
regulatory assets
|
|
|
60,398
|
|
|
56,452
|
|
|
18,350
|
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
cost of removal
|
|
|
21,494
|
|
|
21,105
|
|
|
21,494
|
|
Deferred
regulatory revenues
|
|
|
6,260
|
|
|
582
|
|
|
582
|
|
Derivative
asset regulatory liability
|
|
|
468
|
|
|
15,342
|
|
|
-
|
|
Other
regulatory liabilities
|
|
|
7,738
|
|
|
6,485
|
|
|
5,855
|
|
Other
deferred liablilities
|
|
|
5,759
|
|
|
7,737
|
|
|
3,062
|
|
Total
regulatory liabilities
|
|
|
41,719
|
|
|
51,251
|
|
|
30,993
|
|
Regulatory
assets net of regulatory liabilities
|
|
$
|
18,679
|
|
$
|
5,201
|
|
$
|
(12,643
|
)
|
The
2007
Alternative Regulation Plan provides for amortization and recovery of the
regulatory assets and regulatory liabilities as listed above, beginning January
2007, except for pension funding and the power supply portion of derivative
regulatory assets and regulatory liabilities, which will not be amortized.
The
Pine Street Barge Canal regulatory asset is subject to amortization over
a
period of 20 years without a return on the remaining balance of the asset.
The
VPSB approval of regulatory assets under the 2003 Rate Plan and the 2007
Alternative Regulation Plan has eliminated much uncertainty regarding the
recovery of these assets.
Pursuant
to the adoption by the Company of SFAS No. 158, Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106, and 132(R), a regulatory asset
for
the total unfunded pension obligation was created. The following table
summarizes the effect of adoption of SFAS 158 on the Company’s consolidated
financial statements.
|
|
|
|
|
|
SFAS
158
|
|
|
|
|
|
December
31
|
|
2006
Activity
|
|
and
regulatory
|
|
December
31
|
|
in
thousands
|
|
2005
|
|
|
|
reclassification
|
|
2006
|
|
Prepaid
pension
|
|
$
|
2,170
|
|
$
|
1,623
|
|
$
|
(3,793
|
)
|
$
|
-
|
|
Regulatory
asset FAS 158 pension funding obligation offset
|
|
|
-
|
|
|
-
|
|
|
11,789
|
|
|
11,789
|
|
Deferred
tax asset - federal
|
|
|
3,271
|
|
|
(1,749
|
)
|
|
2,459
|
|
|
3,982
|
|
Deferred
tax asset - state
|
|
|
868
|
|
|
(464
|
)
|
|
653
|
|
|
1,057
|
|
Accumulated
other comprehensive income
|
|
|
3,263
|
|
|
(3,074
|
)
|
|
(188
|
)
|
|
-
|
|
Minimum
pension funding liability
|
|
|
(5,486
|
)
|
|
5,486
|
|
|
-
|
|
|
-
|
|
Total
pension funding obligation
|
|
|
-
|
|
|
(317
|
)
|
|
(12,116
|
)
|
|
(12,433
|
)
|
SERP
liability
|
|
|
(3,897
|
)
|
|
(202
|
)
|
|
4,099
|
|
|
-
|
|
Post
retirement health care liability
|
|
|
(832
|
)
|
|
493
|
|
|
338
|
|
|
-
|
|
Deferred
tax liability - federal
|
|
|
(695
|
)
|
|
(520
|
)
|
|
(2,561
|
)
|
|
(3,776
|
)
|
Deferred
tax liability - state
|
|
|
(184
|
)
|
|
(138
|
)
|
|
(680
|
)
|
|
(1,002
|
)
|
Derivatives
The
derivative regulatory assets and liabilities represent the value of certain
power supply contracts and interest rate positions (“swaps”) that must be marked
to fair value as derivatives under current accounting rules. The fair value
of
derivatives can vary significantly based on assumptions, including interest
rates, price volatility for the power supply contracts and expected average
forward market prices. The Company records contract specified prices for
electricity as expense in the period used, as opposed to the fair market
values
of derivatives, 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 more detail under Power Supply and Other Derivatives. The
final
settlement of an interest rate swap will be amortized over the life of the
related bond issue as a component of interest expenses.
Revenue
Recognition
Our
operating revenues are derived principally from 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 (“line losses”) during transmission and distribution. The
Company estimates its range of line losses at between 3.0 percent and 5.0
percent. The Company estimates that a substantial change of 1.5 percent (e.g.,
from 3.5 percent to 5 percent) in its line loss rate used for calculating
its
unbilled revenues would result in a pre-tax change of approximately
$300,000.
Defined
Benefit Plans
The
Company's defined benefit pension and postretirement health care plans’ costs
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. See Note G in the Notes to Consolidated Financial
Statements for a discussion of sensitivities around certain defined benefit
plan
assumptions.
Contingencies
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," under "Liquidity
and Capital Resources", in Note A, "Significant Accounting Policies," in
Note G,
"Pension and Retirement Plans" and in Note H, "Commitments and
Contingencies."
Results
of Operations
Operating
Revenues and MWh Sales -
Operating revenues, megawatt hour ("MWh") sales and number of customers for
the
years ended 2006, 2005 and 2004 were as follows:
|
|
For
the Years ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(dollars
in thousands)
|
|
Operating
Revenues
|
|
|
|
|
|
|
|
Retail*
|
|
$
|
205,851
|
|
$
|
208,494
|
|
$
|
200,241
|
|
Regulatory
Revenue (Deferred) Recognized
|
|
|
(5,678
|
)
|
|
(582
|
)
|
|
2,977
|
|
Net
Retail Revenue
|
|
$
|
200,173
|
|
$
|
207,912
|
|
$
|
203,218
|
|
Sales
for Resale
|
|
|
26,642
|
|
|
28,298
|
|
|
22,652
|
|
Other
Revenues
|
|
|
13,661
|
|
|
9,650
|
|
|
4,704
|
|
Total
Operating Revenues
|
|
$
|
240,476
|
|
$
|
245,860
|
|
$
|
230,574
|
|
|
|
|
|
|
|
|
|
|
|
|
MWH
Sales-Retail
|
|
|
1,962,924
|
|
|
2,008,250
|
|
|
1,969,925
|
|
MWH
Sales for Resale
|
|
|
442,777
|
|
|
368,317
|
|
|
411,769
|
|
Total
MWH Sales
|
|
|
2,405,701
|
|
|
2,376,567
|
|
|
2,381,694
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Customers
|
|
|
|
|
|
|
|
|
|
For
the Years ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Residential
|
|
|
77,862
|
|
|
76,481
|
|
|
75,507
|
|
Commercial
and Industrial
|
|
|
13,978
|
|
|
13,779
|
|
|
13,539
|
|
Other
|
|
|
62
|
|
|
60
|
|
|
62
|
|
Total
Number of Customers
|
|
|
91,902
|
|
|
90,320
|
|
|
89,108
|
|
Comparative
changes in operating revenues are summarized below:
Change
in Operating Revenues
|
|
2005
to
|
|
2004
to
|
|
2003
to
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
Retail
Rates
|
|
$
|
2,110
|
|
$
|
4,285
|
|
$
|
(1,027
|
)
|
Regulatory
revenue (deferred) recognized
|
|
|
(5,096
|
)
|
|
(3,559
|
)
|
|
1,857
|
|
Retail
Rates, net of regulatory revenue
|
|
|
(2,986
|
)
|
|
726
|
|
|
830
|
|
Retail
Sales Volume
|
|
|
(4,753
|
)
|
|
3,968
|
|
|
3,671
|
|
Resales
and Other Revenues
|
|
|
2,355
|
|
|
10,592
|
|
|
(54,397
|
)
|
Increase
(Decrease) in Operating Revenues
|
|
$
|
(5,384
|
)
|
$
|
15,286
|
|
$
|
(49,896
|
)
|
In
2006,
retail revenues decreased $7.7 million or 3.7 percent compared with
2005, due
to:
· |
Decreased
retail residential revenues of $1.3 million, or 1.7 percent,
arising from
a 2.7 percent decrease in sales of electricity and a 0.9 percent
retail
rate increase effective January 1, 2006;
and
|
· |
Increased
retail small commercial and industrial ("C&I") revenues of $300,000,
or 0.4 percent, arising from a 1.5 percent decrease in sales
of
electricity and a 0.9 percent retail rate increase effective
January 1,
2006; and
|
· |
Decreased
retail large C&I revenues of $1.4 million or 2.6 percent, arising from
a 2.7 percent decrease in sales of electricity and a 0.9 percent
retail
rate increase effective January 1, 2006.
|
Wholesale
revenues decreased by $1.7 million in 2006 or 5.9 percent compared
with the
prior year, reflecting a 20 percent increase in volume sales but substantially
lower market prices for electricity. These lower prices also affected
the prices
paid for wholesale market purchases.
Other
operating revenue increased by $4.0 million or 41.6 percent, reflecting
a $3.7
million increase from the sale of utility services to other utilities
and large
industrial customers. Other operating expense increased by a similar
amount,
reflecting the cost of sales for these activities.
In
2005,
total retail revenues increased 4.7 million or 2.6 percent compared
with 2004,
due to:
· |
Increased
retail residential revenues of $3.5 million, or 4.7 percent,
arising from
a 3.0 percent increase in sales of electricity and a 1.9 percent
retail
rate increase effective January 1, 2005;
and
|
· |
Increased
retail small commercial and industrial ("C&I") revenues of $3.4
million, or 4.6 percent, arising from a 2.7 percent increase
in sales of
electricity and a 1.9 percent retail rate increase effective
January 1,
2005; and
|
· |
Increased
retail large C&I revenues of $1.2 million or 2.4 percent, arising from
a 0.3 percent increase in sales of electricity and a 1.9 percent
retail
rate increase effective January 1, 2005.
|
These
increases were partially offset by $3.0 million in deferred revenues
recognized
in 2004 under the 2003 Rate Plan.
Wholesale
revenues increased by $5.6 million in 2005, compared with the prior
year,
reflecting substantially higher market prices for electricity. These
higher
prices also affected the prices paid for wholesale market
purchases.
Other
operating revenue more than doubled, increasing revenue by $4.9 million
and
reflected a $4.3 million increase from the sale of utility services
to other
utilities and large industrial customers. Other operating expense increased
by a
similar amount, reflecting the cost of sales for these activities.
Power
Supply Expenses - Power
supply expenses constituted 62.6, 65.3 and 67.0 percent of total operating
expenses for the years 2006, 2005 and 2004, respectively.
The
Company’s most significant power supply contracts are the Hydro Quebec-Vermont
Joint Owners ("VJO") Contract (the "VJO Contract"), the Vermont Yankee
Nuclear
Power Corporation Contract (the "VYNPC Contract"), through which we
buy power
from ENVY’s nuclear power plant, and the Morgan Stanley Contract. The Morgan
Stanley Contract expired December 31, 2006, was replaced by a contract
with JP
Morgan Venture Energy Corporation (the “JP Morgan Contract”).
Power
supply expenses decreased $9.5 million in 2006 compared with 2005 reflecting
increased entitlements under long-term contracts and greater output
from the
Company’s hydroelectric generating facilities that reduced reliance on more
expensive wholesale market purchases and other miscellaneous purchases
as
follows:
· |
Market
purchases declined by approximately $20 million on reduced
purchases of
192,000 megawatt hours in 2006 compared to 2005. Other bilateral
contracts
declined by $2.7 million on reduced purchases of 19,000 megawatt
hours.
|
· |
Purchases
from Morgan Stanley decreased by $2.4 million reflecting the
absence of a
scheduled outage at the ENVY nuclear power plant in 2006.
|
These
decreases were offset by the following:
· |
Increased
purchases from VYNPC totaled $7.9 million on increased volumes
of 148,000
megawatt hours in 2006 compared to 2005, and resulted from
a temporary
increase in entitlements during a process (“uprate”) to increase the
output of the ENVY nuclear power plant and because 2006 had
no scheduled
outage for the plant which operates under an eighteen month
refueling
schedule.
|
· |
Increased
entitlements under the VJO Contract with Hydro-Quebec amounted
to 103,000
megawatt hours at a cost of $3.9 million, and resulted from
the VJO’s
exercise of an option to increase the load factor under the
contract.
|
· |
Increased
precipitation was principally responsible for increased purchases
from
Independent Power Producers (“IPPs”) of $3.2 million for 20,000 additional
megawatt hours.
|
· |
Hydroelectric
production was up substantially as the Company’s generation costs
increased by only $402,000 on 44,000 additional megawatt hours
of
production.
|
The
additional 2006 contract entitlements and Company hydroelectric generation
were
purchased or generated, on average, at prices below the wholesale market
price
for 2006 and substantially below 2005 wholesale market prices. Market
prices in 2005 were extremely high reflecting the interruption of gas
supplies
in the Gulf caused by hurricane activity and warmer than normal summer
temperatures.
Power
supply expenses increased by $6.0 million in 2005 when compared with
2004, and
resulted from the following:
· |
A
$2.3 million increase in the cost of market purchases caused
primarily by
higher wholesale market prices ($1.4 million) and a reduction
of credits
for the auction of transmission rights allocated by ISO-NE
($840,000);
|
· |
A
$2.3 million increase in power supply expenses under agreements
with Hydro
Quebec caused by increased megawatt hour purchases of
electricity;
|
· |
A
$1.5 million increase in purchases from Morgan Stanley caused
primarily by
an increase in contract prices; and
|
· |
A
$654,000 increase in the costs of electricity supplied by independent
power producers caused by production increases due to higher
levels of
precipitation.
|
These
increases were partially offset by a $922,000 decrease in the cost
of power
under our contract with VYNPC.
Other
Operating Expenses - Other
operating expenses increased $4.5 million, or 18.3 percent, in 2006
compared
with 2005, primarily as a result of a $3.6 million increase in expenses
associated with the sale of utility services and a $381,000 increase
in
administrative and general expenses.
Other
operating expenses increased $5.5 million, or 28.3 percent, in 2005
compared
with 2004, primarily as a result of a $4.3 million increase in expenses
associated with the sale of utility services and an $852,000 increase
in
administrative and general expenses.
Transmission
Expenses -
Transmission expenses decreased $154,000, or 0.9 percent, in 2006 compared
with
2005 resulting from regional transmission credits from ISO New England
to
VELCO.
Transmission
expenses increased $797,000, or 5.1 percent, in 2005 compared with
2004
resulting from a $400,000 increase in system-wide allocation of costs
associated
with voltage control and reactive power (“VAR”) in New England. The remainder of
the increase is due primarily to increased sales of energy and investment
in
VELCO and Transco transmission facilities allocable to the Company.
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.
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,
through its subsidiary Transco, 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 and 21.9 percent of Transco. In January
2005,
the project received regulatory approval from the VPSB. The project
is estimated
to cost approximately $200 million through 2008. VELCO intends to finance
the
costs of constructing the Northwest Reliability Project in part through
increased equity investment, primarily in Transco. In October 2004,
the Company
invested $4.6 million in VELCO to support this project and other transmission
projects. During 2006, the Company invested $17.1 million in Transco
and plans
to invest $8.4 million in 2007 for transmission infrastructure projects.
The
Company is evaluating opportunities to invest an additional $19 million
in
Transco during 2007 for similar purposes. 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 approximately
5 percent of pool transmission facility upgrades in other New England
states.
Maintenance
Expenses -
Maintenance
expense decreased $275,000 or 2.5 percent in 2006 compared with 2005
due to a
$204,000 decrease in maintenance expenditures on gas turbines.
Maintenance
expense increased $1.5 million or 15.4 percent in 2005 compared with
2004, due
to a $641,000 increase in maintenance expenditures on gas turbines
and a
$486,000 increase in distribution expenses, principally for right-of-way
maintenance programs.
Depreciation
and Amortization - Depreciation
and amortization expense decreased $704,000 in 2006 or 4.7 percent
compared with
2005 reflecting the impact of a new depreciation schedule adopted as
a result of
a study that was completed in 2005 and implemented in 2006, and a $213,000
decrease in amortization of conservation expenditures.
Depreciation
and amortization expense increased $1.1 million in 2005 or 8.2 percent
compared
with 2004 due to a $604,000 increase in depreciation of utility plant
in service
and a $539,000 increase in amortization of conservation
expenditures.
Taxes
other than income - Taxes
other than income taxes increased $252,000, or 3.8 percent, in 2006
compared
with 2005 due to a $233,000 increase in property taxes and a $19,000
increase in
gross revenue tax.
Taxes
other than income taxes decreased $98,000, or 1.5 percent, in 2005
compared with
2004 due to a $238,000 decrease in property tax offset partially by
a $144,000
increase in gross revenue tax.
Income
Taxes - Income
tax expense increased $823,000, or 14.5 percent, in 2006 compared with
2005 due
to an increase in the Company’s taxable income, $1.6 million of which was
related to nondeductible merger expenses.
Income
tax expense decreased $86,000, or 1.5 percent, in 2005 compared with
2004 due to
a decrease in the Company’s pre-tax income.
Total
Other Income (net of other deductions) -
Total
other income decreased $502,000, or 29.1 percent, in 2006 compared
with 2005
primarily due to $1.6 million in merger expense, partially offset by
increased
earnings of VELCO and earnings of Transco LLC.
Total
other income decreased $362,000, or 17.4 percent, in 2005 compared
with 2004
primarily due to $402,000 of one-time gains in 2004 on the sale of
non-utility
property, and a decrease of $420,000 in equity returns capitalized
on regulatory
assets in 2005, partially offset by increased earnings of VELCO.
Interest
Expense - Interest
expense increased $653,000, or 9.7 percent, in 2006 compared with 2005
primarily
due to the interest expense on $30 million new first mortgage bonds
issued in
2006.
Interest
expense increased $254,000, or 3.9 percent, in 2005 compared with 2004
primarily
due to a $266,000 decrease in interest capitalized on conservation
expenditures
that are being recovered under the Company’s 2003 Rate Plan. Once plant or
regulatory assets begin to be recovered in the rates we collect, interest
is no
longer capitalized on those assets.
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 were the first utility in the northeast to join the CCX,
and have
achieved our voluntary goal to reduce our emissions by 4 percent below
our 1998
- 2001 baseline average by 2006, either directly or by purchasing credits.
Participation in this program is not expected to significantly affect
Company
operating results. As part of our commitment to transparency in our
environmental, social and economic activities, we published our second
Corporate
Responsibility Report, covering 2005, in accordance with the Global
Reporting
Initiative guidelines. Investors can review the Company’s 2005 Corporate
Responsibility Report at www.greenmountainpower.biz, Who We Are, Environmental
Policies.
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 2006, 2005, and 2004, the Company
disbursed
approximately $1.4 million, $600,000, and $1.4 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 $4.5
million, net of recoveries. 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 $12.1 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 began to amortize past unrecovered
costs in
2005. The Company expects to amortize the full amount of incurred costs
over 20
years without a return. If there were a substantial increase in Pine
Street
remediation costs, it could result in an adverse impact on earnings
under the
2007 Alternative Regulation Rate Plan.
RATES
On
December 22, 2006, the VPSB approved a 9.09 percent rate increase for
the
Company, effective January 1, 2007. The rate increase allows us to
recover
increased power and transmission costs in 2007 compared to 2006. The
VPSB also
approved the Company’s 2007 Alternative Regulation Plan, effective for three
years beginning February 1, 2007. The 2007 Alternative Regulation Plan
includes
the following principal elements:
· |
A
power supply cost adjustment mechanism under which the Company
will
recover or credit to customers, on a quarterly basis, 90 percent
of power
supply costs that are $300,000 (per quarter) higher or lower
than power
supply costs included in rates.
|
· |
An
allowed rate of return on equity (“ROE”) of 10.25 percent for 2007. The
allowed ROE adjusts annually, up or down, in the amount of
one-half the
change in the ten-year Treasury bond
rate.
|
· |
An
annual earnings sharing mechanism under which the Company has
the
opportunity to earn up to 75 basis points above its allowed
ROE and to
recover earning shortfalls in excess of 100 basis points below
the allowed
ROE. Under the plan, certain exclusions, commonly made in setting
rates,
are applied to determine the Company’s earnings and are expected to affect
adversely the Company’s ability to earn its allowed rate of return on
equity for core utility operations.
|
· |
Base
rates will be adjusted annually, based on the Company’s cost of service.
Non-power supply cost increases are capped at no more than
$1.25 million
in 2008 and $1.5 million in 2009, exclusive of ROE adjustments
and
extraordinary costs in excess of $600,000 per year. Base rate
adjustments
must be approved by the VPSB.
|
· |
The
VPSB retains the authority to investigate the Company’s rates at any time
and to modify or terminate the plan.
|
The
2007
Alternative Regulation Plan creates opportunities and incentives for
the Company
to become more efficient, improve customer service, decouple earnings
from
increased electricity sales, streamline cost recovery, share efficiency
savings
with customers, increase credit quality, and reduce regulatory and
borrowing
costs borne by customers.
During
February 2006, the Company requested that the VPSB grant an accounting
order to
allow us to defer up to approximately $3.7 million in incremental
hurricane-related power supply expenses to be incurred in the first
quarter of
2006, and to also allow the Company to defer and amortize $1.3 million
of
incremental hurricane-related benefits realized in the fourth quarter
of 2005
against these costs. The accounting order was approved by the VPSB
in February
2006, allowing the Company to defer power supply expenses of $2.1 million
in the
first quarter of 2006.
On
December 22, 2003, the VPSB approved our 2003 Rate Plan, jointly proposed
by the
Company and the DPS. The 2003 Rate Plan covered the period from 2003
through
2006. Under the 2003 Rate Plan, the Company’s rates remained unchanged through
2004, increased 1.9 percent effective January 1, 2005, and increased
an
additional 0.9 percent effective January 1, 2006. We submitted a cost
of service
schedule supporting the rate increases for 2005 and 2006. The Company’s allowed
return on equity was capped at 10.5 percent for the period January
1, 2003
through December 31, 2006. Certain exclusions, commonly made in setting
rates,
prevented the Company from achieving its allowed return on equity for
its core
utility operations for 2006 and 2005. Revenues in excess of allowed
costs are
deferred and appear in the Company’s financial statements under the caption
“Deferred Regulatory Revenues.” Deferred regulatory revenues will be refunded to
customers as a credit on customer bills or applied to reduce regulatory
assets,
as the Department directs.
Under
the
2003 Rate Plan, the Company began amortizing (recovering), in January
2005,
certain regulatory assets, including Pine Street Barge Canal environmental
site
costs and past demand-side management program costs, with those amortizations
to
be allowed in future rates. Pine Street costs will be recovered over
a
twenty-year period without a return.
In
January 2001, the VPSB issued the 2001 Settlement Order, which included
the
following:
· |
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;
|
· |
The
Company and customers shall share equally any premium above
book value
realized by the Company’s shareholders 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,
|
|
|
|
2006
|
|
2005
|
|
(In
thousands)
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
2,031
|
|
$
|
6,500
|
|
Current
assets
|
|
$
|
44,256
|
|
$
|
64,312
|
|
Less
current liabilities
|
|
|
31,219
|
|
|
63,156
|
|
Net
working capital
|
|
$
|
13,037
|
|
$
|
1,156
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
$
|
18,142
|
|
$
|
29,771
|
|
Cash
and
cash equivalents decreased by approximately $4.5 million in 2006. Operating
cash
flows decreased by $11.6 million from the prior year primarily as a result
of
income tax payments. Net cash used in investing activities totaled $34.1
million, principally for investments in Transco and to construct utility
plant.
We
expect
most of our utility construction expenditures and dividends to be financed
by
net cash provided by operating activities. We expect to finance our increasing
investment in Transco through debt issuance. Material risks to cash flow
from
operations include regulatory risk, power supply risks, slower than anticipated
load growth and unfavorable economic conditions.
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. During
2006, the Company invested $17.1 million in Transco and plans to invest $8.4
million through 2007 for transmission infrastructure projects. The Company
is
evaluating opportunities to invest an additional $19 million in Transco during
2007 for similar purposes. Our planned investments will fund an increase
in the
amount of equity in Transco’s capital structure and increased transmission
investment, principally driven by construction of the Northwest Reliability
Project and other Vermont construction projects.
Future
capital expenditures, net of contributions in aid of construction of
approximately $2.5 million per year and excluding the planned investment
in
Transco, are expected to range from $25 to $28 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 2007 are as follows:
|
Generation
|
Transmission
|
Distribution
|
Other*
|
Total
|
(In
thousands)
|
|
|
|
|
|
Actual:
|
|
|
|
|
|
2004
|
$
3,053
|
$
2,898
|
$
8,662
|
$
5,005
|
$
19,618
|
2005
|
2,060
|
596
|
8,541
|
6,400
|
$
17,597
|
2006
|
$
4,895
|
$
1,001
|
$
13,869
|
$
4,581
|
$
24,346
|
Forecast:
|
|
|
|
|
|
2007
|
$
6,232
|
$
4,345
|
$
11,368
|
$
3,702
|
$
25,647
|
|
|
|
|
|
|
*
Other includes Pine Street Barge Canal net expenditures of $1.4
million in
2004
|
$600,000
in 2005, $1.4 million in 2006 and an estimated $1.1 million in
2007.
|
Dividend
Policy -
The
Company increased the annual dividend on its common stock in the first quarter
of each of the past three years. Our recent dividend history is as
follows:
Period
Reflecting
Dividend
Change
|
New
Annual
Dividend
Rate
|
Annual
Payout
Ratio
|
2006
1st
Quarter
|
1.12
|
60%
|
2005
1st
Quarter
|
1.00
|
47%
|
2004
1st
Quarter
|
.88
|
42%
|
|
|
|
Payout
ratio is computed as annual dividend rate divided by annual earnings from
continuing operations.
The
Merger Agreement with NNEEC permits the Company to pay quarterly dividends
at
the current level of $0.28 per common share. Under this agreement, the Company
has agreed not to increase the dividend prior to the closing of the merger
without the permission of NNEEC.
FINANCING
AND CAPITALIZATION
Credit
Facilities
Effective
June 14, 2006, the Company obtained a five-year revolving credit facility
of $30
million with Sovereign Bank and Key Bank replacing the expiring 364-day
revolving credit agreement with Bank of America and Sovereign Bank. The
Sovereign/Key Bank revolving credit facility is unsecured, and allows the
Company to choose any blend of a daily variable prime rate and a fixed term
LIBOR-based rate. This revolving credit facility does not include any material
adverse change or material adverse effect clauses, subsequent to the effective
date, as pre-conditions for borrowing under the facility. There was no revolving
credit short-term debt outstanding at December 31, 2006.
During
June 2005, 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 was for $30.0 million, unsecured,
and allowed the Company to choose any blend of a daily variable prime rate
and a
fixed term LIBOR-based rate. There was no short-term debt outstanding on
the
Fleet-Sovereign Agreement at December 31, 2005. There was no non-utility
short-term debt outstanding at December 31, 2005. The Fleet-Sovereign Agreement
expired June 14, 2006.
On
August
3, 2006, the Company closed on the first tranche of the new $30 million First
Mortgage Bonds, 6.53% Series, due August 1, 2036 and received $11 million
in
funds. The primary use of these funds was to partially fund additional capital
investments by the Company in Transco. The second tranche of $19 million
was
received in December 2006 and was used to repay $14 million of First Mortgage
Bonds and to repay short-term bank borrowings.
The
credit ratings of the Company's first mortgage bonds at December 31, 2006
were:
|
Moody's
|
Standard
& Poor's
|
First
mortgage bonds
|
Baa1
|
BBB
|
The
Moody’s rating at December 31, 2006 expired when the $4.0 million First Mortgage
Bonds matured in December 2006. Subsequent to year end, the Company obtained
a
Moody’s rating on the $30.0 million First Mortgage Bonds issued during 2006. The
rating was reinstated at Baa1.
PERFORMANCE
ASSURANCE
The
Company is subject to performance assurance requirements associated with
its
power purchase and sale transactions through ISO-NE under the Financial
Assurance Policy for NEPOOL members. While the Company is generally a net
seller
to ISO-NE, it must post collateral if the net amount owed exceeds its credit
limit at ISO-NE. A company’s credit limit is calculated as a percentage, based
on its credit rating, of its net worth. The Company’s present credit limit with
ISO-NE is approximately $2.9 million. ISO-NE reviews collateral requirements
on
a daily basis. As of December 31, 2006, the Company had no collateral
requirements with ISO-NE.
The
Company is also subject to performance assurance requirements under the VYNPC
Contract to purchase power from ENVY. If ENVY, the seller, has commercially
reasonable grounds for insecurity regarding the Company’s ability to pay for its
monthly purchases, ENVY may ask VYNPC and VYNPC may then ask the Company
to
provide adequate financial assurance (collateral) payments. The Company has
never been requested to post collateral under this contract.
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
Company typically utilizes EEI standard contracts for residual power supply
contractual arrangements that contain triggers that require posting of letters
of credit or other credit assurances if amounts due the creditor party exceed
certain thresholds, frequently tied to the Company’s credit rating. The JP
Morgan Contract contains certain confidential credit assurance requirements
if
the Company’s unsecured credit ratings fall below investment grade. While the
Company’s principal long-term contracts do not contain these strict provisions,
if replacement contracts were entered into today, they likely would contain
specified collateral thresholds and credit rating triggers.
The
following table presents a summary of certain material contractual obligations
and other expected payments existing as of December 31, 2006.
|
|
Future
Payments Contractually Due by Period
|
|
At
December 31, 2006
|
|
|
|
|
|
2008
and
|
|
2010
and
|
|
After
|
|
|
|
Total
|
|
2007
|
|
2009
|
|
2011
|
|
2011
|
|
|
|
(In
thousands)
|
|
Long-term
debt
|
|
$
|
109,000
|
|
$
|
-
|
|
$
|
-
|
|
$
|
6,000
|
|
$
|
103,000
|
|
Interest
on long-term debt
|
|
|
115,872
|
|
|
7,493
|
|
|
14,986
|
|
|
14,623
|
|
|
78,769
|
|
Capital
lease obligations
|
|
|
3,592
|
|
|
402
|
|
|
709
|
|
|
709
|
|
|
1,772
|
|
Hydro-Quebec
power supply contracts
|
|
|
475,117
|
|
|
52,376
|
|
|
103,582
|
|
|
105,676
|
|
|
213,483
|
|
JP
Morgan contract
|
|
|
75,680
|
|
|
17,029
|
|
|
36,973
|
|
|
21,678
|
|
|
-
|
|
Independent
Power Producers
|
|
|
120,610
|
|
|
17,145
|
|
|
31,332
|
|
|
29,619
|
|
|
42,514
|
|
Stony
Brook contract
|
|
|
23,573
|
|
|
3,858
|
|
|
7,844
|
|
|
7,878
|
|
|
3,994
|
|
VYNPC
PPA
|
|
|
189,308
|
|
|
33,744
|
|
|
73,155
|
|
|
72,118
|
|
|
10,292
|
|
Benefit
plan contributions*
|
|
|
39,366
|
|
|
3,366
|
|
|
7,150
|
|
|
7,250
|
|
|
21,600
|
|
Deferred
Compensation
|
|
|
13,136
|
|
|
1,029
|
|
|
2,850
|
|
|
2,546
|
|
|
6,711
|
|
Transco
capital contributions
|
|
|
24,930
|
|
|
8,400
|
|
|
10,730
|
|
|
5,800
|
|
|
-
|
|
Pine
Street Barge Canal remediation, excluding recoveries
|
|
|
9,629
|
|
|
1,024
|
|
|
926
|
|
|
458
|
|
|
7,221
|
|
Total
|
|
$
|
1,199,813
|
|
$
|
145,865
|
|
$
|
290,237
|
|
$
|
274,354
|
|
$
|
489,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
the captions "Power Supply Expense" and "Power Contract Commitments"
for
additional information
|
|
about
the Hydro-Quebec and JP Morgan power supply contracts
|
|
*Benefit
plan contributions and Deferred Compensation payments are estimated
through 2016
|
|
Off-Balance
Sheet Arrangements and Other Contractual Obligations - 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 own an equity interest in VELCO and Transco, which requires
the
Company to pay a portion of their operating costs, including debt service
costs.
We also own an equity interest in VYNPC in which we are obligated to pay
a
portion of VYNPC’s operating costs based on our Vermont entitlement
percentage.
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.
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
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, customer service
quality measures, 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 VJO Contract and the
VYNPC Contract, which together are expected to cover approximately 75 to
80
percent of our retail load. The Company also entered into the Morgan Stanley
Contract designed to manage wholesale electricity price risks associated
with
changing fossil fuel prices. The Morgan Stanley Contract made up approximately
an additional ten percent of our power supply resources in 2006 and expired
December 31, 2006. The Morgan Stanley Contract was replaced with the JP Morgan
Contract for the period 2007-2010. The JP Morgan Contract is expected to
supply
just under 10 percent of the Company’s retail load requirements for a four year
period commencing January 1, 2007 and ending December 31, 2010. Both the
Morgan
Stanley Contract and JP Morgan Contract terms are subject to confidentiality
agreements.
|
2006
|
2006
|
2005
|
2005
|
2004
|
2004
|
Contract
|
|
MWh
|
$/MWh
|
MWh
|
$/MWh
|
MWh
|
$/MWh
|
Expires
|
VJO
Contract
|
784,098
|
$65.38
|
680,984
|
$69.61
|
605,718
|
$74.47
|
2015
|
VYNPC
Contract
|
965,080
|
$40.15
|
816,989
|
$39.67
|
764,010
|
$43.63
|
2012
|
Purchases
under the VJO and VYNPC contract increased in 2006 reflecting the exercise
of an
option to increase the VJO load factor and the uprate of the Vermont Yankee
nuclear power plant that provided the Company with a temporary increase in
entitlement. 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 for twenty years beginning in September 1995; and (2) Schedule
C3 -- 46 megawatts of firm capacity and associated energy at any time for
20
years, beginning in November 1995.
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
Derivatives."
On
July
31, 2002, VYNPC completed the sale of its nuclear power plant to ENVY. VYNPC
entered into a Power Purchase Agreement ("PPA") with ENVY under which ENVY
is
obligated to provide between 100MW to 106MW 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. 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. Current market
prices are far above these levels so we do not expect the low market adjuster
to
affect contract pricing in the near future. We no longer bear the operating
costs and risks associated with running and decommissioning the
plant.
JP
Morgan Contract
-The
Company entered into the JP Morgan Contract during 2006 to purchase
approximately 10 percent of the Company’s retail load requirements for a four
year period commencing January 1, 2007 and ending December 31, 2010. The
JP
Morgan Contract will help the Company cover a portion of its retail load
requirements. With the JP Morgan Contract in place approximately 10 percent
of
our off-peak load remains exposed to market prices during the period 2007
-
2010, as well as peak and off-peak load variances caused by weather variations
or other factors. Management will continue to monitor the markets for
opportunities to cover the Company’s open position or purchase this energy in
the spot market. The replacement power costs reflected in the JP Morgan Contract
and the forecasted costs of the Company’s remaining open position are included
in the Company’s 2007 rates.
Power
Supply Price Risk - The
Company meets most of its customer demand through a series of long-term physical
and financial contracts. 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. There are occasions when the Company’s available supply of electricity
is insufficient to meet customer demand. During those periods, electricity
is
purchased at market prices. The Company must also purchase energy at market
prices for outages or other delivery interruptions under its principal supply
contracts.
We
expect
more than 90 percent of our estimated load requirements through 2007 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. 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. Under the
Company’s 2007 Alternative Regulation Plan approved by the VPSB in 2006, the
Company obtained an automatic power supply adjustment clause (“Power Supply
Adjustor”) to adjust rates for higher or lower energy costs without prior
regulatory approval under a formula that allows the Company to recover 90
percent of energy price increases in excess of $300,000 on a quarterly basis
or
return to customers equivalent decreases in energy prices.
As
an
example, the estimated average variation of power supply costs to rate
allowances under the Power Supply Adjustor formula for the past two years
was
$360,000, and the highest quarterly variation was $780,000. However, future
power supply adjustments could include the effects of material outages that
would cause the value of the power supply adjustment clause to be much
higher.
The
Company is charged for a number of power supply ancillary services, including
costs for congestion, line losses, reserves, and regulation that vary in
part
due to changes in the price of energy. The method of settling the cost of
congestion and other ancillary services is administered by ISO New-England
and
is subject to change. During periods of high prices, ancillary charges are
volatile and can adversely impact earnings to a significant degree. In periods
of high price volatility, we estimate that our power supply expenses could
vary
in excess of $1 million annually due to changes in line loss and congestion
costs. Congestion and loss charges represent the cost of delivering energy
to
customers and reflect energy prices, customer demand, and the demands on
transmission and generation resources.
ISO-NE
is
implementing a new forward capacity market (“FCM”) in an effort to differentiate
the price generators receive for capacity at different locations within New
England and support new investments. ISO-NE believes that proposed higher
capacity payments in constrained areas will encourage the development of
new
generation where needed. The Company has existing power supply resources
that
meet most of our present needs. Incrementally, future FCM amounts for load
growth beyond 2007 could be material, and if so, would be expected to increase
Company rate requirements accordingly. The derating of generation capacity
from
our wholly-owned units by ISO-NE could require the Company to purchase that
lost
capacity at market prices. The Company estimates that the 2007 impact of
FCM
price increases will raise our power supply expenses by approximately $1
million, pre-tax, and those costs are included in our rates.
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. Most of our principal power supply
contract counter-parties and generators, including Hydro Quebec and JP Morgan,
currently have investment grade credit ratings. ENVY does not have an investment
grade rating.
Power
Supply and Other Derivatives - The
Company’s 9701 agreement with Hydro Quebec grants Hydro Quebec an option to call
power annually at prices that are expected to be below estimated future
wholesale market prices. The terms of the 9701 agreement meet the definition
of
a derivative under Statement of Financial Accounting Standards No. 133 ("SFAS
133"). Management has estimated the fair value of the future net cost of
this
agreement at December 31, 2006 to be approximately $20.6 million. We use
forward
contracts and power supply swaps to hedge forecasted calls by Hydro Quebec
under
the 9701 agreement and treat such contracts and swaps as derivatives under
SFAS
133.
Under
the
9701 Agreement, 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). We expect Hydro Quebec to exercise this
option each year.
Hydro
Quebec exercised Option A for delivery in January and February 2007. The
Company
has covered Hydro Quebec’s 2007 call at a net cost of $4.9 million. Hydro
Quebec’s call for 2006 was made during the fourth quarter of 2005 for delivery
during January and February, timed to take advantage of extremely high forward
energy prices resulting from the effects of hurricanes Katrina and Wilma
that
interrupted gas production in the Gulf of Mexico. Energy prices in the Northeast
are heavily dependent upon natural gas prices. In February 2006, the Company
requested an accounting order from the VPSB allowing it to defer in 2006
extraordinary hurricane-related costs. The VPSB granted our request in February
2006 and we recorded a regulatory asset of approximately $2.1 million. These
costs are included in rates.
The
Company has other less significant derivative positions. The Company entered
into forward sales contracts for the months of March and April, 2007 to sell
energy excess of forecasted demand to capture forward energy prices that
were
high by historical standards. The interest rate swaps described below were
used
to hedge against rising interest rates for the issue of new first mortgage
bonds
in 2006 and 2007.
The
table
below presents the Company’s estimated market risk of the 9701 agreement and
other derivatives estimated as the potential loss in fair value resulting
from a
hypothetical ten percent adverse change in wholesale energy prices, which
nets
to $3.7 million. Actual results may differ materially from the table
illustration.
Commodity
Price Risk
|
|
At
December 31, 2006
|
|
|
|
Fair
Value
|
|
Market
Risk
|
|
|
|
(in
thousands)
|
|
Interest
rate swap
|
|
$
|
193
|
|
$
|
19
|
|
Power
supply swaps
|
|
|
(1,918
|
)
|
$
|
(654
|
)
|
9701
agreement
|
|
|
(20,608
|
)
|
|
(3,193
|
)
|
Forward
sale contracts
|
|
|
275
|
|
|
116
|
|
|
|
$
|
(22,058
|
)
|
$
|
(3,712
|
)
|
The
table
below presents assumptions used to estimate the fair value of the 9701 agreement
and other contracts treated as derivatives. 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
|
Interest
rate swap
|
Deterministic
|
n/a
|
n/a
|
n/a
|
2007
|
9701
agreement
|
Black-Scholes
|
4.4%
|
29%-10%
|
$93
|
2015
|
Forward
sale contracts
|
Deterministic
|
5%
|
n/a
|
$70
|
2007
|
Power
supply Swaps
|
Deterministic
|
4.8-5.1%
|
n/a
|
$92
|
2007-2009
|
In
March
2006, the Company entered into an interest rate swap relating to the Company’s
2006 issuance of first mortgage bonds to mitigate the risk of rising interest
rates. Approximately one-half of the new $30 million first mortgage bonds in
2006 was covered. The interest rate swap was settled on August 2, 2006, with
a
final gain on settlement of approximately $600,000, which will be amortized
over
the life of the bond issue as a component of interest expense. See Liquidity
and
Capital Resources.
In
December 2006, the Company entered into a second interest rate swap relating
to
the Company’s anticipated 2007 first mortgage bonds. Approximately $15 million
of the $20 million first mortgage bonds proposed for 2007 was covered. The
interest rate swap is still outstanding and has a fair value of $193,000 as
of
December 31, 2006. The final settlement will be amortized over the life of
the
bond issue as a component of interest expense.
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 - Hydro
Quebec had 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.
During 2004, Hydro Quebec exercised its third and last option for deliveries
occurring principally during 2005 that resulted in an incremental expense of
$3.9 million based on current market prices. Hydro Quebec also retains the
right
to curtail annual energy deliveries to the Company 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, exercised their
last
option to adjust deliveries by a five percent load factor in the fourth quarter
of 2006 for delivery effective November 1, 2006 to October 31,
2007.
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
substantially higher than VJO Contract energy costs. The VJO Contract energy
prices are approximately $30 per megawatt hour, while forward prices in 2007
have typically been in excess of $70 per megawatt hour. We expect to purchase
in
excess of 700,000 megawatt hours during 2007 under the VJO contract, so any
significant deficiencies in deliveries would increase power supply costs
materially.
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 other 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 under the step-up provision would be
approximately $692 million for the remainder of the contract, assuming that
all
other members of the VJO defaulted by January 1, 2007 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 resell the energy in the wholesale power markets
and
recover the losses, if any, and/or recover its costs from the defaulting members
or its retail customers. 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.
While
the
Vermont Yankee plant has had an excellent operating record, future unscheduled
outages could occur at times when replacement energy costs are well above VYNPC
Contract costs. Based on current forward prices, we estimate that the Company
could potentially have to pay increased costs of approximately $60,000 to
$80,000 for each day that the Vermont Yankee plant experienced an unscheduled
outage, if uncovered by insurance. The Company maintains insurance for
unscheduled outages for the Vermont Yankee plant and those costs are included
in
rates. The Company’s coverage is for 60 days of such unscheduled outage and
includes a $1 million deductible amount, with a maximum of $6 million coverage
for on-peak energy only. Historically, the VPSB has allowed the Company to
defer, rather than expense, the higher costs resulting from extraordinary
outages at the plant, not otherwise covered by insurance. 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
Vermont Yankee plant resulted in a shutdown of the 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.
The
RPP
was a part of ENVY's request to uprate or increase the output of the Vermont
Yankee nuclear plant that was approved by the VPSB. Under the RPP, we have
indemnification rights of 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. In March 2006, the Company and ENVY agreed to
a
settlement that would pay amounts to the Company sufficient to eliminate the
deferred outage costs of approximately $500,000. The settlement agreement is
subject to VPSB approval.
The
Vermont Yankee plant received final approval for uprating from the Nuclear
Regulatory Commission on March 2, 2006. Since that time the ENVY nuclear plant
output has increased to the expected uprated power level of 120 percent or
620
megawatts. While the Company has been receiving its normal share at contract
rates, it was temporarily obligated to purchase a share of uprate power at
market rates. The purchases did not have a material effect on the Company’s net
income because the Company either resold the power for a comparable price in
the
same New England market or used it, displacing other market purchases.
The
purchased power agreement between ENVY and VYNPC specifies that our percentage
of energy output under VYNPC’s contract with ENVY declines after the VY nuclear
plant uprating is completed. Post uprate, the Company believes that it is
entitled to approximately the same amount of power it received before the uprate
process began. VYNPC and ENVY are discussing the calculations, which depend
upon
determination of the pre-uprate capability of the plant, which is presently
disputed. The Company estimates the potential impact of the differing methods
of
calculation could adversely affect power supply expense by up to $600,000
annually. In the event that the VY nuclear plant is derated in the future,
then
our rights to energy output could decline proportionately to such derating.
If
this were to occur, we estimate it would have a material adverse effect on
our
power supply costs. In this event we would seek recovery of these costs in
rates.
The
Company is currently a party to a VPSB Docket that was opened to investigate
whether the reliability of the increased VY nuclear plant output will be
adversely affected by the operation of the plant’s steam dryer. On September 18,
2006, the VPSB issued a ruling requiring ENVY to provide additional ratepayer
protections that would make Vermont ratepayers whole in the event that VY must
reduce power due to uprate-related steam dryer failure. Under the VPSB ruling,
these protections will only apply to incremental replacement power costs
incurred under the terms of the PPA between ENVY and VYNPC. The additional
ratepayer protections are required to remain in effect through a period two
months after the first refueling outage in which VY operates successfully with
no steam dryer-related outages or derates. VY’s next scheduled refueling outage
is presently scheduled for May 2007. ENVY has appealed the VPSB ruling to the
Vermont Supreme Court, where the appeal is pending.
ENVY
has
announced that, under current operating parameters, it will exhaust the capacity
of its existing nuclear waste storage pool in 2008 and will need to store
nuclear waste in so-called “dry fuel storage” facilities to be constructed on
the site. ENVY received approval from the Vermont legislature in 2005 and the
VPSB in April 2006 to construct and use such dry fuel storage facilities.
Regulatory
Risk
-
Management believes that fair regulatory treatment is crucial to maintaining its
financial stability, including its ability to attract capital. Principal
regulatory risks for the Company relate to the relative frequency and magnitude
of rate increases sought in contested retail rate filings. Regulatory lag and
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. When
the
Company’s regulated earnings are capped at an allowed rate of return and certain
costs that are disallowed for rate setting purposes reduce the earnings
potential, the Company is at risk of not achieving its allowed rate of return
on
equity for its operations as a whole. The VPSB approved a retail rate increase
of 9.09 percent in 2006 to be effective January 1, 2007. Principal reasons
for
the rate increase request include forecasted higher replacement energy costs
upon expiration of the Morgan Stanley Contract on December 31, 2006, increased
energy costs for uncovered load obligations and a forecasted increase in
transmission expense.
Electric
rates in Vermont are currently among the lowest in the New England region due
in
large part to Vermont utilities’ relatively low cost, long-term contracts with
VYNPC and Hydro Quebec. Since 2001, the Company’s need for rate relief has been
modest, reflecting only scheduled rate increases of 1.9 percent in 2005 and
0.9
percent in 2006 under the 2003 Rate Plan. The 9.09 percent retail rate increase
that was approved for the Company for 2007, while significant, is below that
of
many other utility companies in Vermont and New England.
In
December 2006, the VPSB approved an Alternative Regulation Plan (the “2007
Alternative Regulation Plan”) for the Company effective February 1, 2007 and
continuing for a three-year period ending January 31, 2009 (unless extended
by
approval of the VPSB). The 2007 Alternative Regulation Plan includes a power
supply adjustment mechanism and an earnings sharing mechanism. The 2007
Alternative Regulation Plan is described in more detail below under
“Rates.”
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.
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.
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 23.3, 23.5, and 24.1 percent of the Company’s retail MWh sales in
2006, 2005, and 2004, respectively, and 15.0, 15.3, and 16.4 percent of the
Company’s retail operating revenues in 2006, 2005, and 2004, respectively. No
other retail customer accounted for more than one percent of the Company’s
revenue in any year.
Company
revenues from sales of electricity to IBM decreased $1.1 million in 2006 when
compared with 2005. Company revenue from sales of electricity to IBM decreased
by approximately $95,000 in 2005 compared with 2004. Our operating results
are
not adversely impacted by reductions in sales to IBM because IBM’s retail rates
have recently been below wholesale market prices. We believe, based on a number
of projected variables, that a hypothetical shutdown of the IBM facility,
inclusive of the tertiary effects on commercial and residential customers,
may
necessitate a modest retail rate increase. The amount of such an increase would
change materially as a result of any significant reductions in energy prices
or
increases in retail rates paid by IBM.
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, income on plan assets and,
for
our postretirement health care plan, health care cost trends. The Company
contributed approximately $3.0 million, $2.0 million, and $2.2 million to its
defined benefit plans during 2006, 2005, and 2004, respectively, and we expect
to contribute approximately $2.7 million during 2007 and in future
years.
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. This 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 is expected to reduce the rate at which postretirement healthcare
expenses grow in the future.
The
adoption of SFAS 158 for the year ended December 31, 2006 affected the Company’s
consolidated financial statements in the following ways. First, the previously
recognized amounts of Accumulated Other Comprehensive Income were reduced to
zero. Second, recognition of the total pension funding obligation created a
regulatory asset. The following table summarizes the effects of the adoption
of
SFAS 158.
|
|
|
|
|
|
SFAS
158
|
|
|
|
|
|
December
31
|
|
2006
Activity
|
|
and
regulatory
|
|
December
31
|
|
in
thousands
|
|
2005
|
|
|
|
reclassification
|
|
2006
|
|
Prepaid
pension
|
|
$
|
2,170
|
|
$
|
1,623
|
|
$
|
(3,793
|
)
|
$
|
-
|
|
Regulatory
asset FAS 158 pension funding obligation offset
|
|
|
-
|
|
|
-
|
|
|
11,789
|
|
|
11,789
|
|
Deferred
tax asset - federal
|
|
|
3,271
|
|
|
(1,749
|
)
|
|
2,459
|
|
|
3,982
|
|
Deferred
tax asset - state
|
|
|
868
|
|
|
(464
|
)
|
|
653
|
|
|
1,057
|
|
Accumulated
other comprehensive income
|
|
|
3,263
|
|
|
(3,074
|
)
|
|
(188
|
)
|
|
-
|
|
Minimum
pension funding liability
|
|
|
(5,486
|
)
|
|
5,486
|
|
|
-
|
|
|
-
|
|
Total
pension funding obligation
|
|
|
-
|
|
|
(317
|
)
|
|
(12,116
|
)
|
|
(12,433
|
)
|
SERP
liability
|
|
|
(3,897
|
)
|
|
(202
|
)
|
|
4,099
|
|
|
-
|
|
Post
retirement health care liability
|
|
|
(832
|
)
|
|
493
|
|
|
338
|
|
|
-
|
|
Deferred
tax liability - federal
|
|
|
(695
|
)
|
|
(520
|
)
|
|
(2,561
|
)
|
|
(3,776
|
)
|
Deferred
tax liability - state
|
|
|
(184
|
)
|
|
(138
|
)
|
|
(680
|
)
|
|
(1,002
|
)
|
In
2004
and 2005, a reduction in the pension plan's discount rate was primarily
responsible for increasing the OCI charge and related net liability by $566,000
and $910,000, respectively. The 2004 and 2005 OCI charges had only an indirect
effect on net income by adjusting the amount of equity used in the allowed
rate
of return on equity calculation.
Customer
Service Quality -
The
Company has agreed to customer service performance requirements that impose
penalties up to approximately $750,000 in the event that the Company does not
achieve certain goals. The Company typically exceeds the measurements, but
in
2006 fell short on three goals due to extreme weather conditions, two unusual
safety events and measurement protocol issues in our customer survey.
Nevertheless, our performance fell well within the bandwidth that avoids
financial penalties. The Company continues to enhance its use of technology
to
improve its performance and does not expect its measurements to fall below
the
prescribed penalty limits.
Weather
- The
Company periodically uses weather insurance to mitigate some of the risk of
lost
electricity sales caused by unfavorable weather conditions. The Company did
not
procure coverage for 2006 or 2005 because forward energy prices approximated
average retail rate levels.
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
For
the Years Ended December 31, 2006, 2005 and 2004
|
49
|
Consolidated
Statements of Cash Flows for the
Years
Ended December 31, 2006, 2005 and 2004
|
50
|
Consolidated
Balance Sheets as of December 31, 2006 and 2005
|
51
|
Consolidated
Statements of Changes in Stockholders’ Equity
And
Comprehensive Income for the Years Ended
December
31, 2006, 2005 and 2004
|
53
|
Notes
to Consolidated Financial Statements
|
53
|
Quarterly
Financial Information (Unaudited)
|
80
|
Reports
of Independent Registered Public Accounting Firm
|
82
|
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
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(In
thousands, except per share data)
|
|
Revenues
|
|
|
|
|
|
|
|
Retail
and other revenues
|
|
$
|
213,833
|
|
$
|
217,562
|
|
$
|
207,922
|
|
Wholesale
revenues
|
|
|
26,643
|
|
|
28,298
|
|
|
22,652
|
|
Total
operating revenues
|
|
|
240,476
|
|
|
245,860
|
|
|
230,574
|
|
Operating
expenses-Power Supply:
|
|
|
|
|
|
|
|
|
|
|
Purchases
from others
|
|
|
133,596
|
|
|
143,512
|
|
|
137,503
|
|
Company-owned
generation
|
|
|
6,880
|
|
|
6,477
|
|
|
6,516
|
|
Other
operating
|
|
|
28,898
|
|
|
24,751
|
|
|
19,295
|
|
Transmission
|
|
|
16,299
|
|
|
16,453
|
|
|
15,656
|
|
Maintenance
|
|
|
10,972
|
|
|
11,247
|
|
|
9,746
|
|
Depreciation
and amortization
|
|
|
14,370
|
|
|
15,074
|
|
|
13,931
|
|
Taxes
other than income
|
|
|
6,841
|
|
|
6,589
|
|
|
6,687
|
|
Income
taxes
|
|
|
6,499
|
|
|
5,676
|
|
|
5,762
|
|
Total
operating expenses
|
|
|
224,355
|
|
|
229,779
|
|
|
215,096
|
|
Operating
income
|
|
|
16,121
|
|
|
16,081
|
|
|
15,478
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
income
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of affiliates and non-utility operations
|
|
|
2,564
|
|
|
1,585
|
|
|
1,232
|
|
Allowance
for equity funds used during construction
|
|
|
106
|
|
|
29
|
|
|
449
|
|
Other
income
|
|
|
412
|
|
|
268
|
|
|
714
|
|
Expense
of proposed merger
|
|
|
(1,621
|
)
|
|
-
|
|
|
-
|
|
Other
deductions
|
|
|
(238
|
)
|
|
(157
|
)
|
|
(308
|
)
|
Total
other income
|
|
|
1,223
|
|
|
1,725
|
|
|
2,087
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
charges
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
6,806
|
|
|
6,534
|
|
|
6,534
|
|
Other
|
|
|
655
|
|
|
244
|
|
|
257
|
|
Allowance
for borrowed funds used during construction
|
|
|
(48
|
)
|
|
(18
|
)
|
|
(285
|
)
|
Total
interest charges
|
|
|
7,413
|
|
|
6,760
|
|
|
6,506
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
|
|
9,931
|
|
|
11,046
|
|
|
11,059
|
|
Income
from discontinued operations, net
|
|
|
192
|
|
|
134
|
|
|
525
|
|
Net
income applicable to common stock
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share-continuing operations
|
|
$
|
1.88
|
|
$
|
2.12
|
|
$
|
2.18
|
|
Basic
earnings per share-discontinued operations
|
|
|
0.04
|
|
|
0.03
|
|
|
0.10
|
|
Basic
earnings per share
|
|
$
|
1.92
|
|
$
|
2.15
|
|
$
|
2.28
|
|
Diluted
earnings per share-continuing operations
|
|
$
|
1.85
|
|
$
|
2.09
|
|
$
|
2.10
|
|
Diluted
earnings per share-discontinued operations
|
|
|
0.04
|
|
|
0.03
|
|
|
0.10
|
|
Diluted
earnings per share
|
|
$
|
1.89
|
|
$
|
2.12
|
|
$
|
2.20
|
|
Cash
dividends declared per share
|
|
$
|
1.12
|
|
$
|
1.00
|
|
$
|
0.88
|
|
Weighted
average common shares outstanding-basic
|
|
|
5,270
|
|
|
5,195
|
|
|
5,083
|
|
Weighted
average common shares outstanding-diluted
|
|
|
5,348
|
|
|
5,285
|
|
|
5,254
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
For
the Years Ended
|
|
Consolidated
Statements of Cash Flows
|
|
December
31
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Operating
Activities:
|
|
(in
thousands)
|
|
Net
income
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
Less
net income from discontinued operations
|
|
|
192
|
|
|
134
|
|
|
525
|
|
Income
from continuing operations
|
|
|
9,931
|
|
|
11,046
|
|
|
11,059
|
|
Adjustments
to reconcile net income to net cash
|
|
|
|
|
|
|
|
|
|
|
provided
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
14,370
|
|
|
15,074
|
|
|
13,931
|
|
Dividends
from associated companies
|
|
|
1,017
|
|
|
1,273
|
|
|
863
|
|
Equity
in undistributed earnings of associated companies
|
|
|
(2,268
|
)
|
|
(1,318
|
)
|
|
(880
|
)
|
Allowance
for funds used during construction
|
|
|
(154
|
)
|
|
(47
|
)
|
|
(733
|
)
|
Amortization
of deferred purchased power costs
|
|
|
2,896
|
|
|
2,581
|
|
|
318
|
|
Deferred
income tax expense, net of investment tax credit
amortization
|
|
|
(1,411
|
)
|
|
(2,563
|
)
|
|
3,699
|
|
Deferred
purchased power costs
|
|
|
(4,607
|
)
|
|
(2,023
|
)
|
|
(667
|
)
|
Deferred
regulatory revenues
|
|
|
5,678
|
|
|
2,778
|
|
|
(2,970
|
)
|
Environmental
and conservation deferrals, net
|
|
|
(1,109
|
)
|
|
(312
|
)
|
|
(1,041
|
)
|
Gain
on sale of property
|
|
|
-
|
|
|
-
|
|
|
(402
|
)
|
Share-based
compensation
|
|
|
1,816
|
|
|
1,354
|
|
|
1,244
|
|
Changes
in:
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable and accrued utility revenues
|
|
|
1,562
|
|
|
(1,705
|
)
|
|
(1,120
|
)
|
Prepayments,
fuel and other current assets
|
|
|
(3,239
|
)
|
|
(950
|
)
|
|
(418
|
)
|
Accounts
payable and other current liabilities
|
|
|
804
|
|
|
470
|
|
|
1,567
|
|
Accrued
income taxes payable and receivable
|
|
|
(5,367
|
)
|
|
6,031
|
|
|
(2,069
|
)
|
Other
|
|
|
(1,968
|
)
|
|
(2,255
|
)
|
|
1,010
|
|
Net
cash provided by continuing operations
|
|
|
17,950
|
|
|
29,434
|
|
|
23,391
|
|
Operating
cash flows from discontinued operations
|
|
|
192
|
|
|
337
|
|
|
525
|
|
Net
cash provided by operating activities
|
|
|
18,142
|
|
|
29,771
|
|
|
23,916
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
Construction
expenditures
|
|
|
(18,464
|
)
|
|
(16,978
|
)
|
|
(18,577
|
)
|
Restriction
of cash for renewable energy investments
|
|
|
1,024
|
|
|
(973
|
)
|
|
(354
|
)
|
Proceeds
from sale of property
|
|
|
-
|
|
|
-
|
|
|
648
|
|
Investment
in associated companies
|
|
|
(17,083
|
)
|
|
-
|
|
|
(4,579
|
)
|
Distributions
from associated companies
|
|
|
646
|
|
|
189
|
|
|
314
|
|
Investment
in nonutility property
|
|
|
(228
|
)
|
|
(210
|
)
|
|
(338
|
)
|
Net
cash used in investing activities
|
|
|
(34,105
|
)
|
|
(17,972
|
)
|
|
(22,886
|
)
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from bond issuance
|
|
|
30,000
|
|
|
-
|
|
|
-
|
|
Payments
on capital lease
|
|
|
(382
|
)
|
|
(187
|
)
|
|
-
|
|
Issuance
of common stock
|
|
|
1,788
|
|
|
1,373
|
|
|
1,885
|
|
Reduction
in long-term debt and term loan
|
|
|
(14,000
|
)
|
|
-
|
|
|
-
|
|
Short-term
debt
|
|
|
-
|
|
|
(3,000
|
)
|
|
2,500
|
|
Cash
dividends
|
|
|
(5,912
|
)
|
|
(5,205
|
)
|
|
(4,481
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash used in financing activities
|
|
|
11,494
|
|
|
(7,019
|
)
|
|
(96
|
)
|
Net
increase (decrease) in cash and cash equivalents
|
|
|
(4,469
|
)
|
|
4,780
|
|
|
934
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at beginning of period
|
|
|
6,500
|
|
|
1,720
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents at end of period
|
|
$
|
2,031
|
|
$
|
6,500
|
|
$
|
1,720
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosure of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for:
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
6,599
|
|
$
|
6,700
|
|
$
|
6,691
|
|
Income
taxes
|
|
|
10,211
|
|
|
2,221
|
|
|
3,043
|
|
Non-cash
construction additions
|
|
|
5,119
|
|
|
1,229
|
|
|
1,563
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
|
|
|
|
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
At
December 31,
|
|
|
|
2006
|
|
2005
|
|
ASSETS
|
|
(In
thousands)
|
|
Utility
plant
|
|
|
|
|
|
Utility
plant, at original cost
|
|
$
|
362,970
|
|
$
|
347,947
|
|
Less
accumulated depreciation
|
|
|
127,704
|
|
|
122,924
|
|
Utility
plant, net of accumulated depreciation
|
|
|
235,266
|
|
|
225,023
|
|
Property
under capital lease
|
|
|
4,060
|
|
|
4,369
|
|
Construction
work in progress
|
|
|
7,666
|
|
|
7,519
|
|
Total
utility plant, net
|
|
|
246,992
|
|
|
236,911
|
|
Other
investments
|
|
|
|
|
|
|
|
Associated
companies, at equity
|
|
|
27,768
|
|
|
10,036
|
|
Other
investments
|
|
|
9,494
|
|
|
10,627
|
|
Total
other investments
|
|
|
37,262
|
|
|
20,663
|
|
Current
assets
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
2,031
|
|
|
6,500
|
|
Accounts
receivable, less allowance for
|
|
|
|
|
|
|
|
doubtful
accounts of $401 and $484
|
|
|
17,640
|
|
|
19,594
|
|
Accrued
utility revenues
|
|
|
7,683
|
|
|
7,291
|
|
Fuel,
materials and supplies, average cost
|
|
|
6,690
|
|
|
6,360
|
|
Power
supply derivative asset
|
|
|
468
|
|
|
15,342
|
|
Power
supply regulatory asset
|
|
|
4,213
|
|
|
7,791
|
|
Prepayments
and other current assets
|
|
|
4,344
|
|
|
1,434
|
|
Income
tax receivable
|
|
|
1,187
|
|
|
-
|
|
Total
current assets
|
|
|
44,256
|
|
|
64,312
|
|
Deferred
charges
|
|
|
|
|
|
|
|
Demand
side management programs
|
|
|
4,376
|
|
|
5,835
|
|
Purchased
power costs
|
|
|
3,683
|
|
|
1,812
|
|
Pine
Street Barge Canal
|
|
|
12,070
|
|
|
12,861
|
|
Power
supply regulatory asset
|
|
|
18,313
|
|
|
22,344
|
|
Pension
funding regulatory asset
|
|
|
11,789
|
|
|
-
|
|
Other
regulatory assets
|
|
|
5,954
|
|
|
5,809
|
|
Other
deferred charges
|
|
|
1,038
|
|
|
3,068
|
|
Total
deferred charges
|
|
|
57,223
|
|
|
51,729
|
|
Non-utility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
and equipment
|
|
|
-
|
|
|
246
|
|
Other
assets
|
|
|
229
|
|
|
407
|
|
Total
non-utility assets
|
|
|
229
|
|
|
653
|
|
Total
assets
|
|
$
|
385,962
|
|
$
|
374,268
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
|
|
|
|
Consolidated
Balance Sheets
|
|
|
|
|
|
|
|
At
December 31,
|
|
|
|
2006
|
|
2005
|
|
CAPITALIZATION
AND LIABILITIES
|
|
(In
thousands except share data)
|
|
Capitalization
|
|
|
|
|
|
Common
stock, $3.33 1/3 par value,
|
|
|
|
|
|
authorized
10,000,000 shares (issued
|
|
|
|
|
|
6,131,489
and 6,060,962)
|
|
$
|
20,438
|
|
$
|
20,203
|
|
Additional
paid-in capital
|
|
|
82,824
|
|
|
81,271
|
|
Retained
earnings
|
|
|
40,075
|
|
|
35,864
|
|
Accumulated
other comprehensive income
|
|
|
-
|
|
|
(3,263
|
)
|
Treasury
stock, at cost (827,639 shares)
|
|
|
(16,701
|
)
|
|
(16,701
|
)
|
Total
common stock equity
|
|
|
126,636
|
|
|
117,374
|
|
Long-term
debt, less current maturities
|
|
|
109,000
|
|
|
79,000
|
|
Total
capitalization
|
|
|
235,636
|
|
|
196,374
|
|
Capital
lease obligation
|
|
|
3,562
|
|
|
3,944
|
|
Current
liabilities
|
|
|
|
|
|
|
|
Current
portion of long term debt
|
|
|
-
|
|
|
14,000
|
|
Accounts
payable, trade and accrued liabilities
|
|
|
18,575
|
|
|
14,196
|
|
Accounts
payable to associated companies
|
|
|
1,338
|
|
|
1,483
|
|
Accrued
taxes
|
|
|
1,423
|
|
|
5,603
|
|
Power
supply derivative liability
|
|
|
4,213
|
|
|
7,791
|
|
Power
supply regulatory liability
|
|
|
468
|
|
|
15,342
|
|
Customer
deposits
|
|
|
920
|
|
|
1,052
|
|
Interest
accrued
|
|
|
1,491
|
|
|
1,137
|
|
Other
|
|
|
2,791
|
|
|
2,552
|
|
Total
current liabilities
|
|
|
31,219
|
|
|
63,156
|
|
Deferred
credits
|
|
|
|
|
|
|
|
Power
supply derivative liability
|
|
|
18,313
|
|
|
22,344
|
|
Accumulated
deferred income taxes
|
|
|
28,989
|
|
|
28,092
|
|
Unamortized
investment tax credits
|
|
|
1,998
|
|
|
2,280
|
|
Pine
Street Barge Canal cleanup liability
|
|
|
4,535
|
|
|
6,096
|
|
Accumulated
cost of removal
|
|
|
21,494
|
|
|
21,105
|
|
Deferred
compensation
|
|
|
5,485
|
|
|
8,213
|
|
Deferred
regulatory revenues
|
|
|
6,260
|
|
|
582
|
|
Other
regulatory liabilities
|
|
|
7,738
|
|
|
6,485
|
|
Minimum
pension liablity
|
|
|
12,433
|
|
|
5,486
|
|
Other
deferred liabilities
|
|
|
5,759
|
|
|
7,737
|
|
Total
deferred credits
|
|
|
113,004
|
|
|
108,420
|
|
COMMITMENTS
AND CONTINGENCIES, Note 3
|
|
|
|
|
|
|
|
Non-utility
|
|
|
|
|
|
|
|
Net
liabilities of discontinued segment
|
|
|
2,541
|
|
|
2,374
|
|
Total
non-utility liabilities
|
|
|
2,541
|
|
|
2,374
|
|
Total
capitalization and liabilities
|
|
$
|
385,962
|
|
$
|
374,268
|
|
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, 2003
|
|
|
5,033,215
|
|
$
|
19,536
|
|
$
|
76,081
|
|
$
|
22,786
|
|
$
|
(1,787
|
)
|
$
|
(16,701
|
)
|
$
|
99,915
|
|
Common
stock issuance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
options and grants
|
|
|
107,264
|
|
|
358
|
|
|
2,771
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3,129
|
|
Net
income
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
11,584
|
|
|
-
|
|
|
-
|
|
|
11,584
|
|
Other
comprehensive 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
|
|
Common
stock issuance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
options and grants
|
|
|
92,844
|
|
|
309
|
|
|
2,419
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
2,728
|
|
Net
income
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
11,180
|
|
|
-
|
|
|
-
|
|
|
11,180
|
|
Other
comprehensive loss
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(910
|
)
|
|
-
|
|
|
(910
|
)
|
Common
stock dividends-$1.00 per share
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(5,205
|
)
|
|
-
|
|
|
-
|
|
|
(5,205
|
)
|
BALANCE,
December 31, 2005
|
|
|
5,233,323
|
|
|
20,203
|
|
|
81,271
|
|
|
35,864
|
|
|
(3,263
|
)
|
|
(16,701
|
)
|
|
117,374
|
|
Common
stock issuance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
options and grants
|
|
|
70,527
|
|
|
235
|
|
|
1,553
|
|
|
|
|
|
|
|
|
|
|
|
1,788
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
10,123
|
|
|
-
|
|
|
|
|
|
10,123
|
|
Other
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,263
|
|
|
|
|
|
3,263
|
|
Common
stock dividends-$1.12 per share
|
|
|
|
|
|
|
|
|
|
|
|
(5,912
|
)
|
|
|
|
|
|
|
|
(5,912
|
)
|
BALANCE,
December 31, 2006
|
|
|
5,303,850
|
|
$
|
20,438
|
|
$
|
82,824
|
|
$
|
40,075
|
|
$
|
-
|
|
$
|
(16,701
|
)
|
$
|
126,636
|
|
Consolidated
Statements of Comprehensive Income
|
|
For
the years ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
In
thousands
|
|
Net
income
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
Minimum
pension liability adjustment, net of applicable income
taxes
|
|
|
3,263
|
|
|
(910
|
)
|
|
(566
|
)
|
of
$2,223 expense, $620 benefit and $391 benefit,
respectively
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income
|
|
$
|
13,386
|
|
$
|
10,270
|
|
$
|
11,018
|
|
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 generates, 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. Most 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 92,000 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
("VYNPC").
The
results of 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
the
Company's unregulated water heater program is as follows:
|
|
For
the Years ended December 31,
|
|
In
thousands
|
|
2006
|
|
2005
|
|
2004
|
|
Revenue
|
|
$
|
921
|
|
$
|
941
|
|
$
|
961
|
|
Expense
|
|
|
661
|
|
|
652
|
|
|
594
|
|
Net
Income
|
|
$
|
260
|
|
$
|
289
|
|
$
|
367
|
|
The
Company accounts for its investments in VYNPC, Vermont Electric Power Company,
Inc. ("VELCO"), Vermont Transco LLC (“Transco”), 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 effect 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 and deferred regulatory
revenue, pension and postretirement 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
Company’s operating results are subject to an earnings cap equal to its allowed
rate of return on equity on investments allowed to be recovered by the VPSB,
reduced by amounts normally excluded for purposes of setting rates. Nearly
all
of the Company’s continuing operations are treated for ratemaking purposes as
regulated operations. The Company’s 2006 and 2005 return on equity was 8.35 and
9.85 percent, respectively, reflecting the exclusions mentioned above.
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. Revenues in
excess
of allowed costs are deferred and appear in the Company’s financial statements
under the caption “Deferred regulatory revenues”. 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.
|
|
|
|
|
|
Amortizable
|
|
Regulatory
assets and liabilities
|
|
Total
|
|
|
|
2006
balances
|
|
|
|
At
December 31,
|
|
|
|
included
in rates
|
|
|
|
2006
|
|
2005
|
|
in
2007
|
|
Regulatory
assets:
|
|
(in
thousands)
|
|
|
|
|
|
|
|
|
|
Demand-side
management programs
|
|
$
|
4,376
|
|
$
|
5,835
|
|
$
|
4,376
|
|
Purchased
power costs
|
|
|
3,683
|
|
|
1,812
|
|
|
3,683
|
|
Pine
Street barge canal
|
|
|
12,070
|
|
|
12,861
|
|
|
6,732
|
|
Derivative
liability regulatory assets
|
|
|
22,526
|
|
|
30,135
|
|
|
-
|
|
Pension
funding regulatory asset
|
|
|
11,789
|
|
|
-
|
|
|
-
|
|
Other
regulatory assets
|
|
|
5,954
|
|
|
5,809
|
|
|
3,559
|
|
Total
regulatory assets
|
|
|
60,398
|
|
|
56,452
|
|
|
18,350
|
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
cost of removal
|
|
|
21,494
|
|
|
21,105
|
|
|
21,494
|
|
Deferred
regulatory revenues
|
|
|
6,260
|
|
|
582
|
|
|
582
|
|
Derivative
asset regulatory liability
|
|
|
468
|
|
|
15,342
|
|
|
-
|
|
Other
regulatory liabilities
|
|
|
7,738
|
|
|
6,485
|
|
|
5,855
|
|
Other
deferred liablilities
|
|
|
5,759
|
|
|
7,737
|
|
|
3,062
|
|
Total
regulatory liabilities
|
|
|
41,719
|
|
|
51,251
|
|
|
30,993
|
|
Regulatory
assets net of regulatory liabilities
|
|
$
|
18,679
|
|
$
|
5,201
|
|
$
|
(12,643
|
)
|
The
derivative regulatory assets and liabilities represent the value of certain
power supply contracts and interest rate swaps 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 Derivative Instruments.
The
Company has historically deferred and amortized uninsured replacement power
costs associated with significant unscheduled outages at the Vermont Yankee
nuclear power plant owned by Entergy Nuclear Vermont Yankee LLC ("ENVY')
and
other extraordinary losses. The Company also had the ability to defer and
amortize extraordinary costs associated with natural disaster, severe storms
costs or significant loss of load under the Company’s 2003 rate plan, when such
costs are deemed probable of recovery. Such deferral and amortization require
VPSB approval. The Company recovers these costs from customers over periods
determined by the VPSB in a future rate filing. Under the 2007 Alternative
Regulation Plan, 90 percent of extraordinary power costs in excess of $300,000
per quarter will be recovered through the Plan’s power supply adjustment
mechanism (the “power supply adjustor”)
Other
regulatory assets totaled $5.9 million and $5.8 million at December 31, 2006
and
2005, 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. Most of these assets are
amortized over a period of between five and seven years.
Other
regulatory liabilities totaled $7.7 million and $6.5 million at December
31,
2006 and 2005, respectively. It consisted of amounts received from VYNPC
that
were subject to a regulatory deferral order, a settlement from an interest
rate
swap, and regulatory tax liabilities.
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 pursuant to the adoption by the Company of SFAS
143.
In
September 2006, FASB issued SFAS 158, "Employer's Accounting for Defined
Benefit
Pension and Other Postretirement Plans, an amendment of FASB Statements Nos.
87,
88, 106 and 132(R)," to be effective December 31, 2006. SFAS 158 requires
an
employer to recognize in its balance sheet the funded status of its benefit
plans. This is measured as the difference between plan assets at fair value
and
the benefit obligation. Employers are to record previously unrecognized gains
and losses, prior service costs, and the remaining transition asset or
obligation as a result of adopting SFAS 87 and SFAS 106 as accumulated other
comprehensive income ("OCI") or as a regulatory asset reflective of the recovery
mechanism for pension and OPEB costs in the utility's
jurisdictions.
The
following table summarizes the effect of adoption of SFAS 158 on the Company’s
consolidated financial statements.
|
|
|
|
|
|
SFAS
158
|
|
|
|
|
|
December
31
|
|
2006
Activity
|
|
and
regulatory
|
|
December
31
|
|
in
thousands
|
|
2005
|
|
|
|
reclassification
|
|
2006
|
|
Prepaid
pension
|
|
$
|
2,170
|
|
$
|
1,623
|
|
$
|
(3,793
|
)
|
$
|
-
|
|
Regulatory
asset FAS 158 pension funding obligation offset
|
|
|
-
|
|
|
-
|
|
|
11,789
|
|
|
11,789
|
|
Deferred
tax asset - federal
|
|
|
3,271
|
|
|
(1,749
|
)
|
|
2,459
|
|
|
3,982
|
|
Deferred
tax asset - state
|
|
|
868
|
|
|
(464
|
)
|
|
653
|
|
|
1,057
|
|
Accumulated
other comprehensive income
|
|
|
3,263
|
|
|
(3,074
|
)
|
|
(188
|
)
|
|
-
|
|
Minimum
pension funding liability
|
|
|
(5,486
|
)
|
|
5,486
|
|
|
-
|
|
|
-
|
|
Total
pension funding obligation
|
|
|
-
|
|
|
(317
|
)
|
|
(12,116
|
)
|
|
(12,433
|
)
|
SERP
liability
|
|
|
(3,897
|
)
|
|
(202
|
)
|
|
4,099
|
|
|
-
|
|
Post
retirement health care liability
|
|
|
(832
|
)
|
|
493
|
|
|
338
|
|
|
-
|
|
Deferred
tax liability - federal
|
|
|
(695
|
)
|
|
(520
|
)
|
|
(2,561
|
)
|
|
(3,776
|
)
|
Deferred
tax liability - state
|
|
|
(184
|
)
|
|
(138
|
)
|
|
(680
|
)
|
|
(1,002
|
)
|
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; and non-performing loans. The Company recognized income of $.04
per
share in 2006 and $.03 per share in 2005 from Discontinued Operations primarily
as a result of the realization of tax capital loss carryforwards. Income
in 2004
reflects 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, 2006, 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,
|
|
Approximate
|
|
|
|
|
|
|
|
Average
depreciable
|
|
2006
|
|
2005
|
|
|
|
life
in years
|
|
In
thousands
|
Property,
Plant and Equipment:
|
|
|
|
|
|
|
|
Intangible,
FERC Licenses and Software
|
|
|
13
|
|
$
|
8,501
|
|
$
|
11,162
|
|
Generation
|
|
|
41
|
|
|
77,445
|
|
|
73,413
|
|
Transmission
|
|
|
39
|
|
|
40,931
|
|
|
40,311
|
|
Distribution
|
|
|
37
|
|
|
204,235
|
|
|
193,261
|
|
General,
including transportation
|
|
|
18
|
|
|
31,858
|
|
|
29,800
|
|
Total
Plant in Service
|
|
|
|
|
|
362,970
|
|
|
347,947
|
|
Accumulated
Depreciation and Amortization
|
|
|
|
|
|
(127,704
|
)
|
|
(122,924
|
)
|
Net
Plant in Service
|
|
|
|
|
|
235,266
|
|
|
225,023
|
|
Capital
Lease
|
|
|
|
|
|
4,060
|
|
|
4,369
|
|
Construction
Work in Progress
|
|
|
|
|
|
7,666
|
|
|
7,519
|
|
Total
Utility Plant, net
|
|
|
|
|
$
|
246,992
|
|
$
|
236,911
|
|
Depreciation
and Amortization.
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 3.1 percent during 2006,
3.4
percent during 2005, and 3.3 percent during 2004 of total depreciable property,
reflecting the impact of a new depreciation schedule adopted as a result
of a
study that was completed in 2005 and implemented in 2006.
The
Company amortizes nearly all of its intangible and regulatory assets using
the
straight-line method based on the cost and amortization period approved by
the
VPSB for the intangible property outstanding at the beginning of the year.
Amortization expense totaled $3.6 million, $3.8 million, and $3.3 million
for
2006, 2005 and 2004, respectively.
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 is required to set aside $302,000, included in Other Investments,
as of
December 31, 2006, 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 recognizes
deferred regulatory 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. Revenues in excess of allowed costs, or, earnings
in
excess of the earnings limitation, are deferred and appear in the Company’s
financial statements under the caption “Deferred regulatory revenues”. The
Company deferred regulatory revenues of $5.7 million and $582,000 during
2006
and 2005, respectively, and recognized $3.0 million in deferred regulatory
revenues during 2004. See Note H 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
|
|
Accounts
|
|
Balance
at
|
|
|
|
Beginning
of
|
|
Charged
to
|
|
Charged
|
|
End
of
|
|
|
|
Period
|
|
Cost
& Expenses
|
|
Off
|
|
Period
|
|
In
thousands
|
|
|
|
|
|
|
|
|
|
2006
|
|
$
|
484
|
|
$
|
381
|
|
$
|
464
|
|
$
|
401
|
|
2005
|
|
|
620
|
|
|
308
|
|
|
444
|
|
|
484
|
|
2004
|
|
|
691
|
|
|
549
|
|
|
620
|
|
|
620
|
|
Earnings
Per Share.
Basic
earnings per share ("EPS") is calculated by dividing net income 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 are 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.
Stock-Based
Compensation
During
the year ended December 31, 2000, the Company granted options for 335,300 shares
under its 2000 Stock Incentive 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. Prior to the
adoption of SFAS 123R, the Company followed the prospective method of accounting
for stock-based compensation under SFAS 148, Accounting
for Stock-Based Compensation,
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. Stock options granted during
2003
have been expensed and no stock options have been granted after
2003.
Pro-forma
net income
|
|
|
|
|
|
|
|
|
|
For
the years ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
In
thousands, except per share amounts
|
|
|
|
|
|
|
|
Net
income reported
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
Pro-forma
net income
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,503
|
|
Net
income per share
|
|
|
|
|
|
|
|
|
|
|
As
reported-basic
|
|
$
|
1.92
|
|
$
|
2.15
|
|
$
|
2.28
|
|
Pro-forma
basic
|
|
$
|
1.92
|
|
$
|
2.15
|
|
$
|
2.26
|
|
As
reported-diluted
|
|
$
|
1.89
|
|
$
|
2.12
|
|
$
|
2.20
|
|
Pro-forma
diluted
|
|
$
|
1.89
|
|
$
|
2.12
|
|
$
|
2.19
|
|
Stock
compensation included in results, net of tax
|
|
$
|
1,031
|
|
$
|
806
|
|
$
|
740
|
|
Fair
value of all stock compensation
|
|
|
1,031
|
|
|
806
|
|
|
821
|
|
Major
Customers and Other Concentration Risks.
The
Company has one major retail customer, International Business Machines
Corporation ("IBM"), that accounted for 23.3 percent, 23.5 percent, and 24.1
percent of retail MWh sales, and 15.0 percent, 15.3 percent and 16.4 percent
of
the Company’s retail operating revenues in 2006, 2005 and 2004,
respectively.
We
believe that a hypothetical shutdown of the IBM facility may necessitate a
modest retail rate increase for all remaining customers, including secondary
and
tertiary impacts of such a shutdown on other customer sales, because the Company
could sell some of the contracted power supply resources into the wholesale
market at prices in excess of current rates charged to IBM. The amount of such
an increase would change materially as a result of any significant reductions
in
energy prices or increases in retail rates paid by IBM.
Our
material power supply contracts are principally with Hydro Quebec and VYNPC.
These contracts are expected to meet approximately 75 to 80 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. The JP Morgan Contract is expected to provide an additional 10 percent
of our anticipated annual demand requirements during the next five
years.
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:
|
|
At
December 31,
|
|
|
|
2006
|
|
2005
|
|
|
|
Calculated
|
|
Amount
carried
|
|
Calculated
|
|
Amount
carried
|
|
In
thousands
|
|
Fair
Value
|
|
on
balance sheet
|
|
Fair
Value
|
|
on
balance sheet
|
|
Long-Term
Debt, net,(Note F)
|
|
$
|
108,360
|
|
$
|
109,000
|
|
$
|
76,851
|
|
$
|
79,000
|
|
Derivatives,
net
|
|
|
(22,058
|
)
|
|
(22,058
|
)
|
|
(14,793
|
)
|
|
(14,793
|
)
|
Current
portion of long-term debt
|
|
|
-
|
|
|
-
|
|
|
14,080
|
|
|
14,000
|
|
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,
Accounting
for Derivative Instruments and Hedging Activities,
as
amended, established 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.
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.
The
Morgan Stanley Contract was used to hedge against increases in fossil fuel
prices. Morgan Stanley purchased a portion of the Company's power supply
resources at index (fossil fuel resources) or specified (i.e., contracted
resources) prices and then sold to us at a fixed rate to serve pre-established
load requirements. This contract allowed management to fix the cost of
much of
its power supply requirements, subject to power resource availability and
other
risks. The Morgan Stanley Contract expired December 31, 2006.
In
2006,
the Company entered into a power supply agreement with JP Morgan Ventures
Energy
Corporation Contract (“JP Morgan Contract”) to hedge against fossil fuel price
increases. This contract is a derivative but meets the exception for a
normal
purchase and sale contract, and therefore does not require the recording
of an
asset or liability. The JP Morgan Contract begins January 1, 2007 and ends
on
December 31, 2010.
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 a 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
Company has other less significant derivative positions. Forward sales
contracts
for the months of March and April, 2007 were made to capture forward energy
prices that were high by historical standards. Interest rate swaps were
used to
hedge against rising interest rates for the issue of new bonds in 2006
and
2007.
The
table
below presents the Company’s 9701 agreement and other derivatives. Actual
results may differ materially from the table illustration.
Derivatives
|
|
At
December 31, 2006
|
|
|
|
Fair
Value
|
|
|
|
(in
thousands)
|
|
Interest
rate swap
|
|
$
|
193
|
|
Power
supply swaps
|
|
|
(1,918
|
)
|
9701
agreement
|
|
|
(20,608
|
)
|
Forward
sale contracts
|
|
|
275
|
|
|
|
$
|
(22,058
|
)
|
The
table
below presents assumptions used to estimate the fair value of derivatives,
including the 9701 agreement and power supply swaps, forward sales contracts,
and the remaining interest rate swap. 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
|
Interest
rate swap
|
Deterministic
|
n/a
|
n/a
|
n/a
|
2007
|
9701
agreement
|
Black-Scholes
|
4.4%
|
29%-10%
|
$93
|
2015
|
Forward
sale contracts
|
Deterministic
|
5%
|
n/a
|
$70
|
2007
|
Power
supply Swaps
|
Deterministic
|
4.8-5.1%
|
n/a
|
$92
|
2007-2009
|
At
December 31, 2006, the Company had a total power supply derivative
liability of
$22.5 million reflecting the fair value of the 9701 agreement and
power supply
swaps, and a derivative asset of approximately $468,000, reflecting
the fair
value of the interest rate swap and the forward sale contracts. Corresponding
regulatory assets and regulatory liabilities total $22.5 million
and $468,000,
respectively. Amounts due during 2007 are classified in current assets
and
current liabilities.
At
December 31, 2005, the Company had a power supply derivative liability
of $30.1
million reflecting the fair value of the 9701 agreement, and a power
supply
derivative asset of $15.3 million, reflecting the $15.1 million fair
value of
the Morgan Stanley Contract and the remaining asset attributable
to the forward
sale contracts. Corresponding regulatory assets and regulatory liabilities
total
$30.1 million and $15.3 million, respectively. Amounts due during
2006 were
classified in current assets and current liabilities.
In
March
2006, the Company entered into an interest rate swap relating to
the Company’s
2006 issuance of first mortgage bonds to mitigate the risk of rising
interest
rates. Approximately one-half of the new $30 million first mortgage
bonds in
2006 was covered. The interest rate swap was settled on August 2,
2006, with a
final gain on settlement of approximately $600,000, which has been
recorded as a
regulatory liability and will be amortized over the life of the bond
issue as a
component of interest expense.
In
December 2006, the Company entered into a second interest rate swap
relating to
the Company’s anticipated issuance of 2007 first mortgage bonds. Approximately
$15 million of the $20 million first mortgage bonds proposed for
2007 was
covered. The interest rate swap is still outstanding and has a fair
value of
$193,000 as of December 31, 2006. The final settlement will be amortized
over
the life of the bond issue as a component of interest expense.
Other
Comprehensive Income.
Prior to
adoption of SFAS 158, certain negative scenarios and unfavorable
market
conditions (asset returns lower than expected, reductions in discount
rates, and
liability experience losses) caused the Pension Plan's accumulated
benefit
obligation ("ABO") to exceed the fair value of Pension Plan assets
as of the
measurement date and resulted in an unfunded minimum pension liability.
Since
the minimum liability exceeded the accrued benefit cost, an additional
minimum
pension liability had 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. The Company has recorded other
comprehensive losses reflecting additional minimum pension liabilities
relating
to qualified and non-qualified plans. During 2004, due principally
to a decline
in the discount rate assumption used for pension calculations, we
recorded an
increase in other comprehensive loss of $566,000, net of $391,000
income tax.
During 2005, due principally to a decline in the discount rate assumption
used
for plan calculation, we recorded an increase in other comprehensive
loss of
$910,000, net of $620,000 income tax.
For
the
year ending December 31, 2006, the Company adopted SFAS No. 158,
Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans—an
amendment of FASB Statements No. 87, 88, 106, and 132(R). In connection
with the
adoption, the minimum pension fund liability was eliminated.
Recent
Accounting Pronouncements.
Accounting
pronouncements adopted for years ending 2005 and 2004:
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.
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.
The
Company was able to conclude that the benefits provided by the plan
were
actuarially equivalent to Medicare Part D under the Act, and was
able 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"). 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 impacts annual
net periodic
cost in 2005 and beyond.
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 Company estimates its tax deduction
on
qualified production activities approximates $82,000.
As
of
December 31, 2005, the Company adopted FIN 47, which clarified that
a legal
obligation associated with the retirement of a long-lived asset whose
timing
and/or method of settlement are conditional on a future event is
within the
scope of SFAS No. 143, Accounting
for Asset Retirement Obligations.
Under
FIN 47, the Company is required to record liabilities associated
with its
conditional asset retirement obligation (“ARO”) at their estimated fair values
if those fair values can be reasonably estimated.
At
December 31, 2005, the Company measured its conditional AROs at fair
value using
the methodology prescribed by FIN 47 and recorded a resulting regulatory
asset
of approximately $344,000 under SFAS No. 71. During 2006, the Company
recorded
an additional $386,000 liability.
Accounting
pronouncements adopted for year ending 2006:
In
December 2004, the FASB issued SFAS No. 123(Revised), "Share-Based
Payments,"
which replaces SFAS No. 123. 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 is based on the grant
date fair value
of the award. The Company used the fair value method for share-based
payment
awards for grants made after January 1, 2003. The Company adopted
No. 123
(Revised) as of January 1, 2006. See Note C, Common Stock Equity
and Stock Award
Plans for effects on the financial statements of the Company.
In
September 2006, the FASB issued Statement of Financial Accounting
Standards No.
158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS
158”). SFAS 158 requires company plan sponsors to display the net over-
or
under-funded position of a defined benefit postretirement plan as
an asset or
liability, with any unrecognized prior service costs, transition
obligations or
actuarial gains/losses reported as a component of other comprehensive
income in
shareholders’ equity, unless the amount will be recoverable under SFAS 71 for
regulated utilities, in which case it could be recorded as a regulatory
asset.
The provisions of SFAS 158 are effective for fiscal years ending
after December
15, 2006. The Company has recorded a pension funding regulatory asset
for $11.8
million and a total unfunded pension obligation for $12.4 million.
Accounting
pronouncements considered for future periods:
In
June
2006, the FASB issued FIN-48,
Accounting
for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109,
effective for fiscal years beginning after December 15, 2006. This
interpretation clarifies the accounting for uncertainty in income
taxes
recognized in financial statements in accordance with Statement of
Financial
Accounting Standards No. 109, Accounting for Income Taxes. The effects
of the
Company’s adoption of FIN-48 on its results of operations, cash flow or
financial position are currently under consideration. The Company
anticipates
that this new standard will not have a material impact on our financial
condition, results of operations or cash flows.
In
September 2006, the FASB issued Statement of Financial Accounting
Standards No.
157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 redefines fair
value as “the price that would be received to sell an asset or paid to transfer
a liability in an orderly transaction between market participants
at the
measurement date.” SFAS No. 157 establishes a fair value hierarchy that
categorizes and prioritizes the inputs that should be used to estimate
fair
value. We will implement SFAS No. 157 as of January 1, 2008, applying
the
provisions retrospectively for derivative accounting and prospectively
for all
other valuations. We are currently evaluating the impact adoption
may have on
our financial condition, results of operations and cash flows.
In
February 2007 the FASB issued Statement of Financial Accounting Standards
No.
159 The Fair Value Option for Financial Assets and Financial Liabilities,
Including an amendment of FASB Statement No. 115. This Statement
permits
entities to choose to measure many financial instruments and certain
other items
at fair value. The objective of the standard is to improve financial
reporting
by providing entities with the opportunity to mitigate volatility
in reported
earnings caused by measuring related assets and liabilities differently
without
having to apply complex hedge accounting provisions. This Statement
is expected
to expand the use of fair value measurement, which is consistent
with the
Board’s long-term measurement objectives for accounting for financial
instruments. This Statement is effective as of the beginning of an
entity’s
first fiscal year that begins after November 15, 2007. The Company
will
implement this statement as of January 1, 2008 and we are currently
evaluating
the effects of adoption.
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,
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
|
|
|
|
(In
thousands)
|
|
VELCO-common
|
|
|
29.17
|
%
|
|
29.17
|
%
|
$
|
7,054
|
|
$
|
7,048
|
|
VELCO-preferred
|
|
|
30.00
|
%
|
|
30.00
|
%
|
|
52
|
|
|
68
|
|
Total
VELCO
|
|
|
|
|
|
|
|
|
7,106
|
|
|
7,116
|
|
Transco
LLC
|
|
|
21.90
|
%
|
|
-
|
|
|
17,843
|
|
|
-
|
|
VYNPC-
Common
|
|
|
33.60
|
%
|
|
33.60
|
%
|
|
1,615
|
|
|
1,601
|
|
New
England Hydro Transmission-Common
|
|
|
3.18
|
%
|
|
3.18
|
%
|
|
436
|
|
|
485
|
|
New
England Hydro Transmission Electric-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
3.18
|
%
|
|
3.18
|
%
|
|
768
|
|
|
834
|
|
Total
investment in associated companies
|
|
|
|
|
|
|
|
$
|
27,768
|
|
$
|
10,036
|
|
VELCO
and Transco.
In June
2006, VELCO’s Board of Directors approved a plan to transfer substantially all
of VELCO’s business to Transco, a Vermont limited liability company. On June 30,
2006, VELCO’s assets were transferred to Transco in exchange for 2.4 million
Class A Membership Units and Transco’s assumption of VELCO’s debt. VELCO and its
employees will manage the operations of Transco under an operating agreement
that includes the Company, Central Vermont Public Service Corporation and most
of Vermont’s electric utilities. Transco is operating under Amended and Restated
Three Party Agreements that include the Company, Central Vermont Public Service
Corporation, VELCO and Transco. VELCO has a 30.8 percent ownership interest
in
Transco.
The
Company invested $17.1 million in Transco during 2006. These investments
entitled the Company to receive a 21.9 percent equity ownership interest
represented by Class A Membership Units in Transco that will receive an 11.5
percent rate of return. Since results are accounted for as a regulated business
for Vermont rate setting, the return to the Company is capped at our allowed
rate of return.
Transco
owns and operates the transmission system in Vermont over which bulk power
is
delivered to all electric utilities in the state. The Company plans to make
capital investments of approximately $8.4 million in 2007 in Transco in support
of various transmission projects. The Company is evaluating opportunities to
invest an additional $19 million in Transco for similar purposes. The Company’s
capital contributions to Transco are based on, and consistent with, our original
equity commitments to VELCO.
Summarized
unaudited financial information for Transco is as follows:
|
|
|
|
At
and for the year ended December 31,
|
|
|
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Net
income
|
|
$
|
5,527
|
|
Company's
equity in net income
|
|
$
|
1,011
|
|
Total
assets
|
|
$
|
292,707
|
|
Liabilities
and long-term debt
|
|
|
214,101
|
|
Net
assets
|
|
$
|
78,606
|
|
Company's
equity in net assets
|
|
$
|
17,843
|
|
VELCO
has
entered into transmission agreements with the State of Vermont and other
electric utilities including the Company, and under these agreements, VELCO
and
Transco bill all costs, including interest on debt and a fixed return on
equity,
to the State and others, including the Company, using Transco'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 and Transco’s
operating costs, including debt service costs.
Summarized
unaudited financial information for VELCO (consolidated)
follows:
|
|
|
|
|
|
|
|
At
and for the years ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
Net
income
|
|
$
|
5,053
|
|
$
|
3,018
|
|
$
|
1,683
|
|
Company's
equity in net income
|
|
$
|
1,841
|
|
$
|
877
|
|
$
|
472
|
|
Total
assets
|
|
$
|
310,759
|
|
$
|
187,549
|
|
$
|
145,632
|
|
Liabilities
and long-term debt
|
|
|
232,383
|
|
|
163,142
|
|
|
120,983
|
|
Net
assets
|
|
$
|
78,376
|
|
$
|
24,407
|
|
$
|
24,649
|
|
Company's
equity in net assets
|
|
$
|
24,949
|
|
$
|
7,116
|
|
$
|
7,199
|
|
Amounts
due from (to) VELCO
|
|
$
|
1,791
|
|
$
|
1,596
|
|
$
|
(4,068
|
)
|
2006
amounts include Transco
|
|
|
|
|
|
|
|
|
|
|
VELCO
provided transmission services to the Company (reflected as transmission
expenses in the accompanying Consolidated Statements of Income) amounting
to
$1.2 million in 2006, $1.6 million in 2005, and $12.3 million in 2004,
respectively. Amounts decreased in 2006 and 2005 because ISO-NE now invoices
the
Company directly for transmission services. Previously, ISO-NE invoiced VELCO
and VELCO invoiced the Company for those transmission services.
Included
in the Company’s retail and other revenues are construction services of
approximately $8.8 million and $4.8 million billed to VELCO in 2006 and 2005,
respectively.
Vermont
Yankee Nuclear Power Corporation ("VYNPC").
The
Company's ownership share of VYNPC is approximately 33.6 percent. The Company's
entitlement to energy produced by the Vermont Yankee nuclear plant owned
by
Entergy Nuclear Vermont Yankee LLC (“ENVY”) has been approximately 20 percent of
plant production since the plant began operations. The Vermont Yankee plant
received final approval for uprating from the Nuclear Regulatory Commission
on
March 2, 2006, resulting in a lower percentage for our entitlement to an
increased plant production capability of approximately 17 percent.
The
purchased power agreement between ENVY and VYNPC specifies that our percentage
of energy output under VYNPC’s contract with ENVY declines after the VY nuclear
plant uprating is completed. The Company believes its share of the plant’s
output should be equivalent to the amount of power it received before the
uprate
process began. VYNPC and ENVY are discussing the calculations which depend
upon
determination of the pre-uprate capability of the plant, which is presently
disputed. The Company estimates the potential impact of the differing methods
of
calculation could adversely affect power supply expense by up to $600,000
annually. In the event that the VY nuclear plant is derated in the future,
then
our rights to energy output could decline proportionately to such derating.
If
this were to occur, we estimate it would have a material adverse effect on
our
power supply costs. In this event we would seek recovery of these costs from
the
VPSB.
The
Company is currently a party to a VPSB Docket that was opened to investigate
whether the reliability of the increased nuclear plant output will be adversely
affected by the operation of the plant’s steam dryer. On September 18, 2006, the
VPSB issued a ruling requiring ENVY to provide additional ratepayer protections
that would make Vermont ratepayers whole in the event that VY must reduce
power
due to uprate-related steam dryer failure. Under the VPSB ruling, these
protections will only apply to incremental replacement power costs incurred
due
under the terms of the Purchase Power Agreement (“PPA”) between ENVY and VYNPC.
The additional ratepayer protections are required to remain in effect through
a
period two months after the first refueling outage in which VY operates
successfully with no steam dryer-related outages or derates. VY’s next scheduled
refueling outage is presently scheduled for early 2007. ENVY requested
reconsideration of the VPSB ruling. Reconsideration was denied and ENVY has
appealed the decision to the Vermont Supreme Court.
Summarized
unaudited financial information for VYNPC is as follows:
|
|
|
|
|
|
|
|
At
and for the years ended December 31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
|
|
(In
thousands)
|
|
|
|
Earnings:
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
201,325
|
|
$
|
160,613
|
|
$
|
167,399
|
|
Net
income applicable to common stock
|
|
|
749
|
|
|
660
|
|
|
538
|
|
Company's
equity in net income
|
|
$
|
251
|
|
$
|
221
|
|
$
|
181
|
|
Total
assets
|
|
$
|
157,880
|
|
$
|
153,132
|
|
$
|
151,542
|
|
Liabilities
and long-term debt
|
|
|
153,079
|
|
|
148,371
|
|
|
146,747
|
|
Net
Assets
|
|
$
|
4,801
|
|
$
|
4,761
|
|
$
|
4,795
|
|
Company's
equity in net assets
|
|
$
|
1,615
|
|
$
|
1,601
|
|
$
|
1,612
|
|
Amounts
due to VYNPC
|
|
$
|
3,129
|
|
$
|
3,077
|
|
$
|
3,324
|
|
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 J for further information concerning
our long-term power contract with VYNPC.
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, 2006. The
Company also funds an Employee Savings and Investment Plan ("ESIP") under
which
the Company may contribute shares of common stock. Under our ESIP plan,
we match
up to the first four percent of annual base salary and make an additional
contribution of a half percent of base salary on a non-matching basis.
Matching
contributions are currently made in cash and immediately vest. The Company's
matching and non-matching contributions for the years 2006, 2005 and 2004
were
$530,000, $524,000 and $487,000, respectively.
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
previously 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, 2006, no shares were unissued
under the 2000 Stock Plan. During the year ended December 31, 2000, the
Company
granted options for 335,300 shares 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.
The Company discontinued granting stock options 2003.
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, 2006, approximately 116,000 shares have been issued
under the
2004 Stock Incentive Plan. Effective January 1, 2006, the Company adopted
the
provisions of Statement of Financial Accounting Standards No. 123(revised
2004),
Share-Based Payment (“SFAS 123R”), using the Statement’s modified prospective
application method. Prior to the adoption, the Company followed the provisions
of FASB 123 and expensed the stock option grants. Accordingly, prior periods
have not been restated.
All
of
the Company’s stock-based compensation is based on grants of equity instruments
and no liability awards have been granted. Unrestricted stock grants and
deferred stock unit awards have been made only to employees, senior management
and directors. Unrestricted stock grants vest immediately and are recognized
as
compensation expense based on the fair value of the awards at the grant
date.
During the years ended December 31, 2006 and 2005, the Company granted
14,862
shares and 14,450 shares of unrestricted stock to employees with a weighted
average grant date fair value of $33.26 per share, and $29.87 per share,
respectively.
Deferred
stock unit awards are recognized as deferred compensation based on the
fair
value of the award at the grant date and charged ratably to expense over
the
required service period for each award, which generally equals the vesting
period. Stock unit awards to senior management vest over a two-year service
period, unless such senior management is retirement eligible. The stock
unit
awards for retirement eligible senior management are deemed vested and
the
applicable expense recognized over the retirement eligible vesting period.
Stock
unit awards may be deferred and earn the equivalent of dividends each quarter,
which are then converted to share units, during the deferral period. No
modifications of existing awards occurred. All shares issued for stock
awards
are new shares. Total compensation expense from all stock awards to directors,
employees and senior management totaled $1.8 million, $1.4 million and
$1.2
million for the years 2006, 2005 and 2004, respectively. The summary table
of
stock unit awards activity reflects all stock award compensation, but does
not
reflect the “retirement eligible” stock units as vested.
Stock
awards
|
|
Total
|
|
Vested
|
|
Non-vested
|
|
Weighted
|
|
Shares
|
|
|
|
|
|
Stock
|
|
Stock
|
|
Stock
|
|
Average
|
|
returned
for
|
|
Compensation
|
|
|
|
Awards
|
|
Awards
|
|
Awards
|
|
Grant-date
|
|
income
tax
|
|
cost
|
|
|
|
Share
units
|
|
fair
value
|
|
withholding
|
|
recognized
|
|
Outstanding
at December 31, 2005
|
|
|
58,566
|
|
|
7,166
|
|
|
51,400
|
|
$
|
27.39
|
|
|
-
|
|
$
|
-
|
|
Employee
grants and dividend equivalents earned
|
|
|
14,862
|
|
|
14,862
|
|
|
|
|
|
33.26
|
|
|
4,872
|
|
|
494,527
|
|
Grants
to officers and directors
|
|
|
52,870
|
|
|
-
|
|
|
52,870
|
|
|
29.07
|
|
|
311
|
|
|
1,415,805
|
|
Vested
|
|
|
-
|
|
|
41,900
|
|
|
(41,900
|
)
|
|
27.84
|
|
|
-
|
|
|
|
|
Forfeited
|
|
|
(3,333
|
)
|
|
|
|
|
(3,333
|
)
|
|
28.30
|
|
|
|
|
|
(94,324
|
)
|
Issued
|
|
|
(58,215
|
)
|
|
(58,215
|
)
|
|
-
|
|
|
-
|
|
|
10,411
|
|
|
|
|
Outstanding
at December 31, 2006
|
|
|
64,750
|
|
|
5,713
|
|
|
59,037
|
|
$
|
28.53
|
|
|
15,594
|
|
$
|
1,816,008
|
|
Approximately
$761,000 of unrecognized share-based compensation exists at December
31, 2006,
with a weighted average accrual period of 8 months remaining. The amount
capitalized as part of the cost of assets was approximately
$12,000.
For
the
year ended December 31, 2006, cash received from the exercise of options
totaled
approximately $344,000 and the Company recognized a reduction in income
tax
liability of approximately $257,000. The adoption of SFAS 123R resulted
in no
incremental stock-based compensation expense and had no impact on net
income,
diluted earnings per share or cash flows from operating or financing
activities
for this same period.
Upon
consummation of the proposed merger discussed under “Mergers and Acquisitions,”
all of the remaining unexercised stock options convert to shares, and
any
remaining unvested stock grants immediately vest.
The
fair
value of options granted in 2003 was $1.33 per share. The fair value
was
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,
2006:
|
|
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
|
|
|
85,100
|
|
|
3.6
|
|
|
6.05
|
%
|
|
5
|
|
|
30.58
|
|
|
4.5
|
%
|
2001
|
|
$
|
16.78
|
|
|
5,900
|
|
|
4.7
|
|
|
5.25
|
%
|
|
6
|
|
|
32.69
|
|
|
4.0
|
%
|
2002
|
|
$
|
18.03
|
|
|
26,700
|
|
|
5.4
|
|
|
4.50
|
%
|
|
6.5
|
|
|
16.89
|
|
|
4.5
|
%
|
Total
|
|
$
|
10.64
|
|
|
117,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
Range
of
|
|
|
|
Aggregate
|
|
Average
|
|
|
|
Total
|
|
Average
|
|
Exercise
|
|
Options
|
|
Intrinsic
|
|
Contractual
|
|
|
|
Options
|
|
Price
|
|
Prices
|
|
Exercisable
|
|
Value
|
|
Life
in Years
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2003
|
|
|
300,850
|
|
|
11.39
|
|
$
|
7.90-$22.62
|
|
|
193,700
|
|
|
|
|
|
|
|
Granted
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
89,650
|
|
|
12.11
|
|
$
|
7.90-$20.96
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
1,900
|
|
|
18.65
|
|
$
|
17.54-$20.96
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2004
|
|
|
209,300
|
|
$
|
11.07
|
|
$
|
7.90-$22.62
|
|
|
213,500
|
|
|
|
|
|
|
|
Granted
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
62,500
|
|
$
|
11.31
|
|
$
|
7.90-$22.62
|
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
200
|
|
$
|
20.08
|
|
$
|
17.54-$22.62
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2005
|
|
|
146,600
|
|
$
|
10.90
|
|
$
|
7.90-$22.62
|
|
|
146,600
|
|
|
|
|
|
|
|
Granted
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
28,900
|
|
$
|
11.92
|
|
$
|
7.90-$20.96
|
|
|
|
|
|
344,488
|
|
|
|
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2006
|
|
|
117,700
|
|
$
|
10.64
|
|
$
|
7.90-$18.95
|
|
|
117,700
|
|
$
|
1,252,328
|
|
|
4.1
|
|
The
following table presents a reconciliation of 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
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(in
thousands)
|
|
Net
income before preferred dividends
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,587
|
|
Preferred
stock dividend requirement
|
|
|
-
|
|
|
-
|
|
|
3
|
|
Net
income applicable to common
|
|
|
|
|
|
|
|
|
|
|
stock
|
|
$
|
10,123
|
|
$
|
11,180
|
|
$
|
11,584
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
number of common shares-basic
|
|
|
5,270
|
|
|
5,195
|
|
|
5,083
|
|
Dilutive
effect of stock options
|
|
|
78
|
|
|
90
|
|
|
171
|
|
Average
number of common shares-diluted
|
|
|
5,348
|
|
|
5,285
|
|
|
5,254
|
|
Common
stock issuance from compensation programs during 2006 amounted
to 85,662 shares.
Of this amount, 28,900 shares were issued for exercised options,
49,362 shares
were issued for employee stock grants and 7,400 shares were issued
for grants to
the Company’s Board of Directors.
Common
stock issuance from compensation programs during 2005 amounted
to 92,844 shares.
Of this amount, 62,500 shares were issued for exercised options,
20,444 shares
were issued for employee stock grants and 9,900 shares were issued
for grants to
the Company’s Board of Directors. Common stock issuance from compensation
programs during 2004 amounts to 107,264 shares. Of this amount,
89,650 shares
were issued for exercised options, 9,914 shares were issued for
employee stock
grants and 7,700 shares were issued for grants to the Company’s Board of
Directors.
Appropriated
Retained Earnings. The Company had appropriated retained earnings
of $409,000
and $379,000 at December 31, 2005 and 2004, 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 $8.2 million of
retained earnings
were free of restrictions at December 31, 2006.
D.
SHORT-TERM DEBT
Effective
June 14, 2006, the Company has a five year revolving credit facility
of $30
million with Sovereign Bank and Key Bank replacing the expired
364-day revolving
credit agreement with Bank of America, joined by Sovereign Bank
(“the
Fleet-Sovereign Agreement”). The Sovereign/Key Bank revolving credit facility is
unsecured, and allows the Company to choose any blend of a daily
variable prime
rate and a fixed term LIBOR-based rate. This revolving credit
facility does not
include any material adverse change or material adverse effect
clauses,
subsequent to the effective date, as pre-conditions for borrowing
under the
facility. There was no balance outstanding at December 31, 2006.
Under
the
Fleet-Sovereign Agreement, there was no balance outstanding at
December 31,
2005. There was no non-utility short-term debt outstanding at
December 31,
2006.
E.
LONG-TERM DEBT
On
August
3, 2006, the Company closed on the first tranche of the new $30
million First
Mortgage Bonds, 6.53% Series, due August 1, 2036 and received
$11 million in
funds. The funds were primarily used to partially fund additional
capital
investments by the Company in Transco. The second tranche of
$19 million was
received in December 2006 and repaid $14 million of First Mortgage
Bonds and
repaid short-term bank borrowings.
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 6.9 percent
at December 31,
2006 and 7.0 percent at December 31, 2005. 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
|
|
|
|
|
|
At
December 31,
|
|
First
Mortgage Bonds
|
|
|
|
|
|
2006
|
|
2005
|
|
Interest
Rate
|
|
Maturity
|
|
Annual
Sinking Fund
|
|
(In
thousands)
|
|
7.18%
|
|
|
Nov.
6, 2006
|
|
|
-
|
|
$
|
-
|
|
$
|
10,000
|
|
7.05%
|
|
|
Dec.
15, 2006
|
|
|
-
|
|
|
-
|
|
|
4,000
|
|
6.04%
|
|
|
Dec.
1, 2017
|
|
|
6,000,000
begins 2011
|
|
|
42,000
|
|
|
42,000
|
|
6.70%
|
|
|
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
|
|
6.53%
|
|
|
Aug.
1, 2036
|
|
|
-
|
|
|
30,000
|
|
|
-
|
|
Total
Long-term Debt Outstanding
|
|
|
|
|
|
|
|
|
109,000
|
|
|
93,000
|
|
Less
Current Maturities (due within one year)
|
|
|
|
|
|
|
|
|
-
|
|
|
14,000
|
|
Total
Long-term Debt, less current maturities
|
|
|
|
|
|
|
|
$
|
109,000
|
|
$
|
79,000
|
|
F.
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, 2006 and December 31, 2005, were as follows:
|
|
At
December 31,
|
|
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Deferred
Tax Assets
|
|
|
|
|
|
Contributions
in aid of construction
|
|
$
|
3,451
|
|
$
|
2,629
|
|
Deferred
compensation and
|
|
|
|
|
|
|
|
postretirement
benefits
|
|
|
2,466
|
|
|
5,664
|
|
Self
insurance and other reserves
|
|
|
461
|
|
|
405
|
|
Deferred
regulatory earnings
|
|
|
3,371
|
|
|
1,280
|
|
Cost
of removal
|
|
|
8,710
|
|
|
8,553
|
|
Other
|
|
|
2,668
|
|
|
2,011
|
|
Derivatives
|
|
|
9,129
|
|
|
18,432
|
|
|
|
$
|
30,256
|
|
$
|
38,974
|
|
Deferred
Tax Liabilities
|
|
|
|
|
|
|
|
Accelerated
Tax Depreciation on Property
|
|
$
|
41,480
|
|
$
|
40,618
|
|
Demand
side management
|
|
|
1,773
|
|
|
2,364
|
|
Deferred
purchased power costs
|
|
|
1,568
|
|
|
818
|
|
Pine
Street reserve
|
|
|
3,053
|
|
|
2,742
|
|
Investment
in affiliates
|
|
|
1,051
|
|
|
697
|
|
Other
|
|
|
1,620
|
|
|
1,501
|
|
Derivative
regulatory assets
|
|
|
9,129
|
|
|
18,432
|
|
|
|
$
|
59,674
|
|
$
|
67,172
|
|
Net
accumulated deferred income
|
|
|
|
|
|
|
|
tax
liability
|
|
$
|
29,418
|
|
$
|
28,198
|
|
The
change in the net accumulated deferred income tax liability arises from the
deferred income tax expense included in the income statement for the periods
presented, the change in the tax effect of minimum pension funding liability
changes, and the change in the tax effect of changes in income tax related
regulatory assets and liabilities.
The
components of the provision for income taxes are as follows:
|
|
For
the Years ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
Current
federal income taxes
|
|
$
|
5,757
|
|
$
|
6,326
|
|
$
|
461
|
|
Current
state income taxes
|
|
|
2,153
|
|
|
1,913
|
|
|
1,602
|
|
Total
current income taxes
|
|
|
7,910
|
|
|
8,239
|
|
|
2,063
|
|
Deferred
federal income taxes
|
|
|
(897
|
)
|
|
(1,938
|
)
|
|
3,843
|
|
Deferred
state income taxes
|
|
|
(232
|
)
|
|
(341
|
)
|
|
140
|
|
Total
deferred income taxes
|
|
|
(1,129
|
)
|
|
(2,279
|
)
|
|
3,983
|
|
Investment
tax credits-net
|
|
|
(282
|
)
|
|
(284
|
)
|
|
(284
|
)
|
Income
tax expense
|
|
$
|
6,499
|
|
$
|
5,676
|
|
$
|
5,762
|
|
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:
|
|
For
the Years ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
Income
before income taxes and
|
|
|
|
|
|
|
|
preferred
dividends
|
|
$
|
16,622
|
|
$
|
16,856
|
|
$
|
17,346
|
|
Federal
statutory rate
|
|
|
35.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
Computed
"expected" federal income taxes
|
|
$
|
5,818
|
|
$
|
5,900
|
|
$
|
6,071
|
|
Increase
(decrease) in taxes resulting from:
|
|
|
|
|
|
|
|
|
|
|
Tax
versus book depreciation basis difference
|
|
|
99
|
|
|
91
|
|
|
(149
|
)
|
Dividends
received deduction
|
|
|
(312
|
)
|
|
(350
|
)
|
|
(452
|
)
|
Amortization
of ITC
|
|
|
(282
|
)
|
|
(284
|
)
|
|
(284
|
)
|
State
tax
|
|
|
1,247
|
|
|
1,022
|
|
|
1,133
|
|
Excess
deferred taxes
|
|
|
(60
|
)
|
|
(60
|
)
|
|
(123
|
)
|
Energy
credits and production deduction
|
|
|
(493
|
)
|
|
(375
|
)
|
|
(125
|
)
|
Merger
expenses
|
|
|
555
|
|
|
-
|
|
|
-
|
|
Other
|
|
|
(73
|
)
|
|
(268
|
)
|
|
(309
|
)
|
Total
federal and state income tax
|
|
$
|
6,499
|
|
$
|
5,676
|
|
$
|
5,762
|
|
Effective
combined federal and state
|
|
|
|
|
|
|
|
|
|
|
income
tax rate
|
|
|
39.1
|
%
|
|
33.0
|
%
|
|
34.5
|
%
|
G.
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 a non-qualified retirement plan for certain employees.
Benefits
under the non-qualified plan are funded on a cash basis.
The
Company also 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.
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 $3.0 million during 2006, $2.0
million
during 2005 and $3.5 million during 2004. The Company currently plans
to
contribute approximately $2.0 million of additional funds during
2007.
During
2005, the Company increased its previously recognized minimum pension
liability
by $1.5 million to approximately $5.4 million, primarily as a result
of a
decrease in the pension plan discount rate assumption. Common equity
decreased
approximately $910,000, net of applicable income tax, through a charge
to
comprehensive income.
During
2006, the Company recorded a total unfunded pension obligation of approximately
$12.4 million, primarily as a result of the adoption of SFAS 158. Common
equity
increased approximately $3.2 million, through a credit to comprehensive
income
upon the elimination of the minimum pension funding liability. The
Company
recorded a regulatory asset for the total unfunded pension
obligation.
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, 2006 and 2005.
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
|
|
(In
thousands)
|
|
Change
in projected benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected
benefit obligation prior year end
|
|
$
|
45,419
|
|
$
|
41,531
|
|
$
|
19,012
|
|
$
|
18,979
|
|
Service
cost
|
|
|
1,400
|
|
|
1,229
|
|
|
277
|
|
|
306
|
|
Interest
cost
|
|
|
2,479
|
|
|
2,371
|
|
|
991
|
|
|
1,013
|
|
Participant
contributions
|
|
|
-
|
|
|
-
|
|
|
190
|
|
|
157
|
|
Plan
change
|
|
|
70
|
|
|
549
|
|
|
-
|
|
|
-
|
|
Change
in actuarial assumptions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Actuarial
(gain) loss
|
|
|
(2,242
|
)
|
|
1,880
|
|
|
(411
|
)
|
|
(287
|
)
|
Benefits
paid
|
|
|
(2,116
|
)
|
|
(1,964
|
)
|
|
(1,447
|
)
|
|
(1,156
|
)
|
Administrative
expense
|
|
|
(112
|
)
|
|
(177
|
)
|
|
-
|
|
|
-
|
|
Projected
benefit obligation as of year end
|
|
$
|
44,898
|
|
$
|
45,419
|
|
$
|
18,612
|
|
$
|
19,012
|
|
Accumulated
benefit obligation
|
|
$
|
44,898
|
|
$
|
45,419
|
|
$
|
18,612
|
|
$
|
19,012
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets as of prior year end
|
|
$
|
32,217
|
|
$
|
29,930
|
|
$
|
12,306
|
|
$
|
11,672
|
|
Administrative
expenses paid
|
|
|
(112
|
)
|
|
(177
|
)
|
|
-
|
|
|
-
|
|
Participant
contributions
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Employer
contributions
|
|
|
3,369
|
|
|
2,011
|
|
|
-
|
|
|
250
|
|
Actual
return on plan assets
|
|
|
4,113
|
|
|
2,417
|
|
|
1,491
|
|
|
508
|
|
Benefits
paid
|
|
|
(2,116
|
)
|
|
(1,964
|
)
|
|
(191
|
)
|
|
(124
|
)
|
Fair
value of plan assets as of year end
|
|
$
|
37,471
|
|
$
|
32,217
|
|
$
|
13,606
|
|
$
|
12,306
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
status as of year end
|
|
$
|
(7,427
|
)
|
$
|
(13,203
|
)
|
$
|
(5,006
|
)
|
$
|
(6,706
|
)
|
Unrecognized
transition obligation
|
|
|
-
|
|
|
-
|
|
|
1,968
|
|
|
2,296
|
|
Unrecognized
prior service cost
|
|
|
1,426
|
|
|
1,566
|
|
|
(1,500
|
)
|
|
(1,738
|
)
|
Unrecognized
net actuarial loss
|
|
|
5,696
|
|
|
9,910
|
|
|
4,199
|
|
|
5,317
|
|
Prepaid
(accrued) benefits at year end
|
|
$
|
(305
|
)
|
$
|
(1,727
|
)
|
$
|
(339
|
)
|
$
|
(831
|
)
|
Net
periodic pension expense and other postretirement benefit costs include
the
following components:
|
|
For
the years ended December 31,
|
|
|
|
Pension
Plans
|
|
Other
Postretirement Benefits
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
2006
|
|
2005
|
|
2004
|
|
|
|
(In
thousands)
|
|
Service
cost
|
|
$
|
1,400
|
|
$
|
1,229
|
|
$
|
1,123
|
|
$
|
277
|
|
$
|
306
|
|
$
|
335
|
|
Interest
cost
|
|
|
2,479
|
|
|
2,371
|
|
|
2,290
|
|
|
991
|
|
|
1,013
|
|
|
1,165
|
|
Expected
return on plan assets
|
|
|
(2,621
|
)
|
|
(2,454
|
)
|
|
(2,285
|
)
|
|
(977
|
)
|
|
(967
|
)
|
|
(857
|
)
|
Amortization
of transition asset
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Amortization
of prior service cost
|
|
|
210
|
|
|
227
|
|
|
205
|
|
|
(239
|
)
|
|
(239
|
)
|
|
(239
|
)
|
Amortization
of the transition obligation
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
328
|
|
|
328
|
|
|
328
|
|
Recognized
net actuarial gain
|
|
|
480
|
|
|
351
|
|
|
267
|
|
|
192
|
|
|
177
|
|
|
338
|
|
Net
periodic benefit cost
|
|
$
|
1,948
|
|
$
|
1,724
|
|
$
|
1,600
|
|
$
|
572
|
|
$
|
618
|
|
$
|
1,070
|
|
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
Plans
|
|
Other
Postretirement Benefits
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Weighted
average assumptions as of year end:
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
6.00
|
%
|
|
5.50
|
%
|
|
6.00
|
%
|
|
5.50
|
%
|
Expected
return on plan assets
|
|
|
8.00
|
%
|
|
8.25
|
%
|
|
8.00
|
%
|
|
8.25
|
%
|
Rate
of compensation increase
|
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
Medical
inflation
|
|
|
-
|
|
|
-
|
|
|
9.25
|
%
|
|
10.00
|
%
|
Measurement
date
|
|
|
12/31/2006
|
|
|
12/31/2005
|
|
|
12/31/2006
|
|
|
12/31/2005
|
|
Census
date
|
|
|
1/1/2006
|
|
|
1/1/2005
|
|
|
1/1/2006
|
|
|
1/1/2005
|
|
Assumptions
used in
|
|
For
the years ended December 31,
|
|
periodic
cost measurement
|
|
Pension
Plans
|
|
Other
Postretirement Benefits
|
|
|
|
2006
|
|
2005
|
|
2006
|
|
2005
|
|
Weighted
average assumptions as of year end:
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
6.00
|
%
|
|
5.75
|
%
|
|
5.50
|
%
|
|
5.75
|
%
|
Expected
return on plan assets
|
|
|
8.00
|
%
|
|
8.25
|
%
|
|
8.00
|
%
|
|
8.25
|
%
|
Rate
of compensation increase
|
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
Current
year trend
|
|
|
-
|
|
|
-
|
|
|
9.25
|
%
|
|
10.00
|
%
|
Ultimate
year trend
|
|
|
|
|
|
|
|
|
5.00
|
%
|
|
5.00
|
%
|
Year
of ultimate trend
|
|
|
|
|
|
|
|
|
2011
|
|
|
2011
|
|
For
measurement purposes, a 9.25 percent annual rate of increase
in the per capita
cost of covered medical benefits was assumed for 2006. 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 total of the service and interest cost
components of net
periodic postretirement cost for the year ended December
31, 2006 by $152,000,
or 12.0 percent. Decreasing the trend rate by one percentage
point for all
future years would decrease the total of the service and
interest cost
components of net periodic postretirement cost for 2005 by
$117,000, or 9.2
percent.
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 combined
plan assets be
invested in equity securities, 30 percent of combined 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 8.00 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
Plans' Assets
|
|
Other
Postretirement Benefit Assets
|
|
Asset
Category
|
|
For
the years ended December 31,
|
|
|
|
2007
Target
|
|
2006
|
|
2005
|
|
2007
Target
|
|
2006
|
|
2005
|
|
Equity
Securities
|
|
|
65.00
|
%
|
|
53.06
|
%
|
|
66.60
|
%
|
|
65.00
|
%
|
|
68.00
|
%
|
|
65.00
|
%
|
Debt
Securities
|
|
|
23.00
|
%
|
|
26.96
|
%
|
|
18.71
|
%
|
|
35.00
|
%
|
|
29.00
|
%
|
|
31.00
|
%
|
Real
Estate
|
|
|
0.00
|
%
|
|
0.00
|
%
|
|
0.00
|
%
|
|
0.00
|
%
|
|
0.00
|
%
|
|
0.00
|
%
|
Other
|
|
|
0.00
|
%
|
|
11.69
|
%
|
|
6.31
|
%
|
|
0.00
|
%
|
|
3.00
|
%
|
|
4.00
|
%
|
Alternative
investments
|
|
|
12.00
|
%
|
|
8.29
|
%
|
|
8.38
|
%
|
|
0.00
|
%
|
|
0.00
|
%
|
|
0.00
|
%
|
Total
|
|
|
100.00
|
%
|
|
100.00
|
%
|
|
100.00
|
%
|
|
100.00
|
%
|
|
100.00
|
%
|
|
100.00
|
%
|
|
|
|
|
Pension
Plans
|
|
Other
Postretirement Benefits
|
|
|
|
|
|
Projected
|
|
Projected
|
|
|
|
|
|
|
|
Benefit
|
|
|
|
Benefit
|
|
|
|
|
|
Contributions
|
|
payments
|
|
Contributions
|
|
payments
|
|
In
Thousands |
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
$
|
2,403
|
|
$
|
2,137
|
|
$
|
963
|
|
$
|
963
|
|
2008
|
|
|
|
|
|
2,700
|
|
|
2,644
|
|
|
1,000
|
|
|
999
|
|
2009
|
|
|
|
|
|
2,400
|
|
|
2,390
|
|
|
1,050
|
|
|
1,022
|
|
2010
|
|
|
|
|
|
2,300
|
|
|
2,286
|
|
|
1,050
|
|
|
1,065
|
|
2011
|
|
|
|
|
|
2,800
|
|
|
2,790
|
|
|
1,100
|
|
|
1,103
|
|
2012
through 2016
|
|
|
|
|
|
15,500
|
|
|
15,412
|
|
|
6,100
|
|
|
6,104
|
|
The
Company maintains a 401(k) Savings Plan for substantially
all employees. This
savings plan provides for employee contributions up to
specified limits. The
Company matches employee pre-tax contributions up to
4 percent, and contributes
an additional one-half percent each year made on a non-matching
basis, of
eligible compensation. The additional half percent contribution
was added
effective January 2004. The Company match is immediately
vested. The Company's
matching and non-matching contributions for the years
2006, 2005, and 2004 were
$530,000, $524,000 and $487,000, respectively.
H.
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 J Long-Term Power Purchases.
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
$4.5
million, net of recoveries. 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 $12.1 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 began 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, 2006, 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
|
|
$
|
10,482
|
|
$
|
5,753
|
|
McNeil
|
|
|
11.0
|
|
|
5.9
|
|
|
9,111
|
|
|
6,282
|
|
Stony
Brook (No. 1)
|
|
|
8.8
|
|
|
31.0
|
|
|
11,390
|
|
|
10,066
|
|
Wyman
(No. 4)
|
|
|
1.1
|
|
|
6.8
|
|
|
1,980
|
|
|
1,568
|
|
Metallic
Neutral Return
|
|
|
59.4
|
|
|
-
|
|
|
1,563
|
|
|
994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Metallic
Neutral Return is a neutral conductor for the
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 Case - 2007 Alternative Regulation Plan
On
December 22, 2006, the VPSB approved a 9.09 percent
rate increase for the
Company, effective January 1, 2007. The rate increase
allows us to recover
increased power and transmission costs in 2007 compared
to 2006. The VPSB also
approved the Company’s 2007 Alternative Regulation Plan, effective for three
years beginning February 1, 2007. The 2007 Alternative
Regulation Plan includes
the following principal elements:
· |
A
power supply cost adjustment mechanism under
which the Company will
recover or credit to customers, on a quarterly
basis, 90 percent of power
supply costs that are $300,000 (per quarter)
higher or lower than power
supply costs included in rates.
|
· |
An
allowed rate of return on equity (“ROE”) of 10.25 percent for 2007. The
allowed ROE adjusts annually, up or down, in
the amount of one-half the
change in the ten-year Treasury bond
rate.
|
· |
An
annual earnings sharing mechanism under which
the Company has the
opportunity to earn up to 75 basis points above
its allowed ROE and to
recover earning shortfalls in excess of 100
basis points below the allowed
ROE. Under the plan, certain exclusions, commonly
made in setting rates,
are applied to determine the Company’s earnings and are expected to affect
adversely the Company’s ability to earn its allowed rate of return
on
equity for core utility operations.
|
· |
Base
rates will be adjusted annually, based on the
Company’s cost of service.
Non-power supply cost increases are capped
at no more than $1.25 million
in 2008 and $1.5 million in 2009, exclusive
of ROE adjustments and
extraordinary costs in excess of $600,000 per
year. Base rate adjustments
must be approved by the VPSB.
|
· |
The
VPSB retains the authority to investigate the
Company’s rates at any time
and to modify or terminate the plan.
|
The
2007
Alternative Regulation Plan creates opportunities and
incentives for the Company
to become more efficient, improve customer service,
decouple earnings from
increased electricity sales, streamline cost recovery,
share efficiency savings
with customers, increase credit quality, and reduce
regulatory and borrowing
costs borne by customers.
Retail
Rate Case - 2003 Rate Plan
Under
the
2003 Rate Plan, the Company began amortizing (recovering),
in January 2005,
certain regulatory assets, including Pine Street Barge
Canal environmental site
costs and past demand-side management program costs,
with those amortizations to
be allowed in future rates. Pine Street costs will
be recovered over a
twenty-year period without a return.
In
January 2001, the VPSB issued the 2001 Settlement Order,
which included the
following:
· |
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;
|
· |
The
Company and customers shall share equally any
premium above book value
realized by the Company’s shareholders 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.
|
Accounting
Order
During
February 2006, the Company requested that the VPSB
grant an accounting order to
allow us to defer approximately $3.7 million in incremental
hurricane-related
power supply expenses to be incurred in the first quarter
of 2006, and to also
allow the Company to defer and amortize $1.3 million
of incremental
hurricane-related benefits realized in the fourth quarter
of 2005 against these
costs. The accounting order was approved by the VPSB
in February
2006.
Other
Legal Matters
The
Company does not expect any litigation to result in
a material adverse effect on
its operating results or financial condition.
I.
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, 2006, the
present value of the
Company's obligation is approximately $3.5 million.
Projected
future minimum payments under the Phase II support
agreements are as
follows:
|
|
For
the Years ending
|
|
|
|
December
31
|
|
|
|
(In
thousands)
|
|
|
|
|
|
2007
|
|
$
|
354
|
|
2008
|
|
|
354
|
|
2009
|
|
|
354
|
|
2010
|
|
|
354
|
|
2011
|
|
|
354
|
|
Total
for 2012-2015
|
|
|
1,772
|
|
Total
|
|
$
|
3,543
|
|
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.
J.
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 "Purchases from others" in the
accompanying Consolidated
Statements of Income.
Purchased
power expense by significant contract
supplier
|
|
|
|
|
|
|
|
|
|
for
the Yearsended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
In
thousands
|
|
|
|
|
|
|
|
Hydro
Quebec
|
|
$
|
55,045
|
|
$
|
50,112
|
|
$
|
48,309
|
|
Morgan
Stanley
|
|
|
10,313
|
|
|
12,563
|
|
|
11,106
|
|
VYNPC
|
|
|
40,357
|
|
|
32,409
|
|
|
33,331
|
|
Small
Power Producers
|
|
|
19,674
|
|
|
16,486
|
|
|
15,832
|
|
Stony
Brook
|
|
|
1,947
|
|
|
1,667
|
|
|
1,696
|
|
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
2006 follows.
|
|
Future
Payments Contractually Due by Period
|
|
At
December 31, 2006
|
|
|
|
|
|
2008
and
|
|
2010
and
|
|
After
|
|
|
|
Total
|
|
2007
|
|
2009
|
|
2011
|
|
2011
|
|
|
|
(In
thousands)
|
|
Hydro-Quebec
power supply contracts
|
|
$
|
475,117
|
|
$
|
52,376
|
|
$
|
103,582
|
|
$
|
105,676
|
|
$
|
213,483
|
|
JP
Morgan contract
|
|
|
75,680
|
|
|
17,029
|
|
|
36,973
|
|
|
21,678
|
|
|
-
|
|
Independent
Power Producers
|
|
|
120,610
|
|
|
17,145
|
|
|
31,332
|
|
|
29,619
|
|
|
42,514
|
|
Stony
Brook contract
|
|
|
23,573
|
|
|
3,858
|
|
|
7,844
|
|
|
7,878
|
|
|
3,994
|
|
VYNPC
PPA
|
|
|
189,308
|
|
|
33,744
|
|
|
73,155
|
|
|
72,118
|
|
|
10,292
|
|
Total
|
|
$
|
884,288
|
|
$
|
124,151
|
|
$
|
252,886
|
|
$
|
236,968
|
|
$
|
270,283
|
|
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 between 100MW
to 106MWof the plant output to the
Company through 2012, adjusted for uprate,
which is expected to represent
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
|
|
|
2006
|
|
$
|
40,357
|
|
estimated
|
|
|
2007-2012
|
|
$
|
36,318
|
|
Average
cost per KWh
|
|
|
2006
|
|
$
|
0.042
|
|
estimated
|
|
|
2007-2012
|
|
$
|
0.043
|
|
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 maintains insurance for unscheduled
outages for the Vermont Yankee plant
and those costs are included in rates. The
Company’s outage insurance coverage
is for 60 days and includes a $1 million
deductible amount and is limited to $6
million total coverage for incremental on-peak
energy replacement
costs.
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 other 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 under the
step-up provision would be
approximately $692 million for the remainder
of the contract, assuming that all
other members of the VJO defaulted by January
1, 2007 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 had 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. During 2004, Hydro Quebec exercised
its third and last option for
deliveries occurring principally during 2005
that resulted in an incremental
expense of $3.9 million based on current
market prices. 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, exercised their last
option to adjust deliveries by a five percent
load factor in the fourth quarter
of 2006 for delivery effective November 1,
2006 to October 31,
2007.
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, although 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
|
|
|
2006
|
|
$
|
13,608
|
|
|
|
|
$
|
9,380
|
|
|
|
|
estimated
|
|
|
2007-2015
|
|
$
|
14,514
|
|
|
(1
|
)
|
$
|
10,015
|
|
|
(1
|
)
|
Annual
capacity charge
|
|
|
2006
|
|
$
|
16,774
|
|
|
|
|
$
|
11,504
|
|
|
|
|
estimated
|
|
|
2007-2015
|
|
$
|
16,769
|
|
|
(1
|
)
|
$
|
11,493
|
|
|
(1
|
)
|
Average
cost per KWh
|
|
|
2006
|
|
$
|
0.065
|
|
|
|
|
$
|
0.065
|
|
|
|
|
estimated
|
|
|
2007-2015
|
|
$
|
0.072
|
|
|
(2
|
)
|
$
|
0.072
|
|
|
(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 agreement 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 could 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 could purchase no more than 200,000 MWh in any given contract
year
ending October 31. As of December 31, 2005, Hydro Quebec had purchased all
MWh
available under option B.
Hydro
Quebec exercised options A and B for 2004 and 2005, and the Company purchased
replacement power at a net cost of $3.2 million and $2.7 million, respectively.
The Company has also covered option A during 2006 at a net cost of $7.4 million.
The Company received an accounting order from the VPSB to defer $2.1 million
of
the 2006 expense. Hydro Quebec’s call for 2006 was made during the fourth
quarter of 2005 for delivery during January and February, timed to take
advantage of extremely high forward energy prices resulting from the effects
of
hurricanes Katrina and Wilma that interrupted gas production in the Gulf of
Mexico. Energy prices in the northeast are heavily dependent upon natural gas
prices.
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 supplied approximately 15 percent of the Company's estimated customer
demand ("load").
Under
the
Morgan Stanley Contract which expired on December 31, 2006, on a daily basis,
and at Morgan Stanley’s discretion, we sold power to Morgan Stanley from part of
our portfolio of power resources at predefined operating and pricing parameters.
Morgan Stanley sold to the Company, at a predefined price, power sufficient
to
serve pre-established load requirements.
The
Company
purchased the following amounts from Morgan Stanley for the years
indicated:
|
|
The
Morgan Stanley
|
|
|
|
Contract
|
|
|
|
|
|
Capacity
acquired*
|
|
|
1-182
MW
|
|
Contract
period expired
|
|
|
2006
|
|
Annual
energy charge :
|
|
|
|
|
2004
|
|
$
|
11.1
million
|
|
2005
|
|
$
|
12.6
million
|
|
2006
|
|
$
|
10.3
million
|
|
*Capacity
ranged between 0 and 182 MW over the contract life depending on the scheduled
hour.
The
JP Morgan Contract
The
Company entered into a contract with JP Morgan Ventures Energy Corporation
(the
“JP Morgan Contract”) during 2006 to purchase approximately 10 percent of the
Company’s retail load requirements for a four year period commencing January 1,
2007 and ending December 31, 2010. The contract is for firm physical delivery
of
specified hourly quantities and is not associated with any generation source
and
not subject to outage risk. There is no optionality under the contract for
either party. Estimated purchases under the JP Morgan Contract are approximately
$17 million for 2007, $21 million for 2008, $16 million for 2009, and $22
million for 2010.
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 "Purchases from others"
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 2006 follows:
|
|
Stony
|
|
|
|
Brook
|
|
|
(Dollars
in thousands)
|
Plant
capacity
|
|
|
352.0
MW
|
|
Company's
share of output
|
|
|
4.40
|
%
|
Company's
annual share of:
|
|
|
|
|
Interest
|
|
$
|
75
|
|
Other
debt service
|
|
|
493
|
|
Other
capacity
|
|
|
511
|
|
Total
annual capacity
|
|
$
|
1,079
|
|
Company's
share of long-term debt
|
|
$
|
759
|
|
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
2006, the Company received 151,382 MWh under these long-term contracts
at a cost
of $19.7 million. These IPP purchases amount to 6.7 percent of the Company's
total MWh purchased and 14.7 percent of purchase power expenses. Estimated
purchases from IPPs are expected to range between approximately $14.9 million
and $17.1 million for the years 2007 through 2011.
K.
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
|
|
2006
Quarter ended
|
|
|
|
March
|
|
June
|
|
September
|
|
December
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
60,976
|
|
$
|
59,380
|
|
$
|
61,433
|
|
$
|
58,687
|
|
$
|
240,476
|
|
Operating
income
|
|
|
4,958
|
|
|
3,366
|
|
|
4,052
|
|
|
3,745
|
|
|
16,121
|
|
Net
income-continuing operations
|
|
|
3,536
|
|
|
2,026
|
|
|
2,831
|
|
|
1,538
|
|
|
9,931
|
|
Net
income-discontinued operations
|
|
|
76
|
|
|
-
|
|
|
53
|
|
|
63
|
|
|
192
|
|
Net
Income applicable to common stock
|
|
$
|
3,612
|
|
$
|
2,026
|
|
$
|
2,884
|
|
$
|
1,601
|
|
$
|
10,123
|
|
Basic
earnings per share from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$
|
0.68
|
|
$
|
0.39
|
|
$
|
0.54
|
|
$
|
0.28
|
|
$
|
1.88
|
|
Discontinued
operations
|
|
|
0.01
|
|
|
-
|
|
|
0.01
|
|
|
0.02
|
|
|
0.04
|
|
Basic
earnings per share
|
|
$
|
0.69
|
|
$
|
0.39
|
|
$
|
0.55
|
|
$
|
0.29
|
|
$
|
1.92
|
|
Weighted
average common shares outstanding
|
|
|
5,243
|
|
|
5,260
|
|
|
5,280
|
|
|
5,296
|
|
|
5,270
|
|
Diluted
earnings per share from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$
|
0.67
|
|
$
|
0.38
|
|
$
|
0.53
|
|
$
|
0.26
|
|
$
|
1.85
|
|
Discontinued
operations
|
|
|
0.01
|
|
|
-
|
|
|
0.01
|
|
|
0.02
|
|
|
0.04
|
|
Diluted
earnings per share
|
|
$
|
0.68
|
|
$
|
0.38
|
|
$
|
0.54
|
|
$
|
0.28
|
|
$
|
1.89
|
|
Weighted
average common and common equivalent
|
|
|
5,319
|
|
|
5,323
|
|
|
5,362
|
|
|
5,388
|
|
|
5,348
|
|
shares
outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts
in thousands except per share data
|
|
|
2005
Quarter ended
|
|
|
|
|
March
|
|
|
June
|
|
|
September
|
|
|
December
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$
|
58,248
|
|
$
|
54,888
|
|
$
|
57,584
|
|
$
|
75,140
|
|
$
|
245,860
|
|
Operating
income
|
|
|
4,326
|
|
|
3,647
|
|
|
3,839
|
|
|
4,269
|
|
|
16,081
|
|
Net
income-continuing operations
|
|
|
2,981
|
|
|
2,384
|
|
|
2,524
|
|
|
3,157
|
|
|
11,046
|
|
Net
income-discontinued operations
|
|
|
(2
|
)
|
|
(3
|
)
|
|
18
|
|
|
121
|
|
|
134
|
|
Net
Income applicable to common stock
|
|
$
|
2,979
|
|
$
|
2,381
|
|
$
|
2,542
|
|
$
|
3,278
|
|
$
|
11,180
|
|
Basic
earnings per share from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$
|
0.58
|
|
$
|
0.46
|
|
$
|
0.49
|
|
$
|
0.58
|
|
$
|
2.12
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.03
|
|
|
0.03
|
|
Basic
earnings per share
|
|
$
|
0.58
|
|
$
|
0.46
|
|
$
|
0.49
|
|
$
|
0.61
|
|
$
|
2.15
|
|
Weighted
average common shares outstanding
|
|
|
5,160
|
|
|
5,186
|
|
|
5,208
|
|
|
5,224
|
|
|
5,195
|
|
Diluted
earnings per share from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing
operations
|
|
$
|
0.56
|
|
$
|
0.45
|
|
$
|
0.48
|
|
$
|
0.60
|
|
$
|
2.09
|
|
Discontinued
operations
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
0.03
|
|
|
0.03
|
|
Diluted
earnings per share
|
|
$
|
0.56
|
|
$
|
0.45
|
|
$
|
0.48
|
|
$
|
0.63
|
|
$
|
2.12
|
|
Weighted
average common and common equivalent
|
|
|
5,301
|
|
|
5,271
|
|
|
5,301
|
|
|
5,318
|
|
|
5,284
|
|
shares
outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2006
and 2005,
and the related consolidated statements of income, changes in stockholders’
equity and comprehensive income, and cash flows for each of the three
years in
the period ended December 31, 2006. 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, 2006 and 2005, and the results of their
operations and their cash flows for each of the three years in the period
ended
December 31, 2006, in conformity with accounting principles generally
accepted
in the United States of America.
As
discussed in Note 1 to the consolidated financial statements, in 2006,
the
Company adopted the provisions of Statement of Financial Accounting Standard
No.
158, Employer's
Accounting for Defined Benefit Pension and Other Postretirement
Plans.
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, 2006, 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 12, 2007 expressed an unqualified opinion on management’s
assessment of the effectiveness of the Company’s internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
DELOITTE
& TOUCHE LLP
Boston,
Massachusetts
March
12,
2007
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, as amended,
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 amended) 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 are effective.
Management's
Report on Internal Control Over Financial Reporting
Our
management is
responsible for establishing and maintaining effective internal control
over
financial reporting and for the assessment of the effectiveness of internal
control over financial reporting. As defined by the SEC in Rules 13a-15(f)
and
15d-15(f) under the Securities Exchange Act of 1934, 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 implemented by the company’s management and
other personnel, with oversight by the Audit Committee of the Board of
Directors
to provide reasonable assurance regarding the reliability of financial
reporting
and the preparation of financial statements for external purposes in
accordance
with accounting principles generally accepted in the United States of
America
(generally accepted accounting principles).
Management’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
Company’s
assets; (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; 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.
In
connection with the preparation of the Company’s annual financial statements,
our management has undertaken an assessment, which includes the design
and
operational effectiveness of our internal control over financial reporting
using
the framework promulgated by the Committee of Sponsoring Organizations
of the
Treadway Commission, commonly referred to as “COSO”. The COSO framework is based
upon five integrated components of control: control environment, risk
assessment, control activities, information and communications and ongoing
monitoring.
Because
of its inherent limitations, internal control over financial reporting
may not
prevent or detect misstatements. Also, projection of any evaluation of
effectiveness to future periods is subject to the risk that controls
may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Based
on
the assessment performed, management has concluded that its internal
control
over financial reporting is effective and provides reasonable assurance
regarding the reliability of the Company’s financial reporting and the
preparation of its financial statements as of December 31, 2006 in accordance
with generally accepted accounting principles. Further, management has
not
identified any material weaknesses in internal control over financial
reporting
as of December 31, 2006.
The
Company’s external auditors, Deloitte & Touche LLP, have audited our
financial statements for the year ended December 31, 2006 included in
this
annual report on Form 10-K and, as part of that audit, have issued a
report on
management’s assessment of internal control over financial reporting, a copy of
which is included in this annual report on Form 10-K.
Changes
in Internal Controls
We
continue to review, revise and improve the effectiveness of our internal
control
over financial reporting. We have made no change in our internal control
over
financial reporting in connection with our fourth quarter evaluation
that
materially affected, or is reasonably likely to materially affect, our
internal
control over financial reporting.
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") maintained
effective internal control over financial reporting as of December 31,
2006,
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.
In
our
opinion, management’s assessment that the Company maintained effective internal
control over financial reporting as of December 31, 2006, 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, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2006, 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, 2006, of the Company and our report dated
March
12, 2007 expressed an unqualified opinion on those financial statements
and
included an explanatory paragraph regarding Green Mountain Power Corporation’s
accounting changes resulting from the adoption of a new accounting
standard.
DELOITTE
& TOUCHE LLP
Boston,
Massachusetts
March
12,
2007
ITEM
9B. OTHER INFORMATION
Pursuant
to Item 1.01 of Current Report on Form 8-K, the Company provides the
disclosures
included in Exhibits 10.d.76 and 10.d.77 hereto.
PART
III
ITEM
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
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. Such information is incorporated herein by reference.
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 20,
2006. 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,"
"Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters," "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. Such
information
is incorporated herein by reference.
PART
IV
ITEM
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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.
Date:
March 12, 2007
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
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
12, 2007
|
Christopher
L. Dutton
|
Officer,
and Director
(principal
executive officer)
|
|
/s/Mary
G. Powell
|
Chief
Operating Officer,
|
March
12, 2007
|
Mary
G. Powell
|
Senior
Vice President
|
|
/s/Dawn
D. Bugbee
|
Chief
Financial Officer,
|
March
12, 2007
|
Dawn
D. Bugbee
|
Vice
President and Treasurer
(principal
financial officer and principal accounting officer)
|
|
*Nordahl
L. Brue )
|
Chairman
of the Board
|
|
|
|
|
*Elizabeth
A. Bankowski )
|
|
|
|
|
|
*William
H. Bruett )
|
|
|
|
|
|
*Merrill
O. Burns )
|
|
|
|
|
|
*David
R. Coates )
|
Directors
|
|
|
|
|
*Kathleen
C. Hoyt )
|
|
|
|
|
|
*Euclid
A. Irving )
|
|
|
|
|
|
*Marc
A. vanderHyeyden )
|
|
|
|
|
|
*By:
/s/Christopher L. Dutton
|
|
March
12, 2007
|
Christopher
L. Dutton
(Attorney
- in - Fact)
|
|
|
ITEM
15(a) 3 and Item 15c. Exhibits
Exhibit
Number
|
Description
|
Exhibit
|
SEC
Docket
Incorporated
By
reference
Or
Page filed
herewith
|
3.1
|
Amended
and Restated Articles of Incorporation dated May 27, 2004
|
3A
|
Form
10-Q
June
2004
|
3.c
|
By-laws
of the Company, as amended December 8, 2003
|
3
|
Form
8-K
Dec.
8 2003 (1-8291)
|
4.b.1
|
Indentures
of First Mortgage and Deed of Trust dated as of February
1,
1955
|
4.b
|
2-27300
|
4.b.2
|
First
Supplemental Indentures 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
|
5.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
Supplement Indentures 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 Registration
Statement No.
33-59383
|
4.b.17
|
Form
10-Q Sept. 1995 (1-8291)
|
4.b.18
|
Credit
Agreement by and among Green Mountain Power, The Bank of
Nova Scotia,
State Street Bank and Trust Company, Fleet National Bank,
and Fleet
National Bank, as Agent
|
4.b.18
|
Form
10-K 1997
(1-8291)
|
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)
|
4.b.20
|
Revolving
Credit Agreement with Sovereign Bank, Keybank National Association
and
Sovereign Bank, as Agent
|
4.b.20
|
Form
8-K
June
19, 2006
|
4.b.21
|
Eighteenth
Supplemental Indenture dated as of July 1, 2006
|
4.b.21
|
Form
8-K
August
3, 2006
|
4.b.22
|
Bond
Purchase Agreement dated as of July 27, 2006 between Green
Mountain Power
Corporation and CIGNA Investments, Inc. and Hartford Life
Insurance
Company, as purchasers.
|
4.b.22
|
Form
8-K
August
3, 2006
|
10.a
|
Form
of Insurance Policy issued by Pacific Insurance Company,
with respect to
indemnification of Directors and Officers.
|
10.a
|
33-8146
|
10.b.1
|
Firm
Power Contract dated September 16, 1958, between the Company
and the State
of Vermont and supplements thereto dated September 19, 1958;
November 15,
1958; October 1, 1960 and February 1, 1964
|
13.d
|
2-27300
|
10.b.2
|
Power
Contract, dated February 1, 1968, between the Company and
Vermont Yankee
Nuclear Power Corporation
|
13.d
|
2-34346
|
10.b.3
|
Amendment,
dated June 1, 1972, to Power Contract between the Company
and Vermont
Yankee Nuclear Power Corporation
|
13.f.1
|
2-49697
|
10.b.3(a)
|
Amendment,
dated April 15, 1983, to Power Contract between the Company
and Vermont
Yankee Nuclear Power Corporation
|
10.b.3(a)
|
33-8164
|
10.b.3(b)
|
Additional
Power Contract, dated February 1, 1984, between the Company
and Vermont
Yankee Nuclear Power Corporation
|
10.b.3(b)
|
33-8164
|
10.b.4
|
Capital
Funds Agreement, dated February 1, 1968, between the Company
and Vermont
Yankee Nuclear Power Corporation
|
13.e
|
2-34346
|
10.b.5
|
Amendment,
dated March 12, 1968, to Capital Funds Agreement between
the Company and
Vermont Yankee Nuclear Power Corporation
|
13.f
|
2-34346
|
10.b.6
|
Guarantee
Agreement, dated November 5, 1981, of the Company for its
proportionate
share of the obligations of Vermont Yankee Nuclear Power
Corporation under
a $40 million loan arrangement
|
10.b.6
|
2-75293
|
10.b.7
|
Three-Party
Power Agreement among the Company, VELCO and Central Vermont
Public
Service Corporation dated November 19, 1969
|
13.i
|
2-49697
|
10.b.8
|
Amendment
to Exhibit 10.b.7, dated June 1, 1981
|
10.b.8
|
2-75293
|
Exhibit
Number
|
Description
|
Exhibit
|
SEC
Docket
Incorporated
By
reference
Or
Page filed
Herewith
|
10.b.9
|
Three-Party
Transmission Agreement among the Company, VELCO and Central Vermont
Public
Service Corporation, dated November 21, 1969
|
10.b.9
|
2-49697
|
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 into joint ownership
of
Wyman plant, dated November 1, 1974
|
5.16
|
2-52900
|
10.b.15
|
New
England Power Pool Agreement as amended to November 1,
1975
|
4.8
|
2-55385
|
10.b.16
|
Bulk
Power Transmission Contract between the Company and VELCO dated June
1,
1968
|
13.v
|
2-49697
|
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 October 1, 1977,
and
related Transmission Agreement, with the Massachusetts Municipal
Wholesale
Electric Company
|
10.b.20
|
33-8164
|
10.b.21
|
Agreement
dated October 1, 1977, for Joint Ownership, Construction and Operation
of
the MMWEC Phase I Intermediate Units, dated October 1,
1977
|
10.b.21
|
33-8164
|
10.b.28
|
Contract
dated February 1, 1980, providing for the sale of firm power and
energy by
the Power Authority of the State of New York to the Vermont Public
Service
Board
|
10.b.28
|
33-8164
|
10.b.30
|
Bulk
Power Purchase Contract dated April 7, 1976, between VELCO and the
Company
|
10.b.32
|
2-75293
|
10.b.33
|
Agreement
amending New England Power Pool Agreement dated as of December 1,
1981,
providing for use of transmission inter-connection between New England
and
Hydro Quebec
|
10.b.33
|
33-8164
|
10.b.34
|
Phase
I Transmission Line Support Agreement dated as of December 1, 1981,
and
Amendment No. 1 dated as of June 1, 1982, between VETCO and participating
New England utilities for construction, use and support of Vermont
facilities of transmission interconnection between New England and
Hydro
Quebec
|
10.b.34
|
33-8164
|
10.b.35
|
Phase
I Terminal Facility Support Agreement dated as of December 1, 1981,
and
Amendment No. 1 dated as of June 1, 1982, between New England Electric
Transmission Corporation and participating New England utilities
for
construction, use and support of New Hampshire facilities of transmission
interconnection between New England and Hydro Quebec
|
10.b.35
|
33-8164
|
10.b.36
|
Agreement
with respect to use of Quebec Interconnection dated as of December
1,
1981, among participating New England utilities for use of transmission
interconnection between New England and Hydro Quebec
|
10.b.36
|
33-8164
|
10.b.39
|
Vermont
Participation Agreement for Quebec Interconnection dated as of July
15,
1982, between VELCO and participating Vermont utilities for allocation
of
VELCO's rights and obligations as a participating New England utility
in
the transmission interconnection between New England and Hydro
Quebec.
|
10.b.39
|
33-8164
|
10.d.40
|
Vermont
Electric Transmission Company, Inc. Capital Funds Agreement dated
as of
July 15, 1982, between VETCO and VELCO for VELCO to provide capital
to
VETCO for construction of the Vermont facilities of the transmission
interconnection between New England and Hydro Quebec
|
10.b.40
|
33-8164
|
10.b.41
|
VETCO
Capital Funds Support Agreement dated as of July 15, 1982, between
VELCO
and participating Vermont utilities for allocation of VELCO's obligation
to VETCO under the Capital Funds Agreement
|
10.b.41
|
33-8164
|
10.b.42
|
Energy
Banking Agreement dated March 21, 1983, among Hydro 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.42
|
33-8164
|
10.b.43
|
Interconnection
Agreement dated March 21, 1983, between 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.43
|
33-8164
|
10.b.44
|
Energy
Contract dated March 21, 1983, between Hydro Quebec and participating
New
England utilities acting by and through the NEPOOL Management Committee
for purchase of surplus energy from Hydro Quebec
|
10.b.44
|
33-8164
|
10.b.50
|
Agreement
for Joint Ownership, Construction and Operation of the Highgate
Transmission Interconnection, dated August 1, 1984, between certain
electric distribution companies, including the Company
|
10.b.50
|
33-8164
|
Exhibit
Number
|
Description
|
Exhibit
|
SEC
Docket
Incorporated
By
reference
Or
Page filed
Herewith
|
10.b.51
|
Highgate
Operating and Management Agreement, dated as of August 1, 1984, among
VELCO and Vermont electric-utility companies, including the
Company
|
10.b.51
|
33-8164
|
10.b.52
|
Allocation
Contract for Hydro Quebec Firm Power dated July 25, 1984, between
the
State of Vermont and various Vermont electric utilities, including
the
Company
|
10.b.52
|
33-8164
|
10.b.53
|
Highgate
Transmission Agreement dated as of August 1, 1984, between the Owners
of
the Project and various Vermont electric distribution
companies
|
10.b.53
|
33-8164
|
10.b.61
|
Agreements
entered in connection with Phase II of the NEPOOL/Hydro Quebec +
450 KV
HVDC Transmission Interconnection
|
10.b.61
|
33-8164
|
10.b.62
|
Agreement
between UNITIL Power Corp. and the Company to sell 23 MW capacity
and
energy from Stony Brook Intermediate Combined Cycle Unit
|
10.b.62
|
33-8164
|
10.b.68
|
Firm
Power and Energy Contract dated December 4, 1987, between Hydro Quebec
and
participating Vermont utilities, including the Company, for the purchase
of firm power for up to thirty years
|
10.b.68
|
Form
10-K 1992 (1-8291)
|
10.b.69
|
Firm
Power Agreement dated as of October 26, 1987, between Ontario Hydro
and
Vermont Department of Public Service
|
10.b.69
|
Form
10-K 1992 (1-8291)
|
10.b.70
|
Firm
Power and Energy Contract dated as of February 23, 1987, between
the
Vermont Joint Owners of the Highgate facilities and Hydro Quebec
for up to
50 MW of capacity
|
10.b.70
|
Form
10-K 1992
(1-8291)
|
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, between the Vermont Joint
Owners
of the Highgate facilities and Hydro Quebec
|
10.b.71
|
Form
10-K 1992
(1-8291)
|
10.b.72
|
Participation
Agreement dated as of April 1, 1988, between Hydro Quebec and
participating Vermont utilities, including the Company, implementing
the
purchase of firm power for up to 30 years under the Firm Power and
Energy
Contract dated December 4, 1987 (previously filed with the Company's
Annual Report on Form 10-K for 1987, Exhibit Number
10.b.68
|
10.b.72
|
Form
10-Q June 1988 (1-8291)
|
10.b.72(a)
|
Restatement
of the Participation Agreement filed as Exhibit 10.b.72 on Form 10-Q
for
June 1988
|
10.b.72(a)
|
Form
10-K 1988
(1-8291)
|
10.b.77
|
Firm
Power and Energy Contract dated December 29, 1988 between Hydro Quebec
and
participating Vermont utilities, including the Company, for the purchase
of up to 54 MW of firm power and energy
|
10.b.77
|
Form
10-K 1988
(1-8291)
|
10.b.78
|
Transmission
Agreement dated December 23, 1988, between the Company and Niagara
Mohawk
Power Corporation (Niagara Mohawk), for Niagara Mohawk to provide
electric
transmission to the Company from Rochester Gas and Electric and Central
Hudson Gas and Electric
|
10.b.78
|
Form
10-K 1988
(1-8291)
|
10.b.81
|
Sales
Agreement dated May 24, 1989, between the Town of Hardwick, Hardwick
Electric Department and the Company for the Company to purchase all
of the
output of Hardwick's generation and transmission sources and to provide
Hardwick with all-requirements energy and capacity except for that
provided by the Vermont Department of Public Service or Federal Preference
Power
|
10.b.81
|
Form
10-Q
June
1989
(1-8291)
|
10.b.82
|
Sales
Agreement dated July 14, 1989, between Northfield Electric Department
and
the Company for the Company to purchase all of the output of Northfield's
generation and transmission sources and to provide Northfield with
all-requirements energy and capacity except for that provided by
the
Vermont Department of Public Service or Federal Preference
Power
|
10.b.82
|
Form
10-Q
June
1989
(1-8291)
|
10.b.85
|
Power
Purchase and Sale Agreement between Morgan Stanley Capital Group
Inc. and
the Company.
|
10.b.85
|
Form
10-K 1998
(1-8291)
|
10.b.90
|
Power
Purchase Agreement between Entergy Nuclear Vermont Yankee LLC and
Vermont
Yankee Nuclear Power Corporation
|
10.b.90
|
Form
10-Q June 2002 (1-8291)
|
10.b.91
|
First
Amendment to Purchase Power Agreement listed as Exhibit Number 10.b.90,
between Entergy Nuclear Vermont Yankee LLC and Vermont Yankee Nuclear
Power Corporation
|
10.b.91
|
Form
10-Q June 2002 (1-8291)
|
10.b.92
|
Amendment
to Power Purchase and Sale Agreement between Morgan Stanley Capital
Group,
Inc. and the Company
|
10.b.92
|
Form
10-K 2002 (1-8291)
|
10.b.93
|
2001
Amendatory Agreement - Power Supply Agreement between the Company
and
Vermont Yankee Nuclear Power Corporation
|
10.b.93
|
Form
10-K 2004
|
10.b.94
|
Agreement
and Plan of Merger by and among Northern New England Energy Corporation,
Northstars Merger Subsidiary Corporation and Green Mountain Power
Corporation, dated as of June 21, 2006
|
10.b.94
|
Form
8-K
June
22, 2006
|
10.b.95
|
Amended
and Restated Three-Party Transmission Agreement between Vermont Electric
Power Company, Inc., Central Vermont Public Service Corporation,
Green
Mountain Power Corporation, and Vermont Transco LLC.
|
10.b.95
|
Form
10-Q June 2006
|
10.b.96
|
Amended
and Restated Three-Party Agreement between Vermont Electric Power
Company,
Inc., Central Vermont Public Service Corporation, Green Mountain
Power
Corporation, and Vermont Transco LLC.
|
10.b.96
|
Form
10-Q June 2006
|
|
Management
contracts or compensatory plans or arrangements required to be filed
as
exhibits to this Form 10-K to Item 14(c)., all under SEC Docket
1-8291
|
|
|
10.d.1b
|
Green
Mountain Power Corporation Second Amended and Restated Deferred
Compensation Plan for Directors
|
10.d.1b
|
Form
10-K 1993
|
10.d.1c
|
Green
Mountain Power Corporation Second Amended and Restated Deferred
Compensation Plan for Officers
|
10.d.1c
|
Form
10-K 1993
|
10.d.1d
|
Amendment
No. 93.1 to the Amended and Restated Deferred Compensation Plan for
Officers
|
10.d.1d
|
Form
10-K 1993
|
10.d.1e
|
Amendment
No. 94.1 to the Amended and Restated Deferred Compensation Plan for
Officers
|
10.d.1e
|
Form
10-Q June 1994
|
10.d.2
|
Green
Mountain Power Corporation Medical Expense Reimbursement
Plan
|
10.d.2
|
Form
10-K 1991
|
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 Plan as
amended
|
10.d.4a
|
Form
10-K 1990
|
10.d.8
|
Green
Mountain Power Corporation Officers' Supplemental Retirement
Plan
|
10.d.8
|
Form
10-K 1990
|
10.d.15c
|
Green
Mountain Power 2000 Stock Incentive Plan
|
10.d.15c
|
Form
10-K 2001
|
10.d.40
|
Change
in Control Agreement with C. L. Dutton
|
10.d.40
|
Form
10-K 2003
|
10.d.41
|
Change
in Control Agreement with D. J. Rendall, Jr.
|
10.d.41
|
Form
10-K 2003
|
10.d.42
|
Change
in Control Agreement with R. J. Griffin
|
10.d.42
|
Form
10-K 2003
|
10.d.43
|
Change
in Control Agreement with W. S. Oakes
|
10.d.43
|
Form
10-K 2003
|
10.d.44
|
Change
in Control Agreement with M. G. Powell
|
10.d.44
|
Form
10-K 2003
|
10.d.45
|
Change
in Control Agreement with R. E. Rogan
|
10.d.45
|
Form
10-K 2005
|
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 D. R. Coates
|
10.d.56
|
Form
10-K 2003
|
10.d.57
|
Deferred
Stock Unit Agreement with E. A. Irving
|
10.d.57
|
Form
10-K 2003
|
10.d.58
|
Director
Deferral Agreement with E. A. Bankowski
|
10.d.58
|
Form
10-K 2003
|
10.d.59
|
Director
Deferral Agreement with M. O. Burns
|
10.d.59
|
Form
10-K 2003
|
10.d.60
|
Director
Deferral Agreement with D. R. Coates
|
10.d.60
|
Form
10-K 2003
|
10.d.61
|
Director
Deferral Agreement with E. A. Irving
|
10.d.61
|
Form
10-K 2003
|
10.d.62
|
Deferred
Stock Unit Agreement with E. A. Bankowski
|
10.d.62
|
Form
10-Q June 2004
|
10.d.63
|
Deferred
Stock Unit Agreement with N. L. Brue
|
10.d.63
|
Form
10-Q June 2004
|
10.d.64
|
Deferred
Stock Unit Agreement with W. H. Bruett
|
10.d.64
|
Form
10-Q June 2004
|
10.d.65
|
Deferred
Stock Unit Agreement with M. O. Burns
|
10.d.65
|
Form
10-Q June 2004
|
10.d.66
|
Deferred
Stock Unit Agreement with D. R. Coates
|
10.d.66
|
Form
10-Q June 2004
|
10.d.67
|
Deferred
Stock Unit Agreement with K. C. Hoyt
|
10.d.67
|
Form
10-Q June 2004
|
10.d.68
|
Deferred
Stock Unit Agreement with E. A. Irving
|
10.d.68
|
Form
10-Q June 2004
|
10.d.69
|
Deferred
Stock Unit Agreement with M. A. vanderHeyden
|
10.d.69
|
Form
10-Q
June
2004
|
10.d.70
|
Director
Deferral Agreement with E. A. Bankowski
|
10.d.70
|
Form
8-K
Dec.
2, 2004
|
10.d.71
|
Director
Deferral Agreement with M. O. Burns
|
10.d.71
|
Form
8-K
Dec.
2, 2004
|
10.d.72
|
Director
Deferral Agreement with E. A. Irving
|
10.d.72
|
Form
8-K
Dec.
2, 2004
|
10.d.73
|
Officer
Deferral Agreement with S. C. Terry
|
10.d.73
|
Form
8-K
Dec.
2, 2004
|
10.d.74
|
Officer
Deferral Agreement with W. S. Oakes
|
10.d.74
|
Form
8-K
Dec.
2, 2004
|
10.d.75
|
Board
of Directors' Resolutions Amending Deferred Compensation
Plan
|
10.d.75
|
Form
8-K
Dec.
30, 2004
|
10.d.76
|
Officer
Compensation Table
|
10.d.76
|
Form
10-K 2006
|
10.d.77
|
2006
Management Compensation Plan Description
|
10.d.77
|
Form
10-K 2006
|
|
Management
contracts or compensatory plans or arrangements required to be filed
as
exhibits to this Form 10-K to Item 14(c)., all under SEC Docket
1-8291
|
|
|
10.d.1b
|
Green
Mountain Power Corporation Second Amended and Restated Deferred
Compensation Plan for Directors
|
10.d.1b
|
Form
10-K 1993
|
10.d.1c
|
Green
Mountain Power Corporation Second Amended and Restated Deferred
Compensation Plan for Officers
|
10.d.1c
|
Form
10-K 1993
|
10.d.1d
|
Amendment
No. 93.1 to the Amended and Restated Deferred Compensation Plan for
Officers
|
10.d.1d
|
Form
10-K 1993
|
10.d.1e
|
Amendment
No. 94.1 to the Amended and Restated Deferred Compensation Plan for
Officers
|
10.d.1e
|
Form
10-Q June 1994
|
10.d.2
|
Green
Mountain Power Corporation Medical Expense Reimbursement
Plan
|
10.d.2
|
Form
10-K 1991
|
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 Plan as
amended
|
10.d.4a
|
Form
10-K 1990
|
10.d.8
|
Green
Mountain Power Corporation Officers' Supplemental Retirement
Plan
|
10.d.8
|
Form
10-K 1990
|
10.d.15c
|
Green
Mountain Power 2000 Stock Incentive Plan
|
10.d.15c
|
Form
10-K 2001
|
10.d.40
|
Change
in Control Agreement with C. L. Dutton
|
10.d.40
|
Form
10-K 2003
|
10.d.41
|
Change
in Control Agreement with D. J. Rendall, Jr.
|
10.d.41
|
Form
10-K 2003
|
10.d.42
|
Change
in Control Agreement with R. J. Griffin
|
10.d.42
|
Form
10-K 2003
|
10.d.43
|
Change
in Control Agreement with W. S. Oakes
|
10.d.43
|
Form
10-K 2003
|
10.d.44
|
Change
in Control Agreement with M. G. Powell
|
10.d.44
|
Form
10-K 2003
|
10.d.45
|
Change
in Control Agreement with R. E. Rogan
|
10.d.45
|
Form
10-K 2005
|
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 D. R. Coates
|
10.d.56
|
Form
10-K 2003
|
10.d.57
|
Deferred
Stock Unit Agreement with E. A. Irving
|
10.d.57
|
Form
10-K 2003
|
10.d.58
|
Director
Deferral Agreement with E. A. Bankowski
|
10.d.58
|
Form
10-K 2003
|
10.d.59
|
Director
Deferral Agreement with M. O. Burns
|
10.d.59
|
Form
10-K 2003
|
10.d.60
|
Director
Deferral Agreement with D. R. Coates
|
10.d.60
|
Form
10-K 2003
|
10.d.61
|
Director
Deferral Agreement with E. A. Irving
|
10.d.61
|
Form
10-K 2003
|
10.d.62
|
Deferred
Stock Unit Agreement with E. A. Bankowski
|
10.d.62
|
Form
10-Q June 2004
|
10.d.63
|
Deferred
Stock Unit Agreement with N. L. Brue
|
10.d.63
|
Form
10-Q June 2004
|
10.d.64
|
Deferred
Stock Unit Agreement with W. H. Bruett
|
10.d.64
|
Form
10-Q June 2004
|
10.d.65
|
Deferred
Stock Unit Agreement with M. O. Burns
|
10.d.65
|
Form
10-Q June 2004
|
10.d.66
|
Deferred
Stock Unit Agreement with D. R. Coates
|
10.d.66
|
Form
10-Q June 2004
|
10.d.67
|
Deferred
Stock Unit Agreement with K. C. Hoyt
|
10.d.67
|
Form
10-Q June 2004
|
10.d.68
|
Deferred
Stock Unit Agreement with E. A. Irving
|
10.d.68
|
Form
10-Q June 2004
|
10.d.69
|
Deferred
Stock Unit Agreement with M. A. vanderHeyden
|
10.d.69
|
Form
10-Q
June
2004
|
10.d.70
|
Director
Deferral Agreement with E. A. Bankowski
|
10.d.70
|
Form
8-K
Dec.
2, 2004
|
10.d.71
|
Director
Deferral Agreement with M. O. Burns
|
10.d.71
|
Form
8-K
Dec.
2, 2004
|
10.d.72
|
Director
Deferral Agreement with E. A. Irving
|
10.d.72
|
Form
8-K
Dec.
2, 2004
|
10.d.73
|
Officer
Deferral Agreement with S. C. Terry
|
10.d.73
|
Form
8-K
Dec.
2, 2004
|
10.d.74
|
Officer
Deferral Agreement with W. S. Oakes
|
10.d.74
|
Form
8-K
Dec.
2, 2004
|
10.d.75
|
Board
of Directors' Resolutions Amending Deferred Compensation
Plan
|
10.d.75
|
Form
8-K
Dec.
30, 2004
|
10.d.76
|
Officer
Compensation Table
|
10.d.76
|
Form
10-K 2006
|
10.d.77
|
2006
Management Compensation Plan Description
|
10.d.77
|
Form
10-K 2006
|
|
Management
contracts or compensatory plans or arrangements required to be filed
as
exhibits to this Form 10-K to Item 14(c)., all under SEC Docket
1-8291
|
|
|
10.d.79
|
Green
Mountain Power Corporations New Supplemental Retirement Plan with
C. L.
Dutton
|
10.d.79
|
Form
8-K 2005
July
29, 2005
|
10.d.80
|
Green
Mountain Power Corporations New Supplemental Retirement Plan with
R. J.
Griffin
|
10.d.80
|
Form
8-K 2005
July
29, 2005
|
10.d.81
|
Green
Mountain Power Corporations New Supplemental Retirement Plan with
W. S.
Oakes
|
10.d.81
|
Form
8-K 2005
July
29, 2005
|
10.d.82
|
Green
Mountain Power Corporations New Supplemental Retirement Plan with
M. G.
Powell
|
10.d.82
|
Form
8-K 2005
July
29, 2005
|
10.d.83
|
Green
Mountain Power Corporations New Supplemental Retirement Plan with
D. J.
Rendall, Jr.
|
10.d.83
|
Form
8-K 2005
July
29, 2005
|
10.d.84
|
Green
Mountain Power Corporations Officers' Supplemental Retirement Plan
with S.
C. Terry
|
10.d.84
|
Form
10-K 2004
|
10.d.86
|
Green
Mountain Power Corporation 2004 Stock Incentive Plan
|
10.d.86
|
Form
10-K 2005
|
10.d.87
|
Green
Mountain Power Corporation Third Amended and Restated Deferred
Compensation Plan for Certain Officers
|
10.d.87
|
Form
10-K 2004
|
10.d.88
|
2005
Officer Deferred Stock Unit Agreement with Christopher L.
Dutton
|
10.d.88
|
Form
8-K
May
27, 2005
|
10.d.89
|
2005
Officer Deferred Stock Unit Agreement with Robert J.
Griffin
|
10.d.89
|
Form
8-K
May
27, 2005
|
10.d.90
|
2005
Officer Deferred Stock Unit Agreement with Walter S. Oakes
|
10.d.90
|
Form
8-K
May
27, 2005
|
10.d.91
|
2005
Officer Deferred Stock Unit Agreement with Mary G. Powell
|
10.d.91
|
Form
8-K
May
27, 2005
|
10.d.92
|
2005
Officer Deferred Stock Unit Agreement with Donald J. Rendall,
Jr.
|
10.d.92
|
Form
8-K
May
27, 2005
|
10.d.93
|
2005
Officer Deferred Stock Unit Agreement with Stephen C.
Terry
|
10.d.93
|
Form
8-K
May
27, 2005
|
10.d.94
|
Officer
Deferred Stock Unit Agreement with Stephen C. Terry
|
10.d.94
|
Form
8-K
May
27, 2005
|
10.d.95
|
2005
Supplemental Retirement Plan with Stephen C. Terry
|
10.d.95
|
Form
8-K
May
27, 2005
|
10.d.96
|
2005
Director Deferred Stock Unit Agreement with Elizabeth A.
Bankowski
|
10.d.96
|
Form
8-K
July
26, 2005
|
10.d.97
|
2005
Director Deferred Stock Unit Agreement with Nordahl L.
Brue
|
10.d.97
|
Form
8-K
July
26, 2005
|
10.d.98
|
2005
Director Deferred Stock Unit Agreement with William H.
Bruett
|
10.d.98
|
Form
8-K
July
26, 2005
|
10.d.99
|
2005
Director Deferred Stock Unit Agreement with Merrill O.
Burns
|
10.d.99
|
Form
8-K
July
26, 2005
|
10.d.100
|
2005
Director Deferred Stock Unit Agreement with David R.
Coates
|
10.d.100
|
Form
8-K
July
26, 2005
|
10.d.101
|
2005
Director Deferred Stock Unit Agreement with Kathleen C.
Hoyt
|
10.d.101
|
Form
8-K
July
26, 2005
|
10.d.102
|
2005
Director Deferred Stock Unit Agreement with Euclid A.
Irving
|
10.d.102
|
Form
8-K
July
26, 2005
|
10.d.103
|
2005
Director Deferred Stock Unit Agreement with Marc A.
vanderHeyden
|
10.d.103
|
Form
8-K
July
26, 2005
|
10.d.104
|
Director
Deferral Agreement with David R. Coates
|
10.d.104
|
Form
8-K
January
4, 2006
|
10.d.105
|
Change
in Control Agreement with D. D. Bugbee
|
10.d.105
|
Form
8-K
March
7, 2006
|
10.d.106
|
Green
Mountain Power Corporations Supplemental Retirement Plan with D.
D.
Bugbee
|
10.d.106
|
Form
8-K
March
7, 2006
|
10.d.107
|
Amendment
to Change in Control Agreement with R. J. Griffin
|
10.d.107
|
Form
8-K
March
7, 2006
|
10.d.108
|
Form
of 2006 Officer Deferred Stock Unit Agreement with C. L. Dutton,
D. D.
Bugbee, R. J. Griffin, W. S. Oakes, M. G. Powell, D. J. Rendall,
Jr., and
R. E. Rogan
|
10.d.108
|
Form
8-K
May
23, 2006
|
10.d.109
|
Rights
Agreement, dated June 17, 1998, between Green Mountain Power Corporation
and Mellon Investor Services, LLC (f/k/a ChaseMellon Shareholders
Services, L.L.C.)(incorporated by reference from Exhibit 4.a.1 from
the
Company’s Current Report on Form 8-K filed on June 19,
1998)
|
10.d.109
|
Form
8-K
June
22, 2006
|
10.d.110
|
Amendment
to Rights Agreement, Dated June 21, 2006, between Green Mountain
Power
Corporation and Mellon Investor Services LLC (f/k/a ChaseMellon
Shareholder Services, L.L.C.)
|
10.d.110
|
Form
8-K
June
22, 2006
|
10.d.111
|
Resolutions
of the Compensation Committee of the Board of Directors of the Company
adopted on June 21, 2006, approving certain actions under the 2000
and
2004 Stock Incentive Plans
|
10.d.111
|
Form
8-K
June
22, 2006
|
10.d.112
|
Form
of consent provided by the Company’s executive officers and directors in
connection with Awards issued under the 2000 and 2004 Stock Incentive
Plans
|
10.d.112
|
Form
8-K
June
22, 2006
|
10.d.113
|
Resolutions
of the Compensation Committee of the Board of Directors of the Company
adopted on June 21, 2006, amending certain executive Supplemental
Retirement Plans
|
10.d.113
|
Form
8-K
June
22, 2006
|
|
Management
contracts or compensatory plans or arrangements required to be filed
as
exhibits to this Form 10-K to Item 14(c)., all under SEC Docket
1-8291
|
|
|
|
|
|
|
10.d.114
|
Form
of consent provided by the Company’s executive officers in connection with
the Amendments to the Supplemental Retirement Plans
|
10.d.114
|
Form
8-K
June
22, 2006
|
10.d.115
|
Form
of 2006 Director Deferred Stock Unit Agreement
|
10.d.115
|
Form
8-K
July
25, 2006
|
10.d.116
|
Resolutions
of the Compensation Committee of the Board of Directors of the Company
adopted on October 30, 2006, approving certain actions under the
Company’s
2004 Stock Incentive Plan
|
10.d.116
|
Form
8-K
November
1, 2006
|
10.d.117
|
Form
of consent provided by the Company’s executive officers and directors in
connection with DSUs issued under the Company’s 2004 Stock Incentive
Plan
|
10.d.117
|
Form
8-K
November
1, 2006
|
10.d.118
|
Resolutions
of the Board of Directors of Green Mountain Power Corporation adopted
on
December 4, 2006 amending (effective as of January 1, 2007) the Company’s
Deferred Compensation Plan for Certain Officers
|
10.d.118
|
Form
8-K
December
7, 2006
|
|
|
|
|
14
|
Green
Mountain Power Corporation's Code of Ethics and Conduct dated October
6,
2003
|
14
|
Form
10-K 2004
|
|
|
|
|
23.1
|
Consent
of Deloitte and Touche LLP
|
23.1
|
|
24
|
Limited
Power of Attorney
|
24
|
|
|
|
|
|
31.1
|
Certification
of Christopher L. Dutton, President and Chief Executive Officer,
pursuant
to Rules 13a-14(a) and Rule 15d-14(a) promulgated under the Securities
Act
of 1934, as Adopted pursuant to Section 302 of the Sarbanes-Oxley
Act of
2002
|
31.1
|
Form
10-K 2006
|
31.2
|
Certification
of Dawn D. Bugbee, Chief Financial Officer, Vice President and Treasurer
pursuant to Rules 13a-14(a) and Rule 15d-14(a) promulgated under
the
Securities Act of 1934, as Adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002
|
31.2
|
Form
10-K 2006
|
32.1
|
Certification
of Christopher L. Dutton, President and Chief Executive Officer,
Pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the
Sarbanes-Oxley Act of 2002
|
32.1
|
Form
10-K 2006
|
32.2
|
Certification
of Dawn D. Bugbee, Chief Financial Officer, Vice President and Treasurer
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of
the Sarbanes-Oxley Act of 2002
|
32.2
|
Form
10-K 2006
|
GRAPHIC
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end
EX-23.1
3
exhibit23_1.htm
EXHIBIT 23.1
Exhibit 23.1
Exhibit
23.1
Consent
of Independent Registered Public Accounting Firm
We
consent to the incorporation by reference in Registration Statement No.
333-38722 on Form S-3 and Registration Nos. 333-126879, 333-39822 and 333-42356
on Form S-8 of our report dated March 12, 2007, (which report expresses an
unqualified opinion and includes an explanatory paragraph relating to Green
Mountain Power Corporation and its subsidiairies’ accounting change resulting
from the adoption of Statement of Financial Accounting Standard No. 158,
Employer's
Accounting for Defined Benefit Pension and Other Postretirement
Plans),
relating to the financial statements of Green Mountain Power Corporation and
its
subsidiaries, and our report dated March 12, 2007 relating to management’s
report on the effectiveness of internal control over financial reporting,
appearing in this Annual Report on Form 10-K of Green Mountain Power Corporation
for the year ended December 31, 2006.
/s/DELOITTE
& TOUCHE LLP
Boston,
Massachusetts
March
12,
2007
EX-24
4
exhibit24.htm
EXHIBIT 24
Exhibit 24
Exhibit
24
POWER
OF ATTORNEY
We,
the
undersigned directors of Green Mountain Power Corporation, hereby severally
constitute Christopher L. Dutton, Mary G. Powell, and Dawn D. Bugbee, and each
of them singly, our true and lawful attorney with full power of substitution,
to
sign for us and in our names in the capacities indicated below, the Annual
Report on Form 10-K of Green Mountain Power Corporation for the fiscal year
ended December 31, 2006, and generally to do all such things in our name and
behalf in our capacities as directors to enable Green Mountain Power Corporation
to comply with the provisions of the Securities Exchange Act of 1934, as
amended, all requirements of the Securities and Exchange Commission, and all
requirements of any other applicable law or regulation, hereby ratifying and
confirming our signatures as they may be signed by our said attorney, to said
Annual Report.
SIGNATURE
|
TITLE
|
DATE
|
/s/Christopher
L. Dutton
|
President
and Director
(Principal
Executive Officer)
|
March
12, 2007
|
Christopher
L. Dutton
|
|
|
/s/Nordahl
L. Brue
|
Chairman
of the Board
|
March
12, 2007
|
Nordahl
L. Brue
|
|
|
/s/Elizabeth
A. Bankowski
|
Director
|
March
12, 2007
|
Elizabeth
A. Bankowski
|
|
|
/s/William
H. Bruett
|
Director
|
March
12, 2007
|
William
H. Bruett
|
|
|
/s/Merrill
O. Burns
|
Directors
|
March
12, 2007
|
Merrill
O. Burns
|
|
|
/s/David
R. Coates
|
Director
|
March
12, 2007
|
David
R. Coates
|
|
|
/s/Kathleen
C. Hoyt
|
Director
|
March
12, 2007
|
Kathleen
C. Hoyt
|
|
|
/s/Euclid
A. Irving
|
Director
|
March
12, 2007
|
Euclid
A. Irving
|
|
|
/s/Marc
A. vanderHeyden
|
Director
|
March
12, 2007
|
Marc
A. vanderHeyden
|
|
|
EX-31.1
5
exhibit31_1.htm
EXHIBIT 31.1
Exhibit 31.1
Exhibit
31.1
SECTION
302 CERTIFICATION
I,
Christopher L. Dutton, certify that:
1. |
I
have reviewed this Annual Report on Form 10-K for the year ended December
31, 2006 of Green Mountain Power
Corporation;
|
2. |
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3. |
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
4. |
The
registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
a) designed
such disclosure controls and procedures, or caused such disclosure controls
and
procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
b)designed
such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, 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;
c)evaluated
the effectiveness of the registrant's disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures as of the end of the period covered by this
report based on such evaluation; and
d)disclosed
in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the
registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. |
The
registrant's other certifying officer and I have disclosed, based on
our
most recent evaluation of internal control over financial reporting,
to
the registrant's auditors and the audit committee of the registrant's
board of directors (or persons performing the equivalent
functions):
|
a)all
significant deficiencies and material weaknesses in the design or operation
of
internal control over financial reporting which are reasonably likely to
adversely affect the registrant's ability to record, process, summarize and
report financial information; and
b)any
fraud, whether or not material, that involves management or other employees
who
have a significant role in the registrant's internal control over financial
reporting.
Date:
March 12, 2007
|
/s/Christopher
L. Dutton
|
Christopher
L. Dutton, Chief Executive Officer and
President
|
EX-31.2
6
exhibit31_2.htm
EXHIBIT 31.2
Exhibit 31.2
Exhibit
31.2
SECTION
302 CERTIFICATION
I,
Dawn
D. Bugbee, certify that:
1. |
I
have reviewed this Annual Report on Form 10-K for the year ended December
31, 2006 of Green Mountain Power
Corporation;
|
2. |
Based
on my knowledge, this report does not contain any untrue statement
of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3. |
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this
report;
|
4. |
The
registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
a)designed
such disclosure controls and procedures, or caused such disclosure controls
and
procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this report is being prepared;
b)designed
such internal control over financial reporting, or caused such internal control
over financial reporting to be designed under our supervision, 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;
c)evaluated
the effectiveness of the registrant's disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures as of the end of the period covered by this
report based on such evaluation; and
d)disclosed
in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the
registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5. |
The
registrant's other certifying officer and I have disclosed, based on
our
most recent evaluation of internal control over financial reporting,
to
the registrant's auditors and the audit committee of the registrant's
board of directors (or persons performing the equivalent
functions):
|
a)all
significant deficiencies and material weaknesses in the design or operation
of
internal control over financial reporting which are reasonably likely to
adversely affect the registrant's ability to record, process, summarize and
report financial information; and
b)any
fraud, whether or not material, that involves management or other employees
who
have a significant role in the registrant's internal control over financial
reporting.
Date:
March 12, 2007
|
/s/Dawn
D. Bugbee
|
Dawn
D. Bugbee, Chief Financial Officer, Vice President and
Treasurer
|
EX-32.1
7
exhibit32_1.htm
EXHIBIT 32.1
Exhibit 32.1
Exhibit
32.1
CERTIFICATION
PURSUANT TO
18
U.S.C. SECTION 1350,
AS
ADOPTED PURSUANT TO
SECTION
906 OF THE SARBANES-OXLEY ACT OF 2002
In
connection with the Annual Report on Form 10-K of Green Mountain Power
Corporation (the "Company") for the period ending December 31, 2006 as filed
with the Securities and Exchange Commission on the date hereof (the "Report"),
I, Christopher L. Dutton, Chief Executive Officer of the Company, certify,
pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley
Act of 2002, that:
(1) the
Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
(2) the
information contained in the Report fairly presents, in all material respects,
the financial condition and result of operations of the Company.
/s/Christopher
L. Dutton
|
Christopher
L. Dutton, Chief Executive Officer and President
|
March
12, 2007
|
EX-32.2
8
exhibit32_2.htm
EXHIBIT 32.2
Exhibit
32.2
CERTIFICATION
PURSUANT TO
18
U.S.C. SECTION 1350,
AS
ADOPTED PURSUANT TO
SECTION
906 OF THE SARBANES-OXLEY ACT OF 2002
In
connection with the Annual Report on Form 10-K of Green Mountain Power
Corporation (the "Company") for the period ending December 31, 2006 as filed
with the Securities and Exchange Commission on the date hereof (the "Report"),
I, Dawn D. Bugbee, Chief Financial Officer, Vice President and Treasurer of
the
Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of
the Sarbanes-Oxley Act of 2002, that:
(1) the
Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934, as amended; and
(2) the
information contained in the Report fairly presents, in all material respects,
the financial condition and result of operations of the Company.
/s/Dawn
D. Bugbee
|
Dawn
D. Bugbee
Chief
Financial Officer, Vice President and Treasurer
|
March
12, 2007
|
EX-10.D.76
10
exhibit_10d76.htm
EXHIBIT 10.D.76
Exhibit 10.d.76
Exhibit
10.d.76
Officer
Compensation Table
In
December 2006 the Compensation Committee approved a base salary adjustment
for
the CEO and recommended base salary increases ranging from three to five percent
for five other officers of the Company, effective January 1, 2007. The Board
of
Directors approved the non-CEO officer base salary increases in December 2006,
effective January 1, 2007. Officer salaries as of January 1, 2007 and short-term
incentive bonuses paid for 2006 performance are as set forth below:
Name
and Principal Position
|
2007
Salary
|
2006
Short-Term
Incentive
Bonuses
|
Christopher
L. Dutton
President
and Chief Executive
Officer
|
$381,100
|
$0
|
Mary
G. Powell
Senior
Vice President and
Chief
Operating Officer
|
$278,100
|
$0
|
Robert
J. Griffin
Vice
President, Power Supply and Risk Management
|
$199,820
|
$0
|
Donald
J. Rendall, Jr.
Vice
President, General Counsel
and
Corporate Secretary
|
$197,760
|
$0
|
Walter
S. Oakes
Vice
President - Field Operations
|
$161,710
|
$0
|
Dawn
D. Bugbee
Vice
President, Chief Financial
Officer
& Treasurer
|
$183,750
|
$0
|
EX-10.D.77
11
exhibit_10d77.htm
EXHIBIT 10.D.77
Exhibit 10.d.77
Exhibit
10.d.77
2006
Management Compensation Plan Description
CEO
and
officer compensation includes three components: Base salary is intended to
be
set at approximately the 50th
percentile for base salary compensation at comparable companies. Short-term
incentive compensation is intended to compensate officers for Company
performance and is linked to defined Company performance metrics, such that
if
performance targets are achieved, officers’ direct compensation (base salary
plus short-term incentive) would approximate the 40-50th
percentile of total direct compensation at comparable companies. Performance
metrics for short-term incentive compensation include customer service (60%),
based on meeting or exceeding seventeen specified customer service quality
performance standards in the Company's service quality plan approved by the
Vermont Public Service Board, and creating value for shareholders (40%), based
on the Company’s annual consolidated return on equity. The Compensation
Committee (with respect to the CEO) and the Board of Directors (with respect
to
other executive officers) retain discretion to reduce short-term incentive
compensation in light of events or circumstances that would make it
inappropriate to award short-term incentive compensation strictly in accordance
with these performance metrics. Long-term incentive compensation is designed
to
provide long-term incentives for future Company performance and is intended
to
bring total officer compensation to approximately the 40th
percentile of total compensation paid to equivalent executives at comparable
companies, if target performance criteria are met.
10-K
12
form_10-k.pdf
FORM 10-K YE 12 31 2006
begin 644 form_10-k.pdf
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