SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-Q
| x | QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2000
| | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)
Incorporated in Vermont 03-0111290
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)
802-773-2711
(Registrant's telephone number, including area code)
(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 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, 2000
there were outstanding 11,468,685 shares of Common Stock, $6 Par Value.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q
Table of Contents
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statement of Income and Retained Earnings
for the three months ended March 31, 2000 and 1999 3
Consolidated Balance Sheet as of March 31, 2000 and
December 31, 1999 4
Consolidated Statement of Cash Flows for the three
months ended March 31, 2000 and 1999 5
Notes to Consolidated Financial Statements 6-16
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17-43
PART II. OTHER INFORMATION 44-46
SIGNATURE 47
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<TABLE>
<CAPTION> CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)
Three Months Ended
March 31
2000 1999
<S> <C> <C>
Operating Revenues $99,949 $98,642
------- -------
Operating Expenses
Operation
Purchased power 53,576 50,035
Production and transmission 6,503 5,000
Other operation 10,682 12,039
Maintenance 2,825 2,884
Depreciation 4,283 4,185
Other taxes, principally property taxes 3,025 3,087
Taxes on income 6,491 7,557
------- -------
Total operating expenses 87,385 84,787
------- -------
Operating Income 12,564 13,855
------- -------
Other Income and Deductions
Equity in earnings of affiliates 746 745
Allowance for equity funds during construction 27 10
Other income (expenses), net (3,064) 954
Benefit (provision) for income taxes 1,263 (245)
------- -------
Total other income and deductions, net (1,028) 1,464
------- -------
Total Operating and Other Income 11,536 15,319
------- -------
Interest Expense
Interest on long-term debt 3,565 2,093
Other interest 28 503
Allowance for borrowed funds during construction (16) (7)
------- -------
Total interest expense, net 3,577 2,589
------- -------
Net Income 7,959 12,730
Retained Earnings at Beginning of Period 72,371 67,748
------- -------
80,330 80,478
======= =======
Cash Dividends Declared
Preferred stock 445 465
Common stock - -
------- -------
Total dividends declared 445 465
------- -------
Retained Earnings at End of Period $79,885 $80,013
======= =======
Earnings Available For Common Stock $ 7,514 $12,265
Average Shares of Common Stock Outstanding 11,466,805 11,461,131
Earnings Per Basic and Diluted Share of Common Stock $ .66 $1.07
Dividends Paid Per Share of Common Stock $ .22 $.22
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
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<TABLE>
<CAPTION> CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
March 31 December 31
2000 1999
<S> <C> <C>
Assets
Utility Plant, at original cost $477,044 $475,845
Less accumulated depreciation 177,555 173,605
-------- --------
299,489 302,240
Construction work in progress 12,069 11,315
Nuclear fuel, net 1,037 1,177
-------- --------
Net utility plant 312,595 314,732
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 25,597 25,501
Non-utility investments 45,367 45,269
Non-utility property, less accumulated depreciation 2,406 2,513
-------- --------
Total investments and other assets 73,370 73,283
-------- --------
Current Assets
Cash and cash equivalents 58,351 35,461
Special deposits 114 113
Accounts receivable, less allowance for uncollectible
accounts ($1,686 in 2000 and $1,595 in 1999) 27,723 38,381
Unbilled revenues 12,653 20,605
Materials and supplies, at average cost 3,332 3,126
Prepayments 1,753 1,964
Other current assets 6,341 6,510
-------- --------
Total current assets 110,267 106,160
-------- --------
Regulatory Assets 59,331 62,808
-------- --------
Other Deferred Charges 6,946 6,976
-------- --------
Total Assets $562,509 $563,959
======== ========
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized
19,000,000 shares; outstanding 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,345 45,340
Accumulated other comprehensive income (246) (246)
Treasury stock (319,043 shares, at cost) (4,159) (4,159)
Retained earnings 79,885 72,371
-------- --------
Total common stock equity 191,540 184,021
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 16,000 17,000
Long-term debt 156,105 155,251
Capital lease obligations 14,790 15,060
-------- --------
Total capitalization 386,489 379,386
-------- --------
Current Liabilities
Current portion of long-term debt and preferred stock 17,688 16,688
Accounts payable 5,853 14,843
Accounts payable - affiliates 10,479 12,311
Accrued income taxes 7,582 675
Dividends declared - 2,523
Nuclear decommissioning costs 3,024 3,457
Disallowed purchased power costs 2,859 2,859
Other current liabilities 18,520 18,823
-------- --------
Total current liabilities 66,005 72,179
-------- --------
Deferred Credits
Deferred income taxes 46,812 48,631
Deferred investment tax credits 6,342 6,440
Nuclear decommissioning costs 18,000 18,548
Other deferred credits 38,861 38,775
-------- --------
Total deferred credits 110,015 112,394
-------- --------
Total Capitalization and Liabilities $562,509 $563,959
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
</TABLE>
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<TABLE>
<CAPTION>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Three Months Ended
March 31
2000 1999
<S> <C> <C>
Cash Flows Provided (Used) By
Operating Activities
Net income $ 7,959 $12,730
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (746) (745)
Dividends received from affiliates 1,207 928
Equity in earnings of non-utility investments 2,668 (1,372)
Distribution of earnings from non-utility
investments 828 815
Depreciation 4,283 4,185
Deferred income taxes and investment tax credits (1,916) 412
Allowance for equity funds during construction (27) (10)
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs 1,552 2,185
Amortization of conservation and load management
costs 1,305 1,314
Amortization of capital leases 272 270
Decrease in accounts receivable and unbilled
revenues 17,847 4,235
Decrease in accounts payable (9,994) (6,130)
Increase in accrued income taxes 6,907 4,999
Change in other working capital items 311 5,289
Other, net (71) (669)
------- -------
Net cash provided by operating activities 32,385 28,436
------- -------
Investing Activities
Construction and plant expenditures (3,264) (3,283)
Conservation & load management expenditures (405) (496)
Return of capital 47 47
Non-utility investments (3,508) (1,250)
Other investments, net 20 (4)
------- -------
Net cash used for investing activities (7,110) (4,986)
------- -------
Financing Activities
Long-term debt, net 855 (6)
Common and preferred dividends paid (2,968) (2,522)
Reduction in capital lease obligations (272) (270)
------- -------
Net cash used for financing activities (2,385) (2,798)
------- -------
Net Increase in Cash and Cash Equivalents 22,890 20,652
Cash and Cash Equivalents at Beginning of Period 35,461 10,051
------- -------
Cash and Cash Equivalents at End of Period $58,351 $30,703
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 3,199 $ 778
Income taxes (net of refunds) $ 236 $ 2,390
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2000
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note
1 of Notes to Consolidated Financial Statements included in its 1999
Annual Report on Form 10-K filed with the Securities and Exchange
Commission. For interim reporting purposes, the Company follows these
same basic accounting policies but considers each interim period as an
integral part of an annual period.
The financial information included herein is unaudited; however,
such information reflects all adjustments (consisting of normal
recurring accruals) which are, in the opinion of management, necessary
for a fair statement of results for the interim periods.
Note 2 - Environmental
The Company is engaged in various operations and activities which
subject it to inspection and supervision by both federal and state
regulatory authorities including the United States Environmental
Protection Agency ("EPA"). It is Company policy to comply with all
environmental laws. The Company has implemented various procedures and
internal controls to assess and assure compliance. If non-compliance is
discovered, corrective action is taken. Based on these efforts and the
oversight of those regulatory agencies having jurisdiction, the Company
believes it is in compliance, in all material respects, with all
pertinent environmental laws and regulations.
Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture
of a pole mounted transformer, or a broken hydraulic line. Whenever the
Company learns of such a release, the Company responds in a timely
fashion and in a manner that complies with all federal and state
requirements. Except as discussed in the following paragraphs, the
Company is not aware of any instances where it has caused, permitted or
suffered a release or spill on or about its properties or otherwise
which is likely to result in any material environmental liabilities to
the Company.
The Company is an amalgamation of more than 100 predecessor
companies. Those companies engaged in various operations and activities
prior to being merged into the Company. At least two of these companies
were involved in the production of gas from coal to sell and distribute
to retail customers at three different locations. These activities were
discontinued by the Company in the late 1940's or early 1950's. The
coal gas manufacturers, other predecessor companies, and the Company
itself may have engaged in waste disposal activities which, while legal
and consistent with commercially accepted practices at the time, may not
meet modern standards and thus represent potential liability.
The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these historic
activities. The Company's policy is to accrue a liability for those
sites where costs for remediation, monitoring and other future
activities are probable and can be reasonably estimated. As part of
that process, the Company also researches the possibility of insurance
coverage that could defray any such remediation expenses.
Cleveland Avenue Property The Company's Cleveland Avenue property,
located in the City of Rutland, Vermont, was a site where one of its
predecessors operated a coal-gasification facility and later the Company
sited various operations functions. Due to the presence of coal tar
deposits and Polychlorinated Biphenyl ("PCB") contamination and
uncertainties as to potential off-site migration of those contaminants,
the Company conducted studies in the late 1980's and early 1990's to
determine the magnitude and extent of the contamination. After
completing its preliminary investigation, the Company engaged a
consultant to assist in evaluating clean-up methodologies and provide
cost estimates. Those studies indicated the cost to remediate the site
would be approximately $5.0 million. This was charged to expense in the
fourth quarter of 1992. Site investigation has continued over the last
several years and the Company continues to work with the State in a
joint effort to develop a mutually acceptable solution.
Brattleboro Manufactured Gas Facility From the early to late 1940's,
the Company owned and operated a manufactured gas facility in
Brattleboro, Vermont. The Company recently received a letter from the
State of New Hampshire asking the Company to conduct a scoping study in
and around the site of the former facility. The Company has engaged a
qualified consultant to do the scoping study and a search for other
Potential Responsible Parties. At this time the Company has not
finalized an estimate of its potential liability at this site.
Dover, New Hampshire Manufactured Gas Facility The Company was recently
contacted by Public Service Company of New Hampshire ("PSNH") with
respect to this site. PSNH alleges the Company is partially liable for
remediation of this site. PSNH's allegation is premised on the fact
that prior to PSNH's purchase of the facility, it was operated by Twin
State Gas and Electric ("Twin State"). Twin State merged with the
Company on the same day the facility was sold to PSNH. The Company is
researching the underlying transactions in an effort to determine the
nature and extent of any liability it may have. At this time the
Company has not finalized an estimate of its potential liability at this
site.
The Company is not subject to any pending or threatened litigation
with respect to any other sites that have the potential for causing the
Company to incur material remediation expenses, nor has the EPA or other
federal or state agency sought contribution from the Company for the
study or remediation of any such sites.
As of March 31, 2000, a reserve of $9.6 million has been
established representing management's best estimate of the costs to
remediate the sites.
Note 3 - Retail Rates
The Company recognizes that adequate and timely rate relief is
necessary if it is to maintain its financial strength, particularly
since Vermont regulatory rules do not allow for changes in purchased
power and fuel costs to be automatically passed on to consumers through
rate adjustment clauses. The Company intends to continue its practice
of periodically reviewing costs and requesting rate increases when
warranted.
Vermont Retail Rate Proceedings: The Company filed for a 6.6%, or
$15.4 million per annum, general rate increase on September 22, 1997 to
become effective June 6, 1998 to offset increasing costs of providing
service. Approximately $14.3 million or 92.9% of the rate increase
request was to recover scheduled contractual increases in the cost of
power the Company purchases from Hydro-Quebec.
In response to the Company's September 1997 rate increase filing,
the PSB decided to appoint an independent investigator to examine the
Company's decision to buy power from Hydro-Quebec. The Company made a
filing with the PSB stating that the PSB as well as other parties should
be barred from reviewing past decisions because the PSB already examined
the Company's decision to buy power from Hydro-Quebec in a 1994 rate
case in which the Company was penalized for "improvident power supply
management". During February 1998, the DPS filed testimony in
opposition to the Company's retail rate increase request. The DPS
recommended that the PSB instead reduce the Company's then current
retail rates by 2.5% or $5.7 million. The Company sought, and the PSB
granted, permission to stay this rate case and to file an interlocutory
appeal of the PSB's denial of the Company's motion to preclude a
re-examination of the Company's Hydro-Quebec contract in 1991. The
Company has argued its position before the Vermont Supreme Court
("VSC"). The VSC has not yet rendered a decision and it is uncertain at
this time when a decision is forthcoming.
The Company filed on June 12, 1998 with the PSB for a 10.7% retail
rate increase that supplanted the September 22, 1997, 6.6% rate increase
request, to be effective March 1, 1999. On October 27, 1998, the Company
reached an agreement with the DPS regarding the June 1998 retail rate
increase request providing for a temporary rate increase in the
Company's Vermont retail rates of 4.7% or $10.9 million on an annualized
basis beginning with service rendered on or after January 1, 1999. The
agreement was approved by the PSB on December 11, 1998.
The 4.7% rate increase is subject to retroactive or prospective
adjustment upon future resolution of issues arising under the
Hydro-Quebec and Vermont Joint Owners ("VJO") Power Contract presently
before the VSC. The agreement temporarily disallows approximately $7.4
million (based on 1999 power costs)for the Company's purchased power
costs under the VJO Power Contract pending resolution of the issues
before the VSC. As a result of the 4.7% rate increase agreement, during
the fourth quarters of 1998 and 1999, the Company recorded
pre-tax losses of $7.4 million, and $2.9 million, respectively, for
disallowed purchased power costs, representing the Company's estimated
under recovery of power costs, prior to further resolution, under the
VJO Power Contract for 1999 and the first quarter of 2000, respectively.
In the first quarter of 2000, an additional $2.9 million pre-tax loss
was recorded for the estimated under recovery of Hydro-Quebec power
costs for the second quarter of 2000. If in the future, the Company is
unable to increase rates to recover the temporary disallowed purchased
power costs prior to further resolution under the VJO power contract or
otherwise mitigate these costs, the Company would be required to record
losses for any estimated future under recovery.
These temporary disallowances were calculated using comparable
methodology to that used by the PSB in the GMP, rate case on February
28, 1998. In that case, the PSB found GMP's decision to commit to the
VJO Power Contract in 1991 "imprudent" and that power purchased under it
was not "used and useful." As a result, the PSB concluded that a portion
of GMP's current costs should not be imposed on GMP's customers and were
disallowed. GMP is appealing that rate order to the VSC. Should the
Company receive a similar order from the PSB, the Company would
experience a material adverse effect on its results of operations and
financial condition.
If the Company receives an unfavorable ruling from the VSC and the
PSB subsequently issues a final rate order adopting the disallowance
methodology used to determine the temporary Hydro-Quebec disallowance
described above for the duration of the VJO Power Contract, the Company
would not be able to recover approximately $198.2 million of power costs
over the life of the contract, including $11.5 million in 2000, $11.6
million in 2001, $11.8 million in 2002, $11.9 in million 2003 and $12.1
million in 2004. In such an event, the Company would be required to take
an immediate charge to earnings of approximately $198.2 million
(pre-tax). Such an outcome could jeopardize the Company's ability to
continue as a going concern. However, at this time, the Company does
not believe that such a loss is probable.
On April 13, 2000, the Company and the Vermont Department of Public
Service ("DPS") filed a stipulated agreement with the Vermont Public
Service Board ("PSB") to end winter-summer rate differentials for the
Company's Vermont customers. If approved by the PSB, the Company will
have flat rates throughout a given year. Winter rates will be reduced
by 14.9%, while summer rates will increase 10.5%. The impact on
individual customers will depend on each customer's usage patterns. The
change would be revenue neutral over a 12-month period. If approved by
the PSB, the rates will be effective July 1, 2000. The additional 2000
revenues, resulting from implementing this change in mid-year, will be
applied to reduce or eliminate certain regulatory deferrals.
New Hampshire Retail Rate/Federal Court Proceedings: Connecticut
Valley's, retail rate tariffs, approved by the NHPUC, contain a Fuel
Adjustment Clause ("FAC"), and a Purchased Power Cost Adjustment
("PPCA"). Under these clauses, Connecticut Valley recovers its
estimated annual costs for purchased energy and capacity which are
reconciled when actual data is available.
On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to
Connecticut Valley, found that Connecticut Valley was imprudent for not
terminating the FERC-authorized power contract between Connecticut
Valley and the Company, required Connecticut Valley to give notice to
cancel its contract with the Company and denied stranded cost recovery
related to this power contract. Connecticut Valley filed for rehearing
of the February 28, 1997 NHPUC Order.
On April 7, 1997, the NHPUC issued an Order addressing certain
threshold procedural matters raised in motions for rehearing and/or
clarification filed by various parties, including Connecticut Valley,
relative to the Final Plan and interim stranded cost orders. The April
7, 1997 Order stayed those aspects of the Final Plan that were the
subject of rehearing or clarification requests and also stayed the
interim stranded cost orders for the various parties, including
Connecticut Valley. As such, those matters pertaining to the power
contract between Connecticut Valley and the Company were stayed. The
suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.
On November 26, 1997, Connecticut Valley filed a request with the
NHPUC to increase FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
resulted from higher forecast energy and capacity charges on power
Connecticut Valley purchases from the Company plus removal of a credit
effective during 1997 to refund over collections from 1996.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and
PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the
Company, notwithstanding the stays of its February 28, 1997 Orders. The
NHPUC Order further directed Connecticut Valley to freeze its current
FAC and PPCA rates (other than short term rates to be paid to certain
Qualifying Facilities) effective January 1, 1998, on a temporary basis,
pending a hearing to determine: 1) the appropriate proxy for a market
price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price;
and 3) whether the NHPUC's final determination on the FAC and PPCA rates
should be reconciled back to January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with
the Court for a temporary restraining order to maintain the status quo
ante by staying the NHPUC Order of December 31, 1997 and preventing the
NHPUC from taking any action that (i) compromises cost-based rate making
for Connecticut Valley; (ii) interferes with FERC's exclusive
jurisdiction over the Company's pending application to recover wholesale
stranded costs upon termination of its wholesale power contract with
Connecticut Valley; or (iii) prevents Connecticut Valley from recovering
through retail rates the stranded costs and purchased power costs that
it incurs pursuant to its FERC-authorized wholesale rate schedule with
the Company.
On February 23, 1998, the NHPUC announced in a public meeting that
it reaffirmed its finding of imprudence and designated a proxy market
price for power at 4 cents per kWh in lieu of the actual costs incurred
pursuant to the wholesale power contract with the Company. In addition,
the NHPUC indicated, subject to certain conditions which were
unacceptable to the companies, that it would permit Connecticut Valley
to maintain its current rates pending a decision in Connecticut Valley's
appeal of the NHPUC Order to the New Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut
Valley no longer qualified, as of December 31, 1997, for the application
of Statement of Financial Accounting Standards, or SFAS, No. 71. As a
result, Connecticut Valley wrote-off all of its regulatory assets
associated with its New Hampshire retail business as of December 31,
1997. This write-off amounted to approximately $1.2 million on a
pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million
pre-tax loss in 1997 for disallowed power costs.
On March 20, 1998, the NHPUC issued an order which affirmed,
clarified and modified various generic policy statements including the
reaffirmation to establish rates on the basis of a regional average
announced previously in its February 28, 1997 Order. The March 20, 1998
Order also addressed all outstanding motions for rehearings or
clarification relative to the policies or legal positions articulated in
the Final Plan and removed the stay covering the Company's interim
stranded cost order of April 7, 1997. In addition, the March 20, 1998
Order imposed various compliance filing requirements.
On April 3, 1998, the Court held a hearing on the Companies' motion
for a TRO and Preliminary Injunction against the NHPUC at which time
both the companies and the NHPUC presented arguments. In an oral ruling
from the bench, and in a written order issued on April 9, 1998, the
Court concluded that the companies had established each of the
prerequisites for preliminary injunctive relief and directed and
required the NHPUC to allow Connecticut Valley to recover through retail
rates all costs for wholesale power requirements service that
Connecticut Valley purchases from the Company pursuant to its
FERC-authorized wholesale rate schedule effective January 1, 1998 until
further court order. Connecticut Valley received an order from the
NHPUC authorizing retail rates to recover such costs beginning in May
1998. On April 14, 1998, the NHPUC filed a notice of appeal and a
motion for a stay of the Court's preliminary injunction. The NHPUC's
request for a stay was denied. At the same time, the NHPUC permitted
Connecticut Valley to recover in rates the full cost of its wholesale
power purchases from the Company.
Also, on April 3, 1998, the Court indicated its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley
and prohibits the enforcement of the restructuring orders until the
Court conducts a consolidated hearing and rules on the requests for
permanent injunctive relief by plaintiff PSNH and the other utilities
that had been allowed to intervene in these proceedings, including the
Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the
NHPUC to implement restructuring and to make clear that the stay
encompasses the NHPUC's order of March 20, 1998.
As a result of these Court orders, Connecticut Valley's 1997
charges, described above, were reversed in the first quarter of 1998.
Combined, the reversal of these charges increased 1998 net income and
earnings per share of common stock by approximately $4.5 million and
$.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire ("Bank") notified
Connecticut Valley that it was in default of the Loan Agreement between
the Bank and Connecticut Valley dated December 27, 1994 and that the
Bank would exercise all of its remedies from and after May 5, 1998 in
the event that the violations were not cured. After reversing the 1997
write-offs described above, Connecticut Valley was in compliance with
the financial covenants associated with its $3.75 million loan with the
Bank. As a result, Connecticut Valley satisfied the Bank's requirements
for curing the violation.
On May 11, 1998 the NHPUC issued an order requiring Connecticut
Valley to show cause why it should not be held in contempt for its
failure to meet the compliance filing requirements of its March 20, 1998
Order. A hearing on this matter was scheduled for June 11, 1998, which
was subsequently canceled because of the Court's June 5, 1998 Order,
discussed below.
On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order
clearly stated that no restructuring effort in New Hampshire can move
forward without the Court's approval unless all New Hampshire utilities
agree to the plan. The Order suspended all involuntary restructuring
efforts for all New Hampshire utilities until a hearing on the merits
was conducted. The NHPUC appealed this Order to the Court of Appeals.
On July 23, 1998, the NHPUC issued an order vacating that portion
of its February 27, 1997 restructuring order that had directed
Connecticut Valley to terminate its RS-2 wholesale power purchases from
the Company. The NHPUC has expressly stated in federal court filings
that its July 23, 1998 order "clarified that Connecticut Valley should
not terminate the RS-2 Rate Schedule if such termination would trigger
the exit fee" for which the Company has sought authorization from FERC.
On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to implement
the proposed FAC and PPCA rates, on a temporary basis, effective on all
bills rendered on or after January 1, 1999. In addition, the NHPUC also
ordered Connecticut Valley to pay refunds plus interest to its retail
customers for any overcharges collected as a result of the April 9, 1998
Federal District Court Order, should it be overturned or modified, which
are included in the estimated total losses of $4.3 million discussed
below.
On December 3, 1998, the Court of Appeals announced its decisions
on the appeals taken by the NHPUC from the preliminary injunctions
issued by the Court. Those preliminary injunctions had stayed
implementation of the NHPUC's plan to restructure the New Hampshire
electric industry and required the NHPUC to allow Connecticut Valley to
recover through its retail rates the full cost of wholesale power
obtained from the Company.
The Court of Appeals affirmed the preliminary injunction, issued by
the Court, staying restructuring until the plaintiff utilities' claims
(including those of the Company and Connecticut Valley) are fully tried.
The Court of Appeals found that PSNH had sufficiently established that
without the preliminary injunction against restructuring it would suffer
substantial irreparable injury and that it had sufficient claims against
restructuring to warrant a full trial. The Court of Appeals also
affirmed the extension of the preliminary injunction to protect the
other plaintiff utilities, including Connecticut Valley and the Company,
although it questioned whether the other utilities had arguments as
strong against restructuring as PSNH because they did not have formal
agreements with the State similar to PSNH's Rate Agreement. The Court
of Appeals stated that if the Court awards the utilities permanent
injunctive relief against restructuring after the case is tried, then it
must explain why the other utilities are also entitled to such relief.
The NHPUC filed a petition for rehearing on December 17, 1998. The
Court of Appeals denied the petition on January 13, 1999.
The Court of Appeals also reversed the Court's preliminary
injunction requiring the NHPUC to allow Connecticut Valley to recover in
retail rates the full cost of the power it buys from the Company.
Although the Court of Appeals found that Connecticut Valley and the
Company had made a strong showing of irreparable injury to justify the
preliminary injunction, it concluded that Connecticut Valley's and the
Company's claims did not have a sufficient probability of success to
warrant such preliminary relief. The Court of Appeals explained that
the filed-rate doctrine preserving the exclusive jurisdiction of the
FERC over wholesale power rates did not prevent the NHPUC from deciding
whether Connecticut Valley's power purchases from the Company were
prudent given alternative available sources of wholesale power. The
Court of Appeals then stated that Connecticut Valley's rates could be
reduced to the level prevailing on December 31, 1997. However, the
Court of Appeals also stated that if the NHPUC ordered Connecticut
Valley's rates to be reduced below the level existing as of December 31,
1997, "it will be time enough to consider whether they are precluded
from the Court's injunction against the Final Plan or on other grounds."
On December 17, 1998, Connecticut Valley and the Company filed a
petition for rehearing on the grounds that the Court of Appeals had not
given sufficient weight to the Court's factual findings and that the
Court of Appeals had misapprehended both factual and legal issues.
Connecticut Valley and the Company also asked that the entire Court of
Appeals, rather than only the three-judge appellate panel that had
issued the December 3 decision, consider their petition for rehearing.
On January 13, 1999, the Court of Appeals denied the petition for
rehearing.
Connecticut Valley and the Company then requested the Court of
Appeals to stay the issuance of its mandate until the companies could
file a petition of certiorari to the United States Supreme Court and the
Supreme Court acted on the petition.
On January 22, 1999, the Court of Appeals denied the request.
However, the Court of Appeals granted a 21-day stay to enable the
Company to seek a stay pending certiorari from the Circuit Justice of
the Supreme Court. On February 11, 1999, the Company and Connecticut
Valley filed a petition for a writ of certiorari with the United States
Supreme Court and a motion to stay the effect of the Court of Appeals'
decision while the case was pending in the Supreme Court. The motion
for a stay was addressed to Justice Souter who is responsible for such
motions pertaining to the Court of Appeals for the First Circuit. On
February 18, 1999, Justice Souter denied the stay pending the petition
for certiorari. On April 19, 1999 the Supreme Court denied the petition
for certiorari.
As a result of the December 3, 1998 Court of Appeals' decision
discussed above, on March 22, 1999, the NHPUC issued an Order which
directed Connecticut Valley to file within five business days its
calculation of the difference between the total FAC and PPCA revenues
that it would have collected had the 1997 FAC and PPCA rate levels been
in effect the entire year. In its Order, the NHPUC also directed
Connecticut Valley to calculate a rate reduction to be applied to all
billings for the period April 1, 1999 through December 31, 1999 to
refund the 1998 over collection relative to the 1997 rate level. The
Company estimated this amount to be approximately $2.7 million on a
pre-tax basis. Connecticut Valley filed the required tariff page with
the NHPUC, under protest and with reservation of all rights, on March
26, 1999 and implemented the refund effective April 1, 1999.
As a result of legal and regulatory actions discussed above,
Connecticut Valley no longer qualified as of December 31, 1998 for the
application of SFAS No. 71, and wrote-off in the fourth quarter of 1998
all its regulatory assets associated with its New Hampshire retail
business estimated at approximately $1.3 million on a pre-tax basis at
December 31, 1998. In addition, Connecticut Valley recorded estimated
total losses of $4.3 million pre-tax during the fourth quarter of 1998
for disallowed power costs of $1.6 million and its refund obligations of
$2.7 million.
The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants, which if not waived or renegotiated,
would have allowed Connecticut Valley's lender the right to accelerate
the repayment of a $3.75 million loan with Connecticut Valley. On March
12, 1999, Connecticut Valley was notified by the Bank that it would
exercise appropriate remedies in connection with the violation of
financial covenants associated with the $3.75 million loan agreement
unless the violation was cured by April 11, 1999. To avoid default of
this loan agreement, on April 6, 1999, pursuant to an agreement reached
on March 26, 1999, the Company purchased from the Bank the $3.75 million
note.
On April 7, 1999, the Court ruled from the bench that the March 22,
1999 NHPUC Order requiring Connecticut Valley to provide a refund to its
retail customers was illegal and beyond the NHPUC's authority. The
Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates
below rates in effect at December 31, 1997. Accordingly, Connecticut
Valley removed the rate refund from retail rates effective April 16,
1999. Lastly, the Court denied the NHPUC's motion to dissolve the
injunction staying the implementation of its restructuring plan and
stated its desire to rule on the pending motion for summary judgement
and to conduct a hearing on the Company's request for a permanent
injunction, after the NHPUC completes hearings on PSNH's stranded costs.
The District Court's decision was issued as a written order on May 11,
1999.
The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation, effective with bills issued on and after June 1, 1999.
On May 24, 1999, the NHPUC filed a petition for mandamus in the
Court of Appeals challenging the Court's May 11, 1999 ruling and seeking
a decision allowing the refunds as required by the NHPUC's March 22,
1999 order. The Court of Appeals denied that petition on June 2, 1999.
The NHPUC immediately filed a notice of appeal in the Court of Appeals
again challenging the Court's May 11, 1999 ruling. In that appeal, the
Company and Connecticut Valley contend, among other things, that it is
unfair for the NHPUC to direct Connecticut Valley to continue to
purchase wholesale power under RS-2 in order to avoid the triggering of
a FERC exit fee, but at the same time to freeze Connecticut Valley's
rates at their December 31, 1997 level which does not enable Connecticut
Valley to recover all of its RS-2 costs.
On June 14, 1999, PSNH and various parties in New Hampshire
announced that a "Memorandum of Understanding" had been reached that is
intended to result in a detailed settlement proposal to the NHPUC that
would resolve PSNH's claims against the NHPUC's restructuring plan. On
July 6, 1999, PSNH petitioned the Court to stay its proceedings
indefinitely while the proposed settlement is reviewed and approved by
the NHPUC and the New Hampshire Legislature. On July 12, 1999, the
Company and Connecticut Valley objected to any stay that would allow the
NHPUC's rate freeze order to remain in effect for an extended period and
asked the Court to proceed with prompt hearings on its summary judgement
motion and trial on the merits. On October 20, 1999 the Court heard oral
arguments pertaining to the pretrial motions of the Company and the
NHPUC for summary judgement and dismissal, respectively.
On December 1, 1999, Connecticut Valley filed with the NHPUC a
petition for a change in its FAC and PPCA rates effective on bills
rendered on and after January 1, 2000. On December 30, 1999, the NHPUC
denied Connecticut Valley's request to increase its FAC and PPCA rates
above those in effect at December 31, 1997 subject to further
investigation and reconciliation until otherwise ordered by the NHPUC.
Accordingly, during the fourth quarter of 1999 Connecticut Valley
recorded a pre-tax loss of $1.2 million for under collection of year
2000 power costs.
The Court of Appeals issued a decision on January 24, 2000, which
upheld the Court's preliminary injunction enjoining the Commission's
restructuring plan. The decision also remanded the refund issue to the
Court stating:
"the district court may defer vacation of this injunction
against the refund order for up to 90 days. If within that
period it has decided the merits of the request for a
permanent injunction in a way inconsistent with refunds, or
has taken any other action that provides a showing that the
Company is likely to prevail on the merits in federal court in
barring the refunds, it may enter a superseding injunction
against the refund order, which the Commission may then appeal
to us. Otherwise, no later than the end of the 90-day period,
the district court must vacate its present injunction insofar
as it enjoins the Commission's refund order."
On March 6, 2000 the Court granted summary judgment to Connecticut
Valley and the Company on their claim under the filed-rate doctrine and
issued a permanent injunction mandating that the NHPUC allow Connecticut
Valley to pass through to its retail customers its wholesale costs
incurred under the RS-2 rate schedule with the Company. The Court also
ruled that Connecticut Valley is entitled to recover those wholesale
costs that the NHPUC has disallowed in retail rates since January 1,
1997. This decision is subject to implementation by the NHPUC and has
been appealed by the NHPUC to the Court of Appeals. The NHPUC also
requested the Court of Appeals to stay the Court's order pending the
Court's review on appeal. In response, Connecticut Valley offered to
place the additional revenues in escrow pending the outcome of appeal.
The Court of Appeals denied the NHPUC's request for a stay so long as
the incremental revenues were placed in escrow. The appeal is fully
briefed and was argued before the Court of Appeals on May 8, 2000. The
Company expects a decision on the appeal within 90 days.
Pursuant to the March 6, 2000 Court's Order, on March 17, 2000
Connecticut Valley filed a rate request with the NHPUC for an Interim
FAC/PPCA to recover the balance of wholesale costs not recovered since
January 1997. To mitigate the rate increase percentage, the Interim
FAC/PPCA were designed to recover current power costs and a substantial
portion of past under collections by the end of 2000; the remainder of
the past under collections will be collected during 2001 along with 2001
power costs. The NHPUC held a hearing on April 7, 2000 to review the
12.3% increase that would raise $1.6 million of revenues in 2000. The
NHPUC issued an order approving the rates effective May 1, 2000.
Federal Energy Regulatory Commission ("FERC") Proceedings: The Company
filed an application with the FERC in June 1997, to recover stranded
costs in connection with its wholesale rate schedule with Connecticut
Valley and a notice of cancellation of the Connecticut Valley rate
schedule (contingent upon the recovery of the stranded costs that would
result from the cancellation of this rate schedule). In December 1997,
the FERC rejected the Company's proposal to recover stranded costs
through the imposition of a surcharge on our transmission tariff, but
indicated that it would consider an exit fee mechanism for collecting
stranded costs. The FERC denied the Company's motion for a rehearing
regarding the surcharge proposal, so the Company filed a request with
the FERC for an exit fee mechanism to collect the stranded costs
resulting from the cancellation of the contract with Connecticut Valley.
The stranded cost obligation sought to be recovered through an exit fee,
expressed on a net present value basis as of January 1, 2000, is
approximately $44.9 million. On September 14 and 15, 1998 the Company
participated in a settlement conference with an Administrative Law Judge
assigned for the settlement process at the FERC and the parties to the
Company's exit fee filing. During April and May 1999, nine days of
hearings were held at the FERC before an Administrative Law Judge, who
will determine, among other things, whether Connecticut Valley qualifies
for an exit fee, and if so, the amount of Connecticut Valley's stranded
cost obligation to be paid to the Company as an exit fee. The ruling of
the Administrative Law Judge could be issued at any time. Thereafter
the FERC will act on the judge's recommendations.
If the Company is unable to obtain an order authorizing the
recovery of costs in connection with the June 1997 FERC filing or in the
Federal Court, it is possible that the Company would be required to
recognize a pre-tax loss under this contract totaling approximately
$56.3 million as of December 31, 1999. The Company would also be
required to write-off approximately $3.0 million (pre-tax) in regulatory
assets associated with its wholesale business as of December 31, 1999.
However, even if the Company obtains a FERC order authorizing the
updated requested exit fee, if Connecticut Valley is unable to recover
its costs by increasing its rates, Connecticut Valley would be required
to recognize a loss under this contract of approximately $44.9 million
(pre-tax) representing future under recovery of power costs as of
December 31, 1999.
In addition to its efforts before the Court and FERC, Connecticut
Valley has initiated efforts and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding
and the NHPUC. On September 14 and 15, 1998 the Company participated in
a settlement conference with an Administrative Law Judge assigned for
the settlement process at the FERC and the parties to the Company's exit
fee filing.
An adverse resolution of these proceedings would have a material
adverse effect on the Company's results of operations and cash flows.
However, the Company cannot predict the ultimate outcome of this matter.
Note 4 - Segment Reporting
Operating segments are defined as components of an enterprise about
which separate financial information is available that is evaluated
regularly by the chief operating decision maker, or decision making
group, in deciding how to allocate resources and in assessing
performance. The Company's chief operating decision making group is the
Board of Directors, which is comprised of nine Directors including the
Chairman of the Board and the Company's President and Chief Executive
Officer. The operating segments are managed separately because each
operating segment represents a different retail rate jurisdiction or
offers different products or services.
The Company's reportable operating segments include Central Vermont
Public Service Corporation ("CV") which engages in the purchase,
production, transmission, distribution and sale of electricity in
Vermont; Connecticut Valley Electric Company Inc. ("CVEC") which
distributes and sells electricity in parts of New Hampshire; Catamount
which invests in non-regulated, energy-supply projects and SmartEnergy
which pursues retail alliances to market energy and related products and
services, engages in the sale of or rental of electric water heaters and
has a 37.5% ownership interest in The Home Service Store, Inc. ("HSS").
CVEC, while managed on an integrated basis with CV, is presented
separately because of its separate and distinct regulatory jurisdiction.
Other operating segments include a segment below the quantitative
threshold for separate disclosure. This operating segment is C. V.
Realty, Inc., a real estate company whose purpose is to own, acquire,
buy, sell and lease certain real and personal property and interests
therein related to the utility business. Segment information for the
first quarter of 1999 has been restated to separately present
SmartEnergy which became a reportable segment during the fourth quarter
of 1999.
The accounting policies of the operating segments are the same as
those described in Note 1 to Consolidated Financial Statements included
in its 1999 Annual Report on Form 10-K filed with the Securities and
Exchange Commission. Intersegment revenues include sales of purchased
power to Connecticut Valley and revenues for support services to
Connecticut Valley, Catamount and SmartEnergy.
These intersegment sales and services for each jurisdiction are
based on actual rates or current costs. The Company evaluates
performance based on stand alone operating segment net income.
<PAGE>
Financial information by industry segment for the three months
ended March 31, 2000 and 1999, is as follows (dollars in thousands):
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
Reclassifications
CV CVEC & Consolidating
2000 Vermont New Hampshire Catamount SmartEnergy Other(1) Entries Consolidated
---- ------- ------------- --------- ----------- -------- ----------------- ------------
Revenues from external
customers $ 94,938 $ 5,013 $ 99 $ 887 $ 988 $ 99,949
Intersegment revenues 3,135 3,135 -
Net income (loss) 10,383 109 257 (2,792) $ 2 - 7,959
Total assets 504,459 12,405 45,964 6,214 393 6,926 562,509
1999
----
Revenues from external
customers $ 92,259 $ 6,385 $ 129 $ 2,320 2 $ 2,453 $ 98,642
Intersegment revenues 3,323 3,323 -
Net income (loss) 12,211 53 605 (141) 2 - 12,730
Total assets 482,666 12,169 43,861 5,608 355 5,020 539,639
(1) Includes segments below the quantitative threshold for separate disclosure.
</TABLE>
Note 5 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Summarized financial information for Vermont Yankee
Nuclear Power Corporation follows:
<TABLE>
<CAPTION>
Three Months Ended March 31
2000 1999
---- ----
<S> <C> <C>
Operating revenues $40,692 $43,777
Operating income $ 3,883 $ 3,786
Net income $ 1,744 $ 1,656
Company's equity in net income $536 $518
</TABLE>
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
March 31, 2000
Earnings Overview
Net income and earnings per share of common stock for the quarter
ended March 31, 2000 were $8.0 million and $.66 compared to $12.7
million and $1.07 for the corresponding period last year.
Net income and earnings per share of common stock for the 2000
first quarter were affected by lower after-tax income of $2.8 million,
or $.24 per share of common stock, related to the SmartEnergy Service,
Inc. ("SmartEnergy") ownership share in HSS, expenses booked in the
first quarter of 2000 of $1.7 million after-tax, or $.15 per share of
common stock, for expected under recovery of power costs to be incurred
on the Hydro-Quebec ("HQ") power contract during the second quarter of
2000 (no under recovery of HQ power cost was accrued during the first
quarter of 1999), and lower earnings of $.3 million after-tax, or $.03
per share of common stock at Catamount Energy Corporation. Other
factors affecting results for first quarter 2000 are described in
Results of Operations below.
RESULTS OF OPERATIONS
The major elements of the Consolidated Statement of Income are
discussed below.
Operating Revenues and mWh Sales
A summary of mWh sales and operating revenues for the three months
ended March 31, 2000 and 1999 (and the related percentage changes from
1999) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended March 31
---------------------------
Percentage Percentage
mWh Sales Increase Revenues (000's) Increase
2000 1999 (Decrease) 2000 1999 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Retail sales:
Residential 277,353 274,697 1.0 $38,430 $38,693 (.7)
Commercial 230,600 235,320 (2.0) 28,007 30,324 (7.6)
Industrial 125,642 115,181 9.1 11,545 11,276 2.4
Other retail 1,565 1,538 1.8 443 439 .9
--------- --------- ------- -------
Total retail sales 635,160 626,736 1.3 78,425 80,732 (2.9)
--------- --------- ------- -------
Resale sales:
Firm 663 914 (27.5) 38 42 (9.5)
Entitlement 55,590 54,428 2.1 1,956 2,104 (7.0)
Alliance 361,800 223,237 62.1 13,112 6,409 104.6
Other 156,909 264,721 (40.7) 4,499 6,239 (27.9)
--------- --------- ------- -------
Total resale sales 574,962 543,300 5.8 19,605 14,794 32.5
--------- --------- ------- -------
Other revenues - - - 1,919 489 292.4
--------- --------- ------- -------
Total sales 1,210,122 1,170,036 3.4 $99,949 $96,015 4.1
========= ========= ======= =======
</TABLE>
Retail mWh sales for the first quarter of 2000 increased 1.3%
compared to the first quarter of 1999. However, retail revenues
decreased $2.3 million, or 2.9% compared to last year. This retail
revenues variance is attributable to a $.8 million impact of higher mWh
sales in the first quarter of 2000 as compared to the first quarter of
1999 offset by a $3.1 million decrease in price primarily from the
commercial sector.
Effective January 1, 2000 power purchased from Hydro-Quebec is
recorded net of entitlement sales to Hydro-Quebec. The 1999 entitlement
sales included in Resale sales has been restated for comparison
purposes, along with Purchased and Produced Energy (mWh) shown in the
following table.
Alliance resale sales increased 138,563 mWh and related revenues
increased $6.7 million for the first quarter 2000. This increase
results from previously committed activity by the Company through its
alliance with Virginia Power in jointly supplying wholesale power
primarily in the Northeast states. In the third quarter of 1999 the
Company decided to discontinue this alliance.
For the first quarter 2000, other resale sales decreased 107,812
mWh and related revenues decreased $1.7 million. These variances
reflect current market conditions in Vermont and New England and the
greater availability of low cost energy in the region. These sales made
on a short-term basis include sales to NEPOOL and other utilities in New
England.
Other revenues increased for the first quarter of 2000 primarily
due to increased transmission revenues of $.5 million due to a
true-up of 1999, and $.3 million associated with the 1999 provision for
rate refund for Connecticut Valley.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel
costs for the three months ended March 31, 2000 and 1999 are as follows
(dollars in thousands):
<TABLE>
<CAPTION>
2000 1999
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (mW) 460 $22,846 1,084 $22,484
Energy (mWh) 1,154,295 30,731 1,130,559 24,924
------- -------
Total purchased power costs 53,577 47,408
Production fuel (mWh) 115,999 853 115,414 616
------- -------
Total purchased power and
production fuel costs 54,430 48,024
Entitlement and other resale sales (mWh) 574,299 19,567 542,386 14,752
------- -------
Net purchased power and production
fuel costs $34,863 $33,272
======= =======
</TABLE>
Purchased and produced capacity (mW) costs increased $.4 million
for the first quarter of 2000 primarily due to an additional $2.9
million pre-tax loss for the estimated future under recovery of
Hydro-Quebec power costs for the second quarter of 2000. Partially
offsetting this increase is a favorable net price/volume variance of
$1.5 million pre-tax and the positive impact of $1.0 million for
Hydro-Quebec power cost reversals, representing the reversal of a
portion of disallowed Hydro-Quebec power costs accrued during the fourth
quarter of 1998, and 1999.
Purchased and produced energy (mWh) purchases increased $5.8
million for 2000 primarily from a $5.3 million increase in price and a
2.1%, or $.5 million decrease in the amount of mWh purchased.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in the
Millstone Unit #3 ("Unit #3"), an 1149 mW nuclear unit of the Millstone
Nuclear Power Station and owns a 2% equity interest in Connecticut
Yankee. These two plants are operated by Northeast Utilities ("NU").
The Company also owns 2%, 3.5% and 31.3% equity interest in Maine
Yankee, Yankee Atomic and Vermont Yankee, respectively.
Unit #3
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various
activities to monitor and evaluate NU and Northeast Utilities Service
Co.'s efforts relating to Unit #3. On August 7, 1997, the Company and
nine other non-operating owners of Unit #3 filed a demand for
arbitration with Connecticut Light and Power Company and Western
Massachusetts Electric Company, both NU affiliates, and lawsuits against
NU and its trustees. The arbitration and lawsuits seek to recover costs
associated with replacement power, operation and maintenance costs and
other costs resulting from the lengthy outage of Unit #3. The
non-operating owners claim that NU and two of its wholly owned
subsidiaries failed to comply with Nuclear Regulatory Commission's
("NRC") regulations, failed to operate the facility in accordance with
good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
On September 15, 1999, NU announced that it intends to auction its
nuclear generating plants, including Unit #3. We cannot predict at this
time the effect of such an auction, if it occurs, on the Company or on
the ongoing litigation.
Since October, 1999, seven of the non-operating minority joint
owners have settled their claims in the arbitration and lawsuits. The
settlements involve payment of fixed and contingent amounts from NU, and
in some cases, the inclusion of their Unit #3 interests in NU's auction
of the plant. On March 10, 2000, the Company notified the other
non-operating joint owners that the Company was entering settlement
discussions with NU. To date, no settlement has been reached and the
Company cannot predict whether or when a settlement may be reached. The
other two non-operating minority joint owners, and the Company, remain
active in the arbitration and lawsuits and in seeking to settle the
Company's claims against NU.
Maine Yankee
On August 6, 1997, the Maine Yankee's nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Maine Yankee for less than 5% of its required system capacity. Future
payments for the closing, decommissioning and recovery of the remaining
investment in Maine Yankee are estimated to be approximately $715.0
million in 1998 dollars including a decommissioning obligation of $344.0
million.
On January 19, 1999, Maine Yankee and the active intervenors filed
an Offer of Settlement with the FERC which the FERC has approved. As a
result, all issues raised in the FERC proceeding, including recovery of
anticipated future payments for closing, decommissioning and recovery of
the remaining investment in Maine Yankee are resolved. Also resolved are
the issues raised by the secondary purchasers, who purchased Maine
Yankee power through agreements with the original owners, by limiting
the amounts they will pay for decommissioning the Maine Yankee plant and
by settling other points of contention affecting individual secondary
purchasers. As a result, it is possible that the Company will not be
able to recover approximately $.5 million of these costs.
Connecticut Yankee
On December 4, 1996, the Connecticut Yankee Nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Connecticut Yankee for less than 3.0% of its required system capacity.
On August 31, 1998, a FERC Administrative Law Judge recommended
that the owners of Connecticut Yankee, including the Company, may
collect from customers $350.0 million for decommissioning the
Connecticut Yankee Nuclear Power Plant rather than the $426.7 million
requested. The Administrative Law Judge ruling is subject to approval
by the FERC Commissioners. If approved, it is possible that the Company
would not be able to recover approximately $1.5 million of
decommissioning costs through the regulatory process.
Yankee Atomic
In 1992, the Yankee Atomic nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than
1.5% of its system capacity.
Vermont Yankee
During 1996, Vermont Yankee initiated a Design Basis Documentation
project expected to be complete by December 31, 2001. This project was
undertaken to incorporate all design documentation into a centralized
system. The objective is to ensure that Vermont Yankee maintains its
safety margins in connection with any plant modifications. The Design
Basis Documentation project will create a set of design basis documents
which will support more efficient systematic problem solving,
maintenance, and system overview. This effort supports the safe, cost
effective, long term operation of the Vermont Yankee Plant. Vermont
Yankee received FERC approval in 1996 to defer these unrecovered study
costs and amortize the costs through billings to Sponsors over the
remaining license life of the Plant. The Company's 35% share of the
total cost for this Project is expected to be between $5.5 million and
$6.2 million.
On October 15, 1999 the Company and the other owners of Vermont
Yankee accepted a bid for sale of the plant to AmerGen Energy Co.,
which is owned by PECO Energy Company and British Energy. On November
17, 1999, Vermont Yankee executed an Asset Purchase Agreement with
AmerGen Energy Co. The Agreement is subject to several conditions,
including approvals or specific rulings by various regulatory
authorities. As such, execution of the Agreement does not provide
assurance that the sale will occur. This agreement will also involve
the Company entering into a contract to purchase a portion of the power
produced by this plant.
Vermont Yankee estimates that the price to be paid by AmerGen for
the non-transmission assets will range from $10 million to $23.5 million
depending on when the sale occurs. Additionally, Vermont Yankee's
current owners will make a one-time payment of approximately $54.0
million to pre-pay the plant's decommissioning fund and to pay the
Texas, Maine and Vermont Low-Level Waste compact fees. Based on the
expected regulatory treatment of these costs, the Company does not
believe the sale will have a material impact on the financial condition
or operation of the Company.
Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs
Presently, costs billed to the Company by Maine Yankee, Connecticut
Yankee and Yankee Atomic, including a provision for ultimate
decommissioning of the units, are being collected from the Company's
customers through existing retail and wholesale rate tariffs. The
Company's share of remaining costs with respect to Maine Yankee,
Connecticut Yankee and Yankee Atomic's decisions to discontinue
operation is estimated to be $12.5 million, $8.1 million and
$.4 million, respectively, at March 31, 2000. These amounts are subject
to ongoing review and revisions and are reflected in the accompanying
balance sheet both as regulatory assets and nuclear dismantling
liabilities (current and non-current).
The decision to prematurely retire these nuclear power plants was
based on economic analyses of the costs of operating them compared to
the costs of closing them and incurring replacement power costs over the
remaining period of the plants' operating licenses. The Company
believes that based on the current regulatory process, its proportionate
share of Maine Yankee, Connecticut Yankee and Yankee Atomic
decommissioning costs will be recovered through the regulatory process
and, therefore, the ultimate resolution of the premature retirement of
the three plants has not and should not have a material adverse effect
on the Company's earnings or financial condition.
Generating Units
The Company owns and operates 20 hydroelectric generating units and
two gas turbines and one diesel peaking unit with a combined nameplate
capability of 73.7 mW.
The Company is currently in the process of relicensing or preparing
to relicense eight separate hydroelectric projects under the Federal
Power Act. These projects, some of which are grouped together under a
single license, represent approximately 29.9 mW, or about 72.4% of the
Company's total hydroelectric nameplate capacity. In the new licenses,
the FERC is expected to impose conditions designed to address the impact
of the projects on fish and other environmental concerns. The Company
is unable to predict the impact of the imposition of such conditions,
but capital expenditures and operating costs are expected to increase
and net generation from these projects will decrease in future periods.
In addition, the Company maintains joint-ownership interests in
Joseph C. McNeil, a 53 mW wood, gas and oil-fired unit and Wyman #4, a
619 mW oil-fired unit.
Transmission Matters
Vermont Electric Power Company, Inc. ("VELCO") owns and operates
most of the high voltage transmission system in Vermont. The Company
owns 56.8% of the Class B common stock of VELCO and 46.6% of the Class C
preferred stock of VELCO. Approximately 47% of VELCO's costs are borne
by the Company.
On March 22, 2000, the phase angle regulator (PAR), which controls
power flows over the transmission line between Plattsburg, New York, and
Milton, Vermont, suffered a serious failure of insulation in its
windings. Automatic equipment immediately took the line out of service.
Operations were restored within a week, but without the PAR. Repair or
replacement of the PAR, which is owned by the New York Power Authority
(NYPA), will take six months or more. VELCO has requested NYPA to
commence repairs, and has informed NYPA that VELCO will bear the cost of
repair, to the extent that regulatory authorities do not allocate any of
the costs to others.
To compensate for the loss of PAR control, VELCO plans to operate
the affected transmission line during high load periods by employing
inductor coils to provide impedance to restrict flows across the line.
This mode of operation will increase reactive power support requirements
in Vermont. Consequently, VELCO is preparing to install one or more
synchronous condensers or generators near the Vermont terminus of this
line to provide that support. VELCO has filed petitions for all of the
regulatory approvals required to install and operate one unit that will
be operable as either a generator or a synchronous condenser, and it is
continuing studies to determine the need for a second unit. VELCO has
filed petitions with the Vermont Public Service Board for site
preparation, installation and operating authority. Site preparation has
already been authorized. Installation authority, and authority to
operate a synchronous condenser, is expected to be decided upon during
the week of May 8, 2000. VELCO has also filed an application for an air
quality permit with the Vermont Agency of Natural Resources. Authority
to operate in the generation mode depends, and the ability of the Agency
of Natural Resources to act on the air quality permit before June 1,
2000 may depend, on the passage of new statutory authority, which
authority has been approved by the Vermont House of Representatives, and
is pending in the Senate. VELCO believes it likely that it will receive
the necessary approvals in time to allow installation and operation of
at least one unit by June 1, 2000, which is when the need for additional
reactive support may become critical, but it cannot control the timing
or content of regulatory responses. If the approvals are issued, and
VELCO is able to install the facilities described herein, it expects to
be able to provide first contingency coverage for all known events, and
it believes that the transmission system will have at least the level
of reliability it has maintained historically. If approvals are not
received or delayed, or if VELCO is otherwise unable to carry out the
plans referred to above, conditions may arise that will require VELCO to
impose one or more blackouts in the Chittenden County, Vermont area
pending the installation of other system improvements. Although the
Company's service territory includes a portion of Chittenden County, it
is principally served by other utilities.
The cost of the facilities VELCO plans to install will be
substantial (approximately $10.0 million of expenses through April
2001). VELCO is seeking to have such costs spread among all electric
customers in New England. The probability of securing such cost sharing
is uncertain at this time.
VELCO is also in the process of installing a Flexible Alternating
Current Transmission System ("FACTS") device which will, by itself,
provide the reactive support required for the operation of this
Plattsburg, NY to Milton, VT line. The FACTS device is on schedule to
be in service May 1, 2001.
The start-up of the FACTS device will significantly reduce the
current need for the Joseph C. McNeil generating plant to run in support
of area reliability.
Merrimack Unit #2
Until its termination on April 30, 1998, the Company purchased
power and energy from Merrimack #2, pursuant to a contract dated July
16, 1966 entered into by and between VELCO and PSNH. Pursuant to the
contract, as amended, VELCO agreed to reimburse PSNH, in the proportion
which the VELCO quota bears to the demonstrated net capability of the
plant, for all fixed costs of the unit and operating costs of the unit
incurred by PSNH, which are reasonable and cost-effective for the
remaining term of the VELCO contract. In early 1998, PSNH took the
Merrimack Unit #2 facility off line, shut it down and commenced a
maintenance outage. In February, March and April of 1998, PSNH billed
VELCO for costs to complete the maintenance outage. VELCO disputes the
validity of a portion of the charges on grounds that the maintenance
performed at the unit was to extend the life of the Merrimack plant
beyond the term of the VELCO contract and that the charges in connection
with said investments were not reasonable and cost-effective for the
remaining term of the VELCO contract. The Company estimates the portion
of the disputed charges allocable to the Company could be as much as
$.5 million.
Cogeneration/Independent Power Qualifying Facilities ("IPPs")
A number of IPPs using hydroelectric, biomass, and refuse-burning
generation are currently producing energy that the Company is
purchasing. The majority of these purchases are made from a state
appointed purchasing agent who purchases and redistributes the power to
all Vermont utilities.
As part of the Company's initiative to cut power costs and
restructure Vermont's utility industry, on August 3, 1999, the Company,
Green Mountain Power ("GMP"), Citizens Utilities and all of Vermont's 15
municipal utilities, filed a petition with the PSB requesting
modification of the contracts between the IPPs and the state appointed
purchasing agent. The petition is based on unique provisions of the
existing contracts and PSB regulations that provide for modifications
and alterations that serve the public interest. The petition outlines
seven specific elements that, if implemented, would reduce the purchase
power costs of these contracts.
On September 3, 1999, the PSB responded to the Company's petition
by opening a formal investigation regarding these contracts. Shortly
thereafter, Citizens Utilities, Hardwick Electric Department and the
Burlington Electric Department notified the PSB that they were
withdrawing from the petition but they will participate in the case as a
non-moving parties. In a separate VSC action brought by several IPP's
owners, GMP's full participation in this PSB proceeding was enjoined.
That injunction is now on appeal to the VSC. The Company and the other
moving utilities have requested that the PSB issue an order requiring
GMP's full participation in the PSB proceeding. At the same time, the
IPPs have filed a motion seeking to disqualify the law firm representing
the utilities on the grounds of an alleged conflict of interest. The
IPPs have also filed a related proceeding in the Washington County
Superior Court contending that the PSB rules pertaining to IPPs, which
the utilities have relied upon, in part, in their petition before the
PSB contains a so-called "scrivener's error."
Production and Transmission
Primarily as a result of a refund in 1999 related to transmission
billings to Hydro-Quebec in the first quarter of 1999, production and
transmission expenses increased $1.9 million for the first quarter of
2000.
Other Operation
Principally due to lower general and administrative costs, other
operation expenses decreased $1.4 million for the first quarter of 2000
compared to the first quarter of 1999.
Income Taxes
Federal and state income taxes fluctuate with the level of
pre-tax earnings in relation to permanent differences. For the first
quarter of 2000 these taxes decreased as a result of lower
pre-tax earnings.
Other Income and Deductions
Other income and deductions decreased for the first quarter of 2000
primarily due to lower equity income from non-utility subsidiary
companies primarily related to SmartEnergy's ownership share in HSS.
Interest on Long-Term Debt
In July 1999, the Company sold $75.0 million aggregate principal
amount of 8 1/8% Second Mortgage Bonds due 2004. Accordingly, interest
on long-term debt increased for the first quarter of 2000.
Other Interest Expense
Other interest expense decreased for the first quarter 2000
compared to same period last year due to a decrease in average
outstanding short-term debt.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity is primarily affected by the level of cash
generated from operations and the funding requirements of its ongoing
construction and C&LM programs. Net cash flow provided by operating
activities generated $32.4 million and $28.4 million for the three
months ended March 31, 2000 and 1999, respectively.
The Company ended the first three months of 2000 with cash and cash
equivalents of $58.4 million, an increase of $22.9 million from the
beginning of the year. The increase in cash for the first three months
of 2000 was the result of $32.4 million provided by operating
activities, offset by $7.1 million used for investing activities and
$2.4 million used for financing activities.
Operating Activities - Net income, depreciation and deferred income
taxes and investment tax credits provided $10.3 million. About $22.1
million of cash was provided by working capital and other operating
activities.
Investing Activities - Construction and plant expenditures consumed
approximately $3.3 million, while $3.5 million was used for
non-utility investments.
Financing Activities - Dividends paid on common stock were $2.5
million, while preferred stock dividends were $.5 million.
Long-term debt provided $.9 million and reduction in capital lease
obligations required $.3 million.
The level of short-term borrowings fluctuates based on seasonal
corporate needs, the timing of long-term financings and market
conditions.
On July 30, 1999 the Company sold $75.0 million aggregate principal
amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915%.
The net proceeds of the offering were used to repay $15.0 million of
outstanding loans under the Company's revolving credit facility and are
expected to be used for other general corporate purposes relative to the
Company's utility business. In addition, the Company canceled its $40.0
million revolving credit facility.
The Company has an aggregate of $16.9 million of letters of credit
with expiry dates of May 31, 2001.
On February 2, 1999, Standard & Poor's Corporation ("Standard &
Poor's") lowered its corporate credit rating on the Company to
BBB- (triple-'B'-minus) from BBB (triple-'B'), the senior secured rating
to BBB+ (triple-'B'-plus) from A- (single-'A'-minus), and the preferred
stock rating to BB+ (double-'B'-plus) from BBB- (triple-'B'-minus). In
addition, the ratings were also placed on CreditWatch with negative
implications. On February 17, 1999, Standard & Poor's rating on the
Company's preferred stock was automatically reduced to double-'B'- from
double -'B'- plus in response to a policy change in the way Standard &
Poor's rates preferred stock.
On July 16, 1999, Standard & Poor's assigned its
BBB- (triple-'B'- minus) rating to the Company's then proposed $75.0
million second mortgage bonds. Concurrently, the bonds were placed on
CreditWatch with negative implications.
Standard & Poor's said "the second mortgage bonds are rated the
same as the Company's corporate credit rating, and not notched up,
because Standard & Poor's projects that the value of the Company's
collateral will not substantially exceed the maximum combined amount of
first and second mortgage bonds that could be outstanding under the
terms of their respective indentures in a default scenario."
On March 28, 2000 Standard & Poor's reaffirmed that its ratings on
the Company remain on CreditWatch with negative implications, reflecting
the potentially adverse impact of pending legal and regulatory decisions
that could seriously weaken the Company's credit profile.
"Standard & Poor's remains highly concerned about several important
events, which are expected to occur in mid- to late-2000 and could
result in significantly lower ratings. These events include the outcome
of contract renegotiations with key power suppliers, most notably
Hydro-Quebec, the arbitration related to the January 1998 ice storm, and
a Vermont Supreme Court appeal, offset in part by the pending sale of
the Vermont Yankee nuclear plant. Furthermore, if the PSB disallows the
full recovery of power costs associated with the burdensome
Hydro-Quebec contract, the utility may be required to record substantial
write-offs. The outcome of key regulatory decisions will be the
principal rationale for any rating or outlook adjustments.
The Company's ratings reflect a below-average business profile,
coupled with a weak financial profile for the current ratings when
adjusted for off-balance-sheet power and transmission obligations. The
utility's business profile reflects increasingly restrictive regulation,
rising power costs, and nuclear asset exposure. This is tempered only
partially by a diverse service area economy with limited industrial
concentration, regionally competitive rates, and improving operational
efficiency."
Standard & Poor's also said "resolution of the CreditWatch listing
will depend on the Hydro-Quebec renegotiations, the arbitration related
to the January 1998 ice storm the Vermont Supreme Court appeal, and
other state and federal legal proceedings, which could be resolved in
mid- to late-2000. In addition, adequate rate relief and/or successful
mitigation of high power costs through contract renegotiations or other
methods are essential for maintaining ratings".
On February 17, 1999, Duff & Phelps Credit Rating Co.("Duff &
Phelps") placed the credit ratings of the Company on Rating
Watch-Down due to the high level of regulatory and public policy
uncertainty in Vermont and the unfavorable ruling by the United States
Court of Appeals relating to Connecticut Valley, the Company's wholly
owned New Hampshire subsidiary.
On July 16, 1999 Duff & Phelps assigned a rating of
"BBB-" (Triple-B-minus) to the Company's then proposed $75 million issue
of second mortgage bonds and lowered its rating on the Company's
preferred stock to "BB+" (Double-B-plus) from "BBB-" (Triple-B-minus)
with all ratings remaining on Rating Watch- Down.
On April 4, 2000 Duff & Phelps reaffirmed the Company's credit
ratings and has maintained the ratings on Rating Watch-Down. "The watch
status reflects the continued high level of regulatory and public policy
uncertainty in Vermont and the ultimate legal and regulatory outcome
associated with the Company's wholly owned subsidiary, Connecticut
Valley, which adds risk to the Company's financial profile going
forward. Approximately $190 million of debt and preferred securities
are affected."
Duff & Phelps said, "The Company's ratings and watch status
incorporate past negative rulings issued by the PSB regarding purchased
power costs, which have led to financial instability and uncertainty
among electric utilities in Vermont. Consequently, this uncertain
public policy environment has directly impacted CV's overall credit
quality, resulting in lower coverage ratios and reduced financial
flexibility. Positively, CV has taken initiatives to offset the
short-term financial and liquidity constraints of this regulatory
induced situation. CV's recent second mortgage issuance (July 1999)
provides the Company increased financial flexibility to meet its
upcoming mandatory debt and preferred retirements over the next few
years while a resolution to Vermont's above-market purchased power
obligations, stranded cost recovery and ultimately industry
restructuring is attained."
Current credit ratings of the Company's securities by Standard &
Poor's and Duff & Phelps remain as follows:
Standard Duff &
& Poor's(1) Phelps(2)
Corporate Credit Rating BBB- N/A
First Mortgage Bonds BBB+ BBB
Second Mortgage Bonds BBB- BBB-
Preferred Stock BB BB+
(1) All Standard and Poor's ratings are placed on "CreditWatch
with negative implications."
(2) All Duff & Phelps ratings are placed on "Rating
Watch Down."
In 1998, Catamount, replaced its $8.0 million credit facility with
a $25.0 million revolving credit/term loan facility maturing November
2006 which provides for up to $25.0 million in revolving credit loans
and letters of credit of which $6.3 million was outstanding at March 31,
2000. This facility has a security interest in Catamount's assets.
Catamount currently has a $1.2 million letter of credit outstanding to
support certain of its obligations in connection with a debt service
requirement in the Appomattox Cogeneration project. In addition, a
letter of credit for $11.0 million is outstanding in support of
construction and equity commitments for its Gauley River Power project.
SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary
of SmartEnergy, has a secured $1.5 million, seven-year term loan with
Bank of New Hampshire with an outstanding balance of $1.4 million at
March 31, 2000. The interest rate is fixed at 9.50%.
Financial obligations of the Company's subsidiaries are
non-recourse to the Company.
The Company cannot assure that its business will generate
sufficient cash flow from operations or that future borrowings will be
available to the Company in an amount sufficient to enable the Company
to pay its indebtedness, including the $75.0 million second mortgage
bonds, when due or to fund its other liquidity needs. The Company's
ability to repay its indebtedness is, to a certain extent, subject to
general economic, financial, competitive, legislative, regulatory,
weather and other factors that are beyond its control. The type, timing
and terms of future financing that the Company may need will be
dependent upon its cash needs, the availability of refinancing sources
and the prevailing conditions in the financial markets. The Company
cannot guarantee that financing sources will be available to the Company
at any given time or that the terms of such sources will be favorable.
Hydro-Quebec Contract
The Company is purchasing varying amounts of power from
Hydro-Quebec under the VJO contract through 2016. Related contracts
were negotiated between the Company and Hydro-Quebec which in effect
alter the terms and conditions contained in the VJO contract, reducing
the overall power requirements and cost of the original contract.
There are specific contractual step up provisions that provide that
in the event any VJO member fails to meet its obligation under the
contract with Hydro-Quebec, the balance of the VJO participants,
including the Company, will "step up" to the defaulting party's share on
a pro-rata basis. As of December 31, 1999 the Company's VJO projected
cost obligation is approximately 47% or $1.0 billion on a nominal basis
over the term of the contract ending in 2016. The total VJO contract
obligation on a nominal basis over the term of the contract is
approximately $2.1 billion.
During January 1998, a significant ice storm affected parts of New
York, New England and the Province of Quebec, Canada. This storm
damaged major components of the Hydro-Quebec transmission system over
which power is supplied to Vermont under the VJO Power Contract with
Hydro-Quebec. This resulted in a 61-day interruption of a significant
portion of scheduled contractual energy deliveries into Vermont. The
ice storm's effect on Hydro-Quebec's transmission system caused the VJO
to examine Hydro-Quebec's overall reliability and ability to deliver
energy. On the basis of that examination, the VJO determined that
Hydro-Quebec has been and remains unable to make available capacity with
the degree of firmness required by the VJO Power Contract. That
determination has prompted the VJO to initiate an arbitration
proceeding. In the arbitration, the VJO is seeking to terminate the
contract, to recover damages associated with Hydro-Quebec's failure to
comply with the contract, and to recover capacity payments made during
the period of non-delivery.
In September 1999 an initial two weeks of hearings were held
dealing primarily with issues of contract interpretation. The balance
of the hearings will be held in the second and third quarters of 2000.
The Company expects a decision by the end of 2000. In accordance with a
PSB Accounting Order, the Company has deferred incremental costs
associated with this arbitration of approximately $2.6 million through
March 31, 2000. Recovery of these costs will be determined in the next
rate proceedings.
Diversification
Catamount Resources Corporation was formed for the purpose of
holding the Company's subsidiaries that invest in non-regulated business
opportunities. Catamount, a subsidiary of Catamount Resources
Corporation, invests in energy generation projects in North America and
Western Europe. Through its wholly owned subsidiaries, Catamount has
interests in seven operating independent power projects located in
Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont;
Thetford, England; Hopewell, Virginia; and Fort Dunlop, England. In
addition, Catamount has interests in a project under construction in
Summersville, West Virginia. In November 1999 Catamount created a new
subsidiary, Catamount Investment Company LLC, which will provide
additional capital for investment in new generation projects. Catamount
has partnered with CIT Group, a major equipment finance company, and
Dana Commercial Credit Corporation, the finance subsidiary of Dana
Corporation. Capital commitments from these two joint venture partners
are $60.0 million, to be invested over the next four years. Catamount's
after-tax earnings were $.3 million and $.6 million for the first
quarter of 2000 and 1999, respectively.
SmartEnergy also a subsidiary of Catamount Resources Corporation
invests in unregulated energy and service related businesses.
SmartEnergy also has an ownership interest in HSS. Overall, SmartEnergy
incurred net losses of $2.8 million and $.1 million for the first
quarter of 2000 and 1999, respectively. HSS establishes a network of
affiliate contractors who perform home maintenance repair and
improvements via membership. SmartEnergy's investment in HSS is
accounted for using the equity method. HSS began operations in the
first quarter of 1999 and is subject to risks and challenges similar a
company in the early stage of development. HSS' pre-tax loss for the
first quarter of 2000 was $5.0 million, resulting primarily from the
national rollout of HSS, of which SmartEnergy's share was $3.7 million.
HSS began a test rollout through Sam's Club in late spring 1999.
After a successful test market, the national rollout anticipated for
year 2000 was accelerated to begin at the end of 1999. In December 1999
HSS announced that it had developed another marketing relationship with
TruServ Corporation, the cooperative entity for True Value Hardware
Stores. On March 14, 2000, HSS issued 3,500,000 shares of convertible
preferred stock. The proceeds, net of transaction costs, will be used
by HSS to finance the national rollout of HSS. As a result of the sale
of 50% of the ownership in HSS, and losses that have been incurred on
the Company's investment in HSS, the Company expects insignificant
losses during the balance of calendar year 2000. The Company's current
ownership of HSS is 37.5%.
Rates and Regulation
The Company recognizes that adequate and timely rate relief is
necessary if the Company is to maintain its financial strength,
particularly since Vermont regulatory rules do not allow for changes in
purchased power and fuel costs to be automatically passed on to
consumers through rate adjustment clauses. The Company intends to
continue its practice of periodically reviewing costs and requesting
rate increases when warranted.
Vermont
1998 Retail Rate Case: On June 12, 1998, the Company filed with
the PSB for a 10.7% retail rate increase to be effective March 1, 1999.
This rate case proceeding supplanted the 6.6% rate increase request
referenced below that is now stayed pending a review on the so-called
preclusion issue by the VSC. On October 27, 1998, the Company reached
an agreement with the DPS regarding the 10.7% rate increase request.
The agreement, which was approved by the PSB on December 11, 1998,
provides for a temporary rate increase in the Company's Vermont retail
rates of 4.7% or $10.9 million on an annualized basis beginning with
service rendered January 1, 1999 and sets the Company's authorized
return on equity in its Vermont retail business at 11% before
disallowances in connection with the Hydro-Quebec Contract.
The 4.7% rate increase is subject to retroactive or prospective
adjustment upon future resolution of issues arising under the VJO Power
Contract presently before the VSC. The agreement temporarily disallows
approximately $7.4 million for the Company's purchased power costs under
the VJO Power Contract pending resolution of the issues before the VSC.
As a result of the 4.7% rate increase agreement, during the fourth
quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4
million (based on 1999 power costs), and $2.9 million, respectively, for
disallowed purchased power costs, representing the Company's estimated
under recovery of power costs, prior to further resolution, under the
VJO Power Contract for 1999; and the first and second quarters of 2000,
respectively. In the first quarter of 2000, an additional $2.9 million
pre-tax loss was recorded for the estimated under recovery of
Hydro-Quebec power costs for the second quarter of 2000. If in the
future, the Company is unable to increase rates to recover the temporary
disallowed purchased power costs prior to further resolution under the
VJO power contract or otherwise mitigate these costs the Company would
be required to record losses for any estimated future under recovery.
These temporary disallowances were calculated using comparable
methodology to that used by the PSB in the GMP rate case on February 28,
1998. In that case, the PSB found GMP's decision to commit to the VJO
Power Contract in 1991 "imprudent" and that power purchased under it was
not "used and useful." As a result, the PSB concluded that a portion of
GMP's current costs should not be imposed on GMP's customers and were
disallowed. GMP is appealing that rate order to the Vermont Supreme
Court. Should the Company receive a similar order from the PSB, the
Company would experience a material adverse effect on its results of
operations and financial condition.
If the Company receives an unfavorable ruling from the VSC and the
PSB subsequently issues a final rate order adopting the disallowance
methodology used to determine the temporary Hydro-Quebec disallowance
described above for the duration of the VJO Power Contract, the Company
would not be able to recover approximately $198.2 million of power costs
over the life of the contract, including $11.5 million in 2000, $11.6
million in 2001, $11.8 million in 2002, $11.9 in million 2003 and $12.1
million in 2004. In such an event, the Company would be required to take
an immediate charge to earnings of approximately $198.2 million
(pre-tax). Such an outcome could jeopardize the ability of the Company
to continue as a going concern. However, at this time, the Company does
not believe that such a loss is probable.
1997 Retail Rate Case: On September 22, 1997, the Company filed
for a 6.6% or $15.4 million general rate increase to become effective
June 6, 1998 to offset the increasing cost of providing service. $14.3
million or 92.9% of the rate increase request was to recover contractual
increases in the cost of power the Company purchases from Hydro-Quebec.
In response to the Company's filing, the PSB decided to appoint an
independent investigator to examine the Company's decision to buy power
from Hydro-Quebec. The Company made a filing with the PSB stating that
the PSB as well as other parties should be barred from reviewing past
decisions because the PSB already examined the Company's decision to buy
power from Hydro-Quebec in a 1994 rate case in which the Company was
penalized for "improvident power supply management." During February
1998, the DPS filed testimony in opposition to the Company's retail rate
increase request. The DPS recommended that the PSB instead reduce the
Company's then current retail rates by 2.5% or $5.7 million. If the
Company were to eventually receive a rate order that would result in
disallowance of Hydro-Quebec power costs on a permanent basis similar to
that contained in the GMP February 28, 1998 rate order, the Company's
ability to continue as a going concern could be jeopardized. Because of
these risks and because the PSB rejected the Company's claim that the
PSB was precluded from again trying the Company on certain Hydro-Quebec
and related C&LM issues, the Company concluded that it was necessary to
have the so-called preclusion issue reviewed by the VSC before the PSB
issues a final order in the Company's 6.6% rate increase request. Refer
to Note 3 to the Consolidated Financial Statements for related
information. The Company sought, and the PSB granted, permission to
stay this rate case and to file an interlocutory appeal of the PSB's
denial of the Company's motion to preclude a re-examination of the
Company's Hydro-Quebec contract in 1991. The Company has argued its
position before the VSC. The VSC has not yet rendered a decision and it
is uncertain at this time when a decision is forthcoming.
On April 13, 2000, the Company and the DPS filed a stipulated
agreement with the PSB to end winter-summer rate differentials for the
Company's Vermont customers. If approved by the PSB, the Company will
have flat rates throughout a given year. Winter rates will be reduced
by 14.9%, while summer rates will increase 10.5%. The impact on
individual customers will depend on each customer's usage patterns. The
change would be revenue neutral over a 12-month period. If approved by
the PSB, the rates will be effective July 1, 2000. The additional 2000
revenues, resulting from implementing this change in mid-year, will be
applied to reduce or eliminate certain regulatory deferrals.
New Hampshire
Connecticut Valley's retail rate tariffs, approved by the NHPUC
contain a FAC, and a PPCA. Under these clauses, Connecticut Valley
recovers its estimated annual costs for purchased energy and capacity
which are reconciled when actual data is available.
On November 26, 1997, Connecticut Valley filed a request with the
NHPUC to increase FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
resulted from higher forecast energy and capacity charges on power
Connecticut Valley purchases from the Company plus removal of a credit
effective during 1997 to refund over collections from 1996.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and
PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the
Company, notwithstanding the stays of its February 28, 1997 Orders. The
NHPUC Order further directed Connecticut Valley to freeze its current
FAC and PPCA rates (other than short term rates to be paid to certain
Qualifying Facilities) effective January 1, 1998, on a temporary basis,
pending a hearing to determine: 1) the appropriate proxy for a market
price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price;
and 3) whether the NHPUC's final determination on the FAC and PPCA rates
should be reconciled back to January 1, 1998 or some other date. See
Electric Industry Restructuring discussed below and Note 13 to the
Consolidated Financial Statements for additional information.
On April 9, 1998 the Court issued a preliminary injunction against
the NHPUC and directed and required the NHPUC to allow Connecticut
Valley to recover through retail rates all costs for wholesale power
requirements service that Connecticut Valley purchases from the Company
pursuant to its FERC-authorized wholesale rate schedule effective
January 1, 1998 until further court order. Connecticut Valley received
an order from the NHPUC authorizing retail rates to recover such costs
beginning in May 1998.
On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to implement
the proposed FAC and PPCA rates on a temporary basis, effective on all
bills rendered on or after January 1, 1999. In addition, the NHPUC also
ordered Connecticut Valley to pay refunds plus interest to its retail
customers for any overcharges collected as a result of the April 9, 1998
Federal District Court Order, should it be overturned or modified.
As a result of the December 3, 1998 Court of Appeals' decision, see
New Hampshire Retail Rates/Federal Court Proceedings below, on March 22,
1999, the NHPUC issued an Order which directed Connecticut Valley to
file within five business days its calculation of the difference between
the total FAC and the PPCA revenues that it would have collected had the
1997 FAC and PPCA rate levels been in effect the entire year. In its
Order, the NHPUC also directed Connecticut Valley to calculate a rate
reduction to be applied to all billings for the period April 1, 1999
through December 31, 1999 to refund the 1998 over collection relative to
the 1997 rate level. The Company estimated this amount to be
approximately $2.7 million on a pre-tax basis. Connecticut Valley filed
the required tariff page with the NHPUC, under protest and with
reservation of all rights, on March 26, 1999 and implemented this refund
effective April 1, 1999.
On April 7, 1999, the Court ruled from the bench that the March 22,
1999 NHPUC Order requiring Connecticut Valley to provide a refund to its
retail customers was illegal and beyond the NHPUC's authority. The
Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates
below rates in effect at December 31, 1997. Accordingly, Connecticut
Valley removed the rate refund from retail rates effective April 16,
1999.
The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation effective with bills issued on and after June 1, 1999.
On December 1, 1999, Connecticut Valley filed with the NHPUC a
petition for a change in its FAC and PPCA rates effective on bills
rendered on and after January 1, 2000. On December 30, 1999, the NHPUC
denied Connecticut Valley's request to increase its FAC and PPCA rates
above those in effect at December 31, 1997 subject to further
investigation and reconciliation until otherwise ordered by the NHPUC.
On March 6, 2000 the Court granted summary judgment to Connecticut
Valley and the Company on their claim under the filed-rate doctrine and
issued a permanent injunction mandating that the NHPUC allow Connecticut
Valley to pass through to its retail customers its wholesale costs
incurred under the RS-2 rate schedule with the Company. The Court also
ruled that Connecticut Valley is entitled to recover those wholesale
costs that the NHPUC has disallowed in retail rates since January 1,
1997. This decision is subject to implementation by the NHPUC and has
been appealed by the NHPUC to the Court of Appeals. The NHPUC also
requested the Court of Appeals to stay the Court's Order pending the
Court's review on appeal. In response, Connecticut Valley offered to
place the additional revenues in escrow pending the outcome of appeal.
The Court of Appeals denied the NHPUC's request for a stay so long as
the incremental revenues were placed in escrow. The appeal is fully
briefed and was argued before the Court of Appeals on May 8, 2000. The
Company expects a decision on the appeal within 90 days.
Pursuant to the March 6, 2000 Court's Order, on March 17, 2000
Connecticut Valley filed a rate request with the NHPUC for an Interim
FAC/PPCA to recover the balance of wholesale costs not recovered since
January 1997. To mitigate the rate increase percentage, the Interim
FAC/PPCA were designed to recover current power costs and a substantial
portion of past under collections by the end of 2000; the remainder of
the past under collections will be collected during 2001 along with 2001
power costs. The NHPUC held a hearing on April 7, 2000 to review the
12.3% increase that would raise $1.6 million of revenues in 2000. The
NHPUC issued an order approving the rates effective May 1, 2000.
Proposed Formation of Holding Company
In order to further prepare Central Vermont Public Service
Corporation for deregulation, on July 24, 1998, the Company filed a
petition with the PSB for permission to create a holding company that
would have as subsidiaries the Company and non-utility subsidiaries,
Catamount and SmartEnergy. The Company believes that a holding company
structure will facilitate the Company's transition to a deregulated
electricity market. The proposed holding company formation must also be
approved by Federal regulators, including the Securities and Exchange
Commission and the FERC, and by the Company's shareholders. The Company
has negotiated an agreement regarding the formation of a holding company
with the DPS. The agreement establishes a code of conduct and affiliate
transaction rules. As part of the agreement, the Company has also
agreed to not further pursue the holding company proceeding before the
PSB until additional progress is made on other restructuring
initiatives.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from rate making based on cost of service and
return on equity to more market-based rates with energy sold to
customers by competing retail energy service providers. Many states,
including Vermont and New Hampshire, where the Company does business,
are exploring new mechanisms to bring greater competition, customer
choice and market influence to the industry while retaining the public
benefits associated with the current regulatory system.
Vermont
Recently, there have been three primary sources of Vermont
governmental activity in attempting to restructure the electric industry
in Vermont: (1) the Governor's Working Group, created by the Governor of
Vermont; (2) the PSB's Docket No. 6140, through which the PSB considered
restructuring proposals; (3) the PSB's Docket No. 6330, through which
the PSB is considering the establishment of policies and procedures to
govern retail competition within the Company's Vermont service
territory.
The Working Group
On July 22, 1998, the Governor of Vermont issued an Executive Order
establishing the Working Group on Vermont's Electricity Future to lead a
new effort to review the issues of potential restructuring of Vermont's
electric industry. The Working Group was created to determine how
restructuring the electric industry in Vermont could reduce both current
and long-term electric costs for all classes of Vermont electric
consumers. The Working Group was asked to provide a fact-based analysis
of the options for electric industry restructuring and the impact of
such industry changes on consumers and upon Vermont utilities. Further,
the Working Group was directed by the Governor to gather information on
and evaluate the possible consequences of the current financial status
of Vermont electric utilities.
A report was issued by the Working Group on December 18, 1998. Key
conclusions of the report were:
- The bankruptcy of Vermont electric utilities should not be viewed
as an appropriate means to reduce Vermont utilities' committed
power supply costs.
- Vermont should restructure its electric industry by moving
rapidly to retail choice whereby consumers would purchase power
directly from competing power suppliers.
- Vermont electric utilities should pursue power contract
renegotiations through payments to buy down power contracts or
buy-out power contracts. Financing for such payments should be
obtained in the capital markets after a comprehensive regulatory
process dealing with all of the elements of the restructuring of
the Vermont electric utility industry.
- The Vermont electric utilities should pursue auctions of their
power generation assets and remaining power contracts.
- Consolidation of existing electric utilities in Vermont (there
are currently 22 utilities) should be considered in order to
effect additional savings for utility customers.
The Working Group noted that by March 1, 2000, most New Englanders
outside Vermont will have a choice of their power supplier. While New
England has the highest electricity rates in the nation, electricity
costs in Vermont have been among the lowest in the region, although the
Company's rates are higher than the Vermont average. However, that
advantage is eroding as other states in New England restructure their
electric utility industries. Therefore, the Working Group noted that it
is in the interest of Vermont ratepayers to have the benefit of a
restructured electric utility industry as soon as possible.
Public Service Board Docket No. 6140
On September 15, 1998, the PSB opened Docket No. 6140 with the goal
of creating a regulatory environment and a procedural framework to call
forth, for disciplined review, proposals for reducing current and future
power costs in Vermont. The PSB intended that this proceeding define one
or more acceptable courses for power supply reform. All Vermont
utilities were made a party to the proceeding. Subsequent to the PSB's
announcement, preliminary position papers were filed and a series of
technical conferences were convened with the PSB to recommend the scope
of the investigation, potential courses for reform of Vermont's power
supply and other matters associated therewith including the
consideration of the Working Group's recommendations.
On March 3, 1999, the Company filed its Restructuring Plan, a
Working Plan to restructure a significant portion of Vermont's Electric
Utility Industry, with the PSB and parties in Docket No. 6140. The
Company's plan was a joint plan with GMP. On July 12, 1999, the PSB
issued a Status Order concluding that the objective of implementing
power supply reform may be advanced more effectively in ways other than
holding further technical conferences in this docket. Absent good
reason to hold one or more technical conferences pertinent to power
supply reform, the PSB indicated that the docket would be closed on
December 31, 1999, which action has occurred. As a companion proceeding
to its Docket No. 6140 investigation, on January 19, 1999, the PSB
issued an order opening a new contested case proceeding, Docket No.
6140-A, where it indicated that it intended to issue final, binding and
appealable orders concerning matters related to the reform and
restructuring of Vermont's electric utility industry. Initially, the PSB
notified parties that it intended proceedings in Docket No. 6140-A to
consider matters associated with the bankruptcy of one or more of the
Vermont electric utilities. After an opportunity for comment, the focus
of the proceeding was amended to consider the principles, authority and
proposals for reform of Vermont's electric power supply. This included
issues associated with the scope and extent of the Board's authority to
approve "securitization" and other financings proposed to be entered
into in connection with the buy-out or buy-down of power contracts and
the criteria to be applied by the PSB when considering voluntary utility
restructuring proposals.
By Order dated June 24, 1999 in Docket 6140-A, the PSB formally
adopted the Vermont Principles on Electric Utility Restructuring. The
Order explains that proposals to open utility franchise service areas to
retail competition, including our Restructuring Plan, will only be
approved if they can be found to satisfy the public good after due
consideration is given to each of 14 Restructuring Principles. If one or
more of the principles is not satisfied by the proposal, then the
proponent must offer justification for the deficiency and demonstrate
satisfaction of certain statutory requirements. As such, the PSB stated
that any filing proposing to open a franchise territory to retail choice
would have to be supported, at a minimum, by an explanation of how that
proposal fulfills the policy objectives established by the Vermont
Principles on Electric Utility Restructuring.
With regard to financing, no party to the investigation asked that
the PSB clarify its authority or issue a declaratory ruling concerning
the criteria to be considered when approving utility financings for the
buy-out or buy-down of committed power contracts. During the
investigation, both the Company and Green Mountain Power Corporation
asserted that anticipated refinancing approaches could be accomplished
utilizing the existing Vermont and federal legislative regime that
governs the regulation of electric utilities and that "securitization"
style financings were not presently being contemplated. Because no party
to the Docket contradicted these statements, the Board accepted our
assertions and took no further action to evaluate specific utility
financing proposals.
In contrast, Vermont Electric Power Producers, Inc.("VEPP"),
purchasing agent for the purchase of power from qualifying facilities
pursuant to PSB Rule 4.100, proposed to use administrative
securitization to finance the reform of its power purchase contracts.
However, at the request of all commenting parties, the PSB determined to
withhold judgment on the issue as to whether the PSB had jurisdiction to
authorize a VEPP financing until such time as a specific proposal was
actually filed with the PSB. Toward this end, the PSB has stated that it
will convene a workshop, independent of this Docket, to further discuss
VEPP's financing proposal and to prepare for the opening of a possible
rulemaking proceeding to amend Rule 4.100 on this topic. In the absence
of any requests for further investigation or action to be filed within
30 days of the Docket No. 6140-A Order, the PSB indicated that this
investigation would be closed, which action has occurred.
The Company supports the Working Group recommendations described
above and believes that the restructuring of the electric industry is
essential to improve our financial position, enhance our ability to
effectively compete in a changing electric utility industry and
stabilize projected costs.
As a result, the Company is pursuing a comprehensive financial
Restructuring Plan, certain elements of which were included in the Plan
that the Company and GMP filed with the PSB in the first quarter of 1999
in connection with the proceedings in Docket No. 6140 described above.
The Company is aggressively pursuing implementation of the Restructuring
Plan which includes the following elements:
- Retail choice: voluntarily giving up the exclusive right to
supply power to the Company's present electric customers, while
retaining its rights as a distribution company, as part of a
global settlement of regulatory issues.
- Renegotiation of certain purchase power contracts: reducing the
Company's future cost of power by renegotiating power contracts,
specifically those with Hydro-Quebec and the Vermont purchasing
agent's contracts with IPPs which together represent
approximately 40% of the Company's 1998 net energy supply. The
Company may seek to finance the cost of any buy-outs or
buy-downs of power contracts through the future issuance of
securities in the capital markets.
- Contract and asset disposition: seeking to sell power purchase
contracts and generating assets, including the Company's interest
in the Vermont Yankee nuclear generating plant. On October 15,
1999, the Company and the other owners of Vermont Yankee accepted
a bid for sale of the plant to AmerGen Energy Company, which is
owned by PECO Energy Company and British Energy. This
transaction will also involve taking back a contract to purchase
a portion of the power produced by this plant. The Vermont
Yankee sale needs to be approved by numerous state and
federal regulatory bodies. On November 4, 1999 the PSB opened
Docket No. 6300 to consider the issues attendant to the approval
of the sale of Vermont Yankee and approval of various related
agreements including the Company's agreement to continue to
purchase its share of the output of Vermont Yankee.
- Cost-cutting: implementing cost-cutting measures to reduce cash
flow requirements while maintaining safety and reliability
standards.
- Holding company: establishing a holding company in order to
further prepare the Company for deregulation.
- Industry consolidation: evaluating possible consolidations with
other Vermont electric distribution companies.
- Regulatory settlement: seeking a comprehensive regulatory
settlement that leads to long-term financial stability.
- Energy efficiency activities: creating a state sponsored
"energy-efficiency utility" to take over most system-wide
energy-efficiency services for electric customers. On
September 30, 1999, the PSB issued a final Order approving a
Memorandum of Understanding between the Company, the Vermont
Department of Public Service, all other Vermont electric utility
companies and other interested parties that calls for the
establishment of the energy-efficiency utility and provides for
its funding via a separate stated Energy Efficiency Charge.
The Company believes that implementation of its Restructuring Plan
is a critical element to improving its future financial performance and
to providing its customers with more stable electric rates and the
continuation of efficient and reliable electric service. The key
contingency of the Company's Restructuring Plan is regulatory approval
of a rate schedule that will allow the Company to recover the costs of
the restructuring. If the financial restructuring described in this
section is completed in conjunction with the deregulation of Vermont's
electric industry described in "Electric Industry Restructuring," the
Company anticipates that its utility financial performance and prospects
will improve significantly.
Public Service Board Docket No. 6330
On November 23, 1999, the Company and GMP ("Companies") filed a
joint Petition and Supporting Materials with the PSB asking that the PSB
open an investigation to establish retail access policies and procedures
to resolve issues that must be decided to implement the Companies'
Restructuring Plan. Specifically, the Petition requests that the PSB
issue such orders and approvals as are necessary or advisable to:
1) permit the Companies to suspend their provision of power supply
Services ("Generation Service") to customers located within
their respective service territories;
2) permit the Companies to amend their service tariff obligations
to clarify that they retain their exclusive service franchises
as providers of electric delivery services ("Delivery Service")
to customers within their respective service territories;
3) permit the Companies to implement a Retail Open Access Tariff
("R-OAT") that enables customers located within the Companies'
respective service territories to choose their power supplier
from an array of approved energy service providers ("ESP"),
and to purchase Generation Service from such ESPs at
market-determined prices;
4) select through a competitive bidding process an ESP or ESPs to
deliver "Default Service" for energy to customers located
within the Companies' service territories that do not otherwise
have an arrangement with an ESP for the Provision of Generation
Service;
5) select through a competitive bidding process an ESP or ESPs to
deliver "Transition Service" for energy to customers located
within the Companies' service territories; and
6) approve revisions and modifications to the Companies' tariffs
to implement voluntary retail access within the Companies'
respective service territories as provided for pursuant to this
Petition.
The consent to retail access within the Companies' service areas
established by the Petition is voluntary and conditional. Pursuant to
the Petition, the Company's' consent to customer choice and retail
competition is expressly conditioned upon approval of all elements of
the Companies' Restructuring Plan including the approval of any proposed
mitigation measures to reduce power costs and financing measures related
thereto, and a mechanism to recover the costs rendered stranded on
account of the move to retail access and customer choice.
On January 14, 2000, the PSB opened Docket No. 6330 to consider the
issues raised by the Companies' petition. In its opening Order, the
Board states:
"The scope of this investigation is intended to address many of
the more detailed aspects of retail open access. While current
law may not permit this Board to require retail open access of
Vermont utilities, the companies are clearly able to open their
service territories on a voluntary basis. Whether retail open
access is established on a voluntary basis through existing
statutes or through revised legislation, there are many technical
issues to be resolved. This investigation will serve to advance
many aspects of issues surrounding retail open access."
An initial pre-hearing conference was held in this investigation on
January 31, 2000. The parties to Docket No. 6330 have agreed to
consider the Companies proposal in a proceeding consisting of two
phases. In Phase I parties will identify the scope and extent of
consensus on docket issues (Module 1) and attempt to negotiate
agreements on matters where consensus does not initially emerge (Module
2). In Phase II, parties will litigate unresolved issues. At this
time, it is premature to predict the date upon which a final PSB
resolution of the matters raised in this investigation will be decided
although, the Companies proposed an initial start date for retail
competition of September 1, 2001, provided that all of the elements of
the joint Restructuring Plan are completed by that time.
New Hampshire Retail Rates/Federal Court Proceedings
On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to
Connecticut Valley, found that Connecticut Valley was imprudent for not
terminating the FERC-authorized power contract between Connecticut
Valley and the Company, required Connecticut Valley to give notice to
cancel its contract with the Company and denied stranded cost recovery
related to this power contract. Connecticut Valley filed for rehearing
of the February 28, 1997 NHPUC Order.
On April 7, 1997, the NHPUC issued an Order addressing certain
threshold procedural matters raised in motions for rehearing and/or
clarification filed by various parties, including Connecticut Valley,
relative to the Final Plan and interim stranded cost orders. The April
7, 1997 Order stayed those aspects of the Final Plan that were the
subject of rehearing or clarification requests and also stayed the
interim stranded cost orders for the various parties, including
Connecticut Valley. As such, those matters pertaining to the power
contract between Connecticut Valley and the Company were stayed. The
suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.
On November 26, 1997, Connecticut Valley filed a request with the
NHPUC to increase the FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
resulted from higher forecast energy and capacity charges on power
Connecticut Valley purchases from the Company plus removal of a credit
effective during 1997 to refund over collections from 1996.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and
PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the
Company, notwithstanding the stays of its February 28, 1997 Orders. The
NHPUC Order further directed Connecticut Valley to freeze its current
FAC and PPCA rates (other than short term rates to be paid to certain
Qualifying Facilities) effective January 1, 1998, on a temporary basis,
pending a hearing to determine: 1) the appropriate proxy for a market
price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price;
and 3) whether the NHPUC's final determination on the FAC and PPCA rates
should be reconciled back to January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with
the Court for a temporary restraining order to maintain the status quo
ante by staying the December 31, 1997 NHPUC Order and preventing the
NHPUC from taking any action that (i) compromises cost-based rate making
for Connecticut Valley or otherwise seeks to impose market price-based
rate making on Connecticut Valley; (ii) interferes with the FERC's
exclusive jurisdiction over the Company's pending application to recover
wholesale stranded costs upon termination of its wholesale power
contract with Connecticut Valley; or (iii) prevents Connecticut Valley
from recovering through retail rates the stranded costs and purchased
power costs that it incurs pursuant to its FERC-authorized wholesale
rate schedule with the Company.
On February 23, 1998, the NHPUC announced in a public meeting that
it reaffirmed its finding of imprudence and designated a proxy market
price for power at 4 cents per kWh in lieu of the actual costs incurred
pursuant to the wholesale power contract with the Company. In addition,
the NHPUC indicated, subject to certain conditions which were
unacceptable to the companies, that it would permit Connecticut Valley
to maintain its current rates pending a decision in Connecticut Valley's
appeal of the NHPUC Order to the New Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut
Valley no longer qualified, as of December 31, 1997, for the application
of SFAS No. 71. As a result, Connecticut Valley wrote-off all of its
regulatory assets associated with its New Hampshire retail business as
of December 31, 1997. This write-off amounted to $1.2 million on a
pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million
pre-tax loss in 1997 for disallowed power costs.
On March 20, 1998, the NHPUC issued an order which affirmed,
clarified and modified various generic policy statements including the
reaffirmation to establish rates on the basis of a regional average
announced previously in its February 28, 1997 Final Plan. The March 20,
1998 order also addressed all outstanding motions for rehearings or
clarification relative to the policies or legal positions articulated in
the Final Plan and removed the stay covering the Company's interim
stranded cost order of April 7, 1997. In addition, the March 20, 1998
Order imposed various compliance filing requirements.
On April 3, 1998, the Court held a hearing on the Companies' motion
for a Temporary Restraining Order, or TRO, and Preliminary Injunction
against the NHPUC at which time both the Companies and the NHPUC
presented arguments. In an oral ruling from the bench, and in a written
order issued on April 9, 1998, the Court concluded that the Companies
had established each of the prerequisites for preliminary injunctive
relief and directed and required the NHPUC to allow Connecticut Valley
to recover through retail rates all costs for wholesale power
requirements service that Connecticut Valley purchases from the Company
pursuant to its FERC-authorized wholesale rate schedule effective
January 1, 1998 until further court order. Connecticut Valley received
an order from the NHPUC authorizing retail rates to recover such costs
beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of
appeal and a motion for a stay of the Court's preliminary injunction.
The NHPUC's request for a stay was denied. At the same time, the NHPUC
permitted Connecticut Valley to recover in rates the full cost of its
wholesale power purchases from the Company.
Also, on April 3, 1998, the Court indicated that its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley
and prohibits the enforcement of the restructuring orders until the
Court conducts a consolidated hearing and rules on the requests for
permanent injunctive relief by plaintiff PSNH and the other utilities
that had been allowed to intervene in these proceedings, including the
Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the
NHPUC to implement restructuring and to make clear that the stay
encompasses the NHPUC's order of March 20, 1998.
As a result of these Court orders, Connecticut Valley's 1997
charges described above were reversed in the first quarter of 1998.
Combined, the reversal of these charges increased first quarter 1998 net
income and earnings per share of common stock by $4.5 million and $.39,
respectively.
On April 1, 1998, Citizens Bank of New Hampshire, or Bank, notified
Connecticut Valley that it was in default of the Loan Agreement between
the Bank and Connecticut Valley dated December 27, 1994 and that the
Bank would exercise all of its remedies from and after May 5, 1998 in
the event that the violations were not cured. After reversing the 1997
write-offs described above, Connecticut Valley was in compliance with
the financial covenants associated with its $3.75 million loan with the
Bank. As a result, Connecticut Valley satisfied the Bank's requirements
for curing the violation.
On May 11, 1998 the NHPUC issued an order requiring Connecticut
Valley to show cause why it should not be held in contempt for its
failure to meet the compliance filing requirements of its March 20, 1998
Order. A hearing on this matter was scheduled for June 11, 1998, which
was subsequently canceled because of the Court's June 5, 1998 Order,
discussed below.
On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order
clearly states that no restructuring effort in New Hampshire can move
forward without the Court's approval unless all New Hampshire utilities
agree to the plan. The Order suspended all involuntary restructuring
efforts for all New Hampshire utilities until a hearing is conducted.
The NHPUC appealed this Order to the United States First Circuit Court
of Appeals ("Court of Appeals").
On July 23, 1998, the NHPUC issued an order vacating that portion
of its February 27, 1997 restructuring order that had directed
Connecticut Valley to terminate its RS-2 wholesale power purchases from
the Company. The NHPUC has expressly stated in federal court filings
that its July 23, 1998 order "clarified that Connecticut Valley should
not terminate the RS-2 Rate Schedule if such termination would trigger
the exit fee" for which the Company has sought authorization from FERC.
On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to implement
the proposed FAC and PPCA rates on a temporary basis, effective on all
bills rendered on or after January 1, 1999. In addition, the NHPUC also
ordered Connecticut Valley to pay refunds plus interest to its retail
customers for any overcharges collected as a result of the April 9, 1998
Court Order should it be overturned or modified, which are included in
the estimated total losses of $4.3 million discussed below.
On December 3, 1998, the Court of Appeals announced its decisions
on the appeals taken by the NHPUC from the preliminary injunctions
issued by the Court. Those preliminary injunctions had stayed
implementation of the NHPUC's plan to restructure the New Hampshire
electric industry and required the NHPUC to allow Connecticut Valley to
recover through its retail rates the full cost of wholesale power
obtained from the Company.
The Court of Appeals affirmed the preliminary injunction, issued by
the Court, staying restructuring until the plaintiff utilities' claims
(including those of the Company and Connecticut Valley) are fully tried.
The Court of Appeals found that PSNH had sufficiently established that
without the preliminary injunction against restructuring it would suffer
substantial irreparable injury and that it had sufficient claims against
restructuring to warrant a full trial. The Court of Appeals also
affirmed the extension of the preliminary injunction to protect the
other plaintiff utilities, including Connecticut Valley and the Company,
although it questioned whether the other utilities had arguments as
strong against restructuring as PSNH because they did not have formal
agreements with the State similar to PSNH's Rate Agreement. The Court
of Appeals stated that if the Court awards the utilities permanent
injunctive relief against restructuring after the case is tried, then it
must explain why the other utilities are also entitled to such relief.
The NHPUC filed a petition for rehearing on December 17, 1998. The
Court of Appeals denied the petition on January 13, 1999.
The Court of Appeals also reversed the Court's preliminary
injunction requiring the NHPUC to allow Connecticut Valley to recover in
retail rates the full cost of the power it buys from the Company.
Although the Court of Appeals found that Connecticut Valley and the
Company had made a strong showing of irreparable injury to justify the
preliminary injunction, it concluded that Connecticut Valley's and the
Company's claims did not have a sufficient probability of success to
warrant such preliminary relief. The Court of Appeals explained that
the filed-rate doctrine preserving the exclusive jurisdiction of the
FERC over wholesale power rates did not prevent the NHPUC from deciding
whether Connecticut Valley's power purchases from the Company were
prudent given alternative available sources of wholesale power. The
Court of Appeals then stated that Connecticut Valley's rates could be
reduced to the level prevailing on December 31, 1997. However, the
Court of Appeals also stated that if the NHPUC ordered Connecticut
Valley's rates to be reduced below the level existing as of December 31,
1997, "it will be time enough to consider whether they are precluded
from the Court's injunction against the Final Plan or on other grounds."
On December 17, 1998, Connecticut Valley and the Company filed a
petition for rehearing on the grounds that the Court of Appeals had not
given sufficient weight to the Court's factual findings and that the
Court of Appeals had misapprehended both factual and legal issues.
Connecticut Valley and the Company also asked that the entire Court of
Appeals, rather than only the three-judge appellate panel that had
issued the December 3 decision, consider their petition for rehearing.
On January 13, 1999, the Court denied the petition for rehearing.
Connecticut Valley and the Company then requested the Court of
Appeals to stay the issuance of its mandate until the companies could
file a petition for certiorari to the United States Supreme Court and
the Supreme Court acted on the petition.
On January 22, 1999, the Court of Appeals denied the request.
However, the Court of Appeals granted a 21-day stay to enable the
Company to seek a stay pending certiorari from the Circuit Justice of
the Supreme Court. On February 11, 1999, the Company and Connecticut
Valley filed a petition for a writ of certiorari with the United States
Supreme Court and a motion to stay the effect of the Court of Appeals'
decision while the case was pending in the Supreme Court. The motion
for a stay was addressed to Justice Souter who is responsible for such
motions pertaining to the Court of Appeals for the First Circuit. On
February 18, 1999, Justice Souter denied the stay pending the petition
for certiorari. On April 19, 1999, the Supreme Court denied the
petition for certiorari.
As a result of the December 3, 1998 Court of Appeals' decision
discussed above, on March 22, 1999, the NHPUC issued an Order which
directed Connecticut Valley to file within five business days its
calculation of the difference between the total FAC and PPCA revenues
that it would have collected had the 1997 FAC and PPCA rate levels been
in effect the entire year. In its Order, the NHPUC also directed
Connecticut Valley to calculate a rate reduction to be applied to all
billings for the period April 1, 1999 through December 31, 1999 to
refund the 1998 over collection relative to the 1997 rate level. The
Company estimated this amount to be approximately $2.7 million on a
pre-tax basis. Connecticut Valley filed the required tariff page with
the NHPUC, under protest and with reservation of all rights, on March
26, 1999 and implemented the refund effective April 1, 1999.
As a result of legal and regulatory actions discussed above,
Connecticut Valley no longer qualified as of December 31, 1998 for the
application of SFAS No. 71, and wrote-off in the fourth quarter of 1998
all its regulatory assets associated with its New Hampshire retail
business estimated at approximately $1.3 million on a pre-tax basis at
December 31, 1998. In addition, Connecticut Valley recorded estimated
total losses of $4.3 million pre-tax during the fourth quarter of 1998
for disallowed power costs of $1.6 million and its refund obligations of
$2.7 million.
The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants, which if not waived or renegotiated,
would have allowed Connecticut Valley's lender the right to accelerate
the repayment of a $3.75 million loan with Connecticut Valley. On March
12, 1999, Connecticut Valley was notified by the Bank that it would
exercise appropriate remedies in connection with the violation of
financial covenants associated with the $3.75 million loan agreement
unless the violation was cured by April 11, 1999. To avoid default of
this loan agreement, on April 6, 1999, pursuant to an agreement reached
on March 26, 1999, the Company purchased from the Bank the $3.75 million
note.
On April 7, 1999, the Court ruled from the bench that the March 22,
1999 NHPUC Order requiring Connecticut Valley to provide a refund to its
retail customers was illegal and beyond the NHPUC's authority. The
Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates
below rates in effect at December 31, 1997. Accordingly, Connecticut
Valley removed the rate refund from retail rates effective April 16,
1999. Lastly, the Court denied the NHPUC's motion to dissolve the
injunction staying the implementation of its restructuring plan and
stated its desire to rule on the pending motion for summary judgement
and to conduct a hearing on the Company's request for a permanent
injunction, after the NHPUC completes hearings on PSNH's stranded costs.
The District Court's decision was issued as a written order on May 11,
1999.
The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation, effective with bills issued on and after June 1, 1999.
On May 24, 1999, the NHPUC filed a petition for mandamus in the
Court of Appeals challenging the Court's May 11, 1999 ruling and seeking
a decision allowing the refunds as required by the NHPUC's March 22,
1999 order. The Court of Appeals denied that petition on June 2, 1999.
The NHPUC immediately filed a notice of appeal in the Court of Appeals
again challenging the Court's May 11, 1999 ruling. In that appeal, the
Company and Connecticut Valley contend, among other things, that it is
unfair for the NHPUC to direct Connecticut Valley to continue to
purchase wholesale power under RS-2 in order to avoid the triggering of
a FERC exit fee, but at the same time to freeze Connecticut Valley's
rates at their December 31, 1997 level which does not enable Connecticut
Valley to recover all of its RS-2 costs.
On June 14, 1999, PSNH and various parties in New Hampshire
announced that a "Memorandum of Understanding" had been reached that is
intended to result in a detailed settlement proposal to the NHPUC that
would resolve PSNH's claims against the NHPUC's restructuring plan. On
July 6, 1999, PSNH petitioned the Court to stay its proceedings
indefinitely while the proposed settlement is reviewed and approved by
the NHPUC and the New Hampshire Legislature. On July 12, 1999 the
Company and Connecticut Valley objected to any stay that would allow the
NHPUC's rate freeze order to remain in effect for an extended period and
asked the Court to proceed with prompt hearings on its summary judgement
motion and trial on the merits. On October 20, 1999 the Court heard
oral arguments pertaining to the pretrial motions of the Company and the
NHPUC for summary judgement and dismissal, respectively.
On December 1, 1999, Connecticut Valley filed with the NHPUC a
petition for a change in its FAC and PPCA rates effective on bills
rendered on and after January 1, 2000. On December 30, 1999, the NHPUC
denied Connecticut Valley's request to increase its FAC and PPCA rates
above those in effect at December 31, 1997 subject to further
investigation and reconciliation until otherwise ordered by the NHPUC.
Accordingly, during the fourth quarter of 1999 Connecticut Valley
recorded $1.2 million for under collection of year 2000 power costs.
The Court of Appeals issued a decision on January 24, 2000, which
upheld the Court's preliminary injunction enjoining the Commission's
restructuring plan. The decision also remanded the refund issue do the
Court stating:
"The district court may defer vacation of this injunction
against the refund order for up to 90 days. If within that
period it has decided the merits of the request for a
permanent injunction in a way inconsistent with refunds, or
has taken any other action that provides a showing that the
Company is likely to prevail on the merits in federal court
in barring the refunds, it may enter a superseding injunction
against the refund order, which the Commission may then
appeal to us. Otherwise, no later than the end of the
90-day period, the district court must vacate its present
injunction insofar as it enjoins the Commission's refund
order."
On March 6, 2000 the Court granted summary judgment to Connecticut
Valley and the Company on their claim under the filed-rate doctrine and
issued a permanent injunction mandating that the NHPUC allow Connecticut
Valley to pass through to its retail customers its wholesale costs
incurred under the RS-2 rate schedule with the Company. The Court also
ruled that Connecticut Valley is entitled to recover those wholesale
costs that the NHPUC has disallowed in retail rates since January 1,
1997. This decision is subject to implementation by the NHPUC and has
been appealed by the NHPUC to the Court of Appeals. The NHPUC also
requested the Court of Appeals to stay the Court's Order pending the
Court's review on appeal. In response, Connecticut Valley offered to
place the additional revenues in escrow pending the outcome of appeal.
The Court of Appeals denied the NHPUC's request for a stay so long as
the incremental revenues were placed in escrow. The appeal is fully
briefed and was argued before the Court of Appeals on May 8, 2000. The
Company expects a decision on the appeal within 90 days.
Pursuant to the March 6, 2000 Court's Order, on March 17, 2000
Connecticut Valley filed a rate request with the NHPUC for an Interim
FAC/PPCA to recover the balance of wholesale costs not recovered since
January 1997. To mitigate the rate increase percentage, the Interim
FAC/PPCA were designed to recover current power costs and a substantial
portion of past under collections by the end of 2000; the remainder of
the past under collections will be collected during 2001 along with 2001
power costs. The NHPUC held a hearing on April 7, 2000 to review the
12.3% increase that would raise $1.6 million of revenues in 2000. The
NHPUC issued an order approving the rates effective May 1, 2000.
FERC Proceedings
The Company filed an application with the FERC in June 1997, to
recover stranded costs in connection with its wholesale rate schedule
with Connecticut Valley and a notice of cancellation of the Connecticut
Valley rate schedule (contingent upon the recovery of the stranded costs
that would result from the cancellation of this rate schedule). In
December 1997, the FERC rejected the Company's proposal to recover
stranded costs through the imposition of a surcharge on our transmission
tariff, but indicated that it would consider an exit fee mechanism for
collecting stranded costs. The FERC denied the Company's motion for a
rehearing regarding the surcharge proposal, so the Company filed a
request with the FERC for an exit fee mechanism to collect the stranded
costs resulting from the cancellation of the contract with Connecticut
Valley. The stranded cost obligation sought to be recovered through an
exit fee, expressed on a net present value basis as of January 1, 2000,
is approximately $44.9 million. During April and May 1999, nine days of
hearings were held at the FERC before an Administrative Law Judge, who
will determine, among other things, whether Connecticut Valley qualifies
for an exit fee, and if so, the amount of Connecticut Valley's stranded
cost obligation to be paid to the Company as an exit fee. The ruling of
the Administrative Law Judge is expected at any time. Thereafter the
FERC will act on the judge's recommendations.
If the Company is unable to obtain an order authorizing the
recovery of costs in connection with the June 1997 FERC filing or in the
Federal Court, it is possible that the Company would be required to
recognize a pre-tax loss under this contract totaling approximately
$56.3 million as of December 31, 1999. The Company would also be
required to write-off approximately $3.0 million (pre-tax) in regulatory
assets associated with its wholesale business as of December 31, 1999.
However, even if the Company obtains a FERC order authorizing the
updated requested exit fee, if Connecticut Valley is unable to recover
its costs by increasing its rates, Connecticut Valley would be required
to recognize a loss under this contract of approximately $44.9 million
(pre-tax) representing future under recovery of power costs as of
December 31, 1999.
In addition to its efforts before the Court and FERC, Connecticut
Valley has initiated efforts and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding
and the NHPUC. On September 14 and 15, 1998 the Company participated in
a settlement conference with an Administrative Law Judge assigned for
the settlement process at the FERC and the parties to the Company's exit
fee filing.
An adverse resolution of these proceedings would have a material
adverse effect on the Company's results of operations and cash flows.
However, the Company cannot predict the ultimate outcome of this matter.
For further information on New Hampshire restructuring issues and
other regulatory events in New Hampshire affecting the Company or
Connecticut Valley and the 1997, 1998 and 1999 charges and reversals of
charges, see the Company's Current Reports on Form 8-K dated January 12,
1998, January 28, 1998, April 1, 1998 and February 1, 1999; the
Company's Form 10-Q for the quarterly periods ended March 31, June 30
and September 30, 1998; and March 31, June 30 and September 30, 1999.
Also, Item 1. Business-New Hampshire Retail Rates, Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations-Electric Industry Restructuring-New Hampshire and Item 8.
Financial Statements and Supplementary Data-Note 13, Retail Rates-New
Hampshire in the Company's 1999, 1998 and 1997 Annual Reports on Form
10-K.
Connecticut Valley constitutes approximately 7% of the Company's
total retail mWh sales.
Competition-Risk Factors
If retail competition is implemented in Vermont or New Hampshire,
the Company is unable to predict the impact of this competition on its
revenues, the Company's ability to retain existing customers with
respect to their power supply purchases and attract new customers or the
margins that will be realized on retail sales of electricity, if any
such sales are sought. The Company expects its power distribution and
transmission service to its customers to continue on an exclusive basis
subject to continuing economic regulation.
Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain
accounting standards that are not applicable to other business
enterprises in general. SFAS No. 71 requires regulated entities, in
appropriate circumstances, to establish regulatory assets and
liabilities, and thereby defer the income statement impact of certain
costs and revenues that are expected to be realized in future rates.
As described in Note 1 of Notes to Consolidated Financial
Statements, the Company believes it currently complies with the
provisions of SFAS No. 71 for both its regulated Vermont service
territory and FERC regulated wholesale businesses. In the event the
Company determines that it no longer meets the criteria for following
SFAS No. 71, the accounting impact would be an extraordinary, non-cash
charge to operations of approximately $59.3 million on a pre-tax basis
as of March 31, 2000. Criteria that give rise to the discontinuance of
SFAS No. 71 include (1) increasing competition that restricts the
Company's ability to establish prices to recover specific costs and (2)
a significant change in the manner in which rates are set by regulators
from cost-based regulation to another form of regulation.
The Securities and Exchange Commission has questioned the ability
of certain utility companies continuing the application of SFAS No. 71
where legislation provides for the transition to retail competition.
Deregulation of the price of electricity issues related to the
application of SFAS No. 71 and 101, as to when and how to discontinue
the application of SFAS No. 71 by utilities during transition to
competition has been referred to the Financial Accounting Standards
Board's Emerging Issues Task Force ("EITF").
The EITF has reached a tentative consensus, and no further
discussion is planned, that regulatory assets should be assigned to
separable portions of the Company's business based on the source of the
cash flows that will recover those regulatory assets. Therefore, if the
source of the cash flows is from a separable portion of the Company's
business that meets the criteria to apply SFAS No. 71, those regulatory
assets should not be written off under SFAS No. 101, "Accounting for the
Discontinuation of Application of SFAS No. 71," but should be assessed
under paragraph 9 of SFAS No. 71 for realizability.
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets
and for Long-Lived Assets to Be Disposed Of," which was adopted by the
Company on January 1, 1996, requires that any assets, including
regulatory assets, that are no longer probable of recovery through
future revenues, be revalued based upon future cash flows. SFAS No. 121
requires that a rate-regulated enterprise recognize an impairment loss
for the amount of costs excluded from recovery. As of December 31,
1999, based upon the regulatory environment within which the Company
currently operates, SFAS No. 121 did not have an impact on the Company's
financial position or results of operations. Competitive influences or
regulatory developments may impact this status in the future.
Because the Company is unable to predict what form possible future
restructuring legislation will take, it cannot predict if or to what
extent SFAS Nos. 71 and 121 will continue to be applicable in the
future. In addition, if the Company is unable to mitigate or otherwise
recover stranded costs that could arise from any potentially adverse
legislation or regulation, the Company would have to assess the
likelihood and magnitude of losses incurred under its power contract
obligations.
As such, the Company cannot predict whether any restructuring
legislation enacted in Vermont or New Hampshire, once implemented, would
have a material adverse effect on the Company's operations, financial
condition or credit ratings. However, the Company's failure to recover
a significant portion of its purchased power costs, would likely have a
material adverse effect on the Company's results of operations, cash
flows, ability to obtain capital at competitive rates and ability to
exist as a going concern. It is possible that stranded cost exposure
before mitigation could exceed the Company's current total common stock
equity.
Recent Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June 1999, the FASB
issued Statement No. 137, Accounting for Derivative Instruments and
Hedging Activities -- Deferral of the Effective Date of SFAS No. 133.
This Statement establishes accounting and reporting standards requiring
that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. This
Statement requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that
receive hedge accounting.
SFAS No. 133, as amended, is effective for fiscal years beginning
after June 15, 2000. A company may also implement this Statement as of
the beginning of any fiscal quarter after issuance (that is, fiscal
quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot
be applied retroactively. SFAS No. 133 must be applied to (a)
derivative instruments and (b) certain derivative instruments embedded
in hybrid contracts. With respect to hybrid instruments, a company may
elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2)
only those hybrid instruments that were issued, acquired, or
substantively modified after December 31, 1997, or (3) only those hybrid
instruments that were issued, acquired, or substantively modified after
December 31, 1998. The Company has not yet quantified the impacts of
adopting SFAS No. 133 on the financial statements and has not determined
the timing or method of the adoption of SFAS No. 133.
Forward Looking Statements
This document contains statements that are forward looking. These
statements are based on current expectations that are subject to risks
and uncertainties. Actual results will depend, among other things, upon
general economic and business conditions, weather, the actions of
regulators, including the outcome of the litigation involving
Connecticut Valley before the FERC and the Court and the Company's
pending rate case before the PSB and associated appeal to the Vermont
Supreme Court, as well as other factors which are described in further
detail in the Company's filings with the Securities and Exchange
Commission. The Company cannot predict the outcome of any of these
proceedings or other factors.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On August 7, 1997, the Company and eight other non-operating owners
of Unit #3 filed a demand for arbitration with Connecticut Light and
Power Company and Western Massachusetts Electric Company, both NU
affiliates, and lawsuits against NU and its trustees. The arbitration
and lawsuits seek to recover costs associated with replacement power,
operation and maintenance costs and other costs resulting from the
shutdown of Unit #3. The non-operating owners claim that NU and two of
its wholly owned subsidiaries failed to comply with NRC's regulations,
failed to operate the facility in accordance with good operating
practice and attempted to conceal their activities from the
non-operating owners and the NRC. A mediator has been hired in an
attempt to settle prior arbitration and the lawsuit.
On September 15, 1999, NU announced that it intends to auction its
nuclear generating plants, including Unit #3. We cannot predict at this
time the effect of such an auction, if it occurs, on the Company or on
the ongoing litigation.
On October 27, 1999, NU and NEP, disclosed that NU had reached an
agreement with NEP and MEC, two of the non-operating minority joint
owners, to settle their claims in the arbitration and lawsuits. The
settlement involves payment of fixed and contingent amounts to NEP and
MEC and the inclusion of their Unit #3 interests in NU's auction of the
plant. In addition, on January 28, 2000 CMP, also one of the
non-operating minority joint owners, disclosed that NU and CMP had
reached an agreement to settle CMP's claims in the arbitration and
litigation on terms similar to the NEP and MEC settlement. The other
non-operating minority joint owners, including the Company, remain
active in the arbitration and lawsuits and in seeking to settle our
claims against NU.
Except as otherwise described under Management's Discussion and
Analysis of Financial Condition and Results of Operations, Item 2, there
are no other material pending legal proceedings, other than ordinary
routine litigation incidental to the business, to which the company or
any of its subsidiaries is a party or to which any of their property is
subject.
Items 2 and 3.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
(a) The Registrant held its Annual Meeting of Stockholders on
May 2, 2000.
(b) To approve the Stock Option Plan for Key Employees:
For 8,775,317
Against 993,841
Abstain 318,593
Non-vote 2
(c) Directors elected whose terms will expire in year 2003:
Votes FOR Votes WITHHELD
--------- --------------
Robert L. Barnett 9,886,182 201,571
Frederic R. Bertrand 9,875,264 212,489
Robert G. Clarke 9,882,673 205,080
Mary Alice McKenzie 9,876,543 211,210
Other Directors whose terms will expire in 2001:
Votes FOR Votes WITHHELD
--------- --------------
Timothy S. Cobb 9,855,532 232,221
Other Directors whose terms will expire in 2001:
Luther F. Hackett
Janice L. Scites
Other Directors whose terms will expire in 2002:
Rhonda L. Brooks
Patrick J. Martin
Robert H. Young
Item 5. Other Information.
(a) In the summer of 1997, the City of Claremont ("Claremont"),
New Hampshire engaged a consulting firm to conduct a study to determine
Claremont's options under New Hampshire law including the possible
municipalization of Connecticut Valley's service area located within its
jurisdiction. The City Council ("Council") appropriated approximately
$75,000 for purposes of the study which has been completed. In May
1999, the City Council of Claremont considered whether to publicly warn
a vote to acquire the Company's facilities located in Claremont and to
establish a municipal electric utility pursuant to N.H.R.S.A. Chapter 38
et. sec. By vote of six to three, the Council voted to proceed towards
the establishment of a municipal electric utility and acquisition of
Company facilities. This action required that Claremont hold an
election within one year of the Council's action to determine if a
majority of the qualified voters will confirm the Council's decision.
Should the Council's decision be confirmed by Claremont voters, the
Council will have thirty days from the date of the confirming vote to
notify the Company of its intention to purchase all or such portion of
the Company's plant and property located within Claremont and such
portion of the plant lying within the municipality as the public
interest may require. The Company would thereafter have sixty days to
reply to the Claremont's inquiry. If there is no agreement between the
Company and Claremont, Claremont may proceed to condemn the Company's
facilities with proceedings before the NHPUC as provided for in Chapter
38 and the FERC as provided for in its Rule 35.26 (18CFR Chapter 1). On
September 8, 1999, the City Council voted to postpone indefinitely the
citizens' vote on municipalization which had been set for November 2,
1999. A group of Claremont citizens opposed to a government electric
takeover actively participated in the November 2, 1999 municipal
election, resulting in the election of three challengers opposed to the
idea, and the creation of a majority on the city council against the
municipalization of Connecticut Valley's system. The Company cannot
predict at this time when or if a citizens' vote on municipalization
will be held in connection with this initiative.
(b) On May 2, 2000, Joan F. Gamble was elected Vice President of
Human Resources and Strategic Planning.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
10. Material Contracts
A 10.91 Management Incentive Plan for Executive
Officers dated January 1, 2000
A 10.92 Change Of Control Agreement as approved
April 3, 2000
A - compensation related plan, contract or
arrangement
27. Financial Data Schedule
(b) Item 5. Other Events, dated March 17, 2000 re: Sale of a 50
percent interest in the Home Service Store, Inc. to
Jupiter Partners II L.P.
<PAGE>
<PAGE>
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 Francis J. Boyle
Francis J. Boyle
Authorized Signatory and Senior Vice President,
Principal Financial Officer and Treasurer
Dated May 12, 2000
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This Financial Data Schedule contains summary financial information extracted
from the Consolidated Financial Statements included herein and is qualified in
its entirety by reference to such financial statements (dollars in thousands,
except per share amounts).
</LEGEND>
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-END> MAR-31-2000
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 312,595
<OTHER-PROPERTY-AND-INVEST> 73,370
<TOTAL-CURRENT-ASSETS> 110,267
<TOTAL-DEFERRED-CHARGES> 66,277
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 562,509
<COMMON> 66,556
<CAPITAL-SURPLUS-PAID-IN> 45,345
<RETAINED-EARNINGS> 79,885
<TOTAL-COMMON-STOCKHOLDERS-EQ> 191,540
16,000
8,054
<LONG-TERM-DEBT-NET> 156,105
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 17,688
0
<CAPITAL-LEASE-OBLIGATIONS> 14,790
<LEASES-CURRENT> 1,094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 157,238
<TOT-CAPITALIZATION-AND-LIAB> 562,509
<GROSS-OPERATING-REVENUE> 99,949
<INCOME-TAX-EXPENSE> 6,491
<OTHER-OPERATING-EXPENSES> 80,894
<TOTAL-OPERATING-EXPENSES> 87,385
<OPERATING-INCOME-LOSS> 12,564
<OTHER-INCOME-NET> (1,028)
<INCOME-BEFORE-INTEREST-EXPEN> 11,536
<TOTAL-INTEREST-EXPENSE> 3,577
<NET-INCOME> 7,959
445
<EARNINGS-AVAILABLE-FOR-COMM> 7,514
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 3,079
<CASH-FLOW-OPERATIONS> 32,385
<EPS-BASIC> 0.66
<EPS-DILUTED> 0.66
</TABLE>
Exhibit A 10.91
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
MANAGEMENT INCENTIVE PLAN
Adopted As Of January 1, 2000
I. PURPOSE
The Company's executive officers participate in the
Company's Management Incentive Plan ("MIP"). The purpose of
the MIP is to focus the efforts of the executive team on the
achievement of challenging and demanding objectives. When
actual performance attains the pre-specified annual
performance targets, an award is granted. A well designed
incentive plan, in conjunction with competitive salaries,
provides a level of compensation which allows the company to
attract and retain skilled Executive Officers.
II. ADMINISTRATION
The MIP is administered by the Compensation Committee
of the Board of Directors (the "Committee"). All Committee
actions are subject to review and approval by the full Board
of Directors (the "Board").
At the beginning of each calendar year ("Plan Year"),
the Committee submits to the Board its recommendations for
that Plan Year as to (i) the MIP's corporate and business
unit performance targets, and (ii) the eligible
participants. Individual performance targets are also set
in the beginning of the Plan Year for the Chief Executive
Officer by the Chairman of the Board, with input from the
Committee and the Board, and for each officer by the Chief
Executive Officer . After the end of each Plan Year, the
Committee will report to the Board with respect to
achievement of the previously approved Corporate, business
unit and individual performance targets for that Plan Year,
and will submit to the Board its recommendations as to the
appropriate award payment levels for each eligible
participant. Recommendations of the Committee, with such
modifications as may be made by the Board, will be binding
on all participants in the MIP.
III. THE PLAN
Awards are based on the actual performance achieved vs.
the performance goals set in the beginning of the Plan Year
for each of the following areas:
CASH FLOW FROM OPERATING ACTIVITIES. A measure of
overall corporate financial performance.
BUSINESS UNIT PERFORMANCE. Measures the performance
for each strategic business unit or for overall corporate
performance, depending on the officer's responsibilities. These
performance measures which are established annually are a balanced
set of measures including customer satisfaction, financial
performance, process improvement and employee measures.
INDIVIDUAL PERFORMANCE. Based on advice and
recommendation from the Chief Executive Officer for those reporting to him.
The Chairman and Committee evaluate the Chief Executive
Officer's performance.
For all of the CVPS Executive Officers, these three
performance areas are equally weighted. For the Executive
Vice President and General Manager of Catamount the business
unit performance is given an 80% weight with the other two
measures equally weighted at 10%.
For each performance measure, goals are set at three
levels: threshold, target and maximum. These are set based
on the following probabilities: 90% probability of achieving
the threshold level; 50% probability of achieving target
level; and 10% probability of achieving the maximum level.
Payout is determined by linear interpolation between three
points where achieving the threshold level of performance
results in no payout, the target level of performance
results in a 100% of the target payout and achieving the
maximum level of performance results in a 200% of target
payout. The maximum TOTAL payout is capped at 150% of
target.
Any annual incentive award is made in cash. Payments
are made in the spring of the following year to officers
employed at that time. Officers who commence employment
partway through the Plan Year will have their incentive
prorated based on their start date.
IV. AMENDMENTS
The Board reserves the right to amend, modify or
terminate the Management Incentive Plan at any time.
Exhibit A 10.92
CHANGE OF CONTROL AGREEMENT
(Officer Name)
This Agreement, entered into as of ________________
between Central Vermont Public Service Corporation
(hereinafter "Company") and the undersigned Executive
executing this Agreement (hereinafter "Executive").
WHEREAS, the Executive is providing valuable services
to the Company, and
WHEREAS, the Company wishes to assure continued
availability of the Executive's services and to create an
environment which will promote the Executive's giving
impartial and objective advice in the face of potentially
disturbing circumstances arising from the possibility of a
Change of Control of the Company (as herein defined);
NOW THEREFORE, the Company and the Executive in
consideration of the terms and conditions set forth hereby
mutually covenant and agree as follows:
1. GENERAL CONDITIONS No benefit shall be payable
hereunder pursuant to Section 4 of this Agreement unless
there shall have been both a Change of Control of the
Company, as set forth in Section 3 below, and a Termination
Event, as set forth in Section 4 below. In construing the
terms of the Agreement, it is the intent of the parties to
this Agreement to provide the Executive with financial
protection in the event significant changes in his
employment status occur following a Change of Control of the
Company, and it is agreed that provisions of the Agreement
are therefore to be construed using a reasonable man
standard and not on narrow technical grounds.
2. TERM OF AGREEMENT This Agreement shall commence on
the date hereof and shall continue in effect until the
earlier of (i) the fifth anniversary of such date or (ii)
the Executive's normal retirement date under the PENSION
PLAN OF CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS
SUBSIDIARIES or any successor retirement plan ("Normal
Retirement Date"); provided, however, that commencing on the
date three years after the date hereof, and on each annual
anniversary of such date (the "Renewal Date"), the term of
the Agreement shall automatically be extended so as to
terminate on the earlier of (x) three years from such
Renewal Date or (y) the Executive's Normal Retirement Date,
unless at least sixty days prior to the Renewal Date the
Company shall give written notice that the Agreement shall
not be so extended.
3. CHANGE OF CONTROL For purposes of this Agreement, a
Change of Control shall mean (a), (b), (c), (d) or (e)
below:
(a) The acquisition, directly or indirectly, of
securities of the Company representing 20% or more of the
combined voting power of the Company's then outstanding
securities by any third person including a "Group" as that
term is used in Section 13 (d)(3) of the Securities Exchange
Act of 1934 (the Exchange Act); or
(b) A change in the membership of the Board of
Directors over a period of two consecutive years in which
the members of the Board at the beginning of the period
cease for any reason to be at least two-thirds of the Board
at the end of the period provided, however, that this
section does not apply if the nomination of each new
director was approved by a vote of at least two-thirds of
the directors then still in office who were directors at the
beginning of the period; or
(c) The acquisition by a third person either
directly or indirectly, of the right to own, control or hold
with power to vote 10% or more of the outstanding voting
securities of the Company, if immediately subsequent to the
acquisition of the Company's voting securities by such third
person: (A) such third person shall be a "public utility
holding company" within the meaning of the 1935 Act, whether
or not exempt from registration thereunder, or (B) the
Company shall be in danger of losing its exemption under the
1935 Act or shall otherwise be required to register under
the 1935 Act; or
(d) Consummation of a reorganization, merger or
consolidation, other than a reorganization, merger or
consolidation following which the individuals and entities
that were the beneficial owners of the outstanding voting
securities of the Company immediately prior to such
reorganization, merger or consolidation, beneficially own,
directly or indirectly, more than 60% of the outstanding
voting securities of the company resulting from such
reorganization, merger or consolidation, in substantially
the same proportions as their ownership immediately prior to
such reorganization, merger or consolidation; or
(e) Consummation of (i) a complete liquidation or
dissolution of the Company or (ii) the sale or other
disposition in one transaction or a series of related
transactions of all or substantially all of the assets of
the Company, as determined by the Board, other than a sale
or other disposition to a company, which following such sale
or other disposition, the individuals and entities that were
the beneficial owners of the outstanding voting securities
of the Company immediately prior to such sale or other
disposition, beneficially own, directly or indirectly, more
than 60% of the outstanding voting securities of such
company in substantially the same proportions as their
ownership in the Company, immediately prior to such sale or
other disposition.
4. TERMINATION EVENT
A. DEFINITION OF TERMINATION EVENT
A Termination Event shall mean any of the following
within the thirty-six month period following a Change of
Control:
(1) the loss by the Executive of his position by reason of
demotion, or the withholding, adverse alteration or
reduction of responsibility, authority, or compensation
(including any compensation or benefit plan in which the
Executive participates or substitute plans adopted prior to
the Change of Control) to which the Executive was entitled
immediately prior to a Change of Control of the Company or
to which he would normally be entitled from time to time by
reason of his office;
(2) the relocation of the Company's principal executive
offices more than 25 miles away from the current offices or
the Company requiring the executive to be based anywhere
other than within 25 miles of the Company's principal
executive offices except for the required travel on the
Company's business to an extent substantially consistent
with his present business travel obligations;
(3) the failure of any other company, business,
corporation, partnership, individual, or group which
succeeds substantially to the interest of the Company or
into which it is merged or consolidated, to expressly assume
all rights, duties, privileges and obligations set forth in
this Agreement;
(4) the termination of the Executive's employment for any
reason during the 30 day period commencing on the first
anniversary of the Change of Control if, on the first
anniversary of the Change of Control, a majority of the
Company's (or if the Company's shares are not publicly
traded, the Company's ultimate parent whose shares are
publicly traded) board of directors were not members of the
Board immediately prior to the Change of Control (a
Termination Event described in this Section 4A(4), a
"Voluntary Termination Event").
B. OTHER TERMINATIONS
Provided no preceding or coincident Termination
Event has occurred, no payments hereunder shall be made on
account of the Executive's termination because of (1) the
Executive's death, disability or retirement (other than a
retirement following or coincident with a termination by the
Company of the Executive's employment without Cause) ; or
(2) by the Company for Cause; or (3) the Executive's
voluntary termination.
(1) DISABILITY; RETIREMENT
If the Executive shall have been absent from the full-
time performance of his duties with the Company for six
consecutive months as the result of the Executive's
incapacity due to physical or mental illness, and the
Executive shall not have returned to the full-time
performance of his duties within thirty days after written
notice of termination, the Executive's employment may be
terminated for disability. Termination of the Executive's
employment based on retirement shall mean termination in
accordance with the Company's generally applicable
retirement policy or with any retirement arrangement
established with the Executive's consent.
(2) CAUSE
Cause means termination based on the willful and
continued failure by the Executive to perform his duties for
the Company or a subsidiary (other than any such failure
resulting from the Executive's incapacity due to physical or
mental illness), after a written demand for performance is
delivered to the Executive by the Chief Executive Officer of
the Company which specifically identifies the manner in
which the CEO believes the Executive has not performed his
duties; or an act or acts of dishonesty taken by the
Executive and intended to result in his personal enrichment
at the expense of the Company or a subsidiary.
5. SEVERANCE COMPENSATION
A. If within three (3) years following a Change of
Control, (i) a Termination Event shall have occurred or (ii)
the Company terminates the Executive's employment without
Cause (either of (i) or (ii) occurring within three years
following a Change of Control being a ("Payment Event"), the
Company agrees to make payment in a lump sum ("Severance
Compensation") to the Executive of an amount equal to (1)
times (2), where:
(1) Equals 2.999, and
(2) Equals the Base Amount (as defined in 280G(b)(3) of
the Internal Revenue Code of 1986, as amended, and the regulations
and proposed regulations promulgated thereunder); PROVIDED, HOWEVER
that the Base Amount, solely for purposes of this Section
5A.(2), shall be calculated without taking into account any taxable
income that the Executive recognized as a result of the exercise of
stock options during the two-year period prior to a Change of
Control.
B. The Company shall also pay the Executive all legal
fees and expenses incurred by the Executive as a result of
such termination, including all such fees and expenses, if
any, incurred in investigating the merits, contesting,
(including the cost of alternate dispute resolution
procedures to which the parties may agree), or disputing any
such termination or in seeking to determine, obtain or
enforce any right or benefit provided by this Agreement.
C. If the amounts of such payments cannot be finally
determined when due, the Company shall pay the Executive an
estimate, as determined in good faith by the Company, of the
minimum amount of such payments and shall pay the remainder
of such payments together with interest at the prime rate,
plus 2% in effect at the First National Bank of Boston, as
soon as the amount thereof can be determined.
D. The Executive shall not be required to mitigate the
amount of any payment provided for in this Section 5 by
seeking other employment or otherwise, nor shall the amount
of any payment or benefit provided for in this Section 5 be
reduced by any compensation earned by the Executive as the
result of employment by another employer, by retirement
insurance or similar benefits, by offset against any amount
claimed to be owing by the Executive to the Company, or
otherwise.
6. TERMINATION DATE; PAYMENT OF SEVERANCE BENEFITS
A. PAYMENT OF COMPENSATION TO TERMINATION DATE
The Company shall pay the Executive full compensation and
all other amounts and benefits to which the Executive is
entitled through the Termination Date, including the payment
of such compensation, amounts and benefits during the time
of any extension of the Termination Date pursuant to Section
6C.(4) hereof.
B. DATE OF PAYMENT OF SEVERANCE BENEFITS
The Company shall pay to the Executive Severance
Compensation provided in Section 5 hereof within thirty days
of the Termination Date.
C. DEFINITION OF TERMINATION DATE
Termination Date means:
(1) FOR DISABILITY, that date thirty days after written
notice of termination if the Executive shall not have returned
to the full time performance of his duties, as described in
Section 4B.(1) hereof.
(2) FOR CAUSE, (i) due to performance, that date following
the notice to the Executive of performance failure, which ends
the period within which the Executive is given to correct his
performance as described in Section 4B.(2); or (ii) regarding acts of
dishonesty, thirty days after the Company's written notification
as described in Section 4B.(2) hereof.
(3) WITHOUT CAUSE, that date on which the Executive's
employment was terminated by the Company without Cause.
(4) FOR A TERMINATION EVENT, the date on which the
Executive notifies the Company a Termination Event as described in
Section 4A. has occurred.
If within thirty days following the Termination Date
described above, a party notifies the other party
that a dispute exists concerning the Termination Event,
the Termination Date shall be extended to the date the
dispute is fully determined; provided however, that
such notice must be given in good faith and the party
giving such notice pursues the resolution of the
dispute with reasonable diligence. The amount of
compensation and benefits paid to the Executive
during such period of dispute shall be subject to recovery
if the Company prevails on the dispute.
7. FUTURE SERVICES AND COMPENSATION
A. If a Payment Event has occurred, after which
Severance Compensation has been paid in accordance with
Section 5 hereof, the Executive agrees:
(1) To refrain from entering into competition with the
Company or from working for a competitor of the Company for a period
of one year following the date he gives notice of the Termination
Event, and
(2) To provide such consulting services as may be
reasonably requested by the Company for a period of one year following the
date he gives notice of the Termination Event.
B. As compensation to the Executive for his promises in
Section 7A hereof, the Company agrees to cause the following
actions to be carried out:
(1) As respects the status of the Executive as a
participant in the Company's Officers' Supplemental Retirement Plan, see
the Officers' Supplemental Retirement and Deferred
Compensation Plan as amended and restated effective August 1, 1984
signed December 1998.
(2) As respects the status of the Executive as a
participant in the Company's Officers Insurance Agreement:
(i) Cause such coverage to remain in force until the
Executive obtains life insurance coverage from a subsequent
employer, or for a period of three years from the termination
date, whichever comes first.
(3) If the Executive has less than ten years of service as
of the Termination Date, the Company shall also pay to the
Executive a lump sum amount, in cash, equal to the excess of (a)
the actuarial value of the benefits the Executive would commence
receiving on his 65th birthday under the Pension Plan of Central
Vermont Public Service Corporation and its subsidiaries in effect at
the Termination Date (the APlan@), calculated as if the
Executive had ten years of service with the Company, over (b) the
actuarial value of the benefits actually payable to the
Executive under the Plan commencing on his 65th birthday.
(4) As respects the status of the Executive as a
participant in any health or disability insurance plan in which the
Executive was participating as of the Termination Date, grant the
Executive a leave of absence for three years and cause the
Executive's participation in said health or disability insurance
plan or plans to continue during his leave of absence.
C. It is agreed that this Agreement will supersede any
other separation plan or practice maintained by the Company
for its officers to the extent there is any conflict.
Compensation earned but deferred under terms of its
Management Incentive Plan or any other executive
compensation plan which the Company may institute hereafter
shall specifically be paid to the Executive.
8. CERTAIN ADDITIONAL PAYMENTS BY THE COMPANY
A. Anything in this Agreement to the contrary
notwithstanding, but subject to Section 8H, in the event
that this Agreement shall become operative and it shall be
determined (as hereafter provided) that any payment (other
than the Gross-Up payments provided for in this Section 8)
or distribution by the Company or any of its subsidiaries to
or for the benefit of the Executive, whether paid or payable
or distributed or distributable pursuant to the terms of
this Agreement or otherwise pursuant to or by reason of any
other agreement, policy, plan, program or arrangement,
including without limitation any stock option, stock
appreciation right or similar right, restricted stock,
deferred stock or the lapse or termination of any
restriction on, deferral period or the vesting or
exercisability of any of the foregoing (a "Payment"), would
be subject to the excise tax imposed by Section 4999 of the
Code (or any successor provision thereto) by reason of being
considered Acontingent on a change in ownership or control@
of the Company, within the meaning of Section 280G of the
Code (or any successor provision thereto) or to any similar
tax imposed by state or local law, or any interest or
penalties with respect to such tax (such tax or taxes,
together with any such interest and penalties, being
hereafter collectively referred to as the AExcise Tax@),
then the Executive shall be entitled to receive an
additional payment or payments (collectively, a "Gross-Up
Payment"). The Gross-Up Payment shall be in an amount such
that, after payment by the Executive of all taxes (including
any interest or penalties imposed with respect to such
taxes), including any Excise Tax and any income tax imposed
upon the Gross-Up Payment, the Executive shall retain an
amount of Gross-Up Payment equal to the Excise Tax imposed
upon the Payment.
B. Subject to the provisions of Section 8F, all
determinations required to be made under this Section 8,
including whether an Excise Tax is payable by the Executive
and the amount of such Excise Tax and whether a Gross-Up
Payment is required to be paid by the Company to the
Executive and the amount of such Gross-Up Payment, if any,
shall be made by Arthur Andersen or any successor entity or
by such other nationally recognized accounting firm (the
"Accounting Firm") selected by the Executive with the
consent of the Company, which consent will not be
unreasonably withheld. The Executive shall direct the
Accounting Firm to submit its determination and detailed
supporting calculations to both the Company and the
Executive within 30 calendar days after the Change of
Control or the Termination Event, if applicable, and any
such other time or times as may be requested by the Company
or the Executive. If the Accounting Firm determines that
any Excise Tax is payable by the Executive, the Company
shall pay the required Gross-Up Payment to the Executive
within five business days after receipt of such
determination and calculations with respect to any Payment
to the Executive. If the Accounting Firm determines that no
Excise Tax is payable by the Executive, it shall, at the
same time as it makes such determination, furnish the
Company and the Executive an opinion that the Executive has
substantial authority not to report any Excise Tax on his
federal, state or local income or other tax return. As a
result of the uncertainty in the application of Section 4999
of the Code (or any successor provision thereto) and the
possibility of similar uncertainty regarding applicable
state or local tax law at the time of any determination by
the Accounting Firm hereunder, it is possible that a Gross-
Up Payment which will not have been made by the Company
should have been made (an "Underpayment"), consistent with
the calculations required to be made hereunder. In the
event that the Company exhausts or fails to pursue its
remedies pursuant to Section 8F and the Executive thereafter
is required to make a payment of any Excise Tax, the
Executive shall direct the Accounting Firm to determine the
amount of the Underpayment that has occurred and to submit
its determination and detailed supporting calculations to
both the Company and the Executive as promptly as possible.
Any such Underpayment shall be promptly paid by the Company
to, or for the benefit of, the Executive within five
business days after the receipt of such determination and
calculations.
C. The Company and the Executive shall each provide the
Accounting Firm access to and copies of any books, records
and documents in the possession of the Company or the
Executive, as the case may be, reasonably requested by the
Accounting Firm, and otherwise cooperate with the Accounting
Firm in connection with the preparation and issuance of the
determinations and calculations contemplated by Section 8B.
Any determination by the Accounting Firm as to the amount of
the Gross-Up Payment shall be binding upon the Company and
the Executive.
D. The federal, state and local income or other tax
returns filed by the Executive shall be prepared and filed
on a consistent basis with the determination of the
Accounting Firm with respect to the Excise Tax payable by
the Executive. The Executive shall make proper payment of
the amount of any Excise Payment, and at the request of the
Company, provide to the Company true and correct copies
(with any amendments) of his federal income tax return as
filed with the Internal Revenue Service and corresponding
state and local tax returns, if relevant, as filed with the
applicable taxing authority, and such other documents
reasonably requested by the Company, evidencing such
payment. If prior to the filing of the Executive's federal
income tax return, or corresponding state or local tax
return, if relevant, the Accounting Firm determines that the
amount of the Gross-Up Payment should be reduced, the
Executive shall within five business days pay to the Company
the amount of such reduction.
E. The fees and expenses of the Accounting Firm for its
services in connection with the determinations and
calculations contemplated by Section 8B shall be borne by
the Company. If such fees and expenses are initially paid by
the Executive, the Company shall reimburse the Executive the
full amount of such fees and expenses within five business
days after receipt from the Executive of a statement thereof
and reasonable evidence of his payment thereof.
F. The Executive shall notify the Company in writing of
any claim, by the Internal Revenue Service or any other
taxing authority that, if successful, would require the
payment by the Company of a Gross-Up Payment or any
additional Gross-Up Payment. Such notification shall be
given as promptly as practicable but no later than l0
business days after the Executive actually receives notice
of such claim and the Executive shall further apprise the
Company of the nature of such claim and the date on which
such claim is requested to be paid (in each case, to the
extent known by the Executive). The Executive shall not pay
such claim prior to the earlier of (x) the expiration of the
30-calendar-day period following the date on which he gives
such notice to the Company and (y) the date that any payment
or amount with respect to such claim is due. If the Company
notifies the Executive in writing prior to the expiration of
such period that it desires to contest such claim, the
Executive shall:
(i) provide the Company with any written records or
documents in his possession relating to such claim
reasonably requested by the Company;
(ii) take such action in connection with contesting such
claim as the Company shall reasonably request in
writing from time to time, including without
limitation accepting legal representation with
respect to such claim by an attorney competent in
respect of the subject matter and reasonably selected
by the Company;
(iii) cooperate with the Company in good faith in order to
effectively contest such claim; and
(iv) permit the Company to participate in any proceedings
relating to such claim;
PROVIDED, HOWEVER, that the Company shall bear and pay
directly all costs and expenses (including interest and
penalties) incurred in connection with such contest and
shall indemnify and hold harmless the Executive, on an
after-tax basis, for and against any Excise Tax or income
tax, including interest and penalties with respect thereto,
imposed as a result of such contest and payment of costs and
expenses. Without limiting the foregoing provisions of this
Section 8F, the Company shall control all proceedings taken
in connection with the contest of any claim contemplated by
this Section 8F and, at its sole option, may pursue or
forego any and all administrative appeals, proceedings,
hearings and conferences with the taxing authority in
respect of such claim (PROVIDED, HOWEVER, that the Executive
may participate therein at his own cost and expense) and
may, at its option, either direct the Executive to pay the
tax claimed and sue for a refund or contest the claim in any
permissible manner, and the Executive agrees to prosecute
such contest to a determination before any administrative
tribunal, in a court of initial jurisdiction and in one or
more appellate courts, as the Company shall determine;
PROVIDED, HOWEVER, that if the Company directs the Executive
to pay the tax claimed and sue for a refund, the Company
shall advance the amount of such payment to the Executive on
an interest-free basis and shall indemnify and hold the
Executive harmless, on an after-tax basis, from any Excise
Tax or income or other tax, including interest or penalties
with respect thereto, imposed with respect to such advance;
and PROVIDED FURTHER, HOWEVER, that any extension of the
statute of limitations relating to payment of taxes for the
taxable year of the Executive with respect to which the
contested amount is claimed to be due is limited solely to
such contested amount. Furthermore, the Company's control of
any such contested claim shall be limited to issues with
respect to which a Gross-Up Payment would be payable
hereunder and the Executive shall be entitled to settle or
contest, as the case may be, any other issue raised by the
Internal Revenue Service or any other taxing authority.
G. If, after the receipt by the Executive of an amount
advanced by the Company pursuant to Section 8F, the
Executive receives any refund with respect to such claim,
the Executive shall (subject to the Company's complying with
the requirements of Section 8F) promptly pay to the Company
the amount of such refund (together with any interest paid
or credited thereon after any taxes applicable thereto). If,
after the receipt by the Executive of an amount advanced by
the Company pursuant to Section 8F, a determination is made
that the Executive shall not be entitled to any refund with
respect to such claim and the Company does not notify the
Executive in writing of its intent to contest such denial or
refund prior to the expiration of 30 calendar days after
such determination, then such advance shall be forgiven and
shall not be required to be repaid and the amount of any
such advance shall offset, to the extent thereof, the amount
of Gross-Up Payment required to be paid by the Company to
the Executive pursuant to this Section 8.
H. Notwithstanding any provision of this Agreement to
the contrary, if (i) but for this sentence, the Company
would be obligated to make a Gross-Up Payment to the
Executive, and (ii) either (a) the aggregate "present value"
of the "parachute payments" to be paid or provided to the
Executive under this Agreement or otherwise does not exceed
1.10 multiplied by three times the Executive's "base
amount," or (b) the Executive's termination of employment
constitutes a Voluntary Termination Event, then the payments
and benefits to be paid or provided under this Agreement
will be reduced to the minimum extent necessary (but in no
event to less than zero) so that no portion of any payment
or benefit to the Executive, as so reduced, constitutes an
"excess parachute payment." For purposes of this Section 8H,
the terms "excess parachute payment," "present value,"
"parachute payment," and "base amount" will have the
meanings assigned to them by Section 280G of the Code. The
determination of whether any reduction in such payments or
benefits to be provided under this Agreement is required
pursuant to the preceding sentence will be made at the
expense of the Company, if requested by the Executive or the
Company, by the Accounting Firm. The fact that the
Executive's right to payments or benefits may be reduced by
reason of the limitations contained in this Section 8H will
not of itself limit or otherwise affect any other rights of
the Executive other than pursuant to this Agreement. In the
event that any payment or benefit intended to be provided
under this Agreement or otherwise is required to be reduced
pursuant to this Section 8H, the Executive will be entitled
to designate the payments and/or benefits to be so reduced
in order to give effect to this Section 8H. The Company will
provide the Executive with all information reasonably
requested by the Executive to permit the Executive to make
such designation. In the event that the Executive fails to
make such designation within l0 business days of the
Termination Date, the Companymay effect such reduction in
any manner it deems appropriate.
9. ARBITRATION In the event of any dispute arising between
the parties to this Agreement, the parties agree that such
controversy shall be settled by arbitration, in accordance
with the rules of the American Arbitration Association
applicable to employee benefit cases. If the parties are
unable to agree upon a mutually acceptable arbitrator, then
one arbitrator shall be named by each party involved in the
dispute, with an additional arbitrator to be chosen by the
other named arbitrators. In the event the arbitrator finds
that either party has breached its obligation under this
Agreement, the arbitrator may award such amount as is
necessary to remedy such breach.
10. WITHHOLDING Distribution of any benefit payments under
this Agreement will be reduced for the amounts required to
be withheld pursuant to any government law or regulation
with respect to taxes or similar provisions.
11. STATE LAW This Agreement shall be construed under the
laws of the State of Vermont.
12. REVOCABILITY This Agreement may be revoked or amended
in whole or in part only by a writing signed by both parties
hereto.
13. VALIDITY The invalidity or unenforceability of any
provision of this Agreement shall not affect the validity
or enforceability of any other provision of this Agreement,
which shall remain in full force and effect.
ACKNOWLEDGEMENT OF ARBITRATION
The parties to this Agreement acknowledge the
arbitration provision of this Agreement, and acknowledge
that no lawsuit may be brought by either party concerning
any dispute that may arise which is covered by the
arbitration provision, unless it involves a question of
constitutional or civil rights, and that such dispute shall
be submitted to arbitration in accordance with the
arbitration provision as set forth in Paragraph 9.
DATED at Rutland, Vermont this ____ day of ___________,
.
IN PRESENCE OF:
________________________ ______________________________
Witness Central Vermont
Executive
CENTRAL VERMONT PUBLIC
SERVICE CORPORATION
________________________ ______________________________
Witness Frederic H. Bertrand
Chairman of the Board
