UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
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(Mark
One)
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x
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QUARTERLY
REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE
ACT OF 1934
For
the quarterly period ended
March 31,
2008
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or
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¨
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TRANSITION
REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
EXCHANGE
ACT OF 1934
For
the transition period from
to
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Commission
file number
1-8222
Central Vermont Public
Service Corporation
(Exact
name of registrant as specified in its
charter)
|
Vermont
(State
or other jurisdiction of
incorporation
or organization)
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03-0111290
(IRS
Employer
Identification
No.)
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77 Grove Street,
Rutland, Vermont
(Address
of principal executive offices)
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05701
(Zip
Code)
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Registrant's telephone number,
including area code
802-773-2711
|
(Former
name, former address and former fiscal year, if changed since last
report)
|
Indicate
by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes
x
No
¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of "large accelerated filer",
"accelerated filer" and "smaller reporting company" in Rule 12b-2 of the
Exchange Act.
|
Large
accelerated filer
|
¨
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Accelerated
filer
|
x
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Non-accelerated
filer
|
¨
(Do not check if a smaller
reporting company)
|
Smaller
Reporting Company
|
¨
|
Indicate
by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes
¨
No
x
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date. As of April 30, 2008
there were outstanding 10,332,183 shares of Common Stock, $6 Par
Value.
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CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
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Form
10-Q for Period Ended March 31, 2008
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Table
of Contents
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2
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3
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4
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6
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7
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8
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20
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27
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27
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28
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28
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28
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29
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30
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PART I. FINANCIAL
INFORMATION
Item
1. Fin
ancial Statements
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
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CONDENSED CONSOLIDATED STATEMENTS OF
INCOME
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(dollars
in thousands, except per share data)
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(unaudited)
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Three
months ended March 31
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2008
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2007
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Operating
Revenues
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$
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91,224
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$
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86,696
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Operating
Expenses
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Purchased
Power - affiliates
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16,468
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16,138
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Purchased
Power
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26,438
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26,122
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Production
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3,342
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3,139
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Transmission
- affiliates
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3,389
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1,497
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Transmission
- other
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4,474
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4,187
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Other
operation
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14,745
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13,788
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Maintenance
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6,169
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5,457
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Depreciation
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3,869
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3,739
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Taxes
other than income
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4,039
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3,728
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Income
tax expense
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1,859
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2,838
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Total
Operating Expenses
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84,792
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80,633
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Utility
Operating Income
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6,432
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6,063
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Other
Income
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Equity
in earnings of affiliates
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4,185
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1,702
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Allowance
for equity funds during construction
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17
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17
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Other
income
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767
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1,067
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Other
deductions
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(1,308
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)
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(593
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)
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Income
tax expense
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(1,425
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)
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(526
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)
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Total
Other Income
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2,236
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1,667
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Interest
Expense
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Interest
on long-term debt
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1,937
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1,799
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Other
interest
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831
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230
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Allowance
for borrowed funds during construction
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(8
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)
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(5
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)
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Total
Interest Expense
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2,760
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2,024
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Net
Income
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5,908
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5,706
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Dividends
declared on preferred stock
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92
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92
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Earnings
available for common stock
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$
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5,816
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$
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5,614
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Per
Common Share Data:
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Basic
earnings per share
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$
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0.57
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$
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0.55
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Diluted
earnings per share
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$
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0.56
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$
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0.55
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Average
shares of common stock outstanding - basic
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10,275,505
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10,135,481
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Average
shares of common stock outstanding - diluted
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10,377,034
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10,240,602
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Dividends
declared per share of common stock
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$
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0.46
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$
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0.46
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The
accompanying notes are an integral part of these condensed consolidated
financial statements.
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
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CONDENSED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME
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(dollars
in thousands)
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(unaudited)
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Three
months ended March 31
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2008
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2007
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Net
Income
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$
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5,908
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$
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5,706
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Other comprehensive income, net
of tax
:
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Defined
benefit pension and postretirement medical plans:
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Portion
reclassified through amortizations, included in benefit
costs
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and
recognized in net income:
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Actuarial
losses, net of income taxes of $0 and $3
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1
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5
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Prior
service cost, net of income taxes of $3 and $2
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2
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3
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3
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8
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Portion
reclassified due to adoption of SFAS 158 measurement
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provision,
included in retained earnings:
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Prior
service cost, net of income taxes of $2 and $0
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4
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-
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4
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-
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Comprehensive
income adjustments
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7
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8
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Total
comprehensive income
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$
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5,915
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$
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5,714
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The
accompanying notes are an integral part of these condensed consolidated
financial statements.
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
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CONDENSED
CONSOLIDATED BALANCE
SHEETS
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(dollars
in thousands, except share data)
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(unaudited)
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March
31, 2008
|
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December
31, 2007
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ASSETS
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Utility
plant
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Utility
plant, at original cost
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$
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540,850
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$
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538,229
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Less
accumulated depreciation
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238,236
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235,465
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Utility
plant, at original cost, net of accumulated depreciation
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302,614
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302,764
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Property
under capital leases, net
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6,564
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6,788
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Construction
work-in-progress
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12,587
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9,611
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Nuclear
fuel, net
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1,063
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1,105
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Total
utility plant, net
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322,828
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320,268
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Investments
and other assets
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Investments
in affiliates
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96,427
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93,452
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Non-utility
property, less accumulated depreciation
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($3,683
in 2008 and $3,681 in 2007)
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1,635
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1,646
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Millstone
decommissioning trust fund
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5,299
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5,645
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Other
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6,884
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7,504
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Total
investments and other assets
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110,245
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108,247
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Current
assets
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Cash
and cash equivalents
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6,365
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3,803
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Restricted
cash
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-
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62
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Special
deposits
|
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-
|
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1,000
|
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Accounts
receivable, less allowance for uncollectible accounts
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($2,032
in 2008 and $1,751 in 2007)
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26,898
|
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24,086
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Accounts
receivable - affiliates, less allowance for uncollectible
accounts
|
|
|
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($48
in 2008 and $48 in 2007)
|
|
|
63
|
|
|
|
254
|
|
Unbilled
revenues
|
|
|
15,566
|
|
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|
17,665
|
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Materials
and supplies, at average cost
|
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5,330
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|
5,461
|
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Prepayments
|
|
|
5,488
|
|
|
|
8,942
|
|
Deferred
income taxes
|
|
|
5,887
|
|
|
|
3,638
|
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Power-related
derivatives
|
|
|
934
|
|
|
|
707
|
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Other
current assets
|
|
|
1,160
|
|
|
|
1,081
|
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Total current
assets
|
|
|
67,691
|
|
|
|
66,699
|
|
|
|
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Deferred
charges and other assets
|
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|
|
|
|
|
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Regulatory
assets
|
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32,175
|
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31,988
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Other
deferred charges - regulatory
|
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|
13,074
|
|
|
|
8,988
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Other
deferred charges and other assets
|
|
|
3,909
|
|
|
|
4,124
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Total
deferred charges and other assets
|
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|
49,158
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|
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45,100
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TOTAL
ASSETS
|
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$
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549,922
|
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$
|
540,314
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The
accompanying notes are an integral part of these condensed consolidated
financial statements.
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
|
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CONDENSED
CONSOLIDATED BALANCE SHEETS
|
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(dollars
in thousands, except share data)
|
|
(unaudited)
|
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|
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March
31, 2008
|
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December
31, 2007
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CAPITALIZATION
AND LIABILITIES
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Capitalization
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Common
stock, $6 par value, 19,000,000 shares authorized,
12,547,776
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issued
and 10,329,013 outstanding at March 31, 2008 and
12,474,687
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issued
and 10,244,559 outstanding at December 31, 2007
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$
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75,287
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$
|
74,848
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Other
paid-in capital
|
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|
57,086
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56,324
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Accumulated
other comprehensive loss
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(371
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)
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(378
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)
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Treasury
stock, at cost, 2,218,763 shares at March 31, 2008 and
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2,230,128
shares at December 31, 2007
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(50,476
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)
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|
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(50,734
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)
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Retained
earnings
|
|
|
109,787
|
|
|
|
108,747
|
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Total
common stock equity
|
|
|
191,313
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|
|
188,807
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Preferred
and preference stock not subject to mandatory redemption
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|
8,054
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8,054
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Preferred
stock subject to mandatory redemption
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|
1,000
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|
|
|
2,000
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Long-term
debt
|
|
|
112,950
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|
|
|
112,950
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Capital
lease obligations
|
|
|
5,665
|
|
|
|
5,889
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Total
capitalization
|
|
|
318,982
|
|
|
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317,700
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|
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Current
liabilities
|
|
|
|
|
|
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Current
portion of preferred stock subject to mandatory redemption
|
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1,000
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|
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|
1,000
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Current
portion of long-term debt
|
|
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3,000
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|
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3,000
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Accounts
payable
|
|
|
5,087
|
|
|
|
6,253
|
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Accounts
payable - affiliates
|
|
|
11,473
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|
|
|
13,205
|
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Notes
payable
|
|
|
63,800
|
|
|
|
63,800
|
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Dividends
payable
|
|
|
2,363
|
|
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|
-
|
|
Nuclear
decommissioning costs
|
|
|
2,150
|
|
|
|
2,309
|
|
Power-related
derivatives
|
|
|
7,159
|
|
|
|
3,225
|
|
Other
current liabilities
|
|
|
22,339
|
|
|
|
20,761
|
|
Total
current liabilities
|
|
|
118,371
|
|
|
|
113,553
|
|
|
|
|
|
|
|
|
|
|
Deferred
credits and other liabilities
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
35,873
|
|
|
|
33,666
|
|
Deferred
investment tax credits
|
|
|
3,246
|
|
|
|
3,341
|
|
Nuclear
decommissioning costs
|
|
|
9,172
|
|
|
|
9,580
|
|
Asset
retirement obligations
|
|
|
3,248
|
|
|
|
3,200
|
|
Accrued
pension and benefit obligations
|
|
|
21,699
|
|
|
|
19,874
|
|
Power-related
derivatives
|
|
|
5,201
|
|
|
|
4,592
|
|
Other
deferred credits - regulatory
|
|
|
9,771
|
|
|
|
9,395
|
|
Other
deferred credits and other liabilities
|
|
|
24,359
|
|
|
|
25,413
|
|
Total
deferred credits and other liabilities
|
|
|
112,569
|
|
|
|
109,061
|
|
|
|
|
|
|
|
|
|
|
Commitments
and contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
CAPITALIZATION AND LIABILITIES
|
|
$
|
549,922
|
|
|
$
|
540,314
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
|
|
CONDENSED
CONSOLIDATED STATEMENTS OF CASH
FLOWS
|
|
(dollars
in thousands)
|
|
(unaudited)
|
|
|
|
Three
months ended March 31
|
|
|
|
2008
|
|
|
2007
|
|
Cash
flows provided (used) by:
|
|
|
|
|
|
|
OPERATING
ACTIVITIES
|
|
|
|
|
|
|
Net
income
|
|
$
|
5,908
|
|
|
$
|
5,706
|
|
Adjustments
to reconcile net income to net
|
|
|
|
|
|
|
|
|
cash
provided by operating activities:
|
|
|
|
|
|
|
|
|
Equity
in earnings of affiliates
|
|
|
(4,185
|
)
|
|
|
(1,702
|
)
|
Distributions
received from affiliates
|
|
|
1,330
|
|
|
|
1,353
|
|
Depreciation
|
|
|
3,869
|
|
|
|
3,739
|
|
Deferred
income taxes and investment tax credits
|
|
|
(200
|
)
|
|
|
(350
|
)
|
Non-cash
employee benefit plan costs
|
|
|
1,445
|
|
|
|
1,811
|
|
Regulatory
and other amortization, net
|
|
|
149
|
|
|
|
(11
|
)
|
Other
non-cash expense, net
|
|
|
1,368
|
|
|
|
896
|
|
Changes
in assets and liabilities:
|
|
|
|
|
|
|
|
|
(Increase)
decrease in accounts receivable and unbilled revenues
|
|
|
(1,350
|
)
|
|
|
1,426
|
|
Decrease
in accounts payable
|
|
|
(2,052
|
)
|
|
|
(2,149
|
)
|
Increase
in accrued income taxes
|
|
|
3,098
|
|
|
|
3,709
|
|
Decrease
in other current assets
|
|
|
702
|
|
|
|
550
|
|
Decrease
(increase) in special deposits and restricted cash for power
collateral
|
|
|
62
|
|
|
|
(1,937
|
)
|
Employee
benefit plan funding
|
|
|
(586
|
)
|
|
|
(618
|
)
|
Increase
in other current liabilities
|
|
|
1,848
|
|
|
|
858
|
|
Other
non-current assets and liabilities and other
|
|
|
(184
|
)
|
|
|
(121
|
)
|
Net
cash provided by operating activities
|
|
|
11,222
|
|
|
|
13,160
|
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Construction
and plant expenditures
|
|
|
(7,267
|
)
|
|
|
(5,032
|
)
|
Investments
in available-for-sale securities
|
|
|
(202
|
)
|
|
|
(519
|
)
|
Proceeds
from sale of available-for-sale securities
|
|
|
135
|
|
|
|
477
|
|
Return
of capital from investments in affiliates
|
|
|
96
|
|
|
|
108
|
|
Other
investments and capital expenditures
|
|
|
(44
|
)
|
|
|
(200
|
)
|
Net
cash used for investing activities
|
|
|
(7,282
|
)
|
|
|
(5,166
|
)
|
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds
from issuance of common stock
|
|
|
1,180
|
|
|
|
629
|
|
Common
and preferred dividends paid
|
|
|
(2,453
|
)
|
|
|
(2,423
|
)
|
Proceeds
from borrowings under revolving credit facility
|
|
|
9,300
|
|
|
|
3,500
|
|
Repayments
under revolving credit facility
|
|
|
(9,300
|
)
|
|
|
(3,500
|
)
|
Retirement
of preferred stock subject to mandatory redemption
|
|
|
(1,000
|
)
|
|
|
(1,000
|
)
|
Decrease
in special deposits held for preferred stock redemptions
|
|
|
1,000
|
|
|
|
1,000
|
|
Reduction
in capital lease obligations and other
|
|
|
(105
|
)
|
|
|
(217
|
)
|
Net
cash used for financing activities
|
|
|
(1,378
|
)
|
|
|
(2,011
|
)
|
|
|
|
|
|
|
|
|
|
Net
increase in cash and cash equivalents
|
|
|
2,562
|
|
|
|
5,983
|
|
Cash
and cash equivalents at beginning of the period
|
|
|
3,803
|
|
|
|
2,799
|
|
Cash
and cash equivalents at end of the period
|
|
$
|
6,365
|
|
|
$
|
8,782
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
|
|
CONDENSED
CONSOLIDATED STATEMENT
OF CHANGES IN COMMON
STOCK EQUITY
|
|
(in
thousands, except share data)
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock
|
|
|
|
|
|
Treasury
Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
Paid-in
|
|
|
Comprehensive
|
|
|
|
|
|
|
|
|
Retained
|
|
|
|
|
|
Issued
|
|
|
Amount
|
|
|
Capital
|
|
|
Loss
|
|
|
Share
|
|
|
Amount
|
|
|
Earnings
|
|
|
Total
|
|
Balance,
December 31, 2007
|
|
|
12,474,687
|
|
|
$
|
74,848
|
|
|
$
|
56,324
|
|
|
$
|
(378
|
)
|
|
|
2,230,128
|
|
|
$
|
(50,734
|
)
|
|
$
|
108,747
|
|
|
$
|
188,807
|
|
Adjust
to initially apply
SFAS
158
measure
provision, net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
(49
|
)
|
|
|
(45
|
)
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,908
|
|
|
|
5,908
|
|
Other
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
Dividend
reinvestment plan
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,365
|
)
|
|
|
258
|
|
|
|
|
|
|
|
258
|
|
Stock
options exercised
|
|
|
58,000
|
|
|
|
348
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,120
|
|
Share-based
compensation
|
|
|
15,089
|
|
|
|
91
|
|
|
|
(59
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
Dividends
declared on
common and
preferred
stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,816
|
)
|
|
|
(4,816
|
)
|
Amortization
of preferred
stock
issuance
expense
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
Gain
on issuance of
treasury stock
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
Loss
on reacquisition
of capital
stock
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
-
|
|
Balance,
March 31, 2008
|
|
|
12,547,776
|
|
|
$
|
75,287
|
|
|
$
|
57,086
|
|
|
$
|
(371
|
)
|
|
|
2,218,763
|
|
|
$
|
(50,476
|
)
|
|
$
|
109,787
|
|
|
$
|
191,313
|
|
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS
NOTE
1 - BUSINESS ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
General Description of Business
Central Vermont Public Service Corporation ("we", "us", "CVPS" or the
"company") is engaged in the purchase, production, transmission, distribution
and sale of electricity. We are the largest electric utility in
Vermont, serving about 158,000 retail customers spread across about half of
Vermont. Our wholly owned subsidiaries include Custom Investment
Corporation, C.V. Realty, Inc., Central Vermont Public Service Corporation -
East Barnet Hydroelectric, Inc. and Catamount Resources
Corporation.
We have
equity ownership interests in Vermont Yankee Nuclear Power Corporation
("VYNPC"), Vermont Electric Power Company, Inc. ("VELCO"), Vermont Transco LLC
("Transco"), Maine Yankee Atomic Power Company ("Maine Yankee"), Connecticut
Yankee Atomic Power Company ("Connecticut Yankee") and Yankee Atomic Electric
Company ("Yankee Atomic").
Basis of
Presentation
These unaudited interim financial statements have been
prepared pursuant to the rules and regulations of the Securities and Exchange
Commission. Accordingly, certain information and footnote disclosures
normally included in the financial statements prepared in accordance with
accounting principles generally accepted in the United States of America ("U.S.
GAAP") have been condensed or omitted. In our opinion, the
accompanying interim financial statements reflect all normal, recurring
adjustments considered necessary for a fair presentation. Operating
results for the interim periods presented herein may not be indicative of the
results that may be expected for the year. The financial statements
incorporated herein should be read in conjunction with the consolidated
financial statements and accompanying notes included in our annual report on
Form 10-K for the year ended December 31, 2007.
Regulatory Accounting
Our
utility operations are regulated by the Vermont Public Service Board ("PSB"),
the Connecticut Department of Public Utility and Control and the Federal Energy
Regulatory Commission ("FERC"), with respect to rates charged for service,
accounting, financing and other matters pertaining to regulated
operations. As such, we prepare our financial statements in
accordance with SFAS 71,
Accounting for the Effects of
Certain Types of Regulation
("SFAS 71"). The application of
SFAS 71 results in differences in the timing of recognition of certain expenses
from those of other businesses and industries. In the event we
determine that our utility operations no longer meet the criteria for applying
SFAS 71, the accounting impact would be an extraordinary non-cash charge to
operations of an amount that would be material unless stranded cost recovery is
allowed through a rate mechanism. Based on a current evaluation of
the factors and conditions expected to impact future cost recovery, we believe
future recovery of our regulatory assets is probable. See Note 4 -
Retail Rates and Regulatory Accounting.
Reclassifications
Certain
prior year amounts have been reclassified to conform to the current year
presentation. In 2007, power-related derivatives of $0.7 million were
included in Other current assets on the Consolidated Balance Sheet and have been
reclassified on a separate line at March 31, 2008.
Recently
Adopted Accounting Policies
Fair Value:
On January
1, 2008, we adopted FASB Statement No. 157,
Fair Value Measurements
("SFAS 157"), which addresses how companies should measure fair value when they
are required to use a fair value measure for recognition or disclosure purposes
under U.S. GAAP. This standard applies prospectively to new fair
value measures of financial instruments and recurring fair value measurements of
non-financial assets and non-financial liabilities. SFAS 157 does not
expand the use of fair value, but it has applicability to several current
accounting standards that require or permit us to measure assets and liabilities
at fair value.
On
February 12, 2008, the FASB issued FASB Staff Position No. FAS 157-2,
Effective Date of FASB Statement No.
157
, which amends SFAS 157 by allowing entities to delay its effective
date by one year for non-financial assets and non-financial liabilities, except
for items that are recognized or disclosed at fair value in the financial
statements on a recurring basis. We have deferred the application of
SFAS 157, related to asset retirement obligations until January 1, 2009, as
permitted by this FSP.
SFAS 157
defines fair value as "the price that would be received to sell an asset or paid
to transfer a liability in an orderly transaction between market participants at
the measurement date," or the "exit price." We must determine that
fair value of an asset or liability based on the assumptions that market
participants would use in pricing the asset or liability (if available), and not
on our assumptions. The identification of market participant
assumptions provides a basis for determining what inputs are to be used for
pricing each asset or liability. SFAS 157 also establishes a
three-level fair value hierarchy, reflecting the extent to which inputs to the
determination of fair value can be observed, and requires fair value disclosures
based upon this hierarchy. The adoption of SFAS 157 did not have a
material impact on our financial position, results of operations and cash
flows. See Note 5 - Fair Value for additional
information.
In
February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial
Assets and Financial Liabilities
("SFAS 159"). SFAS 159
establishes a fair value option under which entities can elect to report certain
financial assets and liabilities at fair value, with changes in fair value
recognized in earnings. On January 1, 2008, SFAS 159 became
effective; however, we did not elect the fair value option for any of our
financial assets or liabilities.
Pension and
Postretirement:
We adopted the
recognition and disclosure provisions of SFAS No. 158
Employers' Accounting for Defined
Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements
No. 87, 88, 106, and 132(R)
("SFAS 158") as of December 31,
2006. SFAS 158 requires companies to measure plan assets and benefit
obligations as of the same date as their fiscal year-end balance
sheet. This provision of SFAS 158 is effective for CVPS in 2008 and
we adopted the measurement provisions on January 1, 2008. For the
purpose of determining the impact of adoption, we estimated that changing the
annual benefit measurement date from September 30, 2007 to December 31, 2008
resulted in a pre-tax charge of $1.3 million, of which $0.1 million was recorded
to retained earnings. Our pension and postretirement medical plans
will be remeasured as of December 31, 2008. In the most recent retail
rate proceeding we received approval for recovery of the regulated utility
portion of the impact resulting from the change in measurement
date. Accordingly, we have recorded a regulatory asset of $1.2
million in the first quarter of 2008 that will be amortized over five years,
commencing on February 1, 2008.
FSP FIN 39-1:
In April 2007, the FASB
issued FSP FIN 39-1,
Offsetting of Amounts Related to
Certain Contracts
. It permits the offsetting of amounts
recognized for the right to reclaim cash collateral or the obligation to return
cash collateral against amounts recognized for derivative instruments executed
with the same counterparty under the same master netting arrangement that have
been offset. We adopted this FSP on January 1, 2008 and it did
not impact our financial statements since our accounting policy is to continue
reporting derivatives on a gross basis.
Recent
Accounting Pronouncements Not Yet Adopted
SFAS 141(R)
: In
December 2007, the FASB issued SFAS No. 141 (revised 2007),
Business Combinations
("SFAS
141R"). SFAS 141R replaces SFAS 141 and establishes principles and
requirements for the recognition and measurement by acquirers of assets
acquired, the liabilities assumed, any noncontrolling interest in the acquiree
and any goodwill acquired. SFAS 141R also establishes disclosure
requirements to enable financial statement readers to evaluate the nature and
financial effects of the business combination. SFAS 141R will become
effective for us on January 1, 2009. The impact of applying SFAS 141R
for periods subsequent to implementation will be dependent upon the nature of
any transactions within the scope of SFAS 141R.
SFAS 160
: In
December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in
Consolidated Financial Statements - an amendment of ARB No. 51
("SFAS
160"). SFAS 160 states that minority interests will be
recharacterized as noncontrolling interests and classified as a component of
equity. SFAS 160 also establishes reporting requirements that provide
sufficient disclosures that identify and distinguish between the interests of
the parent and the interests of the noncontrolling owners. SFAS 160
will affect only those entities that have an outstanding noncontrolling interest
in one or more subsidiaries or that deconsolidate a subsidiary. It
requires that once a subsidiary is deconsolidated, any retained noncontrolling
equity investment in the former subsidiary be initially measured at fair
value. SFAS 160 is effective as of the beginning of an entity's first
fiscal year beginning on or after December 15, 2008 (beginning January 1, 2009
for us). We have not yet evaluated the impact, if any, that the
adoption of SFAS 160 may have on our financial statements.
SFAS 161:
In March
2008, the FASB issued SFAS No. 161,
Disclosures about Derivative
Instruments and Hedging Activities, an amendment of FASB Statement No.
133
("SFAS 161"). SFAS 161 requires enhanced disclosures about
an entity's derivative and hedging activities. SFAS 161 is effective
for financial statements issued for fiscal years and interim periods beginning
after November 15, 2008 (beginning January 1, 2009 for us). We have
not yet evaluated the impact, if any, that the adoption of SFAS 161 may have on
our financial statements.
NOTE
2 - EARNINGS PER SHARE ("EPS")
The
Condensed Consolidated Statements of Income include basic and diluted per share
information. The table below provides a reconciliation of the
numerator and denominator used in calculating basic and diluted EPS for the
three months ended March 31 (dollars in thousands, except share
information):
|
|
2008
|
|
|
2007
|
|
Numerator for basic
and diluted EPS:
|
|
|
|
|
|
|
Net
income
|
|
$
|
5,908
|
|
|
$
|
5,706
|
|
Dividends
declared on preferred stock
|
|
|
(92
|
)
|
|
|
(92
|
)
|
Net
income available for common stock
|
|
$
|
5,816
|
|
|
$
|
5,614
|
|
|
|
|
|
|
|
|
|
|
Denominators for basic
and diluted EPS:
|
|
|
|
|
|
|
|
|
Weighted-average
basic shares of common stock outstanding
|
|
|
10,275,505
|
|
|
|
10,135,481
|
|
Dilutive
effect of stock options
|
|
|
90,916
|
|
|
|
102,920
|
|
Dilutive
effect of performance shares
|
|
|
10,613
|
|
|
|
2,201
|
|
Weighted-average
diluted shares of common stock outstanding
|
|
|
10,377,034
|
|
|
|
10,240,602
|
|
All
outstanding stock options were included in the computation of diluted shares in
2008 and 2007 because the exercise prices were below the average market price of
the common shares. A total of 12,159 of performance shares were
excluded from the computation in 2008 because the grant-date fair value exceeded
the average market price of common shares. All performance shares
were included in the computation in 2007.
NOTE
3 - INVESTMENTS IN AFFILIATES
Summarized
financial information for Transco for the three months ended March 31 follows
(dollars in thousands). These amounts are also included in VELCO
consolidated financial information below.
|
|
2008
|
|
|
2007
|
|
Operating
revenues
|
|
$
|
17,747
|
|
|
$
|
12,664
|
|
Operating
income
|
|
$
|
9,058
|
|
|
$
|
5,540
|
|
Net
income
|
|
$
|
8,767
|
|
|
$
|
3,507
|
|
|
|
|
|
|
|
|
|
|
Company's
ownership interest
|
|
|
39.79
|
%
|
|
|
29.86
|
%
|
Company's
equity in net income
|
|
$
|
3,732
|
|
|
$
|
1,161
|
|
Included
in Transco's operating revenues above are transmission sales to us of
approximately $3.4 million in 2008 and $1.5 million in 2007. These
amounts are reflected as Transmission - affiliates on our Condensed Consolidated
Statements of Income. Transmission services provided by Transco are
billed to us under the 1991 Transmission Agreement ("VTA"). All
Vermont electric utilities are parties to the VTA. In June 2007, FERC
issued an Order combining three FERC filings related to the VTA, including a
request by five municipal utilities for FERC approval to withdraw from the VTA
and take transmission service under a different tariff, and a request by Transco
for revisions to the VTA. The parties reached a preliminary
settlement in January 2008 and filed a definitive settlement agreement with the
FERC in March 2008. The settlement agreement is supported by all
parties, including us, and resolves all issues that were raised in the FERC
proceedings. The settlement agreement must be approved by the FERC
and related amendments to the Transco Operating Agreement, necessary to
implement the settlement, must be approved by the PSB. We expect that
the settlement agreement, if approved, will trigger reconsideration events under
FIN 46R,
Consolidation of
Variable Interest Entities
, but have not yet completed our assessment of
the potential impact, if any.
Summarized
financial information for VELCO consolidated for the three months ended March 31
follows (dollars in thousands):
|
|
2008
|
|
|
2007
|
|
Operating
revenues
|
|
$
|
17,874
|
|
|
$
|
12,787
|
|
Operating
income
|
|
$
|
8,609
|
|
|
$
|
5,088
|
|
|
|
|
|
|
|
|
|
|
Net
income before non-controlling interest
|
|
$
|
8,339
|
|
|
$
|
3,174
|
|
Less
members non-controlling interest in net income
|
|
|
7,628
|
|
|
|
2,365
|
|
Net
income
|
|
$
|
711
|
|
|
$
|
809
|
|
|
|
|
|
|
|
|
|
|
Company's
common stock ownership interest
|
|
|
47.05
|
%
|
|
|
47.05
|
%
|
Company's
equity in net income
|
|
$
|
372
|
|
|
$
|
397
|
|
Summarized
financial information for VYNPC for the three months ended March 31 follows
(dollars in thousands):
|
|
2008
|
|
|
2007
|
|
Operating
revenues
|
|
$
|
45,654
|
|
|
$
|
44,372
|
|
Operating
income
|
|
$
|
139
|
|
|
$
|
827
|
|
Net
income
|
|
$
|
124
|
|
|
$
|
225
|
|
|
|
|
|
|
|
|
|
|
Company's
common stock ownership interest
|
|
|
58.85
|
%
|
|
|
58.85
|
%
|
Company's
equity in net income
|
|
$
|
73
|
|
|
$
|
133
|
|
Included
in VYNPC's operating revenues above are sales to us of approximately $15.9
million in 2008 and $15.5 million in 2007. These are included in
Purchased power - affiliates on our Condensed Consolidated Statements of
Income. Also see Note 7 - Commitments and Contingencies.
Maine Yankee, Connecticut Yankee and
Yankee Atomic
We own, through equity investments, 2 percent of Maine
Yankee, 2 percent of Connecticut Yankee and 3.5 percent of Yankee
Atomic. All three companies have completed plant decommissioning and
the operating licenses have been amended by the Nuclear Regulatory Commission
("NRC") for operation of Independent Spent Fuel Storage
Installations. All three remain responsible for safe storage of the
spent nuclear fuel and waste at the sites until the United States Department of
Energy ("DOE") meets its obligation to remove the material from the
sites. Our share of their estimated costs are reflected on the
Condensed Consolidated Balance Sheets as regulatory assets and nuclear
decommissioning liabilities (current and non-current). These amounts
are adjusted when revised estimates are provided. At March 31, 2008,
we had regulatory assets of $1.7 million for Maine Yankee, $6.8 million for
Connecticut Yankee and $2.8 million for Yankee Atomic. These
estimated costs are being collected from customers through existing retail rate
tariffs. Total billings from the three companies amounted to $0.6
million in 2008 and $0.7 million in 2007. These amounts are included
in Purchased power - affiliates on our Condensed Consolidated Statements of
Income.
All three
companies have been seeking recovery of fuel storage-related costs stemming from
the default of the DOE under the 1983 fuel disposal contracts that were mandated
by the United States Congress under the Nuclear Waste Policy Act of
1982. Under the Act, the companies believe the DOE was required to
begin removing spent nuclear fuel and Greater than Class C material from the
nuclear plants no later than January 31, 1998 in return for payments by each
company into the nuclear waste fund. No fuel has been collected by
the DOE, and spent nuclear fuel is being stored at each of the
plants. Maine Yankee, Connecticut Yankee and Yankee Atomic collected
the funds from us and other wholesale utility customers, under FERC-approved
wholesale rates, and our share of these payments was collected from retail
customers.
In 2006,
the United States Court of Federal Claims issued judgment in the spent fuel
litigation. Maine Yankee was awarded $75.8 million in damages through
2002, Connecticut Yankee was awarded $34.2 million through 2001 and Yankee
Atomic was awarded $32.9 million through 2001. In December 2006, the
DOE filed a notice of appeal of the court's decision and all three companies
filed notices of cross appeals. As a result none of the companies
have recognized the damage awards on their books. A decision on the
appeals is expected in late 2008. Each of the companies' respective
FERC settlements requires that damage payments, net of taxes and net of further
spent fuel trust funding, be credited to ratepayers including us. We
expect that our share of these awards, if any, would be credited to our
ratepayers.
In
December 2007, the three companies filed a second round of claims against the
government for damages sustained from 2002 for Maine Yankee and from 2001 for
Connecticut Yankee and Yankee Atomic.
We cannot
predict the ultimate outcome of these cases due to the pending appeals and the
complexity of the issues in the second round of cases.
NOTE
4 - RETAIL RATES AND REGULATORY ACCOUNTING
Retail Rates
In January 2008,
the PSB approved a settlement agreement that we previously reached with the
Vermont Department of Public Service ("DPS"). The settlement
included, among other things, a 2.30 percent rate increase (additional revenue
of $6.4 million on an annual basis) effective February 1, 2008 and a 10.71
percent rate of return on equity, capped until our next rate proceeding or
approval of the alternative regulation plan that we submitted in August
2007. We also agreed to conduct an independent business process
review to assure our cost controls are sufficiently challenging and that we are
operating efficiently. That review commenced in April
2008.
If
approved, our alternative regulation plan allows for quarterly rate adjustments
to reflect power supply cost changes and annual rate adjustments to reflect
changes, within predetermined limits, from the allowed earnings
level. The plan is designed to encourage efficiency in operations,
and would replace the traditional ratemaking process. We cannot
predict the outcome of this matter at this time.
Regulatory Accounting
Under
SFAS 71, we account for certain transactions in accordance with permitted
regulatory treatment whereby 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. In the event that
we no longer meet the criteria under SFAS 71 and there is not a rate mechanism
to recover these costs, we would be required to write off $16.9 million of
regulatory assets (total regulatory assets of $32.2 million less pension and
postretirement medical costs of $15.3 million), $13.1 million of other deferred
charges - regulatory and $9.8 million of other deferred credits -
regulatory. This would result in a total extraordinary charge to
operations of $20.2 million pre-tax as of March 31, 2008. We would
also be required to record pre-tax pension and postretirement costs of $14.1
million to Accumulated Other Comprehensive Loss and $1.2 million to Retained
Earnings as reductions to stockholders' equity. We would also be
required to determine any potential impairment to the carrying costs of
deregulated plant.
Regulatory
assets, certain other deferred charges and other deferred credits are shown in
the table below (dollars in thousands). All regulatory assets are
being recovered in retail rates, and are earning a return except for income
taxes, nuclear plant dismantling costs and pension and postretirement medical
costs.
|
|
March
31, 2008
|
|
|
December
31, 2007
|
|
Regulatory
assets
|
|
|
|
|
|
|
Pension
and postretirement medical costs - SFAS No. 158
|
|
$
|
15,278
|
|
|
$
|
14,673
|
|
Nuclear
plant dismantling costs
|
|
|
11,322
|
|
|
|
11,889
|
|
Nuclear
refueling outage costs - Millstone
|
|
|
547
|
|
|
|
820
|
|
Income
taxes
|
|
|
3,812
|
|
|
|
3,757
|
|
Asset
retirement obligations
|
|
|
570
|
|
|
|
575
|
|
Other
|
|
|
646
|
|
|
|
274
|
|
Total
Regulatory assets
|
|
|
32,175
|
|
|
|
31,988
|
|
Other deferred charges
- regulatory
|
|
|
|
|
|
|
|
|
Vermont
Yankee sale costs (tax)
|
|
|
673
|
|
|
|
673
|
|
Unrealized
loss on power contract derivatives
|
|
|
12,360
|
|
|
|
7,817
|
|
Tree
trimming and pole treating
|
|
|
41
|
|
|
|
498
|
|
Total
Other deferred charges - regulatory
|
|
|
13,074
|
|
|
|
8,988
|
|
Other
deferred credits -
regulatory
|
|
|
|
|
|
|
|
|
Vermont
utility overearnings 2001 - 2003
|
|
|
534
|
|
|
|
961
|
|
Asset
retirement obligation - Millstone Unit #3
|
|
|
2,702
|
|
|
|
3,085
|
|
Vermont
Yankee IRS settlement
|
|
|
635
|
|
|
|
726
|
|
Emission
allowances and renewable energy credits
|
|
|
539
|
|
|
|
616
|
|
Unrealized
gain on power contract derivatives
|
|
|
845
|
|
|
|
707
|
|
Environmental
remediation
|
|
|
1,693
|
|
|
|
1,834
|
|
Vermont
Yankee fire settlement
|
|
|
609
|
|
|
|
870
|
|
Amortization
of provision for rate refund
|
|
|
705
|
|
|
|
-
|
|
VYNPC
nuclear insurance refund
|
|
|
560
|
|
|
|
57
|
|
Other
|
|
|
949
|
|
|
|
539
|
|
Total
Other deferred credits - regulatory
|
|
$
|
9,771
|
|
|
$
|
9,395
|
|
NOTE
5 - FAIR VALUE
Effective
January 1, 2008, we adopted SFAS 157 as required. SFAS 157
establishes a single, authoritative definition of fair value, prescribes methods
for measuring fair value, establishes a fair value hierarchy based on the inputs
used to measure fair value and expands disclosures about the use of fair value
measurements; however, SFAS 157 does not expand the use of fair value accounting
in any new circumstances. SFAS 157 defines fair value as “the price
that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the measurement
date.”
Valuation
Techniques:
SFAS 157 emphasizes that fair value is not an
entity-specific measurement but a market-based measurement utilizing assumptions
market participants would use to price the asset or liability. SFAS
157 provides guidance on three valuation techniques to be used at initial
recognition and subsequent measurement of an asset or liability:
Market
Approach:
This approach uses prices and other relevant
information generated by market transactions involving identical or comparable
assets or liabilities.
Income
Approach:
This approach uses valuation techniques to convert
future amounts (cash flows, earnings) to a single present value
amount.
Cost
Approach:
This approach is based on the amount currently
required to replace the service capacity of an asset (often referred to as the
“current replacement cost”).
The
valuation technique (or a combination of valuation techniques) utilized to
measure fair value is the one that is appropriate given the circumstances and
for which sufficient data is available. Techniques must be
consistently applied, but change is appropriate if new information is
available.
Fair Value
Hierarchy:
SFAS 157 establishes a fair value hierarchy
(“hierarchy”) to prioritize the inputs used in valuation techniques. The
hierarchy is designed to indicate the relative reliability of the fair value
measure. The highest priority is given to quoted prices in active markets, and
the lowest to unobservable data, such as an entity’s internal information. The
lower the level of the input of a fair value measurement, the more extensive the
disclosure requirements. There are three broad levels:
Level
1:
Quoted prices (unadjusted) are available in active markets
for identical assets or liabilities as of the reporting date.
Level
2:
Pricing inputs are other than quoted prices in active
markets included in Level 1, which are directly or indirectly observable as of
the reporting date. This value is based on other observable inputs,
including quoted prices for similar assets and liabilities in markets that are
not active. Level 2 includes investments in our Millstone
Decommissioning Trust Funds such as fixed income securities (Treasury
securities, other agency and corporate debt) and equity securities.
Level
3:
Pricing inputs include significant inputs that are
generally less observable. Unobservable inputs may be used to measure
the asset or liability where observable inputs are not available. We
develop these inputs based on the best information available, including our own
data. Level 3 instruments include derivatives related to our forward
energy purchases and sales, financial transmission rights and a power-related
option contract.
Recurring
Measures:
The following table sets forth by level within the
fair value hierarchy our financial assets and liabilities that were accounted
for at fair value on a recurring basis. Our assessment of the
significance of a particular input to the fair value measurement requires
judgment, and may affect the valuation of fair value assets and liabilities and
their placement within the fair value hierarchy levels (dollars in
thousands):
|
Fair
Value as of March 31, 2008
|
|
|
Level
1
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Millstone
decommissioning trust fund
|
|
|
$
|
5,299
|
|
|
|
|
|
$
|
5,299
|
|
Power-related
derivatives
|
|
|
|
|
|
|
$
|
934
|
|
|
|
934
|
|
Total
|
|
|
$
|
5,299
|
|
|
$
|
934
|
|
|
$
|
6,233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power-related
derivatives
|
|
|
|
|
|
|
$
|
12,360
|
|
|
$
|
12,360
|
|
Millstone Decommissioning
Trust:
Our primary valuation technique to measure the fair
value of our nuclear decommissioning trust investments is the market
approach. Actively traded quoted prices cannot be obtained for the
funds in our decommissioning investments. However, actively traded
quoted prices for the underlying securities comprising the funds have been
obtained. Due to these observable inputs, fixed income, equity and
cash equivalent securities in the funds are classified as Level 2.
Derivative Financial
Instruments:
We estimate fair values of power-related
derivatives based on the best market information available, including the use of
internally developed models and broker quotes for forward energy
contracts. We use other models and our own assumptions about future
congestion costs for valuing financial transmission rights. We also
use a binomial tree model and an internally developed long-term price forecast
to value a power-related option contract.
Level 3
Changes:
The following table is a reconciliation of changes in
the fair value of items classified as level 3 in the fair value
hierarchy. There were no transfers in or out of level 3 during the
period (dollars in thousands).
|
|
Power-related
|
|
|
|
Derivatives,
net
|
|
Balance
as of January 1, 2008
|
|
$
|
(7,110
|
)
|
Net
realized losses recognized in Purchase Power - other
|
|
|
(44
|
)
|
Net
unrealized gains (losses) included in regulatory liability
(asset)
|
|
|
(4,921
|
)
|
Purchases,
sales, issuances & net settlements
|
|
|
649
|
|
Transfers
to or (from) level 3
|
|
|
|
|
Balance
as of March 31, 2008
|
|
$
|
(11,426
|
)
|
|
|
|
|
|
Net
realized losses relating to instruments still held as of March 31,
2008
|
|
$
|
(23
|
)
|
Based on
a PSB-approved Accounting Order, we record the change in fair value of power
contract derivatives as deferred charges or deferred credits on the Condensed
Consolidated Balance Sheet, depending on whether the fair value is an unrealized
loss or gain. The corresponding offsets are recorded as current and
long-term assets or liabilities depending on the duration.
NOTE
6 - PENSION AND POSTRETIREMENT MEDICAL BENEFITS
The fair
value of Pension Plan trust assets was $85.6 million at March 31, 2008 and $91.9
million at December 31, 2007. The unfunded accrued pension benefit obligation
recorded on the Condensed Consolidated Balance Sheets was $2.7 million at March
31, 2008 and $1.7 million at December 31, 2007.
The fair
value of Postretirement Plan trust assets was $12.2 million at March 31, 2008
and $13.2 million at December 31, 2007. The unfunded accrued
postretirement benefit obligation recorded on the Condensed Consolidated Balance
Sheets was $13.7 million at March 31, 2008, and $13 million at December 31,
2007.
Components
of net periodic benefit costs for the three months ended March 31 follow
(dollars in thousands):
|
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Service
cost
|
|
$
|
823
|
|
|
$
|
888
|
|
|
$
|
155
|
|
|
$
|
145
|
|
Interest
cost
|
|
|
1,523
|
|
|
|
1,561
|
|
|
|
403
|
|
|
|
377
|
|
Expected
return on plan assets
|
|
|
(1,831
|
)
|
|
|
(1,680
|
)
|
|
|
(267
|
)
|
|
|
(233
|
)
|
Amortization
of net actuarial loss
|
|
|
-
|
|
|
|
146
|
|
|
|
263
|
|
|
|
263
|
|
Amortization
of prior service cost
|
|
|
97
|
|
|
|
100
|
|
|
|
-
|
|
|
|
-
|
|
Amortization
of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
64
|
|
|
|
64
|
|
Net
periodic benefit cost
|
|
|
612
|
|
|
|
1,015
|
|
|
|
618
|
|
|
|
616
|
|
Less
amounts capitalized
|
|
|
88
|
|
|
|
171
|
|
|
|
89
|
|
|
|
104
|
|
Net
benefit costs expensed
|
|
$
|
524
|
|
|
$
|
844
|
|
|
$
|
529
|
|
|
$
|
512
|
|
NOTE
7 - COMMITMENTS AND CONTINGENCIES
Nuclear Decommissioning Obligations
We have a 1.7303 joint-ownership percentage in Millstone Unit # 3, in
which Dominion Nuclear Connecticut ("DNC") is the lead owner with about 93.4707
percent of the plant joint-ownership. We have an external trust
dedicated to funding our joint-ownership share of future decommissioning
costs. DNC has suspended contributions to the Millstone Unit #3 Trust
Fund because the minimum NRC funding requirements are being met or
exceeded. We have also suspended contributions to the Trust Fund, but
could choose to renew funding at our own discretion as long as the minimum
requirement is met or exceeded. If additional decommissioning funding
is necessary, we will be obligated to resume contributions to the Trust
Fund.
Our
obligations related to Maine Yankee, Connecticut Yankee and Yankee Atomic are
described in Note 3 - Investments in Affiliates. We also had a 35
percent ownership interest in the Vermont Yankee nuclear power plant through our
equity investment in VYNPC, but the plant was sold in 2002. Our
obligation for plant decommissioning costs ended when the plant was sold, except
that VYNPC retained responsibility for the pre-1983 spent fuel disposal cost
liability. VYNPC has a dedicated trust fund for this
liability. At this time, the fund balance is expected to equal or
exceed the obligation. Excess funds, if any, will be returned to us
and must be applied to the benefit of ratepayers.
Long-Term Power Purchase Obligations
Vermont
Yankee:
We
are purchasing our entitlement share of Vermont Yankee plant output through the
Purchase Power Agreement ("PPA") between Entergy Nuclear Vermont Yankee, LLC
("ENVY") and VYNPC. An uprate in 2006 increased the plant's operating
capacity by approximately 20 percent. After completion of the uprate, VYNPC's
entitlement to plant output declined from 100 percent to 83 percent, and our
entitlement share declined from 35 percent to 29 percent. ENVY has no
obligation to supply energy to VYNPC over its entitlement share of plant output,
so we receive reduced amounts when the plant is operating at a reduced level,
and no energy when the plant is not operating. The plant normally
shuts down for about one month every 18 months for maintenance and to insert new
fuel into the reactor.
We
normally purchase replacement energy in the wholesale markets in New England
when the Vermont Yankee plant is not operating or is operating at reduced
levels. We also have forced outage insurance to cover additional
costs, if any, of obtaining replacement power from other sources if the Vermont
Yankee plant experiences unplanned outages. We recently renegotiated
the policy to extend coverage through March 31, 2009 instead of December 31,
2008. The coverage applies to unplanned outages of up to 30
consecutive calendar days per outage event, and provides for payment of the
difference between the spot market price and $40/mWh. The total maximum coverage
is $12.0 million.
We are a
party to a PSB Docket that was opened in June 2006 to investigate whether the
reliability of the increased plant output would be adversely affected by the
operation of the plant's steam dryer. In September 2006, the PSB
issued an order requiring ENVY to provide additional ratepayer
protections. The DPS and ENVY reached an agreement in a compliance
filing with the PSB, but ENVY requested reconsideration of the PSB
ruling. Reconsideration was denied and ENVY has appealed to the
Vermont Supreme Court. Although the appeal remains pending, the
period during which the protection applied has expired without occurrence of
such an event.
The PPA
between ENVY and VYNPC contains a formula for determining the VYNPC power
entitlement following the uprate. VYNPC and ENVY are seeking to
resolve certain differences in the interpretation of the formula. At
issue is how much capacity and energy VYNPC Sponsors receive under the PPA
following the uprate. Based on VYNPC's calculations, the VYNPC
Sponsors should be entitled to slightly more capacity and energy than they are
currently receiving under the PPA. We cannot predict the outcome of
this matter at this time.
If the
Vermont Yankee plant is shut down for any reason prior to the end of its
operating license, we would lose the economic benefit of an energy volume equal
to close to 50 percent of our total committed supply and have to acquire
replacement power resources for approximately 40 percent of our estimated power
supply needs. Based on projected market prices as of March 31, 2008,
the incremental replacement cost of lost power, including capacity, is estimated
to average $60 million annually. We are not able to predict whether
there will be an early shutdown of the Vermont Yankee plant or whether the PSB
would allow timely and full recovery of increased costs related to any such
shutdown. However, an early shutdown could materially impact our
financial position and future results of operations if the costs are not
recovered in retail rates in a timely fashion.
Hydro-Quebec:
We are
purchasing power from Hydro-Quebec under the Vermont Joint Owners ("VJO") Power
Contract and related contracts negotiated between us and
Hydro-Quebec. There are specific contractual provisions that provide
that in the event any VJO participant fails to meet its obligation under the
contract, the remaining VJO participants must "step-up" to the defaulting
party's share on a pro rata basis. The VJO contract runs through
2020, but our purchases end in 2016. As of November 1, 2007, the
annual load factor was reduced from 80 percent to 75 percent, and it will remain
at 75 percent until the contract ends, unless the contract is changed or there
is a reduction due to the adverse hydraulic conditions described
below. Total purchases under the VJO Contract were $16.4 million in
the first quarter of 2008 and $16.7 million in the first quarter of
2007.
In the
early phase of the VJO Power Contract, two sellback contracts were negotiated,
the first delaying the purchase of 25 MW of capacity and associated energy, the
second reducing the net purchase of Hydro-Quebec power through 1996. In 1994, we
negotiated a third sellback arrangement whereby we received a reduction in
capacity costs from 1995 to 1999. In exchange, Hydro-Quebec obtained
two options. The first gives Hydro-Quebec the right, upon four years'
written notice, to reduce capacity and associated energy deliveries by 50 MW,
including the use of a like amount of our Phase I/II transmission facility
rights. The second gives Hydro-Quebec the right, upon one year's
written notice, to curtail energy deliveries in a contract year (12 months
beginning November 1) from an annual capacity factor of 75 to 50 percent due to
adverse hydraulic conditions as measured at certain metering stations on
unregulated rivers in Quebec. This second option can be exercised
five times through October 2015. Hydro-Quebec has not yet exercised
these options.
In
accordance with FIN 45, we are required to disclose the "maximum potential
amount of future payments (undiscounted) the guarantor could be required to make
under the guarantee." Such disclosure is required even if the
likelihood is remote. With regard to the "step-up" provision in the
VJO Power Contract, we must assume that all members of the VJO simultaneously
default in order to estimate the "maximum potential" amount of future
payments. We believe this is a highly unlikely scenario given that
the majority of VJO members are regulated utilities with regulated cost
recovery. Each VJO participant has received regulatory approval to
recover the cost of this purchased power in their most recent rate
applications. Despite the remote chance that such an event could
occur, we estimate that our undiscounted purchase obligation would be about an
additional $550 million for the remainder of the contract, assuming that all
members of the VJO defaulted by April 1, 2008 and remained in default for the
duration of the contract. In such a scenario, we would then own the
power and could seek to recover our costs from the defaulting members or our
retail customers, or resell the power in the wholesale power markets in New
England. The range of outcomes (full cost recovery, potential loss or
potential profit) would be highly dependent on Vermont regulation and wholesale
market prices at the time.
Independent Power Producers:
We purchase power
from a number of Independent Power Producers that own qualifying facilities
under the Public Utility Regulatory Policies Act of 1978. These
qualifying facilities produce energy primarily using hydroelectric and biomass
generation. Most of the power comes through a state-appointed
purchasing agent that allocates power to all Vermont utilities under PSB
rules. Total purchases were $7.9 million in the first quarter of 2008
and $6.2 million in the first quarter of 2007.
Performance
Assurance
We are subject to performance assurance
requirements through ISO-New England under the Financial Assurance Policy for
NEPOOL members. We are required to post collateral for all net
purchased power transactions since our credit limit with ISO-New England is
zero. Additionally, we are selling power in the wholesale market
pursuant to contracts with third parties, and are required to post collateral
under certain conditions defined in the contracts. At March 31, 2008,
our total collateral requirements amounted to $4.5 million. We posted
$6 million of letters of credit under our $25 million revolving credit facility
and $0.6 million in cash to support these requirements. The $0.6
million in cash is included in Cash and Cash Equivalents on the Condensed
Consolidated Balance Sheet since it is not legally restricted.
We are
also subject to performance assurance requirements under our Vermont Yankee
power purchase contract (the 2001 Amendatory Agreement). If ENVY, the
seller, has commercially reasonable grounds to question our ability to pay for
our monthly power purchases, ENVY may ask VYNPC and VYNPC may then ask us to
provide adequate financial assurance of payment. We have not had to post
collateral under this contract.
Operating leases:
We
lease our vehicles and related equipment under one operating lease
agreement. We have guaranteed a residual value to the lessor in the event
leased items are sold. The guarantee provides for reimbursement of up to 87
percent of the unamortized value of the lease portfolio. Under the
guarantee, if the entire lease portfolio had a fair value of zero at March 31,
2008, we would have been responsible for a maximum reimbursement of $8.5
million. At March 31, 2008, we had a liability of $0.2 million, which
is offset in prepayments on the Condensed Consolidated Balance
Sheet.
Environmental
Over
the years, more than 100
companies have merged into or been acquired by CVPS. At least two of
those companies used coal to produce gas for retail sale. This
practice ended more than 50 years ago. Gas manufacturers, their
predecessors and CVPS used waste disposal methods that were legal and acceptable
then, but may not meet modern environmental standards and could represent a
liability. Some operations and activities are inspected and
supervised by federal and state authorities, including the Environmental
Protection Agency. We believe that we are in compliance with all laws
and regulations and have implemented procedures and controls to assess and
assure compliance. Corrective action is taken when
necessary. Below is a brief discussion of known material
issues.
Cleveland Avenue Property
:
The Cleveland Avenue property in Rutland, Vermont, was used by a predecessor to
make gas from coal. Later, we sited various operations
there. Due to the existence of coal tar deposits, polychlorinated
biphenyl contamination and the potential for off-site migration, we conducted
studies in the late 1980s and early 1990s to quantify the potential costs to
remediate the site. Investigation at the site has continued,
including work with the State of Vermont to develop a mutually acceptable
solution. In 2006, we updated the cost estimate of remediation for
this site. The liability for site remediation is expected to range
from $2.3 million to $0.9 million. As of March 31, 2008, we accrued
$1.3 million representing the most likely cost of the remediation
effort.
Brattleboro Manufactured Gas
Facility
: In the 1940s, we owned and operated a manufactured gas
facility in Brattleboro, Vermont. We ordered a site assessment in
1999 at the request of the State of New Hampshire. In 2001, New
Hampshire indicated that no further action was required, though it reserved the
right to require further investigation or remedial measures. In 2002,
the Vermont Agency of Natural Resources notified us that our corrective action
plan for the site was approved. That plan is now in
place. In 2006, we updated the cost estimate of remediation for this
site. The liability for site remediation is expected to range from
$1.3 million to $0.1 million. As of March 31, 2008, we accrued $0.6
million representing the most likely cost of the remediation
effort.
Dover, New Hampshire, Manufactured
Gas Facility:
In 1999, Public Service Company of New Hampshire
contacted us about this site, and we reached a settlement with them in
2002. Our remaining obligation was less than $0.1 million at March
31, 2008.
The
reserve for environmental matters described above amounted to $1.9 million as of
March 31, 2008 and December 31, 2007. The current and long-term
portions are included as liabilities on the Condensed Consolidated Balance
Sheets. The reserve represents our best estimate of the cost to
remedy issues at these sites based on available information as of the end of the
reporting period. To our knowledge, there is no pending or threatened
litigation regarding other sites with the potential to cause material
expense. No government agency has sought funds from us for any other
study or remediation.
Reserve for Loss on Power Contract
On January 1, 2004, we terminated a long-term power contract with
Connecticut Valley Electric Company, a regulated electric utility that used to
be our wholly owned subsidiary. In accordance with the requirements
of SFAS 5,
Accounting for
Contingencies
, we recorded a $14.4 million pre-tax loss accrual in the
first quarter of 2004 related to the contract termination. The loss
accrual represented our best estimate of the difference between expected future
sales revenue in the wholesale market for the purchased power that was formerly
sold to Connecticut Valley Electric Company and the net cost of purchased power
obligations. We review this estimate at the end of each reporting
period and will increase the reserve if the revised estimate exceeds the
recorded loss accrual. The loss accrual is being amortized on a
straight-line basis through 2015, the estimated life of the power contracts that
were in place to supply power under the contract. The reserve
amounted to $9.3 million at March 31, 2008 and $9.6 million at December 31,
2007. The current and long-term portions are included as liabilities
on the Condensed Consolidated Balance Sheets.
Catamount Indemnifications
In
2005 we sold our remaining interests in Catamount Energy Corporation
("Catamount"), our wholly owned subsidiary, and agreed to indemnify Catamount,
the purchaser and certain of their respective affiliates, in respect of a breach
of certain representations and warranties and
covenants. Indemnification is subject to a $1.5 million deductible
and a $15 million cap, excluding certain customary
items. Environmental representations are subject to the deductible
and the cap, and such environmental representations for only two of Catamount's
underlying energy projects survived beyond June 30, 2007. Our
estimated "maximum potential" amount of future payments related to these
indemnifications is limited to $15 million. We have not recorded any
liability related to these indemnifications.
NOTE
8 - SEGMENT REPORTING
The
following table provides segment financial data for the three months ended March
31 (dollars in thousands). Inter-segment revenues were a nominal
amount in both periods presented.
|
|
|
|
|
|
|
|
Reclassification
&
|
|
|
|
|
|
|
CV-VT
|
|
|
|
|
|
Consolidating
Entries
|
|
|
Consolidated
|
|
March 31,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from external customers
|
|
$
|
91,224
|
|
|
$
|
432
|
|
|
$
|
(432
|
)
|
|
$
|
91,224
|
|
Net
income
|
|
$
|
5,830
|
|
|
$
|
78
|
|
|
$
|
-
|
|
|
$
|
5,908
|
|
Total
assets at March 31, 2008
|
|
$
|
548,333
|
|
|
$
|
1,872
|
|
|
$
|
(283
|
)
|
|
$
|
549,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
from external customers
|
|
$
|
86,696
|
|
|
$
|
435
|
|
|
$
|
(435
|
)
|
|
$
|
86,696
|
|
Net
income
|
|
$
|
5,478
|
|
|
$
|
228
|
|
|
$
|
-
|
|
|
$
|
5,706
|
|
Total
assets at December 31, 2007
|
|
$
|
538,481
|
|
|
$
|
2,134
|
|
|
$
|
(301
|
)
|
|
$
|
540,314
|
|
Item
2. Management's
Discussion and Analysis of Financial
Condition and Results of Operations
In this
section we discuss our general financial condition and results of
operations. Certain factors that may impact future operations are
also discussed. Our discussion and analysis is based on, and should
be read in conjunction with, the accompanying Condensed Consolidated Financial
Statements.
Forward-looking statements
Statements contained in this report that are not historical fact are
forward-looking statements within the meaning of the 'safe-harbor' provisions of
the Private Securities Litigation Reform Act of 1995. Whenever used
in this report, the words "estimate," "expect," "believe," or similar
expressions are intended to identify such forward-looking
statements. Forward-looking statements involve estimates,
assumptions, risks and uncertainties that could cause actual results or outcomes
to differ materially from those expressed in the forward-looking
statements. Actual results will depend upon, among other
things:
§
|
the
actions of regulatory bodies with respect to allowed rates of return,
continued recovery of regulatory assets and proposed alternative
regulations;
|
§
|
performance
and continued operation of the Vermont Yankee nuclear power
plant;
|
§
|
effects
of and changes in weather and economic
conditions;
|
§
|
volatility
in wholesale power markets;
|
§
|
ability
to maintain or improve our current credit
ratings;
|
§
|
the
operations of ISO-New England;
|
§
|
changes
in the cost or availability of
capital;
|
§
|
changes
in financial or regulatory accounting principles or policies imposed by
governing bodies;
|
§
|
capital
market conditions, including price risk due to marketable securities held
as investments in trust for nuclear decommissioning, pension and
postretirement medical plans;
|
§
|
changes
in the levels and timing of capital expenditures, including our
discretionary future investments in
Transco;
|
§
|
our
ability to replace or renegotiate our long-term power supply
contracts;
|
§
|
our
ability to replace a mature workforce and retain qualified, skilled and
experienced personnel;
|
§
|
and
other presently unknown or unforeseen
factors.
|
We cannot
predict the outcome of any of these matters; accordingly, there can be no
assurance as to actual results. We undertake no obligation to
publicly update any forward-looking statements, whether as a result of new
information, future events or otherwise.
EXECUTIVE
SUMMARY
Our core
business is the Vermont electric utility business. The rates we
charge for retail electricity sales are regulated by the Vermont Public Service
Board ("PSB"). Fair regulatory treatment is fundamental to
maintaining our 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.
Our
consolidated earnings for the first quarter of 2008 were $5.9 million or 56
cents per diluted share of common stock, and $5.7 million, or 55 cents per
diluted share of common stock for the same period in 2007. The
primary drivers of the first quarter year-over-year earnings variance are
described in Results of Operations below.
We
continue to focus on key strategic financial initiatives including: restoring
our corporate credit rating to investment-grade; ensuring that our retail rates
are set at levels to recover our costs of service; evaluating financing options
to support current and future working capital needs; and planning for
replacement power when long-term power contracts begin to expire in
2012.
In
December 2007, we invested $53 million in Vermont Transco LLC ("Transco") using
the proceeds from the issuance of a $53 million six-month unsecured
note. We expect to issue $60 million of first mortgage bonds on or
around May 15, 2008. The proceeds will be used to pay off the
note.
RETAIL RATES AND ALTERNATIVE
REGULATION
In
January 2008, the PSB approved a settlement agreement that we reached with the
Vermont Department of Public Service ("DPS"). This included, among
other things, a 2.30 percent rate increase (additional revenue of $6.4 million
on an annual basis) effective February 1, 2008 and a 10.71 percent rate of
return on equity, capped until our next rate proceeding or approval of the
alternative regulation plan that we submitted in August 2007. We also
agreed to conduct an independent business process review to assure our cost
controls are sufficiently challenging and that we are operating
efficiently. That review commenced in April 2008, and is expected to
conclude in the third quarter of 2008.
The
alternative regulation plan proposal that we submitted in August 2007 for PSB
approval is currently under review and a PSB decision is expected in the third
or fourth quarter of 2008. If approved, the plan would allow for
quarterly rate adjustments to reflect power supply cost changes and annual rate
adjustments to reflect changes, within predetermined limits, from the allowed
earnings level. The plan is designed to encourage efficiency in
operations, and would replace the traditional ratemaking process, which is
costly and time-consuming. We cannot predict the outcome of the
review at this time.
LIQUIDITY AND CAPITAL
RESOURCES
Cash Flows
At March 31, 2008,
we had cash and cash equivalents of $6.4 million compared to $8.8 million at
March 31, 2007. The primary components of cash flows from operating,
investing and financing activities for both periods are discussed in more detail
below.
Operating
Activities:
Operating activities provided $11.2 million in the first
quarter of 2008. Net income, when adjusted for depreciation,
amortization, deferred income tax and other non-cash income and expense items,
provided $9.7 million. In addition, changes in working capital and
other items provided $1.5 million.
During
the first quarter of 2007, operating activities provided $13.2
million. Net income, when adjusted for depreciation, amortization,
deferred income tax and other non-cash income and expense items, provided $11.5
million. Special deposits and restricted cash used to meet
performance assurance requirements for certain power contracts increased by $1.9
million because a $4.5 million letter of credit for purchased power performance
assurance was replaced with cash collateral. The remaining changes in
working capital and other items provided $3.6 million.
Investing
Activities:
Investing activities used $7.3 million in the first
quarter of 2008 for construction and plant expenditures. During 2007,
investing activities used $5.2 million, including $5.0 million for construction
and plant expenditures and $0.2 million for other investments.
Financing Activities:
In
the first quarter of 2008, financing activities used $1.3 million, including
$2.4 million for dividends paid on common and preferred stock, $1.0 million for
preferred stock sinking fund payments, and $0.2 million for capital lease
payments. These items were partially offset by $1.2 million from
stock option exercises, a $1.0 million reduction in special deposits for
preferred stock sinking fund payments, and $0.1 million for other financing
activities.
During
the first quarter of 2007, financing activities used $2.0 million, including
$2.4 million for dividends paid on common and preferred stock, $1.0 million for
preferred stock sinking fund payments, and $0.2 million for capital lease
payments. These items were partially offset by $0.6 million from
stock option exercises, and a $1.0 million reduction in restricted cash for
preferred stock sinking fund payments.
Financing
2008 Financing:
We
expect to issue $60 million of first mortgage bonds on or around May 15,
2008. The proceeds will be used to pay off our $53 million short-term
note due June 30, 2008. We are also reviewing financing options to
support current and future working capital needs resulting from investments in
our distribution and transmission system and possible future investments in
Transco.
Credit Facility:
We have a
364-day, $25 million unsecured revolving credit facility with a major lending
institution pursuant to a Credit Agreement dated December 28,
2007. Pursuant to a commitment from the bank dated February 11, 2008,
we have the sole option to extend the maturity of the credit facility to March
31, 2009. The purpose of the facility is to provide liquidity for
general corporate purposes, including working capital needs and power contract
performance assurance requirements, in the form of funds borrowed and letters of
credit. In the first quarter of 2008, we were able to obtain
amendments to certain first mortgage bond issuance restrictions. At
March 31, 2008, there were no borrowings outstanding under this facility, but $6
million of letters of credit were outstanding in support of performance
assurance requirements associated with our power transactions.
Short-Term Note
: We have a
six-month unsecured term note in the principal amount of $53 million with a
major lending institution. The loan is payable June 30, 2008 and
currently carries an adjustable interest rate tied to overnight LIBOR plus a
fixed spread that decreases as our credit rating improves. Pursuant
to a commitment from the lending institution dated February 11, 2008, we have
the sole option to extend the maturity of the term note to March 31,
2009. As described above, we intend to pay off this note in the
second quarter of 2008.
Covenants:
At
March 31, 2008, we were in compliance with all financial and non-financial
covenants related to our various debt agreements, articles of association,
letters of credit and credit facility.
Investment opportunities in
Transco
Based on current projections, Transco expects to need additional
capital in 2008 and 2009, but its projections are subject to change based on a
number of factors, including revised construction estimates, timing of project
approvals from regulators, and desired changes in its equity-to-debt
ratio. While we have no obligation to make additional investments in
Transco, we continue to evaluate investment opportunities on a case-by-case
basis. Depending on timing, the factors discussed above, and the
amounts invested by other owners, we could have an opportunity to make
additional investments up to $2 million in 2008 and $20 million to $25 million
in 2009. Any investments that we make in Transco are voluntary, and
subject to available capital and appropriate regulatory approvals.
Capital spending
In 2008, we
expect to invest $41.5 million primarily in our transmission and distribution
infrastructure to ensure continued system reliability, including installation of
new voltage support equipment in southern Vermont currently estimated at $11
million. This compares to capital expenditures of approximately $23
million in 2007. These estimates are subject to continuing review and
adjustment, and actual capital expenditures and timing may vary.
Performance assurance
We
are subject to performance assurance requirements through ISO-New England under
the Financial Assurance Policy for NEPOOL members. We are required to
post collateral for all net purchased power transactions since our credit limit
with ISO-New England is zero. Additionally, we are selling power in
the wholesale market pursuant to contracts with third parties, and are required
to post collateral under certain conditions defined in the
contracts. At March 31, 2008, our total collateral requirements
amounted to $4.5 million. We posted $6 million of letters of credit
and $0.6 million in cash to support these requirements.
We are
also subject to performance assurance requirements under our Vermont Yankee
power purchase contract (the 2001 Amendatory Agreement). If Entergy
Nuclear Vermont Yankee, LLC ("ENVY"), the seller, has commercially reasonable
grounds to question our ability to pay for monthly power purchases, ENVY may ask
VYNPC and VYNPC may then ask us to provide adequate financial assurance of
payment. We have not had to post collateral under this contract.
Cash flow risks
Based on our
current cash forecasts, we will require outside capital in addition to cash flow
from operations and our $25 million unsecured revolving credit facility in order
to fund our business over the next year. While we expect to issue
first mortgage bonds in the second quarter of 2008, continued upheaval in the
capital markets as described below could negatively impact our ability to obtain
additional outside capital on reasonable terms. In addition, an
extended unplanned Vermont Yankee plant outage or similar event could
significantly impact our liquidity due to the potentially high cost of
replacement power and performance assurance requirements arising from purchases
through ISO-New England or third parties. In the event of an extended
Vermont Yankee plant outage, we could seek emergency rate relief from our
regulators. Other material risks to cash flow from operations
include: loss of retail sales revenue from unusual weather;
slower-than-anticipated load growth and unfavorable economic conditions;
increases in net power costs due to lower-than-anticipated margins on sales
revenue from excess power or an unexpected power source interruption; required
prepayments for power purchases; and increases in performance assurance
requirements.
Subprime credit
crisis
Due to recent market developments, including a series of
rating agency downgrades of subprime U.S. mortgage-backed securities, the fair
values of subprime-related investments have declined. This decline in
fair value has become especially problematic for certain large financial
institutions. We performed an assessment of our ability to obtain
financing and currently expect to have access to liquidity in the capital
markets at reasonable rates. We also have access to our unsecured
revolving credit facility, which is not affected by general market
conditions. However, sustained turbulence in the U.S. credit markets
could limit or delay our future access to capital.
We have
also performed an assessment of the subprime exposure in our money market,
benefit and nuclear decommissioning trust funds and have determined that a
decline, if any, in fund fair value of subprime-related investments is not
expected to be material.
ACCOUNTING
MATTERS
Critical accounting policies and
estimates
Our financial statements are prepared in accordance
with generally accepted accounting principles in the United States ("U. S.
GAAP"), requiring us to make estimates and judgments that affect reported
amounts of assets and liabilities, revenues and expenses, and related disclosure
of contingent assets and liabilities at the date of the Condensed Consolidated
Financial Statements. Our critical accounting policies and estimates are
described in Management's Discussion and Analysis of Financial Condition and
Results of Operations in our 2007 Annual Report on Form 10-K. At
March 31, 2008, our critical accounting policies and estimates did not change
significantly from December 31, 2007, except as described below.
Fair Value
Measurements:
We adopted SFAS 157,
Fair Value Measurements
("SFAS 157"), on January 1, 2008. SFAS 157
defines fair value,
establishes criteria to be considered when measuring fair value and expands
disclosures about fair value measurements, but it does not expand the use of
fair value accounting in any new circumstances. On February 12, 2008, the FASB
issued FASB Staff Position No. FAS 157-2,
Effective Date of FASB Statement No.
157
, which amends SFAS 157 by allowing entities to delay its effective
date by one year for non-financial assets and non-financial liabilities, except
for items that are recognized or disclosed at fair value in the financial
statements on a recurring basis. We have deferred the application of
SFAS 157, related to our asset retirement obligations until January 1, 2009, as
permitted by this FSP. Adoption of SFAS 157 did not have a material
impact on our financial position, results of operations and cash
flows.
SFAS 157
establishes a fair value hierarchy to prioritize the inputs used in valuation
techniques. The hierarchy is designed to indicate the relative reliability of
the fair value measure. The highest priority is given to quoted prices in active
markets, and the lowest to unobservable data, such as an entity’s internal
information. The lower the level of the input of a fair value measurement, the
more extensive the disclosure requirements. The three broad levels
include: quoted prices in active markets for identical assets or liabilities
(Level 1); significant other observable inputs (Level 2); and significant
unobservable inputs (Level 3).
Our
assets and liabilities that are recorded at fair value on a recurring basis
include power-related derivatives and our Millstone decommissioning
trust. Power-related derivatives are classified as Level
3. The Millstone decommissioning trust funds include treasury
securities, other agency and corporate fixed income securities and equity
securities that are classified as Level 2. Our assessment of the
significance of a particular input to the fair value measurement requires
judgment, and may affect the valuation of fair value assets and liabilities and
their placement within the SFAS 157 fair value hierarchy levels. At
March 31, 2008, the net fair value of power-related derivatives was $11.4
million, and the fair value of decommissioning trust assets was $5.3
million.
Also see
Note 5 - Fair Value for additional information.
Other
See Note 1 - Business
Organization and Summary of Significant Accounting Policies for discussion of
newly adopted accounting policies and recently issued accounting
pronouncements.
RESULTS OF
OPERATIONS
The
following is a detailed discussion of the results of operations for the first
quarter of 2008 compared to the same period in 2007. It should be
read in conjunction with the condensed consolidated financial statements and
accompanying notes included in this report.
Our first
quarter 2008 earnings increased by $0.2 million, or 1 cent per diluted share of
common stock, compared to the same period in 2007. The table below
provides a reconciliation of the primary year-over-year variances in diluted
earnings per share.
2007
Earnings per diluted share
|
|
$
|
0.55
|
|
|
|
|
|
|
Higher operating revenues
|
|
|
0.25
|
|
Higher equity in earnings of affiliates
|
|
|
0.14
|
|
Higher purchased power expense
|
|
|
(0.04
|
)
|
Higher transmission expense
|
|
|
(0.12
|
)
|
Higher other operating expenses
|
|
|
(0.13
|
)
|
Other
|
|
|
(0.09
|
)
|
|
|
|
|
|
2008
Earnings per diluted share
|
|
$
|
0.56
|
|
Operating Revenues
Operating
revenues and related mWh sales are summarized below.
|
|
Revenue
(in thousands)
|
|
|
mWh
Sales
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Residential
|
|
$
|
38,512
|
|
|
$
|
37,705
|
|
|
|
280,995
|
|
|
|
287,588
|
|
Commercial
|
|
|
26,799
|
|
|
|
27,148
|
|
|
|
219,751
|
|
|
|
224,672
|
|
Industrial
|
|
|
9,630
|
|
|
|
10,238
|
|
|
|
104,925
|
|
|
|
118,378
|
|
Other
|
|
|
465
|
|
|
|
450
|
|
|
|
1,570
|
|
|
|
1,537
|
|
Total
retail sales
|
|
|
75,406
|
|
|
|
75,541
|
|
|
|
607,241
|
|
|
|
632,175
|
|
Resale
sales
|
|
|
13,502
|
|
|
|
9,607
|
|
|
|
205,137
|
|
|
|
174,983
|
|
Provision
for rate refund
|
|
|
(62
|
)
|
|
|
(187
|
)
|
|
|
-
|
|
|
|
-
|
|
Other
operating revenues
|
|
|
2,378
|
|
|
|
1,735
|
|
|
|
-
|
|
|
|
-
|
|
Total
operating revenues
|
|
$
|
91,224
|
|
|
$
|
86,696
|
|
|
|
812,378
|
|
|
|
807,158
|
|
Revenue
increased $4.5 million in the first quarter of 2008 compared to the same period
in 2007 as a result of the following:
§
|
Retail
sales decreased $0.1 million comprised of a $2.6 million decrease due to
lower sales volume, largely offset by a $2.5 million increase due to
higher average retail rates. Sales volume decreased due to
lower average usage resulting from economic conditions, including the
effect of the loss of two industrial customers due to plant
closures. Retail revenue increased $1.2 million due to the 2.30
percent rate increase effective February 1, 2008 and $1.3 million due to
higher average unit price due to customer usage
mix.
|
§
|
Resale
sales increased $3.9 million resulting from higher average market prices
and additional excess power available for resale due in large part to
decreased retail sales volume compared to last
year.
|
§
|
The
provision for rate refund, which is a reduction in operating revenues,
decreased by $0.1 million in the first quarter. It is related
to amounts that were included in retail rates in 2007 and January 2008
that were to be refunded to customers. The provision for refund
ended with retail rates effective February 1, 2008 because the new rates
include the customer refund.
|
§
|
Other
operating revenues increased $0.6 million largely due to sales of
additional transmission capacity from our share of Phase I/II transmission
facility rights. We began selling transmission capacity in
April 2007, and we have the ability to restrict the amount of capacity
assigned to the purchasers based on certain conditions. Revenue
from these sales amounted to approximately $1.4 million in calendar year
2007, and is estimated to be approximately $1.8 million annually from 2008
through 2010.
|
Operating
Expenses
Operating expenses increased $4.2 million in the first
quarter of 2008 compared to the same period in 2007. Significant
variances in operating expenses on the Condensed Consolidated Statements of
Income are described below.
Purchased Power
: Purchased
power expense and volume are summarized below.
|
|
Purchases
(in thousands)
|
|
|
mWh
purchases
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
VYNPC
|
|
$
|
15,900
|
|
|
$
|
15,454
|
|
|
|
393,572
|
|
|
|
386,996
|
|
Hydro-Quebec
|
|
|
16,421
|
|
|
|
16,733
|
|
|
|
251,089
|
|
|
|
267,542
|
|
Independent
Power Producers
|
|
|
7,904
|
|
|
|
6,186
|
|
|
|
56,306
|
|
|
|
44,644
|
|
Subtotal
long-term contracts
|
|
|
40,225
|
|
|
|
38,373
|
|
|
|
700,967
|
|
|
|
699,182
|
|
Other
purchases
|
|
|
1,744
|
|
|
|
2,769
|
|
|
|
16,526
|
|
|
|
31,717
|
|
SFAS
No. 5 Loss amortizations
|
|
|
(299
|
)
|
|
|
(299
|
)
|
|
|
-
|
|
|
|
-
|
|
Nuclear
decommissioning
|
|
|
568
|
|
|
|
684
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
668
|
|
|
|
733
|
|
|
|
-
|
|
|
|
-
|
|
Total
purchased power
|
|
$
|
42,906
|
|
|
$
|
42,260
|
|
|
|
717,493
|
|
|
|
730,899
|
|
Purchased
power increased $0.6 million in the first quarter of 2008 compared to the same
period in 2007 as a result of the following:
§
|
Purchases
under long-term contracts increased $1.8 million largely due to increased
output from Independent Power Producers, most of which are hydro
facilities, and increased Vermont Yankee plant output purchased at higher
rates under the long-term contract with VYNPC. These were
partially offset by fewer scheduled deliveries from Hydro-Quebec because
the annual load factor under the contract decreased from 80 percent to 75
percent beginning November 1, 2007.
|
§
|
Other
purchases decreased $1.0 million resulting from lower average market
prices and lower volume due to decreased retail sales volume and fewer
short-term contract purchases.
|
§
|
Nuclear
decommissioning costs are associated with our ownership interests in Maine
Yankee, Connecticut Yankee and Yankee Atomic. Their costs are
based on FERC-approved tariffs. The $0.1 million decrease
resulted from lower revenue requirements for Connecticut
Yankee.
|
§
|
Other
costs include net accounting deferrals and amortizations for Millstone
Unit #3 scheduled refueling outages and deferrals for our share of nuclear
insurance refunds received by VYNPC. These deferrals and
amortizations are based on PSB-approved regulatory
accounting. Amortizations for Millstone Unit #3 scheduled
refueling outages were $0.1 million lower than 2007. Our share
of nuclear insurance refunds from VYNPC amounted to approximately $0.5
million in 2008 and in 2007.
|
Transmission - affiliates:
These expenses represent our share of the net cost of service of Transco and
some direct charges for facilities that we rent. Transco allocates
its monthly cost of service through the Vermont Transmission Agreement ("VTA"),
net of NEPOOL Open Access Transmission Tariff ("NOATT") reimbursements and
certain direct charges. The NOATT is the mechanism through which the
costs of New England's high-voltage transmission facilities are collected from
load-serving entities using the system and redistributed to the owners of the
facilities, including Transco. These expenses increased $1.9 million
due to higher charges under the VTA resulting from Transco's capital
projects.
Other
operation:
These expenses increased $1 million resulting from
the following: 1) a $0.4 million increase in employee-related benefits related
to increased active medical and workers' compensation claims, partly offset by
lower pension costs; 2) a $0.5 million increase in professional service costs
primarily related to consulting support for the implementation of an enterprise
resource planning system; and 3) a $0.1 million increase due to other offsetting
items.
Maintenance:
These
expenses increased $0.7 million principally due to storm restoration costs
resulting from a higher level of storm activity.
Income tax expense (benefit):
Federal and state income taxes fluctuate with the level of pre-tax
earnings in relation to permanent differences, tax credits, tax settlements and
changes in valuation allowances for the periods. The effective
combined federal and state income tax rate was 35.73 percent for the first
quarter of 2008 compared to 37.08 percent for the same period in
2007.
Other Income
Significant
variances in income statement line items that comprise other income on the
Condensed Consolidated Statements of Income are described below.
Equity in earnings of
affiliates:
These earnings increased $2.5 million due to the
return on our $53 million investment that we made in Transco in December
2007.
Other
deductions:
Other deductions increased $0.7 million resulting
from a decline in the cash surrender value of variable life insurance policies
in trust to fund a supplemental employee retirement plan.
Benefit (expense) for income
taxes:
Federal and state income taxes fluctuate with the level
of pre-tax earnings in relation to permanent differences, tax credits, tax
settlements and changes in valuation allowances for the periods.
Interest Expense
Other
interest increased $0.6 million principally due to interest on the $53 million
short-term note.
POWER SUPPLY
MATTERS
Power Supply Risk:
Our
contract for power purchases from VYNPC ends in 2012, but there is a risk that
the plant could be shut down earlier than expected if ENVY determines that it is
not economical to continue operating the plant. Hydro-Quebec contract
deliveries end in 2016, but the average level of deliveries decreases by
approximately 20 percent to 30 percent after 2012, and by approximately 85
percent after 2015. There is a risk that future sources available to
replace these contracts may not be as reliable and the price of such replacement
power could be significantly higher than what we have in place
today. These contracts are described in Note 7 - Commitments and
Contingencies.
ENVY has
submitted a renewal application with the Nuclear Regulatory Commission ("NRC")
for a 20-year extension of the Vermont Yankee plant operating
license. ENVY also needs approval from the PSB and Vermont
Legislature to continue to operate beyond 2012. At this time, ENVY
has not received approvals for the license extension, but we are continuing to
participate in negotiations for a power contract beyond 2012 and cannot predict
the outcome at this time.
An early
shutdown of the Vermont Yankee plant would cause us to lose the economic benefit
of an energy volume equal to close to 50 percent of our total committed supply
and we would have to acquire replacement power resources for approximately 40
percent of our estimated power supply needs. Based on projected
market prices as of March 31, 2008 2007, the incremental replacement cost of
lost power, including capacity, is estimated to average $60 million
annually. We are not able to predict whether this will occur or
whether the PSB would allow timely and full recovery of increased costs related
to any such shutdown. However, an early shutdown could materially
impact our financial position and future results of operations if the costs are
not recovered in retail rates in a timely fashion.
We, other
Vermont electric utilities and HQ-Production are using a steering committee
structure to develop background materials, terms and supporting actions needed
in negotiations for future power purchases from Hydro-Quebec. We
believe there is a high probability that we will have a new contract with
Hydro-Quebec, and we have agreed to target completion of proposed draft terms by
the end of 2008, with a proposed contract for review by the PSB in
2009. We cannot predict whether a contract will ultimately be
approved or, if approved, the quantities of power to be purchased or the price
terms of any purchases.
Power Supply
Management:
Our power supply portfolio includes a mix of base
load and dispatchable resources. These sources are used to serve our
retail electric load requirements plus any wholesale obligations into which we
enter. We manage our power supply portfolio by attempting to optimize
the use of these resources, and through wholesale sales and purchases to create
a balance between our power supplies and load obligations.
Our
current power forecast shows energy purchase and production amounts in excess of
load obligations through 2011. Due to the forecasted excess, we enter
into fixed-price forward sale transactions to reduce price (revenue) volatility
in order to help stabilize our net power costs. Our main supply risk
is with Vermont Yankee, and we have outage insurance through March 2009 to
mitigate the market price risk during an unplanned outage through that
time. We also have a contract in place for the purchase of
replacement power during the scheduled Vermont Yankee plant outage in late
2008.
RECENT ENERGY POLICY
INITIATIVES
Several
laws have been passed since 2005 that impact electric utilities in
Vermont. The major provisions of the new laws that could affect our
business are described in our 2007 Annual Report on Form 10-K. Since that
report, the Vermont Legislature passed two bills related to operations at
Vermont Yankee. S. 269, the “Comprehensive Vertical Audit and Reliability
Assessment of Vermont Yankee Nuclear Power Plant,” establishes protocols for
state review of the plant, is expected to be signed into law. A separate
bill, S. 373, which addresses the funding mechanism for the plant’s future
decommissioning costs, passed the legislature but was vetoed by the
Governor. The Legislature adjourned on May 4, so the Governor’s veto
constitutes final action on S.373.
Item
3. Quantitative
and Qualitative Disclosures About Market
Risk
There
were no material changes from the disclosures in our Annual Report on Form 10-K
for the year ended December 31, 2007. Our derivative financial
instruments include certain power contracts and financial transmission
rights. Summary information related to the fair value of these
derivatives is shown in the table below (dollars in thousands):
|
|
Forward
|
|
|
Forward
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
Purchases
|
|
|
Hydro-Quebec
|
|
|
|
|
|
|
Contracts
|
|
|
Contracts
|
|
|
Sellback
#3
|
|
|
Total
|
|
Total
fair value at December 31, 2007 - unrealized loss
|
|
$
|
(2,037
|
)
|
|
$
|
(481
|
)
|
|
$
|
(4,592
|
)
|
|
$
|
(7,110
|
)
|
Plus
new contracts entered into during the period
|
|
|
8
|
|
|
|
0
|
|
|
|
0
|
|
|
|
8
|
|
Less
amounts settled during the period
|
|
|
597
|
|
|
|
0
|
|
|
|
0
|
|
|
|
597
|
|
Change
in fair value during the period
|
|
|
(5,522
|
)
|
|
|
1,210
|
|
|
|
(609
|
)
|
|
|
(4,921
|
)
|
Total
fair value at March 31, 2008 - unrealized (loss) gain, net
|
|
$
|
(6,954
|
)
|
|
$
|
729
|
|
|
$
|
(5,201
|
)
|
|
$
|
(11,426
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
fair value at March 31, 2008 for changes in projected market
price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
percent increase
|
|
$
|
(9,553
|
)
|
|
$
|
1,379
|
|
|
$
|
(10,150
|
)
|
|
$
|
(18,324
|
)
|
10
percent decrease
|
|
$
|
(4,355
|
)
|
|
$
|
79
|
|
|
$
|
(1,806
|
)
|
|
$
|
(6,082
|
)
|
Item
4. Controls
and Procedures
Evaluation of Disclosure Controls and
Procedures
As of the quarter ended March 31, 2008, our management, with
participation from the Chief Executive Officer and Chief Financial Officer, has
evaluated the effectiveness of our disclosure controls and procedures (as
defined in Rule 13a-15(e) under the Securities Exchange Act of
1934). Based on that evaluation, our Chief Executive Officer and
Chief Financial Officer have concluded that our disclosure controls and
procedures are effective.
Changes in Internal Control over
Financial Reporting
There were no changes in our internal
control over financial reporting during the quarter ended March 31, 2008 that
have materially affected or are reasonably likely to materially affect our
internal control over financial reporting.
PART II - OTHER
INFORMATION
|
Item 1.
Legal
Proceedings.
The Company is involved in legal and administrative proceedings in
the normal course of business and does not believe that the ultimate outcome of
these proceedings will have a material adverse effect on its financial position
or results of operations.
Item 1A.
Risk Factors.
In addition to the other information set forth in this report, you
should carefully consider the factors discussed in Part I "Item 1A. Risk
Factors", in our Annual Report on Form 10-K for the year ended December 31,
2007, which could materially affect our business, financial condition or future
results. The risks described in our Annual Report on Form 10-K are not the only
risks facing our Company. Additional risks and uncertainties not currently
known to us or that we currently deem to be immaterial also may materially
adversely affect our business, financial condition and/or operating
results.
Item 5.
Other
Information.
On May 6,
2008 the Board of Directors adopted changes to the existing Change In Control
(CIC) Agreements to comply with the new statutory rules under Section 409A of
the Internal Revenue Code of 1986, as amended. Section 409A alters
the income tax treatment of compensation that is regarded as deferred under a
nonqualified deferred compensation plans and arrangements. Section
409A also imposes other requirements on such plans and
arrangements.
The
amendment to the existing CIC included the following modifications:
·
|
adding
a 6-month delay of severance payment upon separation from
service,
|
·
|
clarifying
the definition of the non-compete period,
and
|
·
|
clarifying
the Executive and Company's ability to alter the method and/or time of
payment under the Officers' Supplemental Retirement and Deferred
Compensation Plan ("2005 SERP") be inapplicable and without effect for all
purposes.
|
Also on
May 6, 2008, the Board of Directors adopted a new CIC Agreement to become
effective April 2009 which includes changes based on general market trends and
changes in the new statutory rules under Section 409A. These changes
include:
·
|
Elimination
of the automatic renewal feature
|
·
|
Maintenance
of 2.99 severance multiplier for grandfathered officers (Robert
Young, Joseph Kraus, William Deehan, Joan
Gamble)
|
·
|
Increase
of severance multiplier from one to two times for non-grandfathered
(Pamela Keefe, Brian Keefe, Dale Rocheleau) and new
officers
|
·
|
Change
in covered compensation to include only base salary and target annual
incentive versus five-year average of W-2 pay (with exclusion of stock
options exercised within two years of
CIC)
|
·
|
Alignment
of benefit period with severance
multiplier
|
·
|
Limitation
of the continuation of SERP accrual to restoration SERP only (e.g., no
continuation of grandfathered provisions in CIC
agreement)
|
·
|
Elimination
of additional benefit based on qualified Pension Plan applicable to
officers with less than 10 years of service
credit
|
·
|
Addition
of a limited outplacement benefit
|
·
|
Addition
of a confidentiality, non-disparagement and non-solicitation
requirements
|
·
|
Requirement
for a legal release and waiver to receive
payments
|
·
|
Modification
of "good reason" for termination by executive of executive's employment to
include
|
§
|
Reduction
in an executive's annual base salary or value of benefits to any amount
less than 90% of salary or benefits in effect prior to
CIC
|
§
|
Increase
relocation of principal executive offices to more than 75 miles from
location in effect prior to CIC (rather than previous 25
miles)
|
Item 6.
|
Exhibits.
|
|
(a)
List
of Exhibits
|
|
|
A.
10.5.1
|
Form
of Change In Control Agreement as Amended May 6, 2008.
|
|
|
A
10.5.2
|
Form
of Change In Control Agreement to Become Effective April
2009.
|
|
|
31.1
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
31.2
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
32.1
|
Certification
of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
32.2
|
Certification
of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
SIGNATURE
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.
|
|
CENTRAL
VERMONT PUBLIC SERVICE CORPORATION
|
|
(Registrant)
|
By
|
/s/
Pamela J.
Keefe
|
|
Pamela
J. Keefe
Vice
President, Principal Financial Officer, and
Treasurer
|
Dated May
9, 2008
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