United
States
Securities
and Exchange Commission
Washington,
D.C. 20549
FORM
10-Q
x
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange
Act
of 1934
For
the quarterly period ended September 30, 2005
or
o
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 1-8291
GREEN
MOUNTAIN POWER CORPORATION
(Exact
name of registrant as specified in its charter)
Vermont
|
03-0127430
|
(State
or other jurisdiction of
incorporation
or organization
|
(I.R.S.
Employer
Identification
No.)
|
|
|
163
Acorn Lane
Colchester,
Vermont
(Address
of Principal Executive Offices)
|
05446
(Zip
Code)
|
(802)
864-5731
Registrant's
telephone number, including area code
Indicate
by check mark whether the registrant (1) has filed all reports required to
be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements
for
the past 90 days. Yes x
No
o
Indicate
by check mark whether the registrant is an accelerated filer (as defined in
Rule
12b-2 of the Exchange Act). Yes x
No
o
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date.
Class
- Common Stock
|
Outstanding
at October 31, 2005
|
$3.33
1/3 Par Value
|
5,224,070
|
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 including 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.
AVAILABLE
INFORMATION
Our
Internet website address is: www.greenmountainpower.biz. We make available
free
of charge through the website our annual report on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K and amendments to those reports filed
or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange
Act
of 1934, as amended, as soon as reasonably practicable after such documents
are
electronically filed with, or furnished to, the SEC. The information on our
website is not, and shall not be deemed to be, a part of this report or
incorporated into any other filings we make with the SEC.
PART
I FINANCIAL INFORMATION
GREEN
MOUNTAIN POWER CORPORATION
INDEX
TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND
SCHEDULES
At
and for the Three and Nine months Ended September 30, 2005 and
2004
Part
I.
|
Financial
Information
|
Page
Number
|
Item
1.
|
Financial
Statements
|
|
|
|
4
|
|
|
5
|
|
|
6
|
|
|
8
|
|
|
9
|
Item
2.
|
|
19
|
Item
3.
|
|
28
|
Item
4.
|
|
31
|
Part
II.
|
Other
Information
|
33
|
|
|
33
|
|
- Signatures
|
34
|
|
- Certifications
|
35
|
|
|
|
The
accompanying notes are an integral part of the consolidated financial
statements.
GREEN
MOUNTAIN POWER CORPORATION
|
|
|
Unaudited
|
|
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
|
September
30
|
|
|
September
30
|
|
In
thousands, except per share data
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Operating
revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
Revenues
|
|
$
|
57,584
|
|
$
|
51,224
|
|
$
|
162,874
|
|
$
|
154,838
|
|
Wholesale
Revenues
|
|
|
6,740
|
|
|
4,443
|
|
|
14,586
|
|
|
19,220
|
|
Total
operating revenues
|
|
|
64,324
|
|
|
55,667
|
|
|
177,460
|
|
|
174,058
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
Supply
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vermont
Yankee Nuclear Power Corporation
|
|
|
8,375
|
|
|
8,602
|
|
|
25,837
|
|
|
23,223
|
|
Company-owned
generation
|
|
|
1,905
|
|
|
1,650
|
|
|
4,336
|
|
|
5,095
|
|
Purchases
from others
|
|
|
30,125
|
|
|
23,814
|
|
|
77,739
|
|
|
80,916
|
|
Other
operating
|
|
|
6,968
|
|
|
5,089
|
|
|
17,124
|
|
|
14,518
|
|
Transmission
|
|
|
4,077
|
|
|
3,479
|
|
|
12,707
|
|
|
11,217
|
|
Maintenance
|
|
|
2,842
|
|
|
2,451
|
|
|
7,871
|
|
|
7,147
|
|
Depreciation
and amortization
|
|
|
3,770
|
|
|
3,479
|
|
|
11,299
|
|
|
10,451
|
|
Taxes
other than income
|
|
|
1,530
|
|
|
1,361
|
|
|
4,914
|
|
|
4,853
|
|
Income
taxes
|
|
|
893
|
|
|
1,147
|
|
|
3,826
|
|
|
4,246
|
|
Total
operating expenses
|
|
|
60,485
|
|
|
51,072
|
|
|
165,653
|
|
|
161,666
|
|
Operating
income
|
|
|
3,839
|
|
|
4,595
|
|
|
11,807
|
|
|
12,392
|
|
Other
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of affiliates and non-utility operations
|
|
|
360
|
|
|
410
|
|
|
1,201
|
|
|
943
|
|
Allowance
for equity funds used during construction
|
|
|
8
|
|
|
112
|
|
|
22
|
|
|
336
|
|
Other
income (deductions), net
|
|
|
3
|
|
|
(122
|
)
|
|
(70
|
)
|
|
112
|
|
Total
other income
|
|
|
371
|
|
|
400
|
|
|
1,153
|
|
|
1,391
|
|
Interest
charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,633
|
|
|
1,633
|
|
|
4,901
|
|
|
4,900
|
|
Other
interest
|
|
|
57
|
|
|
41
|
|
|
173
|
|
|
181
|
|
Allowance
for borrowed funds used during construction
|
|
|
(4
|
)
|
|
(71
|
)
|
|
(14
|
)
|
|
(213
|
)
|
Total
interest charges
|
|
|
1,686
|
|
|
1,603
|
|
|
5,060
|
|
|
4,868
|
|
Income
from continuing operations
|
|
|
2,524
|
|
|
3,392
|
|
|
7,900
|
|
|
8,915
|
|
Income
(Loss) from discontinued operations, net
|
|
|
18
|
|
|
(2
|
)
|
|
2
|
|
|
(9
|
)
|
Net
income applicable to common stock
|
|
$
|
2,542
|
|
$
|
3,390
|
|
$
|
7,902
|
|
$
|
8,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
Statements of Comprehensive Income
|
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
|
|
|
|
September
30
|
|
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
2,542
|
|
$
|
3,390
|
|
$
|
7,902
|
|
$
|
8,906
|
|
Other
comprehensive income, net of tax
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Comprehensive
income
|
|
$
|
2,542
|
|
$
|
3,390
|
|
$
|
7,902
|
|
$
|
8,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share
|
|
$
|
0.49
|
|
$
|
0.67
|
|
$
|
1.52
|
|
$
|
1.76
|
|
Diluted
earnings per share
|
|
$ |
0.48
|
|
$
|
0.65
|
|
$
|
1.50
|
|
$
|
1.70
|
|
Cash
dividends declared per share
|
|
$
|
0.25
|
|
$
|
0.22
|
|
$
|
0.75
|
|
$
|
0.66
|
|
Weighted
average common shares outstanding-basic
|
|
|
5,208
|
|
|
5,089
|
|
|
5,185
|
|
|
5,068
|
|
Weighted
average common shares outstanding-diluted
|
|
|
5,301
|
|
|
5,251
|
|
|
5,284
|
|
|
5,238
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
Nine
Months Ended
|
|
|
|
September
30
|
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
Operating
Activities
|
|
|
|
|
|
|
|
Income
from continuing operations
|
|
$
|
7,900
|
|
$
|
8,915
|
|
Adjustments
to reconcile net income to net cash
|
|
|
|
|
|
|
|
provided
by operating activities:
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
11,299
|
|
|
10,451
|
|
Equity
in undistributed earnings of associated companies
|
|
|
(1,107
|
)
|
|
(648
|
)
|
Dividends
from associated companies
|
|
|
916
|
|
|
545
|
|
Allowance
for funds used during construction
|
|
|
(36
|
)
|
|
(549
|
)
|
Amortization
of deferred purchased power costs
|
|
|
1,841
|
|
|
239
|
|
Deferred
income tax (benefit) expense, net of investment tax credit
amortization
|
|
|
(1,175
|
)
|
|
1,424
|
|
Deferred
purchased power costs
|
|
|
(2,023
|
)
|
|
(1,435
|
)
|
Rate
levelization liability and other deferred revenues
|
|
|
1,284
|
|
|
(1,876
|
)
|
Environmental
and conservation deferrals, net
|
|
|
(268
|
)
|
|
(1,250
|
)
|
Cash
in advance of construction
|
|
|
2,160
|
|
|
1,495
|
|
Gain
on sale of property
|
|
|
-
|
|
|
(242
|
)
|
Amortization
of Pine Street
|
|
|
255
|
|
|
-
|
|
Deferred
and share-based compensation
|
|
|
780
|
|
|
522
|
|
Changes
in:
|
|
|
|
|
|
|
|
Accounts
receivable and accrued utility revenues
|
|
|
(1,390
|
)
|
|
2,522
|
|
Prepayments,
fuel and other current assets
|
|
|
686
|
|
|
(145
|
)
|
Accounts
payable and other current liabilities
|
|
|
285
|
|
|
2,056
|
|
Income
taxes payable and receivable
|
|
|
1,012
|
|
|
(1,416
|
)
|
Other
|
|
|
(1,140
|
)
|
|
831
|
|
Net
cash provided by continuing operations
|
|
|
21,279
|
|
|
21,439
|
|
Net
loss from discontinued operations
|
|
|
2
|
|
|
(9
|
)
|
Net
cash provided by operating activities
|
|
|
21,281
|
|
|
21,430
|
|
Investing
Activities
|
|
|
|
|
|
|
|
Construction
expenditures
|
|
|
(14,281
|
)
|
|
(14,626
|
)
|
Restriction
of cash for renewable energy investments
|
|
|
(969
|
)
|
|
(352
|
)
|
Return
of capital from associated companies
|
|
|
166
|
|
|
220
|
|
Investment
in nonutility property
|
|
|
(156
|
)
|
|
(297
|
)
|
Net
cash used in investing activities
|
|
|
(15,240
|
)
|
|
(15,055
|
)
|
Financing
Activities
|
|
|
|
|
|
|
|
Issuance
of common stock
|
|
|
946
|
|
|
1,368
|
|
Short-term
debt
|
|
|
(3,000
|
)
|
|
(500
|
)
|
Cash
dividends
|
|
|
(3,898
|
)
|
|
(3,352
|
)
|
Net
cash used in financing activities
|
|
|
(5,952
|
)
|
|
(2,484
|
)
|
Net
increase in cash and cash equivalents
|
|
|
89
|
|
|
3,891
|
|
Cash
and cash equivalents at beginning of period
|
|
|
1,720
|
|
|
786
|
|
Cash
and cash equivalents at end of period
|
|
$
|
1,809
|
|
$
|
4,677
|
|
Supplemental
Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
Cash
paid for:
|
|
|
|
|
|
|
|
Interest
|
|
$
|
4,362
|
|
$
|
4,383
|
|
Income
taxes
|
|
|
3,073
|
|
|
2,897
|
|
Non-cash
construction additions
|
|
|
567
|
|
|
536
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
|
|
|
|
|
|
|
|
|
December
31
|
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Utility
plant
|
|
|
|
|
|
|
|
|
|
|
Utility
plant, at original cost
|
|
$
|
346,614
|
|
$
|
327,908
|
|
$
|
339,269
|
|
Less
accumulated depreciation
|
|
|
126,800
|
|
|
120,438
|
|
|
119,633
|
|
Utility
plant, net of accumulated depreciation
|
|
|
219,814
|
|
|
207,470
|
|
|
219,636
|
|
Property
under capital lease
|
|
|
4,731
|
|
|
5,162
|
|
|
4,731
|
|
Construction
work in progress
|
|
|
10,656
|
|
|
17,493
|
|
|
8,345
|
|
Total
utility plant, net
|
|
|
235,201
|
|
|
230,125
|
|
|
232,712
|
|
Other
investments
|
|
|
|
|
|
|
|
|
|
|
Associated
companies, at equity
|
|
|
10,089
|
|
|
5,779
|
|
|
10,179
|
|
Other
investments
|
|
|
10,454
|
|
|
8,731
|
|
|
8,780
|
|
Total
other investments
|
|
|
20,543
|
|
|
14,510
|
|
|
18,959
|
|
Current
assets
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
1,809
|
|
|
4,677
|
|
|
1,720
|
|
Accounts
receivable, less allowance for
|
|
|
|
|
|
|
|
|
|
|
doubtful
accounts of $466, $747 and $621
|
|
|
20,800
|
|
|
16,664
|
|
|
18,216
|
|
Accrued
utility revenues
|
|
|
5,769
|
|
|
4,874
|
|
|
6,964
|
|
Fuel,
materials and supplies, average cost
|
|
|
4,726
|
|
|
4,463
|
|
|
4,848
|
|
Prepayments
|
|
|
1,188
|
|
|
1,997
|
|
|
1,674
|
|
Income
tax receivable
|
|
|
695
|
|
|
422
|
|
|
1,717
|
|
Other
|
|
|
244
|
|
|
893
|
|
|
323
|
|
Total
current assets
|
|
|
35,231
|
|
|
33,990
|
|
|
35,462
|
|
Deferred
charges
|
|
|
|
|
|
|
|
|
|
|
Demand
side management programs
|
|
|
6,199
|
|
|
7,144
|
|
|
7,293
|
|
Purchased
power costs
|
|
|
2,540
|
|
|
3,170
|
|
|
2,322
|
|
Pine
Street Barge Canal
|
|
|
12,996
|
|
|
12,954
|
|
|
13,250
|
|
Net
power supply deferral
|
|
|
7,765
|
|
|
7,114
|
|
|
12,085
|
|
Power
supply derivative asset
|
|
|
22,826
|
|
|
11,511
|
|
|
10,736
|
|
Other
regulatory assets
|
|
|
6,612
|
|
|
7,578
|
|
|
6,932
|
|
Other
deferred charges
|
|
|
832
|
|
|
1,434
|
|
|
1,113
|
|
Total
deferred charges
|
|
|
59,770
|
|
|
50,905
|
|
|
53,731
|
|
Non-utility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property
and equipment
|
|
|
246
|
|
|
248
|
|
|
247
|
|
Other
assets
|
|
|
431
|
|
|
542
|
|
|
508
|
|
Total
non-utility assets
|
|
|
677
|
|
|
790
|
|
|
755
|
|
Total
assets
|
|
$
|
351,422
|
|
$
|
330,320
|
|
$
|
341,619
|
|
|
|
|
|
|
|
|
|
|
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
|
|
|
|
|
|
|
|
|
Consolidated
Balance Sheets
|
|
Unaudited
|
|
|
|
|
|
|
September
30
|
|
|
December
31
|
|
In
thousands except share data
|
|
|
2005
|
|
|
2004
|
|
|
2004
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
Common
stock, $3.33 1/3 par value,
|
|
|
|
|
|
|
|
|
|
|
authorized
10,000,000 shares (issued
|
|
|
|
|
|
|
|
|
|
|
6,050,209,
5,930,126 and 5,968,118)
|
|
$
|
20,167
|
|
$
|
19,767
|
|
$
|
19,894
|
|
Additional
paid-in capital
|
|
|
80,437
|
|
|
77,741
|
|
|
78,852
|
|
Retained
earnings
|
|
|
33,893
|
|
|
28,340
|
|
|
29,889
|
|
Accumulated
other comprehensive income
|
|
|
(2,353
|
)
|
|
(1,787
|
)
|
|
(2,353
|
)
|
Treasury
stock, at cost (827,639 shares)
|
|
|
(16,701
|
)
|
|
(16,701
|
)
|
|
(16,701
|
)
|
Total
common stock equity
|
|
|
115,443
|
|
|
107,360
|
|
|
109,581
|
|
Long-term
debt, less current maturities
|
|
|
93,000
|
|
|
93,000
|
|
|
93,000
|
|
Total
capitalization
|
|
|
208,443
|
|
|
200,360
|
|
|
202,581
|
|
Capital
lease obligation
|
|
|
4,364
|
|
|
4,967
|
|
|
4,493
|
|
Current
liabilities
|
|
|
|
|
|
|
|
|
|
|
Short-term
debt
|
|
|
-
|
|
|
-
|
|
|
3,000
|
|
Accounts
payable, trade and accrued liabilities
|
|
|
9,467
|
|
|
12,609
|
|
|
9,437
|
|
Accounts
payable to associated companies
|
|
|
5,545
|
|
|
3,212
|
|
|
7,391
|
|
Deferred
revenues
|
|
|
-
|
|
|
1,351
|
|
|
-
|
|
Accrued
taxes
|
|
|
1,353
|
|
|
-
|
|
|
1,290
|
|
Customer
deposits
|
|
|
936
|
|
|
954
|
|
|
1,063
|
|
Interest
accrued
|
|
|
1,788
|
|
|
1,769
|
|
|
1,136
|
|
Other
|
|
|
1,730
|
|
|
1,585
|
|
|
1,151
|
|
Total
current liabilities
|
|
|
20,819
|
|
|
21,480
|
|
|
24,468
|
|
Deferred
credits
|
|
|
|
|
|
|
|
|
|
|
Power
supply derivative liability
|
|
|
30,591
|
|
|
18,626
|
|
|
22,821
|
|
Accumulated
deferred income taxes
|
|
|
31,186
|
|
|
31,533
|
|
|
32,223
|
|
Unamortized
investment tax credits
|
|
|
2,351
|
|
|
2,641
|
|
|
2,564
|
|
Pine
Street Barge Canal cleanup liability
|
|
|
6,190
|
|
|
6,106
|
|
|
6,458
|
|
Accumulated
cost of removal
|
|
|
21,121
|
|
|
19,618
|
|
|
19,806
|
|
Deferred
compensation
|
|
|
8,740
|
|
|
8,625
|
|
|
8,872
|
|
Other
regulatory liabilities
|
|
|
4,858
|
|
|
4,403
|
|
|
4,012
|
|
Other
deferred liabilities
|
|
|
10,506
|
|
|
9,425
|
|
|
11,150
|
|
Total
deferred credits
|
|
|
115,543
|
|
|
100,977
|
|
|
107,906
|
|
COMMITMENTS
AND CONTINGENCIES, Note 3
|
|
|
|
|
|
|
|
|
|
|
Non-utility
|
|
|
|
|
|
|
|
|
|
|
Net
liabilities of discontinued segment
|
|
|
2,253
|
|
|
2,536
|
|
|
2,171
|
|
Total
non-utility liabilities
|
|
|
2,253
|
|
|
2,536
|
|
|
2,171
|
|
Total
capitalization and liabilities
|
|
$
|
351,422
|
|
$
|
330,320
|
|
$
|
341,619
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
|
|
|
|
Three
Months Ended
|
|
Nine
Months Ended
|
|
|
|
September
30
|
|
September
30
|
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
- beginning of period
|
|
$
|
32,657
|
|
$
|
26,071
|
|
$
|
29,889
|
|
$
|
22,786
|
|
Net
Income
|
|
|
2,542
|
|
|
3,390
|
|
|
7,902
|
|
|
8,906
|
|
Other
adjustments
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Cash
Dividends-common stock
|
|
|
(1,306
|
)
|
|
(1,121
|
)
|
|
(3,898
|
)
|
|
(3,352
|
)
|
Balance
- end of period
|
|
$
|
33,893
|
|
$
|
28,340
|
|
$
|
33,893
|
|
$
|
28,340
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GREEN
MOUNTAIN POWER CORPORATION
SEPTEMBER
30, 2005
Part
I — ITEM 1
1. SIGNIFICANT
ACCOUNTING POLICIES
It
is our
opinion that the financial information contained in this report reflects all
normal, recurring adjustments necessary to present a fair statement of results
for the periods reported, but such results are not necessarily indicative of
results to be expected for the year due to the seasonal nature of our business
and include other adjustments discussed elsewhere in this report necessary
to
reflect fairly the results of the interim periods. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with accounting principles generally accepted in the United States
of
America have been condensed or omitted in this Form 10-Q pursuant to the rules
and regulations of the Securities and Exchange Commission. However, the
disclosures herein, when read with the Green Mountain Power Corporation (the
"Company" or "GMP") annual report for 2004 filed on Form 10-K, are adequate
to
make the information presented not misleading. The preparation of financial
statements in conformity with generally accepted accounting principles requires
the use of estimates and assumptions that affect assets and liabilities, and
revenues and expenses. Actual results could differ from such
estimates.
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 Vermont Public Service Board ("VPSB"). The Vermont Department of Public
Service ("DPS" or the "Department") is the public advocate for utility
customers.
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. Regulators may
also require benefits to be deferred as regulatory liabilities, pending future
rate proceedings.
Revenues.
The VPSB
sets the rates we charge our customers for their electricity. In periods prior
to April 2001, we charged our customers higher rates for billing cycles in
December through March and lower rates for the remaining months. These were
called seasonally differentiated rates. Seasonal rates were eliminated in April
2001, and generated approximately $8.5 million of revenues deferred in 2001
pursuant to VPSB order (the "Deferred Revenues"), of which $3.0 million, was
recognized during 2004. At December 31, 2004, the Company had recognized all
the
Deferred Revenues.
Electricity
sales to customers are based on monthly meter readings. Estimated unbilled
revenues are recorded at the end of each monthly accounting period. In order
to
determine unbilled revenues, the Company makes various estimates including
1)
energy generated, purchased and resold, 2) losses of energy over transmission
and distribution lines, 3) kilowatt-hour usage by retail customer mix
(residential, small commercial and industrial), and 4) average retail customer
pricing rates.
The
Company recognizes revenues from sales of utility construction and other
services in retail revenues. To the extent that these revenues arise under
long-term contracts, the Company records revenues and net income using the
percentage of contract completion method.
Benefit
Plans.
The
Company sponsors several qualified and nonqualified pension plans and other
post-employment benefit plans covering current and former employees who meet
certain eligibility criteria. The assumptions used to calculate the cost and
obligations associated with these plans are determined on January 1 for the
upcoming year. These assumptions are disclosed in the Company's Annual Report
on
Form 10-K for the fiscal year ending December 31, 2004 (the "Form 10-K"). The
Company expects to contribute approximately $2.0 million to its benefit plans
in
2005. During the nine months ended September 30, 2005, GMP contributed $1.5
million to its benefit plans.
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
Qualified
Pension and Supplemental Pension Plans
|
|
September
30
|
|
September
30
|
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Service
cost
|
|
$
|
256
|
|
$
|
281
|
|
$
|
768
|
|
$
|
842
|
|
Interest
cost
|
|
|
588
|
|
|
573
|
|
|
1,764
|
|
|
1,718
|
|
Expected
return on plan assets
|
|
|
(603
|
)
|
|
(571
|
)
|
|
(1,809
|
)
|
|
(1,714
|
)
|
Amortization
of prior service cost
|
|
|
52
|
|
|
51
|
|
|
156
|
|
|
154
|
|
Recognized
net actuarial gain
|
|
|
55
|
|
|
67
|
|
|
165
|
|
|
200
|
|
Net
periodic pension benefit cost
|
|
$
|
348
|
|
$
|
401
|
|
$
|
1,044
|
|
$
|
1,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended
|
|
Other
Postretirement Benefit Plan
|
|
September
30
|
|
September
30
|
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Service
cost
|
|
$
|
77
|
|
$
|
84
|
|
$
|
231
|
|
$
|
251
|
|
Interest
cost
|
|
|
267
|
|
|
291
|
|
|
801
|
|
|
874
|
|
Expected
return on plan assets
|
|
|
(236
|
)
|
|
(214
|
)
|
|
(708
|
)
|
|
(643
|
)
|
Amortization
of prior service cost
|
|
|
(59
|
)
|
|
(60
|
)
|
|
(177
|
)
|
|
(179
|
)
|
Amortization
of the transition obligation
|
|
|
83
|
|
|
82
|
|
|
249
|
|
|
246
|
|
Recognized
net actuarial gain
|
|
|
56
|
|
|
85
|
|
|
168
|
|
|
254
|
|
Net
periodic other postretirement benefit cost
|
|
$
|
188
|
|
$
|
268
|
|
$
|
564
|
|
$
|
803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 third quarter of 2005 and 2004
were $131,000 and $137,000, respectively. The Company's matching and
non-matching contributions for the first nine months of 2005 and 2004 were
$351,000 and $380,000, respectively.
Reclassification.
The
Company changed the classification of certain previously reported amounts in
the
accompanying balance sheet and cash flow statement as of September 30, 2004
to
correct immaterial errors related to the accounting for income taxes. The effect
of the changes was to decrease accumulated deferred income taxes by $4.0
million, increase other deferred credits by $3.4 million, and increase net
liabilities of a discontinued segment by approximately $600,000. We reclassified
certain items on the cash flow statement and the balance sheet at and for the
nine months ended September 30, 2004 to provide additional detail and for
consistent presentation with the current year.
Earnings
Per Share.
Basic
earnings per share ("EPS") is calculated by dividing net income, by the
weighted-average common shares outstanding for the period. Diluted EPS reflects
the impact of the issuance of common shares for all potential dilutive common
shares outstanding during the period, including stock options.
Reconciliation
of income and shares used in
|
|
Three
months ended
|
|
Nine
months ended
|
|
computing
fully diluted earnings per share
|
|
September
30
|
September
30
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Net
income applicable to common stock
|
|
$
|
2,542
|
|
$
|
3,390
|
|
$
|
7,902
|
|
$
|
8,906
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average number of common shares-basic
|
|
|
5,208
|
|
|
5,089
|
|
|
5,185
|
|
|
5,068
|
|
Dilutive
effect of stock options
|
|
|
93
|
|
|
162
|
|
|
99
|
|
|
170
|
|
Weighted
average number of common shares-diluted
|
|
|
5,301
|
|
|
5,251
|
|
|
5,284
|
|
|
5,238
|
|
The
Company adopted the prospective method of accounting for stock-based
compensation under SFAS 148 beginning January 1, 2003. The information presented
below has been determined as if the Company accounted for all past employee
and
director stock options under the fair value method.
|
|
Three
months ended
|
Nine
Months Ended
|
Pro-forma
net income
|
|
September
30
|
September
30
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
In
thousands, except per share amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income reported
|
|
$
2,542
|
|
$
3,390
|
|
$
7,902
|
|
$
8,906
|
|
Pro-forma
net income
|
|
2,542
|
|
3,370
|
|
7,901
|
|
8,845
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
reported-basic
|
|
$
|
0.49
|
|
$
|
0.67
|
|
$
|
1.52
|
|
$
|
1.76
|
|
Pro-forma
basic
|
|
|
0.49
|
|
|
0.66
|
|
|
1.52
|
|
|
1.75
|
|
As
reported-diluted
|
|
|
0.48
|
|
|
0.65
|
|
|
1.50
|
|
|
1.70
|
|
Pro-forma
diluted
|
|
|
0.48
|
|
|
0.64
|
|
|
1.50
|
|
|
1.69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unregulated
operations. Our
wholly owned subsidiaries include GMP Real Estate Corporation and Green Mountain
Power Investment Company ("GMPIC"). Green Mountain Resources, Inc. and Green
Mountain Propane Gas Company Limited were dissolved in March and May 2004,
respectively, with no gain or loss resulting from dissolution. We also have
a
rental water heater program that is not regulated by the VPSB. The results
of
these subsidiaries, and the Company’s unregulated rental water heater program,
are included in equity in earnings of affiliates and non-utility operations
in
the Other Income (Deductions) section of the Consolidated Statements of Income.
Discontinued
Operations.
The
Company accounts for its wholly-owned subsidiary, Northern Water Resources,
Inc.
("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; a minority interest in a manufacturer of waste treatment equipment;
and
non-performing loans. Substantially all of NWR's investments have been written
off, except for associated deferred tax amounts, net of applicable valuation
allowances.
2.
INVESTMENT IN ASSOCIATED COMPANIES
We
recognize net income from our affiliates (companies in which we have ownership
interests) listed below based on our percentage ownership (equity
method).
Vermont
Yankee Nuclear Power Corporation ("VYNPC")
Percent
ownership: 33.6% common
Summarized
unaudited financial information for VYNPC follows:
|
|
Three
Months Ended
|
Nine
Months Ended
|
|
|
September
30
|
|
September
30
|
In
thousands
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
Gross
Revenue
|
|
$
41,918
|
|
$
44,132
|
|
$
125,227
|
|
$
118,329
|
|
Net
Income Applicable
|
|
|
169
|
|
|
130
|
|
|
511
|
|
|
401
|
|
to
Common Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in Net Income
|
|
|
57
|
|
|
44
|
|
|
172
|
|
|
135
|
|
Amounts
due to VYNPC at September 30
|
|
|
2,862
|
|
|
3,171
|
|
|
2,862
|
|
|
3,171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Entergy
Nuclear Vermont Yankee, LLC ("ENVY"), the owner of the Vermont Yankee Nuclear
Plant, has announced that, under current operating parameters, it will exhaust
the capacity of its existing nuclear waste storage pool in 2007 or 2008 and
will
need to store nuclear waste in so-called "dry fuel storage" facilities to
be
constructed on the site. Current Vermont law requires ENVY to obtain approval
of
the Vermont State legislature, in addition to VPSB approval, to construct
and
use such dry fuel storage facilities. The Vermont legislature passed a bill
in
June 2005 allowing ENVY to apply for dry fuel storage permission from the
VPSB.
The bill was signed into law in June and ENVY subsequently applied for VPSB
approval. VPSB hearings are expected to be conducted over an extended period
of
time.
If
ENVY
fails to obtain VPSB approval, ENVY could be required to shut down the Vermont
Yankee plant. If the Vermont Yankee plant is shut down, we would have to
acquire
substitute base load power resources, comprising approximately 35 percent
of our
estimated total power supply needs. At currently projected market prices
for
2006, we estimate the annual incremental cost (in excess of the projected
costs
of power under our power supply contract for output from the Vermont Yankee
facility) would be approximately $56.8 million annually. Recovery of those
increased costs in rates would require a rate increase of approximately 28
percent.
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 Proposal ("RPP") to reduce the balance of deferred replacement
power
costs.
The
RPP
was part of ENVY's request to uprate or increase the output of the Vermont
Yankee plant that was approved by the VPSB, subject to certain conditions.
The
Nuclear Regulatory Commission has not yet approved Entergy’s application to
uprate the plant. Under the RPP, we have indemnification rights to between
approximately $550,000 and $1.6 million to recover uprate-related reductions
in
output for the three-year period beginning in May 2004 and ending after
completion of the uprate (or a maximum of three years), depending on future
wholesale energy market prices. The Company and ENVY dispute whether the
fire
was uprate-related, and therefore whether the associated outage is subject
to
indemnification under the RPP. The Company has petitioned the VPSB to resolve
the dispute.
Vermont
Electric Power Company, Inc. ("VELCO")
Percent
ownership: 29.2%
common
30.0%
preferred
VELCO
and
its wholly-owned subsidiary, Vermont Electric Transmission Company, own and
operate 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 up to $32 million in VELCO through 2009 in support of various
transmission projects, including a $4.6 million investment made in the last
quarter of 2004.
Summarized
unaudited financial information for VELCO is as follows:
|
|
|
Nine
Months Ended
|
|
|
September
30
|
|
September
30
|
In
thousands
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Gross
Revenue
|
|
$
|
7,248
|
|
$
|
6,363
|
|
$
|
22,754
|
|
$
|
19,239
|
|
Net
Income
|
|
|
739
|
|
|
779
|
|
|
2,213
|
|
|
1,397
|
|
Equity
in Net Income
|
|
|
214
|
|
|
204
|
|
|
642
|
|
|
335
|
|
Amounts
due to VELCO at June 30
|
|
|
2,682
|
|
|
20
|
|
|
2,682
|
|
|
20
|
|
The
cost
of transmission services charged by VELCO included in the Company's transmission
expenses in the accompanying Consolidated Statements of Income amounted to
$3.2
million and $10.3 million in the third quarter and first nine months of 2005,
respectively, compared with $2.7 million and $8.9 million in the third quarter
and first nine months of 2004, respectively.
3.
COMMITMENTS AND CONTINGENCIES
Environmental
Matters
The
electric industry typically uses or generates a range of potentially hazardous
products in its operations. We must meet various land, water, air and aesthetic
requirements as administered by local, state and federal regulatory agencies.
We
believe that we are in substantial compliance with these requirements, and
that
there are no outstanding material complaints about our compliance with present
environmental protection regulations, except as described below under the
caption "Pine Street Barge Canal Superfund Site."
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." We have estimated total future costs of the Company’s
future obligations under the consent decree to be approximately $6.2 million.
The estimated liability is not discounted, and it is possible that our estimate
of future costs could change by a material amount. We previously recorded a
regulatory asset of $13.2 million to reflect unrecovered past and future Pine
Street costs. Pursuant to the Company’s 2003 Rate Plan approved by the VPSB, the
Company has begun 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.
Rates
-
Management
believes that fair regulatory treatment, including adequate and timely rate
relief, is required to maintain the Company's financial strength.
Retail
Rate Cases -
On
December 22, 2003, the VPSB approved our 2003 Rate Plan, jointly proposed by
the
Company and the Department. The 2003 Rate Plan covers the period from 2003
through 2006 and includes the following principal elements:
· |
The
Company’s rates remained unchanged through 2004. The 2003 Rate Plan allows
the Company to raise rates 1.9 percent, effective January 1, 2005,
and an
additional 0.9 percent, effective January 1, 2006, if the increases
are
supported by cost of service schedules submitted 60 days prior to
the
effective dates. We submitted a cost of service schedule supporting
the
1.9 percent rate increase for 2005, and in accordance with the plan,
the
increase became effective on January 1, 2005. On November 1, 2005,
we
submitted a cost of service schedule supporting the 0.9 percent rate
increase for 2006 in accordance with the plan. The rate increase
is
subject to VPSB approval. The VPSB retains the discretion to open
an
investigation of the Company’s rates at any time, at the request of the
DPS, the request of ratepayers, or on its own volition. Certain ratepayers
requested the VPSB to open such an investigation in connection with
the
Company’s 1.9 percent rate increase for 2005. The VPSB granted the request
in December 2004, and then, at our request, closed and terminated
its
investigation in January 2005, with no adverse impact on the Company’s
rates.
|
· |
The
Company may seek additional rate increases in extraordinary circumstances,
such as severe storm repair costs, natural disasters, extended
unanticipated unit outages, or significant losses of customer
load.
|
· |
The
Company’s annual allowed return on equity is 10.5 percent for the period
January 1, 2003 through December 31, 2006. During the same period,
the
Company’s earnings on core utility operations are capped at 10.5 percent.
The Company’s earnings did not exceed the cap in 2004. If earnings exceed
the cap in 2005 or 2006, they will be refunded to customers as a
credit on
customer bills or applied to reduce regulatory assets, as the Department
directs.
|
· |
The
Company carried forward into 2004 $3.0 million in Deferred Revenues
remaining at December 31, 2003, from a previous VPSB order. These
revenues
were applied in 2004 to offset increased
costs.
|
· |
The
Company has begun to amortize (recover) certain regulatory assets,
including Pine Street Barge Canal environmental site costs and past
demand-side management program costs, beginning in January 2005,
with
those amortizations to be allowed in future rates. Pine Street costs
will
be recovered over a twenty-year period without a
return.
|
Other
Regulatory Matters
On
March
29, 2005, the VPSB issued its Order in a retail rate proceeding filed by Central
Vermont Public Service Corporation (“CVPS”), the largest Vermont electric
utility. The CVPS Order included a determination that CVPS should calculate
its
utility earnings under a voluntary earnings cap, to which CVPS had previously
agreed, using a new ratemaking methodology. The VPSB required CVPS to
recalculate its earnings cap retroactively to 2001, after removing expenses
and
assets that would not be included in its cost of service or rate base. Under
the
2003 Rate Plan, GMP calculated its earnings cap in 2003 in the same manner
as
CVPS. GMP does not have substantial net assets on its balance sheet that would
normally be excluded from rate base. We have also calculated, and submitted
to
the DPS, earnings cap calculations for 2003 and 2004 applying the methodology
ordered by the VPSB in the CVPS rate case. The calculations indicate that the
Company did not exceed its earnings cap in 2003 and 2004 under either
calculation method.
The
CVPS
Order also provided CVPS with an allowed rate of return of 10 percent as
compared with the 10.5 percent return on equity allowed in our 2003 Rate Plan.
The CVPS Order found that CVPS's risk profile differs from GMP's in several
ways, including the absence of significant customer concentration risk, cost
of
capital and other considerations.
Power
Supply Risks and Contingencies
All
of
the Company’s power supply contract costs are currently being recovered through
rates approved by the VPSB. The Company’s most significant power supply
contracts are the Hydro Quebec Vermont Joint Owners ("VJO") Contract (the "VJO
Contract") and the VYNPC Contract, which together supply approximately 70
percent of our retail load. The Company has a contract with Morgan Stanley
Capital Group, Inc. (the "Morgan Stanley Contract"), that supplies approximately
16 percent of our load.
We
expect
approximately 90 percent of our estimated load requirements through 2006 to
be
met by our contracts and generation and other power supply resources. These
contracts and resources significantly reduce the Company's exposure to
volatility in wholesale energy market prices.
There
are
uncertainties regarding risks of delivery under various contracts that the
Company relies upon to satisfy customer demand for electricity. If the Company’s
entitlements for electricity are not realized due to delivery risks, the
exercise of options that reduce our entitlements under certain contracts, or
for
other reasons, then the Company would purchase replacement energy and be subject
to volatile energy prices that exist in the wholesale markets that could
materially affect our operating results and financial condition.
The
Company remains exposed to wholesale energy prices for approximately 10 percent
of its load. Wholesale energy price volatility can also adversely impact margins
on incremental sales. Energy price risk remains one of the Company’s most
significant risks and can have a material adverse effect on the Company’s
operating results and financial condition.
Our
outage risks are generally a function of how much energy we receive from a
particular source, the price of energy received from that source, whether the
energy is unrelated to any specific operating plant (low-risk system power)
or
is dependent upon a particular power plant operating (high-risk), and the
dependability of the transmission delivery system for that source. Counterparty
credit quality also impacts risk. The Company's most significant power supply
contract counterparties and certain associated risk attributes are summarized
in
the following table:
Contract
|
Counterparty
|
Investment
Grade
|
System
Power
or
Plant
|
Approximate
Percent
Load
|
Approximate
Amount
$
Per MWh
|
VYNPC
|
ENVY
(through VYNPC)
|
No
|
VY
Plant
|
35
- 40%
|
$40
|
VJO
|
Hydro
Quebec
|
Yes
|
System
Power
|
30
- 35%
|
$70
|
Morgan
Stanley
|
Morgan
Stanley
|
Yes
|
System
Power
|
16%
|
Confidential*
|
*Morgan
Stanley Contract terms are subject to a confidentiality
agreement.
See
further discussion of the Company's power supply commitments and risk under
Part
I, Item 3, Management's Discussion and Analysis.
Competition
The
Town
of Rockingham, Vermont, located in the southeastern portion of our service
territory, had an option to purchase a hydro-electric facility partially located
in the town (the "Bellows Falls facility"). On July 12, 2005, Rockingham voters
rejected their option to purchase the Bellows Falls facility. A group of
residents petitioned the Town for a re-vote on the issue. Upon re-vote,
Rockingham voters again rejected their option to purchase the Bellows Falls
facility, effectively ending negotiations between the Company and the Town
to
permit the Town to be responsible for its own power supply needs.
Other
Legal Matters
In
2002,
the owners of property along the shoreline of Joe's Pond, an impoundment located
in Danville, Vermont, created by the Company's West Danville hydro-electric
generating facility, filed an inquiry with the VPSB seeking review of certain
dam improvements made by the Company in 1995, alleging that the Company did
not
obtain all necessary regulatory approvals for the 1995 improvements and that
the
Company's improvements and subsequent operation of the dam have caused flooding
of the shoreline and property damage. The Company received VPSB approval for,
and has made additional dam improvements at, the facility. The VPSB had pending
a regulatory proceeding to determine whether to impose regulatory penalties
in
connection with the 1995 dam improvements. The Company and the DPS have
stipulated to a penalty amount of $50,000. The stipulation was approved by
the
VPSB on July 20, 2005 and the stipulated $50,000 penalty amount has been paid.
In addition, numerous owners of shoreline property on Joe's Pond have filed
a
lawsuit in Vermont superior court seeking damages for property damage allegedly
caused by the Company's negligent conduct in making dam improvements and
operating the dam facilities. The Company is defending against these claims.
The
Company does not expect the litigation to result in a material adverse effect
on
its operating results or financial condition.
4.
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 which allows for changes
in fair values of derivatives to be recorded as regulatory assets or
liabilities.
SFAS
133,
as amended, establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded on the balance sheet as either an asset or
liability measured at its fair value.
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 a derivative and is effective through 2015.
The
Morgan Stanley Contract is used to hedge against increases in fossil fuel
prices. The Morgan Stanley Contract is a derivative and expires December 31,
2006.
At
September 30, 2005, the Company had a power supply derivative liability recorded
in deferred credits of $30.6 million reflecting the fair value of the 9701
agreement, and a power supply derivative asset of $22.8 million, reflecting
the
fair value of the Morgan Stanley Contract. A corresponding net regulatory asset
of $7.8 million is also recorded in deferred charges. At December 31, 2004,
the
Company had a liability of $22.8 million, reflecting the fair value of the
9701
agreement, and an asset of $10.7 million, reflecting the fair value of the
Morgan Stanley Contract. A corresponding net regulatory asset of $12.1 million
was also recorded. The Company believes that the net regulatory asset is
probable of recovery in future rates. The net regulatory asset is based on
current estimates of future market prices that are likely to change by material
amounts.
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 would be recorded in the period that the derivative is sold
or
matures.
5. SEGMENTS
AND RELATED INFORMATION
The
Company's electric utility operation is its only operating segment. The electric
utility is engaged in the procurement, generation, distribution and sale of
electrical energy in the State of Vermont and also reports the results of its
wholly owned subsidiaries (GMPIC and GMP Real Estate) and the rental water
heater program as a separate line item in the Other Income section in the
Consolidated Statement of Income.
6.
NEW ACCOUNTING STANDARDS
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," (the "Act") which requires employers to provide
certain disclosures regarding the effect of the federal subsidy provided by
the
Act. The effect of the federal subsidy under the Act, accounted for as an
actuarial gain, resulted in a reduction of $3.5 million to the Company's
accumulated postretirement benefit obligation at December 31, 2004, and is
expected to reduce net periodic cost by approximately $368,000 in
2005.
In
December 2004, the FASB issued a revision to SFAS No. 123R, "Share-Based
Payments," which replaces SFAS No. 123, "Accounting for Stock-Based
Compensation." The revision determines how the Company will measure the cost
of
employee services received in exchange for share-based payments. The cost of
share-based payments will be based on the grant date fair value of the award.
The guidance is effective for the Company as of the beginning of 2006. The
Company has not yet determined what the impact of this new standard will be
on
its financial position or results of operations.
In
December 2004, the FASB issued FASB Staff Position 109-1 ("FSP 109-1"), which
was effective upon issuance, to provide guidance of the application of SFAS
No.
109, "Accounting for Income Taxes" ("SFAS 109"), to the provision within the
American Jobs Creation Act of 2004 ("Jobs Act") that provides a tax deduction
on
qualified production activities. The Jobs Act includes a tax deduction of up
to
9 percent (when fully phased-in) of the lesser of (a) "qualified production
activities income," as defined in the Jobs Act, or (b) taxable income (after
the
deduction for the utilization of any net operating loss carryforwards). The
tax
deduction is limited to 50 percent of W-2 wages paid by the taxpayer. FSP 109-1
clarifies that the manufacturer's deduction provided for under the Jobs Act
should be accounted for as a special deduction in accordance with SFAS 109
and
not as a tax rate reduction. The adoption of FSB 109-1 had no impact on the
Company's financial statements in 2004. The Company estimates that in 2005
the
deduction will approximate $80,000.
In
March
2005, the FASB issued FASB Interpretation No. 47 ("FIN 47") Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB 143,
Accounting for Asset Retirement Obligations. FIN 47 clarifies that the term
conditional
asset retirement obligation
as used
in FASB 143 refers to a legal obligation to perform an asset retirement activity
in which the timing or method of settlement is conditional on a future event
that may or may not be within the control of the reporting entity. An entity
is
required to recognize a liability for the fair value of a conditional asset
retirement obligation if the fair value can be reasonably estimated, and should
be recognized when incurred. FIN 47 is effective for the Company in 2005. The
Company has not yet determined what the impact of this new standard will be
on
its financial position or results of operations.
In
May
2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”,
a replacement of APB Opinion No. 20 and FASB Statement No. 3. This statement
applies to voluntary changes in accounting principle and requires retrospective
application to prior period final statements, unless impracticable to determine.
The statement is a result of a broader effort by the FASB to improve
comparability of financial reporting between US and international accounting
standards. The Company does not expect this standard to have any material impact
on its results of operations or its financial condition.
GREEN
MOUNTAIN POWER CORPORATION
Part
I — ITEM 2
CONDITION
AND RESULTS OF OPERATIONS
September
30, 2005
Executive
Overview -- Green
Mountain Power Corporation (the "Company") generates most of its earnings from
retail electricity sales. Our retail electricity sales typically grow at an
average annual rate of between one and two percent, about average for most
electric utility companies in New England. Wholesale revenues have relatively
minor impact on our operating results and financial condition because our power
supply resources approximate expected customer demand. The Company is regulated
and cannot adjust prices of retail electricity sales without regulatory approval
from the Vermont Public Service Board ("VPSB").
Fair
regulatory treatment is fundamental to maintaining the Company’s financial
stability. Rates must be set at levels to recover costs, including a market
rate
of return to equity and debt holders in order to attract capital. In December
2003, the Company received approval from the VPSB of a new rate plan covering
the period 2003 through 2006 (the "2003 Rate Plan"). In accordance with the
2003
Rate Plan, the VPSB approved, and the Company implemented, a 1.9 percent rate
increase, effective January 1, 2005. The 2003 Rate Plan also provides for an
additional 0.9 percent increase effective January 1, 2006, subject to the
Company's need for such increase. The
2003
Rate Plan is summarized in more detail in Part I, Item 1, Note 3 "Retail Rate
Cases".
The
Company expects to request an accounting order to defer incremental power supply
and transmission costs caused by an extraordinary and rapid increase in energy
prices that is forecasted to adversely affect costs in 2006 by a material
amount, absent deferral. Much of the recent increase in energy prices was caused
by hurricanes Katrina and Rita, which interrupted natural gas and oil supplies.
VPSB approval is required to permit the Company to defer these costs. The
estimated deferral amount is expected to range between $4 and $8 million and
could change by a material amount based on energy prices and other factors.
The
Company will not seek to defer unanticipated higher energy expenses incurred
in
2005.
The
VPSB’s January 2001 rate order (the "2001 Settlement Order") allowed the Company
to defer revenues of approximately $8.5 million (the “Deferred Revenues”),
generated by leveling winter/summer rates during 2001, to help offset costs
and
realize our allowed rate of return during the 2001-2003 period. The 2003 Rate
Plan permitted us to continue to defer and recognize these revenues in 2004.
We
recognized approximately $3.0 million of the Deferred Revenues in 2004. At
December 31, 2004, the Company had recognized all the Deferred
Revenues.
Power
supply expenses were equivalent to approximately 63 percent of total revenues
in
the third quarter of 2005. The Company’s need to seek rate increases from its
customers frequently moves in tandem with increases in our power supply costs.
We have entered into long-term power supply contracts for most of our energy
needs. All of our power supply contract costs are currently included in the
rates we charge our customers.
Company
forecasts presently indicate the need for a rate increase of approximately
13
percent in 2007 to achieve our allowed rate of return, caused principally by
forecasted higher replacement energy costs upon expiration of the Company's
power supply contract with Morgan Stanley Capital Group, Inc. on December 31,
2006, increased energy costs for uncovered load obligations and a forecasted
increase in transmission expense. Forecasted amounts could change materially
based on energy prices, the timing of transmission investments and other
factors. The Company is exploring alternatives designed to mitigate the
magnitude of this potential rate increase, including alternative regulation
and
power supply contract options. The Company expects the customers of many other
New England utilities to experience similar cost pressures in light of current
wholesale energy prices.
Growth
opportunities beyond the Company’s normal investment in its infrastructure
include a planned increase in our equity investment in Vermont Electric Power
Company, Inc. ("VELCO") and a planned increase in sales of utility
services.
In
this
section, we explain the general financial condition and the results of
operations for the Company and its subsidiaries. This explanation
includes:
· |
factors
that affect our business;
|
· |
our
earnings and costs in the periods presented and why they changed
between
periods;
|
· |
the
source of our earnings;
|
· |
our
expenditures for capital projects and what we expect they will be
in the
future;
|
· |
where
we expect to get cash for future capital expenditures; and
|
· |
how
all of the above affect our overall financial
condition.
|
Management
believes its most critical accounting policies include the timing of expense
and
revenue recognition under the regulatory accounting framework within which
we
operate; the manner in which we account for certain power supply arrangements
that qualify as derivatives; the assumptions that we make regarding defined
benefit plans and contingency reserves; and revenue recognition, particularly
as
it relates to unbilled and deferred revenues. These accounting policies, among
others, affect the Company's significant judgments and estimates used in the
preparation of its consolidated financial statements.
There
are
statements in this section that contain projections or estimates that are
considered to be "forward-looking" as defined by the Securities and Exchange
Commission (the "SEC"). In these statements, you may find words such as
believes, expects, forecasts, plans, or similar words. These statements are
not
guarantees of our future performance. There are risks, uncertainties and other
factors that could cause actual results to be different from those projected.
Some of the reasons the results may be different include:
· |
regulatory
and judicial decisions or
legislation
|
· |
changes
in regional market and transmission
rules
|
· |
energy
supply and demand and pricing
|
· |
contractual
commitments
|
· |
availability,
terms, timing and use of capital
|
· |
general
economic and business environment
|
· |
nuclear
and environmental issues
|
· |
industry
restructuring and cost recovery (including stranded
costs)
|
· |
performance
of equity investments in pension
assets
|
We
address these items in more detail below.
These
forward-looking statements represent our estimates and assumptions only as
of
the date of this report.
As
you read this section it may be helpful to refer to the consolidated financial
statements and notes in Part I - ITEM 1.
RESULTS
OF OPERATIONS
Earnings
Summary - Overview
In
this
section, we discuss our earnings and the principal factors affecting
them.
Total
basic earnings per share of Common Stock
|
|
|
Three
months ended
|
|
|
Nine
months ended
|
|
|
|
|
September
30
|
|
|
September
30
|
|
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Utility
business
|
|
$
|
0.49
|
|
$
|
0.66
|
|
$
|
1.50
|
|
$
|
1.72
|
|
Unregulated
businesses
|
|
|
0.00
|
|
|
0.01
|
|
|
0.02
|
|
|
0.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share of common stock
|
|
$
|
0.49
|
|
$
|
0.67
|
|
|
1.52
|
|
|
1.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share
|
|
$
|
0.49
|
|
$
|
0.67
|
|
$
|
1.52
|
|
$
|
1.76
|
|
Diluted
earnings per share
|
|
$
|
0.48
|
|
$
|
0.65
|
|
$
|
1.50
|
|
$
|
1.70
|
|
Operating
Results
The
Company had consolidated earnings of $0.48 per share of common stock, diluted,
for the third quarter of 2005 compared with consolidated earnings of $0.65
per
share of common stock, diluted, for the same period in 2004.
Earnings
declined in the third quarter of 2005 primarily as a result of higher power
supply, other operating and transmission expenses partially offset by an
increase in retail revenues. The earnings decline in 2005 was caused in large
part by significantly higher wholesale energy prices.
The
Company has long-term, essentially fixed-price, power supply contracts that
cover over 90 percent of customer demand under normal weather conditions.
Nonetheless we were exposed to higher energy prices in the third quarter
of
2005, including lost margins on incremental sales, increased costs of energy
lost over the transmission system (line losses) and higher allocated costs
from
ISO New England for congestion and other ancillary energy services. Hurricanes
Katrina and Rita and a very hot summer sent New England wholesale electricity
prices sharply higher in the third quarter.
The
Vermont Public Service Board issued an order in December 2003 allowing the
Company to carry unused deferred revenue totaling approximately $3.0 million
to
2004 and to recognize this revenue to achieve its allowed rate of return
during
2004. During the third quarter of 2004, the Company’s earnings benefited by
$0.05 per share as a result of recognizing deferred revenues, compared with
no
recognition of deferred revenue during the same period of 2005. A rate increase
of 1.9 percent effective in January 2005 resulted in the replacement of deferred
revenues with cash revenues and has contributed to strong cash flows in
2005.
Retail
operating revenues for the third quarter of 2005 increased by $6.4 million
compared with the same period in 2004, reflecting the effects of warmer summer
weather, increased sales of utility services to other municipalities and
utilities, a 1.9 percent rate increase and an increase in the number of
customers. Total retail megawatt hour sales of electricity increased by 6.6
percent in the third quarter of 2005, compared with the same period in 2004.
Sales to residential and small commercial and industrial customers increased
by
13.4 percent and 8.2 percent, respectively, compared with the third quarter
in
2004. By contrast, sales to large commercial and industrial customers decreased
by 0.2 percent in the third quarter of 2005 compared with the same quarter
last
year. Increased revenues from the sale of utility services to other utilities
and large industrial customers in the third quarter of 2005 also contributed
approximately $2.1 million to retail revenue growth, when compared to the
same
period last year. Other operating expenses increased by $1.9 million in the
third quarter of 2005, reflecting an increase of $1.7 million in utility
services expense. These sales of services are intended to allow the Company
to
recover a portion of its administrative and general and staffing costs from
other parties and ultimately reduce costs to customers. Wholesale revenues
in
the third quarter of 2005 increased by $2.3 million compared with the third
quarter of 2004, reflecting higher energy prices.
Power
supply expenses increased $6.3 million in the third quarter of 2005 compared
with the same quarter of 2004 due to increased costs of market purchases
to
serve marginal load, and increased costs of transmission line losses and
congestion costs allocated within the New England power pool by ISO New England.
Congestion charges represent the cost of delivering energy to customers and
reflect energy prices, customer demands, and the availability of transmission
and generation resources. The Company paid an average market price of
approximately $103 per megawatt hour for system purchases during hours when
customer demand exceeded supply during the third quarter of 2005, compared
to
$41 per megawatt hour in the same period last year, inclusive of the effects
of
congestion and line losses.
Transmission
expenses increased by $600,000 in the third quarter of 2005 compared with
the
same period last year, primarily as a result of increased energy purchases.
The
Company’s future growth will benefit from expanded transmission investment by
VELCO, principally for the construction of high voltage transmission lines
in
Vermont. The Northwest Reliability Project is the most significant component
of
that expanded investment. The VPSB has issued a certificate of public good
for
the project and VELCO has begun construction of this project.
The
Company recorded diluted earnings per share of $1.50 for the nine months
ended
September 30, 2005, compared with diluted earnings per share of $1.70 in
the
same period last year. Earnings decreased in 2005 principally because of
energy
price increases and increased transmission expenses, other operating expenses,
and depreciation and amortization expenses. These increases in expenses more
than offset the benefits of increased retail sales of electricity.
Transmission
expenses increased by approximately $1.5 million in the first nine months
of
2005 compared with the same period last year, reflecting an increase in charges
allocated for system support in New England by ISO New England and additional
transmission investment by VELCO.
Other
operating expenses increased by approximately $2.6 million in the nine months
of
2005 compared with the same period of 2004 due primarily to a $2.2 million
increase in expenses associated with the sale of utility services and regulatory
expenses. These expenses were substantially offset by an increase of $2.4
million in retail revenue from the sale of these services.
Energy
prices rose substantially in 2005, principally in the third quarter. The
increase in energy prices caused lost margins on retail sales and an increase
in
transmission line losses and congestion costs allocated within the New England
power pool by ISO-NE, when compared with the first nine months of
2004.
Depreciation
and amortization expenses increased by approximately $848,000 in the first
nine
months of 2005 as a result of increased investment in utility plant and
increased amortization of regulatory assets, when compared with the same
period
during 2004.
During
the nine month period ended September 30, 2004, the Company reversed operating
reserves totaling approximately $700,000, based upon management’s assessment
that the contingencies reserved for were no longer probable of
occurring.
OPERATING
REVENUES AND MWh
SALES
Our
revenues from operations, megawatt hour ("MWh") sales and average number
of
customers for the three and nine months ended September 30, 2005 and 2004
are
summarized below:
|
|
|
|
|
|
Nine
months ended
|
|
|
|
September
30
|
|
|
September
30
|
|
Dollars
in thousands
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
Operating
revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail
|
|
$
|
57,584
|
|
$
|
51,224
|
|
$
|
162,874
|
|
$
|
154,838
|
|
Sales
for Resale
|
|
|
6,740
|
|
|
4,443
|
|
|
14,586
|
|
|
19,220
|
|
Total
Operating Revenues
|
|
$
|
64,324
|
|
$
|
55,667
|
|
$
|
177,460
|
|
$
|
174,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh
Sales-Retail
|
|
|
525,783
|
|
|
493,135
|
|
|
1,508,825
|
|
|
1,469,090
|
|
MWh
Sales for Resale
|
|
|
74,139
|
|
|
93,833
|
|
|
209,017
|
|
|
347,453
|
|
Total
MWh Sales
|
|
|
599,922
|
|
|
586,968
|
|
|
1,717,842
|
|
|
1,816,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Number of Customers
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended
|
|
|
Nine
months ended
|
|
|
|
|
September
30
|
|
|
September
30
|
|
|
|
2005
|
|
|
2004
|
|
|
2005
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
76,316
|
|
|
75,253
|
|
|
76,162
|
|
|
75,341
|
|
Commercial
and Industrial
|
|
|
13,658
|
|
|
13,480
|
|
|
13,708
|
|
|
13,476
|
|
Other
|
|
|
60
|
|
|
62
|
|
|
61
|
|
|
62
|
|
Total
Number of Customers
|
|
|
90,034
|
|
|
88,795
|
|
|
89,931
|
|
|
88,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
Total
operating revenues in the third quarter of 2005 increased by $8.7 million
or
15.6 percent from the same period in 2004, consisting of an increase in retail
revenues of $6.4 million and an increase in wholesale revenues of $2.3 million.
Most of the Company's earnings result from retail sales of
electricity.
Retail
operating revenues for the third quarter of 2005 increased $6.4 million or
12.4
percent compared with the same period in 2004, reflecting increased megawatt
hour sales of electricity caused by warmer summer weather, increased revenues
from the sale of utility construction services, a 1.9 percent rate increase
under the 2003 Rate Plan and an increase in the total number of customers.
This
increase was offset in part by a $385,000 decrease in the recognition of
revenues deferred under the 2001 Settlement Order. Total retail megawatt
hour
sales of electricity increased by 6.6 percent in the third quarter of 2005,
compared with the same period in 2004. Sales to residential and small commercial
and industrial customers increased by 13.4 percent and 8.2 percent,
respectively, while sales to large commercial and industrial customers declined
by 0.2 percent, when comparing the third quarter of 2005 to the same period
in
2004. Most of the increase in residential and small commercial and industrial
consumption was related to warmer than normal summer weather.
The
Company recognizes revenues from sales of utility construction services in
retail revenues. Revenues from these activities amounted to $2.6 million
in the
third quarter of 2005 compared with $522,000 in the same period last year.
Revenues from these activities are expected to increase to approximately
$5
million during 2005 from $1.9 million in 2004.
Wholesale
revenues increased $2.3 million or 51.7 percent during the third quarter
of
2005, compared with the same period in 2004, as a result of increased energy
prices.
Retail
operating revenues increased $8.0 million or 5.2 percent during the first
nine
months of 2005, compared with the same period of 2004, reflecting an increase
of
approximately $2.9 million or 5.1 percent in revenues from residential
customers, an increase of $2.6 million or 4.7 percent in small commercial
and
industrial revenues, and an increase of $1.3 million or 3.4 percent in large
commercial and industrial revenues, offset by a $1.9 million decrease in
the
recognition of the Deferred Revenues. Other operating revenues also increased
by
$2.5 million reflecting increased revenues from sales of utility construction
services.
Total
retail MWh sales of electricity in the first nine months of 2005 increased
2.6
percent when compared with the first nine months of 2004, reflecting an increase
in residential and small commercial and industrial sales of 3.9 percent,
and 3.7
percent, respectively, and an increase of 0.4 percent in large commercial
and
industrial sales. A warmer than normal summer and an increase in the number
of
customers caused the increase in sales.
Wholesale
revenues decreased $4.6 million or 24.1 percent during the first nine months
of
2005, compared with the same period in 2004, as a result of reduced market
sales.
Customer
Concentration Risk
The
Company’s major industrial customer, International Business Machines ("IBM"),
accounted for 16.3 percent, 16.4 percent and 16.6 percent of retail revenue
for
2005 year to date, 2004 and 2003, respectively. The Company currently estimates,
based on current forward energy prices, that a hypothetical shutdown of the
IBM
facility would not require any rate increase, inclusive of projected related
declines in sales to residential and commercial customers. This effect occurs
because forward energy prices are well above the price at which we sell
electricity to IBM.
OPERATING
EXPENSES
Power
supply expenses
Power
supply expenses increased $6.3 million or 18.6 percent in the third quarter
of
2005 compared with the same period in 2004, primarily as a result of a $6.1
million increase in market purchases for resale and increased costs of
transmission line losses and congestion allocated within the New England
power
pool by ISO-NE. The increase in market purchases was caused by higher energy
prices and increased sales of electricity. Higher energy prices resulted
principally from a sharp rise occurring as hurricanes Katrina and Rita disturbed
energy production in the Gulf of Mexico. A significant amount of production
in
the Gulf remains unavailable, and prices remain high.
Power
supply expenses from VYNPC decreased $227,000 or 2.6 percent during the third
quarter of 2005 compared with the same period of 2004, primarily due to a
declines in the price of Vermont Yankee energy purchased under our contract
with
VYNPC.
Company-owned
generation expenses decreased $255,000 or 15.5 percent in the third quarter
of
2005 compared with the same period in 2004, primarily due to decreased
production at peak generation facilities, partially offset by higher fuel
prices. Peak generation facilities are run only to maintain system reliability
or when wholesale energy prices are extremely high.
The
cost
of power that we purchased from other companies increased $6.3 million or
26.5
percent in the third quarter of 2005 compared with the same period in 2004,
primarily due to increased market purchases caused by sharply higher energy
prices and increased retail sales of electricity.
The
Independent System Operator for New England ("ISO-NE") was created to manage
the
New England power pool. 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. Transmission projects, such as the recently approved Northwest
Reliability Project ("NRP"), will reduce congestion when they are completed.
The
NRP is not expected to be completed prior to 2007. Even though Vermont utilities
share a zone price for specific energy resources, congestion can cause a
material difference to arise between the credit received at a generating
point
or node, (for example, entitlements to Vermont Yankee at the Vermont Yankee
node) and the price that must be paid to serve Vermont load. ISO-NE allocates
congestion charges to New England utilities according to its load model
results.
ISO-NE
supports locational capacity payments (“LICAP”) to generators in an effort to
differentiate the price generators receive for capacity at different locations
within New England. ISO-NE believes that proposed higher capacity payments
in
constrained areas will encourage the development of new generation where
needed.
ISO-NE has petitioned FERC for approval of LICAP at levels that are expected
to
result in substantially higher capacity payments to generators beginning
January
1, 2006. The changes have been disputed by numerous parties for a variety
of
reasons. FERC has not yet approved ISO-NE’s LICAP proposal. In October 2005,
FERC initiated a settlement process to consider alternatives to the LICAP
proposal Under ISO-NE’s LICAP proposal, Vermont is expected to fare better than
many New England states since Vermont has not restructured and many of its
utilities, including the Company, have specified power supply resources that
meet their present needs. Therefore, requirements for capacity in Vermont
would
largely consist of obtaining resources for incremental as opposed to existing
load. Even incrementally, future LICAP amounts for load growth beyond 2006
could
be material, and if so, would be expected to increase Company rate requirements
accordingly.
Power
supply expenses increased $1.3 million or 1.2 percent in the first nine months
of 2005 compared with the same period in 2004, primarily as a result of a
$3.2
million increase in the cost of power we purchase from others, and a $2.6
million increase in power supply expenses from VYNPC that was partially offset
by a $4.6 million decline in wholesale sales of electricity.
Power
supply expenses from VYNPC increased $2.6 million or 11.3 percent during
the
first nine months of 2005 compared with the same period of 2004, primarily
due
to an increase in energy provided under the Power Purchase Agreement between
VYNPC and ENVY, because of plant outages that occurred in 2004.
Company-owned
generation expenses decreased $759,000 or 14.9 percent in the first nine
months
of 2005 compared with the same period in 2004, because peaking facilities
were
used less for reliability and economic reasons.
The
cost
of power that we purchased from other companies decreased $3.2
million or 3.9 percent in the first nine months of 2005 compared with the
same
period in 2004, primarily due to increased market purchases caused by sharply
higher energy prices and increased retail sales of electricity.
Other
operating expenses
Other
operating expenses increased $1.9 million or 36.9 percent in the third quarter
of 2005 compared with the same period in 2004 due primarily to increased
expenses associated with the sale of utility services and regulatory expenses.
Other operating expenses increased $2.6 million or 18.0 percent in the first
nine months of 2005 compared with the same period in 2004 for the same
reason.
Transmission
expenses
Transmission
expenses increased by approximately $598,000 or 17.2 percent for the three
months ended September 30, 2005 compared with the same period in 2004, due
primarily to an increase in charges allocated for system support in New England
by the ISO-NE. Transmission expenses increased by approximately $1.5 million
or
13.3 percent for the nine months ended September 30, 2005 compared with the
same
period in 2004 for the same reason.
Maintenance
expenses
Maintenance
expenses increased $391,000 or 16.0 percent for the three months ended September
30, 2005 compared with the same period in 2004, primarily due to an increase
in
plant maintenance at joint-owned and peaking facilities. Maintenance
expenses increased $724,000 or 10.1 percent for the nine months ended September
30, 2005 compared with the same period in 2004 for the same reason.
Depreciation
and amortization expenses
Depreciation
and amortization expenses for the quarter ended September 30, 2005 increased
$291,000 or 8.4 percent compared with the same period in 2004, reflecting
an
increase in the depreciation of utility plant due to increased investment,
and
the amortization of regulatory assets in accordance with the 2003 Rate Plan.
Depreciation and amortization expenses increased $848,000 or 8.1 percent
for the
nine months ended September 30, 2005 compared with the same period in 2004
for
the same reasons.
Taxes
other than income taxes
Other
tax
expense for the third quarter of 2005 increased by $169,000 or 12.4 percent
compared with the same period in 2004 due to increases in property taxes.
Other
tax expense for the first nine months of 2005 increased by $61,000 or 1.3
percent compared with the same period in 2004 due to gross revenue taxes
on
increased revenues.
Income
taxes
Income
taxes decreased $254,000 or 22.1 percent in the third quarter of 2005 compared
with the same period in 2004 due to a decrease in pretax book income.
Income
taxes decreased $420,000 or 9.9 percent in the first nine months of 2005
compared with the same period in 2004 due to a decrease in pretax book
income.
The
Company expects to recognize an income tax benefit of approximately three
cents
per share as a result of an income tax credit and deduction available in
2005
under the American Jobs Creation Act of 2004. The credit and deduction arise
from our ownership interest in a biomass generation plant and from the
production of electricity at Company hydro and fossil fuel plants.
Interest
Charges
Interest
charges increased $83,000 or 5.2 percent in the third quarter of 2005 compared
with the same period in 2004, due to a decrease in interest capitalized on
utility plant construction. Interest charges increased $192,000 or 4.0 percent
in the first nine months of 2005 compared with the same period in 2004, for
the
same reason.
LIQUIDITY
AND CAPITAL RESOURCES
At
December 31, 2004, we had cash and cash equivalents of $1.7 million. In the
first nine months of 2005, cash and cash equivalents increased to $1.8 million.
Operating cash flows decreased by $149,000 from the same period last year
primarily as the result of increased working capital needs and a decrease
in
income from continuing operations that were offset by a rate increase that
substantially replaced deferred revenue recognition and increases in
depreciation and amortization. Net cash used by investing activities amounted
to
$15.2 million, principally for investments to construct utility plant. We
expect
to spend approximately $9.8 million during the remainder of 2005, primarily
for
improvements in transmission, distribution and generation plant, and
environmental expenditures. The Company plans to invest up to $32 million
in
VELCO through 2009 in support of the NRP and other transmission projects,
including a $4.8 million investment made in the last quarter of 2004. Our
investment projections for VELCO have increased from previous estimates
primarily as a result of increases in VELCO’s cost estimates for the
NRP.
On
February 14, 2005, the annual dividend rate was increased from $0.88 to $1.00
per share, a payout ratio of approximately 48 percent based on 2004 earnings
from continuing operations. On February 9, 2004, the annual dividend rate
was
increased from $0.76 per share to $0.88 per share, a payout ratio of
approximately 44 percent based on 2003 earnings. The Company expects to increase
the dividend on a consistent basis in the first quarter of each year to the
middle of a payout ratio that falls between 50 percent and 70 percent of
anticipated earnings, so long as financial and operating results permit.
We
believe this payout ratio to be consistent with that of other electric utilities
having similar risk profiles. The Company expects to increase the annual
dividend by 12 cents per share beginning in the first quarter of 2006,
consistent with our dividend growth policy over the last few years, so long
as
financial and operating results permit.
We
expect
most of our construction expenditures and dividends to be financed by net
cash
provided by operating activities. Material risks to cash flow from operations
include increases in net power costs, regulatory risk, and unfavorable economic
conditions. We anticipate that we will issue long-term debt of up to $30
million
in 2006 for scheduled first mortgage bond redemptions of $14 million and
to
finance increased investment in VELCO and generation. The Company has no
plans
at present to issue additional equity and seeks to maintain equity at between
fifty and fifty-five percent of its capital structure.
During
June 2005, the Company renegotiated a 364-day revolving credit agreement
with
Bank of America, joined by Sovereign Bank (the "BOA-Sovereign Agreement").
The
BOA-Sovereign Agreement is for $30.0 million, unsecured, and allows the Company
to choose any blend of a daily variable prime rate and a fixed term LIBOR-based
rate. There was no short-term debt outstanding in the BOA-Sovereign Agreement
at
September 30, 2005, compared with $3.0 million outstanding at December 31,
2004.
The BOA-Sovereign Agreement expires June 14, 2006.
The
credit ratings of the Company's first mortgage bonds at September 30, 2005
were:
|
Moody's
|
Standard
& Poor's
|
|
|
|
First
mortgage bonds
|
Baa1
|
BBB
|
Moody's
affirmed the Company's senior secured debt rating at Baa1, with a stable
outlook
on June 18, 2004.
On
November 3, 2004, Standard and Poor's Ratings Services upgraded the Company's
issuer credit rating to BBB from BBB-.
In
the
event of a change in the Company's first mortgage bond credit rating to below
investment grade, scheduled payments under the Company's first mortgage bonds
would not be affected. Such a change would require the Company to post what
would currently amount to a $4.3 million bond under our remediation agreement
with the EPA regarding the Pine Street Barge Canal site. The Morgan Stanley
Contract and ISO-NE require credit assurances if the Company's first mortgage
bond credit ratings are lowered to below investment grade by any one of the
two
credit rating agencies listed above.
The
following table presents a summary of certain material contractual obligations
existing as of September 30, 2005, for which undiscounted future annual payments
are shown.
In
thousands
|
|
Payments
Due by Period as of September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
2006
and
|
|
|
2008
and
|
|
|
After
|
|
|
|
|
Total
|
|
|
2005
|
|
|
2007
|
|
|
2009
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$
|
93,000
|
|
$
|
-
|
|
$
|
14,000
|
|
$
|
-
|
|
$
|
79,000
|
|
Interest
on long-term debt
|
|
|
65,808
|
|
|
2,172
|
|
|
12,068
|
|
|
11,068
|
|
|
40,500
|
|
Capital
lease obligations
|
|
|
4,363
|
|
|
143
|
|
|
879
|
|
|
766
|
|
|
2,575
|
|
Hydro-Quebec
power supply contracts
|
|
|
538,486
|
|
|
13,219
|
|
|
103,169
|
|
|
102,723
|
|
|
319,375
|
|
Morgan
Stanley Contract
|
|
|
14,937
|
|
|
4,780
|
|
|
10,157
|
|
|
-
|
|
|
-
|
|
Independent
Power Producers
|
|
|
172,091
|
|
|
4,779
|
|
|
33,923
|
|
|
32,808
|
|
|
100,581
|
|
Stony
Brook contract
|
|
|
44,347
|
|
|
415
|
|
|
6,024
|
|
|
6,506
|
|
|
31,402
|
|
VYNPC
PPA
|
|
|
229,737
|
|
|
7,196
|
|
|
68,090
|
|
|
71,590
|
|
|
82,861
|
|
Total
|
|
$
|
1,162,769
|
|
$
|
32,704
|
|
$
|
248,310
|
|
$
|
225,461
|
|
$
|
656,294
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Off-Balance
Sheet Arrangements - The
Company does not use off-balance sheet financing arrangements, such as
securitization of receivables or obtaining access to assets through special
purpose entities.
Other
Commitments - We
have
material power supply commitments that are discussed in detail under the
captions "Power Contract Commitments and Related Risks" and "Power Supply
Expenses." We also own an equity interest in VELCO, which requires the Company
to contribute capital when required and to pay a portion of VELCO’s operating
costs, including its debt service costs.
ITEM
3. Quantitative and Qualitative Disclosures About Market
Risk and Other Risk Factors
Future
Outlook - Competition, Legislation and Restructuring -
The
electric utility business continues to experience rapid and substantial changes.
These changes are the result of the following trends:
· |
disparity
in electric rates, transmission, and generating capacity among
and within
various regions of the country;
|
· |
improvements
in generation efficiency;
|
· |
consolidation
through business combinations;
|
· |
new
regulations and legislation intended to foster competition, ;
|
· |
changes
in rules governing wholesale electricity markets;
and
|
· |
increasing
volatility of wholesale market prices for
electricity.
|
Vermont
is the only state in the New England region that has not adopted some form
of
electric industry restructuring. The Vermont legislature enacted a bill that
would impose renewable portfolio standards ("RPS") on Vermont electric
distribution utilities. The bill currently contemplates that, effective January
1, 2013, distribution utilities will be required to supply all load growth
for
2005 - 2013 with "renewable" energy supply, as defined in the bill. The bill
provides the alternative that if in-state renewable generation sufficient
to
supply statewide load growth for 2005 - 2013 becomes operational before 2012,
and if Vermont distribution utilities acquire the output of these facilities,
the RPS requirement would be avoided.
Power
Contract Commitments and Related Risks
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 or sell the difference into a marketplace
that has experienced volatile energy prices. Volatility and market price
trends
also make it more difficult to extend or enter into new power supply contracts
at prices that avoid the need for rate relief.
We
have
developed a power supply portfolio that meets approximately 90 percent of
our
estimated customer demand ("load") requirements through 2006. Our power supply
contracts and resources significantly reduce the Company's exposure to
volatility in wholesale energy market prices. The Company remains exposed
to
very volatile energy markets for the remaining 10 percent of its load
requirements, as well as congestion, line loss and other ancillary service
charges allocated to New England utilities by ISO-NE.
Vermont
does not have a fuel or purchased-power adjustment clause that would allow
increases in power supply costs to be recovered immediately in the rates
we
charge customers. Historically, however, the VPSB has allowed electric utilities
to defer material unexpected increases in power supply costs to future periods
to permit recovery in future rates. Vermont law also allows electric utilities
to seek temporary rate increases if deemed necessary by the VPSB to provide
adequate and efficient service or to preserve the viability of the
utility.
Vermont
Yankee - We have a 20 percent entitlement in Vermont Yankee plant output
sold by
Entergy to Vermont Yankee Nuclear Power Corporation ("VYNPC"), through a
long-term purchase contract with VYNPC (the "VYNPC Contract"). We generally
purchase between 35 and 40 percent of our annual load requirements from VYNPC
at
rates that are presently well below market. We are responsible for the purchase
of replacement power to serve our load requirements when the plant is not
operating due to scheduled or unscheduled outages. In the first nine months
of
2005, we purchased $25.9 million from VYNPC based on our entitlement share
of
plant output, compared to $23.2 million for the same period in 2004, reflecting
2004 scheduled and unscheduled plant outages.
Hydro
Quebec - We purchase varying amounts of power from Hydro Quebec under the
Vermont Joint Owners ("VJO") Contract negotiated between the Company and
Hydro
Quebec. There are specific contractual provisions that provide that in the
event
any VJO member fails to meet its obligation under the contract with Hydro
Quebec, the remaining VJO participants, including the Company, must "step-up"
to
the defaulting party's share on a pro rata basis. The Company is not aware
of
any instance where this provision has been invoked by Hydro Quebec. In the
first
nine months of 2005, we purchased $34.9 million of energy and related capacity
from Hydro Quebec, compared to $33.8 million for the same period in
2004.
Under
the
VJO Contract, Hydro Quebec had the right to reduce the load factor from 75
percent to 65 percent a total three times over the life of the contract.
Hydro
Quebec exercised its third and last option in 2004 for deliveries occurring
principally during 2005. Hydro Quebec retains the right to reduce the load
factor by 10 percent up to five times, over the 2001 to 2015 period, if
documented drought conditions exist in Quebec. The utilities that comprise
the
VJO retain two options to increase or reduce the load factor by 5 percent
under
the VJO Contract and exercised the first of these options to increase deliveries
occurring principally between November 1, 2005 and October 30, 2006. The
option
will provide approximately 50,000 additional off-peak megawatt hours of
supply.
Morgan
Stanley - We purchase approximately 16 percent of our load requirements under
a
contract with Morgan Stanley Capital Group, Inc. (the "Morgan Stanley
Contract"), designed to manage some of the price risks associated with changing
fossil fuel prices. The Morgan Stanley Contract price is substantially below
current market prices and expires on December 31, 2006. The Company is unable
to
predict the price, contract duration or terms of any future power supply
contracts that could replace the Morgan Stanley Contract after it expires.
Defined
Benefit Plans
The
Company’s defined benefit plan assets are primarily made up of public equity and
fixed income investments. Fluctuations in actual equity market returns as
well
as changes in general interest rates may result in increased or decreased
defined benefit plan costs in future periods.
The
Company’s funding policy is to make voluntary contributions to its defined
benefit plans before ERISA or Pension Benefit Guaranty Corporation requirements
mandate such contributions under minimum funding rules, and so long as the
Company’s liquidity needs do not preclude such investments. The Company expects
to contribute approximately $2.0 million to defined benefits plans during
2005,
of which $1.5 million has been contributed to date.
Power
Supply Derivatives
The
Morgan Stanley Contract is used to hedge our power supply costs against
increases in fossil fuel prices. The Morgan Stanley Contract is a derivative
under Statement of Financial Accounting Standards No. 133 ("SFAS 133").
Management has estimated the fair value of the future net benefit of this
agreement at September 30, 2005 to be approximately $7.8 million.
We
currently have an agreement that grants Hydro Quebec an option (the "9701
agreement") to call power at prices that are expected to be below estimated
future market rates. This agreement is a derivative and is effective through
2015. Management’s estimate of the fair value of the future net cost for the
9701 agreement at September 30, 2005 is approximately $30.6 million.
Hydro-Quebec has exercised its 9701 option for delivery during the first
quarter
of 2006, when market prices are currently projected to be approximately $180
per
MWh. Prices are expected to be substantially higher in January and February
than
during the remainder of the year, reflecting hurricane activity in the Gulf
of
Mexico that has shut down a significant amount of natural gas production.
Natural gas availability drives electricity pricing. The Company expects
to ask
the VPSB for an accounting order to defer 2006 incremental costs related
to the
run-up in energy prices, including the energy price effects on the 9701
agreement.
The
table
below presents the Company’s market risk of the Morgan Stanley Contract and the
9701 agreement derivatives, estimated as the potential loss in fair value
resulting from a hypothetical ten percent adverse change in wholesale energy
prices, which nets to approximately $2.7 million. Actual results may differ
materially from the table illustration. Under an accounting order issued
by the
VPSB, changes in the fair value of derivatives are deferred.
Commodity
Price Risk
|
|
|
September
30, 2005
|
|
In
thousands
|
|
|
Fair
Value(Cost)
|
|
|
Market
Risk
|
|
Morgan
Stanley Contract
|
|
$
|
22,826
|
|
$
|
3,533
|
|
9701
agreement
|
|
|
(30,591
|
)
|
|
(3,977
|
)
|
|
|
$
|
(7,765
|
)
|
$
|
(444
|
)
|
|
|
|
|
|
|
|
|
New
Accounting Standards
See
Part
I-Item 1, Note 5, "New Accounting Standards" for information on the adoption
of
new accounting standards and the impact, if any, on the Company's financial
position and operating results.
Pursuant
to Rule 13a-15(b) under the Securities Exchange Act of 1934, the Company
carried
out an evaluation, with the participation of the Company's management, including
the Company's President and Chief Executive Officer, and Chief Financial
Officer
and Treasurer, of the effectiveness of the Company's disclosure controls
and
procedures (as defined under Rule 13a-15(e) under the Securities Exchange
Act of
1934) as of the end of the period covered by this report. Based upon that
evaluation, the Company's President and Chief Executive Officer, and Chief
Financial Officer and Treasurer, concluded that the Company's disclosure
controls and procedures are effective.
Management’s
report on the Company’s internal control over financial reporting was included
in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004
and concluded that, as of December 31, 2004, the Company did not maintain
effective internal control over financial reporting due to a material weakness
as a result of deficiencies in both the design and operating effectiveness
of
controls associated with the Company’s accounting for income taxes. During the
first nine months of 2005, management conducted testing and enhancement of
the
Company’s internal controls associated with accounting for income taxes and
engaged a public accounting firm to assist management with its review of
all
income tax entries for the quarter, the statutory rate reconciliation, the
Company's treatment of new tax credits and deductions, if applicable, and
timing
differences. These ongoing efforts, which required certain changes to the
Company’s internal controls associated with accounting for income taxes, and
which are subject to audit by the Company’s independent registered accounting
firm at year-end, have improved the design and operational effectiveness
of the
Company's control processes and systems for financial reporting. Based on
these
efforts, management believes that the deficiencies in both the design and
operating effectiveness of controls associated with the Company’s accounting for
income taxes have been remediated and that the Company no longer has a material
weakness in its internal control over financial reporting. It should be noted
that the design of any system of controls is based, in part, on certain
assumptions about the likelihood of future events, and that only reasonable
assurance can be given that any internal control system will succeed in
achieving its stated goals against all potential future conditions, regardless
of how remote.
Except
as
described above, there has been no change in our internal control over financial
reporting during the quarter ended September 30, 2005, that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting
GREEN
MOUNTAIN POWER CORPORATION
September
30, 2005
PART
II - OTHER INFORMATION
Item
1.
Legal
Proceedings
See
Note
3 of Notes to Consolidated Financial Statements
Item
2.
Unregistered
Sales of Equity Securities and Use of Proceeds
NONE
Item
3.
Defaults
Upon Senior Securities
NONE
Item
4.
Submission
of Matters to a Vote of Security Holders
NONE
Item
5.
Other
Information
NONE
ITEM
6.
Exhibit
31.1, Certification by Christopher L. Dutton,
President and Chief Executive Officer of Green Mountain Power Corporation,
pursuant to Rules 13a-14(a) and Rule 15d-14(a) promulgated under the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
Exhibit
31.2, Certification by Robert J. Griffin, Chief
Financial Officer, Vice President, Treasurer and Principal Accounting Officer
of
Green Mountain Power Corporation, pursuant to Rules 13a-14(a) and Rule 15d-14(a)
promulgated under the Securities Exchange Act of 1934, as adopted pursuant
to
Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit
32.1, Certification by Christopher L. Dutton,
President and Chief Executive Officer of Green Mountain Power Corporation,
and
Robert J. Griffin, Chief Financial Officer, Vice President Treasurer and
Principal Accounting Officer of Green Mountain Power Corporation, pursuant
to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
GREEN
MOUNTAIN POWER CORPORATION
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant
has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
GREEN
MOUNTAIN POWER CORPORATION
|
|
|
|
By:
/s/ Christopher L. Dutton
|
|
November
9, 2005
|
|
Christopher
L. Dutton
President
and
Chief
Executive Officer
|
|
Date
|
|
|
|
|
|
By:
/s/ Robert J. Griffin
|
|
November
9, 2005
|
|
Robert
J. Griffin
Vice
President, Chief Financial Officer and Treasurer and Principal
Accounting
Officer
|
|
Date
|